Battalion Oil Corporation (BATL) Q1 2014 Earnings Report, Transcript and Summary

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

Thanks, and good morning, everyone. I'm a little hoarse today, sorry. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday afternoon. First quarter results were solid despite some weather-related downtime and associated drilling completion delays experienced in the Williston Basin. First quarter '14 production was above the high end of guidance. This production -- our production guidance for the second quarter represents 20% quarter-over-quarter pro forma growth and takes into account the sale of our Woodbine assets. We expect to close that sale of about $450 million within the next day or 2. And as we've reported before, we are entirely comfortable with our liquidity position. We continue to evaluate all our remaining noncore properties for future divestment. A lot of action going on at the company. Company-wide, we have 22 operated wells being completed or waiting on completion at this time. We're operating 8 rigs, 4 in the Williston, 3 at El Halcón and 1 in the TMS. We're adding a second rig in the TMS this month. And rig count in the TMS could easily double by early 2015 as we build a growth ramp there. Current plans call for spending roughly the same amount on drilling and completion CapEx in 2015 as in '14, about $1 billion. Up in the Williston Basin, production growth was fantastic, 73% quarter-over-quarter. We're currently producing about 25,000 barrels a day. That's -- 73% with first quarter '14 versus first quarter '13, 7% versus first quarter '14, as far as our guidance. Activity in the Williston Basin is back to normal after a very harsh winter. We generally were able to manage our way through this with a few delays, but not as nearly as bad as it could have been. We continue to make progress towards realizing efficiencies associated with pad drilling simultaneous operations and completion modifications. We are on track for a 5% or more decrease in completed well costs by year-end 2014 up in the Bakken and Three Forks drilling program. More importantly, though, average IP 30-day rates and the EUR estimates continued to increase. At the Fort Berthold Indian Reservation, we have a 10% improvement in average IP rate, first quarter versus fourth quarter of '13. 30% improvement in average 30-day rate, which is a great number, first quarter versus fourth quarter '13. And on average, all Halcón-operated Bakken wells online in the Fort Berthold area completed via slickwater frac continued to outperform the 801 MBoe average type curve that we put out a few months ago. Testing is underway to determine if the use of slickwater fracs on Three Forks wells in the Fort Berthold may yield similar results, but initially, we're thinking that our hybrid fracs will work best in the Three Forks. We're in the process of putting 6 new wells online that were drilled from a single pad and spaced 660 feet apart. The IP rate for 1 of those 6 wells was 4,225 Boe per day. That's a new company record. Up in Williams County, we had some wells we drilled last year, finished up drilling early in the quarter. We completed 7 wells up there using slickwater fracs during the quarter and we -- those wells are outperforming the 477 MBoe type curve for that area. Keep in mind, we have a very large development inventory in Williams County although we don't intend to run any rigs there for the balance of this year. Downspacing tests continued to yield positive results, and we're watching our, of course, our own results and our peers' results all around the field, all around the basin. We're currently in various stages of downspacing tests on 16 pads. This is 50 wells in the Fort Berthold area. And results are expected from several of those this quarter. Bottom line results in the Williston Basin continue to improve from their already excellent position. The El Halcón in East Texas production growth is almost exponential. It grew 843% versus the first quarter of '13. Sequential growth was very strong as well. Currently, we're producing over 10,000 barrel -- Boe per day, nearly 50% more than our first quarter average. While results continue to improve, average IP rates improved over 10%, average 30-day rates improved 15%. We continue to make progress towards identifying the optimal well design. Keep in mind, we've only drilled -- we only have on production 50 or 60 wells. It's early stage in a play of this nature. So testing is underway on a number of completion design variations to reduce cost and increase performance. These include increasing stage length while delivering the same amount of proppant per lateral foot via tighter perf cluster spacing, increasing the percentage of resin-coated sand relative to total proppant, using different components within the frac fluid and testing different frac assemblies. Also, several artificial lift modifications are being evaluated as we continue to work to find the most economic formula overall. We're also working on trying to define that point of diminishing returns in terms of lateral length. Not quite there yet. We continue to feel that the longer lateral lengths are yielding the better results. We expect well costs to decrease as we continue to transition to full-scale pad drilling. That's going on this year with a couple of our rigs. Another rig will still be drilling a single well test here and there. Based on results from step out wells drilled to the south of our initial position in Northwest Brazos, combined with results from other operators, our entire acreage position is being de-risked, and we've declared it commercial. In the TMS, we've added a few acres here and there. We now have over 316,000 net acres in the play. We're off to a solid start, drilled our first TMS well in Wilkinson County, Mississippi, a bit ahead of schedule and in about 39 days. It was a 21,171-foot TD with a 7,751-foot lateral. Completion operations are currently underway. We're confident we can reduce the drilling days by year end by 15% to 20%. We're drilling our second well now, the Black Stone minerals well, and we'll move in the second rig within 10 days or so. We continue to evaluate joint venture or financing options for the TMS. This is 100% about balance sheet management and future rig count growth opportunities as we and a few others guide this play into its place as a-- one of the premier large-scale crude oil-based resource plays in the United States. Our excitement for the TMS continues to build. Mark Mize can -- will now go over our financial results for the quarter.

