Battalion Oil Corp (BATL) 2015 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Halcon Resources first-quarter 2015 earnings conference call. (Operator Instructions) As a reminder, this conference is being recorded.

I would like to introduce your host for today's conference, Mark Mize, our CFO. Mr. Mize, you may begin.

Okay. Thank you. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday and posted to our website. And we'll start the call with some financial comments, and then I'll turn it over to Floyd Wilson.

A few brief comments about our line of credit with the banks and liquidity. Subsequent to the quarter end, we amended our revolving credit agreement to provide covenant flexibility by removing the interest coverage ratio and replacing it with a total secured debt to EBITDA ratio of 2.75 times. We also extended the maturity of the facility from February of 2017 to August of 2019, and our credit facility continues to be led by JPMorgan and Wells Fargo. We continue to have a very supportive and constructive bank group that we are happy to call our partners.

Concurrent with the execution of the revolver amendment last week, we closed our second lien notes offering in the amount of $700 million and use the proceeds to repay borrowings on the credit facility with the banks. In conjunction with that capital raise, our borrowing base was reduced from $1.50 billion to $900 million. So we picked up net additional liquidity, up about $550 million, which is a great outcome for the Company.

Pro forma for the second lien offering and the borrowing base reduction, we ended the quarter with about $920 million of liquidity, which allows us to comfortably operate the Company well into 2018 with no additional capital raises required. This does assume an annual D&C capital spend equivalent to that of the current year, and it's based on current strip prices.

Production for the quarter was in line with our guidance to an average of just over 43,000 barrels of oil equivalent a day. We published production guidance for the second quarter in the earnings release, and this accounts for approximately 2000 Boe a day of nonoperated production in the Williston Basin that's currently shut in due to low commodity prices. However, we are reaffirming full-year 2015 production guidance of 40,000 to 45,000 Boe a day.

On the cost side, LOE plus workover expense was $9.51 per Boe in Q1, which was within our guidance range for the year of $8 to $10. Expect this line item to trend lower throughout the remainder of the year. And then after adjusting for selected items, cash G&A was just under $5 per Boe in the first quarter, which is in line with the guidance range of $4 to $6 and is consistent with expectations for the remainder of the year.

Taxes other than income came in under the low end of guidance of $3.16. Gathering, transportation and other after adjusting for some selected items came in at $2 per Boe, which is in line with full-year guidance. And then just overall total operating costs on a per Boe basis improved 8% compared to the fourth quarter of 2014. And we do expect continued improvement in 2015, not only driven by general market conditions but more importantly our cost-cutting initiatives, despite a relatively flat production profile for the remainder of 2015 as we round out 2015.

For modeling purposes, it's worth mentioning that due to an overall decrease in unevaluated properties, which is the basis for the capitalized interest calculation, we're capitalizing less interest expense than we have historically and are now projecting capitalized interest to be about 30% of our total interest burden in 2015.

Also, we produced our annual cash interest expense by approximately $25 million as a result of the recent common equity for debt swaps that we've executed, and given the recent ceiling test write-downs, our DD&A rate has also declined.

With regards to D&C CapEx, we spent approximately $105 million during the first quarter, which is in line with expectations. We continue to be extremely focused on capital discipline this year as we have indicated by our reduced 2015 capital budget, and our current D&C budget for this year was reduced by another $25 million to $325 million to $375 million.

2015 D&C CapEx will be front-half loaded, primarily due to the number of wells waiting on completion at the end of 2014 related to more rigs running in late 2014 as compared to current levels.

Finally, with regard to hedges, as the close of market yesterday, we had a mark-to-market value of about $320 million. Today we have 31,410 barrels per day of oil hedged for the remainder of 2015 at an average price of $90.28 and for 2016 have about right at 25,000 barrels per day of oil hedged at an average price of just over $81 per barrel, and we've recently started layering in some hedges in 2017.

While our hedging for 2015 is complete, we will continue to opportunistically layer in additional hedges in 2016 and 2017 to meet our target of being hedged at about 80% of what we expect to produce.

And with that, I'll turn the call back to Floyd.

Thanks, Mark. The performance of the wells we put online in the fourth quarter was excellent and consistent, despite the headwinds our industry is currently facing. Well costs came down meaningfully, and we expect this trend to continue.

Based on our lower completed well cost expectations, we reduced our 2015 drilling and completion budget yet again by another $25 million to about $350 million, as Mark mentioned.

