Good day, ladies and gentlemen and welcome to the Halcón Resources Fourth Quarter 2016 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time [Operator Instruction]. As a reminder, today’s conference may be recorded. I would like to introduce your host for today's conference, Mr. Mark Mize, Chief Financial Officer. Sir, please go ahead.

Okay. Good morning. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday and posted on our Web site. We've also updated our investor presentation for the fourth quarter it can also be accessed from our Web site. And I’ll start the call with a few comments on our financial performance for the fourth quarter and then I’ll turn the call over to Floyd to discuss A&D activities and operations. Production for the fourth quarter averaged 30,620 barrels of oil equivalent per day, which was in line with our guidance range of 38,000 to 39,000 for the quarter. Our realized fourth quarter oil differential of 89% in NYMEX was in line with differences in the first quarter. Our fourth quarter natural gas differentials improved over the previous quarter, and came in at about 80% in NYMEX. For 2017, we do expect our differentials to be approximately 90% for oil and 85% for the gas, and that is based on the current strip. LOE expense was $5.23 per Boe in the fourth quarter, which compares to about $5.17 per Boe in the third quarter of 2016. And taxes other than income came in at $2.87 per Boe during the fourth quarter versus $3.06 during the third quarter. Gathering and other efforts of reflected items came in at $2.54. G&A came in right at $3.96 per Boe in the fourth quarter versus $4.21 in the third quarter of 2016. Overall, total operating cost for some selected items of $17.06 per Boe in the fourth quarter versus $17.33 in the third quarter. With respect to D&C CapEx, we incurred approximately $44 million during the fourth quarter, bringing our total 2016 D&C spend to $175 million. We did bring on 16 operated wells in the…

Thanks Mark. So, fourth quarter 2016 was a quarter where we were quite busy, setting our plans in motion for 2017 and beyond. Just to recap a little bit. In just the few months, we have transformed our financial setting at Halcón. So much so that today we have an undrawn $600 million revolver and $100 million in cash. And we have placed down maturities out a number of years. In just a few months, we've transformed our operational setting also. We've left one Basin and we've entered another, and we're already drilling in our new basin to Delaware. We’ve acquired three high potential Permian blocks and dramatically added to our inventory. Now for some actual exciting news, in Ward County in the Delaware Basin, we've finished our first vertical well in the southern end of our acreage. The only thing surprising about that well is that it had four strong pay zones, all much better than we expected and our expectations were high near our several others zones of interest as well. We’re already drilling the horizontal well from the same location, our CRMWD 79-1H. This will go in production during the second quarter. It's going to be a 5,000 foot lateral targeting the Wolfcamp at about 10,800 feet. As much as Delaware Basin, the upper section of the Wolfcamp is not geo-mechanically separated. So, in about 650 feet of Wolfcamp at this place in our acreage, we have three distinct landing zones. These are depending on spacing and pad design of course. We also found about 300 feet of high quality third Bone Springs, so one landing zone there. And we have several opportunities uphold from the third zone. Our Wolfcamp and third Bone zones all look equally as good, I expect our CRMWD 79-1H to be one…

Thank you [Operator Instruction]. Our first question comes from the line of Will Green with Stephens. Your line is open, please go ahead.

I know its early days in the Delaware and you guys are still just getting going here. But obviously just the production, the extra production volumes help. But this gets going and if it works to your expectation. Is this potentially something that drives the unit cost down, you going apples-to-apples basis. I guess what I’m getting at is, do you expect that this is going to be a less costly basin to maintain production on going forward. And do you have the G&A already in the system to maintain a much bigger rig count down there?

Taking the second part first, we’ve got plenty of staff to do what we need to do there. In fact, we’re doing it now. We’re already planning for the rigs for 2018, and we’re making everything -- we’re making sure that we’re sufficient for that and we are. Cost, you’re talking about cost in the Delaware Basin. Our first few wells are all going to be $8 million to $9 million. Yes, costs will go down overtime drill -- rig days will go down, some other costs will go up. And we're keeping a steady finger on that pulse. I think that overtime the history of all the basins and certainly where we were has been a steady improvement in cost metric. We would expect that here as well. I don’t think with just running a couple of rigs will happen overnight. But certainly by year-end 2017, we should be looking at a different AFE than we're looking at today.

And then just on the LOE side, I mean obviously, that the production volumes help as you guys add extra production on. But on just straight apples-to-apples basis LOE, do you expect that this is a less costly basin to maintain going forward on LOE basis?