Okay, thank you, Floyd. Production for the quarter came in above guidance and averaged right at 36,622 barrel of oil equivalent a day. It was about 3% above Street estimates, and that is, as Floyd had touched on, despite some weather-related downtime and associated drilling and completion delays in the Williston Basin. LOE came in at $11.12 per Boe in the first quarter, which was 8% lower than the fourth quarter of 2013 although slightly higher than expected again due to weather conditions in the Bakken this past winter. After adjusting for some selected items that we have disclosed in the table in our press release, cash G&A expense for the quarter was $7.56 per Boe and taxes other than income came in at $7.33, with gathering coming in at $1.54. So we are on track to meet our previously issued cost guidance for the year. During the first quarter, our borrowing base was increased to $800 million from $700 million in conjunction with our regular spring redetermination. We ended the quarter with undrawn revolver capacity and cash on hand totaling right at $452 million and then pro forma for the pending $450 million sale of East Texas Assets that Floyd had touched on and an associated $100 million reduction to the borrowing base. We had undrawn revolver capacity plus cash on hand of $802 million. We expect the borrowing base from our revolver to increase when we have our fall redetermination later this year. And we would expect to have that done before the third quarter earnings call. We're comfortable with our liquidity position for the remainder of 2014 and going into 2015, and we do not anticipate any type of capital market transactions to fund any of our drilling activities. If we decide to bring in a financial partner to assist in financing our TMS activities, the liquidity would, of course, be further improved by that transaction. A couple of comments on D&C. We did spend about $330 million during the first quarter. That's in line with our internal forecast. That sets us up for solid production growth in the second quarter. According to our business plan, D&C will decrease quarterly throughout the remainder of the year as we continue to improve operational efficiencies, which allows us to decrease rig count in certain plays at the company. Lease acquisitions, seismic and infrastructure came in at $128 million for the quarter. Most of the spending was related to growing our acreage position in the TMS, and we expect a lot of these figures to trend down significantly for the remainder of the year. Finally, with regards to our hedge program. We continue to hedge solely to protect our cash flow so that we can execute our drilling program. We continue to target a hedge portfolio, where we hedge about 80% of what we expect to produce over the next 18 to 24 months. Today, we have about 27,600 barrels per day of oil hedged for the last 9 months of 2014, at an average floor of just under $90. For 2015, we have about 26,300 barrels of oil hedged at an average price of right at about $89 and for 2016, we've hedged about 6,000 barrels. We are going to continue to keep our eye on 2016 and then layer in positions as we can. While our hedging for 2014 is essentially complete, we're about 60% or 65% complete for 2015, and we'll continue to hedge to attain our targeted levels. With that, I'll turn the call back over to Floyd.

Thanks, Mark. Hopefully, the takeaway from this call is that results are excellent in all of our core areas. We are on track to deliver or beat our plan for 2014. In each of these core areas, costs are under the microscope, and we will continue to reduce costs. Having the more important piece or pieces of the economic value equation are IPs and EURs. We are making massive strides in those areas. We build our pads and facilities for all-weather production, and our weather-related production losses are minimal. Operational excellence will translate into value creation for all of our shareholders. Operator, we're ready for questions if there are any.

[Operator Instructions] Our first question is from Neal Dingmann of SunTrust.

Say, Floyd, just based on, obviously, impressive results you've seen on that Horseshoe Hill on, obviously, drilling that thing. Your thoughts as far as timing just on wells going forward, I mean, is that you think going to be the -- you're going to see more like that? Or is that more of an aberration? And then your thoughts on cost on these wells, have that -- has that changed, I know at least based on your initial estimates?

