Battalion Oil Corp (BATL) 2014 Q2 法說會逐字稿

Good day ladies and gentlemen, and welcome to the Halcon 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 Halcon in East Texas, TMS are all moving ahead. All of our production's coming out of the Williston Basin and El Halcon at this time.

So second-quarter 2014 production of over 42,000 barrels a day equivalent was a record, despite selling 3700 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. We're waiting on completion in probably 3 times as many non-op wells as that. We're running eight rigs right now; three in the Williston, three in East Texas El Halcon, and two in the TMS.

A couple comments about each area. The Middle Bakken and the Three Forks and 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 ran an average of four 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 the EURs.

Down-spacing tests have yielded really interesting results and positive. Based on our own work and looking at our own acreage, our current development plans are to proceed 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 Halcon 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 group. Over 450% year over year and 30% quarter over quarter. Progressively, the wells are getting better every single quarter.

The wells put online during the second quarter are performing in line with expectations but are outperforming the wells in the first quarter, and the wells that we have drilled so far and completed so far in the third quarter are 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 barrel of oil equivalent type curve.

A couple of data points on IPs. IP rates for wells put online in 2Q was 804 barrels a day. Better than the average IP of the wells put on in the first quarter. Average 30 IPs for wells put on 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're doing very little pad drilling here. We're not doing any spacing tests 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 length, tighter per cluster spacing, increasing the percentage of resin-coated sand relative to total profit. We're using different surfactants and installing large-bore frac plugs during the completion.

Several artificial lift modifications continue be tested and evaluated, and we continue 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 feet 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 feet 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 Halcon potential is second to none in the area.

Tuscaloosa Marine Shale, of course, is on everybody's radar screen these days. We're running two 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.

I 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.

Of the last 10 wells drilled in the play, there's 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, it's over 1300 barrel oil a day equivalent.

So, it's an early stage play. As I said, we're very happy to be there. Our field services unit continues to work on several initiatives that have the potential to improve realized prices and margins in all of our plays.

Our first compressed natural gas facility is expected to be in service by the end of this quarter at El Halcon. We'll use CNG to displace diesel fuel. This isn't only green, but it also could result in a nearly 50% savings on fuel cost in frac jobs and with drilling rigs. We expect to build similar facilities to service our operations at Williston Basin and in the TMS next year.

HFS continues to provide low-pressure gathering services in El Halcon and plans to support the TMS by building a three-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 processing plant at other 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; this facility will be capable of handling truck and pipe offloading from the TMS and to market the crude barge on the Mississippi River or by rail. We're working on that as we speak, as well.

Mark Mize will now go through our financial results.

Thanks, Floyd.

Production for the quarter averaged just over 42,000 barrel of oil equivalent per day, which was above street estimates in the midpoint 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 with (inaudible) 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 BOE to 42,000 BOE a day. On the cost side, all of the work over extends came over at 913 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, which is $8 to $10. After adjusting for selected items, cash G&A expense for the quarter was [$586]. The BOE was about 22% improvement compared to first quarter, and we are projecting to track to the low end of our 2014 guidance.

(inaudible) income came in at [$792] and gathering and other expense came in 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 barring 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 closing of an 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, Apollo 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 barring base on our revolver to increase when we have our Apollo re-determination 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. 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 in 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 the last six 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 positions in 2016. While 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 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 minimum 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; your line is open.

Good morning, everyone. I wonder if we can start with El Halcon. You guys talked about the target of these laterals being kind of 7,500 feet to 8,000 feet. I think in the press release you mentioned that the wells in the third quarter so far had started at 1,091 BOE on an initial rate. Can you talk to just the 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? Do you know?

How many wells were in that? Just about three wells in that sampling.

This quarter?

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

How many stages in those, and then what the kind of average -- I know all of these wells are going to be different, but kind of where the laterals were shaken out and how many stages are you guys putting on those?

It all depends on our leases. These laterals average 60; they are all in the 6,200 to 7,500 range.

This quarter? We had a couple 9,000 foot laterals.

Yes. 6200, 6300 were those; most of them are a little longer than that coming up.

What's the stage length?

250 foot.

(multiple speakers) So however long we can drill the wells, you can divide by 250 and get the number of stages. Most of our wells are between 22 and 30 stages, I think.