Yes, it's easier to figures. First off I’ll tell you that Mark and the guys here, a bunch of crazy sand baggers will beat that number. Second, the Williston Basin is more mature. All the wells are on lot less by now, or not all of them, but almost all of them early days in any new basin of the operating costs are quite a bit lower. The difference in the Delaware is that you haven’t a room or water, these doing some shale plays in the beginning. So, you do have a component there that's quite different from other areas that you have to keep track of. But yes, you would expect this to be as we shift from heavily weighted Williston production to heavily weighted Delaware production over a couple of years here, you'll find that the LOE will track down dramatically.

And then I wanted to get your take on some of the improvements, a number of the other operators are seeing up in Bakken. It does look like you guys you are doing -- I guess you guys are calling an optimized completion test over in Williams. I wonder if you could update us on what exactly you’re doing. I think you’re already at £500 per foot, but we've seen a lot bigger test in the basin. I wonder if you could just give us some additional color on what do you think of what's going on in the Basin and how you see it playing out for you guys?

Well, let's start with -- we started optimizing completions a few years ago. Many of our great peers are just getting into that now. And just to keep it clear, we make better wells than anybody in the basin. And we have been for a long time. The difference between how much proppant you use has to be a strict calculation. The economic calculation is based on diminishing returns. And the rest of it is based on experience and history of what's going on. So, we've done plenty of frac jobs at 1,000 pounds. We've done them at 750. We've done them at £500. We've done some at over 1,000 pounds. So far, we're finding that we're making great wells in great rock with less extent in these lower levels. And I know when I say too much, but some of the huge volume sand that we’ve seen requires an unusually robust de-factors to achieve the results that some people are hoping for. And history will tell them that, so this whole business of economic returns has to do a lot with how much proppant we’re going to use and so on in the early days. So, while we don’t know that 500 is the perfect number, and we’ve -- like I said, we’ve done a lot of wells at a 1,000, a few wells at more than that. We’ll continue to watch all of our grades peers there and take information from them and share our information with them, and ours will continue to progress. But as I said, we’re making wells that are basically carbon copies of each other, and a million barrels like every day, it's kind of hard to meet -- assess our ability to really improve that a lot, it's possible.

And maybe just one more. Do you see like in the same line of thinking, do you think that changes the in-fill opportunity for you guys versus another operator that maybe putting a more intense frac on these?

Well, I don’t know about that. Again, if in the past, you spend more money on a well than you needed to spend, but you still have good well that’s kind of in the past. So, there is always when a new person comes in on an asset on some properties, there is always some opportunity to do things little bit differently, and hopefully to improve things as far as given us advantage or whatever we’d like to think so. But listen, the people that drill and explore the field up here, they are all doing really good work, just as we do really good work ourselves.

Thank you. And our next question comes from the line of Jason Wangler with Wunderlich. Your line is open, please go ahead.

I noticed that two wells added on the CapEx, but I was also curious, because you were able to pick up some acreage as you look at drilling some longer lateral wells. Was that just a shift and where or what you want to drill, or does that help from the acreage pick up?

It helped a little bit from the acreage pick up in Pecos County. But -- and Jon is on the call here. But he plan and we plan to drill 10,000 foot laterals right out of the box everywhere we can. It didn’t line up that properly to do that in Ward County, but our next well will be 10,000 feet for sure in Ward County. So, we’re planning on drilling 10,000 foot laterals. And as you know, we drill them everyday up in the Williston Basin with great results, and we don’t see that that’s going to be a big issue for us.

And maybe just a side question, you have some standby cost on the rigs, but obviously you’re adding some rigs here. Will we see those come down or maybe even go away going forward as you pick up these rigs and get back to work, especially from the Williston more?

I’m trying to remember if we’ve revised. I think we’re getting some of that standby money back as we bring new rigs on. I don’t if it's 25% or 30% of the standby money, it's something like that. Those rigs that are paying standby money on you know were commissioned in 2013, and early ‘14. And so, we’re paying standby and we’re getting some of it back. But the new rig rate is $10,000 to $13,000 per day less than it was then. So, we’re getting that as a differential. Well, I think we’re running out of all the standby stuff this year, right.

Very little in ’18…

Maybe a little bit in the first few months of ‘18, but all of its running out this year.

Thank you. And our next question comes from the line of John White with ROTH Capital. Your line is open, please go ahead.

Good morning and congratulations on your Ward County pilot well. I wondered in the press release, you called the third Bone Springs a carbonate. Is it a true carbonate or is that saving carbonate, if you could give us some little more on the methodology, I would appreciate it.

