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Abraxas Petroleum (AXAS) Q1 2019 Earnings Call Transcript

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Abraxas Petroleum (NASDAQ: AXAS)
Q1 2019 Earnings Call
May. 07, 2019, 3:00 p.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

Good day, ladies and gentlemen, and welcome to the Q1 2019 Abraxas Petroleum Corporation conference call. [Operator instructions] I would now like to introduce your host for today's conference call, Mr. Steve Harris, CFO; and Bob Watson, CEO. You may begin.

Steve Harris -- Chief Financial Officer

Thank you, Kevin, and welcome everyone to Abraxas Petroleum's first-quarter 2019 earnings conference call. With me, I've got Bob Watson, president and CEO. In addition, we have our chief accounting officer and VPs of operations, land, engineering and business development to answer any questions 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.

And finally, I would like to remind everyone that any statements made during this call that are not statements of historical fact 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, and I would encourage everyone to review the risk factors contained in these filings and in our press releases. So with that, I'd like to turn the call over to Bob.

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Bob Watson -- Chief Executive Officer

Thanks, Steve, and good afternoon. At least operating expenses for the quarters were high for a number of reasons and not just bad weather. Earlier in the Delaware play, Abraxas did what most operators did and that was to not anticipate the levels of hydrogen sulphide gas that would be encountered in the Wolfcamp and the Bone Springs. Sweet processing plants were built and high-tensile strength tubules were run in wells due to the well depth and pressure.

Now the industry is scrambling, but not saying much about it. H2S levels are all over the board and impossible to predict. We have wells with levels as low as 200 ppm, which is 0.02%, and as high as 60,000 ppm, which is 6% H2S, and they're not far away and in the same landing zone. We do not have a good explanation but have certainly changed our operations to account for it.

Gas processing is a necessity in this play due to the high liquids content of the gas, and we are blessed with legacy acreage dedication to a sour gas system. Lease sweetening high concentrations of H2S is very expensive, especially when you have to pay to sell your gas, which is happening today. More important for Abraxas and the major contributor to our high expenses last quarter were the fact that we ran high-strength tubulars in our initial wells. High-strength tubulars are more subject to hydrogen embrittlement due to contact with H2S gas and thus failure than lower-strength tubulars.

During the quarter, three of our earlier wells had tubular failures that had to be repaired. Some companies might have found a way to capitalize this rather expensive work, but we elected to charge it off as lease operating expense. The good news is, we started running lower-strength tubulars early on, as well as taking other measures, so the expense of tubular failure should be minimized going forward. Our main focus remains maximization of financial returns, independent of production growth objectives.

In that regard, in light of the Waha gas prices trading negative, we have elected to shut-in substantially all of our deep dry gas production in the Delaware Basin. This will impact production by about 500 BOEs per day net, but we will save money as we're not having to pay to sell, actually it's hard to say you're selling the gas when you have to pay for it, but to deliver our gas. The approximate 6 million a day gross production is our small contribution to alleviating the gas surplus at Waha, and these wells will remain shut-in until prices recover. Onto our Bakken value crystallization process.

I wish I could say more, but we are still in discussions with a number of interested parties, and I can't afford the risk of saying something that might be interpreted in a manner that could have an impact on our discussions. When the process is over, we, with the advice of our financial advisors, will do whatever is best for our shareholders. We were interested to see how much more aggressive the non-op buyers were than those interested in the entire package. We have further reduced our capital budget for the year to around $86 million, which, once again, is designed to grow our business while, at the same time, generate free cash flow to pay down debt.

As I have stated in the past, this budget is very front-end loaded with a busy first half of the year, drilling and completing high working interest wells in the Delaware. We are in the process of moving our rig to the two-well 100% on Greasewood pad, which, incidentally, these are the last two of our commitment wells that we have. And when these wells are finished, we expect to drop the rig for the rest of the year. For the second half of the year, we will concentrate on the Bakken, where our Raven Rig No.

1 recently commenced operations on our six-well Jore Federal Extension Pad, in which we own an approximate 75% working interest. The flow down on the Delaware will allow us time to work on production optimization of our existing wells, as well as hopefully find a better gas market when we bring new wells on in the future. While in the Bakken, the first-half slowdown has hopefully worked to our benefit and getting us closer to better gas market for the new wells when they are completed. The timing of the completion of the six-well Jore pad will depend on weather, oil prices and gas takeaway, but could be delayed into the spring of 2020.