Aberration, you mean an aberration on the low side or the high side?

Just how quick you did it, obviously.

Yes, as we've mentioned during the call, we fully expect to reduce drilling days, which is the first win in any of these horizontal plays, by 15% or 20% through the course of the year. I notice that one of our peers in the play has reported that they expect to drill their wells in less than 40 days, assuming no major trouble. We are planning on this sort of timing, but we would expect to beat it, of course. On the cost side, we're walking into this thing as we do in any new play with full analytical planning in place in terms of tools, logs, pilot holes, whatever we think we require. Our initial feel for the play is that we'll drill most of our wells, first few wells, for about $13 million. We think we can get that down about $1 million a year, each year for a couple of years. And our thoughts haven't changed along those lines.

And then, Floyd, what about -- I guess, how critical is the JV to either excel in -- excel the drilling dots there or potentially even adding more acreage? I don't know how many sizable leases are available, but your thoughts on how of much that would play into what happens on the JV or in the near term.

I might have mentioned it on the call, I'm not sure, but it's 100% about balance sheet management and about providing ourselves a sure path to future growth, meaning rig increases. So we decided to at least evaluate options at this moment, and it's not a critical item to us. We would only do a deal that's attractive to us. And it's just one of the things that we have determined that would be appropriate for us to review for this play. Our plans for 2014 and our current plan for 2015 will be unchanged in the absence of any kind of a new JV or some sort of financing of that type. The only thing that might happen, we might ramp up a bit quicker at the end of the year and into '15, and that's just -- and by the way, that's all based more on results than it is on money. We're well equipped right now financially to deal with this play. And we're well experienced, as you know, in this kind of thing. So the results are the first thing. We've got plenty of money right now. Ramping up is an objective, but it's an objective based on results.

Okay, and last one if I could, Floyd. It's just obvious on the El Halcón, the results continue to improve there nicely. Your thoughts about how they trend versus the type curve and thoughts about maybe even bringing that type curve up?

Well, we try not to move the -- we try not to move these type curves around too often. However, there's a clear trend as you move somewhat down dip for higher IPs and higher 30-day IPs, and these typically translate into faster payouts and higher EURs. So as we get a little bit more seasoning in the south end of the play where only about, I don't know, 10% of our wells have been drilled so far, not even 10%, we'll consider moving the type curve. We would move the type curve for the play for the sort of the public consumption. It's clear to us, we'll end up with probably 3 kind of regional type curves for our acreage and right now, the trend would be dramatically higher towards the south.

Our next question is from Brian Corales of Howard Weil.

And Floyd, just another question on El Halcón. You talked about going longer laterals. Can you maybe talk about your standard lateral and what you've been testing and kind of the result differences?

Well, we don't know that. We're shooting for longer laterals. I think we drilled a couple at 9,000 feet, and we've tested a few shorter laterals at 5,000 and 5,500, 6,000. I think our standard design calls for a 7,500. Charles, correct me there, is it 7,200 or 7,500?

7,500.

7,500 on...

7,900, the rest of the year.

Okay. So you don't quite know if that's perfect. It might be perfect for it to be 300 feet longer or shorter and depending on the costs. We -- our calculations yield that, that length is about the right length. And we also keep in mind in East Texas, we're constrained by the shapes of leases to some extent. And it's harder to put together units there across boundaries, much harder there than in almost any other area.

Okay. And then just into the Bakken, obviously, slickwater, both you and others, I think, this earnings season have talked about success. Is that going to -- do you think that's probably going to become a norm going forward? And is there a big cost difference?

Well, I'd like Charles to pipe in here, but it's certainly a norm for us in the Middle Bakken. It will not be a norm for us at this stage in our thinking in the benches of the Three Forks. The lithology is a bit different. As far as the norm for the industry, we're all a bunch of stubborn bastards in our business, as you know, and some of us are -- we -- like me, you have to get hit right between the eyes, I think, sometimes to make a change. Charles, what do you think?

Yes, I'm -- I mean, the results are in the pudding. We've had excellent results with slickwater. That being said, a modified hybrid design with some more slickwater upfront has worked great also, and that's what our last well is, 4,225 barrels a day is. So we're going to keep going with what works the best. We're never going to stick on one thing and say, "We have the absolute answer." We're going to strive to get the best.

And what about the costs?

It's a little higher because of the water cost, it depends where you are in the basin in general, but that's a problem you're always trying to solve to get water cheaper and find it in better places. And that is a limiting factor for some people in some places and why you might not see as many slickwater jobs also.