Great. And then, you guys have 100,000 acres there in El Halcon. Obviously, you know, some really good results so far. Probably gives you guys a lot of running room. How are you guys thinking about the rig count issue, you know, step towards the end of this year and into 2015?

Well, we are able to keep this growth rate up with fewer rigs than we thought we could. So, for now we're going to run three or four rigs in this play and throughout this year and next, and 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% this past 90 days or so.

I appreciate the color, guys.

Thank you. Our next question comes from the line of Jason Wangler of Wunderlich Securities. Your line is open.

Morning, guys. Curious on the Black Stone well. You just gave us a little bit of an indication that the well was pumped, that all the frac stages, but then there were some issues. Do you have an idea yet -- will all the frac stages still be able to go off or will that shorten the effective lateral? Kind of curious, some color on that?

We don't know yet. All the -- I think over 22 stages, they all fracked well. We're just in that cleanup process, and we'll start flow back here soon. We're just not quite there.

Okay. Fair enough. And then, just possibly for Mark. He may have already answered this, honestly. Just $150 million, obviously, from Apollo that already came in. You know, when do you think you 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 a year end or first quarter time frame? Or just where your thoughts are there?

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

Perfect. I appreciate it. I'll turn it back.

Thank you. Our next question comes from the line of Neal Dingmann of SunTrust. Your line is open.

Morning, guys. Say, I was just wondering what you've seen on these TMS wells, you know, just the one you have down and, obviously, you've got a lot going on right now. Is your thoughts changed as far as the way you are going to, obviously, drill and complete these -- a lot of these guys talk about above or below the rubble zone. Wonder what you've seen -- two questions around this. Have your thoughts changed on how you want to tackle these? Number two, you had early EUR estimate on your tight curve. Has 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. You've got three operators running multiple rigs there now. All of those operators are targeting about the same area. There aren't any other conditions that direct you to go somewhere else in terms of the placement of the lateral. And the operators are, actually, a pretty tight range of frac job, you know, volumes of profit and water. There are some differences.

So what you've got is, currently everyone is 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 slick water, 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 remain, that it's a tough nut to crack down here, but we expect it to significantly reduce costs over a couple of years. And we haven't changed our thoughts along those lines at all. Anything else, Charles?

No. That pretty well covered it.

Okay. All right. Great, Floyd. And then just one follow-up. Obviously, on the Bakken, efficiencies keep adding. Is it safe to say there's just no -- I mean, you would add per acreage up there if it was available. Is it just at this time there's nothing available around your surrounding areas or is there a little [basin] still left?

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

Got it. Thanks, Floyd.

Your next question comes from the like of Ron Mills of Johnson Rice. Your line is open.

Hey, Floyd, you mentioned quickly in the Williston commentary about the Fort Berthold wells exceeding the 800,000 barrel curve. Any more color around that given that you brought 18 wells on during the quarter, you know, how they came on relative to that 2,000 barrel a day rate in that IP? Were most of those wells Bakken or Three Forks? Any more commentary on the Three Forks under your acreage?

Well, of course, it varies across the field. But in general, all the wells that we've reported in this, I think this last group of wells, they all averaged well over 2,000 barrels a day. 2,500, 2,600 barrels a day. 2,550 barrels a day. That's average Three Forks and Middle Bakken wells. So, we're drilling 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 like 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.

Okay. And then down in El Halcon, 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 drilling. Sounds like you still have more to lease capture there. Is the rest of this year in El Halcon really going to see rigs move across your position for more lease capture; and then as we look to 2015, start to get more into the optimization that more development type drilling provides?

You know, 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, say, the Stasny-Honza, that was a wonderful well. Some of our peers in the area have hit 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 two of our three rigs are up in Brazos now. Maybe all three, for all I know. They're drilling these wells so fast. You have to read your drilling report every day and every weekend day to remember where the rigs are.

And then as more -- you know, 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 that 100,000 acres where it's located. Any opportunities to expand in that area and/or even in the TMS,'s as some of that play has moved a little bit to the Southeast, into especially Tanjoboa?

Well, again, the acreage is pretty tight in the TMS, and we have so much that it would be like gluttony to just think we have to have more. And at El Halcon we were probably a little too conservative when we drew our map the first time. We outlined a bull's-eye there that has been 100% accurate. But our bull's-eye could have been a little bit larger. With the smart dummies that 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, we are always looking in any of our areas, but we're not seeing any large deals in the Williston or the TMS or at El Halcon that are in the area that we'd want to be in at this time.

