Battalion Oil Corporation (BATL) Q2 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Halcón Resources Q2 2014 Earnings Conference. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Chairman and CEO, Floyd Wilson. Sir, you may begin.

Good morning, everyone. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday and posted on our website. So our second quarter results were an indication of enhancements achieved in every area of the company. Our 3 main plays: the Williston Basin, the El Halcón in East Texas, TMS are all moving ahead. All of our production is coming out of the Williston Basin and El Halcón at this time. So second quarter of '14 production of over 42,000 barrels a day equivalent was a record, despite selling 3,700 barrel a day of equivalent in May. This is 15% quarter-over-quarter growth. We have -- company-wide we've got 14 operated wells being completed or waiting on completion and probably 3x as many non-op wells as that. We're running 8 rigs right now, 3 in the Williston, 3 in East Texas, El Halcón and 2 in the TMS. A few couple of comments about each area. The Middle Bakken and the Three Forks in the Williston Basin had an outstanding quarter. Congratulations to John Wright and his great staff for that. Production grew 87% for that business unit year-over-year, and 22% quarter-over-quarter. We're in an average of 4 rigs during the second quarter, but we recently dropped a rig due to efficiency gains. We're drilling the wells more quickly so we're getting just as many wells completed with fewer rigs. We continue to make progress towards solving for even more efficiencies. Some of those are having to do with pad drilling, simultaneous operations and a few completion tweaks. On average, the 18 wells we put online, and they were all in the Fort Berthold area during the second quarter, are outperforming our 801,000 barrel of oil equivalent type curve. Currently, we're focused on continued improvements and improving economics by lowering completed well costs but without impacting production rates in EURs. Downspacing test have yielded really interesting results and positive. Based on our own work and looking at our own acreage, our current development plans are to proceeded with spacing wells at either 660 feet or 880 feet apart depending on where that well lies within the basin. In summary, the Williston Basin continues to improve. Our assets there and staff are performing outrageously well. El Halcón in East Texas, the Eagle Ford of East Texas, a great quarter for the staff. Thanks to Nick Koch and his great staff for that -- production grew over 450% year-over-year and 30% quarter-to-quarter. Progressively, the wells are getting better every single quarter. The wells put on line during the second quarter are performing in line with expectations, but are outperforming the wells in the first quarter. And the wells that we've drilled so far and completed so for in the third quarter, outperforming those in the second quarter. So results continue to improve, and all the wells we've put on this quarter are outperforming our 452,000 barrels of oil equivalent type curve. A couple of data points on IPs. IP rates for wells put online in 2Q were -- was 804 barrels a day, better than the average IP of the wells put on in one -- first quarter. Average 30-day IPs for wells from the second quarter was 620 barrel of oil equivalent per day, also a large improvement compared to first quarter. We're still working -- changes and variations and enhancements and looking for inefficiencies. We are doing very little pad drilling here. We're not doing any spacing test right now. We're capturing leases and making sure that we have idle work accomplished, so that we can continue to drill. Title in East Texas is difficult. We're testing increasing stage link, tighter per cluster spacing, increasing the percentage of resin-coated sand relative to total profit. We're using different surfactants and then starting installing large bore frac plugs during the completion. Several artificial lift modifications continue to be tested and evaluated. And we continue to find -- to work to find the most economic completed lateral length. A lot of the length of laterals in East Texas often depends on the shape of leases. Our target is 7,500 to 8,000 feet if the lease shape allows. Oftentimes, we have hundreds of leases under one drilling unit. We have several wells that are drilling at 9,000 feet and we have a few that are drilling less, but our target is 7,500 to 8,000 feet if the lease shape allows. Interestingly, industry activity has really ramped up in this area. And currently, there are nearly 20 rigs drilling in the play. Our entire 100,000 net acre position has been de-risked in our estimation, and we believe our El Halcón potential is second to none in the area. Tuscaloosa Marine Shale, of course, is on everybody's radar screen these days. We're running 2 rigs in the play. And with continued progress and success, our rig count could easily double early next year. Economics are expected to improve over time as they have in every other resource play in the United States. We believe the quick win -- we believe we can reduce the number of drilling days by 15% to 20% on average throughout the remainder of this year. We understand that other operators expect to increase rig counts and all this leads to a lot more information in the field. If you think about the play, I guess there's been about 50 wells drilled so far. The first large number of those were not so good. A few good ones in there. The last 10 wells drilled in the play has been mostly good wells, so it's a traditional learning curve situation that's going on there and we're pretty happy to be there. We are working interest partner in several wells that are performing to expectations and give us added confidence that the industry as a whole has continued and will continue to make progress in this play. Specifically, the average IP rate of the producing non-op wells that are near us, that we have an interest in, has been about 1,100 barrels of oil a day, not including gas. Include gas as over 1,300 barrel of oil equivalent. So it's an early stage play and, as I said, we're very happy to be there. Our field services unit continues to work on several initiatives they have the potential to improve, realize prices and margins in all of our plays. Our first compression natural gas facility is expected to be in service by end of this quarter at El Halcón. We'll use CNG to displace diesel fuel. This isn't only green but is also could result in a nearly 50% savings on fuel cost in frac-ed jobs and with drilling rigs. We expect to build similar facilities and service operations at the Williston Basin and in the TMS next year. HFS continues to provide low pressure gathering services in El Halcón and plans to support the TMS by building a 3-phase gathering system in centralized gathering facilities located throughout the play where we have clusters of wells. Centralized aggregation points are expected to reduce the overall cost of facilities and allow for more efficient transportation of both crude oil natural gas and produced water. Our central facilities will be located with access to one or more gas pipelines as well. The system design and layout are both substantially complete, and we plan to begin permitting for a processing plant at our facilities during this quarter. We also continue to develop a crude oil handling facility at the Port of Natchez in Mississippi. This is in the planning stage. That will be a facility capable of handling truck and pipe offloading from the TMS. And to market the crude via barge on Mississippi River or by rail. We're working on that as we speak as well. Mark Mize will now through our financial results.

