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Abraxas Petroleum (NASDAQ:AXAS)

Q2 2013 Earnings Call

August 08, 2013 11:00 am ET

Executives

Geoffrey R. King - Chief Financial Officer and Vice President

Robert L. G. Watson - Chairman, Chief Executive Officer and President

Analysts

Will Green - Stephens Inc., Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Kenneth Pounds

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

John Polcari

Michael Kelly - Global Hunter Securities, LLC, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Quarter 2 2013 Abraxas Petroleum Corporation Earnings Conference Call. My name is Ben, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes.

I would now like to turn the call over to Mr. Geoff King, Vice President and Chief Financial Officer. Please proceed, sir.

Geoffrey R. King

Thank you, Ben, and welcome to the Abraxas Petroleum Second Quarter 2013 Earnings Conference Call. Bob Watson, President and CEO of Abraxas, joins me today for the call. 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.

Before we get started, 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.

Robert L. G. Watson

Thanks, Geoff, and good morning. Our second quarter met expectations. Higher oil prices helped offset lower production, and our production was a little light, mainly due to the previously announced asset sales and a very wet spring in North Dakota, where torrential rains caused some production shut-ins, but more impactful for us was the delay it caused in our Lillibridge East pad completions. All that's now behind us, and third quarter is off to a roaring start, a much higher production and much higher oil percentage.

Late June and early July, I personally witnessed an amazing logistical and operational feat in North Dakota. I'm extremely proud of our operations team who pulled off a 4-well simultaneous frac, pumping 122 stages over 12 million pounds of sand and ceramic prop and over 250,000 barrels of water without any serious issues, proving even though we're a small company, we can operate as good or better than most.

The results have been fantastic. We really couldn't have predicted how good they actually are. When you have to curtail production because oil trucks can't load fast enough or a gas pipeline gets full, you know you're doing good, or as Geoff King told me, a very good problem to have.

In 22 days from 2 wells and 17 days from the third, we've produced over 61,000 barrels of oil, and a significant amount of very rich gas has been sold. The fourth well had a suspected sand plug inhibiting flow. We finally got a coil tubing in it on it this past Tuesday. We washed out a very large amount of sand underneath the first frac plug. And since we had the coil tubing on the well, we've decided to go out and drill out all the frac plugs. As of this morning, we're on #14, with 11 more to go.

From right now, we expect as good a well as the other 3, and the timing has been good as the sales bottlenecks are getting worked out. The delayed third-party oil pipeline should be in service next week, taking lots of trucks off the road.

After the drilling was completed on the Lillibridge East pad, we did a cross-country walk with our own rig, Raven Drilling Company rig 1, to the Lillibridge West pad, another amazing and cost saving accomplishment, especially considering the wet weather conditions during the move.

The rig has now successfully drilled the surface hole, the intermediates drill a hole through the curve with casing set at 90 degrees on all 4 wells on the west pad. As of this morning, we've started drilling the first lateral. Hopefully, I'm not jinxing us, but we're way ahead of schedule, which equates to significant cost savings again. We could actually be frac-ing these 4 wells before cold weather sets in.

And another additional feat is that we are very close to having the rig -- Raven rig 1 converted to natural gas. There are actually test running the engines as we speak. Again, a cost savings over burning diesel.

Abraxas owns a 34% interest in both the Lillibridge East and the West pads.

Equally as proud of our South Texas operations team as we continue to excel in our Eagle Ford development. During the quarter, we placed 5 gross, 1 net well on production. 2 of these came on in late June, so they had virtually no impact to our second quarter results. We've now successfully drilled and completed our 40-acre pilot with 2 wells with 5,000-foot laterals, with the laterals being 300 feet apart. Both of these wells should begin flowback today or tomorrow. So far there, we've seen no indication of communication, but it's way too early to make a final assessment of whether these 2 wells are talking to each other.

Our Gran Torino A 11H is, as of this morning, on stage 14 of a scheduled 19-stage frac. Therefore, it should be on flowback next week.

And we're currently drilling the lateral on the Sting Ray A 8H, which is a long lateral well for us, 7,500 feet. And certainly, that well should be on production here shortly during the third quarter as well.

From public data, and that's all we have access to, we feel like we are among the industry leaders in completed well costs. And our well performance would indicate that we're not cutting corners to our economic detriment.

Perhaps a comment again on initial potentials. We bring our wells on very slowly on small chokes. Some companies bring their wells on wide open with very high, headline-grabbing producing rates. The question we have is, are they harming their wells from an economic standpoint? And our answer would be no one really knows for sure, but we're not taking that chance.

