Abraxas Petroleum Corporation
Q4 2014 Earnings Call Transcript

Published: 5 Mar 2015

[Operator:]

Welcome to the Fourth Quarter 2014 Abraxas Petroleum Corporation Earnings Conference Call. My name is Tony and I will be your operator for today. [Operator Instructions]. 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.

[Geoff King:]

Thank you, Tony. And welcome to the Abraxas Petroleum fourth quarter and year-end 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'll now turn the call over to Bob.

[Bob Watson:]

Thanks, Jeff and good morning. Yesterday we released earnings revenues and cash flows that were a record for the 20-plus years that Abraxas has been a public company. Obviously, our focused transformation has succeeded. I don't plan to dwell on any of this because obviously times have changed drastically. But I would like to say that our focused transformation over the last four years, slower perhaps than some would've wanted, has been very successful. And it has put Abraxas in a great position to not only weather the current storm, but to use the opportunities created by it for quality measured growth into the future. Over the past several weeks we've seen a number of E&Ps raise substantial amounts of potentially dilutive equity to fix their balance sheet. And I'm proud that Abraxas is not in a position to have to fix our balance sheet and that we would only raise equity to effect an acquisition that is accretive to our existing shareholders. Now these types of opportunities are getting better and certainly more numerous and I'll address those in a bit. But first, on to operations in North Dakota, we recently completed the drilling of four wells to about 21,000 feet each on the Jore Federal West pad. I would like to say this was in record time and at record low cost for us. As we've previously announced, we've elected to defer the completion on these wells to, one, better weather and two, even lower frac costs. We anticipate this timing to be sometime early summer. Abraxas owns about a 76% working interest in these wells, so they are obviously very impactful. Our company-owned drilling rig, Raven Rig number 1, is moving to a three-well Northwest pad for two Three Forks and one middle Bakken well, where Abraxas will have an average of about 60%. Costs are coming down in North Dakota but we certainly expect more to come in the future. On the most recently completed and previously announced Stenehjem pad, where three wells were drilled this past fall and completed this past fall, I'm pleased to say that all three wells are performing above our recently upward revised type curve. And we continue to work on swapping interests in the surrounding area to create more operated units and we've had some success in doing this. It's a slow process. We're dealing with big companies in relatively small deals in relation to their size, but in the meantime we still have about four more years of quality locations. That's before counting on any results from this ongoing rationalization activity, which I'm very confident will be successful. At current commodity prices, we're generating acceptable economics in North Dakota, a combination of lowered costs and exceptional well results. So we expect to continue our one-rig program in North Dakota for the foreseeable future. Now down south in the Eagle Ford, we have completed drilling on two wells with casings set to total depth. We have released the drilling rig as previously announced and we've elected to postpone the fracs on these wells until costs come down even more. Again, I anticipate that would be late spring, early summer. We continue to evaluate opportunities to expand our operations in the Eagle Ford when conditions warrant and I would anticipate that activity will continue on during the entire down cycle that we're currently experiencing. I might add that our Cat Eye number one and the Jourdanton South Fault Block in Atascosa County is still producing right on the type curve. Our gas facility at Jourdanton should be online in about two weeks. This will reduce flaring and increase production. And keep in mind, due to our financial flexibility and the fact that we own 100% of all of our properties in the Eagle Ford, we can start back up in a moment's notice when the economic conditions warrant. In the Powder River Basin, as we previously talked about, our sale process was started at a very bad time, just as crude oil prices started tanking. Also said at that time that that we weren't going to give these properties away and we would not sell them at the current price deck. We did not receive any acceptable bids. So instead, we have decided we're going to keep these assets and we have started working on a development plan. And with decreased costs that we're seeing now and the performance from our existing wells, we're in the process of permitting five high-interest wells that should exhibit good economics at existing prices. We're even considering the economics of bringing Raven Rig 1 down to Wyoming for a five-well program. Don't know the timing on this project yet. Three of the wells are on federal land. And with the associated permitting delays, timing is very much up in the air. In West Texas, we have three wells that are waiting on frac that we've actually placed on production natural and have had some encouraging results from that. Again, we're waiting on frac costs to come down anymore, anticipate fracking these wells summer timeframe, then we'll evaluate the merits of the continuing multi-well drilling and rework program on our existing properties in the Permian Basin. Today we found ourselves in a very enviable position in the current commodity price environment. With just the nine wells that we have drilled and not completed, four in the Bakken, two in the Eagle Ford and three in the Permian and with the plans to frac and complete these wells late spring, summer timeframe, we expect to grow production 26% year over year to around 7100 barrels a day average, while generating free cash flow and thus increasing liquidity. With free cash flow that we're generating currently and our credit line, we've reduced our working capital deficit quite substantially, giving us ultimate flexibility to capitalize on opportunities for accretive growth for our shareholders. We're looking at lots of deals. Most we dismiss quickly, but several we're doing in-depth investigation. Rest assured we expect to use this down cycle to our advantage and you should expect to see Abraxas emerge on the upside a bigger, stronger and even more profitable company with a clean balance sheet. Now I'll open it up for questions.

