Battalion Oil Corp (BATL) 2017 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halcón Resources First Quarter 2017 Earnings Conference Call. (Operator Instructions) And as a reminder, this conference is being recorded.

And now I'll turn the conference over to your host, Mark Mize, Executive Vice President and Chief Financial Officer. Please begin.

Okay. Good morning. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday and posted on our website. We've also updated our investor presentation for the first quarter and certain other items. And you can access that presentation on our website also.

I'm going to begin the call with comments on our financial performance during the first quarter as well as some thoughts on our updated 2017 guidance. And then I'm going to turn the call over to Jon Wright, SVP of Operations. He's going to make some comments about operations, and then Floyd will finish the call with a few comments.

Production for the first quarter averaged 38,478 barrels of oil equivalent per day, which exceeded the high end of our guidance range of 36,000 to 37,000 Boe a day. The strong first quarter production was driven by outperformance from several wells put online in late 2016 on Fort Berthold as well as improved production from existing PDP wells on our recent Pecos County acquisition.

Our realized first quarter oil differential of 90% of NYMEX was slightly better than the 89% we saw in the fourth quarter. And our first quarter natural gas differential came in at 77% in NYMEX. And the NGL differential for the first quarter was 27%.

For 2017, we conservatively estimate our company-wide differentials to be approximately 90% for oil, 85% for gas and 30% for NGLs based on the current strip.

LOE expense was $5.96 per Boe in the first quarter versus $5.23 in the fourth quarter of 2016. Workover expense was $3.30 per Boe in the first quarter versus $2.52 in the fourth quarter. And both LOE and workover expense on a per unit basis did increase in the first quarter, but it's mainly due to the impact of the El Halcón still on production levels as well as some inclement weather conditions in the Bakken.

Taxes other than income came in at $3.34 per Boe during the first quarter versus $2.87 in the fourth quarter. And this increase was driven by higher average oil and gas prices experienced in the current quarter.

Gathering, transportation and other after adjusting for selected items came in at $2.66 per Boe for the first quarter, which is roughly in line with the fourth quarter rate of $2.54.

And after adjusting for selected items, G&A expense was $3.44 per Boe in the first quarter versus $3.90 in the fourth quarter of last year. Our G&A expense continues to trend down as we focus on reducing corporate level expenditures.

Total operating costs adjusted for selected items were $18.70 per Boe in the first quarter versus $17.06 in the fourth quarter of 2016.

With respect to D&C CapEx, we incurred $39 million during the current quarter. As previously announced, we also spent $727 million on our Pecos County acquisition, which was largely funded with cash proceeds from the $500 million sale of El Halcón and a placement of $400 million of equity.

With regard to hedges, we realized a net gain on settled derivative contracts of about $2 million during the first quarter. Hedged settlement proceeds are expected to be much lower in 2017 versus 2016, given our average hedged oil price per barrel in 2017.

For the last 9 months of 2017, we have 20,645 barrels per day of oil hedged at an average price of $54.89. And for 2018, we currently have 5,000 barrels a day of oil hedged at $54.73.

With regards to gas, we have 18,900 MMBtu of gas hedged for the remainder of 2017 at an average price of $3.34. And then we have 5,000 MMBtu of gas hedged in 2018 at $3.19. As we have historically done, we'll continue to monitor the strip and look at hedges as it's appropriate.

As of March 31 and pro forma for the recent $650 million borrowing base redeterminations, that's an increase of $50 million to the borrowing base, we had just over $700 million of liquidity, which consisted of revolver availability in cash on the balance sheet. Our next borrowing base redetermination is scheduled for October of this year, and we expect our borrowing base to continue to grow as we grow production and reserves.

So we have adequate liquidity to execute our business plan for the foreseeable future, including the exercise of the Ward County option, the 2 options that are going to be due later this year.

Our earnings release, which was issued yesterday, provides some changes to certain financial and operational guidance items in 2017. Specifically, we increased our production guidance for the second quarter and the full year by 1,000 Boe a day. We also refined our production mix expectations for 2017 and increased our expected infrastructure, seismic and other CapEx in 2017 to account for surface acreage acquisition, and then more infrastructure spending in Ward County.

And with that, I'll turn the call over to Jon Wright.

