Abraxas Petroleum Corporation
Q2 2017 Earnings Call Transcript

Published: 9 Aug 2017

[Operator:]

Good day, ladies and gentlemen, and welcome to the Q2 2017 Abraxas Petroleum Corporation Earnings Conference Call. At this time, all participants are in a listen-only mode. Following management’s prepared remarks, we will host a question-and-answer session and our instructions will be given at that time. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to hand the conference over to Mr. Geoffrey King, Chief Financial Officer. Sir, you may begin your conference.

[Geoffrey King:]

Thank you, Brian, and welcome to the Abraxas Petroleum second quarter 2017 earnings conference call. Bob Watson, President and CEO of Abraxas, joins me today. In addition, we have our Chief Accounting Officer and our VPs of Operations, Land and Engineering available to answer any questions that you may have after Bob’s overview. As a reminder, today’s call is being taped, and a webcast replay will be available immediately after the conclusion of the call. I would like to remind everyone that any statements made during this call that are not statements of historical facts are considered forward-looking statements and actual results could vary materially from those contained in these statements. Factors that could cause our actual results to vary are described in our filings with the Securities and Exchange Commission. I would encourage everyone to review the risk factors contained in these filings and in our press releases. I’ll now turn the call over to Bob.

[Robert Watson:]

Thanks, Geoff, and good morning. As I stated on our last quarterly conference call, our Q2 production was going to be very noisy. We were expecting the established production decline to continue as no new wells we’re going to be brought online. We had six high-volume Bakken wells shut-in a little bit longer than we had originally forecast for frac protection and we suffered an unanticipated third-party gas plant outage in both South Texas and West Texas. The good news, all those are now back online. And I guess, I didn’t articulate all of this enough as there is some disappointment out there this morning, and I’ll put that one on me. But all this, and we still had a positive earnings for the second quarter. The good news, and I mean, really good news is, all the new wells that we talked about on last quarter’s conference call came on more or less on schedule. The frac protect wells came back with no significant frac hits, and currently, all – essentially all our gas is now being sold. Production now is consistently over 9,000 Boes per day. And as we conservatively ramp up our Delaware wells, we should exceed our guidance year-end exit rate of 9,500 barrels a day during August. We have now increased our year-end exit rate guidance to approximately 10,750 Boes per day, with CapEx remaining the same. With successful flowback on our recent Delaware wells, as well as flowback data from surrounding wells by other operators with whom we are sharing data, we’ve now become comfortable enough with our existing published Delaware type curve that we can now guide to average production for 2018 of 11,500 Boes per day, and for 2019 of 12,750 Boes per day. At CapEx levels, each year of about $90 million consisting of single rig programs in the Bakken and the Delaware. At current commodity prices, this should generate free cash flow in both 2018 and 2019, giving us the opportunity to remain acquisitive going forward without jeopardizing our balance sheet. This is a very unique story in the E&P space and one that we are very proud of. We will incorporate this new guidance in our corporate presentations going forward and we invite anyone to try to shoot holes in it. Now on to operations. In North Dakota, our four wells Stenehjem pad in which Abraxas owns a 75% working interest were successfully fracked with a few tweaks to our proven frac recipe. We started flowback in late June under a more conservative flowback protocol, which hopefully will result in a lesser decline rate in the future. And even with smaller chokes, the 30-day rates averaged right at 11,044 Boes per day per well. The previous six wells on the Stenehjem pad using the same frac recipe averaged 11,042, or 142 barrels of oil per day, and that’s the Bakken and Three Forks combined. Our rig is now drilled our three-well Yellowstone Northeast pad in which Abraxas owns a 52% working interest, that’s a total depths of about 21,000 feet. We’ve had one hiccup, while cementing the liner on the 4H well. The cement flash set, for some reason and stuck the drill pipe. Our rig is now back on this well drilling on the struck drill pipe, and in case, the fishing job is not successful, we are permitting a replacement well just in case. These three wells are scheduled for frac in early October. We plan to move the rig to the Yellowstone Northeast Central pad as soon as delayed permits are received. In West Texas, specifically the Delaware