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Abraxas Petroleum (NASDAQ:AXAS)

Q1 2013 Earnings Call

May 10, 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

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

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

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

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Evan Richert - Sidoti & Company, LLC

Stephen F. Berman - Canaccord Genuity, Research Division

Joel P. Musante - Euro Pacific Capital, Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Q1 2013 Abraxas Petroleum Corporation Earnings Conference Call. My name is Karen, and I'll be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I'd like to turn the call over to Geoff King, Vice President and CFO of Abraxas Petroleum Corporation. Please proceed.

Geoffrey R. King

Thank you, Karen. And welcome to the Abraxas Petroleum First 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, Bill Krog.

As a reminder, today's call is being taped and a webcast replay will be available immediately after the conclusion of the call.

Before I get started, I would like to remind everyone that the statements made during this call that are not statements of historical facts 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 you, Jeff. Good morning.

Crude oil production continued to increase, up 8% in the first quarter over the fourth quarter of 2012. We've actually experienced an 81% growth in liquids production since the first quarter of 2010. Production for Q1 was 4,216 BoEs per day, up 2% over the fourth quarter, despite a very tough January that averaged around 3,700 barrels per day due to weather and third-party gas plant outages.

Our March production averaged about 4,500 barrels per day, showing the contribution of our recent Eagle Ford and Bakken completions.

As testimony to the success of our oil-directed capital program, oil and liquids represented 58% of our production stream for the first quarter, and I might compare that to the first quarter of 2010, where oil and liquids comprised 34% of our production strength. Our increasing oil production now more than offsets, on a Boe basis, the natural decline from our gas properties, thus overall production on a Boe basis begins to increase.

With continued success of our Eagle Ford and Bakken, we're very confident that our 2013 average production guidance of 4,900 to 5,200 barrels per day is achievable, and this is despite the property sales that we've had to date.

On a Boe basis, oil generates considerably more revenue than gas. Consequently, cash flow is increasing nicely.

In the Eagle Ford, since the beginning of the year, we placed 4 wells on production at average 30-day rates on restricted chokes of 998 barrels of oil equivalent per day. Our rock star Mustang 3H has produced over 55,000 barrels in 53 days, and we'll pay out at $6.2 million well cost in about 3 months. Apparently, we have 1 additional well on production for less than 30 days and 2 more wells drilled with casings set to total depth waiting on frac, which should start in about 2 weeks, we expect to frac both of these wells back to back.

The latest well, the Corvette A1H, was drilled in record time, 12 days from spud to total depth of 15,000 feet, which is a pretty good start on a potential cheapest well cost yet. The rig will be moving shortly to the Camaro B pad for a 2-well 40-acre spacing pilot. And I might remind you that Abraxas owns 18.75% to 25% in all of these McMullen County Eagle Ford wells.

In North Dakota, the first quarter saw very difficult weather conditions, hampering all operators' production and drilling operations. We placed 2 operated wells on production at average 30-day rates on restricted chokes of 524 barrels of equivalents per day. Both of these wells we consider incomplete completions due to the previously discussed mechanical issues where I might add we've received a very significant settlement from third-party service provider, and we certainly expect future wells to be much better.

We've almost completed drilling operations on the 4-well Lillibridge East pad, 2 Bakken and 2 Three Forks. The last well, the Lillibridge 1H, is drilling the lateral below 15,500 feet this morning toward a 20,000-foot target.

Extremely -- because of the extremely cold weather, road bans are in place in North Dakota now as the frost comes out of the roads, and they're expected to be in place till sometime in June. Because of this, we changed our drilling schedule. We now plan to walk the rig on a lease road to the Lillibridge West pad, 4-well pad, 2 Bakken, 2 Three Forks. And by doing this, we should avoid a potential delay from not being able to get trucks on the state and county roads. The 4-well Lillibridge East pad wells should be frac-ed as soon as road conditions permit, and hopefully, be on production in June. Abraxas owns a 34% interest in the Lillibridge East pad. At this point, it looks like without completion issues, the Lillibridge wells will average about 8.5 million each, completed and on production.