Thanks, Mark. I will comment on our Delaware operations first before discussing the Williston Basin. In Ward County, we recently completed our first operated well in the Delaware Basin, the CRMWD-79 #1H. This well has a 5,500 foot effective lateral length and was completed with 35 frac stages and about 2,500 pounds per lateral foot of proppant. The well is currently flowing back after completion. The drilling and completion of this well progressed as per plan and on schedule. We're excited to have this well on flowback.

Industry activity in Ward County has heated up. There have been a number of great wells recently completed, offsetting our acreage by our peers. We plan to exercise the option on the southern tract of the Ward County acreage in June. We'll drill our first well on the northern tract in the third quarter.

In Pecos County, we've hit the ground running. As you recall, we closed this acquisition on February 28, and within a couple of weeks, had our first 2 operator rigs running. We finished drilling our first 2 wells there, both 10,000 foot laterals targeting the Wolfcamp B. Both rigs have moved on to additional locations, and we expect to run these 2 rigs continuously in the Delaware for the remainder of the year, with most of the drilling focused on Pecos County. Nearly all the wells planned for 2017 will be 10,000 foot laterals and include a combination of Wolfcamp A and B wells and one Bone Spring well. The expected D&C cost for these 10,000 foot wells is approximately $9.5 million.

We also recently contracted a frac fleet, which is scheduled to begin continuous frac operations at the beginning of June. Accordingly, we expect to have a steady stream of well results from our Pecos County assets later this summer.

We've also had considerable success enhancing the existing production for the Pecos County assets since taking over operatorship and executing on a number of production optimization initiatives. We have increased PDP production here by approximately 1,000 Boe per day or 45% since taking over operations.

We further improve -- we expect to further improve existing production in the field over the next month or so through further optimization initiatives. As a result of our improvements in the PDP of existing wells on our acreage as well as our continued study of offsetting wells, we have increased the EUR assumptions in our type curves of Pecos County. As indicated in the presentation posted to our website last night, we expect our 10,000 foot laterals to produce between 1.1 million to 1.3 million barrels of oil equivalent or between 115 and 130 Boe per lateral foot. These wells will generate very strong economics of $50 or even $40 oil.

In the Delaware, we're also doing a number of things to ensure that we are set up for an efficient and effective long-term development of this asset. We recently contracted modern 3D seismic to be shot across our Pecos County assets. We are currently constructing water, gas and oil infrastructure in both the Pecos and Ward County positions. We've also obtained surface acreage in Ward County, where we're drilling water wells, disposal wells and constructing a water recycling facility similar to those that we have in Pecos County.

Moving on to the Williston Basin. After running just one rig for more than a year, we recently added a second operator rig to drill on our Fort Berthold acreage. We expect to run these 2 rigs on FBIR exclusively for the remainder of 2017. We also commenced our spring completion activities after taking a break on completions during the dead of winter. We will have a number of new wells coming online over the next few months, which will average more than 1 million barrels equivalent per well.

We are also completing about 15 wells this year in FBIR with enhanced frac designs, which include up to 10 million pounds of sand per well and tighter cluster spacing. We have seen recent results drilled by us and others with these enhanced frac designs that yield significantly higher EURs. We are conservatively estimating D&C costs in FBIR to be $6.2 million with our standards to [quarter] frac design and $7.2 million with our higher profit intensity frac.

With that, I'll turn it over to Floyd for his comments.

Thanks, Jon and Mark, for all the good news. So far this year, we've focused on upgrading our asset base through our entry into the Delaware Basin and the sale of our Eagle Ford property. Since closing those deals in March, our focus has shifted towards execution. We, as always, are confident in our ability to deliver well results across our property set. And we expect to outperform our pronouncements along those lines. And as Jon has just reported, our drilling, completion and production efforts are going great.

On the A&D front, we continue to evaluate property additions that make sense, with particular focus on the Delaware Basin.

I point out, though, that we have plenty of drilling inventory in front of us today with more than 2,300 identified high-class locations. So we're in no hurry to add property.

As Mark mentioned, we have the financial resources to fund our plans for the next several years. We will continue to drive costs down and improve our leverage. There are a number of positive catalysts on our horizon. It's an exciting time to be a shareholder at Halcón, and I look forward to updating you soon on how things are progressing.

