Abraxas Petroleum Corporation
Q1 2018 Earnings Call Transcript

Published: 9 May 2018

[Operator:]

Good day, ladies and gentlemen, and welcome to the First Quarter 2018 Abraxas Petroleum Corporation Earnings Conference Call. [Operator Instructions] As a reminder, this conference may be recorded. I would now like to turn the conference over to Geoff King. You may begin.

[Geoff King:]

Thank you, Nicole and welcome to the Abraxas Petroleum first quarter 2018 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 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'd 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'd like to 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:]

Thank you, Geoff and good morning. Another solid quarter showing our focus on economic returns. Although the quarter focused on drilling as no new operated wells were brought on production, the quarter set us up for a very busy completion quarter during Q2 where we expect to frac 11 wells, 7 in the Bakken, 4 in the Delaware, and with a significant ramp up of production in Q3 and the remainder of the year. Specifically in the Delaware, we successfully completed the drilling operations on our four well downspacing test; with four wells 660 feet apart in the same zone, and importantly 660 feet from our original parent well which is now been on production almost two years. To-date, we have completed 10 to 11 stages on each well, we developed a casing integrity issue on one of those wells which we are in the process of remediating before we continue fracking off four wells. These wells should be on flowback around the end of the month. Since this is the third well we've had casing integrity issues with, we will be adopting a completion protocol that we developed up in the Bakken where we've been successful fracking about 50 wells to-date on a go-forward basis in the Delaware. The main reason for downspacing test is to give us a good handle on correct spacing going forward. The first indication is monitoring of offset wells for frac hits during the pumping of the various frac stages. We have the parent well shut in with pressure gauges in it and are monitoring pressures on two other wells, and to date we have seen no indication of frac hits. We are also gathering microsiesmic data and we'll be closely monitoring flowback pressures and initial production profiles before coming to any conclusions. The Permian drilling rig is currently drilling without issues as two well pad which we call Greasewood, 3 miles north of Caprito. The drilling operation of these two 1-mile lateral should be completed in the next several weeks at which time the rig will move about 4-mile south of Caprito to drill a two well pad on what we call mesquite [ph]. Up in North Dakota we have 7 DUGs drilled on completed wells to start completion soon. The 3 well Yellowstone north central pad has May 27 frac date and the four well Lillybridge southeast pad will have frac operations start immediately after we finish the Yellowstone. These wells should be on flowback or early Q3 -- and the drilling rig, our Raven Rig1 is again ahead of schedule on the four well Raven north central pad. We hope to have these four wells on flowback by the end of the third quarter. Now I'm going to try to answer four questions that I know will come up before you have to ask them. One, will be on Permian takeaway issues and differentials. Two, will be on M&A. Three, service cost escalation. And four, adding a second rig in the Delaware. The first question, the Permian takeway gets a lot of press lately, mostly negative and it's not one we're taking lightly. Within the last week we have had face-to-face conversations with all of our oil and gas purchasers who have all said that there may be problem -- there will probably be issues somewhere in the basin but they see no problem in delivering our barrels and our MCS because of all the pipeline interconnects we have available to our existing in place gathering systems. That being said, we will be subject to basin pricing. Last year we were concerned with the basin blowout and hedged basin differentials for oil. Although we made a bit of money on the hedges, we never saw the blowout, so when the hedges rolled off, we were looking for a favorable entry point which is never materialized and thus far we have missed our opportunity. Second question; our focus in the Delaware on M&A is consolidating our acreage footprint to maximize efficiency economics and value; while at the same time we're looking for opportunities to add to our position at a reasonable cost. And looking at our area of Ward-Winkler Counties, we have one opportunity to do this consolidation and it's now. I would say in 6 to 12 months, all the consolidating that can be done will be done and that opportunity will not be available anymore. In the first quarter, we added about 1,000 net acres and expanded our footprint up into Winkler County where we participated in two 5,000 foot laterals on this new acreage on a non-op basis for 30% working interest. Both of these wells are now on production and have 30 day rates over 1,100 barrels a day. We have several other deals that are -- that help accomplish our objective of increasing our acreage footprint that are in the final stages and we look forward to discussing these in the very near future. On our South Texas divestiture, we are still in talks with several parties interested in our properties. Even though we have reasonable expectations, no one has meet them yet. South Texas is generating about $0.5 million a month in free cash flow, so we're certainly not going to give these properties away. On the issue for service inflation, we see service costs gradually creeping up in the Delaware, not so much in North Dakota but we've not seen the huge increase people have speculated about. We've also not had an issue finding availability of confident frac crews and thus it has not been an issue as well. And finally, the fourth question, adding a second rig in the Delaware. We have on our existing mostly held by production leases as many as 20 years plus of inventory with the one rig program. We have existing staff fully capable of running a two rig Delaware program and we have the financial capability to support a second Delaware rig. However, we have a number of questions to answer before we make that move. One, with a one rig program in the Bakken and Delaware, we're guiding to year-over-year production growth between 40% and 50%; and the market doesn't seem to recognize that. So would it recognize even more growth? Two, to support a second rig we would need to add capital to our balance sheet. We are proud of our conservative balance sheet with the market penalize us for adding capital. And three, although we have been assured of ample takeaway capacity to support our current program, does it make sense to add production above our current plans when there could be takeaway issues and certainly on favorable differentials when both takeaway and differential issues should be solved within the next year to year and a half. Now if I haven't answered all your questions, please ask them now.

