Abraxas Petroleum Corporation
Q1 2014 Earnings Call Transcript

Published: 8 May 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to the First Quarter 2014 Abraxas Petroleum Corporation's Earnings Conference Call. My name is Kim, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Geoff King, Vice President and Chief Financial Officer. Please proceed.

[Geoffrey R. King:]

Thank you, Kim, and welcome to the Abraxas Petroleum First Quarter 2014 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 Land, Operations, Engineering 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 a webcast replay will be available immediately after the conclusion of the call. 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. I would encourage everyone to review the risk factors contained in these filings and in our press releases. I will now turn the call over to Bob.

[Robert L. G. Watson:]

Thanks, Geoff, and good morning. We're very pleased to announce that we beat our first quarter guidance on all fronts and -- resulting in the numbers that are what they are. I'll give you a little bit of color on some of those and I promise you this will be the last time you hear me complain about winter weather in North Dakota, at least this year. But despite the weather, January production was about 4,073 barrels a day, February fell down to 3,639, then March rebounded to 4,802, for the average that we announced of 4,189 barrels of equivalents per day. Now we've guided second quarter to 4,600 to 4,750. The impact of the increase in March was basically from 3 Eagle Ford wells, all of which we own 100% working interest in. Our Blue Eagles well at Jourdanton continues to perform above our type curve. The Snake Eyes well came on late in the quarter and it, too, is performing well above our type curves. The Dutch 2H long lateral, down in McMullen County, came on about mid-quarter and had a 30-day rate of almost 1,100 Boes per day. That included about 28,000 barrels of oil by itself. Both of which were well above our expectations. In the Eagle Ford, our long-term growth going forward currently is in the Jourdanton area and Atascosa County, where we now have 100% working interest in about 7,200 acres. We found out now the 4 wells that we drilled recently and -- plus the fifth well that we drilled 2 or 3 years ago have all performed differently. And it's way too early to tell what the average well in this play is going to look like. The last 2 wells, the Spanish Eyes and Eagle Eyes, are making a little less oil. Same total fluid, however, and the same pressure. The oil is a little heavier, about 27 gravity, opposed to the low 30s on the first 2 wells, but you really can't tell what they're going to do until we get them on pump. This part of the Eagle Ford is shallower. It's lower pressure. The oil is heavier. So they won't flow as long as wells that are deeper in the basin. We ran submersible pumps on the first 2 wells and both of them showed a very favorable impact. We tried to run a sub-pump on the Spanish well this week, found the pressure is still too high and with the high cost to try to kill the well and possible reservoir damage, we decided to continue to let it flow on its own until it lays down before we run the pump. Obviously, the Eagle Eyes is just now in production so it's continuing to flow and we'll be putting it on pump when it lays down, probably several weeks from now. When the rig got through with the Eagle Eyes, we moved it south back into McMullen County to start drilling the Dutch 1H, which is the second well on the pad. This necessitated shutting in the 2H well. The 1H is, this morning, currently drilling below 17,500 feet toward a target of 19,000 feet, which would be about a 9,000-foot lateral. The good news is we stayed in the zone almost the whole lateral, so don't expect any surprises with this one. The rig will move back to Jourdanton after the Dutch well to drill the Ribeye, which is -- will be our first long lateral well in Jourdanton. It will be about a 7,000-foot lateral. Up in the Bakken, during the quarter we finished drilling 3 new wells. All of them 76% working interest on the 4-well Jore Federal East pad. Drilling was finished in January. We've learned from experience that we don't want to attempt frac jobs during extremely cold weather, so we decided to postpone these fracs until warmer weather. Then we've had a delay because of a lost sand train but, luckily, we're now underway. As of this morning, we're about 1/3 done, 30 successful stages planned out of 99. After the rig -- our company-owned