A. Langford - Executive Vice President of Operations Ben Brigham - Chairman, Chief Executive Officer and President Eugene Shepherd - Chief Financial Officer, Principal Accounting Officer and Executive Vice President Jeffery Larson - Executive Vice President of Exploration

Scott Hanold - RBC Capital Markets, LLC Will Green - Stephens Inc. Michael Scialla - Stifel, Nicolaus & Co., Inc. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc. Rehan Rashid - FBR Capital Markets & Co. John Freeman - Raymond James & Associates, Inc.

Good day, ladies and gentlemen. Welcome to Brigham Exploration Second Quarter 2011 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to Bud Brigham. You may begin.

Thank you, LaToya. Thanks to each of you for participating in Brigham Exploration Company's Second Quarter 2011 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 of Land and Administration; and Rob Roosa, our Director of Finance. 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 second quarter results, as well as our plans for the remainder of 2011. 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 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 the plans and projections we talk about today. I encourage you to review our filings with the SEC. In addition, in this call, we may use the terms EUR and probable and possible reserves that we do not include in our SEC filings. We may also discuss de-risked acreage and locations, which include proved reserves as disclosed in our SEC filings. Please refer to Page 2 of our corporate presentation for a cautionary note to U.S. investors regarding the use of these terms. Finally, a copy of our company's press releases as well as other financial and statistical information about the period 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, and briefly, as shown on Slide 3, we reached a couple of very significant milestones recently. We recently drilled our 100th operated Bakken and Three Forks well and we also have now drilled over 1 million feet of Bakken and Three Forks lateral. Congratulations to all our employees and our shareholders. And as shown on this slide, you can see that it's just the tip of the iceberg. Given our delineated inventory, I expect us to drill up to 2,200 operated wells and up to 22 million feet of Bakken and Three Forks play. Now if you'll move to Slide 4, you can see our outline for the call. Our motto is "No Oil Left Behind." We're determined to fully and optimally exploit yjod world-class resource for our shareholders. I'm going to start the call with opening comments and an overview, followed by Jeff reviewing our current and future drillings plans, then Lance will provide you an operational update. Following which, Gene will finish with the financial update. Please skip forward to Slide 8. You can see a description of the investment opportunity we present. Importantly, as you look toward the bottom of the slide, you can see the catalysts that I referred to in our operations press release that highlights the significant potential that we could unlock over the remainder of 2011. These catalysts include further de-risking of the Three Forks in Rough Rider, additional drilling in Montana, our Smart Pad efficiency initiatives and the potential for additional productive zones. If you'll click forward to slide 9, I will review the topics we'll focus on during the call. First, although there's a great deal of turbulence in the markets, the environment remains very constructive for Brigham Exploration, a continued compounding stockholder net asset value. Second, North Dakota experienced a record winter followed by tragic flooding during the spring melt and late May rainstorms. And as a result, several of our Bakken competitors missed their guidance or experienced declines in their second quarter production. Thanks in part to our team at Smart Pad, zipper fracs and the infrastructure build-out, which was only just getting started, We were able to continue much of our operations in the field and as a result, our production was within our previous guidance range, albeit at the lower end. And we were one of the exceptions, and that we generated meaningful sequential growth in production during the second quarter. We believe this is foreshadowing the significant competitive advantage that's our Smart Pads and infrastructure build-out we'll provide that will materially differentiate us in subsequent periods of difficult weather such as early as -- potentially as early as this coming winter. Given that we have 2 fully dedicated frac crews working and given our efficiencies increasingly being generated in the field, which Lance will discuss in some detail, production growth is accelerating in the second half of the year. Third, it's remarkable that we've now drilled 79 consecutive North Dakota wells with an average IP of roughly 2,800 barrels of oil equivalent per day. That's amazing consistency and given that it's just the tip of the iceberg, we have 1,400 to over 2,200 gross wells to be drilled. We've only just scratched the surface of this inventory. Fourth, despite the recent decline in oil prices, our returns remain strong and this is prior to considering our 10% to 20% cost savings initiative we believe we're just beginning to experience in the field with our Smart Pads. Based on the recent prices, a 600,000-barrel well generates about $8.7 million in net present value, will bring an estimated 51% rate of return and paying out in less than 2 years. That's remarkable when you consider that these wells should produce for 25 years. Fifth, our success in Montana, combined with our acreage acquisitions, is growing our de-risk inventory by about 10,800 net acres to 235,200 net acres. That's an 11- to 18-year inventory, depending on whether you give us credit for the Three Forks in Rough Rider. We'll discuss the fact that despite our continuing acceleration in our drilling program, recently to 10 rigs, we have grown our de-risk inventory more rapidly than we drilled it. Sixth, we and other operators have now completed 4 successful Three Forks wells in Rough Rider with an average IP of approximately 1,840 barrels of oil equivalent per day. I believe we've clearly de-risked a portion of our Rough Rider area for the Three Forks. And by year end, after we've completed 3 additional Three Forks wells, and other operators have also completed additional Three Forks wells, it's likely that much, if not all, of our Three Forks -- excuse me, all of our Rough Rider area will be de-risked for the Three Forks, providing us with up to 500 incremental net drilling locations. Seventh, we'll discuss in a bit more detail our planned 5.5 Bakken wells per unit pilot, which we will compare over time with the results of our current 4.5 Bakken wells per unit drilling. Eighth, Lance will also discuss some exciting technological innovations we're testing in the field. Who would have envisioned the game changes that swell packers provided. We're very optimistic about working with our leading service company providers. We can capitalize on potential new game-changing technology to further enhance our returns in this play that thus far has responded so well to improving technology. That's one example of the option value that this play provides for us. We stated, and continue to evaluate, other potential resource objectives, and we believe it's likely that some of these will blossom for us. Now skipping forward in the presentation to Slide 10. The commodity advantage for all that has persisted now since 2006, we don't see any indications of that changing for the next 3 to 5 years. Moving to Slide 12 so that you can see why we believe the Bakken and Three Forks is the top resource play in North America. We're fortunate to have an early mover position and be right in the middle of the best areas in the play. So we're in the best play in North America, and Lance will provide production data delineating our industry-leading well performance in this top resource play. Moving to Slide 13, which I believe is a very important slide. This chart shows the very dramatic growth in production we've achieved. North Dakota experienced its coldest winter in years with record levels of snowfall, followed by a tragic 100-year [ph] flooding. Despite those challenges, in part due to our Smart Pads and infrastructure advantage, which Lance will discuss in more detail, we generated strong sequential growth in Williston production during the second quarter. Importantly, we've achieved this growth by barely scratching the surface of our inventory. We've only drilled 6% to 9% of our currently de-risked inventory, depending on whether or not you give us credit for the Three Forks in Rough Rider. With 2 dedicated frac crews and increasing