Okay. Thanks, Floyd. Production for the quarter averaged just over 42,000 barrels of oil equivalent per day, but was above those 3 estimates and the mid-point of our published guidance. It's important to note that the second quarter production included the impact of over 1,600 barrel of oil equivalent a day that was sold in the first part of May. That production was associated -- that was the non-core expense of assets. We're also providing production guidance for the third quarter of 41,000 to 43,000 barrel of oil equivalent a day. We've revised the mid-point of our full year 2014 production guidance to 40,000 to 42,000 Boe a day. On the costs side, all of the work order [ph] expense came in at $9.13 per Boe in the second quarter, which is about 24% lower than the first quarter. As we'd indicated in the first quarter call, we are projecting to come in toward the upper end of our guidance range versus the $8 to $10. After adjusting for some selected items, cash, G&A expense for the quarter was $5.86 per Boe, which is about a 22% improvement compared to first quarter, and we are projecting tracks at the low end of our 2014 guidance. Taxes other than income came in at $7.92 million, and gathering and other expense came out at $1.54 per Boe. So overall, we're tracking to or beating the cost guidance that we have for the year. As mentioned, we have sold certain non-core assets in East Texas for about $450 million during the second quarter, which had an effect on our borrowing base of a reduction of about $100 million to our current base of $700 million. And, as previously disclosed, we also announced the signing and the closing of a agreement with Apollo Global management, which may invest up to $400 million in our wholly-owned subsidiary, HK TMS. In about mid-June of this year, Paulo did fund the first phase and contributed $150 million in cash consideration for 150,000 of HK TMS preferred shares, and they can acquire an additional 250,000 preferred shares of HK TMS on the same terms. As of June 30, we had undrawn capacity on our revolving credit facility plus cash on hand of $618 million, so that sets us up nicely from a liquidity perspective. And we expect borrowing base on our revolver to increase, when we have our fall redetermination here in the next few months. A few comments on D&C CapEx. We spent about $270 million during the second quarter, representing about a 19% decrease versus the first quarter of this year. D&C CapEx is currently expected to trend up in the third quarter, but then pull back some in the fourth. So overall, we're tracking to spend about $1.1 billion in D&C. And when you take the $150 million of HK TMS funding that came in from Apollo, it puts us right to our $950 million of guidance for D&C. Lease acquisition, seismic, infrastructure and other came in at about $224 million for the quarter. As part of our agreement with Apollo, we accelerated about $127 million payment to Encana on the acquisition of certain properties perspective for the TMS. We had originally planned on deferring these payments throughout 2014 and then 2015, but that was accelerated. We expect lease acquisition, seismic and infrastructure expenditures to be significantly lower for the remainder of the year. Finally, with regards to our hedging program. We continue to target a hedge portfolio, in which about 80% of our expected production is hedged for the next 18 to 24 months. Today, we have about 28,000 barrels a day of oil hedged for last 6 months of 2014, with an average floor just under $90. And for 2015, we have about 31,000 barrels of oil hedged on an average price of about $87, and we're continuing to keep our eye on opportunities to layer out positions in 2016. Our hedging program for 2014 is essentially complete. We have a little more work to do in 2015 to get to our target level. And with that, I'll turn it back over back to Floyd.