rig got finished drilling on the Jore East pad, we moved the -- to the Ravin West pad for a 4-well Middle Bakken downspacing pilot, where the laterals will be 660 feet apart. We've got a 50% working interest, plus or minus, in the Ravin West pad. We've already TD-ed one lateral. We'll be running liner on it hopefully today and tomorrow. We'll have 3 more to go. As you know, this is a walking rig, so the intermediate hole down and through and including the curves have already been drilled on those 3, so it's just a matter of drilling the laterals now on the last 3. I might add, as a continuation of the efficiency gain from our own drilling rig, this last 10,000-foot lateral, down to 20,700 feet, was drilled in 5 days. So as we continue to gain efficiency, that reduces our costs and increases our rate of return. Hopefully, these wells will be down and cased here shortly and be ready to frac sometime in July. Now let's specifically look back at what we see happening in the second quarter to give you some comfort on the guidance that we've put out. First impact I want to talk about is the shut-ins. In the Eagle Ford, the Dutch 2H was shut in mid-April to accommodate the rig on the Dutch 1H. The surface is only 30 feet away from the wells. So that well will remain shut in until after the 1H is -- the frac is completed. In the Bakken, we had to shut in the Jore 3H, which had been on production almost 2 years or so, on the Jore pad, as well as the Ravin 2 and 3, which also share the same pad, that's currently a 6-well pad, all to accommodate the fracs on the Jore. So these wells were shut in mid-April. The Ravins will come online as soon as the fracs are completed. The Jore 3 will come on when the other 3 wells, the 1, 2 and 4, come on after their fracs are finished and the plugs drilled out. So hopefully, they'll be on -- all on production in the latter part of May. Now the positives. The 2 Jourdanton wells that are still flowing, we expect to put them on pump mid-May or so and hope to see a nice production increase from that. The Dutch 1H frac is scheduled June 1. So both of the Dutch wells should come back on production around mid-June. Keep in mind these are "1,000-barrel of equivalent a day" type wells. Also in the Eagle Ford, our gas processing facility should be in place late May on our Henry lease, on our Dilworth project, also 100% owned. We've got a 19-stage frac scheduled for mid-May, so that we can turn the well on and immediately be selling gas around the 1st of June. Our expectations here are also about "1,000-barrel equivalent per day" type well. In the Bakken, the 3 new Jore wells, as I mentioned earlier, plus the original Jore well, should be on production late May, so as soon as the fracs are complete and the plugs are drilled out. Keep in mind the last 8 wells that we've drilled in this area have all been about in a 1,000-barrel of equivalent 30-day rates. We're drilling in the same rocks, we're using the same geosteering and the same fracs, so hopefully we'll achieve the same results. Those wells -- are we -- a 76% interest in the 3 new wells and the 1 older well would be a nice boost in production for part of the second quarter, anyway. All of this will also be joined to help kick-off the third quarter. The Ribeye well hopefully will be drilled successfully and frac-ed in July, and the 4 Bakken wells and our 660-foot pilot hopefully will be frac-ed in July and be on production for a good portion of the third quarter. Now, I understand there has been some confusion about our CapEx budget. Several months ago, we announced we increased our budget to $125 million. We said at the time it was front-end loaded. We spent about $36 million in the first quarter and we're anticipating, with all this activity, spending about $53 million in the second quarter. But this budget assumes that we drop the Eagle Ford rig at mid-year and, thus, the lower half CapEx budget drops as well to stay within that $125 million limit. Dropping the Eagle Ford rig probably doesn't make sense with the results that we've seen and the greatly expanded inventory. With the backward nature, or backward-dated nature of the crude curve and the time value of money, acceleration moves up our NAV considerably. So in all probability, we hope to keep the Eagle Ford rig. We'll be increasing our budget, we'll be increasing guidance and, all the while, keep in mind that we're going to be managing our debt to equal to or less than 1x our forward 12-month EBITDA. So that's a good summary of what's happening here. We'll open it up for questions.