In summary, for the rest of the year, we will place on production five new wells in the Delaware, that's 4.75 net wells. And the Bakken will place five new wells on production, approximately 1.8 net wells here in the next couple of months. And we will have more than six DUCs to frac and bring on production in the spring of 2020, with an outside chance of completing six of them before winter weather sets in, in North Dakota this fall. All of which should create slow and steady production growth for 2019 and 2020 and still generate free cash flow.

And with that, I'll open it for questions.

Questions & Answers:


Operator

[Operator instructions] Our first question comes from John Aschenbeck with Seaport Global.

John Aschenbeck -- President and Chief Executive Officer

So I was hoping to dig in a little bit more on the Bakken assets, and I'll say I certainly understand you can't provide too much detail here. But was curious how sizable are the remainder of your non-op assets, just say, in comparison to ones you just monetized? I'm just really trying to get a feel for how meaningful those potential monetizations could be?

Bob Watson -- Chief Executive Officer

Well, it would basically be a percentage of our operated assets and so it could be any size. But I don't want to say any more than that. But it would be assets that we continue to operate, we just sell down our interest.

John Aschenbeck -- President and Chief Executive Officer

OK. I hear you. OK. Good deal.

OK. Yes, that's helpful. And then, yes, just for my second one, was just hoping you could just walk us through your comfort on liquidity, which is certainly in a much better position than where you were, say, at the beginning of the year after the borrowing base increased and this asset sale certainly helps too. But just thinking, suppose if you couldn't ultimately get the bid you're looking for on the remainder on your assets, with pro forma liquidity around $55 million, just what's your comfort level on that? And I guess, maybe you could also speak to just your outlook for free cash flow for the remainder of the year too?

Bob Watson -- Chief Executive Officer

I would say that with this small non-op Bakken sale, certainly, liquidity is quite adequate. We still have our Eagle Ford assets, which are still actively being marketed with maybe some positive movement in that regard. All of those sales would potentially go toward paying down debt, as well as -- as much as we've tried to clean up our portfolio over the years, we still have some assets stranded here and there that collectively could be worth some decent money. And so we're starting a process of trying to put those together, and we'll put those on the market probably in one of the competitive auction companies here in the near future.

Ultimate goal will be a pure play Bakken, Delaware or potentially just Delaware with no other stranded assets out there. So I think we're very comfortable with liquidity. We had an outspend, obviously, in the first quarter, and we'll have a slight outspend in the second quarter but that was planned. And then with just the drilling rig running in the third and fourth quarters and no planned completions, then we generate a substantial amount of free cash flow, which should get us in the free cash flow total for the entire year.

So we're -- I know it sounds tight, but we're not worried about it.

John Aschenbeck -- President and Chief Executive Officer

OK. Got it. And a follow-up there, if you don't mind. Can you just remind us in terms of maybe potential asset monetization candidates? Just can you remind me, how many acres do have -- mineral acres do you have in the Delaware? What doest the opportunity set look like there? And then same with your water infrastructure?

Bob Watson -- Chief Executive Officer

We own 100% of our water infrastructure. We intend to keep that because we think it adds value to our overall property there. And that's what our ultimate goal is to maximize the value of that asset. We do own minerals in the southern part of the Delaware that, I guess, we can transact on if somebody offered us the right price.

We're not actively out marketing those. The other assets that we have, we have a number of non-Bakken/non-Three Forks producing wells in the Williston Basin, both operated and non-operated, that have collectively a decent amount of value. We also have some scattered wells in Wyoming and Utah that we really don't need in our portfolio, as well as a package of overriding rolling interest scattered all over that we've collected over the years, and we could put all those in one package and hopefully get a decent price for them as well.

Operator

Our next question comes from Michael Scialla with Stifel.

Michael Scialla -- Stifel Financial Corp. -- Analyst

Bob, you mentioned the H2S, how variable that is. And can you just talk about some of the things you're doing? You did mention the lower-strength tubulars, but anything else there you're doing to account for the H2S levels?

Bob Watson -- Chief Executive Officer

Yes. We're also cementing the wells back to surface, top to bottom. We didn't do that on the initial wells, thinking that the tubulars would be adequate. But that's the main difference.

Obviously, we're taking extra precaution with our service facilities to make sure there is plenty of belts and suspenders there to make sure that we don't let any H2S get loose. The good news is that we are tied in to sour gas gathering systems on all our leases so far. And as long as those plants are running, we're selling gas, we're not flaring. Energy transfers, Coyanosa plant is down for maintenance right now, so we are flaring a good amount of gas, hopefully not much longer.

