Abraxas Petroleum Corporation
Q1 2017 Earnings Call Transcript

Published: 10 May 2017

[Operator:]

Good day, ladies and gentlemen, and welcome to the Abraxas Petroleum Corporation Q1 2017 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 follow at that time. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. It’s now my pleasure to hand the conference over to Geoff King, Chief Financial Officer. Sir, you may begin.

[Geoffrey King:]

Thank you, Brian, and welcome to the Abraxas Petroleum first 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 and Land 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. Abraxas had a great quarter financially, despite what I stated on our last call in March that production would decline about 15% over the fourth quarter of 2016, due to no new wells coming online. But it actually declined only 14.2%, so pretty close. I also stated that that rate of decline would continue until a number of new wells would come online towards the end of the second quarter. Since our March call, operations have run very smoothly, and I’m very happy to report that everything discussed on that call is still on schedule. In the Delaware Basin of West Texas, our Caprito 99-302H, in which we have a 100% working interest is still producing above our tight curve, and after five months, it’s producing about 400 Boe’s per day out of the Wolfcamp A2. We started our continuous one-rig program around March 1, the first two-well pad, the Caprito 98-201H and the Caprito 98-301HR, both of which in which we have about an 88% working interest have been drilled and cased to around 16,000 feet, including about a 5,000 foot lateral in each well. The 201H is in the Wolfcamp A1 and the 301HR is in the Wolfcamp A2. These wells are scheduled to be fracked on – in June, with first well around July 1. The rig moved to a new two-well pad in Section 83 and is drilling the Caprito 83-304H in the Wolfcamp A2 and the Caprito 83-404H in the Wolfcamp B. Both of these wells, we have about a 81% working interest. These wells are scheduled to be fracked in September. There’s a chance that we could get to him sooner. We plan to run one-rig program to continue for the foreseeable future, and we are actively negotiating a number of bolt-on acquisitions, and I might add it reasonable prices on interest either under our existing units, adjacent to existing units are very proximal to our existing units. We hope to have some news on our efforts in this regard in the very near future. In the Bakken, our company-owned rigs successfully drilled and cased the last four wells on the Stenehjem super pad, we have about a 75% working interest in these wells. They were drilled to a depth of about 21,000 feet, including 10,000 foot lateral. Production facilities are being constructed and the wells are being prepped for frac scheduled to start midweek next week, with first oil toward the end of June. Our rig moved to drill a three-well Yellowstone Northeast pad, where drilling is well underway. We have about a 52% working interest in the Yellowstone unit, there’s a chance that this interest might increase as we are in negotiations with acquiring some minor working interest partners in the Yellowstone unit. Frac date for these three wells has been secured for September, and we would expect first oil sometime in October. We have also secured another frac date for late November/December for the next set of wells, but this would be very weather dependent. If we don’t go forward with fracking them due to winter weather conditions, that will give us a slug of wells to be fracked one year from now, up in the Bakken. In the Eagle Ford, I discussed our reasoning to attempt another Eagle Ford well instead of an Austin Chalk well, where we will use, for the first time for Abraxas enhanced steering and completion techniques. The Shut Eye number 1H in which we have a 100% working interest is drilling the curve, as we speak, below 8,000 feet on its way to a planned 5,800 foot lateral. Completion is planned for July with first oil around August 1. Now, our second quarter is difficult to model even for us and for various reasons. The most obvious is timing of first oil. But in addition, we will be shutting in several high-volume Bakken wells for about a month for offset frac protection. In the past, we’ve had fracked protect wells come back on, it’s recharged and producing at higher rates than before. Some had come back on with no change from previous rates, and some had come back on at less and need a cleanout due to a frac hit. These are issues that we have no way of predicting. So despite the noise of Q2, I think you’ll agree that we have set the stage for a dramatic boost in production in the third quarter and continuing into the fourth quarter. At this point, we are very comfortable with our previously guided exit rate of 9,500 Boe’s per day on a CapEx budget of $110 million. With that, I’ll open it for questions.

[Operator:]

Thank you, sir. [Operator Instructions] Our first question will come from the line of John Aschenbeck with Seaport Global. Please proceed.

[John Aschenbeck:]

Hey, good morning, Bob and Geoff. Thanks for taking my question.

[Robert Watson:]

Hi, John.

