Abraxas Petroleum Corporation
Q4 2016 Earnings Call Transcript

Published: 15 Mar 2017

[Operator:]

Good day ladies and gentlemen, and welcome to the Abraxas Corporation Q4 2016 Earnings Conference Call. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Mr. Geoff King. You may begin.

[Geoffrey King:]

Thank you, [Kiara] (Ph) and welcome to the Abraxas Petroleum fourth quarter and year-end 2016 earnings conference call. Bob Watson, President and CEO of Abraxas, joins me today. In addition, we have our Chief Accounting Officer and several of our VPs 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 this 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, good morning. Fourth quarter we produced approximately 800,000 barrels a day up 34% from third quarter, which gave us an average production for 2016 of approximately 6,200 barrels a day, which was the center point of our guidance, which is up 3% from 2015. Now we got there with very high quality development opportunities, which has given us an extremely great capital efficiency, which is reflected in our proved develop producing finding and development costs. Now analysts tend calculate finding and development costs different ways, but we feel like adding PUDs to that number can have a material and perhaps misleading impact on F&D cost calculations. So we take them out, I just want to walk you through the numbers to show what we come up with as far as the capital efficiency goes. We start with our year-end proved develop producing reserves roughly 14 million barrels. We add to that the PDP reserves that we sold in our property divestiture program which was 1.2 million barrels. We also add back to that the production of 2.2 million barrels and then subtract our beginning PDP reserves of 13.6 million and then come up with there was PDP reserves added during the year of roughly 3.8 million barrels. Now our total CapEx for 2016 which includes acreage, infrastructure but just to be conservative we used the total number $31.7 million you divide that by the 3.8 million barrels added PDP reserves you can come up with an $8.39 per BOE finding and developing cost. Now let's look at our actual operating costs, our lease operating expenses were at the low end of our guidance of $8.27 per BOE. Our G&A was the middle of our guidance $4.43 per BOE. Production tax right in the middle of $2.41 and our demonisms interest charge since we have very pristine low leverage balance sheet of $1.69 that comes in with the total of $16.80 per BOE. That gives us an operating margin when you take the average price that we received per BOE for the year including our hedges of 3229, subtracting our operating costs that results in an operating margin of $15.49. You divide that number by our F&D finding cost and income up with the full cycle ratio was 1.85. We are very proud of that number we think we will do as good or better this year, despite what I think is overblown rhetoric about that service cost inflation. Now we guided to a midpoint in 2017 average production of about 8200 barrels a day, which will be up 32% year-over-year with an exit rate of 9500 barrels a day, which will be up 19% year-over-year. But we get there along a fairly towards this path which might difference from some analysts projects. As we are not adding any new wells in the first quarter of 2017, unconventional well decline kind a takes over and we expect about 15% production decline in Q1. And that rates are continue on into Q2 before a slug of new very impactful wells come online towards the end of second quarter causing our production to rocket up for the second half of 2017. Now I would like to continue with my catalyst theme from last year and I will update the list with our planned catalyst for 2017. And like to say that although adding bolt-on acreage principally in the Delaware at an extremely attractive price and I want to emphasis that we are not going to compete in the $30,000 $40,000, $50,000 per acre deals. But by bolting on acreage consolidating our block and thus increasing our location inventory for the future. That all might be considered to catalyst and that’s going to happen when it happens but instead I'm going to concentrate on catalysts that create near term invisible growth. And catalyst number one again is in the Bakken where we have almost completed a four well Stenehjem pad where we have a 75% working interest 62% net revenue interest. These fracs are scheduled and has been contracted for mid-May when warm weather should be around I hope. And if using an average 30 day rate of more than 1000 barrels a day, which is our history now for the last 30 some odd wells, we would add about 2500 barrels a day of net production hopefully by late June. Our company owned rig would then move or will move as soon as its finish things drilling the Stenehjem four well to a three wells Yellowstone pad which if all goes well that should be drilled and completed towards the end of the summer or towards the end of the third quarter, we will have 52% working interest in those wells thus comprising a catalyst number two which would arrived during towards the end of the third quarter. Now catalyst number three, we are currently drilling a two well Caprito-98 pad in Ward County. Delaware basin West Texas where we have an approximately 89% working interest. These wells have a scheduled frac day for early June and with first production by the end of June. Now I would like to degrade for a second and hopefully clear up what we feel is a misconception out there. And it really was a non-material event that while we were drilling the first well, we were running the surface casing and the whole started getting sticky. We thought we needed to work the pipe up and down to relieve the stickiness and then we found out that the rig have mechanical issue and couldn't pull the pipe. By the time the mechanical issue was fixed the pipe was stuck. We had only spent a couple of days and a couple of hundred thousand dollars to this point. We tried to unstuck the pipe we felt license we didn't have much invested at that point, it’s the prudent thing to do is just plug that well and then skid the