Battalion Oil Corp (BATL) 2016 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halcon Resources 3Q 2016 earnings conference call. At this time, all participants are in a listen-only mode. (Operator Instructions).

I would now like to introduce your host for today's conference call, Mr. Mark Mize, EVP, CFO, and Treasurer. You may begin sir.

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

Production for the third quarter averaged 34,185 barrels of oil equivalent per day, which was net of approximately 7,000 BOE a day of operated production voluntarily shut in during the quarter. If this production had been online for the full quarter, we would have averaged over 40,000 BOE a day. And we expect production to be at the high end of our previously provided guidance range of 37,000 to 39,000 for the full year.

Our realized third-quarter oil differential of 89% of NYMEX was a 2% improvement over the second quarter and was driven by better differentials in the Williston Basin. LOE expense was $5.17 per BOE in the third quarter versus $5.20 per BOE in the second quarter of this year. LOE per BOE continued its stalwart trend in the quarter. It would have been $4.29 if the shut in production had been online.

Workover expense, $2.66 per BOE in the third quarter versus $2.42 in the second quarter. Our workover expense has been increased in 2016 as we have increased our efforts to install artificial lift on many of our more mature Bakken wells.

Taxes other than income came in at $3.06 per BOE during the third quarter and gathering, transportation, and other, after adjusting for selected items, came in at $2.23. Both of those items are in line with expectations within our guidance range for the full year of 2016.

After adjusting for some selected items, G&A expense was $4.21 per BOE in the third quarter versus $4.55 in the second quarter this year. And G&A per BOE also continued its downward trend in the quarter despite lower production from the shut-in wells that I've previously mentioned. Overall total operating cost adjusted for selected items was $17.33 per BOE.

With respect to D&C, we incurred approximately $36 million during the current quarter and we are guiding toward $45 million to $50 million in D&C spending in the fourth quarter, resulting in full-year spending of $175 million to $180 million. This is slightly above the previous guidance range but it's also driven by improved drilling efficiencies, resulting in more wells being drilled than we had initially estimated.

Regarding hedges, we realized a net gain on several derivative contracts of $80 million. The current price to market value of our hedges is approximately $100 million. For the fourth quarter of 2016, we have 26,000 barrels per day of oil hedged at an average price of $76.60 a barrel. And for 2017, it will be hedged right at 15,000 barrels a day at an average price of $55 a barrel. We will continue to watch and monitor the strip in 2017 and 2018, and we still have the goal of hedging a few years out at about 80% of what we expect to produce.

We ended the third quarter with $369 million of liquidity, which consisted of $600 million of revolver availability less $233 million drawn on the revolver, plus about $2 million in cash. We are forecasting positive cash flow in the fourth quarter, so expect our revolver draw to decline and our liquidity to improve by year-end. And our next redetermination is scheduled in May of 2017.

We have not yet provided 2017 guidance, but, with one or two grids running, we expect to be cash flow positive to neutral in 2017 at current strip prices. And we will provide formal 2017 guidance at some point here over the next few months.

And with that, I will turn the call over to Floyd.

Thanks Mark. Well, with our balance sheet in good order, as always, we are a transaction-oriented team, and we continue to pursue opportunities that will add to our asset portfolio. As Mark pointed out with a few comments, operations are going quite well here and we have some great properties on board at Halcon.

Our primary focus for new activities in the Williston Basin and Eagle Ford, although we look at select opportunities around the country as well, any transaction that we pursue will have drilling economics that compete with those in our current inventory and will look to finance anything -- any new transaction in such a way that it is leverage neutral or leverage enhancing. We have excellent access to capital, and we hope to get a deal or two done over the next few quarters.

We are in a great spot, even though we are not satisfied with the oil prices, but we can grow production next year at about 10% if we added a second rig in the Williston Basin just for the last three quarters. And as you might remember, the last three quarters of that year, you won't get much benefit out of the fourth quarter, so that's a couple quarters of activity. We can keep production roughly flat if we continue with just one rig, so we are going to take our direction from the market, the oil market. If the market is good, we will add a rig. If it's not, we're just going to keep doing what we are doing. Our number somewhere is around $50 to $55. It's not an exact name -- exact number. We make money today, as a lot of companies are, at these prices.

We are currently cash flow neutral to positive, and expect to be the same next year. We have no current need to access the capital markets. We will let future events dictate whether or not we do that.

