Battalion Oil Corp (BATL) 2015 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halcon 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. (Operator Instructions)

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.

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 will start the call today by summarizing the steps we've taken over the past few months to improve our balance sheet, and then I will 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 expanded 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 of about $1.63, but we are not doing any more transactions at this time just due to current trading levels.

Third, we negotiated with bondholders to exchange $0.25 billion in face value of our senior unsecured notes into 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 draw 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 all these efforts is that we have no near-term maturities. 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 is currently shut in or deferred.

Having said that, we are still comparable with our full-year production guidance of 40,000 to 45,000 BOE a day. On the cost side, LOE plus workover expense of $7.70 per BOE in the second quarter, which is below our guidance range of the year, 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 is $4.60 per BOE in the second quarter, which is at the low end of our guidance range for the year. And it'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 was also in line with full-year guidance. So overall, total operating costs per BOE improved 11% compared to the first quarter of this year and 28% compared to the second quarter of 2014. These cost improvements are the result of continued efforts to drive efficiencies in all aspects of the business. And we are 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 our 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 hedged positions as cash flow hedges for accounting purposes. And accordingly, we continue to record the net change in the mark-to-market value of derivative contracts. On the income statement we reported 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 at June 30 versus March 31 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 will continue to layer in positions in 2016 and 2017 to try to meet our targets. With that, I will turn the call back over to Floyd.

Thanks, Mark. Okay, our second quarter was excellent operationally. Completed well costs came down significantly throughout the quarter, and that trend continues. We are 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 costs down and production up. We are drilling our wells in record time --- some wells in only 16 or 17 days. That's spud to rig release. We have continued to adjust our completions based on past results and feel we are closing in on a near-perfect completion scenario.

In the Williston Basin gas capture for Halcon will be at over 90% by year-end. At our current rig deployment level, we have about 10 years of inventory, including a couple hundred locations at Fort Berthold and over 400 viable locations in 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 Halcon, 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 lease 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 Halcon drill days per well are decreasing. Costs are going down and completions becoming ever more efficient. Current thinking, largely based on our current frac design, leads us to plan to space future wells at El Halcon at 800 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. Costs are down; 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 drill and 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 -- you know, we are in stormy seas at this time. And while we expect and hope for improvement, we are planning for current conditions to persist. Do not believe this is exactly the right time to press drillbit growth, which would mean add rigs and etc. so right now our plans are somewhat steady-state on the CapEx side. Our CapEx, as Mark mentioned, is -- our estimates of what we will spend this year is coming down each time we report.

With that, operator, we've got -- if there's any questions, we can address those.

(Operator Instructions) Brian Corales, Howard Weil.

Just a question more -- I guess the run rate in the back half of the year is $70 million $75 million in capital a quarter. Is that likely to maintain in 2016 based on your thoughts today?

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 thereabouts this year, the same rig program, we would spend less next year. We are not giving that guidance just yet, but we think we can do that and maintain production fairly well as well.

And I guess if you run three rigs, would it kind of have a similar makeup, too, in the Bakken, one in El Halcon? Or when you get the pads, would El Halcon potentially get more of the capital?

Well, while the current economics at El Halcon 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 Halcon at this time.

Okay, thanks, guys.

Jason Wangler, Wunderlich.

Was curious -- at El Halcon, as you move to new development, what kind of -- or how big are the pads are you looking to drill? Is it going to be a couple wells at a time? Where do you see that going as you kind of get into that program?

Charles is sitting here. Let me just let him address that. He's been doing all of this planning with our operation teams just recently, so it's right on the tip of his tongue.

Yes, I would say it's going to be variable. We are 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. And it all depends on the unit configurations, and where we are, and if we are trying to drill into one unit or two units. So it's going to be a smorgasbord. And that's why we are -- the cost of -- the savings will vary pad to pad. As we get further into it, we will probably have more and more wells. But we are 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. I guess this last month has obviously been pretty ugly. Just what you're seeing out there, and maybe if you could give any color on what and even where you are targeting as you look to the M&A market?

No.

Always worth a shot.

You know, we don't talk about that. We are just doing what we do here, and we don't -- we don't really talk about that.

Okay, I appreciate it.

Chad Mabry, MLV & Co.

Good color on the call. Looks like you've done a good job of achieving your midyear well cost targets in both the Bakken and the Eagle Ford. Just curious if there is any more room for savings? How long you think this is sustainable? Just general thoughts on cost trends.

Well, our partners in our business on the service side are under the same sorts of pressure that we are. So our partnership with them persists, even though it seems like we are pushing for lower costs all the time.

The costs that you've seen on -- the actual historical costs that you have seen reported by us for the entire first half of this year involve a mixture of wells drilled on kind of an old 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 AFE, that means a well that we are going to spud soon. We will be at that level. If oil prices -- this is only an opinion -- if oil prices stay low, there is going to be more pressure on service costs to go down, and that is just a fact of life.