[Operator:]

[Operator Instructions]. Your first question comes from the line of Ryan Oatman. Please proceed.

[Ryan Oatman:]

For the production outlook on a quarterly basis, should we look for kind of a peak in 3Q as these wells come on from the deferred completion activity and kind of a slight decline thereafter?

[Bob Watson:]

That's probably the way our model would look like right now. But keep in mind we also have a continuing operation in the Bakken. And I would expect to have the three wells that we're currently moving on ready to go late summer. And if frac costs have come down substantially, we could go on and put those wells on production before year end and also have a nice boost in the fourth quarter as well.

[Ryan Oatman:]

And can you just speak to what you are seeing on the ground in terms of service cost reductions? And maybe, Geoff, just kind of remind me what the budget assumes in terms of those service cost reductions?

[Bob Watson:]

I would say 20% is probably a good round number that we're seeing across the board. I know we've reduced the day rates charged on our company-owned rig up in North Dakota due to cost reductions. I anticipate seeing more. I'd like to see another 10% to 20% reduction before we crank up activity again. And I think we'll see that and as far as what Geoff's numbers include--?

[Geoff King:]

The $53.8 million that we put out there did not include -- it was using 2014 service costs, so it doesn't include any benefit for the 20% that Bob spoke of. Now that said, we might fill that in with a few other things and keep it. So I'd keep that $53 million, but that activity hopefully would have associated barrels coming off of it. But nonetheless, I would say that trajectory is downwards, but don't hack that number by 20%.

[Ryan Oatman:]

Right. No, that makes sense. And it does sound like there are some opportunities, should the costs come down, to kind of boost activity back half of the year, that's helpful. There was a little blurb in the press release about the potential to lower per-unit LOE costs. I was just wondering if you could kind of speak to that.

[Bob Watson:]

I would say that we have been blowing and going for the last couple of years. And we have a fairly small staff for the amount of activity that we were generating and consequently, we were letting some things go, the focus on more important things during the drilling and completion stays. So now our staff is concentrating on getting more efficient on the LOE side and I fully expect a pretty substantial reduction in LOE because of those efforts and we're already seeing some of them. And actually this down cycle will do us some good to get even more efficient than we were beforehand.

[Operator:]

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

[Will Green:]

I wanted to follow on, on the LOE question there, because obviously that's been a great area of kind of cost reduction. I was just noticing you guys were roughly flat year on year, I think, on an absolute basis and yet you grew production by over 30% in 2014. So, what's kind of the lowest hanging fruit there on the LOE side that you guys are targeting first?

[Bob Watson:]

Obviously the lowest hanging fruit in the Eagle Ford is probably artificial lift. We've been lifting our Jourdanton wells with sub pumps, which are extremely expensive to operate, expensive when they break down. So that's an ongoing process to convert those to rod beam pumps. Up in North Dakota there's not a whole lot more we can do. We're very efficient up there and our lifting costs are extremely low. But every little thing adds up and so I would expect certainly improvement there. I don't expect them to go up. But the biggest low hanging fruit will be in the Eagle Ford. And it will also help when we get our Jourdanton gas plant online. It should operate at considerably cheaper than the chemical sweetening process that we've been using. It's also bigger, can handle more gas and obviously that means more production, less flaring. So that's what you should focus on, looking at substantial reductions would be in South Texas.

[Will Green:]

And then you mentioned looking at deals and obviously given the strong balance sheet, maybe utilizing this downturn and getting stronger. Can we think about that as potential bolt-ons? Are you looking at new areas? How should we think about that? And then does that mean you guys are starting to see kind of land pricing and that sort of thing come down a little bit, reflective of the current commodity environment?

[Bob Watson:]

Well I would say we're looking at deals that are bigger than just bolt-ons, but they are in areas where we have potential operating experience in the past, primarily focused in the Bakken, Eagle Ford in Permian Basin. But there are some areas that we've operated in the past that we feel very comfortable that we can be efficient in that we might consider. But the four core areas we have are our primary objective. But the deals we're looking at are bigger than just bolting onto our existing acreage position.