John, I didn’t write that press release. Jon Wright, why don’t you address that? Thank you.

Thanks for the question John. It's a carbonate. There is also shale in it as well, so it's not much difference than what you would see outside of Ward County or the Delaware.

Thank you. And our next question comes from the line of Vivek Pal with Seaport Global. Your line is open, please go ahead.

I was looking at your cost structure, and it seems like based on your guidance, your unit costs are going to go up to $21 from roughly $17 in ‘16. And I'm assuming half of it is because of higher production taxes because of higher commodity prices, but still the $2 that you see increase year-over-year it has been most of -- most of the people are seeing costs flat to slightly down, is because of gathering contracts and higher LOEs, if I am -- is that a fair assumption?

Yes, it's a couple of things. Number one, we do have a pretty flat year-over-year production profile, so versus our peer group who have most because of the disposition in the Eagle Ford assets, our production at year-over-year is flat. So we’re not getting the benefit of a large ramp year-over-year in production, it's a lot of our peers are that drive down per unit costs on the LOE and other items. The other thing I would say is when we structure our gathering transportation and operating line item is depending on how the oil has gathered in the field. And some of those contracts translate in 2016, whereas before we would have pass through that as a differential cost, meaning a reduction to our revenue. Looking forward in 2017 is going to be captured on the line items, gathering transportation and other, and that's about $1 per barrel. So, it's a net zero impact, because our differentials would be about a $1 higher, our DTO will be about $1 higher. So, the net impact on our cash flow and revenue and profitability is negligible at systems accounting adjustment.

So the dollar increase in GTO is offset by higher realization in Bakken, is that what it is?

Exactly.

And the LOE is just higher because of we were spending more in Delaware, is that what it is?

Again, as Floyd mentioned earlier, our Bakken assets are mature assets. There is a lot of work over expense in that asset. And so, in 2018 and 2019, we expect LOE to come down by more than $1 barrel as we grow our production in the Delaware.

And now based on your equity issuance, you have the option to take out a third of your still outstanding 12% second lien notes, right. I think in total this $113 million is outstanding. Are you still planning to do that, or you are going to use that money to buyback option that you have?

We haven’t fully come to that inclusion we do have that ability, and we’re thinking through it. There is not a troublesome piece of paper, it’s quite small. And we’re quite intent on adding assets in this rate basin in the Permian and the Delaware Basin.

Thank you. And our next question comes from the line of Sean Sneeden with Oppenheimer. Your line is open, please go ahead.

Floyd, I know you had mentioned that the general plan is to run four rigs in the Permian. But can you help us maybe think about how you’re approaching the Williston next year, is the goal run one and half again next year are going to keep the Williston flat, or how you’re thinking about that?

Williston will continue to grow. We’ll have two rigs running for most of next year, and a lot of this year. So, the Williston will continue to grow from its current levels around 30,000 net barrels a day for the next several years. It’s a lot of people don’t really think about it, but it’s an awesome assets. And we’re just a little -- very light weight capital intensity, we can keep that growing. So, we could shift money from there to the Delaware as we get into a more mature development drilling situation there, because we have no lease explorations or any fear of losing any lands in the Williston Basin. Right now next year we’ll be at four rigs in Delaware and two rigs in the Williston. But plans are made to be broken by opportunities, and we’re going to be super -- highly focused on -- where the best money can be spent. Right now, it's just four and two. We’ll see what really goes on as we get through this year.

When you think about funding for next year, I think previously you’d hope to try to run relatively your free cash flow neutral. Just giving the four and two plan there, is the expectation then at this point you’re going to use some of the dry powder on the revolver, or how do you guys think about funding any deficit in that sense?

Well, through all this business that we’ve done this quarter of repositioning and Company financially, we provided enough flexibility within our capital structure to take case of our deficit for the next few years. The deficit is relatively small anyway it's kind of which year you’re looking at $50 million to $100 million in a given year. So, we’re good to go with that requirement. Higher prices will make that better and we’re doing a lot of hedging. So, I mean we’re – we don’t expect to be cash flow neutral into 2019, not next year. But I think what we said was we’ve provided enough money to take care of our deficit for several years.

Okay.

There is an acquisition or something that comes up yes, we’ll be needing to fund it through the revolver or through some other means. But we’ve just closed one yesterday, and we’re closing another one sales soon, so we’ll let these things mature for a few days before we start talking about new ideas.

