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Abraxas Petroleum (NASDAQ:AXAS)

Q3 2013 Earnings Call

November 06, 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

Stephen F. Berman - Canaccord Genuity, Research Division

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

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

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Q3 2013 Abraxas Petroleum Corporation Earnings Conference Call. This call is -- my name is Whitley, 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 conference over to your host for today, Mr. Geoff King, CFO. Please proceed.

Geoffrey R. King

Thank you, Whitley, and welcome to the Abraxas Petroleum Third Quarter 2013 Earnings Conference Call. Before we get started, I'd like to note one correction to our operational update provided last night. Guidance of 4,400 to 4,500 Boe per day is for the year 2013, not 2014 as stated in the press release. Apologies for that oversight.

Onwards to the 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'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 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. Well, third quarter has started to prove that our business plan is definitely working. We're focusing on our highest return basins, principally the Bakken and the Eagle Ford. We've been divesting noncore and lower return assets, and yet we're still growing production and cash flow. So despite divesting a significant amount of production over the past 12 months, the third quarter production of almost 4,800 barrels a day is the highest for the company in over 10 years, with the cleanest balance sheet in quite some time.

Production was up 16% over the second quarter of 2013. This was achieved by focusing on our high-return basins as we not only had great production growth, but we had a significant beat of the Street on both -- on all 3: earnings per share, cash flow per share and EBITDA. Perhaps the most significant event during the third quarter was the successful completion of 4 wells on the Lillibridge East pad in McKenzie County, North Dakota. All 4 wells had 30-day average rate of about 1,000 barrels of equivalent per day. All 4 wells were capable of much more. I want to remind you of our company philosophy of -- in both Bakken and the Eagle Ford of bringing wells on line on a restricted choke, to conserve reservoir pressure for as long as possible and potentially avoid formation damage. We're seeing that our decline rates are not as steep. And consequently, we think we're enhancing our estimated ultimate reserves. As an example of this, I have some statistics on our Lillibridge East pad for you. And these numbers are oil and well head gas. They do not include the impact of NGLs or gas shrink through the gas plant, which would actually enhance the BOEs per day somewhat. I have a 90-day rate. This is an average rate for the first 90 days on the 1H well, which is a middle Bakken well. It averaged 1,148 BOEs per day, 80% oil. I've got an 86-day rate on the 2H well, which is a Three Forks well, 875 BOEs per day, again, 80% oil; an 82-day rate on a 3H well, which is another middle Bakken well, 1,152 barrels of equivalents per day, again, 80% oil; and a 66-day rate on the 4H. This was a Three Forks well, in which we had some completion issues and don't have as much production history, 736 BOEs per day, 77% oil.

During the quarter, we also drilled the Lillibridge West pad, 4 wells, 79 days quicker than on the East pad. I would attribute this to not only better weather drilling during the summer, but we're seeing some tremendous efficiency from our operations group and the drilling effort with our company-owned drilling rig, and we expect these efficiencies to continue going forward. The Lillibridge West pad is currently being frac-ed. They could all be on production in a couple of weeks. As of this morning, we pumped 44 out of the planned 130-some-odd stages, all is going well. And so that job should continue for another 7 or 8 days, and then we'll be in a position of putting those wells on production. The rig was mobilized. Our company-owned rig was mobilized to the Jore Federal East pad, where we had 1 existing well to drill 3 new wells, had to shut in the existing well just for safety concerns. But those 3 wells are well underway. All the -- all 3 of them have had surface casing set, and we're beginning to drill the curve this morning on the first -- of the intermediate holes at Jore #1. We'll drill 2 more intermediate holes, and then start the laterals. And these 3 well pass -- 3 new wells on the 4-well pad are ahead of schedule and hopefully, will be on production during the first quarter of '14.

Also during the quarter, we closed on selling a good portion of our non-op Bakken asset for about $40 million of additional liquidity. We retained some of the non-op that we originally thought we would sell, principally in areas where we have operated positions. We felt like the non-op portion was still additive to us, so we held those back from the sale. But the $40 million liquidity is certainly important to us.

