Battalion Oil Corporation (BATL) Q2 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Halcón Resources Second Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. We will have a question-and-answer session later on, and the instructions will follow at that time. As a reminder, this conference is being recorded. Now, I would like to welcome our host for today's conference, Executive Vice President, CFO and Treasurer, Mark Mize. Please go ahead. Mark J. Mize - Chief Financial Officer, Treasurer & Executive VP: Okay, thank you, 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 website. I'll start the call today by summarizing the steps we've taken over the past few months to improve our balance sheet, and then I'll provide commentary about the second quarter financials. As it relates to the balance sheet improvement, we've executed on several initiatives over the first half of 2015. One, we extended the maturity of our 8% senior convertible notes to 2020 from 2017. We've also initiated an ATM equity program to raise up to $150 million in proceeds over time. To date, we have raised about $15 million under this program at an average stock price about $1.63, but we're not doing any more transactions at this time just due to current trading levels. Third, we negotiated with bondholders to exchange $250 million in face value of our senior unsecured notes in the common equity at around $1.80 a share. And then fourthly, we've issued about $700 million in senior secured second lien notes due 2020 and used the proceeds to repay outstanding borrowings under our revolver. As a result of the capital raise, we currently have very little drawn on our revolver and are expected to remain relatively undrawn for the rest of the year based on our current plans. Finally, we amended our senior secured revolving credit facility by extending the maturity to 2019 from 2017 with a borrowing base of $900 million. And we also had the interest coverage ratio covenant replaced with a total secured leverage-to-EBITDA ratio of 2.75 times. We continue to stay in close contact with our bank group. We don't anticipate any surprises when we have our fall redetermination. The end result of these efforts is that we have no near-term maturities and we have sufficient liquidity to fund our operations and service our debt for years to come. We continue to look for ways to further strengthen our balance sheet as it relates to leverage and liquidity. We ended the second quarter with just over $900 million of liquidity and we can comfortably operate the company through 2018 at the current drilling pace with the current financial resources available to HK. Production for the quarter was in line with our guidance and averaged 41,297 barrels Boe a day. We published production guidance for the third quarter in our earnings release which accounts for approximately 1,800 Boe a day of non-operated production in the Williston Basin that's currently shut in or deferred. Having said that, we're still comfortable with our full-year production guidance of 40,000 Boe a day or 45,000 Boe a day. On the cost side, LOE plus workover expense was $7.70 per Boe in the second quarter, which is below our guidance range for the year and represents a 19% improvement compared to the first quarter of this year. After adjusting for selected items in the press release, cash G&A expense was $4.60 per Boe in the second quarter, which is at the low end of our guidance range for the year and that's a 7% improvement versus the first quarter. Taxes other than income came in at $3.43 per BOE for the quarter, which was also below our guidance range for the year. Gathering, transportation and Other came in at $1.78 per BOE, which is also in line with full-year guidance. So overall, total operating cost per BOE improved 11% compared to the first quarter of this year and 28% compared to the second quarter of 2014. This cost improvements are the result of continued efforts to drive efficiencies in all aspects of the business or continuing to seek out additional ways to get costs down further. With regards to D&C, we spent $75 million during the second quarter, which was less than expected mainly due to lower well costs. We continue to be extremely focused on both capital discipline and capital efficiency this year as indicated by reduced 2015 budget. Our current D&C budget for this year was reduced by another $25 million to a midpoint of $325 million, and we currently expect D&C CapEx in the third quarter