Battalion Oil Corp (BATL) 2015 Q3 法說會逐字稿

Good day, ladies and gentlemen and thank you for standing by and welcome to Halcon Resources' third-quarter 2015 earnings conference call. (Operator Instructions). As a reminder, this conference is being recorded. And now I would like to turn the call to the Executive Vice President, CFO and Treasurer, Mark Mize. Please begin.

Good morning. Thank you. This conference call contains forward-looking statements. For a detailed description of our disclaimer, you can see our earnings release that we issued yesterday and we posted on our website.

Production for the third quarter was in line with our guidance and averaged about 40,739 barrels of oil equivalent per day. We published production guidance for the fourth quarter in our earnings release yesterday, which indicates we expect to be in line with our full-year 2015 guidance range despite the previously disclosed negative impacts associated with non-operated production in the Williston Basin that was either shut in or deferred.

On the cost side, LOE plus workover expense was just over $7 per BOE in the third quarter, which was below our guidance range for the year and represents about a 6% improvement compared to the second quarter of this year. After adjusting for selected items, cash G&A was $4.58 per BOE in the third quarter, which was toward the low end of our guidance range for the year and slightly lower than the second quarter.

Taxes other than income came in at $3.23 per BOE for the quarter, which was also below our guidance range for the year and gathering, transportation and other after adjusting for some selected items was just over $2 per BOE, which is in line with guidance.

An overall look at operating cost per BOE, we decreased about 3% compared to the second quarter and more importantly about 27% when you compare to the third quarter of 2014. The cost reductions that we are experiencing are reflective of the continuing efforts to drive costs down both operationally, as well as administratively.

With respect to drilling and completion CapEx, we spent $84 million during the third quarter, which is in line with expectations. We continue to be extremely focused on both capital discipline and capital efficiency and we currently expect drilling and completion CapEx in the fourth quarter to be the low watermark for the year with our full-year D&C CapEx being within the previously disclosed guidance range.

With regards to hedging, I think I may have mentioned this on the last earnings call, we do not designate any positions as cash flow hedges for accounting purposes and therefore, we record any change in the value of those positions in the mark-to-market value of the derivative contracts on the income statement. We did realize a net gain on settled derivative contracts of about $115 million during the third quarter and I'm making a comment about the accounting that we applied because I think there's a lot of analysts that include the realized hedge gains and losses in their revenue estimates and we do not.

As of the close of the market yesterday, our hedge portfolio had a mark-to-market value of right around $350 million. Today, we have about 30,500 barrels per day of oil hedged for the remainder of 2015 at an average price of just over $90 a barrel. For 2016, we currently have about 25,500 barrels of oil hedged at an average price of just over $80 a barrel and then there's a small amount hedged in 2017.

We ended the quarter with $827 million of liquidity, consisting of cash on hand, plus our undrawn capacity on our revolver. And as we disclosed here a few days back, our bank group did recently reaffirm our $850 million borrowing base. Our next redetermination will be the regularly scheduled redetermination in the spring of 2016.

Since the beginning of the year, we've executed on several initiatives to strengthen our balance sheet and improve our leverage profile. During the third quarter, we were able to exchange right at $1.57 billion of unsecured debt for about $1 billion of third lien secured notes, which reduced our leverage by about -- our debt load by about $550 million. This exchange transaction resulted in an almost full turn improvement in our leverage profile with no dilution to our shareholders. And it also reduced our annual interest expense by about $12 million.

When you combine this with the exchanges that we did earlier this year, we've reduced our overall debt by more than $800 million. With this -- this is a strong step in the right direction, but we are going to remain focused on further improvement to our leverage profile as we move forward and with that, I will turn the call over to Floyd.

Thanks, Mark. So as Mark indicated, the environment that we are in demands efficiency. Halcon's operating staff has been very successful in driving efficiency gains without negatively impacting production rates. This will continue. We are operating three rigs today and we will likely keep three rigs running next year as well. A three-rig program in 2016 should run about 25% less in CapEx than this year and allow us to keep production relatively flat. Those are comments, not perfect guidance at this time.

In the Williston Basin, the wells that we put online this year are all outperforming our published type curves. We continued to set new drilling records during the third quarter in the Fort Berthold area. Our average time for Middle Bakken and Three Forks wells was 14 days. That's spud of surface to rig release. On completions, frac to first production times are one-third faster than they were this time last year and all of our completions are coming in under AFE.

Lease operating costs are also down about a third since this time last year. Completed well costs on our property in the Williston Basin have been running about $7.2 million this quarter while new AFEs are projecting $6.8 million, so presenting the continued cost declines that we are experiencing. About a third of the reduction, this is kind of a good point, about a third of the reduction in total completed well costs since last year for us is related to design modifications. These efficiencies will stick even in a higher commodity price environment.

We've also made significant progress in gas capture in the Williston Basin. We are currently selling approximately 95% of our gas at El Halcon in East Texas. This story is similar. Our average spud to TD was 11.4 days for a three-string well during the third quarter. That's about one-third less time than last year. Our shortest time for a three-string well this year was just under 10 days.