[John Aschenbeck:]

Answer my first one in terms of hitting that exit rate, so that was very helpful. But just as I think of the rest of 2017 and particularly the commodity mix as we progress throughout the rest of the year, I understand there might be some noise in Q2 with the offset fracs in Bakken. But assuming, we do get to that 9,500 barrels a day of equivalent or more, what is the oil kind of look like under that scenario?

[Robert Watson:]

Hey, John, it’s a good question. I just walk you through how this is – the reasons for our mix in the first quarter, and then what it looks like going into 2Q and then beyond? In the first quarter, we had a little bit of downtime in the Bakken, which obviously is where our oily wells are as well as we were tweaking our pump on the bull’s eye well. That brought down oil rates a little bit, so the mix was a little bit gassier for the factor of bring down those oiler wells that same thing and I expect similar mix in 2Q as we bring down these six wells in the Bakken through the offset stimulation. Then when you’re heading into 3Q and 4Q, you were obviously bringing on some significant oily volumes in Bakken, as well as in the Permian Basin. So that mix will get decidedly more oily. And I would expect by the end of the year, we come in with a mix that is similar to what we guided to.

[John Aschenbeck:]

All right, good view. That’s helpful, Geoff, appreciate that. And just kind of keeping with the same theme with my follow-up, Bob, you kind of touched on this new press release last night. You made some considerable improvements on the cost front year-over-year. Should we expect that downward trend throughout the year, especially in the back half of the year as it pertains to kind of downward pressure on LOEs as you bring more volumes on? And then also just with production coming from different basins, how we should think about just oil realizations going into the back-half of the year?

[Robert Watson:]

I think what you’ll see is that, we will tend toward the low level of our LOE guidance as we bring on really good flesh production, the LOEs tend to be constant. And as you add more barrels, obviously, your lifting cost per barrel goes down. So we’re pretty comfortable with that guidance and would be disappointed if it’s not pretty close to the low end. As far as oil realizations go, you tell me what oil prices are going to do and we’ll tell you what realizations are going to be. The one good thing we have been able to stabilize our differentials up in the Bakken, which have been a big contributor to our big differential company-wide for oil. We’re going to save about $2.50 to $3 a barrel starting June 1 for a 9-month period. So that would get us all the way through the year with a lower average oil differential, then you can apply what you expect to see what WTI is doing, and we’ll have a little bit higher net after a lower differential.

[John Aschenbeck:]

Got it. That’s really helpful. That’s it for me. Thanks, guys.

[Robert Watson:]

Thanks, John.

[Operator:]

Thank you. Our next question will come from the line of Will Green with Stephens. Please proceed.

[Will Green:]

Good morning, guys.

[Robert Watson:]

Hi, Will.

[Will Green:]

I wanted to touch on that kind of tentative date you guys have set for the Bakken. And I think you said November right, or October November timeframe, is that right?

[Robert Watson:]

Well, we have a frac date scheduled for September. That would be the three wells that are currently drilling on the Yellowstone Northeast pad. And then we have – we’ve got another frac date scheduled for late November early December. But that’s tentative on our mine, because we – if we have an early winter up there, we probably won’t commence a frac operation, we’ll wait until the spring time.

[Will Green:]

Sure. And so, I guess, what I’m getting at is, if that does get pushed, does that do anything to guidance or would you guys opt to redirect CapEx to, say, do some more Caprito wells or something of that nature? I mean, how should we think about that if that does end up getting pushed out, given that that weather can be a wild card up there in November/December?

[Robert Watson:]

I would say, our guidance assumes that it does get pushed out. And then if we do go forward with fracking it, we would increase our CapEx and increase our production guidance due to that. But if it – we do cancel because of weather there will be no impact on our guidance.

[Will Green:]

Great, that’s good to hear. And then I think you mentioned 870 pounds per foot on the Stenehjem wells. I know you guys are probably seeing this. But some operators up there have been experimenting with good success with higher proppant loading. I don’t know if you guys have planned on looking at something like that for, say, one of these Yellowstone wells, or varying that up at all, just any color on that and how you guys think about that would be great?

[Robert Watson:]

We monitor everybody’s activity. We monitor everybody’s press releases about what they’re doing. We find that there’s a pretty big disconnect with what they say and what is actually reported on the NDIC website. So until such time as we see actual results positively impact – be positively impacted by higher proppant load completions, we feel like where we are right now is kind of the optimum level. Now, there have been a few recent wells, where there just isn’t a whole lot of data yet, just need some more time. But that’s something that we continually monitor, we will continually look at tweaking our frac recipe. I think our results in the past has shown that we do a pretty good job with that. But until there’s some proof, we’re not big enough to be the leader. We want to see somebody else prove something before we try it. But until there is a very good proof in our mind probably comfortable where we are.