rig and start over. Now in Texas when you drill a well to any depth and plug it you have to file a plugging report. Some research we have done in the last week or so we found out that on some websites and some talk people where they talk about Abraxas and some analyst reports actually pickup on this plug and abandoning report that we have to file with the railroad commission. And all of sudden assume that we have disaster in the Delaware basin and we actually had to abandon the Delaware well. That's not the case, we were able to get back on this well, replacement well we have not fit first intermediate casing on both wells on the pad and the replacement well that's drilling below 9000 feet this morning getting ready to build the curve. So it was certainly a non-issue, I think it's a indicative of what is happening in our world today where various people pickup on a very minor negative, blow it out of proportion, spend more time on that and to where they don't have time to talk about the good things. So getting back to our results, assuming that we have results similar to what we obtained on our Caprito-99-301H using that as analogy of about 1000 barrels a day 30 day rate by the end of the second quarter we should add an additional 1600 barrels a day. The rig is scheduled to have quite a bit of flexibility, but it will create additional catalysts throughout the year. We do plan on a continue with development program. We do have some flexibility to enable us to use land deals, drilling wells our land. But our current plans in case we don't have an issue there, we permit the two well pad in both Section 82 and Section 83. Each pad is designed to test one previously tested target zone plus one new zone until all four identified targets have been tested with obvious implications to our year-end 2017 reserve adds. Now catalyst number four is in South Texas in the Jourdanton, Atascosa County where we have a 100% working interest; we continue to evaluate the performance of our Bulls Eye Austin Chalk well, it's currently producing after some production issues, producing about 160 barrels of oil a day; we might want to say we would wish it was higher, we always wish that but it's certainly not a bad well. But as we continue to study the Austin Chalk, we have also continued to study our Eagle Ford in our area; and that study has caused us to change our plans a bit. And although we still consider the Austin Chalk a very viable target and are still buying acreage in the Austin Chalk play at a very good price. While we were studying our Cat Eye 1H which was the last Eagle Ford we drilled and the first well we drilled in what we call our South Fault Block and it's turned out to be probably the second best Eagle Ford well we drill; in studying the results of that well, we determined that and this was about two years ago using current technologies and for steering we were only in the lateral that our target for about 25% of the time. Then when we frac the well we used different radioactive tracers in each stage while we were fracking it and the purpose of that is that you can measure the percentage of the tracer in the oil that you are getting back to give you an idea where the oil is coming from. Well that analysis indicated that about 75% of our production was coming from the 25% of the lateral that we were in zone. Also that well was not fracked with our new technology of using diverters; so all that together we decided to drill well as an Eagle Ford test and it will called the Shut Eye 1H; we will use the new steering technology and employ diverters for the first time in the Eagle Ford for us; all designed to give the Eagle Ford another chance; it will also HBP another units, which will also hold the Austin Chalk rights in that unit. Now we are hoping for a rig during the second quarter; we got some indications that we have one, which would allow us to get the well completed in the early third quarter. Now the expected results who knows, I wish had a better analogy to give you, but whatever they are they will be added to the previously discussed production adds from our other two areas. Now we hear a lot of talk about service cost inflation and I don't mean to sound cavalier about it, but I think it is over blown a bit. To be safe, we have budgeted about 10% to 15% overall increase in our ASDs, mainly attributable to what we think is going to be a 20% to 25% increase in frac costs. Now we keep in my mind, we own our own drilling rig in North Dakota; so any increase in drilling rig rates in the Bakken for us simply means moving money from one pocket to the other; but we are experiencing some tightness and frac spreads schedules especially in the Permian and that usually results in price increases. But our contracted frac spreads for both the Bakken and the Delaware, May and June have shown only about a 15% increase over what we were paying last year. Another concern we continue to hear about is the takeaway capacity. We are fortunate to be in areas both the Delaware and the Bakken that are well served by both gas and oil lines. In the Bakken we have not experienced any significant production outages for more than a year as oil and gas systems have been expanded and we see no future issues there at our anticipated production levels. In fact with the completion of the Dakota Access Pipeline, we see a significant improvement and the differentials we have received for our crude oil. In the Delaware, we are fortunate to be in a legacy producing area that is crisscross by pipelines, we have experienced gas takeaway issues in the past and continue to have periodic issues mainly due to antiquated processing plant that we go to. A new plant is under construction is almost complete, and if that doesn't completely eliminate the problem, we have several alternatives when our existing gas contract expires in early 2018. So in summary, 2016 was a great year for Abraxas to slightly industry downturn, but 2017 will be even better with significant exposure and two exciting plays that have very predictable results giving us very much high confidence in our 2017 guidance. With that, I'll open it to questions.