Operator, we're ready for some questions, if there are any.

(Operator Instructions) Our first question is from Will Green of Stephens.

I wanted to start on the workovers in the Bakken. LOE jumped a little bit this quarter. You did mention that there were some higher workover costs. Is that sort of a transitory issue, where you just -- a bunch of stuff got lumped in this quarter and we start to see that LOE kind of normalize going forward? Or any kind of color there would be great.

This is Jon. Thanks for the call -- or question, Will. Regarding LOE workovers in the Bakken, we had a number of workovers, rigs operating in the Bakken, 11 rigs to be exact. Through some of our production initiatives there, we've decreased the number of rigs to 6. So we'll see a significant increase -- decrease in our workover expenses as we move into 2017.

Great. And then the other thing I wanted to ask about is, in talking to investors and other operators, you hear rumblings about -- concern about completion crews getting tied out in the Permian Basin. I figured I would ask you guys since you guys have recently been in the market kind of looking to get these next set of wells fracked. As you guys are getting ramped, how has availability been? How have pricing talks been? Just any kind of additional color around that? Is that -- is the basin extremely tight on completion crews? Do you feel pretty comfortable about where you guys stand in terms of getting them?

Will, as we mentioned, we recently contracted a frac fleet, which will begin operations in mid- to early June. The market is tight. We were able to get the CRMWD well fracked on a spot fleet. So the opportunity is there. A lot of this is about relationships as well. The frac fleet we'll be utilizing in the Permian will be the same or from the same company as our fleet in the Bakken. So relationships matter here.

Our next question is from [Tarek Sumit] of JPM.

This is actually [Kevin] calling in for [Tarek]. Just wanted to see -- I know it's early days in Pecos, and congrats on the well performance out there recently. Just wanted to see what your appetite, though, is for additional bolt-on acreage and kind of how your thought processes are on that.

Yes. Our appetite is good for that. It's pretty tight, as you know, out there. There's always a few things that you can add, and we've added a few acres here and there. We have a very strong eye towards forming 10,000 foot -- drilling units that will accommodate 10,000 foot wells. So that's -- that relegates us to acquiring acreage that are at least that large and near other operations or adding to acreage that allows us to do 10,000 foot laterals on our existing acreage. So yes, we're looking in both of our areas right now and having some success here and there.

That's helpful. And just to that context, in terms of the 10,000 foot laterals, what percentage of your inventory is prospective of that similar kind of a completion design?

Almost, all of it. I mean, we'll drill a few 5,000 foot wells here and there just because of acreage explorations and acreage -- sort of stranded acreage in a good spot. But I don't think we have more than couple of those planned this year.

Okay. Understood. And I assume that's -- I read that the -- your Ward County acreage is kind of similar. Most of this is prospective of 10,000 foot laterals.

Yes, maybe as I reported before, but maybe not on the quarterly call. We hired a rig to go out there and drill a vertical well. We call it pilot hole or a strat test. The results were so great. We just used that same rig, which was a very underpowered rig, to drill a long lateral. And we drilled a short lateral just to get the ball rolling out there, a 5,500 foot lateral. Since then, we've released that rig, and we have only rigs that are confident to drill long lateral wells.

Okay. That's helpful. And my last question is just on that slight uptick in spend on seismic and infrastructure. Just wanted to get more color on that and wanted to see if that might be -- if that's kind of done for the year or there's some additional spend needed potentially in the future.

Well, when you have geophysicists shopping, it's like a kid going to a candy store. So there's always some new piece of seismic or some relook at some existing seismic that they want to do. We're -- I think what we have projected for seismic for the rest of this year is about firm. There could be a small reduction or a small increase. The timing of all that is such that we may have put the entire load on this year, but the way those contracts work, you don't really pay for them until they perform the work.

Our next question is from Ron Mills of Johnson Rice.

Jon, maybe for you on the EUR as you touched on Pecos County. I know part of the absolute increase is due to using 10,000 foot laterals. But on a per foot basis, they increased about 50% versus the prior slide deck. What were some of the primary drivers in terms of those production enhancements to generate that kind of improvement in EURs per foot in Pecos?