They say it's just a day or two, but they've said that now for a week. So we're unfortunately subject to their operating capabilities. It's beyond our control. But we're watching it very closely, and we're very pleased to be in the position we're in as opposed to some operators that don't have access to a sour system and having to treat wells on the lease, which can become extremely expensive.

Michael Scialla -- Stifel Financial Corp. -- Analyst

Gotcha. I guess any estimate on what the incremental cost for you might be with the cementing -- additional cementing required and in the lower-strength tubulars?

Bob Watson -- Chief Executive Officer

So Kenny Johnson is saying $100,000 a well?

Kenny Johnson -- Vice President of Operations

Yes. It's about $100,000 that we're looking at right now. But the flip side, I would save it on the frac due to the less friction, less horsepower. And then bigger -- we went bigger too at the same time.

Bob Watson -- Chief Executive Officer

Yes. We went bigger pipe, lower-stressed tubulars, so we're saving money on hydraulic horsepower on the fracs, which kind of offsets some of the increased cost of cementing back to surface. And the lower-strength tubulars are a little bit cheaper than the high-strength tubulars. So there's some offsets in the works and it's not that much incremental cost to us.

Michael Scialla -- Stifel Financial Corp. -- Analyst

Got it. OK. And then curious on -- I know you said you are sticking with the plan for this year despite the higher oil prices. You had some issues, but your first-quarter production was strong.

But I realize there's some unpredictability with third-party gas processing constraints here. But any updated thoughts on your production for the year that 10,500 to 11,500 BOE a day still feel like a good number or does that need to be adjusted?

Bob Watson -- Chief Executive Officer

Well, we're going to wait until this small Bakken sale goes through and closes. And then we'll look at our model and see if the combination of that and shutting in 500 BOEs a day of dry gas production necessitates a change in the guidance. But other than that that's the only thing that would impact it. The wells are coming on as good as we expected, above our type curves.

Timing is as we expect so far. So I see no other reason to change it other than those two events.

Operator

Our next question comes from Noel Parks with Coker Palmer.

Noel Parks -- Coker and Palmer Investment Securities Inc. -- Analyst

Just a couple of things. I was wondering, in Ward County, in the Delaware where you are, has there been any particular incremental news from other operators out there that has any bearing on your plans or -- as far as other formations, etc., in the Delaware?

Bob Watson -- Chief Executive Officer

I don't think there's anything new then since the last time we talked. Certainly, we monitor that to the extent that we can get the information. We do have data swap agreements with three nearby operators, so we are getting information from them on wells that are close to us. But I don't think we know of anything new of substance that impacts our operation other than what we're learning ourselves.

Noel Parks -- Coker and Palmer Investment Securities Inc. -- Analyst

OK. I guess along the line I was wondering -- oh, sorry, yes, along the line I was also wondering about just if you've gotten any additional data that gives you more confidence in your density assumptions out there?

Bob Watson -- Chief Executive Officer

We have pretty much concluded our study of our downspacing test. And as I alluded to last call, it looks like the 900 to 1,000-foot spacing seems to be the optimum to maximize recovery over a section of land and not interfere with surrounding wells. So we're going to continue to study it. We know other operators offsetting us are continuing to study it.

We know of one 660 downspacing test nearby that's under way. Luckily, we don't have to do any more parent-child drilling for a while, so we can sit back and wait for these results to come forward before we have to make any decisions. But if we had to make a decision today, we would reconfigure our spacing to, say, 1,000 foot apart in the same zone. And that would -- we've published before our net locations, both 1,320 and 660, so that would put the net locations approximately right in the middle of that, which is about 400 net locations that we have on our land, which at 24 wells a year for two rigs, that's a lot inventory.

Noel Parks -- Coker and Palmer Investment Securities Inc. -- Analyst

Great. Great. And I've been thinking, as you were going through reviewing different bids in the Bakken, and matter of fact, obviously you're talking about still doing some discussions around the Eagle Ford, I'm just curious, what you guys are using for service cost assumptions, mainly for the near term? And then to the degree that you've seen people modeling out the longer-term returns on the wells, just wondering if people are baking in any significant service cost assumptions.

Bob Watson -- Chief Executive Officer

We're not. We're assuming oil prices stay flat and service cost stay flat. Obviously, if all prices go up, service costs are going to go up. Margins, maybe they stay the same.

It's anybody's guess. And I think trying to refine that gas into the future might be a fool's errand. But we're comfortable leaving cost flat, as well as oil prices.