Okay, down south in the Eagle Ford, in the WyCross area of McMullen County. During the quarter, we drilled 3 new wells, brought 4 new wells on production, including our 300-foot spacing, which equates to 40-acre pilots. To give you an update on those wells, we're very pleased and we have got an 83-date on the Camaro B3H at average 542 Boes per day, 93% oil; and an 84-day rate on the Camaro B4H. It averaged 560 barrels of equivalents per day, also 93% oil. And, again, these -- the gas portion of these production rates do not include NGLs or the effect of plant shrink on the gas. So to date, we've seen no evidence of communication or diminished production. These wells are still well above our type curve. The rig is currently drilling a 300-foot offset to the Camaro A #1 being the Camaro A #2, and that well is also starting to drill the curve as of this morning. Both of those wells will be zipper frac-ed soon. And then toward the end of the year, we'll mobilize a rig down to our 100% owned Cave Prospect also in McMullen County for 2 9,000-foot laterals. We found that the 2 longer laterals in WyCross, being 7,500 feet, are showing very good additional production and reserves for the added cost of the longer lateral. So we're very much looking forward to the 9,000-foot laterals on our 100% owned Cave Prospect as they should have significant impact on the company. We've been asked why we went back to WyCross from -- instead of going immediately to Cave. We feel like we want to take advantage of our completion and drilling experience in the WyCross area as much as possible before transferring operations in January to another company that acquired our partner.

At the end of the third quarter, we spotted our 100% Blue Eyes 1H well in Atascosa County. That well was successfully drilled to below 13,000 feet, including a 5,000-foot lateral. And the frac on this well is scheduled to start November 17, right around the corner. Obviously, with 100% interest in this well and the surrounding 4,000 plus or minus acres, this is a very impactful well for Abraxas as well.

In West Texas, we successfully drilled and completed the Spires Ranch 129-2H in Nolan County, a horizontal well with about a 3,000-foot lateral. This is the first well on our Spires Ranch prospect where we attempted a frac, and we frac-ed this well with 21 stages. The other 4 wells have not been stimulated. We still have about 6,000 barrels of load water to recover. The well is testing on pump, currently producing about a 50% oil cut, taking a little bit longer to clean up than we thought but we'll certainly be talking about the ultimate results of this well here in the future.

So how do we keep the momentum going? People have asked that. This is the way we look at it here at Abraxas. In the fourth quarter, just to remind you, we should have 4 new Lillibridge West pad wells on production, mid-November, time frame. We own a 34% interest in those wells. We should have our 100% owned Blue Eyes well on production late November. And we expect to have 2 new WyCross wells that we own 25% of, mid- to late-December on production. Thus, we are maintaining our previously announced exit rate guidance of 5,300 barrels of equivalents per day. And by the way, we define exit rate as our average December month-wide production. Following that and the first quarter, we got hopefully 3 new wells in the Bakken on our Jore Federal East pad. These are 76% owned, thus, significantly more impactful. We hope to have them on production during Q1. And we hope to have our 2 100% owned long lateral Eagle Ford wells on production during Q1. And all of this, with a year-end debt-to-EBITDA of less than 2x with a 2014 goal of even less than that.

With that, we'll turn it over for questions.

Question-and-Answer Session

Operator

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

Stephen F. Berman - Canaccord Genuity, Research Division

Can you talk a little bit more about what else might be in the hopper in terms of potential divestments following this Fairview sale?

Robert L. G. Watson

We still have some extraneous assets. Actually, we're going to auction with them in the month of December. Principally, non-operative properties in Wyoming, one property in West Texas, one property in Montana. This will go a long way to cleaning up our act. We would like to eventually have as close to 100% operated properties as we possibly can. So the WyCross assets will not be that starting in January. So we'll look at what we want to do. These are very high-quality assets, and we're certainly inclined to keep them unless we get a very aggressive bid. So that's all in the hopper. To offset these divestitures, we have a number of bolt-on acquisitions that we're working on in, principally in the Eagle Ford, that we're very excited about. We think we'll have even more inventory here fairly shortly than we have now. So we're pretty excited about what we're looking at on the A&D effort.

Stephen F. Berman - Canaccord Genuity, Research Division

And, Bob, on the Spires Ranch, I know it's the first of a kind well but just any thoughts on what kind of rate, maybe even a range that we could expect for a 30-day rate on a well like that?

Robert L. G. Watson

Well, I think it's too early. We're still getting a significant amount of load water back. Although we are getting a 50% oil cut, this is a sub-pressured reservoir, so it is on pump. So -- I just hesitate to throw out something yet. I would think, at least, initially, the rates look like they will exceed our previous 4 wells, which are essentially unstimulated. But we'll have to just wait and see.

Stephen F. Berman - Canaccord Genuity, Research Division

And remind me what those rates were. Do you have that?

Robert L. G. Watson

Oh, do we have [indiscernible] on those? I don't have it right here in front of me, but I think we're looking at, what, 40,000 to 60,000 barrels of reserves, and probably about half of Bcf of gas on those wells. Something -- I'm getting a few nods around the table, but don't have the exact numbers in front of us. But that shouldn't be too far off.

Stephen F. Berman - Canaccord Genuity, Research Division

Right. And how many locations do you think you have here, if this is successful, just going forward?

Robert L. G. Watson

We have 6 more for sure, and then we'll look and see what those bring us.

Operator

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

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

Can you talk a little bit about the shut ins at Lillibridge East? How much is that? And how long do you think that's going to go on while the fracs are getting done?