Ron, just to clarify on the EURs, those are not on a Boe per foot basis. They have been (inaudible). Just -- so when you talk about the production optimization piece, we have seen increases of 20% to 60% in the EURs on those specific PDP wells we've increased the production on. But that really has translated to increasing our EUR perspective for the entire property with those PDP increases as well as looking at our offset operators. So feel like those EURs are grounded in some solid data.

Ron, addition to that -- additionally to that, we reported -- or we indicated that when we put out the initial estimates, we were using our acquisition economics and our acquisition view of things. And it was widely commented on that our -- those acquisition economics were considerably lower than all of the peers nearby. And this is just the natural movement towards -- moving from the acquisition mode, which you try to make a good deal on, and to the reality of what you expect to make.

So it's a good segue, because even the increased EURs seems not as conservative as they were on the acquisition case, but they still, both in Pecos and even on the high-intensity fracs up in the Williston, seem -- still seem conservative relative to what other operators in your areas are talking. And this just a possible continued march-up in these EURs as you have more data.

Well, there's a bunch of sandbaggers sitting here in this room. And we try to be as accurate and realistic as we can. But generally speaking, our goal would be to outperform these things. And then we tend to walk up, if there's any walking up to be done on a considered and not often basis. As you probably remember, we didn't even increase our -- we're making million barrel wells right and left up in the Williston Basin. We didn't increase from 800,000 for 1.5 years just because their results speak for themselves.

Right. And then also probably back over to Jon. When you look at Ward County versus Pecos County, I know you're just flowing back your first well, but if you were going to try to make some sort of comparison as to how those wells will look versus Pecos County, will they look like -- more like the Wolfcamp B well in the Delaware? Or is there some -- I think it's deeper and higher pressured, so there's -- is there potential for that acreage to, on an economic and EUR basis, even look better than Pecos County? Or is it just too early?

The Ward County property is in a deeper part of the basin, higher pressures. If you look at our company presentation, we show a number of offset drilling activity results from our peers. Outstanding results in both areas. We feel that both areas are excellent properties in excellent positions within the Delaware.

Great. And then lastly for Mark. The revolver, the increase despite the sale of El Halcón is obviously a nice plus. How much of those EUR uplifts have already been accounted for in that? I guess I'm trying to get a sense -- I think you mentioned that it would point to probably further increases in the fall as you have more production history in the way your -- the use of ESPs and the way you've enhanced the production. But trying to get a sense as to how much of those -- these early improvements were behind the spring redetermination increase.

Not much at all, if any. And, Ron, our projections -- we're probably going to be seeing increases of -- there's a little bit of art to this, of course, but probably between $50 million to maybe $100 million as we start getting into the second half of '18 and going forward as this production really starts to take effect with the lending group. And obviously, it's subject to price, of course, as always.

Second half of '17 or '18?

Going into '18, when the production really starts to take effect and the reserve adds really start coming on.

Our next question is from David Epstein of Cowen.

What would be a driver of you guys doing something on the high-intensity Tier 1 Williams wells, which I think you were showing for the first time? And then also, under what conditions would you accelerate FBIR beyond what you're doing already?

The strategic nature of all that is that everything is HBP-ed up there, and we don't have to do anything that doesn't make good sense. And right now, after our recent entry in the Delaware Basin, it makes more sense for us to spend more time there. As Jon mentioned, we've already done quite a few of these higher prop-loaded wells up in the Williston Basin. And we found that in certain areas, it's a very dramatic difference, certain zones, middle Bakken versus Three Forks. In other areas, it's not quite so dramatic. The wells are just so darn good. It doesn't seem to make them better. So that's the answer. Jon is going to do the majority of the wells up there this year with a higher prop loading. Williams County, a good part of Williams County is great. Again, it's HBP-ed. We tend to want to go out and do pads at a time, not just a well. And we have a nice 5-well pad ready to go, but we've got some fill-in work down in the -- on Fort Berthold to finalize a couple of the pads, and so we're doing that right now. The trend towards the prop loading is in almost every play, everywhere in the United States, and it seems to be bearing fruit on a statistically regular basis for the industry.

There are no further questions at this time. I'd like to turn the call over to Floyd Wilson for any closing remarks.

Well, the only remarks would be thanks for calling in, and call us if you think there's something that we didn't cover. Thank you.

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