Thanks, Mark. Well, we're performing at a high level and continue to work on improving the economics in each of our plays. We're set to grow for the rest of this year and next, while keeping spending at minimal levels. Operator, we can take a few questions now, if there are any.

[Operator Instructions] Our first question comes from the line of Will Green of Stephens.

I wonder if we can start with El Halcón. You guys talked about the target of these laterals being kind of 7,500 to 8,000 feet. I think in the press release, you mentioned that these -- the wells in the third quarter so far, it started $10.91 on initial rate. Can you talk to just a sample set of those wells? How those laterals have looked? And then kind of how the frac spacing is checking out on those more recent completions?

How many wells are in that, just?

About 3 wells in that sampling.

This quarter?

Yes, just for this quarter. Two more that are completing next week. As far as the frac spacing -- you're talking about the well spacing or just the length of the frac stages?

How many stages in those? And then what the kind of -- I know all of these wells are going to be different, but kind of where the laterals are shaking out? How many stages you guys putting on this?

It all depends on our leases. Lease laterals would average, 60. They're all on a 6,200 to 7,500 range.

This quarter, with just a little of couple of 9,000 foot laterals?

Yes, They're 6,200, 6,300 were those, but where most those are a little longer than that coming up.

What's the stage life?

250 foot stage life.

250 foot. So however long we can drill the wells you can divide by 250 and get the number of stages because the wells are between 22 to 30 stages, I think.

Right. And then, you guys have a 100,000 acres there in El Halcón. Obviously, some really good results so far. Probably gives you guys a lot of running room. How are your guys thinking about that rig count as you kind of step towards into this year and into '15?

Well, we're able to keep this growth rate up with fewer rigs than we thought we could. So for now, we're going to run 3 or 4 rigs in this play. And throughout this year and next, we might add one. We'll just wait and see. We're pretty focused on, right now, on our spending program for next year and keeping it about what it is this year. So we just have to put it all together here before the end of the year. We'll let you know how that goes, but I think they've reduced rig days per well by another good 10% or 15% of this past 90 days or so.

Our next question comes from the line of Jason Wangler of Wunderlich Securities.

I'm curious on the Black Stone well. You just kind of give us a little bit of indication of the well was pumped all through the frac stages, but then there was some issues. Do you have an idea yet of how -- will the frac stages still be able to go off? Or will that shortened kind of the effective laterals? Or just kind of give us some color on that?

We don't know yet. All the -- I think there are 22 stages, they're all frac-ed well. We are just in that clean out process and we'll start flow back here. We're just not quite there.

Okay. Fair enough. And then, just possibly for Mark. He may have already answered this honestly is -- just a $150 million, obviously, from Apollo that already came in, when do you think you'll start to get to the point where you're going to go back to them for their next tranche decision? Do you think it's kind of be year end or first quarter time frame? Or which way are your thoughts there?

It'll be when 70% of the first funding is put into a drilling. We would expect that to be the first part of next year.

Our next question comes from the line of Neal Dingmann of SunTrust.

So, Floyd, just wondering what you've seen so far in these 3 CMS wells. Obviously, just the one you have down and, obviously, you've got a lot going on right now. As your thoughts changed as far as the way you're going to obviously drill and complete these? A lot of these guys talking about, above or below the rubble zone? Just wonder what you've seen -- 2 questions around this. Have your thoughts changed on how you want to sort of tackle these? And number two, just -- you had early EUR estimates sort of on your type curve -- is that changed either?