efficiencies, which are quickening our completions in the field, production growth has accelerated dramatically, setting us up for a remarkable second half of 2011. You can see the accelerating trend on the chart after we picked up the second dedicated frac crew. You can also see that our Williston oil production averaged over 13,000 barrels of oil equivalent per day in July. Our strong entry into the third quarter as shown on the chart provides good visibility for our substantial growth in average production for the third quarter. On Slide 14, you can see the impact our Williston drilling is having on our company's quarterly oil production volumes, including our forecast for the third quarter. Again, given that our July production in Williston averaged over 13,000 barrels of oil equivalent per day, and given that we're now in August, we have a good deal of confidence in our Q3 forecast. If you move forward to Slide 15, you'll see our total equivalent production. Our second quarter production was up 88%, relative to the second quarter of 2010 and up 11% sequentially. We expect our third quarter production to be up 28% sequentially. Moving to Slide 16, you can see that our strong growth in production volumes is compounding with strong oil prices that drive a remarkable growth in EBITDA to sequential quarterly records. Given current commodity prices and the visibility we have for our forecasted very strong production growth, the third quarter revenue and cash flow should once again achieve new record levels. On Slide 17, you can see another way the macro continues to be supportive. Differentials for us have stabilized over the last 2 years at $8 to $11 per barrel. But in April, they trended down to about $6 per barrel. This is a $5 per barrel improvement in our net pricing, which helps lead Bakken operators to offset or mitigate some of the oil price decline we've all just recently experienced. As you can see from the chart, the improvement continued throughout the second quarter and is rolled into the third quarter as well. It appears that many of our barrels are piped to the Midwest, which has minimized the impact of attrition surplus on our volumes. On Slide 18, we've overlaid our production growth on a chart with our year-end reserves, the last 3 years as green bars. As some of you know, in 2008, our growth and production reserves into Williston was just beginning to take over. As you can see on the start, production can be a very good proxy for reserve growth. And it's apparent we're headed for another very big year for reserve additions. Again, we've only drilled 6% to 9% of our currently de-risked inventory, but we're just getting started. It's exciting when you think of it from a valuation perspective to roll 6 months forward with the dramatic growth in year-end reserves and production and to think about what that implies as to our company's valuation as the market moves forward one more year. On slide 19, we've added, with the yellow ovals, our undrilled inventory and you can see that despite our continued acceleration with the drill bit, we've grown our inventory faster than we've drilled it. The first number in the oval is the inventory, assuming no credit for the Three Forks in Rough Rider, while the second number includes the Three Forks locations. Jeff will discuss our inventory further. The growth is occurring through acreage acquisitions and our step-out drilling successes such as our recent wells in Montana. I think it's clear, we've delineated attractive Three Forks economics for portions of Rough Rider area with the 4 wells we and other operators drilled. And by year end, with significantly more wells completed, we will likely be specifically delineating the economics for a much and potentially all of those locations as part of our de-risk core inventory. Now taking a look at the economics. Slide 20 shows that the returns in this play remains strong even with the recent decline in oil prices. Keep in mind that these returns are prior to the cost efficiencies that we're beginning to generate in the field with our Smart Pads, which Lance will discuss further later in the call. Despite the recently reduced drift, a 600,000 barrel of oil equivalent well generates about $8.7 million in net present value. That's over the capital cost and a rate of return of about 51% with a payout of less than 2 years. Slide 21 shows that even at lower oil prices, this play generates solid returns. And again, this is prior to our cost efficiencies that we're beginning to generate in the field. In addition, we get excellent support from our hedges. For example, we've aggressively hedged our oil volumes to address commodity price risk. Based on the midpoint of our production guidance, we have 56% of our second half 2011 oil volumes hedged with a floor of $69.41 per barrel and $3.9 million of our 2012 oil volumes hedged with a floor of $71.40 per barrel. Even without hedges, we estimate that these wells generate a 29% return at flat $75 oil. Again, before our 10% to 20% cost reductions in the field and before any potential changes to service cost structure that would occur as a result of reduced prices. Slide 22 is our chart of production curves for all of our North Dakota, Bakken and Three Forks wells. Our more recent wells continue to outperform. Lance has some excellent data that he'll discuss that delineates our outperformance relative to our peers. Now a few comments on our density pilot projects. And we'll start with a quick update. Slide 23 shows in map view our Brad Olson #2H, which had an approximate 4-well spacing distance from a well completed one year prior, the Brad Olson #1H. We subsequently brought online the Brad Olson #3. And if you forward to the next slide, Slide #24, you can see the production performance for these wells. The Brad Olson #2, as shown in green, which was completed a year after the Brad Olson #1, shown in Orange. We have previously shown this slide, but the production is now updated here. However, it's a little misleading given that we shut in the Brad Olson #2 well during periods that we were refrac-ing the Brad Olson #3H in order to report pressure data to identify potential communication. By the way, our data indicates that the pressures in the Brad Olson #2H were not materially affected by the frac-ing of the Brad Olson #3. The next slide, Slide 25, shows the same well's performance with the downtime removed from the wells. Without the distortion created by the downtime, you can see how well the Brad Olson #2H has performed, despite its approximate 4-well spacing distance from the Brad Olson #1H and despite the fact it came online one year later. It slowed longer and almost double the ore of the #1H, and is producing right on track despite, again, coming on a year later. We believe this indicates no material competition between these wells. You can also see that the Brad Olson #3 is performing as well or even better than the prior 2 wells. Slide 26 is an illustration of our current spacing plan for our wells in the play, which provides for 4.5 Bakken wells per unit. We have additional density pilots underway for this plan. Slides 27 to 29 show our current interpretation of the frac drainage areas on our 3D geologic block diagrams with our current 4.5 well Bakken spacing pattern for both our Rough Rider and Ross areas. As you can see on these slides, we may be leaving a little behind with the spacing. If you move forward to Slide 30, you can see our spacing plan for a potential 5.5 Bakken well and Three Forks density unit. We have the density pilot that we'll drill this year, utilizing this pattern. We'll record microseismic and pressure data on these projects, and our objective is to accumulate as much quality data as early as possible such that we can optimize our development plans and thereby optimize our net asset value creation for this world-class resource. Slide 31 illustrates this potential 5.5 Bakken well development, along with associated potential 3/4 pattern on our 3D geologic block diagram. Again, we want to begin monitoring the production from these density pilots as soon as possible so that we can optimize our future development plans. We'll be drilling and completing these wells later in this year. Slide 32 is a map of our Stacked 1,280-acre units in our Rough Rider area. Our concentrated position in the best areas of the play provides us with the opportunity to achieve substantial efficiencies in the field via our Smart Pads. Lance will discuss that further. We have the opportunity to drill about 112 spacing units with our Smart Pads, which represents more than 896 gross wells. That concludes my portion of the call, and I'll now hand the call over to Jeff to provide you with the drilling plan update.