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 extended, etc. Do you see that staying at $900 million?

You know, 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 will stay at $900 million.

Maybe -- could there be a slight reduction of some amount? Maybe. But we are not expecting any significant movements.

All right. That is it for me. Thank you.

James Spicer, Wells Fargo.

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 provide there? I don't know if those would include things like bond repurchases or anything along those lines.

Let me answer for Mark. No. No comment.

No comment. Okay. And then another question I had here: in the 10-Q it looks like there is some additional disclosure around your agreement with Apollo in 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.

Let me ask David, sitting right here, to address that. But nothing's really changed. The contract and the agreement with Apollo had all of these things set out in them. And I think we made an adjustment to extend some of the time frame, 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 have just extended out the contract a bit.

Okay, thank you.

Neal Dingmann, SunTrust.

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?

Yes, that's correct.

Okay, and then just lastly, Floyd -- right now, Floyd, I'm just wondering on the locations at Fort Berthold, your thoughts there? And is the opportunity for -- you know, I know you guys had downspaced 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 is potential for a bit more.

Well, I mentioned that we have -- you know, just round numbers of a couple 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 costs.

Spacing is specific throughout the field. We space Three Forks wells, if they are in the same unit with Middle Bakken wells, a little differently. We space here and there differently based on results.

Charles is sitting here. I don't know if we have standardized 660 or 800 or whatever across the field?

On the Fort on the Middle Bakken, we are pretty much laying out at 660s now, and that is what we are drilling at. I will say some of the offset operators -- there are some 400-foot spacings right now we are watching very closely. So there is a chance, you know, there is upside to go closer there.

In the Three Forks, like Floyd alluded to, we've been a little more conservative. We have been spaced a little wider than that. So there is certainly a chance you could tighten up that Three Forks to the same 660 or so spacing. So there is some upside there as well.

So, Neal, 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 is improving in our industry day by day. As that improves, that gives you a chance to leave less oil behind in the reservoir and downspace your wells in an economic fashion. So we are watching what others are doing, and we are watching our frac technology quite closely to see if that lends itself to tighter spacing.

All right, thanks, you guys.

Ron Mills, Johnson Rice.

Floyd, just on the -- not to belabor the cost savings, but it sounded like about two-thirds of that has been service costs, a third efficiencies. You are 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 commodity -- or when commodity prices improve?

Well, that is kind of the cool thing that goes on here. Efficiencies were ongoing before the current situation with oil prices. Two years ago it was taking us X days to drill a well, and these days it's taking us two-thirds of X days or whatever. Those efficiencies will remain when prices go up. So that part is good.

Now, as far as continued improvements, that is our business and our peers' business is to continue to search for that perfect balance of cost and reward. You never get to the perfect one, but you always are working for it. We are looking for it all the time.

So I think there's room for more. And there could be some breakthrough by one of us one of these days that even has step change there. But there is room for more on the efficiency side.

And then in the El Halcon area, the transition development mode is happening a little bit sooner than what -- I thought it was going to be later in the year. 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 finished, can you talk about -- you know, with the allocation of that rig across that play, because I know you have -- overall you are meeting the type curve, but you have different type curves for the zone. How should we think about the allocation of that across your El Halcon position?

Since we are not stupid, the current schedule for that rig is in our best area. We are 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.

We have so many locations there that -- we have plenty of 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 have -- I don't know if you want to call it [spots] 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 actually do the well, do the drilling.

So we've done a lot of drilling. There are 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 will add up to a higher -- not just EUR, but these days the IP and the three-month and the 12-month IP are probably as important to us as the EURs.

And then lastly, kind of to circle back to one of Brian's questions, as you have that El Halcon 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 -- do you think you will be able to at least kind of maintain production for that level of CapEx as we look through the next 12 to 18 months?

Yes. Listen, if -- you are asking me what I think, right? So just to be clear, I am 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. Those are our targets, and we have a bunch of smart people here at the Company working to achieve those goals.

And then lastly, just on the shut-ins and deferrals up in Fort Berthold and others, those are non-operated decisions. Does that -- do you expect that backlog continue to grow? In other words, are those guys still drilling wells that they are just not completing? Or is that 1,800 barrels a day that's not -- that could be producing right now? Is that a pretty good number that can just resume at some point?

If Charles has something, I would like him to mention if he has some info. Oil was at $60, and it's at $50.

Right.

So I don't -- I think that those companies -- and largely private companies, I guess, that perhaps haven't done much hedging are -- I assume their plans are mobile. So I don't know. You got anything different on that, or do you know?

Well, one of the six that -- we started to see an uptick in completions, but that was all put in place at $60. So we would have to wait and see. We obviously can't control what they do.

No, I understand. Thanks for all the answers.

Operator, I believe I've gotten the nod that we are done here. Thanks, everyone, and give us a call if we didn't cover something you want to talk about.

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