Basin, our initial well, the Caprito 99-302H, which is – in which we own a 100% interest in is completed in the Wolfcamp A2 landing zone, continues to outperform our type curve. Our two-well pads, the Caprito 98-201H, which is in the Wolfcamp A1 zone and the 301HR, which is in the Wolfcamp A2 zone, both of these wells, we have a 98% working interests. We’re successfully fracked and on a conservative flowback protocol, and I might add that, our engineers have studied nearby flowback well data and have found a compelling reason to use, what we call, a flowback procedure of smaller choke sizes for a longer to conserve reservoir pressure for longer. It appears to be working. Our wells are still in production incline, so I can’t predict when we will have a maximum 30-day rate. But after plus or minus 20-days flowback, both wells are exceeding our type curve with significant reservoir pressure remaining, thus indicating a significant outperformance for a longer period of time over and above our initial well and the surrounding wells of outside operators that used a fast frac flow back procedure. You will note, I said, both wells, which includes our initial tests of the Wolfcamp A1 landing zone, which is actually flowing back a little bit stronger than its A2 twin at this time. In our minds, this gives us now two proven zones on our acreage. We have tested the third zone, Wolfcamp B, in our next pad that was drilled. The Caprito 83-304H is in the Wolfcamp A2 and the 404H is in the Wolfcamp B. We have a 100% interest in both of these wells. They’ve both now been drilled with casing set to approximately 16,500 feet. The schedules are – these wells are scheduled to be fracked in mid-September. We are encouraged by the drilling samples, the shows and the pressures we encountered in Wolfcamp B, which has increased our encouragement about a potential fifth zone under our acreage being the Wolfcamp C. Our next two-well pad, the Caprito 82-101H will be our initial test of the third Bone Springs landing zone. And the Caprito will have a 100% interest in that well, and then the Caprito 82-202H, which is in the Wolfcamp A1, we currently will have a 62.5% interest in that well. These wells are spud in the early stages of the drilling phase, and are scheduled to be fracked in November. We are permitting a three-well pad in section 99. What we don’t know is the ultimate spacing of wells between wells in the same zone. We have found that we are one of only a few public companies that are talking about future location inventory, which we said is, over 200, on 1,320-foot spacing between wells. Most companies are reporting their inventory location – of locations on 660-foot spacing. If we would do that, obviously, that would give us over 400 future locations in our inventory. As of today, we’ve closed two larger bolt-on acquisitions and a number of smaller ones at very attractive prices per acre. All of this helps our goal of consulting our area in Ward County into one continuous block. We have a number of potential additional locations in the work – acquisitions in the work that could move our current acreage count of approximately 8,500 net acres to over 10,000 net acres by year-end. This is a goal I was quite vocal about early this year, and I have to admit, it did reach some skepticism. To help in this regard, we have recently beat up our bench in the land area. Steve Wendel, formerly Vice President of Land and Marketing is now Vice President of Marketing and Contracts; Todd Clarke formerly Land Manager is now Vice President of Land; and Dirk Schwartz formerly Manager of Business Development in our Denver office is relocating to San Antonio as Vice President of Business Development. And certainly, not to forget, our often forgotten third asset are close to 10,000 net acre Eagle Ford and Austin Chalk block and Atascosa County, South Texas, our Shut Eye 1 in which we own a 100% working interest, was drilled and cased to approximately 14,400 feet using rotary steerable directional drilling technology to stay in our target zone a 100% of the time and is scheduled to be fracked with the modern frac recipe in September. If this well cracks the economic code, it will open up a number of opportunities for this asset. With the closing today of the trade of our Pecos County Ranch and half our minerals there for HBP acres mostly in Ward County, we are left with only one significant asset left in our current divestiture program and that’s an approximate 1,000 net acre unit in the middle of the play in the Powder River Basin in Wyoming. We are currently in discussions with the coal company on a joint development agreement which when in place this will make this asset marketable. So, you are now up to date on Abraxas and I’ll ask for any questions.

[Operator:]

Thank you. [Operator Instructions] Our first question will come from the line of Will Green with Stephens. Please proceed.

[Will Green:]

Good morning everyone.

[Geoffrey King:]

Good morning, Will.