Our next question is from Jason Wangler of Wunderlich.

Just wanted to just double check and make sure still with the TMS stuff really heating up that, that's not part of your production guidance and obviously, you're doing a pretty good job of the first quarter. I just wanted to make sure that anything there would be kind of incremental.

Mark, you might have to help me on that one, but we might have a tiny slice of production in our 2014 plan. If we do, it's something we wouldn't notice whether it's there or not. Is that about right, Mark?

Yes, it's probably 500 barrels or something along those lines.

So pretty negligible.

Yes, yes, not much, and just vaguely exceed that, though.

Right. And that's kind of my -- that was kind of my angle there. And then just curious what the couple wells that you drilled and starting to drill, are there a lot of changes that you're looking to make as you drill these? Or are they all kind of going to go down the same ways and then learn from these as you kind of get up the learning curve? Just curious if there's any differences that you're setting up to make as you get into the play.

Of course, we're going to learn as we go. Charles will make a comment here. There are some variabilities over the expanse of this very large footprint play, some geologic changes that we take note of and manage our way through. Charles, go ahead and respond.

Yes, there's been a lot of wells drilled already, and we have the benefit of the learning curve that they've gone through. So right now, we feel like we have a good recipe down on the drilling side, and others do also. You're seeing every month, people come out with record drilling days -- time for drilling days. And we're right there with them, and we expect that trend will continue. But we don't see radical changes in the overall design of where you're setting casing and what you're targeting. That's kind of getting locked in for everybody right now. The completion side, like all of these plays, is probably where you have a little more room to tweak the designs a little bit to get better and better results.

Our next question is from Ron Mills from Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Floyd or Charles, you talked about in El Halcón and the drilling experience there over the last 15 to 18 months and how that may have helped you in the TMS first and, I guess, associated with that on the completion side, you talked about tighter perf clusters, but also resin-coated sands. Are those concepts also expected to be tested over in the TMS?

I'm going to let Charles answer most of that. I will say that in a general sense, and we've said this before, that El Halcón -- the El Halcón area is the closest comp in the United States to the TMS of Eastern Mississippi -- Eastern Louisiana and Western Mississippi. And we've had -- we've been able to gather a tremendous amount of knowledge from working in that very similar same-aged, very similar lithology section. So that has been, and along with as Charles mentioned earlier, the results from the other operators in the play has been a tremendous help for us to get off the ground running. What else there, Charles, is important?

That's exactly right. So we've taken what we've learned there. In fact, we took one of our best rigs from there and moved it down there, a flex rig and that crew. And -- so we've had all the learnings that we train them over a year of drilling with that crew of the way we like things done and do things in a safe and first-class manner. And so drilling there, combined with our experience, we're drilling 20,000-, 21,000-foot wells every day in the Bakken. So those 2 backgrounds are a perfect fit for the drilling in the TMS. And then on the completion side, yes it is similar to what we're doing over there also. And so we're taking that learn and combined with all of our hundreds and hundreds of wells we previously did in the Eagle Ford throughout the whole trend, and we expect to hit the ground running on that front with this first well.

Ron, in all these plays, it turns out over time that targeting is tremendously important. For the El Halcón, we have a very tight area to land and then be able to initiate your fracs. And we're well benefited by having that kind of experience and using it from the very first well on it in the TMS, because there's certainly a need for very tight targeting in the TMS. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And on El Halcón, you talked about the appreciable improvements as you've moved south from the Southern Brazos down through the Burleson County. Have you looked at your 100,000 acres that derisked now? How would you -- how is that acreage break out -- broken out from kind of the type wells up in Northern Brazos County versus what you and the industry are starting to see further south in the play?

We haven't really broken that out. We're still leasing. In fact, we've added significant acreage over the past month or 2. Significant portion of our acreage is in the southern end of the play, at least 50%. Let me just leave it at that. And now it's not just south. It's also down dip in Brazos County. So one of our very best wells, and maybe the best well in the play, I don't know, the Reveille is in the south part of Brazos County down near the line. And as you move east there, that's -- you can stay in Brazos County but go down dip a little bit. So you've got quite a wide swath of opportunities there that rather than define them as a county kind of a thing or across the river, whatever, we define them geologically, and we have a really large swath of acreage that we feel is going to be somewhat better than that core place we started up in Northeast Brazos County, which has worked out great, by the way, but -- so we're still in a competitive situation there, and we're not really talking exact spots or anything like that. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then lastly on the rig count. I know you moved 1 rig from El Halcón over to TMS. With the Plan B to kind of really stay at 3 maybe sometimes 4 rigs at El Halcón and just add an incremental rig in the TMS and then in the Bakken, is that 3 to 4 rigs versus the current 4 rigs, is that just driven by efficiencies and managing to that plus or minus $1 billion D&C budget?