to be roughly flat versus the second quarter with lower capital spend in the fourth quarter. Regarding hedges, you will note that consistent with prior years. We've elected not to designate any of our hedge positions as cash flow hedges for accounting purposes and accordingly we continue to record the net change and the mark-to-market value of derivative contracts on the income statement. We recorded a derivative loss of right at $88 million, which consisted – it was the net result of $175 million of an unrealized non-cash loss and then $88 million of a realized cash gain related to settled contracts for the second quarter. The net loss was due to a higher forward curve of 630 versus 331 and also due to about $90 million in hedges rolling off during the quarter which, again, was realized as cash and income in this quarter. Consensus revenue estimates include realized hedge gains and losses, which is why I wanted to point this out on the call. As of the close of market yesterday, our hedge portfolio had a mark-to-market value of right at $450 million. Today, we have 30,500 barrels a day of oil hedged for the remainder of 2015 at an average price of just over $90 a barrel. For 2016, we have right at 25,500 barrels per day of oil hedged at an average price of right at $81 a barrel. And then we have a small amount of hedges in 2017. So we're continuing to keep our eye on the periods out past 2016. While our hedging for 2015 is complete, we'll continue to layer in positions in 2016 and 2017 to try to meet our targets. And with that I'll turn the call back over to Floyd. Floyd C. Wilson - Chairman & Chief Executive Officer: Thanks, Mark. Okay. Our second quarter was excellent operationally. Completed well costs came down significantly throughout the quarter and that trend continues. We're running three rigs today, and our plan is to continue that through the end of this year. Up in North Dakota, the wells put online this year are outperforming our type curves. Completed well costs are down 35% so far this year. Current AFEs are running just over $7 million per well. Drilling completion and production efficiencies are driving cost down and production up. We're drilling our wells in record time, some wells in 16 days or 17 days. That's spud to rig release. We've continue to adjust our completions based on past results and feel we are closing in on a near perfect completion scenario. And the Williston Basin gas capture for Halcón will be at over 90% by year-end. At our current rig deployment level, we have about 10 years of inventory including a couple of hundred locations at Fort Berthold and over 400 viable locations at Williams County, not to mention our over 1,300 non-op locations, most of which are located in the core of the basin. Here in East Texas at El Halcón results continue to be consistent, meaning that each specific area of the field is meeting our expectation for that area. Currently, we are transitioning from leased capture mode to pad drilling. Current AFEs are running just under $7 million on single well pads. Multi-well pad drilling will reduce well costs by up to $1 million per well, and that will vary a bit depending on how many wells are on a pad. As in the Williston Basin, at El Halcón drill days per well are decreasing. Costs are going down and completion is becoming ever efficient Current thinking, largely based on our current frac design, leads us to plan to space future wells at El Halcón at 800 feet to 1,000 feet apart. This yields about 700 future locations on our 100,000-acre position, which is plenty of running room. So operations are going great, cost are downs, spending is down, and production is holding up nicely. Our liquidity is strong and we are very well-hedged through the end of next year. Current economics to drilling complete wells are attractive. Our inventory is deep and we are looking at opportunities to add to our high quality future drill sites. Make no mistake. Our business is in – we're in stormy seas at this time, and while we expect and hope for improvement, we are planning for current conditions to persist. I do not believe this is exactly the right time to press drill bit growth which would mean add rigs and et cetera. So right now, our plans are somewhat steady state on the CapEx side. And our CapEx, as Mark mentioned, is our estimates of what we'll spend this year is coming down each time we report. With that operator, we've got – if there's any questions we can – we can address those.

