Abraxas Petroleum Corporation
Q1 2016 Earnings Call Transcript

Published: 11 May 2016

[Operator:]

Good day ladies and gentlemen, and welcome to the Q1 2016 Abraxas Petroleum Corporation Earnings Conference Call. My name is Ashley and I will be your operator for today. At this time, all participants are in listen-only mode. And later we will conduct a question-and-answer session. [Operator Instructions] I would now like to turn the call over to your host for today, Geoff King, VP and CFO. Please proceed.

[Geoffrey King:]

Thank you, Ashley, and welcome to the Abraxas Petroleum first quarter 2016 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 Exploration available to answer any questions that you may have after Bob’s overview. As a reminder, today’s call is being taped and the 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 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. I’d encourage everyone to review the risk factors contained in these filings and in our press releases. I’ll now turn the call over to Bob.

[Robert Watson:]

Thanks, Geoff, and good morning. Continuing on our previous theme of making Abraxas better in West Texas and specifically in the Delaware Basin, we have suspended our previously announced sales process with a number of entities still interested. And with the knowledge gained from a more in-depth geologic and engineering analysis of our lands, and I remind you, we own about 5,227 net acres out of a gross 8,092 acres in Ward and Reeves County. And especially with recent offsetting well results, we have decided the highest value to our shareholders is to develop these lands ourselves. More detailed plans on this project could be forthcoming as early as next week. But needless to say, we are very excited about this project and what it could mean for Abraxas going forward. In South Texas, we’ve been talking about a joint venture to test our theory that the Austin Chalk is a commercial reservoir on our Jourdanton area leases in a similar geologic setting as to what is being developed in Karnes County by BlackBrush and EOG. Along those lines you might want to check out the EOG press release of last week in regards to their Austin Chalk results. The joint venture agreement is agonizingly close to being done. But we are currently building location for our Bulls Eye number 101H. The rig is actually stacked on our adjoining Cat Eyes location, and we expect to be drilling our first Austin Chalk well with a 6,300 foot lateral in late May using predominantly someone else’s money. With success, this could lead to 100 plus or minus gross, 551 plus or minus net locations on our leases, at this point most of which are held by production. In the Bakken, with the onset of better weather, somewhat higher oil prices, and still conveniently low service costs, we are preparing our six drilled, but uncompleted wells on our eventual 10-well Stenehjem Super Pad to be possibly fracked midsummer with a targeted production date sometime during the third quarter. Once the wells are prepared for frac with tieback casing strings and wellheads, et cetera, the final investment decision can be made with knowledge of then current conditions. I would encourage you to look at our recent corporate presentation on our website. You will find data that shows the results for our 30 completed Bakken and Three Forks wells in the North Fork area that we’ve completed to-date. And you will see that our wells have averaged plus or minus about 1,000 barrels a day of equivalents for a 30-day average. On the Stenehjem Super Pad, we own a 78% working interest, and that’s a plus or minus 63% net revenue interest. So you can do the math, I’ll lead you. Six wealth times 0.63 net revenue interest times 1,000 BOEs, we could be looking at about 3,800 barrels a day of net new production in the third quarter. The last thing I want to mention before questions is Abraxas’s liquidity. We are concerned about liquidity, as every E&P company should be. But we’re not as concerned as the Street appears to be for the following reasons. Number one, we are generating free cash flow. Even with a few more capital projects ahead, we will continue to generate free cash flow for this year. In the first quarter, we improved our working capital position by about $10 million to where our working capital deficit is now very manageable. And we actually paid down our borrowings $1 million last week with excess cash. Number two, we have a number of noncore asset sales in the works, a small one of which – it’s about $2.5 million to $2.8 million, is scheduled to close tomorrow. Our asset sale project should be considered as a number of singles with maybe a double or two thrown in for good measure, but no home runs. We don’t need it, don’t expect it, and all proceeds from this project will be used to paying down the borrowings under our line of credit. Number three, the recent increase in oil prices from – compared to our – what were prevalent at our spring redetermination date, if they stay flat where they are today, we should see an increase in our borrowing base at our next redetermination date around October 1. And finally, number four, we are in total control of our financial and operating destiny. We operate virtually everything we do. Most of our leases, by far the majority of – vast majority of our leases are held by production. So we have the ability to turn off CapEx as fast as we turn it on with no loss of value. And before questions, I’ll leave you with this thought. Our team are all shareholders, and in most cases, our shares represent a substantial portion of our net worth. And I can assure you, we are feeling your pain, but I can also assure you that we are doing our very best to make Abraxas better. And with that, we’ll open up for questions.