On the Lillibridge East pad, we announced flowing pressures and choke sizes and number of producing days, all of which need to be taken into account when comparing wells. Had we opened the Lilli wells up, we could have reported headline-grabbing rates, and the same can be said about our Eagle Ford wells. In house, we like to compare 30, 90, 180 and 1 year cumulative production to see how we're doing.

Back to operations. We're currently drilling a lateral below 8,500 feet toward 10,000 feet on our Spires Ranch 129-2 Nolan County, West Texas, in which we own 100% interest. This well will be the first well where we attempt a stage frac out of the other 4 that we've drilled. There's still open hole completions. The stage frac creates favorable economics, increasing production reserves. This could have a very significant impact on Abraxas going forward.

What to expect the remainder of the year? Significant production and cash flow growth as we continue a 1-rig pad development program that's getting ever more efficient every day in North Dakota; a 1-rig program in the Eagle Ford including at least 1 100% owned well; and several vertical development wells, non-Bakken, in the Williston Basin that we have had in our inventory and find now is a good time to attempt to expand production in our vertical operations.

Our sale of the non-operated [ph] Bakken interest is scheduled to close tomorrow. We'll be putting about $40 million cash against our paying down our revolving credit facility, leaving about $60 million in liquidity after deducting for the reserve sale but before credit for our first half reserve adds.

So we're looking forward to the second half of 2013. We did a lot of preparatory work during the first half, and we're very happy to say that we're now seeing the results of all that work.

So with that, I'll throw it open for questions.

Question-and-Answer Session

Operator

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

Will Green - Stephens Inc., Research Division

I wonder if we could start on the Bakken. It sounds like you guys are getting very efficient there with that pad drilling and pad development. Can you maybe give an estimate on what you think that's dropping the well costs on just savings from redundant facilities?

Robert L. G. Watson

I would say that we're seeing a 10% to 12% cost reduction, perhaps even more than that, on the pad that we're on right now from the previous pad. And all of that would be attributable to learning curve and getting more efficient. We're probably equal on service costs between the 2 pads, and we'd expect that to stay about the same on a go forward basis. But just little things like converting the rig to natural gas saves a lot of money. Walking between pads saved a bunch of money and time. And importantly, mother nature has been kind to us. Now we're in good weather. Winter weather is always going to slow things down and create more costs. But I think on a year-to-year basis, we're making some significant progress. And we look forward to many years of development drilling up there in the Bakken.

Will Green - Stephens Inc., Research Division

I appreciate that. And then on the non-core divestitures, do you guys have anything else planned? And then, what's kind of a good goal for you guys going forward on debt-to-EBITDA or any kind of debt metric you guys look at? What's the goal, or do you have a goal to get to by the end of the year?

Robert L. G. Watson

Well, we've stated that we'll be at 2x. As of tomorrow, we'll be less than that, and we expect to keep it there on a go forward basis. We model a continued improvement in that metric. Ultimate goal would probably be in the 1 to 1.2x, and I think that's readily achievable with our current business plan without having to do anything else.

Will Green - Stephens Inc., Research Division

Great. So at this point, no other non-core sales are planned?

Robert L. G. Watson

We have some small ones. We have a package in Wyoming that we're working on right now, non-operated. Nothing significant, nothing nearly the size of the non-operated Bakken. But we said all along we wanted to rightsize our portfolio and rightsize our balance sheet. A good amount of that has been done, a little bit more to go. And then all the while, we're working at ways at concentrating on our operated Bakken and operated Eagle Ford and operated West Texas assets.

Operator

The next question comes from the line of Ryan Oatman from SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

This is Neal in for Ryan. In the Eagle Ford, we've seen another peer speaking somewhat cautiously about spacing. Are you all still confident you can downspace to 40 acres? And can you give us a little status update on that program?

Robert L. G. Watson

We did not see any communication between wells during the frac jobs. We want -- we're rigging the wells up to where we can monitor more data than we normally would on a well, and thus, a little bit of slowdown on the flowback time, which should start today or tomorrow. But we'll be watching them very closely. But it's way, way too early to fully assess whether 300-foot spacing is correct in our area or not. And our guess is that the different areas in the Eagle Ford, depending on the geology, are probably going to be susceptible to different optimum spacing. But we'll be watching this very closely, and if it works, then we basically doubled our locations that we have at WyCross, which we're very hopeful of.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Great, that's very helpful. And just one final follow up. Do you guys have any status updates on some of the under the radar programs, such as the Cline, Strawn or Duvernay?

Robert L. G. Watson

Well, the Strawn, we're drilling in right now. The Duvernay, we are looking for a partner. We've gotten most of the data back, it's still being held confidential, and we're going to be using that to find a partner to fund the development of our entire Canadian operation. That's our ultimate goal. We want to keep part of the upside, but we don't want to put any more money into it, and that process is underway as we speak. The Cline, we're monitoring very closely. Several wells operated by Devon have been drilled very close to our acreage in -- on the eastern shelf. We're watching that production very closely. But our intention at least near-term is to continue to develop the Strawn section and watch the Cline very closely as we drill down through it.