Robert L. G. Watson

Well, we had them all set in originally. We're gradually bringing them back on as we've seen no evidence of communication to date. We'll just kind of play that by ear. We're about 1/3 of the way through the fractured job on the West pad, and so we're feeling more and more comfortable bringing those wells back on. Maybe within a few days, all 4 of them will be back on. I'm looking across the table. Yes, I'm getting a positive sign on that.

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

Perfect. And then you talked a little bit about Eagle Ford leasing. But any update on the PRB leasing activity that I believe you guys were engaged in?

Robert L. G. Watson

We're still working. No updates. That's a tough area to put acreage together. As you know, people are pretty tight to the vest with it. But we're -- we haven't given up, and we do expect to have some PRB activity in our 2014 budget. We're pretty excited about reviewing the 3D seismic in our Brooks Draw area in relation to the previous horizontal wells, which we've now determined have not been in zone for very long. So we're feeling pretty comfortable about our experience in steering wells and keeping them where they should be. So we might give that play another shot at it and then plus up in our Campbell County area. Our Hedgehog well continues to way outperform our expectations, so we might be doing some more up there as well.

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

Okay, perfect. And then just one last one in the Eagle Ford and I understand if you want to keep this tight. Is it fair to say that the bolt-ons that you talked about are probably going to be up in Atascosa, Bob, at Blue Eyes well?

Robert L. G. Watson

No, not necessarily. And I think we've -- we're pretty excited about we're finding around our home in McMullen County.

Operator

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

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

Actually, just going back to Brooks Draw for a bit. Could you just expand a little bit on what you were saying before about, I guess, you discovered that you weren't in zone as much in the past wells as you thought?

Robert L. G. Watson

That's correct. We've reprocessed and redone our 3D seismic and used that to kind of do a check on how we steer those wells. And the bulk of them were drilled in the year 2000, so the industry didn't have the capabilities that we have now. And yet, some of those wells have been very good producers, so we're hopeful that if we can get in there and steer and keep in the main target zone for most of the entire well board that we can achieve some exceptional results.

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

And what sort of lateral length are those going to be?

Robert L. G. Watson

Those are about 4,000 feet and that's pretty much limited by lease lines.

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

Okay. And do you have a sense of -- I mean, does it look like your past tries were only maybe half of the well barren zone or...

Robert L. G. Watson

Well, actually, less than that.

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

Really? Okay.

Robert L. G. Watson

Yes, and they weren't stimulated either. So steering the wells and then giving it a stage frac with -- I don't think we've decided whether we're going to cement the pipe in place and do plug-and-perf or use sleeves. But we're pretty excited about what that opportunity might present for us. And we own 100% of it at HBP acreage, we've got about 18,000 net acres, so it's not an insignificant asset for us.

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

Okay. Well, great, that's interesting. And just in the Bakken and Three Forks for a second, what do you feel comfortable as far as setting expectations for alternate spacing there? We keep hearing more and more about people getting increasingly aggressive. And in your main areas in particular, though I actually realize that it does vary across the basin, do you -- what do you -- are you thinking it's possible maybe you could have more locations out there than sort of the benchmark we've been using?

Robert L. G. Watson

Well, we're at 1,300-foot spacing. There are a lot of people that are dropping down to 600 feet, which is an easy additional location but in between each of our wells. We're monitoring that very closely. We're watching all of the guys that are testing those pilots. We'll be watching our -- the NDIC for actual production and results. We don't have to make that decision on spacing anytime soon. But if we do, and turn out that 600 feet is more appropriate than 1,300 feet, then we've got a heck of a lot more locations to drill with our drilling rig.

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

Great. And actually, what's the -- at 1,300, what's the location count you're now assuming?

Robert L. G. Watson

Well, we're drilling on 1,300-foot. Is that...

Geoffrey R. King

320.

Robert L. G. Watson

That will be 320-acre spacing. So we would be dropping that down to 160.

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

Okay. And your total locations at your current spacing, can you just refresh my memory what that inventory...

Robert L. G. Watson

I think we have 22 more. Geoffrey?

Geoffrey R. King

20.

Robert L. G. Watson

20 to 22 more.

Geoffrey R. King

Plus the unit lines.

Robert L. G. Watson

Yes, plus the unit line wells. So we've got maybe closer to 25 wells. And if we decrease the spacing, it more than doubles that because you would be decreasing the spacing between the existing producers, as well as the future wells. So that maybe gives us 55-or-so or 60 wells to drill in North Fork, which has been very good production for us. And that's a lot of years of drilling for our drilling rig.

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

Great. And just one last thing, any spacing differences you'd anticipate between the -- what you can do in the Three Forks versus the Bakken? I haven't heard people distinguish much between them but I just wanted to check.