With the goal, just kind of conceptually as you look to perhaps exploit some opportunities around your area, especially within the Permian. Would the goal from a funding perspective to be similar to what you guys were able to do on the most recent Pecos deal?

The goal would be to block-up our acreage to where we can drill 10,000 foot laterals everywhere we drill a well, and that is a little bit of adding and trading going on around both in Ward County and Pecos County. And we have plenty of flexibility for that activity. Any large acquisition would require a new thought of how to fund it. And because as Mark said, our goal is pretty, it's not pretty its various firm are taking leverage from where it is today down under 3 times EBITDAs in the next two years. And we’re going to keep out as a guiding light in terms of how we support ourselves financially.

And maybe just one last one and Mark feel free to jump in. But on the borrowing base, I know you talked about it being flat to maybe slightly up for the Springs. Does that include the benefit of the Pecos and Ward assets, or is that really all being driven by the Williston?

Well, the drilling program in Delaware would really ramp-up in the second quarter of this year. But we’ll of course, will take all activities into considerations, leaving right up to the redetermination that we do in May, or we might even accelerate it a little bit if we decide to.

Well, let's think about it though. We are still at 5,500 barrels a day and our borrowing base didn’t go down. So, trust me that's growth right there. And we expect it to grow in the Springs a bit and in the fall a bit, just by hard work. So our outlook there is very -- really good and we keep, Mark keeps constant touch with our banks and their outlook for what I’ve just outlined is very positive as well.

Thank you. Our next question comes from the line of Kevin MacCurdy with Heikkinen. Your line is open, please go ahead.

Your guidance seems to imply a higher oil percentage for the remainder of the year compared to current levels. Just kind of curious on what you’re seeing that maybe comfortable with that, maybe is the -- Williston have a higher oil mix than previously?

No, nothing has changed in the Williston. This is a higher oil mix in our numbers, it's a bare -- it's modest. I mean we’re still going to be about where we've been that the trade-off of the El Halcón for Delaware barrels is similar in terms of make-up of the product stream, a few more NGLs out there. But there we’re working in a heavily weighted in the Delaware Basin.

Thank you [Operator Instructions]. Our next question comes from the line of Jacob Gomolinski with Morgan Stanley. Your line is open, please go ahead.

Just wanted to confirm, are you saying that the PV-10 spread is about 1.6 billion, and is that including El Halcón or the Delaware?

That is essentially -- let me make sure that -- we’re flipping a couple of sheets here. That’s pro forma what we’ve done, but it was based on the strip at 131. So, that’s ex the Eagle Ford and plus the few barrels we’re picking up at the point of acquisition in the Delaware.

And then just on hedging, it looks like as a percentage of production, is little bit less hedged in 2017 and ’18 than you used to do historically. Does that represent a stripping strategy, or is it more just a reflection of your view on current oil prices?

Well, as you might guess, it’s really paid off to be, not hitting the hedge markets at a full speed earlier. Right now, our financial jackets are well met by anything in the $50 to $60 per barrel range. So, we’ll be adding to the hedges even though on constructive on oil prices. But as I always say, I don’t really have a freaking clue of where they’re really going to go. But I’m kind of constructive on the. But we’ll keep hedging because that band of $50 to $60 serves us quite well in terms of our business plan and revenue that we need and so on and so forth.

We’re still targeting to be 70% or 80% hedged for the two or three year in advance. So, we’re working it. But again, it's been -- it's paid off to right this wave a little bit.

Thank you. And our next question comes from the line of [indiscernible]. Your line is open, please go ahead.

So, I just wanted to ask you guys about your liquidity position. You mentioned in the press release a total $699 million. I was just wondering how much of that is cash and how much of that is undrawn availability on your RBL?

On that number, on that when we stated that $600 million undrawn RBL and $100 million of cash.

And just on the acquisition front. Is there any way you can guide us to the size of any potential acquisition that you might transact on in the future?

Not really. Anything that we do that anybody -- that you would call blocking and tackling around our current positions would be things that we can do within our own capacity. Anything larger than that, which we don’t have any projections on, would require a whole financing plan of separate from where we are today. There is -- we’re ambitious, but we’re also pretty focused on leverage and liquidity, and so on. So we’re -- we have to balance those things.

Thank you. And I’m showing no further questions, at this time. And I would like to turn the conference back over to Mr. Floyd Wilson for any further remarks.

Well, anyway, thanks for calling in today. If there is something that you think that we didn’t covered, 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 great day.