Thanks, Bud. Moving on to Slides 34, 35 and 36, this group of slides highlights our updated Bakken and Three Forks well list. It's really quite remarkable when you step back and think about the fact that we've now completed 79 consecutive North Dakota Bakken and Three Forks wells with an average IP of approximately 2,800 barrels of oil equivalent per day. We're also very excited about the fact, as Bud mentioned, that we have now drilled our 100th operated Williston Basin Bakken or Three Forks well, and we have also reached a milestone of having drilled over 1 million horizontal feet of Bakken and Three Forks. Moving on to Slide 37. You can see in the green box our currently de-risked inventory by area, assuming no credit for the Three Forks in Rough Rider. For this analysis, we are assuming 4 wells per drilling unit. However, as shown on Slide 38 where we focused just on the Rough Rider Three Forks activity, you can see that Brigham and other operators have had successful Three Forks completions on the West side, the East side and also the Southeast of our Rough Rider acreage block. So we are in the process of delineating attractive economics over a good portion of this acreage. By year end, we will have completed 3 additional Three Forks wells, and it's apparent that other operators will also complete a number of wells by year end. As a result, we expect our delineated attractive economics over much or potentially all of our Rough Rider acreage to represent the potential to add up to 500 net locations to our undrilled inventory. On Slide 39, inside the green box, you can see our de-risked core inventory inclusive of the Three Forks in Rough Rider. At our 2011 drilling pace, this represents an 18-year inventory of projects. On Slide 40, we have a chart that illustrates the option value that we have to further grow our de-risked core inventory. Our 5.5 well pilots are important potential catalysts in this regard. And of course, not included on this slide are the locations we could add with other potential Williston Basin resource plays such as the lodgepole and Scallion. Slide 41 is an activity map of Brigham's Rough Rider project area in Williams and McKenzie Counties, North Dakota. On this slide, we have highlighted our operated Bakken activity with yellow tags and all key Brigham and industry Three Forks activity with purple tags. Industry activity continues to pick up in Rough Rider with 44 rigs currently running around the edges of our acreage block. We believe that we control the highest quality acreage block in the area, as we were fortunate to be the early mover and focused our leasing efforts on securing the acreage with the best middle Bakken property. We've accelerated our drilling program in Rough Rider with 7 operated rigs now drilling Bakken and Three Forks wells. We have 3 Three Forks wells that will be completed before year end: The Irgens 27-34 located near the top of the slide; it's just now starting frac-ing operations on a 3-well zipper frac; the Mrachek Trust 22-15 to the South is waiting on completion; and the Broderson 30-31 to the Southeast in our bank's area will spud in early September. There are also several other recent Three Forks industry wells of note. The Tracker Scanlan that IP-ed at 1,781 barrels of oil equivalent per day and the Kodiak Koala, which IP-ed at 2,327 barrels of oil equivalent per day. Both wells are located in the lower right portion of the slide. We believe these new industry wells, coupled with Brigham's Three Forks completions, will de-risk a significant portion of Rough Rider by year end 2011. We will also spud a 5.5 well middle Bakken density pilot in October of this year, highlighted with the green box on the slide. We will collect a significant amount of scientific data during the completion phase of the pilot, including deploying a microseismic array to gather as much information as possible to assess frac wing lengths and potential drainage areas. We believe that it is critical to learn the most effective density drilling pattern in each area as quickly as possible to most efficiently and economically drain each producing units. Slide 42 is an activity map for Brigham's Ross Area in Mountrail County, North Dakota where we currently have 2 rigs running drilling Bakken and Three Forks locations. The first rig is currently drilling the Charlie Sorenson 17-8, highlighted on the left side of the slide with the white tag. This well is drilling from a Smart Pad location where 3 other wells are at TD and waiting on completion. Once the 2H has TD-ed, we will conduct our first 4-well zipper fracs starting in early September. The second operated rig is currently drilling the Brown 2-1H and a Bakken density well in Northwest Ross. Similar to the Rough Rider area, we also plan to spud the first well in a 5.5 well Bakken density pilot and a 5.5 well Three Forks density pilot in Ross by year and. The green box highlights the unit in the Southeastern corner of Ross that we have targeted for the pilot program. As with Rough Rider, we will collect an extensive amount of scientific data to assess optimal drainage areas. Slide 43 is an activity map of Eastern Montana. As with the previous slides, our operated wells are highlighted with yellow tags. Other industry activity, a number of which we are participating in, are denoted by green tags and the Three Forks tests are denoted by purple tags. Eastern Montana continues to be very active with 15 industry wells currently being drilled or completed, including 3 Three Forks tests. The Whiting French well, just north of a large block of our acreage, the Continental Herness to the south and west of our blocks and the Oasis Wilson Federal to the north and to the East. Brigham has successfully completed 2 new Bakken horizontal wells in Eastern Montana, the Charley 10-15 with an IP of 1,069 barrels of oil equivalent a day, located approximately 2 miles east of our recent Gobbs 17-8 completion and highlighted with the yellow tags on the left side of the slide. And also the Storvik 7-6 that IP-ed for 2,066 barrels of oil equivalent a day and is located in the lower right area of the slide. As a result of these and previously announced completions, we have now completed 7 Montana Bakken wells with an average IP of roughly 1,576 barrels of oil equivalent a day. We therefore believe we have de-risked approximately 33,500 net acres for the middle Bakken reservoir in Eastern Montana. Brigham currently has one rig running in the area, drilling the Glenn 28-33 well, a Bakken well located on the southern part of the slide. This well is approximately 6 miles west-southwest of our Johnson 30-19 and is the western most middle Bakken test we have drilled to-date in Richland County. We are also currently using a small rig, called a riglet, to reenter the State Hardy 16-32, which is located east of our drilling Glenn well. The State Hardy is an existing historic middle Bakken horizontal well that was completed with one uncontrolled frac. We have successfully sidetracked this 100% working interest well, run a liner and swell packers to bottom and plan to complete the well with a 34-stage frac in the near future. Lastly, for Eastern Montana, we currently have one additional well, the Beck 15-10, located in the upper left portion of the slide, waiting on completion and plan to spud 4 additional middle Bakken wells by year end 2011. With that, I'll turn the call over to Lance for the operations update. A. Langford: Thanks, Jeff. We are really excited about the operational improvements we are achieving in the field. First, I'll discuss how our wells are performing compared to other operators and then I will discuss our operations, how our operations are becoming more efficient, resulting in significant cost savings today and into the future. If you will move to Slide 45, we reviewed the public production data for all horizontal Bakken wells that were drilled in North Dakota after 2008. The reason for only using wells drilled after 2008 was to cut out the old technology in short lateral wells. We know that our Olson #1H well that was located in Williams County was the first well to complete with 20-plus stages in a long lateral well. It was completed in January of 2009. This slide shows the average of the first 3 months of production by operator. If you look at the map shown on the left, you could see the well locations and the bubble size represents the cumulative production for the first 3 months of production. If you look at the chart on the upper right, you can see Brigham has the highest average production for the first 3 months. This is remarkable to me mainly because approximately 2/3 of the wells in our average are located in Rough Rider and are being compared to Parshall/Austin and Sanish wells.. And finally, if you look on the chart at the bottom right, this shows the distribution of the first 3 months of cums compared to other operators. Moving to Slide 46. If you look at all of the wells that have production for 6 months, this results in Brigham having the second highest average cum. Also remember that we are averaging in our Rough Rider wells and comparing them to Parshall/Austin and Sanish wells. Also notice by looking at the distribution of the wells, the large cums of the top 5 Sanish wells brings the average way up. Moving to Slide 47. Once again, if you take a look at the wells that have production for 12 months, this results in Brigham having the second highest average cum. And again, we're averaging in our Rough Rider wells and comparing them to Parshall/Austin and Sanish wells. As we all know, as you move across the basin, there are gradual changes in lithology and this results in changes in productivity. So we decided to perform the same analysis, but we broke out the wells into 2 areas: Rough Rider and Ross, and limited the data to all wells within 5 miles of our wells in those areas. Moving to Slides 48 to 53. As you move through these slides, you can see, on average, our wells outperformed all the other operators in the area. This is true for both Rough Rider and for the Ross Area. This data demonstrates that we're benefiting from the fact that our technical team is doing a great job of drilling and completing our wells. Moving to Slide 54. To zoom in on an even more detailed study area, this map depicts our wells in red and the direct offset wells shown in other colors. Moving to Slide 55. Comparing Brigham's wells to the direct offset wells, on a cum versus time plot, you can clearly see that our wells are significantly higher cums before they were required to be put on pump, which is represented here by the squares on each curve. But most important, Brigham's wells are significantly outperforming the direct offset. I want to point out that the offset operators are efficient and well-respected operators within the basin. Also note the number of stages and the completion methods denoted in the bottom left corner. Even though we have a couple of wells with fewer stages than the offset wells, we still outperformed the offset wells that have more stages. We believe this is because of our use of the perf and plug method, ceramic proppants and the quality jobs steering the wells by our geosteerers. Moving to Slide 56, this cum versus time plot shows the average of all of Brigham's wells shown in red and a corresponding median curve shown in green. Also shown is an average of the offset wells shown in blue and a corresponding median curve shown in yellow. If you use Brigham's current costs in a recent AFE for the corresponding offset operators, we believe that our wells are generating higher average rate of returns and roughly twice the net present value. So that's a quick overview of well performance. Now, let's take a look at the cost side and how our operations are becoming more efficient, thereby, reducing our costs but also quickening our pace in the field. If you move to Slide 57, although we have just begun to implement Smart Pad drilling and completion techniques, and though we're only utilizing a portion of our pipeline system, we are expecting to see significant cost savings as we move through 2011 and 2012. Our performance in the data we gather today are reinforcing our previous view that we should be able to achieve 10% to 20% reduction in drilling and completion costs through efficiencies in the field. Moving to Slide 58, just looking at the drilling portion alone, it appears that our Smart Pad operations should reduce our total well cost by approximately 5% when we're drilling with 3 or more wells per pad and utilizing walking rigs. Currently, we have 10 operated rigs and we are drilling smart wells approximately 72% of the time. We currently have only one walking rig operating and we will convert 3 additional conventional rigs to walking rigs by year end. And we have 4 new build walking rigs coming in 2012, and we expect to continue to increase the number of walking rigs as we move through 2012. Next on slide 59. The completion portion of our Smart Pad operations should also ultimately reduce our per well capital cost by another approximately 4% when we are zipper frac-ing 3 or more wells at a time or when we're utilizing the new frac sleeve technology. Recently, both of our Halliburton frac crews were reconfigured to perform zipper fracs, and we are now zipper frac-ing approximately 62% of our wells, which approximately half of those are performing 3-well zipper fracs. So roughly 31% of our wells are now 3-well zipper fracs and about 31% are 2-well zipper fracs and the remaining roughly 38% are single-well fracs. Our results can be seen on Slide 60. To-date, we have completed 6 zipper fracs, 5 with 2 wells and one with 3 wells. It typically takes approximately 9 days to frac a single well using perf and plug method. This includes 2 days of moving and rig up time. The last 2-well zipper frac to 5.3 days per well and the 3-well zipper frac to 3.9 days per well. So that's 3.9 days per well for the 3 wells zipper frac relative to 9 days to frac a single well. That's really pretty remarkable and we expect to get more efficient and further reduce the time and capital cost required to frac our wells as we experience -- as we gain experience. We also completed mechanical field tests at both Halliburton and Baker's new technology frac sleeves. We are currently completing 2 wells which have approximately half the well or 15 stages utilizing these new technology frac sleeves. The remaining half of these wells would be frac-ed utilizing perf and plug method. And production from these 2 wells will be compared to direct offset wells that were completed entirely with perf and plug. Now moving to Slide 61. When Brigham's gathering systems are fully operational, we expect these systems to further reduce our capital cost per well by approximately 5%. We currently have approximately 70% of our lines laid, but we still have lots of work ahead of us. We also have 3 SWDs operational, but have only 30 wells hooked up to the salt water gathering system. By year end, we expect to have 6 SWD wells operational and the majority of our wells, approximately 100-plus wells hooked up to our gathering system. We currently have approximately 108 miles of freshwater line laid and we expect to have an additional 62 miles of line fully operational by year end. We are currently using our freshwater system to provide freshwater to 39 of our drilling units. We currently have approximately 102 miles of oil line laid, and we expect to have 180 miles laid and operational by year end. We also expect to be connected to Enbridge, Plains and Bridger pipelines by year end, as well as Savage and Rangeland railports. Moving to Slide 62. We have another -- number of other initiatives underway to further reduce costs. We expect to have additional savings related to other emerging technologies such as biofuel systems, gas lift systems and others. Looking ahead, we expect to start drilling as many as 8 wells per pad and over time we'll become more efficient in executing our plan. So as you can see, we've made great strides in becoming more efficient and reducing our capital cost, but we're only getting started. Not only do we expect to reduce our per well cost by 10% to 20% as we move through 2011 and 2012, we also expect our initiatives to reduce our operating expenses and to generate very substantial returns on our midstream investments. We also expect to become more efficient with our products and services and this will result in execution of our plan, even through the winter and the rainy seasons. With that, I'll turn over the call to Gene.