One of our top priorities is to strengthen our balance sheet. The senior secured second lien note offering was implemented to improve liquidity and shore up the balance sheet. We have sufficient liquidity to fund our operations and service our obligations for the next several years, even if low oil prices persist, and our near-term maturities have been extended, which Mark also mentioned.

We currently have about (technical difficulty) completed or waiting on completion. We are running three rigs, two up north and one at El Halcon. We expect to keep the same three rig program throughout the remainder of this year.

In the Williston Basin, wells put online during the first quarter are outperforming our type curves in both areas: Fort Berthold and Williams County. Downspacing continues to yield positive results, and the data suggests that 660-foot spacing will be appropriate over much of our position.

In the Fort Berthold area, we brought six wells online during the quarter that were spaced between 660 and 770 feet apart drilled from a single pad with a cumulative IP rate of 21,000 barrels a day. One of these wells IP'd at 5248 barrels a day, another new record for us and perhaps for the field.

Completed well costs in the Fort Berthold area have come down over 30% since the fourth quarter of last year. Currently about $8 million, we expect to see more savings or cost reductions in the near term. Using the current strip, the IRR for a well that meets our 801 MBoe type curve in the Fort Berthold area is roughly 50% irrespective of hedges.

We recently put three wells online in Williams County that were spaced 865 feet apart, and they are outperforming our 477 Boe per day type curve for that area with an average IP of 1777 Boe per day. We're in the process of bringing three more wells online in this area and expect some results.

Remember in Williams County, costs are about $1 million per well less than in Fort Berthold, so the economics are competitive.

Drilling to completion efficiencies are an ongoing project at our Company. We are having some success there, notably through more efficient power sourcing and water disposal solutions, repurposing of existing equipment and optimizing chemical programs and effectively managing our work over program including offset frac preparation.

We continue to increase gas capture in the Williston Basin. Currently nearly 90% of our gas production is being sold, which is well above the limits imposed by the NDIC.

In East Texas at El Halcon, results have been consistent, and the wells we have drilled in this quarter, all four wells we put on line during the first quarter are outperforming our 452 MBoe type curve. We are continuing to look for ways to improve efficiency and reduce costs at El Halcon.

In addition to across the board service cost reductions, we've taken the additional steps of bringing directional drilling (technical difficulty) management services in-house, and that's going great.

Current AFE for wells we drilled at Halcon is approximately $7.5 million or about 30% lower than where we were for most of the fourth quarter. Using the current strip, the IRR for a well that meets our 452 type curve at El Halcon is about 20% irrespective hedges. We anticipate completed well costs to continue to decline by an initial 5% to 15% in the next few months.

Also, I'll remind you that we're still in lease capture mode at El Halcon, which means we're only drilling one well per pad this year. That means that that well has to bear the full costs for location and title opinion production facilities and gathering tie-ins. They're all charged to that first well.

Completed well costs in this play will decline by about another $1 million per well once we transition into development group mode next year. And, of course, the economics become compelling.

So operationally, things are going well, and we have the liquidity to see ourselves through the next four years. Our acreage in the Williston Basin and at El Halcon as located in the core of each play has been derisked, and we have an inventory of hundreds and hundreds of future all but proved locations. Our three rig program for 2015 is barely dipping into this inventory.

We continue to improve on addressing leverage concerns and are tackling this issue from all angles. As our background would suggest, we are an acquisitive management team and are constantly generating ideas that could improve Halcon.

Operator, we are ready for questions if there are any.

(Operator Instructions). Neal Dingmann, SunTrust.

Say, Floyd, I'm just looking at slides 13 and 20 that shows the well cost reductions. I guess the question for you, Mark or Charles, are you continuing to push those down? And if so, is it through the -- just kind of wondering what areas are you able to continue to push down? Is it the D&C reductions, the completion costs, facilities or sort of all of the above?

Charles is sitting here. I'm going to ask him to address that. But it's pretty much all of the above. The largest single reduction has been, of course, in the frac and the pumping of the wells, but what do you say, Charles?

Yes, it's everything from the brokers on the front end all the way through the drill and completions. It's every single facet we competitively bid. So it's supply and demand, and we've driven them all down.

Some of it is through efficiencies and, like Floyd mentioned, bringing some services in-house and doing things a little more efficient, which drives prices down, but the bulk majority of it is just service cost reductions.