As mentioned, we are running one rig in Fort Berthold. Our well costs in that area are under $6 million. Our EURs on all recently drilled wells are averaging over 1 million barrels of oil equivalent per well. Completion techniques in this area -- our completion techniques in this area yield the best economics for us, in our opinion, but we are constantly testing new ideas and watching our grade peers to share in new methods. And we investigate everything that we think -- that we hear about.

We have over 190 remaining gross operated locations on Fort Berthold. That provides us with many years of drilling inventory with only two rigs running.

If we decide to add a second rig in 2017 -- in fact, we are going to start that rig by drilling a five-well pad in our Williams County area, that would be the southeast part of Williams County -- we will move it back to the Fort. The Williams County pad we are planning to drill is in the southeast portion of our acreage, as I mentioned, where we expect EURs to be in the 750 to 900 MBOE range. Very strong economics at current prices.

In Williams County, we have more than 125 remaining gross economic locations at the current strip, and over 250 economic locations at a higher price. These locations in the Middle Bakken only are based on conservative spacing assumptions, no Three Forks in that area, in our opinion.

Our East Texas, in our East Texas Eagle Ford area, El Halcon, we are not running a rig today. We have recently been conversing and watching what other operators that are running rigs have been doing. There's a fairly I wouldn't say new, but there's a new-ish application of proven frac technology being used in the area, higher profit concentrations in the 2,500 to 3,500 pound per linear foot range in slick water fracs with only 20% or 30% of gel. Some of these results look very promising, and we expect to actually change our outlook for this area dramatically in light of what we are seeing so far.

As a reminder, we are using fracs that we've been using, fracs we haven't drilled this year. We have been using fracs that are mainly gel fracs with about 1,500 pounds of proppant per linear foot.

So, in summary, we are excited here at Halcon. We have a great set of existing properties. There's been a lot of activity around both of the areas that we operate in today, a lot of buying and selling. We are looking at acquisitions that would enhance our existing portfolio. And our ultimate goal is still the same. We'll get the Company to the right size and we'll look for an exit at the right time and the right price.

Operator, if there's any questions, we've got some time, and that's it.

(Operator Instructions). Brian Corales, Howard Weil.

Good morning guys. Floyd, you kind of touched on I guess the enhanced completions and different techniques used in the Bakken. Can you maybe comment on have sand concentrations increased or have you all tested diverters? Can you maybe elaborate a little bit?

Yes. And it's yes to both of your thoughts there. I would say between 2013 and the beginning of 2016, most of our frac jobs have been in the 400, maybe a few 500 pound per linear foot range. We have been running converters and we have been using higher sand concentrations, 700 pounds, 800 pounds. We are seeing some dramatic changes, but as is our normal pattern, we like to see quite a few months of production to see if we are really on a different track rather than just a slight acceleration on the front part of the decline curve. But some of our great offset operators in these areas are using some of these same concepts and having good success. So, yes, we are looking at those and employing those as we speak.

And the Williams County, the southeast area you're completing, I'm assuming are you all testing some of those as well?

It would be idiotic if we weren't.

Fair enough. And then one on -- in El Halcon, I guess with what you all have seen, would you kind of just maybe do a test pad or I guess a test run for some of the new completion things that you are seeing from Nabors?

I'm actually quite anxious to do that. We don't have a plan for that right now. We are taking our cue from the strip. And right now, it's not that exciting to go out and test things, and I don't believe that growth is quite the mode that we want to be in right now. We will do it. When we do it, like always, we won't talk about it. We'll just do it, make sure we have results. And then when we report them on a quarterly -- at some quarter when they are mature enough to even suggest there is something new there. But I can tell you that the early evidence of several months of production on some of the people that do have rigs running there are quite attractive. You're finding that the IPs are not necessarily a lot higher, but the 90-day decline rates are much lower. And if that holds even longer, you've got quite -- actually it's a step change in economics for that area. You could take wells up by 20%, 30%, 40% in times, depending on what area that you are in. So it's quite an interesting thing. But we are still thinking that the oil price needs to be a little bit higher to really commit.

As you know, Brian, when you're drilling in these kinds of areas, wherever they are in these shale plays, you have to commit for some length of time rigs and frac and personnel to do a good job. And we are not quite ready to do that yet, but we are doing all of the analytical work, hour by hour, and it looks very, very interesting.

All right, thank you.

Kartikye Kumar, JPMorgan.