Thank you. And our first question is from the line of Brian Corales from Howard Weil. Your line is now open.

Good morning, guys. Just a question more – I guess the run rate in the back half of the year is $70 million to $75 million in capital a quarter. Is that likely to maintain in 2016 based on your thoughts today? Floyd C. Wilson - Chairman & Chief Executive Officer: The way the trend is going right now, Brian, the three-rig program, and a lot hinges on when you actually complete these large multi-well pads up at Fort Berthold, would be – we would spend less in 2016 than we will spend in 2015. So if we end up with $325 million or thereabout this year, the same rig program we would spend less next year. We're not giving that guidance just yet, but – and then we think we can do that and maintain production fairly well as well.

And I guess if we – if you run three rigs would it kind of have a similar make up, two in the Bakken, one in El Halcón, or when you get the pads would El Halcón potentially get more of the capital? Floyd C. Wilson - Chairman & Chief Executive Officer: Well, the – while the current economics at El Halcón are attractive, they really don't compare to what goes on up at Fort Berthold. So we would not increase our rig usage at El Halcón at this time.

Okay. Thanks, guys.

And our next question is from the line of Jason Wangler from Wunderlich. Your line is now open.

Good morning. Was curious at El Halcón as you move to the development, what kind or how big are the pads are you looking to drill? Is it going to be a couple of wells at a time and where do you see that going as you kind of get into that program? Floyd C. Wilson - Chairman & Chief Executive Officer: Charles is sitting here. Let me just let him address that. He's been doing all this planning with our operation teams just recently, so it's right on the tip of his tongue. Charles E. Cusack - Chief Operating Officer & Executive Vice President: Yeah. I'll say it's going to be – it's going to be variable. We're basically – we're transitioning into it, but it will be a variety from two well pads up to probably four well pads. And so it will be two, three and four. It all depends on the unit configurations and where we are, and if we're trying to drill into one unit or two units. So it's going to be a smorgasbord, and that's why we're – the cost of – the savings will vary pad to pad. As we get further into it, we'll probably have more and more wells, but we're kind of transitioning into it right now.

Okay, great. And Floyd, you mentioned at the close of your comments there about opportunities to add inventory. Could, I guess this last month has obviously been pretty ugly. Just what you're seeing out there and may be if you could give any color on what or where you're targeting as you look to the M&A market? Floyd C. Wilson - Chairman & Chief Executive Officer: No.

Always worth a shot. Floyd C. Wilson - Chairman & Chief Executive Officer: We don't – we don't talk about that. We're just doing what we do here, and we don't really talk about that.

Okay. I appreciate it.

And our next question is from Chad Mabry from MLV & Company. Please go ahead. Chad L. Mabry - MLV & Co. LLC: Thank you. Guys, good color on the call. It looks like you've done a good job of achieving your midyear well cost targets in both the Bakken and Eagle Ford. I'm just curious if there's any room for savings? How long do you think this is sustainable, just general thoughts on cost trends? Floyd C. Wilson - Chairman & Chief Executive Officer: Well, our partners in our business in the service side are under the same sorts of pressure that we are. And so our partnership with them persists even though it seems like we're pushing for lower costs all the time. The costs that you've seen on a – the actual historical costs that you've seen reported by us for the entire first half of this year involve a mixture of wells drilled on kind of older cost structure, maybe with a newer less expensive frac. So the trend will continue this year that our per well cost on our historical, our reported wells, will go down. When we say an AFE, that means a well that we're going to spud soon. We'll be at that level if oil prices – this is only an opinion – if oil prices stay low. There's going to be more pressure on service costs to go down, and that's just a fact of life. Chad L. Mabry - MLV & Co. LLC: All right, that's helpful. Thanks. And then one question for Mark maybe, just curious any kind of guidance you can provide on the borrowing base in the fall? I know that was reset and with maturity incentives, et cetera. Do you see that staying at $900 million? Mark J. Mize - Chief Financial Officer, Treasurer & Executive VP: We've stayed in very close contact with our two lead banks, which is JPMorgan and Wells Fargo, and every indication that we've received is that there will not be any surprises. We'll stay at $900 million maybe. Could there be a slight reduction of some amount? Maybe, but we're not expecting any significant movements. Chad L. Mabry - MLV & Co. LLC: All right. That's it for me. Thank you.

And your next question is from the line of James Spicer from Wells Fargo. Please go ahead.

Yeah. Good morning, guys. You mentioned in your prepared remarks, Mark, looking at other alternatives to strengthen the balance sheet. Just wondering if you had any specifics you could could provide there? I don't know if those would include things like bond repurchases or anything along those lines? Floyd C. Wilson - Chairman & Chief Executive Officer: Let me answer for Mark. No. No comment.