Operator

The next question comes from the line of Kenneth Pounds from Castlebury.

Kenneth Pounds

Yes, it's Castlebury. It looks like you have a lot of great wells coming on. Why isn't maybe the guidance for the exit rate a little higher, or do you have one?

Robert L. G. Watson

No, we have not issued guidance for an exit rate. We've issued guidance for our average production rate for the year, which I believe is about 4,550 to 4,700 barrels a day average. So if you take the first half average, you can pretty much do the math and come up with what we expect for the second half.

Operator

The next question comes from the line of Welles Fitzpatrick from Johnson Rice.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

On the 10% decline in the Bakken, am I doing this right, that -- would that be 10% off the last Raven well, so around $9 million. Is that fair?

Robert L. G. Watson

No, it's 10% off the last Lillibridge pad, which gets us in the low 8s.

Welles W. Fitzpatrick - Johnson Rice & Company, L.L.C., Research Division

Okay, perfect. And then on the [indiscernible] downspacing test, you said you didn't see any interference, at least initially. Is it fair to say that those rates are comparable to what you have nearby, or was there any degradation there? Did it basically look good all around?

Robert L. G. Watson

Well, we won't know until we start to flow back, but I know when we were drilling out plugs, we were very pleased with what we were seeing as far as oil and pressures are concerned. So we'll bring both wells on at the same time and monitor them very closely, and we'll let people know when we feel like we have something of interest.

Operator

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

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

I wanted to talk a little bit about the Duvernay. I understand that there is, I guess, being pursued by some other operators -- is there a larger, more gas-oriented part of the play up there?

Robert L. G. Watson

Oh, absolutely. We are in the [indiscernible] oil window, and there has not been much activity to date. There has been some. Unfortunately, everybody's keeping their data very, very confidential, so we haven't been able to gather much other than what we've done ourselves. So we just feel like at the stage of this play, it's better to bring in a partner. We feel like our opportunities in the Eagle Ford or the Bakken are far superior at this point, so let somebody else prove that possibly equal economics up in the Duvernay with their money.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Sure. As far as what you know about with other operators active up there, do you have a sense of the timeframe when you will start to get some of that data that has to be made public?

Robert L. G. Watson

Well, I think people are playing games. The law up there is you can hold an exploratory well confidential for a year, I believe, and then a development well for something less than that. But everything that's been drilled has been considered exploratory, and so very little -- this play is just now evolving. So not many wells close to the oil window have been on production for -- or have been drilled for more than a year. So even from a regulatory standpoint, no one is required to release data yet.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Got it, okay. I guess, I've been paying a little more attention to what's been going on up there as activity has been heating up on the gas side with LNG export and so forth. So that was kind of why I started asking about the wider activity. Do you have any thoughts about what that might do overall? I'm thinking for plays, that might be a split of oil and gas, whether that would bring some more capital and services up there, I mean, I guess over the next couple year period.

Robert L. G. Watson

I think it's certainly going to help and I know there's a lot of interest in the Duvernay, a lot of comparisons to some of the U.S. shale plays, favorable comparisons. And we've had a good deal of interest in our -- all of our Canadian assets from the people that we've showed them to so far. So I would suspect that we'll be hearing something or you'll be hearing something from us probably by the fourth quarter anyway about what our intentions in Canada are.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Great. And in the Bakken, sorry if you've already touched on this, but you mentioned you have some vertical drilling opportunities. Are those targets like, I don't know, the Madison or something that you're pursuing up there?

Robert L. G. Watson

Yes. One of them will be a Red River test offsetting a very good Red River well that we have that had mechanical issues and needs to be replaced, so we're pretty confident of the reserves left on that one. And then the other one is a -- and we'll own 100% of it. And then the other one is a Ratcliffe, which is a Mississippian test that offsets a well also with mechanical issues that we acquired the entire interest in. And that well had a very significant test and good logs in the Ratcliffe, so we're basically drilling a twin to that well and putting it on production. So this is really low hanging fruit for us, and we feel like now is a good time to put them on.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Great. And just one more sort of general question. I've been hearing some operators looking at the tough NGL environment we've had for quite a while now and talking about how if that doesn't improve, you can kind of get to a situation where even if industry has liquids-rich plays, the economics on dry gas, especially if it's sort of low-cost, might be as good or better. Do you have any thoughts on that and any thoughts on how that might affect some of the areas that you're operating in?

