Abraxas Petroleum Corporation
Q1 2019 Earnings Call Transcript

Published: 8 May 2019

[Operator:]

Good day, ladies and gentlemen, and welcome to the Q1 2019 Abraxas Petroleum Corporation Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] I would now like to introduce your host for this conference call, Mr. Steve Harris, CFO; and Bob Watson, CEO. You may begin.

[Steven Harris:]

Thank you, Kevin, and welcome everyone to Abraxas Petroleum's first quarter 2019 earnings call. With me I've got Bob Watson, President and CEO. In addition, we have our Chief Accounting Officer and VP 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. With that, I'd like to turn the call over to Bob.

[Bob Watson:]

Thanks, Steve, and good afternoon. Our lease operating expenses for the quarter were high for a number of reasons, and not just bad weather. Only in the Delaware play, Abraxas did what most operators did and that was to not anticipate the levels of hydrogen sulfide gas that would be encountered in the Wolfcamp and the Bone Springs. Sweet processing plants were built and high tensile strength tubulars were running well 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 two 100 to 1% 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 an assisted necessity in this play due to the high liquids content of the gas, and we are blessed with legacy acreage dedication to our solid [ph] gas system. Least 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 expensive 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 are not having to pay to sell, actually it's hard to say, you're selling the gas when you 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 for 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've 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% owned 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 1 recently commenced operations on our six-well Jore Fed Extension pad, in which we own an approximate 75% working interest. The slowdown 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. Well, on the Bakken in the first-half slowdown has hopefully worked to our benefit and getting us closer to better gas market for the new wells when they're completed. The timing of the completion of the six-well Jore pad will depend on weather, oil prices, and gas takeaway that 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'll 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 North Dakota this fall, all of which should create slow and steady production growth for 2019 and 2020 and still generate free cash flow. With that, I'll open it for questions.

[Operator:]

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

[John Aschenbeck:]

Good afternoon Bob and Steve, and thanks for taking my questions.

[Bob Watson:]

Good morning, John, or afternoon.

[John Aschenbeck:]

And 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 -- excuse me, was curious how sizable are -- are the remainder of your non-op assets, just say in comparison to the ones you just monetized them, I'm just really trying to get a feel for how meaningful those potential monetizations could be? Thanks.

[Bob Watson:]

Well, it would basically be a percentage of our operated assets. And so, it could be any size, but I don't want…

[John Aschenbeck:]

Got it.

[Bob Watson:]

-- any more than that, but it would be assets that we continue to operate. We just sell down our interest.

[John Aschenbeck:]

Okay. I hear you. Okay. Good deal. Thanks. Okay. Yes. That's helpful. And then yes, just for my second one, I 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 to say at the beginning of the year after the - the borrowing base increase and then this asset sale certainly helps too. But just thinking, I suppose if you couldn't ultimately get the bid you're looking for on the remainder of your, on your assets with pro forma liquidity around $55 just, 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? Thanks.

[Bob Watson:]

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 outspent obviously in the first quarter and we'll have a slight outspend in the second quarter but that was planned. And then with just a drilling rig running in the third quarters 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:]

Okay got it. And a follow-up there if you don't mind could you just remind us in terms of maybe potential asset monetization candidates just could you remind me how many acres do you have mineral acres do you have in the Delaware what is the opportunity set look like there and then same with your water infrastructure?

[Bob Watson:]

We own a 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 could 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 royalty 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.

[John Aschenbeck:]

Okay, great. I appreciate all the detail. Thanks, Bob.

[Bob Watson:]

Okay, John.

[Operator:]

Our next question comes from Michael Scialla with Stifel.

[Michael Scialla:]

Yes. Hi, Bob. Hi, Steve.

[Bob Watson:]

Hey, Mike.

[Michael Scialla:]

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:]

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. That's the -- excuse me, that's the main difference. Obviously, we're taking extra precaution with our surface facilities to make sure there's 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 can also planned as 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 just - we're very pleased to be in the position we're in as opposed to some operators that don't have access to the gas sour system and having to treat wells on the lease which can become extremely expensive.

[Michael Scialla:]

Got you. Any estimate on what the incremental cost for you might be with the cementing additional spending required and then lower strength tubulars?

[Bob Watson:]

So, Kenny Johnson saying 100 grant a well?

[Kenny Johnson:]

Yes, [indiscernible] generate, but the flips that were saving on the frag due to the less friction and less horsepower.

[Bob Watson:]

Okay.

[Kenny Johnson:]

It's bigger too at the same time.

[Bob Watson:]

Yes, we went bigger pipe, lower stress tubular. So we're saving money on hydraulic horsepower on the fracs which kind of offset some of the increased cost of getting 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:]

Got it. Okay. And then curious on I know you said you were sticking with the plan for this year despite the higher oil prices. You had some issues that your first quarter production was strong, but realize there's some unpredictability with third-party gas processing constraints here, but any updated thoughts on, on your production for the year that 10,500 to 11,500 BOE a day still feel like a good numbers that need to be adjusted?