[Operator:]

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

[Will Green:]

I wonder if we could talk about kind of the standard completion technique you guys are using in the Bakken? It seems like there's been some -- other operators have had some success moving to slick water. Do you guys have any plans to kind of vary what you're doing up there? And maybe if you could just give us a summary of kind of how the standard frac looks for you guys?

[Robert L. G. Watson:]

Yes, I'm going to let Pete Bommer, our VP of Engineering and our frac guru, answer that question because he stays on top of it on a hourly basis, not just a daily basis.

[Peter A. Bommer:]

Yes. We do a bunch of data mining here at Abraxas, looking at what other people do and it's all results-oriented. We just -- we focus on production and rate of return as a bottom line. So the frac world is a combination of applying lots of material but balancing that against cost. So we've looked around the basin at what people do, and there are some folks, starting with Liberty, who applied slick water treatments pretty successfully. We do believe that it's area-dependent. Most of the better Liberty results are in Williams County, north of the river. We're down in McKenzie, down deeper in the basin and we still think that a hybrid-type job, which uses some cross-link gel in the latter portions of the stages, is most effective. We do pump about half of our sand in thin fluid [ph], but then we do cross-link and go to higher concentrations. The -- with a slick-water job, you cannot achieve the proppant concentrations that we achieve. We do think in our region that, that concentration is helpful, it's meaningful. So we've stuck with that pact. The slick water jobs actually, according to my estimate, are more expensive. You use a lot of horsepower. You use a lot of water. You pump about the same amount of sand. So the ticket actually -- the price of the ticket actually increases with slick water and we don't like that so well. But it is certainly a viable approach. There's no question about that. We feel like, where we are in the basin, that the hybrid is still the best way to go.

[Will Green:]

Great. That's great color, I appreciate all that. The other point I wanted to maybe touch on is EOG, I guess, talked about some good results they're seeing in the Turner and Parkman [ph], up near where you guys have acreage in the Powder River. Maybe if you could just expand on that and talk about how that rock differs in their position versus where you guys sit in that kind of area?

[Robert L. G. Watson:]

I would say that our rocks are very similar to EOG's. We're very close to their activity. On our most recent presentation that we 8-K-ed day before yesterday, we have an update on the decline curve or lack thereof on the one well that we drilled into the Turner, near EOG and there's been virtually no decline now over 2, almost 3 years, something like that. So it's extremely good. We've been frustrated that we have not been able to increase our acreage position in this area. We've tried. We've looked at numbers of deals, tried to do numbers of deals. People are pretty proud of the acreage and don't want to give it up. But that doesn't mean it's not valuable. It might be something we can use to trade for an interest in another area that we can have more growth in. Don't know at this point but we're very happy that we own it. We're very happy that EOG has now placed the Turner as one of their primary development zones in the whole company. Doesn't surprise us because we've been monitoring their results offsetting us and they've been pretty impressive.

[Operator:]

Your next question comes from the line of Noel Parks from Ladenburg Thalmann.

[Noel A. Parks:]

I wanted to ask about the acreage at Jourdanton. It looks like the count was up a bit in the last presentation and I just wanted to hear whether those were sort of those hold times you've been expecting all along or new -- different acreage?

[Robert L. G. Watson:]

Pretty much the same thing that we've talked about in the past. We've now solidified those deals to where they're now ours. Do we expect anymore? Are we pretty much done?

[Unknown Executive:]

It's pretty much done.

[Robert L. G. Watson:]

Yes, I think we're pretty much done. We've got plenty. That's a large inventory for a company our size. Buying expensive acreage and putting it into inventory that you're not going to get to for 4 or 5 years really has a negative impact on your rate of return. We are very rate-of-return driven, as you know, so if we're going to buy expensive acreage, we're going to have a rig in there immediately to generate that maximum rate of return. And so we've got plenty of Jourdanton. And we own 100%...