[Operator:]

[Operator Instructions] Our first question comes from the line of Will Green of Stephens. Your line is now open.

[Will Green:]

Bob, I think you hit in the first four questions there but I would like to get a little bit of investor clarity on just the differential situations because I do know that it is topical. So you did mention you guys are going to be exposed to basin pricing; can you help us just -- with how to think about how pricing has been so far this quarter, maybe in the Delaware, specifically?

[Robert Watson:]

The latest number I have in April are differentials, we're just north of $3. So I have not heard anything about what May looks like but it's not going to be any better than that.

[Will Green:]

Sure, that at least gives us kind of a starting off point. And pretty big CapEx spend in 2Q, that seems justified given how much activity you guys have going on. How should we think about that completion schedule as we move into 3Q and 4Q? Is it going to be a pretty big spend in 3Q than tapper off or should 2Q kind of be the biggest piece of the spend this year; how do we think about that?

[Robert Watson:]

I think 2Q will be our biggest. I don't see another quarter where we'll be fracking 11 wells. I think in 3Q, obviously the drilling programs continue each quarter and that's going to be a pretty constant amount of money, the only variability will be the actual working interest on the pads we're drilling. But completions go -- I would suspect it will have a four well completion towards the end of the third quarter in the Bakken and probably a two-well completion at least in the Delaware, and in the fourth quarter possibly another northeast Raven pad three wells or four additional wells in the Bakken -- or five wells, additional wells in the Bakken. That would be dependent on whether -- and probably another couple -- maybe four wells in the Delaware in the fourth quarter. So you can see that the completion activity will be about a half in each quarter and the drilling activity will be about the same each quarter.

[Will Green:]

And so the way to think about it is probably the biggest kind of leap will be in 3Q, and then 4Q, still some growth but maybe not quite as much as we see in 3Q, correct?

[Robert Watson:]

Correct.

[Operator:]

Our next question comes from the line of Ron Mills with Johnson Rice & Company. Your line is now open.

[Unidentified Analyst:]

This is Doug McIntosh [ph] on for Ron this morning. I was just wondering if you could give a little color surrounding the calls of the midstream curtailment you saw in the first quarter? And have those issues been resolved and kind of where do you see future impacts, if any?

[Robert Watson:]

The biggest midstream issues we had were up in the Bakken. Our wells are much stronger than we expected, much stronger than pipeline company expected, and it has taken them a while to figure out a way to take all of our gas and we're pleased to report I guess that just within the last week or so they are now taking all of our gas and so we've been firing [ph] quite a bit up there which has been exacerbating for us but it's just a fact of life and I guess we're just a victim of our own success. We didn't plan for as much production which is a good thing, and one didn't either but they are working on it and hopefully it will be -- that issue will be behind us. The other issues out in the Permian is also been with the gas plants that we're tied into. They -- one of the plants has had a significant upgrade, it is now just going back on-stream this week, and we are now selling essentially 100% of our gas where we were flaring a pretty good percentage each day and it varies every day, and hopefully that issue will be behind us too. So curtailments first quarter, a little bit in the second quarter, and then hopefully, fingers crossed, none going forward.

[Unidentified Analyst:]

And then just back to the casing integrity; you mentioned tie-back strings that you've used to kind of eliminate that risk. Can you mention to develop that in the Bakken; I was just wondering just kind of operationally if you could walk me through the process? What's different there than a standard composition where you weren't using tie-back strings I guess?