It's pretty interesting what's going on there, and Charles can add to this if there's something to be added. But you've got 3 operators running multiple rigs there now. All of those operators are targeting about the same area, if there aren't any other conditions that direct you to go somewhere else in terms of the placement of lateral. And the operators are actually a pretty tight range of frac job volumes of proppant and water. There are some differences, but -- so what you've got is currently everyone's following fairly similar programs and you're going to see more comparable results across the industry going forward than you've been able to see in the past between targeting and small fracs and large fracs and slickwater back in the day. It's just hasn't been as consistent as it is right now. Our thoughts on the type curve remain exactly where they've been. Our thoughts on cost remained at -- it's a tough nut to crack down here, but we expect to significantly reduced cost over a couple of years. And we haven't changed our thoughts along those lines at all. Anything else, Charles?

No, that's pretty well covered it.

Okay, great, Floyd. And then just one follow-up, obviously, in the Bakkens. Efficiencies keep adding. I guess it's safe to say that there's no -- I mean, would you add for, I guess, acreage up there if it was available, at this time? Just nothing available around your surrounding the areas or is there is a little bit of bolt-on still left.

Well, the whole basin is owned by someone as you know. So the only thing that you can do is buy someone else out and not that many sellers out there. I means, deals float around, but we've got a lot of land out there and number of years drilling inventory and these improvements are making more and more of our land, more attractive every day that goes way, there is improvements in frac design and results. So we're very happy with what we've, we're always looking though.

The next question comes from the line of Ron Mills of Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Floyd, you mentioned quickly in the Williston commentary about exceeding the Fort Berthold wells exceeding the 800,000-barrel curve. Can you give more color around that given that you brought 18 wells on during the quarter? How they came on relative to that 2,000 barrel a day rate in that IP? And is -- were most of those wells Bakken or Three Forks? Anymore commentary on the Three Forks under your acreage?

Well, of course, the -- it varies across the field. But in general, all the wells that we've reported in this -- I think this last group of well, they all are averaged well over 2,000 barrels a day, 2,500, 2,600 barrel a day, 2,550 barrels a day. That's average Three Forks and Middle Bakken wells. So we're driving wonderful wells and we're having great results and we're doing the best to tweak these frac jobs and see if there's still some room to go. It's pretty interesting that -- what looks to be a very mature basin unlike the Williston Basin. There's new heights to be scaled there now and new processes to think about. And it's really been pretty awesome. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then down in El Halcón. I know you had moved most of your rigs down towards the Burleson, Brazos border. I think you mentioned you're not doing much pad drillings, it sounds like you still have more lease capture there. Is -- the rest of this year I know Halcón really going to see rigs move across your position for more lease capture, and as we look to '15, start to get more into the optimization that more development type drilling provides?

We move the rigs around. We like the North end of our play, as well as the South end. There's good reason for that, and we've got some new great wells that are North of the of the Haynesville. [ph] That was a wonderful well. Some of our peers in the area had some great wells that are North in the field, so we're moving the rigs. We're not concentrating just in Burleson County at all. I think 2 of their 3 rigs are up in Brazos now, maybe all 3 for all I know. They're drilling these wells so fast, you have to read your drill report everyday and every weekend day to remember where the rigs are. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then as more -- with almost 20 rigs in the play, it seems like that play is just being delineated much greater. I know you've concentrated your position in a -- that 100,000 acres and where it's located. Any opportunities to expand in that area and/or even in the TMS, as some of that play has moved a little bit to the Southeast into especially Tanga Boa [ph]?

Well, again, the acreage is pretty tight in the TMS, and we have so much that it would be like gluttony to just to think we have to have more. And at El Halcón, we were probably a little too conservative when we drew our map the first time. And I mean, we outlined a bull's-eye there. That has been 100% accurate, but our bull's-eye could have been a little bit larger. Some of the smart Companies who come in there and bought land all around the edges of where our bull's-eye was and they're doing quite well. So it's very tight there too. So I -- we're always looking in any of our areas, but we're not seeing any large deals in the Williston or the TMS, or in El Halcón that are in the area that we'd want to be and at this time. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then one last one. The CapEx, Mark. You've talked about $1.1 billion, with the Apollo deal, the $950 million, is that the right way to look at your D&C? Kind of net of the Apollo contribution at that, I guess, net Halcón or Halcón CapEx remains in that kind of $950 million to $1 billion range?