[Will Green:]

Great. Well, thank you guys for all the color.

[Robert Watson:]

Thanks, Will.

[Operator:]

Thank you. Our next question will come from the line of Welles Fitzpatrick with Johnson Rice. Please proceed.

[Welles Fitzpatrick:]

Hey, good morning.

[Robert Watson:]

Hi, Welles.

[Welles Fitzpatrick:]

Can you guys just talk a little bit about the proppant loading and the use of diverters in the Shut Eye 1? And specifically, how that might compare to the last batch of Eagle Ford wells you drilled up in Jordanton, I guess, it will be all the way back in 2014?

[Robert Watson:]

Yes, I think, our prop load is up considerably. Was it 2,000 or 2,400.

[Geoffrey King:]

Well, 2,000.

[Robert Watson:]

2,000 pounds per foot, that’s probably up from maybe 1,200, 1,400 pounds per foot. We did not use diverters on our last Eagle Ford frac, which was 2014, so it’s been a while. So and we did not use rotary steerable steering technology, which we’re using now. And so far it’s worked great. We’re right where we want to be. And hopefully, we’ll be able to continue to lateral in zone and then frac was a little bit higher intensity frac and see what happens.

[Welles Fitzpatrick:]

Perfect. And then I just had one other. Some folks are going a little bit tighter on the entry zone spacing in the Delaware than you all are. If you guys prove up the four-bench concept this year, is testing downspacing, is that something that you would do later in the year in 2018, or is that something that you’re happy to let others, excuse me, to let others derisk for you?

[Robert Watson:]

Yes, I think we’re going to be letting others derisk for us, that’s a big investment the test tighter spacing. Our property is not going anywhere. So if the norm becomes tighter spacing then we can definitely change and drill some infield wells going forward.

[Welles Fitzpatrick:]

That’s perfect. Thank you guys so much.

[Robert Watson:]

Thanks, Welles.

[Operator:]

Thank you. [Operator Instructions] Our next question will come from Eric Engel with Stifel. Please proceed.

[Eric Engel:]

Hi, thanks for taking my questions.

[Robert Watson:]

Good morning, Eric.

[Eric Engel:]

Hey, morning. Has the timing of well completions, has that met your expectations for the year?

[Robert Watson:]

Yes, we’re pretty pleased. We hear – and pumping services are getting tight. Luckily, we have a very good relationship with a number of pumping service providers, and we’ve been able to get windows about when we wanted them. So don’t know, if we can continue to do that. We are continuing to explore, tying up a frac crew every two months out in the Delaware, because that seems to be this – we’ll have two wells to frac every two months and we’re continuing discussions along those lines. And if that’s – if we’re successful at that then I think that gives us that much more comfort in our guidance.

[Eric Engel:]

I mean, are you still planning on testing off four benches in the Delaware, and then as far as your completion recipes is it same as the previous Caprito well, or how are you thinking about that?

[Robert Watson:]

Well, the recipe was a fabulous success first time around. So I wouldn’t expect us to tweak it too much. But again, we are constantly mining data, seeing what other operators are doing and seeing if what they’re doing might enhance what we’re able to do. So until we get to June, we probably won’t have our final frac recipe on the two wells. As far as testing all four benches, the two-well pad we just came off of is, it has a lateral in the Wolfcamp A1, which will be a different for us. The two-well pad we’re drilling right now has a lateral in the Wolfcamp B. And then the next two well pad we go to in Section 85, we’ll actually have a third Bone Springs lateral. So and after we drill the current two-well pad and the next one, we will evaluate all four zones.

[Eric Engel:]

Okay, great. Thanks for taking my questions.

[Robert Watson:]

You bet.

[Operator:]

Thank you. Ladies and gentlemen, this concludes our question-and-answer session for today. So now it’s my pleasure to hand the conference back over to Mr. Geoff King, Chief Financial Officer for closing comments or remarks. Sir?

[Geoffrey King:]

Thank you, Brian. We appreciate your participation today in Abraxas’ earnings conference call. As I mentioned at the start of the call, the 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:]

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