[Robert Watson:]

If you don't use a tie-back string, you're fracking down your 7-inch intermediate casing which has a lower burst pressure than either a 5-inch, 5.5-inch or 4.5-inch tie-back string. We saw this happening quite frequently up in the Bakken early on; we're a small company and we really can't afford issues like that to be very prevalent. So we started running tie-back strings early on up there and have not had an issue with casing integrity on any of fracs that we've done. Out here in the Delaware, we saw people running tie-backs and we saw people fracking down 7-inch. Fracking down 7-inch will save you a little bit of money, so we decided to try that. 7-wells where we had one integrity issue which was too much for us but we thought it was kind of a one-off. And then on this well, to protect or to try to foresee an integrity issues, we ran very sophisticated inspection locks on these wells before fracked them. And in fact, we found well that had a wall thickness issue, so we ran a tie-back string on it already. And we proceeded with fracking the rest of the wells and now we've issued -- busted the casing on one of the wells. So we are in the process of squeezing that off, running a tie back string and then we'll continue on with the frac. Of all four wells, and hopefully all four wells will be on flowback by the end of May. On a go-forward basis we decided we'll just bit the bullet and routinely run tie-backs on every well so that we don't have to worry about this issue going forward.

[Unidentified Analyst:]

And then just quick, in terms of the cost and cycle time in running the tie-back strings. What kind of impact do you have there versus not?

[Robert Watson:]

It really doesn't hurt anything because you have time between when the drilling rig leaves and where your frac crew arrives. So running the tie back string is a work over rig. And then you flow the wells back through the tie-back string, basically until they see slowing. Then you pull the tie-back string to where you can reuse it and then run your ultimate compression of two-wheelers. So you might lose a couple of days then but that's not only the time constraint; you lose and the only cost is; one, the time to run it.

[Unidentified Analyst:]

And then the time that you're using that pipe but it can't be used it up in the Bakken, as well as many as three times, and then we'll use that pipe for our liner. So we completely unused it, so it's eventually used anyway. So it really doesn't add a whole lot of cost per say other than a little bit of extra time to run it and pull it.

[Operator:]

Our next question comes from John Aschenbeck of Seaport Global. Your line is now open.

[John Aschenbeck:]

I appreciate the very thorough prepared remarks as well. So my first question here is just on 2018 production trajectory. I was wondering how we should think about growth in Q3 and Q4, so I'm just kind of eye-balling the visual on Slide 6; it looks like to me that your exit rate for the year appears higher than what it's been on previous steps. And then I guess kind of a follow-up to that; I was hoping that you could remind us what the underlying assumptions are for your 2018 guidance? I suppose what I'm really trying to get at here is, if there is potential upside because just looking at the results across our portfolio, it looks like you continue to beat your tight curves by a pretty wide margin.

[Robert Watson:]

First of all, you can notice from our original slide-deck to the one we put out today. We've always been anticipating as we alluded to this quarter to drop off and the acceleration to the back half. What we're benefiting from -- what we're modeling in is basically tight curve type assumptions for all these wells that they performed to their tight curves; we're obviously beating that. The other thing I'd noticed, our well performance has been -- continues to be substantially above, even those higher expectations that we've had; and as Bob mentioned, we're starting to capture a whole lot more gas in the Bakken and Permian. That also isn't built into those assumptions. So really for us it's about timing and execution; if we can get these wells on in time I have a very high level of confidence that we'd be above what that diagram shows you. If there are delays, that will be an issue. Again, we're ahead of schedule drilling in the Bakken, that's an upside right there, I'm just bringing things on in a timely basis. A little hiccup in the Permian shouldn't cost us all that much. I mean, we blended out over the course of the year, you're probably talking about 50 to 11 barrels a day in last time. So don't really matter all that much although it is an operational hiccup. So overall, we feel good about where we are, declines have been less than we're looking for in the PDP base. And wells continue to perform better than we thought.

[John Aschenbeck:]

That's great color, I appreciate that. And then my follow-up here is just on the downspacing pilot. I was wondering given the remedial work that's taken place on a couple of those wells or has taken place on one and will on the other -- is there any potential risk to some of those wells having initial lower rates than expected?