[Operator:]

Thank you. [Operator Instructions]. Our first question comes from the line of John Aschenbeck from Seaport Global. Your line is open.

[John Aschenbeck:]

Good morning Bob and Geoff thanks for taking my questions and congrats on the updates. Follow-up on 2017's program and I appreciate the details as it pretends to 2017's production profile. My question was more so as it pretends to 2017's exit rate, I think you have previously pegged it at around 9,5000 barrels a day of equivalent. And I was hoping if you could share the assumptions behind that outlook. I know you have had some really nice results from high intensity completions in the Bakken and your Delaware wells look to be outpacing your initial expectations. So I was wondering if recent outperformance we have seen in the Bakken and the Delaware is baked into that 9,500 exit rate?

[Geoffrey King:]

John it's Geoff thanks for the question. When you are looking at how we model this out, we took obviously a very conservative approach. We are using a Bakken type curve that is from actually a couple of years to risk both timing as well as performance. Obviously our performance continues to improve out there. So that's a significant level of conservatism that we have built into that exit rates as well as our production numbers for the year. On top of that in the Permian, we have seen significant outperformance from our first well out there. We are not assuming that outperformance in also risking those tight curve. And then on top of that, I would just add that for timing and the timing of wells coming on, we space them out at what we thought were reasonable assumptions that would be easy to achieve taking into consideration as Bob mentioned frac tightness. So we are already compensating for that and probably overcompensating in our numbers. So I think we are in good shape. And the only other thing which it will be additive volumes will be the Eagle Ford and Austin Chalk tests which we are scheduled for this year. And we have those modeled in per our previous type curve, which is nothing that is crazy. So we are not assuming any outperformance in any of our areas; so that should hopefully all be upside and lead to an even better exit rates and better production for the year.

[John Aschenbeck:]

Got it, it’s really helpful. I appreciate the detail there Geoff. My follow-up here is on Delaware A&D and Bob, your prepared marks last night and the press release kind of touched on this, but I know you have previously spoken about a handful of deals in and around your current footprint, whether that be potentially buying out some of your current working interest partners or bolting on smaller deals nearby. I was curious to get a feeling more so of the size of the opportunity set that you are currently evaluating. And I understand if you can't give too much detail, but just to get a ballpark figure of potentially what your acreage footprint could ultimately look like. You have got 6,000 net acres now, approximately. Would it be unreasonable to foresee you guys would say 10,000 to 12,000 net acres and essentially double what you have today?

[Robert Watson:]

Double would probably be difficult, but we are involved pretty far down the line in a number of negotiations; the unfortunate thing is they are with much bigger companies and they don't act as fast as we do as you can imagine, but we feel comfortable that at least some of those will be successful and with that a number between 7,500 and 10,000 acres is certainly achievable and would not require us to jeopardize our balance sheet to do so. Some of the deals might be outright purchases, but nowhere near the prices that people are paying out there; we are not going to get in that game. And some of them might be drill-to-earns with an implied acreage cost again at a significant discount to what people are paying. So, we are pretty optimistic about it and our internal goal is to certainly grow those net acres, but more importantly grow them in a quality area that gives us high confidence level in a number of new locations that we are adding. Certainly our existing drilling program will help us prove up some additional zones that have not been proved up yet by offset operators, but they are very, very similar to zones further to the west of us that have been proven up; so we have a very high confidence level of them. But our Caprito drilling program is designed to prove up all four, the zones that we have identified there and there is possibly a fifth too, but we are just working on the first four. And if that's the case then we are looking at very significant reserve adds at the end of this year as we only have five PUDs booked now, and that's about 1.5 net wells because of our working interest currently show very insignificant reserve booking in the Delaware, which has an opportunity to really skyrocket with success.

[John Aschenbeck:]

Got it. I appreciate the detail. That’s it for me.

[Operator:]

Thank you. And our next question comes from the line of Steve Berman from Canaccord. Your line is open.

[Stephen Berman:]

Thanks, good morning Bob and Geoff. Your Q4 LOE, Bob, was well down from the prior quarters in 2016; some of that obviously from the sequential big production growth. Can you talk a little bit more about what drove that and that's at the low end of your 2017 guidance of $6 to $8 a BOE. Can you keep it down there with that six handle at the low end as we move through the year?