[Will Green:]

I appreciate the updated guidance you guys gave for 2018 and 2019. And I think I heard you correctly that you said that this would be a scenario where you guys would anticipate throwing off free cash in that scenario. With that in mind, how do we think about the use of that cash going forward? Is that just simply pay down debt? Does that help you fund land purchases you guys were saying on the ground? Just how are you guys thinking about that and how do you guys think about targets for total debt leverage as that process evolves?

[Robert Watson:]

Well, we’ve talked before that we would like to have a pretty hard cap of one times debt-to-EBITDA. We are certainly under that now and would anticipate we stay under that for the foreseeable future, we might get close to it, but it – we’re are throwing off free cash, it drops pretty quick. Free cash would obviously imply that we can remain acquisitive. Our goal is to continue to build our position in the Delaware. We would like to build our position in the core of the Bakken, but that’s a very difficult land play now. But we do see adequate opportunities in the Delaware to continue to core up and then increase our position and having a significant asset base that’s growing and throwing off free cash certainly helps us with the ability to finance any kind of acquisitions we might come across. But we will be very – we will hold to our thoughts that we need to acquire anything at our price. We’re not going to go out and compete with the guys that are paying multiples of what we’ve been paying for acres. But we do think there’s a good opportunity to continue putting together bolt-on acquisitions at our price in our area.

[Will Green:]

Great, thanks for that. And then those two recent Caprito completions that just came online, it sounds like you guys are very excited about how those are already responding to the frac. I guess how do we think about the rollout of that data, is it – are you guys going to provide us a first 30-day or do you think it’s a peak 30-day or do we see this next quarter? Do we see it, some event, just how should we expect that data rollout to occur, because it does sound like you guys are excited about those two wells?

[Robert Watson:]

Yes, with the flowback method that we’re employing, it does appear to be very successful, but it’s a slower ramp up. And as I said, after 20 days the production is still inclining, we’re still bumping chokes very slowly. So, we will certainly discuss a peak 30-day rate when we have it. What I don’t know is when that might happen. I think we’re pretty excited about the impact every time we bump the choke and even now we’re above our tight curve, so who knows how much further above it we’re going to get, but we certainly expect and we’ve got over 2,000 pounds of flowing pressure on both well still. A lot of room to continue bumping chokes and increasing rates.

[Will Green:]

That’s great to hear, I’ll look forward to the progress there. That’s all I had right now, thanks.

[Geoffrey King:]

Thanks Will.

[Operator:]

Thank you. And our next question will come from the line of Sam Roach with Canaccord. Please proceed.

[Sam Roach:]

Yes, thanks, good morning gents.

[Robert Watson:]

Good morning Sam.

[Sam Roach:]

Hey, seeing the increase in exit rate there, I think, in the press release, you alluded to some of that being a result of scheduling – frac scheduling. So can you give me a ballpark on how much is to do with the schedule change, and how much is to do with well performance?

[Robert Watson:]

I would say, the schedule has really not changed that dramatically. I think, the reason for the increase in exit rate this year is principally well performance. And we’re pretty excited about both the Bakken and the Delaware. We’re pretty proud of our – Pete Bommer and the engineering group on the frac recipes that we’re employing, and they’ve contributed better rates than we anticipated.

[Sam Roach:]

Excellent. And just one follow-up. With respect to M&A acquisitions in the Delaware Basin, you mentioned your 10,000 net acre target, given the most recent additions, has that target changed at all?

[Robert Watson:]

I think it’s gotten to be more achievable. We would certainly like to have more than that. And I would say that, if we’re successful in every deal that we’re working on right now, it would be more than that, whether we can assume a 100% success or not might be problematic. But certainly, two or three of those would certainly put us well over the 10,000 acre number.

[Sam Roach:]

Great. That’s it for me. Thank you.

[Robert Watson:]

Thanks, Sam.

[Operator:]

Thank you. And our next question will come from the line of Mike Kelly with Seaport Global. Please proceed.

[Mike Kelly:]

Hey, guys, good morning.

[Robert Watson:]

Hey, Mike.

[Mike Kelly:]

Bob, just hoping you could expand upon your comments, where you just said you would continue to acquire at your price. And just want to understand the dynamics of play that have allowed you to build this position really kind of submarket prices and why you think that could continue?