Noel Parks -- Coker and Palmer Investment Securities Inc. -- Analyst

Great. And just one more. You mentioned the sort of being surprised at the interest you saw on the non-operated side, and I have also been surprised by sort of the transactions that have happened non-op in the Bakken. And I was wondering, looks like you're going to get, arguably, what is a pretty nice premium for your non-op position out there.

And from the standpoint of you looking to consolidate or add acreage or whatever, what's kind of your appetite for similar type transactions, small deals, maybe bolt-on or working interest deals at a premium right now? Do you think this particular price environment is one where you'd be sort of willing to take a look at that? Or you still sticking as conservative a view historically have been?

Bob Watson -- Chief Executive Officer

You know us, Noel. We're pretty conservative. I certainly can see this environment stretching any. And I think most people are realizing that maybe they stretched too much in the past and they've brought that stretch in quite a bit and that might be one of the reasons you're seeing virtually no M&A activity.

Operator

Our next question comes from Joe Allman with Baird.

Joe Allman -- Robert W. Baird and Company -- Analyst

I'm sorry, I missed the first few minutes of your call. But my read of your press release is that you're a lot less optimistic about executing a large Bakken asset sale than you were previously. Is that a fair assessment?

Bob Watson -- Chief Executive Officer

Yes. Obviously, discussions are still ongoing. I think I would have to be more optimistic about dropping down a non-op interest at a nice price today than selling the whole package at a nice price. But you never know.

I mean we have certainly not closed the door on anybody. It's an unusual market out there as everybody's finding out, but we're going to keep at it and see what happens.

Joe Allman -- Robert W. Baird and Company -- Analyst

OK. That's helpful. And then, Bob, what's plan B? Is plan B just to hold on to it? Or do you have any other ideas, maybe kind of doing a joint venture or something?

Bob Watson -- Chief Executive Officer

We've got all those things on the table. They're being evaluated by our financial advisors. So I don't take anything for granted, one way or the other. We're going to do whatever is best for the shareholders.

I would say that generating a good chunk of cash flow is never a bad thing. So we're going to continue operating the Bakken as if it was our crown jewel, which is what it is. And if something comes along that meets our value expectations, we'll execute on it.

Joe Allman -- Robert W. Baird and Company -- Analyst

Gotcha. And Bob, what do you think is preventing these deals from getting done? So, like, the Eagle Ford, I know you said there's some movement potentially there, but that hasn't gotten done. You've got very good quality Bakken assets and it doesn't sound like -- it sounds like there is some risk that's not to get done. So in your assessment, what's the reason for not being able to bring these across the finish line?

Bob Watson -- Chief Executive Officer

Well, and I know you looked at the Pioneer Eagle Ford deal that was announced this morning, I think that is pure testimony to the market that's out there today. They sold a major asset for $25 million up front and $450 million in contingency payments. I think that speaks to the fact that there just isn't any capital out there for people to use to make big acquisitions. Private equity is kind of a lock job.

They are stuck in a lot of investments, they have no exit. Obviously, the capital markets are not available. So unless somebody has a big package of money, they're not going to be in the acquisition game. And since they know if they have a big package of money, they don't have much competition, it's difficult for them to screw up their courage and pay a top price.

Joe Allman -- Robert W. Baird and Company -- Analyst

OK. That's helpful. And just last thing on the gas situation in the Delaware Basin. Couple of things.

One, is it affecting pretty much all of your wells? Because it seems as some of the wells are able to flow gas with little problem. And then also, how much gas are you flaring right now? And then is this issue kind of a -- is a localized issue for you?

Bob Watson -- Chief Executive Officer

It's not localized for the industry. It's basinwide. We're currently flaring -- we've got about 4 million a day off the Creosote pad, don't we? Plus -- and that's just because the Coyanosa plant is down for maintenance. When it goes back on, we'll be flaring very little gas.

So we do have an outlet for our gas in the Waha hub area. What we don't have any control over is pricing and Waha pricing is a big negative, as you know. So we're selling the gas as opposed to flaring it because -- or delivering the gas as opposed to flaring it because at least in the Wolfcamp and Bone Springs, we're recovering liquids and so we're making money off the liquids. And so far, that's more than what we're paying to get rid of the gas.

So it's still positive cash coming in the door, and we anticipate that continuing. Now on our dry gas wells, our deep gas wells, they don't make any liquids to speak of, so we didn't have that offset. So it just made all the sense in the world just to shove that in and wait for better prices before -- the gas isn't going anywhere. It's good, long-term gas, and we can turn it off and turn it back on, on a moment's notice.

So that is not an issue. It just turned out to be the prudent thing to do even though it has a negative impact on our production guidance.