Thanks, Lance. Before we get into a discussion of our second quarter results, several comments about what turned out to be another record quarter in terms of financial results for Brigham. Point number one, first, we experienced strong operational performance during the quarter based on the continuing ramp up in and success of our Williston Basin operating drilling program. We achieved record quarterly production volumes of 12,206 barrels of oil equivalent per day. Given our full year production guidance range of 14,000 to 16,000 BOEs today, we expect to deliver a significant ramp in our production volumes in the second half of the year. That ramp up in production is well underway. In June, in the Williston Basin alone, our production volumes exceeded 12,000 BOEs per day for the month versus 10,472 BOEs per day in the Williston Basin in the month of May. And in July, Williston Basin production volumes averaged over 13,000 BOEs per day. Point number two, this strong operational performance is translated into record financial results. For the quarter, record prehedged revenues of almost $94 million translated into record EBITDA of $76 million. To give you a sense for how far we have come over the last 18 months, this is roughly 143% of the EBITDA that we achieved for all of calendar 2009. Further, based on the growth in our production volumes and the strong commodity prices during the quarter, our per unit operating margins, which represent revenues, excluding hedging gains and losses, less differentials, lease operating expense, production taxes and cash G&A, reached a record $65.14 per barrel, an improvement of 21% from the previous record of $54.06 per barrel achieved in the first quarter of 2001. The second quarter operating margins reflect cash operating costs of $24.70 -- $24.74 per barrel, highly attractive even in light of the recent sell-off in oil prices. Point number three, given that we have drilled a total of 86 horizontal Bakken and Three Forks wells using our current formula and given the consistency of our results, we have excellent visibility as to our future financial performance and future liquidity needs. As depicted on Slide #65, we are still on track to live within the 2011 CapEx budget that we announced in May. Based on our current 12-rig case, current AFEs and strip prices as of the close on August 5, we would expect that our credit facility which currently has a 0 outstanding balance and a borrowing base that will get redetermined in October, would roughly meet our external capital requirements before going free cash flow positive. Point number four, lastly, we continue to take steps to address other sources of execution risk, and in doing so further enhance the predictability of our future financial performance. Aggressively hedging our oil volumes to address commodity price risk based on the midpoint of our production guidance and as depicted on Slide #66, we have 56% of our second half 2011 oil volumes hedged with a floor of $69.41 per barrel and 3.9 million barrels of our 2012 oil volumes hedged with a floor of $71.40 per barrel. Going to Smart Pad drilling, which includes walking rigs, multiwell pads, multi-well simulations as well as we are evaluating new tools to ultimately lower our drilling cost and investing in significant crude oil, produced water and fresh freshwater infrastructure to lower AFEs, differentials and lease operating expenses as well as more efficiently deliver our oil volumes to market by reducing our dependence on trucks. Moving on to a brief discussion of our financial results. Our second quarter total production volumes averaged 12,206 BOEs per day, an increase of 57% from that in the second quarter of 2010 and 8% sequentially. More importantly, given our focus on drilling our Bakken and Three Forks predominantly oil wells, our second quarter oil volumes averaged 10,208 barrels of oil per day, an increase of 83% from that in Q2 2010 and 11% sequentially. Our second quarter oil volumes represented 84% of our total production volumes versus 72% in Q2 2010. 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 93% of our total second quarter prehedged sales revenues. Our second quarter total production volumes reflect an increase in our oil inventory of approximately 18,156 barrels held in our on-site tank batteries at June 30. Adjusting our Q2 production volumes for the growth in our oil inventory results in average daily sales volume for the second quarter of 12,004 BOEs per day. On a per unit basis, lease operating expense, which includes operating and maintenance expense, expense workovers and ad valorem taxes, increased 28% to $8.08 per BOE in the second quarter 2011 from $6.30 per BOE in the second quarter 2010. During the quarter, extraordinary costs associated with dealing with the aftermath of flooding conditions in the Williston Basin from the melt -- from the record winter snowfall and the record rainfall at the end of May and in early June accounted for roughly $500,000 or $0.46 per BOE of incremental LOE costs. General and administrative expense for the second quarter increased $3.2 million -- increased to $3.2 million from $2.7 million in the second quarter of 2010. An increase in payroll and payroll taxes accounted for the bulk of the increase in G&A expense with an increase in noncash, stock comp expense accounting for the vast majority of the increase in payroll and payroll taxes. The growth in our oil volumes and commodity prices and the associated increase in our revenues contributed to a 22% sequential increase in EBITDA during the second quarter to $75.7 million. Further, this growth contributed to a 128% increase in EBITDA during the second quarter of 2011 relative to that in the prior year's quarter. Moving on to the balance sheet and as depicted on Slide #67. At the end of the second quarter, we had $362 million in cash, cash equivalents and short-term investments, $600 million of senior notes and nothing outstanding under our senior credit facility, which has a $325 million borrowing base. Other potential sources of liquidity include conventional asset sales, our October borrowing base redetermination and the potential monetization or partial monetization of our Midstream business including the possibility of an MLP IPO of a portion of our Midstream business in 2012. Reviewing capital spending activity for the second quarter. Oil and gas capital expenditures totaled $244 million, of which $166 million went to drilling expenditures, $50 million went to land and roughly $28 million went to the support of infrastructure. In our earnings release yesterday, we provided production guidance for the third quarter of 2011. In terms of our expectations for the third quarter, we are forecasting our total production volumes to average between 15,000 and 16,200 barrels of oil equivalent per day with 84% of these volumes forecasted to be oil. Using the midpoint of our guidance for the third quarter would result in sequential third quarter production growth of 28%. 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 a record total production volumes in the second quarter with the expectation that we will continue to generate record volumes in the second half of 2011 and beyond. That concludes my remarks. I'll now turn the call back over to Bud.