[Robert Watson:]

I guess, the basic reason is that, we are going after principally non-operated working interest in units that we are already the operator or will soon be. And that diminishes the value in the eyes of most people and it reduces the competition for tracks such as that. So, at least, on the next three or four acquisitions that we’re in the negotiation phase on right now, a good percentage of them includes acreage under units that we already operate and thus less competition for the ownership of those units and that allows us to negotiate a lower price.

[Mike Kelly:]

All right. That makes sense. And switching gears just noticed in the plan through 2019, the Eagle Ford kind of got the highest mid here, just want to hear – I want hear your plans for the basin going forward? Thanks.

[Robert Watson:]

I think, the tune in – and after we have the frac results on the Shut Eye well, because that will dictate what we – what our plans are on that. They’re all up in the air right now. With success in that well, which we certainly hope for and anticipate, we would have an opportunity of just developing that asset, or we could just hold on to it, as most of the acreage is HBP, or we could divest it. It just depends on what we think is best for the shareholders and what use we would have of proceeds on a pretty significant divestiture.

[Mike Kelly:]

Okay, great. And then I’ll sneak one more in. Just it’s exciting to see you guys now test four different zones here on the Delaware package. Anything that you look to, in addition to the, Wolfcamp A, B, and the Bone Springs, anything else was catching your eye that you would like to test maybe moving into 2018?

[Robert Watson:]

Yes, we are feeling more and more comfortable with the Wolfcamp C in our area. It looks very similar on the logs, as the Wolfcamp B does. And I think, we’re very excited about what we saw in drilling, the Wolfcamp B in regard to sample shows, gas shows and pressures. So if the analogy works between – the log analogy works between the B and the C, then we certainly would consider the C worthy of a test in the fairly near future.

[Mike Kelly:]

Okay. Great, guy. Great update.

[Robert Watson:]

Thanks.

[Operator:]

Thank you. And our next question will come from the line of Cameron Ross with Mangrove Partners. Please proceed.

[Cameron Ross:]

Good morning. I guess, what is your net location count in the Bakken and the Delaware Basin pro forma for the recent acquisitions?

[Robert Watson:]

The location count in the Bakken is plus or minus 40 more, that’s a gross number. I don’t have the net number right here in front of me.

[Geoffrey King:]

That’s operated too.

[Robert Watson:]

Yes, that’s operated. We have a number of additional non-op locations there. And in the Delaware, until we’ve decided what the proper spacing is, we need to impress upon people that our location count, which is north of 200, and we don’t have an updated number on that, I think, we’ll be working on it. But it’s north of 200 on 1,320-acre spacing, or 1,320-foot spacing. We found out through the recent data search of what the other public companies in our area that Delaware are talking about. We’re the only company that is saying 1,320-foot spacing, virtually, everybody else is saying, their location count is on 660-foot spacing. So obvious, easy math. If we drop our spacing down to 660, we have over 400 locations. And that counts going to grow as we have more time to do the geology and engineering on our tracks. And certainly the acquisitions that we’ve done recently have increased the net. They might not have increased the gross that much, but the principal driver behind those acquisitions was acquiring acreage in units that we already operated. And that’s how we have close to 100% working interest now in our four section Caprito block as a result of the recent acquisitions.

[Cameron Ross:]

Great. And is that north of 200 number on a gross basis? And if so, would you have to have it on a net basis?

[Robert Watson:]

That’s on a gross basis. If I had to throw out a wild guess right now and it’s very, very fluid, as we are continuing to try to make acquisitions, I would say, at least, 75% of that would be net.

[Cameron Ross:]

Great. Thank you. That’s very helpful.

[Robert Watson:]

Thank you.

[Operator:]

Thank you. [Operator Instructions] And I’m showing no further questions at this time. So I’d like to hand the conference back over to Mr. Geoffrey King, Chief Financial Officer for closing comments or remarks.

[Geoffrey King:]

Thanks, Brian. We appreciate your participation today in Abraxas earnings conference call. As I mentioned at the start of the call, a webcast replay will be available on our website and a transcript will be posted in approximately 24 hours. Thank you, and have a great day.

[Operator:]

Thank you. Ladies and gentlemen, thank you for your participation on today’s conference. This does conclude the program. You may all disconnect. Everybody have a wonderful day.