Okay. Good to hear. And Floyd, what's your thoughts today, Floyd, with prices rallying a bit here in the last few weeks? Your sensitivities to prices rallying and then your thoughts on -- I know you guys don't do this as much; others out there do more of these completion deferrals. Just your thoughts about that. So those two things you could hit?

Well, one of our objectives, Neal, has been to place ourselves in a position that when and if this low price environment changes for the better that we won't have significantly decline in production, at the same time not significantly reducing our future inventories.

So we are looking hard at the strip for this year, and we do have some thoughts about certain frac jobs that may occur at a month or two later than they might have. But we have a weather eye on our production projection and intend to maintain that. So you can't defer things without affecting your prior projections. So we have to try to blend all that together.

We have such a substantial hedge book for 2015. In 2016 it's, of course, helpful to receive the higher physical price, but we are not quite as buffeted this year and next by the spot price for oil.

Okay. Lastly maybe just for Mark. Mark, your thoughts on additional debt swaps or expectations around liquidity there.

Listen, Neal, Mark is sitting here and he just coughed or something, but we don't have any additional debt swaps on the boards right now, and our ATM is currently suspended.

Thanks, Floyd. Perfect.

Steve Berman, Canaccord.

In the TMS, you are participating in a non-op basis recently, and if you are, what are you seeing in terms of AFEs? And with oil rallying here, are we getting close to where you might think about going back in there on an operated basis?

Steve, as we've said, there's a ton of oil down in the TMS. There's billions of barrels of recoverable oil. We've seen some dramatic improvements in the expectation for completed well costs down from the levels that they were in the last couple of years.

We at this Company have no plans to drill any wells there this year. Like I said, it's a huge prize, and I think the entire industry is going to be watching that. It's going to require some more activity, which I don't think is going to happen this year from the industry, and that activity will generate information and knowledge that will be useful in fine-tuning the approach down there.

So we are on the sidelines in terms of drilling down there, and we are watching what everyone's doing. We are in a consortium for all the information that's being generated, and we are adding our information to that.

So I don't know what you're looking for there. We don't spend much time talking about the TMS right now.

Yes, that was a perfect answer. Thanks, Floyd. That's it for me.

Don Crist, Johnson Rice.

In regards to the shut-ins that you talked about in your press release, did those impact the Q1, and is there a timeline as to when those will come back online in the Williston?

We don't have a number, but they impacted Q1 a little bit. And we are not certainly not the ones that are -- the non-op ones, we are not in charge of those. I'm not so sure if we have any intelligence from our partners as to when they'll put those back on, but with the improving strip, we are expecting to get back on this year. But we don't have a timeline.

Okay. Given that this point in the cycle is normally a very good time to buy assets and your increased liquidity position, can you talk a little about the M&A market as you see it right now and your appetite for possibly buying something?

Well, of course, we've got plenty of capacity to do something, but as we've always said, we have a strict focus on property quality, and we have a strict focus on improving core areas or adding to core areas or creating a new core area.

I don't see a lot of action out there. I still think that there is an expectation that prices are going to be better in the future and that a lot of people that might want to sell might be waiting a bit. I don't know all these guys talk about bid/ask, I don't know about all that. I just don't see a lot going on that could change overnight.

We are watching everything closely, and we are always willing to participate in buy or sale if it suits our very strict objectives.

Okay. That's all the questions I had. Thanks, Floyd.

Michael Rowe, Tudor Pickering Holt and Company.

I was just wondering in El Halcon, you're kind of getting about a 17% rate of return at current strip at the $7 million well costs. So I was wondering given your capital structure, what's the rate of return you're looking to get there before you would consider adding capital back to the area. I know you're just in HBP mode right now.

Well, two things. You didn't ask why we're drilling there. It's a wonderful area, and we intend to maintain our great position there through the course of this lower oil price environment. And someday prices and rates return will be quite a bit higher there.

In the general sense, we look for returns that are well over 30%, and usually they are higher than that. As you know in our business, (expletive) happens, so you have to have higher returns on your single well economics to make up for things that just come along.

So we are looking forward to the time when current single well economics are offering 30% to 40% rates of return, and that would generate a lot of interest in an increase in activity there. We will not increase our activity there this year.

Okay. And do you still think it's appropriate to have multiple type curves there? And I was wondering do you anticipate returns are materially different between Brazos and Burleson County at this point?

