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…

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,…

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…

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…

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.

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.

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?

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.

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.

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?

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?

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?

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.

Well, it is approximately 30 days to drill a well. John Freeman - Raymond James & Associates, Inc.: So that doesn't really change?

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?

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.

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?

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.

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?

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.

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?

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.

So we get [ph] was Baker? So those are Baker technology?

Baker and Halliburton are limited. They can't do the 30 stage with this new technology.

Not yet anyway. Not yet.

And that will be their next step.

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?

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?

That's correct, yes.

Yes, because we've done 20 net to mid-year. We completed 20 net to mid-year.

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?

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.

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?

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?

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?

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.

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?

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.

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?

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?

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?

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.