Robert L. G. Watson

I don't think we see a whole lot of difference. Three Forks seems to be a little tighter, so it might be a more amenable to tighter spacing than the middle Bakken. But we just don't have the data yet. I don't think the industry has the data yet to make that differentiation.

Operator

Your next question comes from the line of Mike Scialla with Stifel.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

As you mentioned, Bob, the WyCross area goes non-op here pretty soon. I'm wondering, have you had any discussions with the new operator there to get a sense of what their plans are? And do you think they will continue -- I mean, you guys have obviously drilled some tremendous wells there. Do you think they will change the completion style? Or do you think they'll continue to run with what you've proven as a pretty effective completion style?

Robert L. G. Watson

Well, we don't know what their exact plans are. We have seen what they've told the Street where they plan to keep one rig drilling continuously in WyCross. I would hope they would not change our drilling and completion techniques because you're right, it is a winner. But time will tell. We've not have -- we have not had definitive discussions with them all along those lines, mainly because for the next 2 months, we're still the operator and we're still going to be drilling and completing wells ourselves. So time will tell.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

If you were operator, I guess, hypothetical here, would you be looking at -- given the success you've had on 40-acre spacing there, thinking about testing tighter spacing next year?

Robert L. G. Watson

Well, I don't know that we'll be comfortable with tighter spacing yet. We don't want to be out in the leading edge. We'll let somebody else with a bigger balance sheet prove that out for us. I think we're very comfortable in WyCross now drilling 300-foot offsets. In fact, we're drilling one right now as we speak. Whether that's going to be applicable across the entire play or not, again, time will tell. But we've -- we did not see any interference on our first 40-acre zipper frac between wells, which would indicate that the fracs did not extend more than 150 feet either way. But they might have gone right through that. I don't know. I don't think there's any way of knowing.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay, got you. And then in that Cave area, how does that compare to WyCross? Is it -- I know it's a -- it looks it's a little further south. Would you expect more in the gas condensate window there? Is it going to be similar to the kind of oil cuts you're seeing in WyCross?

Robert L. G. Watson

We think it's going to be pretty similar on oil cuts. The gravity might be a tad higher, 43 as opposed to 40, something like that. But the rocks look very similar. We feel very confident with it. We also feel very confident that our drilling and completion techniques down there will be top percentile of the surrounding wells, just like they are in WyCross. So we must be doing something correct, and we think we can continue it down there.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Great. Last one for me. In the press release, you had mentioned that you were pleased with the drilling of the Atascosa well. Can you elaborate on that at all?

Robert L. G. Watson

We had very significant shows while we were drilling that well. Much better than we saw in our Grass Farms well, which is the first well we drilled up in Atascosa. We also shot 3D seismic after the Grass Farm well was drilled and we used the 3D to steer. Because with the 3D information, we found out that the Grass Farms well was pretty much out of zone most of the well bore and, in fact, with possibly even an upper Eagle Ford test. So that, combined with the gas shows that we saw, we're pretty excited about what we're seeing.

Operator

[Operator Instructions] Your next question comes from the line of John (sic) [Ryan] Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

It's Ryan Oatman. Seeing improvement in operating costs on a per unit basis down about $12.50 a barrel, can you talk about what drove that? And how you feel about that number moving forward?

Robert L. G. Watson

Two pretty interesting concepts have occurred. One, most of our divestitures, including our non-op Bakken were very high LOE-producing barrels. So we're replacing high LOE barrels with very low cost, new flush production in both the Bakken and the Eagle Ford. That combination drove our overall down considerably, and we think that trend will continue going forward.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay, very good. And then with the Fairview Prospect in the Western Williston Basin, can you talk about the decision to divest that and plans for any proceeds there? Do you think you'll redeploy in the Bakken or look more towards the Eagle Ford?

Robert L. G. Watson

The -- we studied Fairview very, very closely, and it is an area that is getting more and more attention. We looked at our position being completely surrounded by a larger operator and thus, our ability to grow would have been extremely limited. We looked at the fact that the Three Forks has not been proven productive there, so we're just looking at one zone. We're looking at the overall results to date -- actual results to date even with the new completion procedures that several companies are talking about and just felt like that we could take a pretty good price and redeploy that money in either both the Bakken or Eagle Ford in our core areas and generate a higher rate of return. I think you're going to see, very shortly, that we're -- we've been successful in doing that and that was our decision process.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

That's helpful. And then one last one for me before I hop back in the queue. Any updates on Canada?

Robert L. G. Watson

That process is proceeding. We hope to have something to talk about before the end of the year.

Operator

[Operator Instructions]

Geoffrey R. King

No more questions?

Operator

There are no further questions in the queue at this time.

Geoffrey R. King

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

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