Well, again, Charles is sitting here, but it's too simple to just spread the counties and say when is this and when is that. They are distinct areas, and we've got it divided into five or six areas. So we're trying to do an efficiency exercise as to what expiries we have, where they are located, how that sets up for future pad drilling, and any competitor activity, and also just trying to drill to make sure we're drilling good locations now. Since we are hedged, we can afford to drill good locations, instead of just trying to drill the edges or whatever.

So, we're highly focused on that. I don't know if that's an answer. Charles, have you got anything else to that?

The only thing I'd add in simple terms is the northern part of Brazos is our two stream area, and it's about $1 million less per well. The reserves are a little bit lower, but they are $6.5 million wells out there. In the general sense, that's probably the easiest way to break it out.

So the other area being requiring three stream completions, which, as Charles just said, adds about $1 million per well.

Fair enough. Yes, that was the color I was looking for. I guess just lastly, more from a corporate standpoint, you've talked a little bit about your substantial hedge book you've got for 2015 and 2016. So, in that context, can you talk about your decision to add to liquidity and reduce cash interest expense by issuing new common shares at this point?

It seems like -- you mean, issuing new common shares through the debt swaps, or what are you talking about?

Yes, for the debt swaps.

Well, listen, right or wrong or popular or not, if you are trying to reduce debt, you have to do something. So, we have some great partners that hold some of our longer-term debt. We've been -- we've made a few of these swaps that turn into equity, and we think that the benefits of doing that and also achieving another highly friendly group of common shareholders is it outweighs the dilution and whatnot.

So it's hard to come up with an answer that everyone would like, but we have been and will continue to sort of work on all angles of our finances here, and right now we're in awesome shape, and we don't have to do anything. So we're put ourselves in that -- Mark put us in that position on purpose, and we will be there now.

Now we'll evaluate additional swaps of debt in our normal practice or business process when and if they come up, and on the ATM, if that was part of your question, we'll access the market through the ATM when we believe it makes sense to do so. And that, of course, has to do with share price and whatnot.

The great news is we won't have to do anything now. Mark has got us in that spot where we can run our production, our wells, drill our wells, make all of our obligations easily and have several years of running room. So I don't like where we are with oil prices, but we are in a great spot right now.

Okay. Thank you.

James Spicer, Wells Fargo.

I had a question on the CapEx spend. You mentioned $105 million in the first quarter, and I think capitalized interest was about $25 million. What was the incremental difference between that and the $265 million on the cash flow statement? Was that just carryover from 2014?

The cash flow statement is what's been paid. Physically a lot of that was Q4 (multiple speakers).

I don't know if you heard that -- and I know you're aware of this, so I might be stating the obvious to you. But the number you're seeing on the cash flow statement does reflect actual -- in the investing section does reflect actual cash being paid on those capital items. So that can be items that had -- were accrued at the end of 2014 that actually get paid in the first quarter of 2015.

Yes, that's what I suspected it was, just verifying. And then just to follow up on the deleveraging discussion here, wondering if you have any targets there in terms of amount and timing, and then if there are other ideas beyond the debt for equity swaps that you guys are looking at, if you have any more color there?

Well, our target would be to get all of the holders to totally release us of all debt obligations. I don't think that's going to happen, so we'll make our payments, and if in our process we think that additional moves are smart, along the way we'll do that. Our targets -- when the price kept dropping so dramatically through the course of the second half of 2014, our targets became more liquidity and process oriented and keeping together the production and the acreage more than what are we going to do? So we went out and did those things to make sure we are in that position.

Our targets would be to reduce leverage over time and to get it down dramatically, either by reducing leverage or increasing production.

Okay. Thank you.

Jason Wangler, Wunderlich.

Just down in El Halcon, curious it looks like the rig now is kind of in that Northeastern position, and I know you have some expiration stuff, too. But what is the plan for this year as you kind of continue to look at it? Are you still kind of working through some of the fringes as you push out or the 10 to 12 I think it is wells this year, kind of where do you expect those to be drilled?

They're really kind of bouncing around the field. Yes, we do have some up in northern Burleson. We've also drilled down the southern part of Brazos. But it's going to some of our larger leases that are coming up on the end of the terms. They are all single well units at this point, and generally all outperforming the type curve.

Okay. And maybe for Mark, just curious I think you mentioned that you started to put some hedges on in 2017. Just curious where you're seeing those levels. Just I don't think there was anything more than that. Just curious what you're able to get given the run in oil.

Right now, we're kind of having indicative bids come in at 65, 75 type levels.

Great. I appreciate it.