Thanks, Gene. That concludes our prepared comments, and we'd be happy to answer any questions.

[Operator Instructions] Our first question is from William Green of Stephens. Will Green - Stephens Inc.: I appreciate the color on all the new slides. It's very helpful. I wanted to jump over to Montana first since that's kind of a new area of focus for you guys. And now that you've drilled -- I guess 6 or 7 wells or completed that many in Montana so far, what kind of differences can you discern, if any, in Roosevelt versus Richland at this stage?

This is Jeff. I mean, I think it's still early. We're seeing a lot of industry activity. As we've mentioned, 15 wells drilling or completing via -- when you look at rock quality, we like the correlation in the middle Bakken between the 2 areas, and that's really what helps kind of focus our leasing efforts over there, was the -- using the historic well control points and the map in that Bakken prosody. I think it's gong to be important to kind of watch the industry. Obviously, there's 3 Three Forks wells that we're very interested in seeing the results on. And hopefully, those folks will report those results by year end and it will give us more clarity on the Three Forks as well. Will Green - Stephens Inc.: Okay, great. I appreciate that. And then I wonder if we could just talk about kind of the Gobbs versus the Charley and Swindle since they're pretty close together. I mean is the biggest variance there, the stages of fracs or what else are you guys doing there that would have the results vary? I mean the Gobbs well was obviously superior on an IP basis and it had the most frac stages, but is that all there is to it or is there a difference in proppant or kind of what are you guys doing there?