Yes, yes, that's correct. When that $950 million was put out the Apollo deal when contemplated, so we are still tracking to $950 million with the Apollo funds that came in.

Our next question comes from the line of Robert Bellinski of Morningstar.

That was a pretty nice decrease in op cost this quarter. I was just wondering can you go into what was driving that improvement? And should we now expect op cost remain at the bottom of your guidance for the rest of the year?

As far as -- I guess, the short answer would be the production. As you know, we'd be -- our internal guidance on production, but we also indicated that LOE is probably going to track towards the higher end of published guidance, but, again, a short answer to your question, is production.

Okay. And then in the TMS, how many core samples do you expect to recover? And are those just planned for Wilkinson County at this point? Or are you looking to pull some samples across your position? And then as a follow-up, do you guys have any preliminary thoughts that you can share at this point?

We just record 200 feet of continuous conventional core in the Smith well. And that was an area of the play that did not previously have conventional core. But between us and the other operators, there's about 10 cores now. Few other operators would be getting a couple of others that we'll have access to, so that we don't plan on taking any others near-term right now. But we got fantastic data in the Smith well, in the core, and all the modern suite of logs we ran in. That well maps out as being having one of the highest original places of any well in the whole field .

Our next question comes from the line of Dan McSpirit of BMO Capital Markets.

A question on the TMS. If we look out 12 months from now, on the play, what should we expect to see in terms of drilling complete cost, production profiles and maybe ultimate recoveries? That's a, I guess, it's a long way of asking about expectations on fuel level of returns. And how they're expected to change? And what is the internal hurdle at the company that is the internal rate at the company that needs to be met?

Well, taking this in reverse order, the -- our internal hurdle is our published type curve. And the cost side of that is to get the cost down within 2 years from where they are down to that under $12 million range, somewhere within that range. We're very comfortable. We're going to make it on the production side, and that the industry is going to make it by the way. The costs -- it's a tough deal down there, and it's a hard area to drill in and hard area to complete wells in. But I think 1 year out, you would expect to see less trouble from all the operators. You'd expect to see more consistency in terms of completion, design and targeting because we're all conversely -- we've got a really awesome information sharing agreement with the other large operators in the play, and we're very open and supportive with all of them. They're great, great people to be in business with. So I think you're going to see a steady inching down of cost. And if it follows the pattern of these other plays, Dan. You have to understand that the type curves in other basin started out at where there's 300,000 barrels or 2 or 3 Bs or something, and I didn't find the best wells early. They didn't find the best geologic spot early, nor did they find the best completion technology early. So I'd be surprised if there's not a few million barrel wells down in here within the next year, but I don't know that.

Okay, great. And then, just as a follow-up to that. You gave us 2014 CapEx and production guidance, appreciating it's only July 2014. Can you sketch for us what next year, that is 2015 could look like in terms of the same, that is CapEx and production growth?

Well, we don't have a projection out in the public, on that yet, but we're going to try to spend a similar amount of money and try to grow at a similar pace. So that's not guidance, that's just what our planning is leading us towards. And that's where our goal is. But we're just not quite ready. We -- a lot is going to depend on what goes on in the TMS. In terms of additional growth, we can make our growth plans with our 2 great core areas that are hitting their stride right now. Incremental with the deal that goes on in the TMS.

Okay, great. And then, lastly here, just on lifting costs on LOE. Just to clarify, if I heard correctly, that they're expected to track toward the higher end or no?

Yes, that's correct. Our guidance range is $8 to $10. We were $9.13 for this quarter. We expect to stay kind of on that higher end as we finish out the year.

Our next question comes from the line of Jeff Robertson, Barclays.

Floyd, just a question on Halcón Field Services. Can you talk in a little bit more detail about the port -- oil handling facility at Natchez and how you -- what kind of capital you might have for that in 2015? And is there an initial number of barrels that you plan to be able to handle in that project? And then lastly, would you, at some point, start to look for a partner to come in and help that project like you all did back in the Haynesville?