Robert L. G. Watson

Well, obviously, NGLs are a product in both -- for us both in the Bakken and the Eagle Ford. I would say that they're probably not a significant revenue stream for us, certainly enough to where we don't want to throw them away. But I don't believe our economics are impacted by NGL prices. And so far, that's the only impact that we've seen in our areas is the price. We've not seen any issue with the takeaway capacity, although we did fill up the gas system with our Lillibridge East wells when we brought them on, but that's now been alleviated with some additional compression. So I don't foresee any more problems there. But we do know other operators, bigger operators in different areas are having some gas and NGL takeaways and they're also getting some pretty good pressure from regulatory front to not flare. So they're perhaps more interested in the NGL environment than we need to be at this point.

Operator

The next question comes from the line of John Polcari from Mutual of America Management Capital Corp.

John Polcari

I wanted to just refresh the information that you provided on your financials. The borrowing base is still $300 million, a borrowing base of $155 million. Is that correct?

Robert L. G. Watson

Yes, the credit line is $300 million. The borrowing base will drop down to about $143 million tomorrow when we close on our non-op Bakken sale because those reserves go off. But we've not gone through midyear redetermination yet, so we're not seeing any credit from the reserve adds that we've had in the first half.

John Polcari

Okay. And the payment again would be how much?

Robert L. G. Watson

It's just interest. It's -- the note's not due until mid-2015.

John Polcari

No, no, no. You're paying down a principal [indiscernible].

Robert L. G. Watson

We're paying down about $40 million. I'm sorry, I misunderstood you. We're paying down about $40 million with proceeds from tomorrow's sale.

John Polcari

Right. And then so as of the paydown, what would be the outstanding, then? Approximately...

Robert L. G. Watson

In the low 80s.

John Polcari

Low 80s?

Robert L. G. Watson

Yes.

John Polcari

And you had -- I missed it when you said what you were targeting in terms of debt-to-EBITDA?

Robert L. G. Watson

We've said our year end target was 2x. As of tomorrow, we'll be considerably less than that. And we were -- our model shows that we'll get even closer to 1 very shortly, which would be our ultimate goal.

John Polcari

Okay. So everything else being equal, normal operating basis, you'd want to be 1x?

Robert L. G. Watson

That's 1x to 1.2x is our long-term goal.

John Polcari

1x to 1.2x, okay. And the redetermination would be probably, when? In the next 30 or 60 days, the mid-year re-determination?

Robert L. G. Watson

Yes, September, early October timeframe.

John Polcari

Okay. And I would imagine that there'd be a possibility for some upward adjustment in light of the reserve production growth?

Robert L. G. Watson

We would hope so, yes.

John Polcari

Yes, yes. But barring that as it stands, it would -- the base would be approximately, you said $143 million?

Robert L. G. Watson

That's where it will be tomorrow, correct.

Operator

The next question comes from the line of Mike Kelly from Global Hunter Services.

Michael Kelly - Global Hunter Securities, LLC, Research Division

It seems like you guys really hit your stride here operationally at both the Bakken and the Eagle Ford. And given that, that will look a lot better tomorrow after you receive these proceeds from the Bakken. Was wondering the potential and your interest in the potential to pick up incremental acreage around your core Bakken and Eagle Ford plays.

Robert L. G. Watson

That is our #1 focus. We're not interested, I don't think, in picking up big blocks of acreage. We feel like we're better off focusing on smaller blocks that we can get on right away and fully develop, similar to what we're doing in both plays. And we have had some success in doing that. It's work in progress, so we won't give you any ultimate numbers yet, but we're certainly working on it. And our goal is to build out our inventory, but not just for the sake of building inventory, but for building it in areas that we know very well, that we've now determined our sweet spots and are thus very economic for our development. But that is our focus going forward is to pick up small tracts here and there, big enough to develop, but not huge capital expenditures upfront.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Got it. And I understand if you don't want to comment and give specifics on this, but maybe if you could give us some indication of what the market would be for a one-off kind of bolt-on asset in McMullen or McKenzie, however you'd want to phrase it.

Robert L. G. Watson

Well, we'd like to get them as cheap as we can, obviously, but the price of poker in both areas has gone up. We're comfortable with the rate. I'm not going to give you that rate because I don't want to tell any of the landowners or whoever we're dealing with what that rate would be. But rest assured that if we are successful in a transaction that it's at a capital level that we're very comfortable with.

Operator

[Operator Instructions] Ladies and gentlemen, it appears that, that is all the time we have today for questions. I would now like to turn the call back over to Geoff King for closing remarks.

Geoffrey R. King

Thanks, Ben. 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

Thank you very much, Geoff. Thank you for your participation in today's conference, ladies and gentlemen. This concludes the presentation. You may now disconnect. Good day.

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