This is Bud. I'll have an initial comment and Lance will probably want to add to it. But we did vary the stages and we're doing that in different areas to try to determine what's optimal in different areas. And so in that case, with fewer frac stages, we've got less IP. Might indicate that more frac stages are better in that area. But obviously, we're in it for long-term value creation, so learning early is very beneficial. And of course, there's rock differences. Even just a few miles away, that can make a difference in the early performance. Lance, do you want to add to that? A. Langford: Right. I might also add on the Swindle, our liner was stacked 3,000 feet off bottom, so we didn't get an effective stimulation of the entire lateral in the Swindle. So that made up some of the differences.

And some of the Charley and the Gobbs. A. Langford: Yes. On the Charley and Gobbs, it's the number of stages and there's always small differences. It could be how long the well was before it was shut-in after frac, before we drilled it out. It could be the mechanical situation, it could be the weather. I mean there are lots of things that can impact IP, so we try not to focus too much on the IPs. I know we've been trying to get everybody to focus away from it and look at more the longer-term production. And I think both wells are going to be good wells. And so I think less to focus on when we fill out the chart with more production data as we go forward.

And then Jeff here again. Just real quickly and then lastly, of the 4 wells that we're going to spud by year end in Eastern Montana, 2 of those wells will be just south of that Charley-Gobbs area. So we clearly like it. Will Green - Stephens Inc.: Okay. I appreciate the color there, and then one more for me. The completion that you guys are doing with the half sleeves, have perf and plug, any estimate on how much that well cost will compare to just a typical full plug and perf Bakken well? A. Langford: Well, we haven't really looked at exactly what that's going to be because we don't know until we actually execute the plan, but our goal is to test the tools. We may take extra precautions at least early on and then to compare the production to the direct offset wells that are all perf and plug and see how they respond economically. So really what you're trying to do is do the same thing we're doing with the zipper frac, you're trying to do 3 wells in the same time it would take you to do one well with just the single well perf and plug method. And so we're testing it, but we've also got to have the same results in production that we see using perf and plug. And so It's going to take us a while to be able to determine that.

Our next question is from John Freeman of Raymond James. John Freeman - Raymond James & Associates, Inc.: First question on the rig program where it says in there that you all have the option to drop an equal number of conventional rigs as you add these walking rigs. Should I -- I'm trying to think of how to think about that. It seems like most of the slides are sort of referencing the ramp to 12 rigs and not necessarily the 14 you're going to have in July. So right now, we're sort of assuming that you sort of high grade on those last 2 rigs and you take the 2 walking and you drop 2 conventional in July? A. Langford: This is Lance speaking. Right now, that's all we've announced and that's what we have approved by the board is to go to 12 rigs, so we built our contracts in. So when we receive the newbuilds and the new technology rigs, we'll be able to drop one of the older conventional rigs. And so that's the assumption I would make for now. That being said, it's obvious that we have more NAV that we can bring forward through further acceleration, so you can always assume that we're looking for ways to try and accelerate. And it's just depending on our financial capability to do it and our manpower and those issues. So we're always looking for opportunities though. John Freeman - Raymond James & Associates, Inc.: Okay, that helps. And then given the new -- this initiative on the Smart Pad initiative, how should we think about, right now once that's sort of in full-scale mode, how many rigs can one frac crew support, one dedicated frac crew? A. Langford: Well, you can take that 3.9 days per well and the 3-well zipper frac, but we try to give you the details because we don't have -- and that includes the rig moves and everything. We don't have full-scale 3-well zipper frac development. We're stepping into it. We've only done one. We're going to get that down less than 3-point days per well but. . . John Freeman - Raymond James & Associates, Inc.: Well, maybe some color then on just how many days it takes to drill a well than using the pad. Like I see all the numbers on the completion side, I guess all they really need today is the drill then. A. Langford: Well, it is approximately 30 days to drill a well. John Freeman - Raymond James & Associates, Inc.: So that doesn't really change? A. Langford: Well, the pads, it does. It's probably going to save some time. I'm going to say it's going to -- on a 3 well, it's going to save probably 3 or 4 days per well. John Freeman - Raymond James & Associates, Inc.: Okay. And then just last question, I'll turn over to somebody else. As you sort of move out and you go to the 2-well zipper frac, you go to the 3 well, like, how far can you sort of push the envelope? Next quarter, you're going to be testing a 4-well, like how many of these can you do? A. Langford: We are going to test a 4 well and we will be drilling and completing 4-well zipper fracs as we go forward. I think that the 3 wells we should be able to maximize on a 3-well zipper frac. The 4-well will just -- it'll be just more efficient, save us a 2-day move and rig up costs I think beyond that. But I think on a 3-day, we should get it down to about 3 days per well on the zipper frac for 3 or more.

Our next question is from Scott Hanold of RBC. Scott Hanold - RBC Capital Markets, LLC: It looks like you guys have held the line on CapEx, which is definitely good to see here. Can you all talk about what you're seeing on like individual oil costs, and I don't know if there's a sort of a good number to put on some of the Smart Pad wells you've drilled now versus sort of the other current standard wells? A. Langford: Well, this is Lance. So our AFEs are still in that $8.9 million or $9 million. We haven't adjusted our CapEx. We haven't seen an increase. We're starting, just now, starting to see the benefits of the Smart Pad drilling. We're going to see more and more, that's why I kind of -- we broke out how many wells we're going to drill on the Smart Pad. Try to talk about converting our rigs to walking rigs that further reduce our cost and how that's going to happen over time. And then same thing with our zipper frac completions, how many on a go-forward basis are we doing, 2 and 3 well. And how, over time, that will be a higher percentage. So it's hard for us to say right now. We've just got early time results. We feel confident that as we move through and we become more and more full scale and we get more efficient at doing the zipper fracs and walking rigs that our costs are going to go down. But we really don't have enough of them to really estimate where are we right now. So I think as we go through the next quarter and the following quarters, we'll have a better idea to give you on how to reduce that cost and how we're doing currently. Scott Hanold - RBC Capital Markets, LLC: Okay, that's fair. And are you all looking at -- I know you talked about looking at using sand or resin coated [ph] versus ceramics, and obviously you're testing sliding sleeves. Are you still looking at sort of the proppant right now and utilizing some less costly proppant? Or are you pretty much committed to ceramic at this point? A. Langford: You know currently, we're still committed to ceramic proppants. And we are trying some things. We've tried to do the ceramic proppants as far as availability is a problem. It's not like it's any easier to access than ceramics and we've got a good flow of ceramics. So we've stayed with ceramics to date. Scott Hanold - RBC Capital Markets, LLC: Okay. And with the, I guess the new technology sleeves you're going to testing, why not try like a well just using sleeves. Why make it a hybrid, just out of curiosity? A. Langford: Well, because the well cost is approximately $9 million. We'd hate to risk the entire wellbore with a technology that we're not confident of. And then also, the sleeves themselves, I think the maximum number of stages you can do with these new technology sleeves is like 17 stages. So because of those 2 reasons. Scott Hanold - RBC Capital Markets, LLC: So we get [ph] was Baker? So those are Baker technology? A. Langford: Baker and Halliburton are limited. They can't do the 30 stage with this new technology.