No comment? Okay. Then another question I had here, in the 10-Q, it looks like there's some additional disclosure around your agreement with Apollo and the TMS regarding minimum drilling commitments and the potential for the redemption of some preferred shares. Just wondering if you could provide some color on what's really changed there if anything? Floyd C. Wilson - Chairman & Chief Executive Officer: Let me ask David. He's sitting right here – to address that, but nothing has really changed. The contract and the agreement with Apollo had all of these things set out in them, and I think we've made an adjustment to extend some of the timeframe. But what else, David?

That's right, Floyd. We just extended some dates, and everything is maintaining the way it is. Both parties are working together, but based on commodity prices and what's happened in the TMS, we've just extended out the contract a bit.

Okay, thank you.

And our next question is from the line of Neal Dingmann from SunTrust. Please go ahead.

Morning guys. Say, hey, Mark, just one clarification, you mentioned about given the sort of current status you guys could operate through 2018. Is that just assuming kind of that current three-rig environment you all have? Mark J. Mize - Chief Financial Officer, Treasurer & Executive VP: Yes, that's correct.

Okay. And then just lastly, Floyd, would it – you're right now, Floyd, the I'm just wondering on locations at Fort Berthold, your thoughts there and is the opportunity for – I know you guys had down spaced a bit more, just if you could comment about locations there or in Williams County? I'm just kind of curious on what you have and if there's potential for a bit more? Floyd C. Wilson - Chairman & Chief Executive Officer: Well, I mentioned that we have just round numbers of a couple of hundred locations at Fort Berthold and 400 or more in Williams County. We believe them all to be viable under the current expectation of drilling and completion cost. Spacing is specific throughout the field. We space Three Forks wells if they're – if they're in the same unit with middle Bakken wells. Little differently – we space here and there differently based on results. I don't – Charles is sitting here. I don't know if we have a standardized 660 or 800 or whatever across the field. Charles E. Cusack - Chief Operating Officer & Executive Vice President: Well in the middle – on the Fort on the middle Bakken we're pretty much laying out at 660s now, and that's what we are drilling at. I will say some of the offset operators, there are some 400 foot spacings right now we're are watching very closely. So there's a chance. There's upside to go closer there. And them Three Forks, like Floyd alluded to, we've been a little more conservative. We've been spaced a little wider than that. So there's certainly a chance you can tighten up that Three Forks to the same 660 or so spacing. So there's some upside there as well. Floyd C. Wilson - Chairman & Chief Executive Officer: So Neil, the answer to your question is really about frac jobs and how more complex can you make them but keep them closer to the drilled wellbore. And that's improving in our industry day-by-day and as that improves that gives you a chance to leave less oil behind in the reservoir and down space your wells in an economic fashion. So we're watching what others are doing, and we're watching our frac technology quite closely to see if that lends itself to tighter spacing.

All right. Thank you, guys.