Sean Sneeden, Oppenheimer.

I guess number one, Floyd, did you say the ATM program is currently suspended?

It's currently suspended. We don't run that one. We are not in a window anyway, so we haven't been in a window until, I think, tomorrow.

Okay.

With the share price though, it didn't make a lot of sense right today, and we'll access it if we think it makes some sense in the future. You know, that's supposed to be an opportunistic sort of a thing and rather than just something you are going to just push through no matter what the costs are. So we'll continue to avail ourselves of that if we think it's appropriate, but not right now.

Just to be clear, there's no tie up with the debt for equity swaps that prevents you from moving forward with the ATM program if the share prices are at an optimal level for you guys, right?

No, we don't do agreements that tie us from other things like that. There's no -- that's just our discretionary program.

Okay. Perfect. And then maybe for Mark or Floyd, the 6% sequential decline in production for the second quarter I guess at the midpoint, is that mainly being driven by timing and completions, or how should we think about that in the context of full-year production, which I think was affirmed for the full year?

Well, as Mark pointed out, it's 100% the combination of timing of completions and some shut-ins for non-operators. We expect to be back on during the course of the year. That guidance on purpose reaffirmed our full-year guidance. We don't do that lightly.

So our planning and expectations are that this dip, as you call it, is a normal thing that happens after winter and with some operators that are preferred to shut production in, and we expect those to come back.

And also completion timing. I mean we are doing -- it's largely driven by Williston Basin since we are running more rigs there, and we are doing pad drilling there.

So, as we mentioned that, I can't remember the name of the pad that we brought on in the first quarter of six well pads -- Sniffles, the six well pad recently brought on.

You have to drill all those wells, frac them all and get them all in production. So that becomes sort of lumpy. The fewer rigs you're running and the fewer completions, it's even more lumpy.

So we've scheduled these things out with a lot of forethought and planning. And I saw a couple of notes that said, oh boy, they are reducing this or that, and that's just a bunch of (expletive). We maintain full-year guidance, and we are used to what goes on with completions and our great partners in the field that under their own discretion they decide to wait for higher prices.

Okay. That actually makes sense. Maybe just lastly, Floyd, as you kind of think about the balance sheet and other initiatives, would you guys ever consider doing a JV in the El Halcon to help expedite your movement to development mode there at all?

Sure. I'm not so sure that today's the right day to do a JV. If you think about how acreage prices have gone, they pretty much tracked oil prices from $100 down to $50. So I don't know that that's -- we look at that kind of thing all the time, and we are wide-open and we have those discussions.

In the past, we were very well served by not doing the JV at the last company we all worked for and keeping the 100% of the property together until the exit.

So there's a -- yes, we look at it and we think about it and we accept discussions on it all the time. But our history suggests that if you are -- since we're not in a bind now, we don't feel like we have to do that.

And I don't know of any great reason to expedite drilling there with the prices exactly where they have been for anybody.

That's helpful. Thank you.

Jason Gilbert, Goldman Sachs.

Floyd, I think you mentioned at the end of the prepared comments that you were looking at ways to reduce leverage possibly through M&A. Did I hear that correctly, and if so, can you maybe elaborate on that a bit?

I was hoping you didn't hear that, but of course. There's any number of smaller E&P company business combinations that could look good on a property basis and could have the impact of a leverage improvement. And just like anything else we do, we're looking at that all the time.

There's nothing on the horizon and no firm plans, but we are -- that is sort of our nature to be continually sifting through ideas of how to make things bigger, stronger, better, faster, etc.

Okay. That's helpful. And then I guess the second one would be at El Halcon, given the strong well results, would you think about raising the type curve there at some point?

We could. Keep in mind that at both El Halcon and the Williston Basin, our type curves are based on averages of areas that vary a bit. So if we wanted to put out a group of type curves, we would put out a definite much higher type curve for some of the wells that we are in the some areas and similar type curve as we have.

So I think for planning purposes, the type curves we have out there since we are running a small number of rigs in both fields should be good enough for anybody that's addressing their model on our Company. We just -- I don't see a big push to finetune that right now. We are outperforming all of them, so that's good.

Okay. Great. Thank you. I'll turn it back to the call.

Thank you. And our last question comes from the line of Dan McSpirit from BMO.

My questions have been answered. Thank you.

All right, operator. Thanks a lot, everyone, and if you think of something we didn't cover, just give us a call. Thanks.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program. You may now disconnect. Everyone, have a great day.