Not yet anyway. Not yet. A. Langford: And that will be their next step. Scott Hanold - RBC Capital Markets, LLC: Okay, understood. And what -- now you guys completed 21 wells in the second quarter. What is the -- can you remind me what the full year wells you're going to drill and complete and kind of what do you think the third quarter would look like? And obviously, 21, what does that potentially look like in the third and fourth quarters? A. Langford: So we talked about the Williston Basin, what we budgeted for was, and this was based on the CapEx budget we announced in May, was 74 net wells in the basin. So you're talking about the 21 would be a gross number. Is that a gross number you referenced? Scott Hanold - RBC Capital Markets, LLC: That's correct, yes.

Yes, because we've done 20 net to mid-year. We completed 20 net to mid-year. Scott Hanold - RBC Capital Markets, LLC: Okay. I mean, so when you look at the third quarter, you did 20 gross -- I'm sorry, you did 20 gross, 21 gross in the second quarter, I mean does that look like something like, I know based on my numbers, it looks like 30 -- somewhere between 30 and 35 gross in each of the third and fourth quarters. Does that sound about right?

Yes, I think kind of when you think about it Scott, we've said we'll complete 8 to 10 wells per month with our 2 dedicated frac crews, but we might be able to do than that with the 3 and 4 well zipper fracs that we're doing. So hopefully we'll be at that higher end of completions per month.

Our next question is from Rehan Rashid with FBR & Company. Rehan Rashid - FBR Capital Markets & Co.: Just a quick 2 questions. Any application of highway frac in your area? A. Langford: Schlumberger uses the highway frac and I've heard that there are some operators that are trying the highway frac in the Bakken. We've not heard any results. We had originally had Schlumberger bringing us a frac crew to do some highway fracs, but they had an entire frac crew quit and go to work for another pumping company. So they got behind on their frac jobs. Hopefully, we'll hear some results from some of the other operators that use Schlumberger currently. So we're very interested in hearing. Rehan Rashid - FBR Capital Markets & Co.: Got it, got it. Continental had mentioned middle and I think lower Three Forks a little bit deeper than kind of what you're doing now. Does that -- any color on that from your perspective?

Jeff here. Yes, it's obviously, we're very interested in their comments and what they're seeing. We have cored a number of wells in some of our areas. And typically, we've just cored that upper Three Forks carbonate cycle and what they're talking about is that middle Three Forks carbonate cycle. But one of our cores in Rough Rider actually touched that second cycle of carbonates and we saw oil for us. And so I guess as we go forward, we're also going to look to see if we can maybe core another well, probably in McKenzie County and see if we can add another core barrel and get a look at that rock and that second -- that lower carbonate cycle as well. It's very exciting development. We're definitely very interested and encouraged by it. Rehan Rashid - FBR Capital Markets & Co.: Good. One nuance. So by year end, with your gathering lines coming online, any impact on what -- maybe quantification of impact on OpEx?

We really haven't issued anything. We haven't really tried to quantify. I mean we obviously have some modeling work that we're doing on the Midstream business and some quite detailed modeling work, but we've not really offered -- made any of that information public yet.

Our next question is from Mike Scialla from Stifel, Nicolaus. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Gene, you laid out some assumptions based on current AFEs and recent strip prices in your 12 well -- or excuse me, 12-rig program. You said you'd dip into the bank line before the project becomes self-funding. Can you give a little more detail on that? How much do you model that you'd draw into that bank line and when would you become self-funding?

Well, I mean the borrowing base is currently at 325, so I'm just saying that based on those 3 assumptions and not assuming any other external source of capital, the message is that we can live within the liquidity that we currently are in control of, which is a combination of cash, the marketable securities which is our cash equivalents and the availability under the credit facility based on the borrowing base that was determined back in January. So obviously, we'll be reevaluating the borrowing base in October and we would expect to see a nice increase in the borrowing base, which would further enhance our liquidity position. So we're just saying that based on those sources of capital, without any other transaction, without any other conventional asset sales which obviously we're pursuing a number of initiatives that, that -- and the 12-rig case that we can finance any cash flow shortfall with essentially what's on the balance sheet. Michael Scialla - Stifel, Nicolaus & Co., Inc.: And in terms of -- based on those assumptions, when does it look like to you that the program would become self-funding? Is it a next-year event or is it further out?

Not next year, but in 2013. We've got a number of different cases that we were on. So what we're doing is we've created a bridge to going free cash flow positive. Now obviously, there's going to be, down the road, an interest in further acceleration. Those are not the kind of things, given what we've seen with oil prices here over the last several days that we're really -- we're looking at those scenarios and want to be prepared that when the time has arrived that we'll be in a position, and certainly with the drilling results, we'll be in a position to announce further acceleration. But as it stands now, we're living within the CapEx budget that we announced in May, the $669 million of drilling CapEx. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Yes, okay. And I know the weather impacted your ability to complete wells and it drove up your LOE cost in the second quarter. Did it cost you to curtail or shut in any production during the quarter?

A little bit.

Yes, a little bit. Mike was asking about the production impact from the weather issues in the second quarter. A. Langford: We didn't shut in any wells.

Right. I mean we still had to shut in wells, trying to move barrels of oil off location. What we were able to do is continue our completion and drilling operations and the completion side primarily because of our Midstream assets that were in place. And moved water, frac fluids to the locations to allow us to keep frac-ing.

And obviously, we ended up at the low end of guidance in the second quarter versus -- when we issued our guidance back in the end of the first quarter, we gave you a range and we expected to be able at least at the midpoint.

So it did impact us.

Certainly, that was a big contributing factor that caused us to be at the low end of the guidance range. Michael Scialla - Stifel, Nicolaus & Co., Inc.: It was really the activity level, not so much -- it sounds like, if I'm hearing you right, you didn't actually shut in or curtail production all that much? A. Langford: No. We shut our production in. It was moving the oil barrels off the location. That's what cost us. We weren't able to do that during some of the weather issues and that caused us to go to the low end of our guidance. If we had shut those barrels in, we would definitely have been much higher in our guidance.

So it's really, it's more -- that was the issue that impacted second quarter numbers, production volumes versus the activity level, which is..,

More so than the activity level.

Yes, more so.

So it would have been worst have we not been able to continue our operations and our drilling and completion operations. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Okay, got it. And then, Lance, that $9 million you referenced, I assumed that was based on your kind of standard 30-stage frac, was that right? A. Langford: That's correct. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Okay. And just a last one, I think both Bud and Jeff had mentioned on their prepared remarks the Scallion and Lodgepole, any update on the timing of testing those zones?