On the completion side, we've put away an average of four stages per day on wells completed during the third quarter. This is a 40% improvement year-over-year with one of those wells setting a record at five stages per day. We are in development mode at El Halcon and expect to drill two, three or four well pads from now through the end of next year. The current completed well cost is estimated at $6.8 million for a three-string well at El Halcon. This includes extensive design changes, a 500-foot increase in average lateral length to approximately 7500 feet and a 33% increase in the amount of proppant used, up to now about 2000 pounds per lateral foot. So $6.8 million if we were following our overdesign would be a lot less, but this is a much more efficient way to spend the money.

In summary, we will continue to make what capital we spend as efficient as possible. We will preserve our wonderful assets for an eventual improvement in crude prices. We will continue to work on reducing leverage and maintaining our strong liquidity position.

Maybe as important as all else that we do, we are flexible. We can cut spending quickly if conditions persist or we can maintain our current plan if conditions improve as we gauge if future changes are directional or blips. Carmen, we can take a few questions now if there are any.

Okay, thank you. (Operator Instructions). Neal Dingmann, SunTrust.

Say, Floyd, just a couple details. First, just on the Bakken. You mentioned early about well costs now even down as low as $6.8 million. Is that something you think can trend forward or is that $7.2 million more a likely rate for early in the year?

If things stay as they are, the definite trend is beneath $7 million.

Got it. All right. And then just my follow-up, over in the El Halcon, you mentioned about two new records, pretty amazing, the three-string at 9.7 days as well as the record on the five stages per single well. Again, is that -- either one of those -- do you consider those potential repeatable or are those sort of one-offs for now?

I don't know about the less than 10 days, but the 14 days is a very achievable number and as you know, that brings additional issues in terms of spend because you drill more wells with the same rig days in a year. So it puts pressure on your budget unless you start delaying things. I pointed this out, but the really interesting part about all that's been going on is that, for Halcon, about a third of our cost reductions have been in design changes and efficiency gains rather than just negotiating with suppliers and those cost-reduction ideas will continue even in a higher price environment.

Great point, Floyd. If things do run ahead like that, when you look at the budget, would you let rigs go occasionally? How do you think of that? Obviously, the benefit of that is, as you said, you would be spending more money. How do you think about that for the plan next year?

Well, we don't intend to spend more and as I said, we are projecting about $325 million for this year. We may beat that. It will be at least 25% less next year with the same rigs with a fairly flat production profile. If the conditions persist as they are or deteriorate, we will certainly, as I said, we will be flexible to slow down the spend and contain that and if things improve, and this is probably an important thing to understand about us, if things improve, we are not going to increase our spend. We're going to give it enough time to make sure it's a real new direction as opposed to just a temporary move driven by speculation and whatnot.

Thanks, Floyd. Appreciate the comments.

Don Crist, Johnson Rice.

Hi, guys. It's Ron Mills. Can you just give us an update on acquisition market appetite on your side? I know you, in the last call, talked about continuing to look at opportunities and in addition to what you've done on the debt side, there's also ways where some opportunities can be deleveraging. Just curious what that market looks like, bid/ask spread and whether or not you think that frees up a little bit? I think people were expecting with this redetermination period that maybe does that slip into the early part of 2016 depending on how the redetermination period looks then.

Well, our entire history, Ron, has been full of continue to look for ways to improve and add to the quality of whatever property set we've owned. It's no different now. We are highly selective. We are very covetous of our liquidity, so we are very conservative in how we might use it, but we are, as always, willing to use it. Again, though, we are highly selective.

In terms of what slips into next year in the spring, Mark can make some comments about that, but we've had extensive conversations about what might happen with us in the spring. I can't speak for the industry and we have a very strong asset base and a great group of banks, so we are not expecting any kind of giant draconian situation in terms of as it relates to Halcon.

Okay. And then on Neal's questions, could you just clarify, when you talked about the $325 million, that's this year's budget?

That's what we've estimated for this year. We may or may not beat that. I'm not sure. But we are estimating right now if we keep the same number of rigs running, we will spend about 25% less. Keep in mind that the first quarter, four months, maybe five of this year, had some sort of older costs involved.

Right, right. And so when you -- and in terms of given the same number of rigs from a well count standpoint, given the continued improvement in drilling days, is that something from an activity level, even though you spend 20% or 25% less from an overactivity level, it's going to be more similar to this year?

In terms of spend? No, we are going to try to spend about 25% less next year and keep a relatively flat profile. The reason we can do that is that, like many others in the industry, but certainly at Halcon, we are getting a lot more out of each well.

And you're getting more out of each rig as well because of drilling efficiencies?

We are getting more out of each rig, which is the double-edged blade and that tends to drive your spend up. So we will moderate wherever we need to to maintain a sensible approach to watching the crude price and see what is really going to happen. We have no idea right now. We are hedged, but we don't really count that in our planning. We are planning on the strip happening. If it doesn't happen, whether it's up or down, we will make some adjustments. In other words, we are going to try to spend a significant amount less next year than this keeping us relatively flat.