[Robert Watson:]

Well we certainly hope so, two things contributed to the improvement throughout last year. One we had as you would know a divestiture program ongoing and we were successful and not only raising a significant amount of cash, but we got rid of some very high cost properties, which drove that average LOE cost up. So they are gone forever, and not the return, and as we continue to add high volume wells in the Bakken and in the Delaware, those wells are coming online at a very low LOE per BOE rate. So hopefully we continue to drive that average down throughout the year.

[Stephen Berman:]

Okay. And then on the pricing you talked about the tremendous improvement in natural gas in NGLs in January. Is that continued through the first quarter and what should we assume for example for NGLs as a percent of WTI as we move forward here, and a lot of companies are seeing a big improvement in NGL realizations, can you talk a little but more about that?

[Robert Watson:]

Yes I think our realizations in December and January were much higher than what we expected. Gas prices as you all know were higher then. We have an unusual gas contract in the Bakken when natural gas is $2.50 or less we virtually get nothing for it or the NGLs, but when it gets above that and we get an exceedingly good price the higher gets. So that's what happened in December and January. Recent weakness in February and early March in gas prices our realizations won't be as good, but another positive is that the gas that we are producing in the Delaware is extremely rich gas as rich as the Bakken. So the NGLs we are getting there are market price and so as a percentage of our production grows in the Delaware, our NGL realization should go up along with that.

[Stephen Berman:]

Got it. And then one final one from me, just a clarification, you said because no new wells coming on in Q1, Q1 would be down production then 15% from Q4 and then you have talked about Q2 being down similar or did I hear that wrong and Q2 would be kind of flat versus Q1 before it rockets up in the second half. Can you just elaborate your Q2 production language for me?

[Robert Watson:]

Yes, I think we expect production to drift off a little bit more in Q2 maybe for the first two months. And then as we have new wells come on in June that's certainly going to impact June production, so the average for the second quarter certainly gets a little better. It's a matter of timing at this point, we are very comfortable with the anticipated results that we expect. We just can't be as precise on when those wells are going actually be on production and what impact they will have at a certain time.

[Stephen Berman:]

Got it. All right, thanks Bob.

[Operator:]

Thank you and our next question comes from the line of Welles Fitzpatrick from Johnson Rice. Your line is open.

[Welles Fitzpatrick:]

Hey guys good morning. the third Delaware pad was around spring stuff. Is sounds like that's also going to be in the Caprito area A, is that correct and B, would you be step down and drilling some of the more Southerly acreage thereafter?

[Robert Watson:]

You are correct, it's in the Caprito area. And as you know all of our acreage is HBP. So we have the luxury of scheduling things when they make the most sense for us. Right now absent any drill-to-earn deals which have a high probability of probably happening, but at this point we are not scheduling for any. So we see the biggest benefit to Abraxas for 2017 is to prove up those four zones in the Caprito area, so until we get those four zones drilled and evaluated probably wouldn't move the rig out of that immediate area and go down south unless it was a drill-to-earn to be so.

[Welles Fitzpatrick:]

And then are you guys planning on any significant tweaks to the completion design that we saw from the 99-101?

[Robert Watson:]

Well you hate to mess with success. We are always looking with that success we kind of got some notoriety out there and we have been approached by a number of companies to swap data and data gathering in Texas is very difficult compared to North Dakota. So we are taking advantage of that opportunity; we are not saying a little bit much more about our completion design because all of a sudden it's become trade bake for us. And if we talk publicly about it to everybody then no one will come to us wanting to give us their information. So, we are confidently evaluating what others are doing and what their results are. And that probably will result in a little bit of tweaking to our design but it's not going to be major because the success that we had.

[Welles Fitzpatrick:]

No, no, that's great. I don't think anyone was looking for a lot of changes given what that well did. And then lastly, any update on the timeline of the PRB and the ranch asset sales?

[Robert Watson:]

Well thank you for asking that, because I forgot to mention it. The ranch is under contract; we are in 21 of the 30 day option period and then to exercise their option they had 15 days to close, which would put closing in the first half of April some time. And the good news is that we have three backups in case this one blows up in our face again like the first one did; don't anticipate that it will but if it does we have got three other interested parties at our price and hopefully capable of closing and closing in a timely manner if we have to do that. No movement on the PRB; we are kind of sticking with our evaluation, and our expected value there. So, it's going to happen when it happens, but it is for sale; but it's not a fire sale, we see no compelling reason to just dump it in the market; and I feel comfortable that eventually we are going to get our price.

[Welles Fitzpatrick:]

Okay, perfect and just as a reminder, the ranch when you say your price, you mean that same price that we had seen in the first sale. Is that correct?

[Robert Watson:]

That’s correct. $550 per surface acre and that includes half of our existing minerals along with that.