[Noel A. Parks:]

[indiscernible] I'm sorry about that. I just had a similar question on the Bakken and the swap connections [indiscernible] you are hoping to achieve to sort of solidify the position there. Any progress there?

[Robert L. G. Watson:]

I guess maybe a little bit but not a whole lot. We don't have any results to talk about yet but it is still ongoing. We've got a guy that is almost -- his full-time job is to work on those deals. And when you're dealing with big companies, it just takes a long time even if both companies recognize it makes a lot of sense. So that's still work in progress.

[Operator:]

[Operator Instructions] Your next question comes from the line of Mike Scialla from Stifel.

[Michael S. Scialla:]

Wondering if you could talk about the Spanish Eyes and Eagle Eyes, what kind of oil cut you saw there versus the first 2 wells? And you said the total fluids were the same and -- or similar. And I'm wondering, too, did you complete those wells any differently than the first 2?

[Robert L. G. Watson:]

Well, the completions were the same. We thought the rocks were the same. We are seeing a little bit heavier oil and we don't have an explanation to that as yet. The oil cuts are coming up. They haven't achieved the rates that we saw on the first 2 wells but they're still early and it could be a mobility issue with a little bit heavier oil, maybe it's got to draw the influence of the frac down more before the oil comes in. It's just too early to say. But we are scratching our heads around here and we've got a bunch of very smart engineers, not including myself, but I am an engineer and we don't like things that we don't understand. And so we don't like the fact that we can't understand what's going on there. But we're very optimistic. The first 2 wells are well beyond our expectations and, hopefully, these wells will come around. They all act different for some reason.

[Michael S. Scialla:]

Is there anything in terms of the differences in depth or any -- could it be a separate fault block? Or you're not seeing anything like that?

[Robert L. G. Watson:]

No. We've got 3D in there and you can pretty much pick up any fault that's over 10 feet, and I doubt if a 10-foot fault would be a difference. Two of the wells are only 1,200 feet apart, so that's what's really gotten us scratching our heads. It could be the frac went down into the Buda. Who knows? We just don't know at this point. But we'll certainly keep everybody appraised of what's going on and it doesn't -- I mean, these results are certainly not impacting our development plans. We're going full bore with that because I think we have confidence that we'll figure this out, one way or another.

[Michael S. Scialla:]

And when do you make that decision on that rig? So you bring it back to Jourdanton next month, I believe? And then you drill a couple of wells and at that point, you make a decision...

[Robert L. G. Watson:]

Yes, I think the decision will be made in June. I think, around this table, the decision's already been made but the Board has to approve it. And so I would say mid-June, something like that.

[Michael S. Scialla:]

And when do you test the southern fault block at Jourdanton?

[Robert L. G. Watson:]

That would be right after that. We're very anxious to get that done. As you know, none of those reserves are booked even 3P for us. So a success down there is really impactful to our net asset value.

[Michael S. Scialla:]

Yes. Okay. And last one for me, you talked some about the Powder and you get a well there that doesn't want to decline. You got a neighbor that's drilling terrific wells. But you have no plans to drill anything there this year. Is that -- and if you can't grow the acreage, I mean, what are your thoughts longer-term there? Is it a divestiture candidate? Or do you kind of wait to grow into a development program there?

[Robert L. G. Watson:]

No, I think if -- just to be perfectly honest with you, it's probably a divestiture candidate for us. It makes a lot more sense for some of the other companies up there that have surrounding acreage positions because it's a great bolt-on for them. And we can hopefully use that to increase our inventory in the Bakken or the Eagle Ford or both. But no active plans at this point.

[Operator:]

This concludes our question-and-answer session. I will now turn the call back to Mr. Geoff King.

[Geoffrey R. King:]

Thank you, Kim. We appreciate your participation today in Abraxas' earnings conference call. As I mentioned at the start of the call, a webcast replay will be available on our website and a transcript will be posted in approximately 24 hours. Thank you, and have a great day.

[Operator:]

Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.