Not at this time, and we're definitely mapping hard. We're looking at all those intervals and I think you'll definitely see us something early like '12. You'll see us test maybe one of these horizons and that we're trying to find the optimal place and...

And we may not be as -- we may be a little bit tight with some of our activity there early on for competitive reasons.

Our next question is from Rehan Rashid of FBR & Company. Rehan Rashid - FBR Capital Markets & Co.: Just a quick follow-up. If oil prices stay low here, when do you get the chance to maybe renegotiate service costs with your providers, how long are your contracts for?

This is Jeff, and just a general statement and Lance will have more specific better points to make. But I mean, we saw in 2009, costs came down by 40% or 50%. So clearly before prices did deteriorate further or maybe even at these levels, it definitely shifts a little leverage our way. Lance, you want to add to that? A. Langford: Yes, the service costs usually lag 3 to 6 months behind activity. So, I mean, you could see some happen pretty quick, but I would expect capital costs to drop in at least 3 months to really 6.

I mean at the end of '08 we're 5.5 [ph]. And by mid-year '09, we were 6.5, low-6s. So that was 6 months and that was a pretty dramatic -- those were very unique circumstances. A. Langford: And that's typical. It usually takes 3 months to start really seeing it, 6 months to fully see it. Rehan Rashid - FBR Capital Markets & Co.: But holding off acreage, will that keep that, maybe the fall-off maybe a little bit longer or further away rather than 3, 6 months? A. Langford: Well, I think it is impacting us. I think you're seeing the gas market to continue to drill well. They stayed pretty high in those areas, but I would assume the markets would only take the structure in capital for so long.

Yes, we don't have to keep 10 or 11 or 12 rigs running to hold our acreage. We would certainly adjust the -- and we devised our hedging strategy to accommodate -- creating the opportunity to maintain a certain level of liquidity that would allow us to fund a certain level of activity, get our acreage converted to held our production and we're way ahead of that.

Our next question is from Brian Lively from Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Just a follow-up question on the discussion around current cost and commodity prices. Do you guys have a sense of what, assuming costs stay flat for 6-plus months and the commodity prices have around $80 where we're at today, what type of program have your hedges basically locked in?

Well, the $80, you're saying $80 NYMEX? Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: $80 NYMEX, correct.

I mean our hedging program is really was designed -- the bulk of it was designed at $65 and $70 and $75. So at $80, the differentials -- if they're in the neighborhood of where they are today at roughly $5 or $6, you got to see some further deterioration in commodity prices to have our hedges really materially kick in. Now there are some obviously -- some of the more recent hedges that we've added in 2013 have higher force in terms. But in terms of very near-term volumes, that will be rolling off, those were done at closer to the $70, $55 to $70 floor neighborhood. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: And so if prices stay where they are and you have a 6-month or so gap before you see the cost come down, do you guys imagine that you would continue to ramp the same program that you're planning right now?

Yes. I mean if you look at the returns, we're still around or just north of 50% rate of return. Payout of these wells is less than 2 years and NPV of $8.7 million a well. It's obviously very attractive rate of return projects. We're compounding a lot of value. And as the efficiencies that Lance talked about start to roll in that cost will come down. Further, those returns will come up given all other costs and the commodity prices stay the same. So I would think that the margins and returns would, in that scenario over time, get better with more -- a little more leverage shifts to our side as well on the cost side to maybe get those costs down a little bit and thus further enhance the margins and returns. A. Langford: Right. I wouldn't think that we would shut down our machine for 3 to 6 months because the costs are a little higher and our returns are 30% rate of returns. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Right. But if you think more basin-wide, if most of the operators are having similar returns and no one wants to cut activity, it means that costs would probably still stay high.

Brian, I think one thing Lance showed us is not all the returns are the same. We're fortunate we're in the core best areas. And so our returns are one or 2 relative to all our peers in the area. So I think what you'd see is some of those guys out in the less attractive areas, the more marginal areas, they're going to be -- they'll be compelled unless someone would destroy capital or not generate solid returns to produce the level of activity. But our returns, we're in the best resource play in North America and the favored commodity and the downside commodity price environment, service providers, you're going to have to reduce the cost to the E&P companies to generate some normal level of activity. We'll be the operators, so I think actively drilling in that environment.

And it's not to say that obviously when you have that of deterioration in pricing that we're going to react to it. And we're looking at a number of different scenarios right now to think about further acceleration down the road. So clearly deterioration in pricing is having an impact, although maybe -- might not be as visible to the street. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Understand. And Lance, question for you on, like all the performance graph that you showed. My question is if you look at your type curve, the 500 to 700 MBOE range and you consider the number of frac stages and just you show the graphs of where the more recent wells are more on the high side of that band of well results. Can you guys talk about, has the average gravitated more towards the upper end of that 700 high number? Or you guys still pretty comfortable with the 600 as being in the true average of the well you're drilling today? A. Langford: I think the average falls in between 500 and 700 and you got to remember we're also stepping out into Montana and trying more Three Forks wells in Rough Rider and when you did the step out on the edges, you're -- sometimes your reserves per well go down. So I think we still -- our average overall is 500 to 700. Of course, you got the Ross area with higher rates and EURs than the Rough Rider area, so it's a blend of all of our wells that we're drilling. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Sure. And can you remind us again what you're assuming as the turn around [ph] of economy rate? A. Langford: We're using the 8% final decline. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: And so if you change that 8% to 6% or 5% or 4%, it would seem to have a pretty big impact on recoveries per well, but what impact would that have on the NPV calculation? A. Langford: It's very little. It's in the single-digit range on percentages increase. Most of the values in the first part of the curve and the first 10 years and you start adding the 6% final decline, it's just adding reserves per well, but really minimal NPV and that's why we think it's -- we don't really know what the final decline is going to be because we don't have wells old enough and really our third-party engineering firm has insisted that we stay at 8% final decline until we get more data. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.: Yes, I understand. I just think the -- a lot of, I think other operators are using lower final decline rates and so it just kind of puts a mismatch between the comparison of EUR guidance. And so I think -- that's why I'm kind of really focusing on the first couple of years and trying to just understand are the wells now coming in more towards that upper band and I understand the comments, so I appreciate it.

I agree, Brian. I think the final decline is going to be shallower than 8%. And I realized I look at the other operators that are around us and I see what they show us in average. My guess is they're using 6% final decline or less. But really I think we're doing the right thing and I think I'm very confident in our numbers.

At this time, I'd turn the call back over to Bud for closing remarks.

Well, again, this is Bud. I want to thank everybody for their participation in the call, and we really look forward to reporting what should be a very exciting third quarter. Thanks again.

Ladies and gentlemen, this concludes today's conference. You may now disconnect. Good day.