And then one last one. The CapEx, Mark, you talked about $1.1 billion, with the Apollo deal, the $950 million. Is that the right way to look at your D&C net of the Apollo contribution, that net Halcon -- or Halcon CapEx remains in that $950 million to $1 billion range?

Yes. Yes, that's correct. When that $950 million was put, the Apollo deal wasn't contemplated. So, we're still tracking to the $950 million with the Apollo funds that came in.

Perfect. All right. Thank you, guys.

Is that it, operator?

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

Good morning and congratulations to you and your staff on the quarter. It was a pretty nice decrease in op costs this quarter. I was just wondering can you go into what was driving that improvement? And, should we now expect op costs to remain at the bottom of your guidance for the rest of the year?

You know, as far as -- I guess the short answer would be the production. As you know, we beat our internal guidance on production. But, we've also indicated that LOE is probably going to track towards the higher end of published guidance. But, again, the 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 acquired 200 feet of continuous conventional core in the Smith well. That was an area of the play that did not previously have conventional core. But, between us and the other operators, there's about ten cores now. A few other operators will be getting a couple others that we'll have access to. We don't plan on taking any others near term right now. We've got fantastic data on that Smith well, and the core and all the moderate suite of logs that we ran in it. That well, maps out as having one of the highest original places of any well in the whole field.

Okay. That's perfect. Thanks, guys.

Thank you. Our next question comes from the line of Dan McSpirit of BMO Capital Markets. Your line is open.

Thank you. Good morning. A question on the TMS. If we look at 12 months from now on the play, what should we expect to see in terms of drilling complete costs, production profiles, and then maybe ultimate recoveries? That's, I guess, a long way of asking about expectations on field level returns, and how they're expected to change, and what is the internal rate at the Company that needs to be met?

Well, taking this in reverse order, our internal hurdle is our published type curve, and the cost side of that is to get the costs down within two years from where they are, down to that under $12 million range. Somewhere in 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 too, by the way.

The cost side, it's a tough deal down there. It's a hard area to drill in and a hard area to complete wells in. But, I think a 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, have 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 people to be in business with.

So, I think you're going to see a steady inching down of costs. And if it follows the pattern of these other plays, Dan, you have to understand that the type curves in other basins started out at, you know, whether it was 300,000 barrels or two or three B's or something. They 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 is not a few million barrel wells found in here within the next year. But, I don't know that.

Okay. Great. And 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 in 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 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.

A lot's going to depend on what goes on in the TMS in terms of additional growth. We can make our growth plans with our two great core areas that are hitting their stride right now. Incremental would be what 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 eight to ten. We were [913] for this quarter, and we expect to stay on that higher end as we finish out the year.

Got it. Thanks again.

Thank you. Our next question comes from the line of Jeff Robertson, Barclays. Your line is open.

Thanks. Floyd, just a question on Halcon Field Services. Can you talk in a little bit more detail about the oil handling facility at Natchez, and 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?

You know, the capital associated this, that project, if it gets fully built as what we think, 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 the refining capacity in the United States is available to that area. It can be used for blending, whatever. So for now, we're doing all the planning. We've acquired some land, which is very small amounts of money.

We haven't really published numbers on that. And, it wouldn't happen until later in 2015 in terms of the spend. But it could be $15 million or $20 million initially. And it's not a ton of money. But what you could find yourself is gaining dollars per barrel in terms of price discovery, as opposed to just spending money. And so, we're really high on it. What we've done in the past is make sure that if an idea is working, that we build it far enough out that our own plans are going to be served. If you bring someone in that maybe has a different capital plan themselves or something. So it's so premature to even talk about bringing anyone in or anything like that.

You know, 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 outlet for others. But it's early to get into that. The only reason we ever brought it up is somebody on these darn blogs or something noticed that we bought some land there in the Port of Natchez and started screaming their Facebook off about it, over whatever. So we just thought we'd better mention it.

And 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?

You know, no. We just have so much acreage in Wilkerson county and just south of Wilkerson county. We just don't have to think about that acreage to the West for some long time.