[Robert Watson:]

We'll let you know in about 60 days. As I said, we've experienced any frac hits which -- basically the fracs are almost half done. Would have thought that if we were going to see him, we would have seen at least one or two of them. We would have seen one or two them by now. We've got a lot more science that we're gathering, the microsiesmic will be very interesting. What I didn't mention is that we're running all sorts of tracers in these wells to see where the fracs are actually going. All of that is designed to help us plan our future operations. It will be very interesting to us to see if there is any production degradation, especially on the well that's closest to our parent well. And only time will tell, hopefully not. I would guess if we had to guess that there would probably be a little bit of degradation but we just don't know the degree at this point. We've done a bunch of activities on degradation, and if we sustain a 10% or 15% degradation, these wells are still extremely economic for us.

[John Aschenbeck:]

Okay, got it. Understood, appreciate the color and that's it for me.

[Operator:]

[Operator Instructions] Our next question comes from the line of Eric Engel of Stifel. Your line is now open.

[Eric Engel:]

So you guys mentioned your clearing quite a bit of gas up in the wells, then how do guys stand on the gas capture roles that are coming down from the NBIC in November?

[Robert Watson:]

We watch that on a daily basis and until this past week we were running right up on our 85% limit, our 15% limit of flowing [ph]. Now that the one-oak system is now taking up all of our gas, that issue is behind us and hopefully, won't have to visit it again.

[Eric Engel:]

And then can you give some color on the completion techniques that you're planning on using for the Greasewood, are there tweaks from how you completed the Caprito well? And then just any additional color there?

[Robert Watson:]

Our frac recipe is always subject to tweaking depending on what we learned. I would say right now that we probably aren't considering any major tweets. The biggest difference is we'll be planning ahead and running tie-back strengths before we frac those wells.

[Operator:]

[Operator Instructions] Our next question comes from the line of [indiscernible] of Baird. Your line is now open.

[Unidentified Analyst:]

Thank you for taking my questions. Just to clarify, for the narrower basin in particular, we'll give you a comfort that you can move 100% on gas over the next year -- year and a half. Marked as of in year 2019, if you were to get interrupted what do you think will cause that interruption?

[Robert Watson:]

All we have is assurances from our purchasers that they can take all of our barrel because of the number of interconnects we have onto our gathering system. Certainly no guarantees were two small to have firm transportation on any other pipelines out of the basin, not unlike everybody else that's a small cap. And so we're relying on what they told us, we've got very long-term relationships with all these purchasers so we have no reason to suspect what they tell us is not true but again, it's just -- their assurance to us is all we have to go on. And if we do have an issue with one interconnect, hopefully the multiple interconnects we have will take care of it, we can instead of moving barrels to one place, we can move barrels to another place. So it will be monitored day-by-day by us, that's for sure with it's marketing and other basis has become a very high priority for us and something that we're spending a lot of time on -- one, understanding; two, minimizing any risk that we can; and that's the best answer I can offer you.

[Geoff King:]

Only other thing I'd add is, let's all remember that the Caprito area and everything else we're developing in this area is all going to be on-pipe. So minimizes trucked volumes which be our highest risk.

[Unidentified Analyst:]

Also, on the pricing side; are you exposed to Milan and Waha [ph] for [indiscernible] Delaware Basin on gas production.

[Geoff King:]

Yes, we are.

[Robert Watson:]

Only other thing I'd like to note on that to just keep in mind on what our pricing in gas is? We ran some economic sensitivities and you can basically assume we give the guests away for free and it takes the rate of return down about 2% on these wells. So not really that important.

[Unidentified Analyst:]

[Operator Instructions] Our next question comes from the line of Sam Roach of Canaccord Genuity. Your line is now open.

[Sam Roach:]

Just really quick question from me; the $20 million of budgeted acquisitions in Q2, is that net of dispositions or is that growth number?

[Robert Watson:]

That's a growth number. And if not just one, it's multiple deals that add upto $20 million.

[Sam Roach:]

And I may have missed it but can you give any additional color on whether that's adding to existing working interest? I'm stepping out to new lines.

[Robert Watson:]

There are some new land and some added working interest but it's a joining land. So joining land; it's not stepping out to a new area. Everything new is joining existing land.

[Operator:]

[Operator Instructions] I'm showing no further questions at this time. I'd like to hand the call back over to management for any closing remarks.

[Geoff King:]

Thanks, Nicole. We appreciate your participation today in Abraxas's 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:]

Ladies and gentlemen, thank you for participation in today's conference. This does conclude today's. You may all disconnect. Everyone have a great day.