It's somewhat managing to the budget, of course. But probably overlaying that and again, Charles could add to this, but we're finding that with this reduction in rig days per well and drilling these laterals in ever quicker time increments, we're drilling the same number of wells or more wells with fewer rigs as the year progresses, which sets you up for being able to drop a rig and -- but still plan on the same number or more of frac jobs, which leads to production growth. Charles, what else is at play there?

That's exactly right. I mean, that's the whole answer right there.

Our next question is from Chad Mabry from MLV. And we'll move on to the next one. Our next question is from Dan McSpirit from BMO Capitals.

Turning to the TMS, can you sketch for us what terms of deal with a financial partner could look like, should you go that route? I'm not talking about amount so much, but about structure.

Not really. The kinds of transactions that you could do along those lines, there's probably 10 or 12 different constructs that have been used in the industry, all the way from traditional JVs to just financial placements. And we would look to do something that suits our needs and suits our thoughts in terms of partner compatibility and cost of capital, and we would look for the cheapest cost to capital with a compatible partner that allows us to increase our targets there and not maintain them because we're already in a position to maintain. So I hate to give you such a weenie answer, but there's so many different -- if and when we do, then we'll report the major components of it, and you'll find that if we do one, it'll be a nice addition to whatever we're doing.

Okay. And then sticking with the TMS, can you share any expectations on early results from these early wells, including the Horseshoe Hill well? That is, what do you need to see in rate or pressure or other measure to confirm the investment was the right move?

We're looking for big a** results. I don't know what else to say. We've programmed the drilling and the completion for optimal -- at this stage of the game, optimal IPs and frac jobs that last, and we've equipped the wells appropriately. So we don't really have a formula. It seems to be that with the lateral this length and absent any completion problems, we should expect a really attractive -- certainly, an IP and a 30-day IP, but it's a little bit out in front of us here. To meet the type curves that we've proposed and to meet the type curves that some of our industry partners are using, you need a fairly stout start to make those work and others are doing it, and we expect to meet or beat our own expectations.

Okay, and then lastly here on other asset sales. How much production is associated with those assets? Again, these are contemplated asset sales above and beyond what you've done. And what are the estimated proceeds to be raised?

Well, we don't really have a ton of other targets. We have some other noncore production, and I think Steve's there, but -- Steve, is that a couple thousand barrels a day of noncore production that's not associated with the current core areas?

Yes, that's right, Floyd.

Is it -- okay, and those are, I think, largely in Texas. Is that right, Steve?

Yes. It's mostly in Texas and in a couple of areas, it's often chalk, and it's mostly actually gassy.

Yes, that's good production though. It's really good and that's why we've kept it and may keep it, but it's not troublesome. It's got good op costs, plenty of drilling opportunities there. Although, we're not spending any money drilling them. So there's some and then if we decide to cut a little bit deeper, there's some more. But everything else that we own on any significant production is quite good. And that's what we try to do with these -- with our planning is to get down to the best of the best and get rid of everything else.

Our next question is from Robert Bellinski of Morningstar.

Switching back to the Bakken, given these ongoing improvements in performance for these Bakken wells, is switching from ceramic to proppant to sand an option to save costs at this point? Or are there any other levers you're considering to pull to continue that cost improvement?

Charles, why don't you take that one?

Yes, we are starting to phase in some sand and going with the mixtures right now. So we are going that direction, and that definitely will save costs, if -- as long as we can keep getting the EURs. That is definitely a lever we are looking at very hard.

Okay. And then the drilling in the Bakken was exclusively in Fort Berthold this quarter. Looking beyond the next couple of quarters, is what you're continuing to learn there something that you can use to add rigs to your acreage in Williams County and maybe drill simultaneously? Or is Williams County now a second stage of development after Fort Berthold is pretty much drilled up?

Go ahead, Charles.