Operator

Our next question comes from Ron Mills with Johnson Rice.

Ron Mills -- Johnson Rice -- Analyst

Just a question on -- you talked a little bit about production versus guidance and a little bit about the cadence. I want to dig a little bit into the cadence. And I know you have a couple of wells coming on kind of in June, some in July, some in September, I think, November if I read the press release right. When you think about the peaks of turning wells online versus your corporate decline rate, is it fair to infer from your comments that you think that as we look through 2019 that your production kind of quarter to quarter will be able to hold around these levels, if not slightly increase? Or how should we think about the cadence?

Bob Watson -- Chief Executive Officer

Well, the cadence is exactly as you say. We expect it to slow with steady growth. There might be some spikes here and there when we put a pad on. We've got a four-well pad up in the Bakken that'll go on in June, all at once.

We've got a two-well pad in the Delaware that'll go on early July, all at once. And then another two-well pad.

Steve Harris -- Chief Financial Officer

October.

Bob Watson -- Chief Executive Officer

October, for the Greasewood. In October. So there'll be spikes during those months, but I think when you average it over the quarter that they are in, it averages out very nicely. And then on depending on weather mainly, the six wells that we have -- that we're drilling right now in the Jore Fed, they get finished in time.

We certainly have the opportunity to frac them before winter weather comes in and we could put them on before year-end. In all probability, however, those wells will probably be kicked into May. And at that time, we'll have another six-well pad ready to bring on. So next May of 2020, we'll have 12 Bakken wells coming online and those are roughly 75% wells, so that would be about eight to nine net wells.

And if you look at our normal rate that we've achieved over the last several years, 1,500 barrels a day per well, that's a big slug of production coming on in the summer of 2020. So there is a huge spike then, but when you average it over the year, it should still show growth year over year with just putting those 12 wells on.

Ron Mills -- Johnson Rice -- Analyst

OK. And then I think you referenced in the press release in the Delaware that once you finish drilling, what you have under way now, you're going to release that rig. You're going to keep, it sounds like, the Raven Rig drilling up in the Williston for the time being. If we think about, over the course of the next 12 to 18 months, how would you picture your activity kind of Williston versus Delaware?

Bob Watson -- Chief Executive Officer

The Delaware is going to be -- the second half of the Delaware other than the wells that we just talked about coming online is going to be directed toward production optimization, maybe putting in fieldwide gas lift just to be more efficient, to save money. And then sometimes toward the end of this year, early next year, we pick up another -- pick up a rig in the Delaware. We still have some wells to drill on outlying leases just to prove up, if you will, although, we think it's already proven, everything that we have. We've probably got another one and a half years to drill in the Delaware before we have to even think about coming in and offsetting a parent well.

So I think that -- it just so happens that things are falling in place very well for us, budget-wise and production-wise, to where this schedule works on slow steady growth, yet still generating free cash flow year over year.

Ron Mills -- Johnson Rice -- Analyst

OK. And then just on the H2S, I guess, one other question. You ended up having to repair the preexisting wells. When you look around, do you think this is -- you think you have incremental repairs? Or have you already repaired the wells where you've seen kind of the higher concentration of H2S and that you seem to be in a better position going forward?

Bob Watson -- Chief Executive Officer

I would say all of our early wells where we're susceptible to them have been -- have had failures and have been fixed. So hopefully, that issue is behind us. And there are certainly no guarantees, you could still have a tubular figure here or there. But when you cement them top to bottom, you certainly reduce the risk of a casing failure, which is the most expensive ones to fix.

Tubing failure is no big deal, just trip the pipe, replace the tubing and go back to work. We might still have some of that. But I don't think it's going to be the magnitude that we experienced in the first quarter.

Operator

And I'm not showing any further questions at this time, I'd like to turn the call back over to our host.

Steve Harris -- Chief Financial Officer

Thanks. We appreciate everyone's participation in the earnings call today. As I mentioned at the start of the call, a webcast will be available on our website and a transcript will be posted in approximately 24 hours. So with that, thanks, everyone, and have a great day.

Operator

[Operator signoff]

Duration: 31 minutes

Call participants:

Steve Harris -- Chief Financial Officer

Bob Watson -- Chief Executive Officer

John Aschenbeck -- President and Chief Executive Officer

Michael Scialla -- Stifel Financial Corp. -- Analyst

Kenny Johnson -- Vice President of Operations

Noel Parks -- Coker and Palmer Investment Securities Inc. -- Analyst

Joe Allman -- Robert W. Baird and Company -- Analyst

Ron Mills -- Johnson Rice -- Analyst

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