The capital associated with this best project, if it's fully -- if it's gets fully built, as what we examine -- as what we think, it's not that much. So for right now, the idea is to get your crude oil away from a local market, which would be a truck market controlled by refiners and perhaps local buyers, and get it floating on the Mississippi river or get it to a rail to where it can be used for others. Most of refining capacity in the United States is available to that area. It can be used for blending or whatever. So for now, we're doing all the planning. We've acquired some land and, which is very small amounts of money. We haven't really published the numbers on that, but it wouldn't happen until later in '15 in terms of the spend, but it could be $15 million or $20 million initially. And it's not a ton of money and -- but what you could find yourself is gaining dollars per barrel in terms of price discovery as opposed to just spending money. And so I -- we're really high on it. What we've done in the past, is make sure that if an idea is going to -- is working that we built far enough out that our own plans are going to be served, if you bring someone in that maybe has a different capital plan in sales or something. So it's so premature to talk about bringing anyone in and anything like that, but we would intend to get storage capacity up pretty high in the hundreds of thousands of barrels. We would think that it would be a good outlook for others, but it's early to get into that. The only reason we ever brought it up is somebody along on these darn log or something noticed we bought some land there in Port of Natchez has been started to screaming their Facebook off about it or whatever. So we just thought we'd better mention it.

Then one other question, Floyd. Have you all learned anything from your activity in the TMS that makes you think differently about the acreage you have over to the West?

No, we just have so much acreage in Wilkinson County, just South of Wilkinson County. We just don't have to think about that acreage to the West for some longtime. What we've learned is that we had a really good show there, and we lost a well before we were able to get the full things drilled, but we had a really good show. It's a different part of the basin. It's a little hotter. It's a little gassier. A lot of crude oil over there, but we just don't have to -- we're just not going over there right now. I mean, it's pretty interesting, but it's just not on our radar screen this year or next for sure.

Our next question comes from the line of Andrew Coleman of Raymond James. Andrew Coleman - Raymond James & Associates, Inc., Research Division: When you look at the East Texas basin, do you have any depth restrictions on the acreage there?

We have some areas where we've acquired just the Eagle Ford rights. Our depth restrictions, generally speaking, are more to the tune of being restricted as the more shallow, but I think there's a few areas that we don't have Buda rights. But by and large, we've got the section that's on both sides of the Eagle Ford and most of our 100,000 acres. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay. And then, I guess, if we look at the oil mix, I mean, at this point, the differentials are primarily, I guess, skewed by Bakken barrels at this point. I think that was your previous discussion, one of the questions, a couple of seconds ago. But as you bring on the extra TMS barrels in that, do you have a view as to where differentials may trend to, aside from tighter?

Well, we're going to expect that -- if you just think of this in a general sense. Since it's closer to refineries, both El Halcón and the TMS and the Williston Basin, it's always going to be a price advantage just because of the simple cost to transportation. In terms of Louisiana Light brand, heavy crude from the Canada or -- and all this stuff, I don't know about all that is, it's a pretty complex thing that's going on. We just think that, that area is going to be -- have a small advantage over other areas just because of its location. Andrew Coleman - Raymond James & Associates, Inc., Research Division: All right, good. And then last one, is just getting back to the cleanout operations, again, I guess, I mean, how long would that job normally take? And I guess how common is that? I guess, you said you had that with the prior well?

Well, how long it takes, I'm not positive. We're pretty cautious down there. It's clearly a sign of it's not something we like to find that have some fill in the casing. That can come through perforations or it can come from a casing problem. We'll figure that out. What we do know is that our job there is to get flow going, and we will report it as soon as we do. Well, we'll report it. We're trying to report once a quarter, but it's hard to say. It should just be a few days to finish that phase and then get the flow. But it's just complicated at that depth, and you decide you need a different tool or you need another string of pipe. We did go on cold tubing, and we decided that we were worried about doing that. So we brought in a natural completion rig with steel work pipe -- or work string to work on the well.