[Operator:]

[Operator Instructions] Your first question comes from the line of Steve Berman of Canaccord. Please proceed.

[Steve Berman:]

Thanks. Good morning, Bob, good morning, Geoff.

[Robert Watson:]

Hi, Steve.

[Steve Berman:]

I know you said it’s – you’re using other people’s money for, at least, part of the Austin Chalk. What would the – do you expect the cost of that well to be?

[Robert Watson:]

We’re estimating it to be about $6 million, and our exposure will be less than $1 million. And actually our cash exposure goes down to virtually nothing as we’ll be using tubulars out of our inventory that we’ve already bought and paid for.

[Steve Berman:]

Okay, thanks. And then up to the Bakken, when you decide to get active there again after the six-well pad, what’s next? The other four wells on that pad, most likely or maybe something else up there, just want to kind of looking forward here a little bit?

[Robert Watson:]

No, our Raven Rig #1 is actually rigged up on our seventh well on that pad that Derrick is in the air. It’s undergoing some very good maintenance, very well needed maintenance. The rig has been running as you know, 24/7 for about four years. Our retained employees have been working on it during the winter months, doing some upgrades as well as maintenance. So that rig will be ready to go on a fairly short notice and we expect it to be even more efficient than it’s ever been in the past.

[Steve Berman:]

Excellent, all right. Thanks Bob.

[Robert Watson:]

Thanks Steve.

[Operator:]

Your next question comes from the line of John Aschenbeck of Seaport Global. Please proceed.

[John Aschenbeck:]

Hey, good morning.

[Robert Watson:]

Hi, John.

[John Aschenbeck:]

Bob, your comments in regard to the Delaware Basin, I found interesting, to kick off that development program there, are you guys potentially considering a JV or perhaps another source of capital?

[Robert Watson:]

We’re looking at all our options. We think we have a number of them to look at, but our goal would be to – try to consolidate interests. As you can see from our gross and net, there is some outside ownership that maybe we would like to consolidate before we kick off our drilling program. But hopefully we would have a way to not only consolidate the interest, but drill a couple of wells before year-end.

[John Aschenbeck:]

All right, good deal. And then a follow-up on that, what are your thoughts of potentially increasing your exposure in the area, perhaps picking up additional leaseholds?

[Robert Watson:]

Outside of our operated leases that we have non-operated interest on, they’re an obvious target for us. The area has been pretty much leased up around us, which was also one of the contributing factors to us deciding not to pursue a sales effort, because some pretty knowledgeable players have bought leases offsetting us. So we don’t know whether we have a lot to go after other than the non-op owners on our existing leases.

[John Aschenbeck:]

Got it; okay. One more if I could, in regards to 2016, you laid out a nice trajectory there on the production side with the Stenehjem is coming on. Let’s just say that the current strip plays out. You bring the Stenehjem on mid-year and you mentioned generating free cash flow earlier. What do you think ballpark figure remainder of the year free cash flow looks like?

[Robert Watson:]

Well, we haven’t guided to that and I guess you could just do the math on the production. We’ve announced our LOEs, which are lower than what consensus was. I might make a comment that March versus February, both of which are in that first-quarter number. March was even better than February, so on a lifting cost per barrel. So I feel comfortable that we’ve done a very good job. Our operations team has done a very good job of reducing expenses wherever possible, and I think we’re in a position to hold or even make that a little bit better going forward. So if you take the projected production that we just talked about on our base, and we did announce yesterday that second quarter will be down a bit as we shut in some wells potentially for the offset fracs. And normal declines, because we haven’t added any new production, so if you make that calculation and add the expected production going forward with the normal Bakken decline. I think you can come up with a pretty good EBITDA number. There won’t be any surprises going forward on our G&A, so that should stay about the same if not get better. First- quarter G&A is impacted by audit and tax computation costs, so we expect second quarter to be a little bit better. So without doing the math myself, I throw that back at you and let you come up with a number; and we’d probably be very comfortable with it.