What we've learned is that we have a really good show there, and we lost a well before we were able to get the full thing 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 the -- 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.

Okay. Thank you.

Thank you. Our next question comes from the line of Andrew Coleman of Raymond James. Your line is open.

Thanks a lot for taking my questions. 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. I think there's a few areas that we don't have Buda rights. By and large, we've got the section that's on both sides of the Eagle Ford and most of our 100,000 acres.

Okay. Thanks. And then, I guess if we look at the oil mix, I mean, at this point the differentials are primarily, I guess, you'd buy it by Bakken barrels at this point. I think that was your previous discussion, one of the questions a couple seconds ago. But as you bring on extra TMS barrels and 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 Halcon and the TMS and the Wilson basin, that it's always going to be a price advantage just because of the simple cost of transportation. In terms of Louisiana light and Brent and heavy crew from Canada and all this stuff, I don't know about all that. It's a pretty complex thing that's going on. We just think that that area is going to be, you know, have small advantage over other areas just because of its location.

All right. Good. And then the last one is, just getting back to the clean out operations, again. How long would that job normally take, and how common is that? You said you had to do that with the prior well?

Well, how long it takes, I'm not positive. You know, we're pretty cautious down there. It's clearly a sign of -- it's not something we like to find, to 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'll 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 to flow. But, you know, 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 with coil tubing. We decided that we were worried about doing that. So, we brought in an actual completion rig with steel work pipe, a work string to work on the well.

Okay. All right. Thank you for the color.

Our next question comes from the line of Michael Rowe of Tudor, Pickering, Holt. Your line is open.

Good morning. Thanks for taking my question. I was wondering if you -- you have all obviously had a lot of success with water fracs in the Middle Bakken formation. I think you're still testing whether or not you think that will be applicable in the Three Forks benches. Have you all made any progress there on what you've learned in your test or is it still too early to tell?

It's still a little too early to tell for sure. But we're leaning towards it does not work as well in the Three Forks. The results right now don't seem to justify the extra expense and 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 slick water fluids and the settling you have, you're not propagating the profit up through the session above you, as well as you do from going from Middle Bakken and propagating down in the Three Forks.

Okay. That's helpful. And then, I just wondered if you all could provide an update on how you all see your Bakken production and Three Forks production adhering to some of the gas flaring reduction initiatives that are being implemented later this year? Are there any similar regions of your Williston program that concern you?

Well, the flaring has been a concern to us ever since we got into the play, and we've been working as hard as we possibly can to get this stuff 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 large improvements in the capacity for gas up there. We're not quite -- we're not in total control of that. But right now -- Steve, help me out here, but I don't think we're planning to be curtailed this year?

No. That's correct. Our plans are to have 100% of our wells with pipe hooked up to them by the end of the year.

Okay. Great. And just one last question, if I could. If we were to shift over to the East Texas Eagle Ford for a second, you produced about 9.1 thousand barrels of oil equivalent a day in the quarter. Looking at your production levels in April, May, and June, I would have expected that that may have been a little bit higher. Can you, maybe, just talk about the cadence of production ramp in the East Texas and Eagle Ford throughout the quarter?

All of these plays are dependent on frac schedules. Sometimes, if you're real near some other wells, you have some other thoughts that come in. So, you really have to look at the this over more than one quarter to get 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 it'll seem a little more smooth over that amount of time. We have, I think, six or seven wells that have been drilled right now that haven't been fracked, and we've got a few wells that have been fracked that aren't quite online.

It's always a little bit lumpy. I don't think this is a real good answer to your question. We think we're doing quite well there.

Understood. I was just kind of looking at some data points from some prior months and was just thinking about the full quarter, but maybe there was some shut-ins and things of that nature. Appreciate the color.

Our next question comes from the line of Sean Sneedin of Oppenheimer. Your line is open.

Hi, good morning. Most of my questions were answered. Mike, on your preliminary CapEx thoughts would you describe your general, you know, 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. At this moment, it would be a very small number as far as any thoughts about leasing.

Drilling completion, we are looking at -- and again, this is not guidance -- but we're looking to spend about $1 billion next year. And 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 off of those comments, it would sound like all else being equal your cash flow outspend would be lower year over year?

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.

Okay, great. Thank you very much.

And this does conclude the question-and-answer session. I would like to it 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.