Our next question comes from the line of Michael Rowe of Tudor, Pickering, Holt. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I was wondering if you -- you all, obviously, had a lot of success with water fracs in the Middle Bakken formation. But I think you're still testing whether or not you think that will be applicable inventory for Three Forks benches. Have you all kind of made any new progress there on what you've learned in your test? Or it's still too early to tell?

It's still a little too early to tell for sure, but we're leaning towards the -- that it does not work as well in the Three Forks. The results right now don't seem to justify the extra expense in water for the Three Forks. We think it's just the physical nature of the Three Forks being underneath the Middle Bakken. And then going with the light slickwater fluids and the settling you have. You're not propagating that profit up through the session above you, as well as you do from going from Middle Bakken and propagating down in the Three Forks. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. That's helpful. And then, I'm just wondering, if you all provide an update on sort of how you all see your Bakken production and Three Forks production here into some of the -- take out black gas flaring reduction initiatives that are being implemented later this year? Are there any similar regions at your Williston program that concern you?

Well, the flaring has been a concern to us ever since we've got into the play. And we've been working as hard as we possibly can to get this stuff under -- in pipelines. At this time, we don't believe we're going to have any shut-in production if our partners in the midstream business up there are able to meet their targets of installation and flow on some of the large improvements in the capacity for gas up there. We're not quite -- we're not in total control of that, but right now our -- Steve help me out here, but I don't think we're planning to be or curtailed this year.

No. That's correct. Our plans are about 100% route wells with pipe put up to by the end of the year. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And just one last question, if I could. If we just shift over to the East Texas Eagle Ford for a second. You produced about 9,100 barrels of oil equivalent a day in the quarter. Just looking at sort of your production levels in April, May and June, I would have expected that may have been a little bit higher. So can you maybe just talk about the cadence of your production ramp in the East Texas, Eagle Ford throughout the quarter?

All these plays are dependent on frac schedules. And sometimes if you're real near some other wells, you have some other thoughts that come in, so you really have to look at this over more than one quarter to get a -- an idea of the ramp. I hear what you're saying, but I think the growth in that area was phenomenal for the company quarter-over-quarter and, of course, year-over-year. Our quarter growth that we had this past quarter is basically what we're planning on for the next couple of quarters. And maybe you will -- it'll see a little more smooth over that amount of time. We have, I think, 6 or 7 wells that have been drilled right now that haven't been frac-ed, and we've got a few wells that have been frac-ed that aren't quite on line. This is always a little bit lumpy. I don't know -- I don't think this is a real good answer to your question. We think we've done quite well there. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Understood. I was just kind of looking at some data points from some prior months, and I was just thinking about the full quarter, but maybe there was some shut-ins or things of that nature, but appreciate the color.

Our next question comes from the line of Sean Sneeden of Oppenheimer.

Most of my questions were answered. But maybe, Mike, on your preliminary '15 CapEx thoughts, would you describe your general plan there as you allocate more towards D&C than leasing if you kind of look at it year-over-year?

Well, we don't have any plans on leasing, except nominal fill-in stuff or trades with other people in the areas that we're working in. So at this moment, it would be a very small number as far as any thoughts about leasing. Drilling to completion, we're looking at, and again, this is not guidance, but we're looking to spend about $1 billion next year and it's -- that's going to be refined through the rest of this year. We'll make sure that, that's a good number for us. As I mentioned earlier, we're finding that in the mature plays, these wells are getting drilled more quickly, so you're going to get the same growth out of fewer rig dollars, But more completion dollars because you're drilling your wells more quickly. So we can actually drill with fewer rigs these days and hit growth targets. So again, don't take that as guidance. Somebody asked me what our general thought was, and that's the general thought that we're going to try to stay within last year's spend. We don't have any ambitions on large acreage positions at this time.

That's helpful. And then I guess just maybe based of off of those comments. It would sound like all else being equal, your cash flow outspend would be lower year-over-year or you know...

Well, it would be dramatically lower just as it's been year-over-year ever since we started the company. So yes, it would be lower because of the growth.

And this does conclude the question-and-answer session. I would like to turn the call back to Mr. Floyd Wilson for closing remarks.

Well, no remarks. Thanks for calling in. If we didn't answer something that you needed, just give us a call. Thanks.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a wonderful day.