[John Aschenbeck:]

Got it. That’s all very helpful. Thanks Bob.

[Robert Watson:]

You bet.

[Operator:]

Your next question comes from the line of Derrick Whitfield of GMP Securities. Please proceed.

[Derrick Whitfield:]

Good morning and thanks for taking my call.

[Robert Watson:]

Hi, Derrick.

[Derrick Whitfield:]

So staying on the Bakken, could you remind me of what level of risking banks apply to PDNP wells for their borrowing base calculations?

[Robert Watson:]

It’s about 25%. So as those wells go on production, it goes up to 65%. That’s kind of one of the hidden increases that we have in our back pocket. If we do go forward and complete those wells, it’s a pretty good boost to our borrowing base next redetermination.

[Derrick Whitfield:]

That makes sense. And then thinking about the costs in your PDP, PDNP calculations for well costs, what was that assumption? And then where do you think the actual completed well costs will land once you guys complete those wells?

[Robert Watson:]

Well, we’ve got them budgeted for $3 million apiece, but I’ll bet pretty good amount of money that we’ll beat that number substantially.

[Derrick Whitfield:]

Very helpful, and then last question for me is looking at your realizations, specifically gas and NGL prices for the quarter were very depressed. Any view on how those differentials in NGL pricing as a percentage of WTI projects for the balance of the year?

[Robert Watson:]

Well, I wish I knew, I could be a billionaire now. But the biggest thing that impacts us is our gas and NGLs in the Bakken. We’re subject to a gas contract, and it’s the only one we have available to our area that basically calls for a $2.50 minimum to the purchaser. So until the combination of gas prices and NGL prices and our NGL cut gets above that number, we’re basically getting nothing for our gas and NGLs. So that greatly increases the differential that you’re seeing in both counts. One positive thing is that the gas and NGLs we’re getting out of our Permian properties have been negatively impacted by a rather consistent outage in our gathering system – our third-party gathering system and gas plant. They continue to tell us that they’re improving and that there will be better on-time performance going forward. We’ve yet to see it. But if that happens, then you’re going to see a higher percentage of our gas production coming from the Permian, which are pretty much closer to market costs and would consequently improve our overall corporate gas differential going forward.

[Derrick Whitfield:]

Very helpful, thanks for taking my question.

[Robert Watson:]

You bet, Derrick.

[Operator:]

Your next question comes from the line of Will Green with Stephens. Please proceed.

[Matt Beeby:]

Good morning. This is Matt Beeby for Will Green.

[Robert Watson:]

Hi Matt.

[Matt Beeby:]

Good morning. So Bob, you talked about the rig and the Bakken pretty much ready to go. What are the factors that you’re considering, be it price or takeaway capacity or whatnot to really get that rig moving again is it more of a function of where you are on the balance sheet?

[Robert Watson:]

I think maybe all of the above, although we have a very limited concerns about takeaway capacity now. Our gas gathering system has ample capacity to handle our increased production. All our tank batteries are on oil pipeline that have ample capacity, so takeaway is not an issue. The final decision is going to be commodity prices and liquidity. And I don’t have an exact number of what that’s going to be, but we’ll just have to make that decision when the time comes.

[Matt Beeby:]

Okay, thanks. Another one I’ve got on the hedges. You’ve recently been monetizing hedges, I think protecting some of your out-year production. We’ve seen some other E&P companies hedging, where oil is today. Is there a point here where it might make sense that you might actually increase your hedges for the near-term?

[Robert Watson:]

Well, under our bank agreement, Matt, we can only hedge 90% of the PDP or the projected PDP on the last reserve report we presented to the bank. And we are maxed out now in 2016 and 2017. We have a little room in 2018, not much. So until we bring new production on and supply them with a new PDP reserve report, we are pretty much precluded from adding additional hedges. Now that being said, if we do go forward and frac these wells and our mid-year reserve report shows a higher PDP rate, we would certainly look favorably toward locking in some higher prices at that point just to protect our cash flows.