And then lastly, just operationally, it seems like both the Bakken and El Halcon relative to curves you continue to outperform. In particular at El Halcon, when did you shift to pad drilling and how quickly do you think you can realize the incremental cost savings you mentioned in the release?

Yes, we are on pad drilling now. We are only running one rig there. So if we were running five or six rigs on pad drilling, you would see some immediate numbers and things, but when you are running one rig, you are completing two or three or four wells in a quarter. We fully expect that the increases in cost due to our design, longer laterals and more proppant have been more than offset by other types of gains, i.e. fewer rig days on a well and less horsepower used on completions or less time, I should say, on completions with frac jobs. And actually on inefficiency, quicker to market times in both areas. So you mix all that together, again, we think we can spend less money and keep production about where it is as we watch crude prices.

Great. Thanks, Floyd.

Sean Sneeden, Oppenheimer.

Mark, you mentioned in your prepared remarks that you are looking at further ways to deleverage the balance sheet. I guess with the third lien exchange being done, is there an ability for you guys to do more unsecured for third lien or are you looking at other mechanisms like unsecured for converts or maybe talk about how you are thinking about that process?

There is not additional third lien capacity, so I can just address that one straight up. Obviously, any other plans or discussions that we're having internally that aren't public, we are not talking about. But we do feel like we have some options available to us, so we are giving them consideration internally right now.

Okay. Would you describe those options as more capital market-based or is this something we should be thinking about in terms of like an asset sale or anything along those lines?

No.

There you go.

We have several levers we can pull. We are evaluating all of them constantly. We are in good shape at this moment. We are not in good shape forever, but we are in good shape at this moment. So we are pretty -- we understand what's going on in the market and we are evaluating lots of different ideas and when one comes to the forefront, you will hear about it after we did it.

That's fair enough. Maybe just thinking about the indications for next year, I guess. Number one, what do you think you need to spend on infrastructure or capitalized G&A and interest on top of your, call it, $250 million-ish type of number on D&C?

That's a question for Mark. On infrastructure, we are not spending much. We, of course, have some things going on, but it's not very much. It's included in our other number, so it's a nominal number. Mark, what about the rest of that?

I'm sorry, was that question about capitalized interest, is that correct?

Yes, that's right.

Yes, about 30%.

Okay. And then just housekeeping on keeping production flat. Are we talking just on a year-over-year basis or are you thinking about that on an exit-to-exit basis?

We are thinking about looking at a whole year's worth of work and since you do have sort of a natural decline built into your PDP base, you can't have a fourth quarter that's dramatically less than your other fourth quarter than your prior fourth quarter. It's mathematically impossible. So our feeling right now is that we need the EBITDA. We are hedged. We are going to keep it relatively flat and watch how things unfold in the markets and whatnot.

Okay. I think that makes sense. I appreciate it. Thank you.

Dan Guffey, Stifel.

Wondering if you can, I guess, give any guidance in terms of how many wells in El Halcon have been drilled with the upsized frac and then kind of talk about, if you have any data, if that supports an increase to your type curve.

You know, Charles should talk about how many wells -- it's early days in this. We tend to not make any changes in type curves until we have plenty of hard evidence in our hands. We can tell you that we will for sure outperform our existing published type curves. Charles, anything to add to that?

Yes, we have three that are flowing -- they are in early stages right now -- flowing back and then two more we are currently completing and then three more we are currently drilling that will all be with the same design. So we will have a lot of data here in a few months.

Okay, great. And then you mentioned $6.8 million well cost on a three-string. Is everything you are drilling now three-string up in Brazos? Is that where you are focusing?

Charles, go ahead and answer it, but it's not Brazos, but go ahead.

It's in Burleson and it's all three-string.

It is? Okay. All right, great. And then I guess moving up to the Bakken, can you remind us of undrilled locations on the Indian reservation and then I guess what spacing assumptions are you assuming in both the Bakken and the Three Forks to get you to that location number?

We are so far away from being developed up there. Charles, please correct me, but I believe all of our indications are that the Middle Bakken in most areas is responding pretty well to 660 feet between wells. And then if you are in an area where the Three Forks is good, you have to temper that spacing pattern with the knowledge that there's some cross drainage, so you don't ever want to stack laterals. You want to have an alternate pattern. So when we are drilling a pad, we are solving for the overall capital efficiency based on reservoir characteristics of all the locations we might drill. We are trying to drill them all at once. Charles, what would you say about all that?

No, that's right. We are drilling everything on 660s right now, pretty much Three Forks and Middle Bakken. Unless there are pre-existing wells that kind of complicate that pattern, then you've got to work around those. But there's a couple hundred locations up there.

Okay, all right. I appreciate the info. Thanks, guys.

This concludes the Q&A session. I will turn the call back to our Chairman and CEO, Floyd Wilson, for final remarks.

Well, that's it, everybody. Thanks for calling in. Feel free to contact us if we didn't cover something that you wanted to have covered. Thanks.

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