Thank you. And our last question is from the line of Ron Mills from Johnson Rice. Please go ahead. Ronald E. Mills - Johnson Rice & Co. LLC: Thanks. Floyd, just on the – just to not to belabor the cost savings, but this sounds like about two-thirds of that has been service costs, a third efficiencies. You're pretty clear that in this environment you expect the service costs to continue to come down. How much more meat do you think is on the bone relative to the efficiency side, which obviously would remain in place even if or when commodity prices improve? Floyd C. Wilson - Chairman & Chief Executive Officer: Well, that's kind of the cool thing that goes on here. Efficiencies were ongoing before the current situation with oil prices. I mean, two years ago it's taken us X days to drill a well and these days it's taken us two-thirds of X days or whatever. And those efficiencies will remain when prices go up. So that part is good. Now as far as continued improvements, that's our business and our peers' business is to continue to search for that perfect balance of cost and reward. And you never get to the perfect one, but you always are working for it and we're looking for all the time. So I think there's room for more. And there could be some breakthrough by one of the – one of us that one of these days that even has step-change there, but it's there's room for more on the efficiency side. Ronald E. Mills - Johnson Rice & Co. LLC: And then in the El Halcón area, the transition development mode is happening a little bit sooner than what I thought. I thought it was going to be later in the year, and that may owe a little bit to drilling these wells faster. But when you look at that rig now that it looks like the HBP component is really – is really finished, can you talk about with the allocation of that rig across that play? Because I know you have overall, you're – you're meeting the type curve, but there you have different type curves with the zone. Like how we should we think about the allocation of that across your – across your El Halcón position? Floyd C. Wilson - Chairman & Chief Executive Officer: So, since we're not stupid, the current schedule for that rig is in our best area. We're well-hedged, costs are down. It makes no sense to drill the other areas. So I think all of our remaining 2015, 2016 wells are situated in areas where we expect to hopefully exceed our type curve. So many of – we have so many locations there that we have plenty of tier – what we'd call tier 1 locations for a few years here before we dig into the other still attractive, but less lucrative. And hopefully prices will make those ever more attractive as time goes by, but we've got plenty of time right now to concentrate on the best part of the field. All of these shale fields – I don't know if you want call it – but there is a lot of variability. And until you drill enough wells in an area, the industry you don't really know 100% where that is. You can predict it, but you have to execute it well through the drilling. So we've done a lot of drilling there, 100 wells by now. We have a really good handle on where the more – the areas that are thicker and have all the components that would add up to higher, not just EUR, but these days the IP and the three-month and the 12-month IP are probably is as important to us as the EURs. Ronald E. Mills - Johnson Rice & Co. LLC: And then last I – kind of to circle back to Brian, one of Brian's questions. It was as you have that El Halcón rig really in the better areas just like you have the two rigs up in Fort Berthold, on a CapEx budget similar or lower than this year's for next year, is that – are you – do you think you'll be able to at least kind of maintain production for that level of CapEx as we look through the next 12 to 18 months? Floyd C. Wilson - Chairman & Chief Executive Officer: Yeah. Listen, if you're asking me what I think, right? So just to be clear I'm not predicting this, but yes, we think we can maintain production, and we think we can do it next year by spending less than $300 million. That's what I think. That's not guidance. Ronald E. Mills - Johnson Rice & Co. LLC: Right. Floyd C. Wilson - Chairman & Chief Executive Officer: That's – those are our targets and we have a bunch of smart people here at the company working to achieve those goals. Ronald E. Mills - Johnson Rice & Co. LLC: And then lastly just on the shut-ins and the deferrals up in Fort Berthold, and I know those are non-operated decisions, is that – does that – do you expect that backlog to continue to grow? In other words, are those guys still drilling wells that they're just not completing? Or is that 1,800 barrels a day that's not – they could be producing right now? Is that a pretty good number to – that can just resume at some point? Floyd C. Wilson - Chairman & Chief Executive Officer: If Charles has something I'd like him to mention if he has some info. You know oil was at $60 and it's at $50. Ronald E. Mills - Johnson Rice & Co. LLC: Right. Floyd C. Wilson - Chairman & Chief Executive Officer: So I don't – I think that those companies, and largely private companies I guess, that are – perhaps haven't done much hedging or I assume their plans are mobile. But I don't know. Have you got anything different on that or do you know? Charles E. Cusack - Chief Operating Officer & Executive Vice President: Well, when it was at $60 we started to see an uptick in completions, but that was all put in place at $60. We would have to wait and see. We obviously can't control what they do. Ronald E. Mills - Johnson Rice & Co. LLC: All right. No, I understand. Look, thanks for all the answers. Floyd C. Wilson - Chairman & Chief Executive Officer: Operator, I believe I've gotten a nod that we're done here. Thanks everyone and give us a call if we didn't cover something you wanted to talk about.

Ladies and gentlemen, thank you for participating in today's conference. This concludes the program and you may call disconnect. Have a wonderful day everyone.