Well, and like Floyd said, those wells that we just brought on came on great in Williams, and those are downspacing tests. Those were really our first tests, and they're hanging in better than the type curves even though they're downspaced. So it's very encouraging for us and right now, we're putting the rigs where you do get your best bang for your buck. But we haven't put out next year's yet, but we'll probably be back up in Williams County, I would think, with certain percentage of our rig fleet.

Keeping in mind, Robert, that when you're doing pad drilling, you use a lot of your rig resource on one pad. So since we're doing all pad drilling, we intend to maintain that this year, and it makes no sense just to drag one of those rigs away. And it also makes no sense for us to try to raise our budget right now because we're doing such great work down on Fort Berthold. So there's a time and a place for those Williams County wells, and results are good and we're really grateful that we own those assets. And we'll be up there probably, as you said, sometime within the next few quarters, maybe in 2015.

Our next question is from Steve Berman of Canaccord.

Floyd, several companies have been in early stage of testing, what they're calling in upper Eagle Ford and different parts of the play, is a possible separate reservoirs. Just wondering if at El Halcón, that might be something you could have there. If not that, then any other formations you might look to go after somewhere down the road?

Charles, why don't you take that one?

We do have an upper section that has pay in it. We think we're frac-ing into it from where we are. And we don't really plan on changing what we're doing. We're in the sweet spot of the zone, and it's repeatable across the entire acreage position. So we're not really interested to go after some other hit-or-miss-type objectives. We're going to stay with what's working well.

Okay. And then one maybe for Mark. Can you talk about differentials in the Williston Basin first quarter and maybe what they're currently running?

Let me [indiscernible] real quick. So in Q1 in the Bakken, we were running close to 90% and then for the overall company, we were running about 93%, and that is for oil. NGLs were about close to 60%, then about 50% for the overall company. But obviously, that's a very small part of our production portfolio.

And if those Bakken differentials narrowed at all as we've moved into the second quarter here?

They're -- we're probably about the same.

Our next question is from Sean Sneeden of Oppenheimer.

Most of my questions were answered already. But Mark or Floyd, can you maybe talk about your plans for leasing for the rest of the year? I think in the past, you've talked about most acreage was already taken at this point.

Yes. We, of course, have an ongoing lease project in any core area where we try to block up working interest and in some areas, that involves trading around with offset operators and in some areas, we're picking up kind of cleanup leasing. In terms of large leasing ambitions, we don't really have any right now. We're looking for that elusive large deal that's right in the exact spot we want, but so is everyone else. So we don't have a huge expectation of anything significant this year. We're just running our programs and picking up things that are strategic in nature.

That's helpful and then -- and I don't know if I missed this in your release, but the $500 million or so of CapEx in Q1, do you -- can you break out how much of that was for leaseholds?

Mark, can you get that?

Yes. We have the amount that we spent on the TMS, that was about $63 million. And then we did break out in the press release, the total was about $100 million -- a little over $113 million.

And so it's $113 million out of -- how much, Mark, $500 million?

Yes, out of the $513 million or so. And then I will also point out that, that full number, the $513 million or so, does include an amount for capitalized interest in G&A of about $55 million.

So that boils down to about $345 million for drilling and completion CapEx?

Yes, about $330 million for D&C.

$330 million, okay.

Yes.

Our final question today is from Andrew Coleman from Raymond James. Andrew Coleman - Raymond James & Associates, Inc., Research Division: I had a couple of them answered, but one, kind of thinking about the non -- other noncore assets that you all have. I know in the past you all had a couple -- a piece there associated with Mississippi Lime, and that was a small acreage block, but you also have that -- is that something you all are looking to divest there or is that acreage expired?

Steve, you want to respond?

Yes. We still have that acreage in Osage County, Mississippi Lime area. And that may be something that we could do something with later this year. We're considering it. Andrew Coleman - Raymond James & Associates, Inc., Research Division: Okay, and then stepping up for the Bakken, the last couple of questions that were there, a couple a few minutes ago. I guess, have you all looked at coil across your completions or just slickwater at this point?

Go ahead, Charles.

Yes. I think you're probably talking about the system-wide infusion. And we're looking at that like we're looking at everything. We don't see a big cost difference. And right now, the guys are doing a great job. We're not going to change anything radically right now. We don't see -- our results are dictating no need to right now.

Thanks, everyone, for dialing in. If something that didn't get asked or we didn't cover, if there's anything like that, just give us a ring. And we'll talk to you again soon. Thank you.

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program. You may now disconnect. Good day.