[Welles Fitzpatrick:]

Okay, perfect. That’s good. Thanks.

[Operator:]

Thank you. And our next question comes from the line of Will Green from Stephens Inc. Your line is open.

[Will Green:]

Good morning guys. So I thought I would jump over to the Eagle Ford. Since you guys are joining these units, it gives you guys the opportunity I guess to maybe lengthen the lateral on this next Eagle Ford well. Is that something you guys are looking at, at all can you talk a little bit more about how that next well looks relative to the others?

[Robert Watson:]

I think it's about a 6700 foot lateral something like that and the main reason for joining the units is one that we could and that means one well will hold more acreage, there is a physical reason also there is an interesting highways that goes down middle of one of them and we didn't want to have to get involved and getting permits to drill along the interstate highly to hold that acreage so now we will hold it without having to do that. So, yes a little bit longer lateral holding a little bit more acreage in the Eagle Ford and thus it also holds that same amount of acreage in the Austin Chalk or at above it.

[Will Green:]

Great. And then one other one I want to ask is, it's been a little bit since you guys completed a well over there. You guys obviously had a great success over in the Delaware upping profit load. Is that something you consider doing with this next well in the Eagle Ford really increasing the profit loading and if that is the case how do we think about an AFE on a little bit longer lateral and how you guys look to complete this.

[Robert Watson:]

Yes I think the our AFE is going to be somewhere little bit less than $6 million and our profit load was pretty high considering what other people are doing already. That certainly might change it would go up rather than go down. But the main difference we are going to do in the Eagle Ford is use diverters which we have had fed with success on now in the different areas, and we have never tried it in the Eagle Ford, others have tried it with apparent good success. So we got a lot of good things going forward and certainly the Eagle Ford in our South fault block deserves our best short and we are planning on giving it.

[Geoffrey King:]

One other thing I might just add to that Will on the pumping side is, although we are using more propane we are seeing service cost savings that shifting some of the components like HCFR. So there is tit and tat.

[Will Green:]

Great. Thank you guys for all the color.

[Operator:]

Thank you. [Operator Instructions] Our next question comes from the line of Mike Scialla from Stifel. Your line is open.

[Michael Scialla:]

Good morning Bob, wondering if you could elaborate a little bit more on these opportunities you are looking at in the Delaware. When you say drill-to-earn, what might those look like is it drill one well and you earn small block acreage or would that necessitate continuous drilling program, just to looking for little bit more on that?

[Robert Watson:]

Yes, I would say all of the above. We are basically dealing with very large companies, none of which really need money, but they want data. And so they are pretty enthusiastic about getting people to drill wells and prove data up so that they can use it in a more contiguous acreage block that they might have somewhere else. So yes, the deals will be variable some will be one well, some will be multiple wells, some will be cash. There might be an opportunity to just cash some people are. We are dealing with relatively small interest and most of them are in blocks that we already control and operate or at least blocks directly adjoining us, which would allow us to drill longer laterals perhaps. So we are kind of the only game in town for these interests and these companies recognize that. So anyway they can add value they are interested in doing it. So the deals that we have that we are working are all across the board as far as what their ultimate structure is going to be.

[Michael Scialla:]

And if you get one or more of these done, I guess your plan to really delineate the Caprito block would go on hold, you would have to shift capital toward these new acreage blocks. Is that fair? And would you still be looking to test four different zones or would it most likely be focused on just one zone with these new blocks?

[Robert Watson:]

Well I think on the new blocks the drill-to-earn would just be focused on one zone and I don't know which zone that would be yet. It could be, there is an outlier possibility that we would have a second rig running for a little while and we have the room to do that in our budget just to accommodate potential drill-to-earn and continue our Caprito program or it could be that the drill-to-earn fits in our drilling program and we move the rig down there and do that and just keep one rig going; we are very fortunate to have the balance sheet that gives us the flexibility to do that.

[Geoffrey King:]

Mike one other thing I would add is everything we are looking at is historically on trend with Caprito; so it's all the same area and even our stuff to the South I would feel very comfortable with and we are looking at too. So any we would bolt-on, it wouldn't be like we are stepping out with all new zones.

[Michael Scialla:]

Got you. Thanks.

[Robert Watson:]

Thank you.

[Operator:]

Thank you. At this time, I’m showing no further questions, I would like to turn the call back over to Geoff King for closing remarks.

[Geoffrey King:]

Thank you, Kiara. We appreciate your participation today in Abraxas' earnings conference call. As I mentioned at the start of 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 your participation in today's conference. This does conclude the program. You may now disconnect. Everyone have a great day.