[Bob Watson:]

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 that would impacted and 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.

[Michael Scialla:]

Very good, thank you.

[Bob Watson:]

Thanks.

[Operator:]

Our next question comes from Noel Parks with Coker & Palmer.

[Noel Parks:]

Hey. Good afternoon.

[Bob Watson:]

Good afternoon, Noel.

[Noel Parks:]

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

[Bob Watson:]

I don't think there's anything new that since 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 for the last -- 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:]

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

[Bob Watson:]

We have pretty much concluded our study of our down spacing tests. And as I alluded to last call, it looks like the 900 foot spacing 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 down spacing test nearby that's underway. 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 a 1,000 foot apart in the same zone and that would -- we've published before 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 is 24 wells a year for two rigs left a lot of inventory.

[Noel Parks:]

Great, great. And I was thinking as you were going through reviewing different bids in the Bakken, and matter of fact 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 well, just wondering if people are baking in a significant service cost assumptions.

[Bob Watson:]

We're assuming oil prices stay flat and service costs stay flat. Obviously if oil 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 guess into the future might be a fool's errand. But we're comfortable leaving costs flat as well as oil prices.

[Noel Parks:]

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

[Bob Watson:]

You know, as now we're pretty conservative. I certainly can't see this environment we 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.

[Noel Parks:]

Got you. Okay. Thanks a lot. That's all from me.

[Bob Watson:]

Thanks, Noel.

[Operator:]

Our next question comes from Joe Allman with Baird.

[Joe Allman:]

Thank you. Hey, Bob and Steve.

[Bob Watson:]

Hey, Joe.

[Joe Allman:]

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:]

Yes. Obviously, if 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 is finding out, but we're going to keep at it and see what happens.

[Joe Allman:]

Okay. That's helpful. And then -- and Bob, what's the Plan B, is Plan B is just to hold on to it or do you have any other ideas, maybe kind of doing a drilling joint venture or something?

[Bob Watson:]

We've got all those things on the table. They're being evaluated by our financial advisers. So, don't take anything for granted one way or the other. You know, we're going to do whatever's 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 something comes along that meets our value expectations, we'll execute on it.

[Joe Allman:]

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

[Bob Watson:]

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 upfront 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 lockjaw, they're stuck in a lot of investments, that 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 pay a top price.

[Joe Allman:]

Okay. That's helpful. And just lastly on the gas situation in the Delaware Basin, a couple of things, one, is it affecting pretty much all of your wells, because it seems, seems that some of the wells were able to flow gas with little problem and then also how much gas are you flaring right now? And then -- and is this issue kind of a is a localized issue for you?

[Bob Watson:]

Well, it's not localized for the industry, it's basin-wide. 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 -- 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 are 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 in 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 shut that in and wait for better prices before that gas isn't going anywhere. It's good long-term gas and we can turn above and turn back on a moment's notice. So that is not an issue, it just turns out to be the prudent thing to do even though it has a negative impact on our production guidance.

[Joe Allman:]

Got it. Okay, that's all very helpful. Thank you, guys.

[Bob Watson:]

Thanks, Joe.

[Operator:]

Our next question comes from Ron Mills with Johnson Rice.

[Ron Mills:]

Good afternoon, Bob. Hey just a -- the 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 the September, I think November if I read the press release right. We need to think about the pace 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:]

Now, the cadence is exactly as you say, we expect it to show slow, but 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 will go on in June all at once. We've got a two-well pad in the Delaware that will go on early July all at once. And then another two-well pad, October for the greasewood, in October. So there will be spikes during those months, but I think when you average it over the quarter that they're in, it averages out very nicely. And then depending on whether mainly the six wells that we have - that we're drilling right now on the Jore pad, if 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 8 to 9 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:]

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

[Bob Watson:]

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 field wide gas lift just to be more efficient to save money. And then sometime towards 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 year and a half to drill in the Delaware before we have to even think about coming in and offsetting apparent 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:]

Okay. And then just on the H2S, I guess one other question you ended up having repair with three existing wells when you look around, do you think this is, you think you have incremental repairs or have you, have you already repaired the wells where you've seen kind of the higher concentration of H2S and in you seem to be in a better position going forward?

[Bob Watson:]

Yes. I would say all of our early wells where we have -- we were susceptible to them have had failures and have been fixed. So hopefully that issue is behind us. There is certainly no guarantees one you could still have a tubular failure here or there, but when you cement them top to bottom you certainly reduced the risk of a casing failure which is the most expensive ones to fix. Tubing failures 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.

[Ron Mills:]

All right. Great, thanks, Bob.

[Bob Watson:]

Thanks, Ron.

[Operator:]

And I am not showing any further questions at this time. I'd like to turn the call back over to our host for closing remarks.

[Steven Harris:]

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

[Operator:]

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect, and have a wonderful day.