[Operator:]

Your next question comes from the line of Mr. Welles Fitzpatrick. Please proceed question.

[Welles Fitzpatrick:]

On the five PRB wells that you all talked about, are those going to be more on the Western acreage by the Hedgehog? And can you remind me -- are those on federal land? And if so, do you have those permits in had already?

[Bob Watson:]

They are up in the Hedgehog/Porcupine area. Two of the areas will be 100% wells on the section where the Hedgehog well is. That is state land. Those permits are going to be achieved pretty quickly. And then we're going to move to the east of there to the -- it's going to be called the Frasier Federal, which tells you right there it's federal land for three locations. We'll own about a 75% to 80% interest in those wells, it appears and that process has started. But the federal process is really dragging out these days, so there's no way of knowing when we might be able to get those. So that's why I say the timing of drilling in the PRB is really up in the air.

[Welles Fitzpatrick:]

And then on the Jore, can you remind me are those Three Forks wells also spaced at 660?

[Bob Watson:]

The Jore Federal were all Middle Bakken, all on 660s. And as we've said in the past our downspacing has been tremendously successful and we continued to monitor our results versus others downspaced as well as wells that are on wider spacing. And our wells continue to outperform. So we're very proud of the fact that our downspacing not only works, but our operations are maximizing that value.

[Operator:]

Your next question comes from the line of Mr. Steve Berman of Canaccord. Please proceed.

[Steve Berman:]

Just focused on Jourdanton for a second, if you get the gas plan on you could drill and complete wells for, say, 30% less than what you were doing before. Can you envision getting back active under that scenario without higher oil prices? Or do you need to see something higher than $50 oil to go back and get active at Jourdanton, or anywhere in the Eagle Ford for that matter?

[Bob Watson:]

I think that applies to everything. I think we need to see that 30%. We're not quite seeing it yet. We want frac costs to come down. We've done a lot of the valuation of our current strategy versus what others are doing. There are some things we want to try, to try to get better. But the main driver is going to be overall costs. And it could very well be that by summertime we'll feel comfortable enough to go in and drove more wells. We've got six more -- at least six more wells to drill in the South Jourdanton fault block to HBP all of that acreage. So that would be our immediate goal. We're comfortable with the results that we're seeing on the one well in the South Fault Block. Certainly one well does not make a field, but we're feeling pretty good about it. So that's why I said we can crank back up in the Eagle Ford on a very short notice. Certainly services are readily available and coming down in price. So that one is just stand by and wait.

[Steve Berman:]

And those six wells would have to be drilled by when?

[Bob Watson:]

We've got two-plus years left on those leases, so we really don't have a gun at our head.

[Operator:]

Your next question comes from the line of Mike Kelly of Global Hunter Securities. Please proceed.

[Mike Kelly:]

Just a follow-up from Welles' question on the PRB, can you remind us? Just there seems to be a wide range of economics or well costs up there. But on that porcupine acreage, what we could expect relief for well costs and if you wanted to give potential ranges on EURs, oil cut, etc. we'd be all ears there. And then just a follow up on that would be -- were those wells originally in the CapEx budget that you previously released, too? Thank you.

[Bob Watson:]

Let me answer the last one first. No, they are not in that original budget, but they could be in that little bit of 20% savings space that's also not in the budget that Geoff talked about. The Turner well that we have up there at the Hedgehog, looks like the EUR is going to be about 5 Bcf and about 300,000 barrels of condensate and I don't know how much NGLs. But it's pretty rich gas. And at about a $6 million well cost, that does generate pretty acceptable economics for us. So that's what we're looking at; would anticipate that all five of those wells would have similar economics, as they're very similar geologically. Down in the Brooks Draw area, we're watching an offset operator drill some direct offsets to us in the Turner. That's an area that we have a big acreage block in. We've not attempted a Bakken-style modern completion in those wells yet. We do have horizontal wells, but they were lightly fracked. So we're looking forward to giving it a try some time when conditions warrant, to go in and drill a long lateral and stimulate it with a number of stages and see what kind of results we might get. We're cautiously optimistic that we might have a big program there to do sometime in the future. And it's all HBP so it's not going anywhere. We've got the luxury of sitting back and watching.

[Mike Kelly:]

What do you think is a ballpark number we could think about for your working interest in those five wells?

[Bob Watson:]

The two Hedgehog wells we have 100% and in the Frasier Federal I think it's going to be between 75% and 80%, that would be three wells.