Could you talk a little bit -- you talked about potential acquisitions. Maybe talk a little bit about the size of what you're seeing in the Williston Basin and sort of your initial thoughts on how you think about financing acquisitions over time?

Sure. We don't have a plan. We have seen transactions happening around us in the several hundred million dollars range up to $1 billion and maybe a little bit more. Given our current situation, we could undertake a transaction of any of those sizes that I just mentioned. We would largely finance it with equity as we stand today, but I don't want to front-run anything. We are just acquisitive. We've got a great set up to either publicly or privately add capital as needed, and we are quite focused on maintaining our property quality, which is quite high. We don't have any (expletive deleted) properties anywhere, so we're going to make sure that we continue that pattern.

Got it. And then just on service costs, as you look at going back into Williams next year, are you seeing any inflation at all versus what you saw in Fort Berthold in 2016, or are rates generally stating relatively constant?

There's a lot of talk about higher costs. We haven't exactly seen it yet. There's talk about higher frac costs. And we are using some great smaller providers up there today, and we don't really anticipate some huge movement quickly.

Now, I think, if the oil price went up, you're going to find that there will be much more pressure than there is today. The larger providers are of course talking up the higher costs and you can't blame them. Where they have been for the past couple of years has been a difficult place to be in business. Probably more than what would go on with a somewhat higher cost, you probably should keep focusing on what operators like ourselves and others are doing with efficiencies and completions.

And I think we just drilled out a 10-well pad. We do all of these pads, we do all the wells at once; we frac them at once; we complete them at once. I think we drilled out a 10-well pad in two weeks, drilled out the plugs and got the wells cleaned up, all 10 wells in two weeks. A year ago, for most operators, that could take you a week to do one well sometimes. So everyone and ourselves are working really hard on getting more bang for the buck, and it really has been really effective.

So, as costs go up, and they will if the price goes up I certainly hope prices go up, you will find that these efficiencies will stick with us and that we'll probably have a better reward ratio than we've had at similar prices in the past just because of experience and application of that experience to the new wells that you're drilling.

Got it. Thank you. That's very helpful.

David Epstein, Cowen.

Guys, I didn't hear if you mentioned this, but in addition to your five-well pad that you have in the presentation generating 60% RORs, recognizing of course that's not your standard Williams acreage, how many more wells do you think might be of that quality?

I don't have that exact number, but I do -- I can say that we have well over 100 wells that earn in the 40% to 60% -- in the 30% to 60% ROR range at the current strip. And that's quite a few. And if the strip was just a little bit higher, we can add another couple hundred wells. So there's quite a few good targets up there. And we have a lot on Ft. Berthold.

Williams County, as you go west, of course it gets dim in terms of high water cut and the zone center and etc., etc., but as you move to the east, it's quite good. And we think it's overlooked by almost everybody that looks at oil and gas companies. There are some very good properties, just not right in the heart of the field. So, yes, you might not have 1 million barrel wells out there, but I promise you we can drill 800,000, 900,000 barrel wells up there. So, we don't have an exact answer to your question, but there's quite a few locations up there.

I appreciate that. One other question, it's sort of a tough question, so feel free to pass on it. Just sort of comparing your acreage to the transaction, the recent big transaction of Oasis bought from SM, do you guys have any sort of views on comparing the acreage, recognizing that theirs was heterogeneous and so was yours?

I don't know what heterogeneous means. However, the transaction that you're referencing, we looked at it quite hard and it's some great property. It's a great transaction I think for both sides, given the rotation towards the Permian by one and the adding of property to another. I think, in any of these cases, all of us should be thinking about the factors and terminal decline rates that are reasonably stated in terms of EURs -- so that you get all of these headlines about us making a 1 million barrel well or somebody else making a 1 million barrel well, and you find that didn't matter that much. It sounds good but what really matters is the first few years of production. And the more production you can get out of those wells in the first few years is how you make your money. The EURs are kind of headline numbers, and it speaks well for the future, but if you have a whole set of companies that use wildly different B factors and wildly different terminal decline rates, you're going to get wildly different EUR type estimates. So, there was great property and no bad comments about it whatsoever. I don't know if that's helpful, but maybe I should have just passed, as you suggested.

That'll do. Thanks very much. I appreciate it.

(Operator Instructions).

Operator, I think we've been on here enough. And if anybody has something they want to travel back to, just give us a call. Thank you.

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day.