[Matt Beeby:]

All right. Thanks, Bob. Sounds good.

[Robert Watson:]

You bet.

[Operator:]

Your next question comes from the line of Neal Dingmann with SunTrust. Please proceed.

[Neal Dingmann:]

Good morning, Bob and Geoff.

[Robert Watson:]

Good morning, Neal.

[Neal Dingmann:]

Hey, Bob, I’m trying to figure, I know, it’s pretty minimal. What are you all assuming for the remainder of the year just on non-op CapEx? I know, I think on that slide around your North Fork, you mentioned, I think there’s what, one non-op well waiting on completion there. As you talk to your partners, what are you thinking CapEx-wise?

[Robert Watson:]

Well, that particular partner is XTO, so it’s hard to get a straight answer out of them. But what we are projecting is – and we own a 36% interest in that well. We’re projecting that that well gets fracked early winter this year and comes online January of next year. And that is the only non-op operation that we have any inkling might get done this year.

[Neal Dingmann:]

Got it. Got it, okay. And then I think on that – around that same North Fork and just overall, did you say – how many DUCs do you have, I think, on just that area? What – do you have six, is that right around the North Fork?

[Robert Watson:]

Six operated and then the one XTO-operated, so seven.

[Neal Dingmann:]

Okay, okay. And is that the only place – is that the only DUCs that you all are sitting on?

[Robert Watson:]

That’s the only ones.

[Neal Dingmann:]

Okay. And then lastly, just also staying in the Bakken, just what are you guys thinking when downspacing? I think what was it 660, I think you were down to most recently? Is that what you will stay with, or what’s your thoughts about that, Bob?

[Robert Watson:]

We’re probably going to stay there. We’ve done an in-depth study on frac hits and we feel pretty comfortable that we are fracking all the rock in between our wells. So that seems to be the optimal spacing for us.

[Neal Dingmann:]

Very good. Thank you.

[Robert Watson:]

Okay. Thanks, Neal.

[Operator:]

[Operator Instructions] Your next question comes from the line of Welles Fitzpatrick with Johnson Rice. Please proceed.

[Welles Fitzpatrick:]

Hey, guys, good morning.

[Robert Watson:]

Good morning, Welles.

[Welles Fitzpatrick:]

You guys have talked in the past about the Wolf A and the Bone being sort of the primary objectives in you all’s footprint on the Delaware. Do you know offhand what those Jagged Peak offset wells were drilled into? And do you have any thoughts as to what might be your first target?

[Robert Watson:]

They appear to be right at the Bone – third Bone Springs Wolfcamp A, what you call it? The interface.

[Lee Billingsley:]

Interface, yes.

[Robert Watson:]

Okay. Yes, top of the Wolfcamp base of the Bone Springs – third Bone Springs. And our thickness in both of those zones is relatively the same as further out into the basin. And most of the activity that we have seen –and we’ve done an extensive study now – the very vast majority of all the wells drilled out in the Texas part of the Delaware are in the Wolfcamp A Bone Springs – third Bone Springs area.

[Welles Fitzpatrick:]

Okay, perfect. And you guys, I mean, obviously it’s early times, but maybe you got one from the study

[Robert Watson:]

We’re AFE in the wells at a little bit less than $6 million, and that would be for roughly 5,000 foot lateral. Our leases – some of our leases might be conducive to 2-mile laterals, which would cost probably $7 million to $8 million. But we come up with an average recovery of about 15 barrels per foot.

[Lee Billingsley:]

First six months

[Robert Watson:]

First six months 15 barrels per foot, thanks. Lee just corrected me, yes, that’s pretty small number. But that’s kind of what we’re using in our economics. And we know now why people are so high on that area of the Delaware, is the economics are very compelling.

[Welles Fitzpatrick:]

Okay, that’s perfect. Yes, it seems like a great call. Thanks so much.

[Robert Watson:]

Okay.

[Operator:]

And there are no more questions in queue. Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a great day.