[Mike Kelly:]

And if I could just ask a follow-up on the M&A side of things, just curious on how big of a bite you might take and willing to either finance it through additional debt or equity. How are you thinking about how aggressive you might want to be in this downturn? Thanks.

[Bob Watson:]

Well we'll bite off as much as we can chew if the deal is right. At the end of the day we want a clean balance sheet and certainly we would want the acquired assets to be accretive to our existing shareholders. And those are the two drivers right there is how we could finance something to keep a clean balance sheet and how accretive can it be to our shareholders and then size really doesn't matter.

[Operator:]

Your next question comes from the line of Mr. Mike Scialla. Please proceed.

[Mike Scialla:]

You have had a few wells online now at Jourdanton for a while. I think those Ribeye wells were spaced pretty closely. Just thoughts on potential spacing there and then your thoughts on the Northern versus Southern Fault Blocks, if you can say where the preference would be there.

[Bob Watson:]

Well I would say our current thinking is the South Fault Block is going to be better than the North because it's a lot more geologically quiet. The North Fault Block, which we knew was filled with small faults, which has caused drilling and completion problems, are really not present in the South Fault Block. The two Ribeye wells are 330 feet apart. But if you will remember, they were both understimulated. So we're actually looking at a project to go back in and re-stimulate those wells, because we feel like our fears for shortening the stimulation were probably not well-founded and that we should go in and frac the whole horizontal section. On the South Fault Block and the Cat Eyes wells, we ran some rather new -- they are not radioactive, but they're salts in the frac fluid. There is 19 different ones. So we're getting data back on where the fluid is coming from. And we're very pleasantly surprised to find out that the entire Eagle Ford is contribute in about the same amount of fluid and even up into the Austin Chalk, where we bounced up for a couple of stages. So we think our opportunity set has actually grown there and now we're trying to figure out a way to maximize the economics by lowering the cost and effecting an optimal frac job.

[Mike Scialla:]

This is maybe a little bit of a hypothetical, but if you were to -- I realize you don't want to be drilling and completing right now until well costs came down or do come down -- but where would they be if you were to drill and complete today?

[Bob Watson:]

I would say the South Fault Block at Jourdanton we're, I think, amply pleased with what we've seen. We certainly feel like it's a development project that needs to be done and we're just trying to optimize timing for costs and economics.

[Mike Scialla:]

Can you throw a number out as to where well costs would be there today?

[Bob Watson:]

Well probably in the $6 million range. A lot of that is on Pete's completion design which we're still working on. But I certainly know that drilling costs would be down considerably and I think the knowledge that we have gained from drilling seven or eight wells in the area Now that is certainly going to help drive our drilling costs down. So if we get real comfortable in that $6 million range or a little bit less, I wouldn't be surprised for us to crank up the development program there sometime this year.

[Mike Scialla:]

And then same on the Bakken in terms of well costs of -- where are those right now?

[Bob Watson:]

We're probably at $8 million right Now because we haven't seen any substantial drop in completion cost yet. We anticipate that, along with better weather and continued efficiency gains in our drilling rig, that $7 million is not going to be out of the realm of possibilities. And at $7 million and the well quality that we're getting, it's certainly generating very attractive economics.

[Mike Scialla:]

And remind me, Bob, I think you had been experimenting between plug and perf and sleeves there. You are still favoring sleeves, if I remember correctly?

[Bob Watson:]

Well we were doing a hybrid, Mike. The first -- or at the toe we're doing about seven or eight stages with sleeves, because you really can't get coiled tubing down there to drill out plugs anyway. Then we're coming up with plug in perf. I would say that we're still doing a considerable amount of research on our frac techniques. Don't anticipate changing much now because of the success we've had. We don't want to bargain that success. But if somebody comes up with something that is really outstandingly new, we would certainly consider it. We found out that in researching well results, some of the companies that have been public about their performance increases really don't hold true when you look at the ultimate production results. So we're not inclined to say that we're going to change anything, but we're certainly looking and we'll make sure that we know about it if somebody comes up with the Holy Grail.

[Mike Scialla:]

Just one last one, on the Canada divestiture, are you completely out of Canada now or is there any exposure there?

[Bob Watson:]

No, we're completely out. We got all our money and at the present time we have no plans whatsoever to go back.

[Operator:]

There are no further questions in the queue. Please proceed.

[Geoff King:]

Thank you, Tony. 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, thank you. That concludes today's presentation. You may now disconnect and everyone have a great day.