Plans going forward for Abraxas are to continue a 1-rig program in both the Eagle Ford and the Bakken for the foreseeable future. We'll continue pad drilling in the Bakken, which means 4 wells on production at once. And we're going to begin pad drilling in the Eagle Ford to hopefully reduce our costs even further, which might make production adds going forward a little bit more lumpy, but they will be there nonetheless.

On the divestiture front, we continue to have success in selling small properties at fair value. They are small, but they all add up. Proceeds are used to pay down debt and increase liquidity. We're now completely out of Oklahoma and Louisiana. And we're currently negotiating bids on a much bigger package, our Bakken non-op properties, and we hope to have that resolved in the near future. We said all along, our divestiture program would be a measured process where we would only sell for fair value. Sometimes, this takes longer, but eventually, it gets done.

That's all I have for you this morning, so we'll open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] 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 divestitures. Do you guys have a timeline for when you hope to get the non-operated Bakken sold?

Robert L. G. Watson

All I can say right now is we hope to have it done in the near future. I'm not going to put a specific date on it, but it should be, hopefully, right around the corner.

Will Green - Stephens Inc., Research Division

Got you. And then you mentioned plans to frac the Lillibridge pad soon, where should we expect that rig to go following that?

Robert L. G. Watson

Well, I just said, we were going to walk the rig on a lease road to the Lillibridge West pad so we can avoid the road bans that are in existence right now and avoid a potential delay because we can't get trucks on the county and state roads.

Will Green - Stephens Inc., Research Division

Got you. I didn't realize you were talking about a separate pad, I apologize for that. And then in your slide show, and I think maybe even in IPAA, you talked about how the Bakken well so far has been outproducing the type curve, what do you think the average EUR those wells are on track to produce at this point?

Robert L. G. Watson

Probably 400,000 barrels of oil, which is going to equate to about 475,000 Boes, which is -- they're actually a little bit above the type curve, but that's our type curve number, which the D&M has given us for all our puds. So hopefully, we'll stay above that curve and they'll actually do a little bit better than that.

Operator

Next question comes from the line of Welles Fitzpatrick from Johnson Rice.

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

At IPAA, you guys mentioned that you were thinking about doing some 300 foot spacing test, if I remember correctly, in the Eagle Ford. Can you talk us through your plans there?

Robert L. G. Watson

That's the 40-acre pilot that we're moving to, rig will probably be moving Monday or Tuesday. We'll drill both of those wells back to back, 300 feet apart, and frac them, zipper frac and see what the results look like.

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

Perfect. And then on the Turner frontier acreage, if I'm remembering that one correctly, you guys had about 2,000 in Campbell, maybe 16 in Converse and Niobrara counties, is that still about right? And what did the Hedgehog end up tracking on a type curve basis?

Robert L. G. Watson

Well, the Hedgehog is extremely good. I don't know that we had a type curve on it. This is one of the first wells drilled in the play. But it certainly has far exceeded our expectations. It's probably going to make 2 Bcf of gas, plus or minus, and a bunch of condensate and liquids, so definitely an economic proposition. We would like to increase our presence up there and are trying to do so. This is an area of convoluted federal leases that are basically held by production, it takes a long time to get deals done. And so -- but we're -- we've decided that it's an area that we want to expand in, so we're trying to get some deals done to expand our presence. All of our acreage is held by production, so we're not in any big hurry to drill wells. We've got plenty of other places to spend our capital anyway. But I think it will be certainly an area of activity for us in the future.

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

And in Campbell, obviously, EOG was drilling a good deal about or around you guys with success, did they ever end up AFE-ing you all in any wells?

Robert L. G. Watson

No, we have not received an AFE from any outside operator, EOG does have lands around us, and they are very, very active. They're announcing new locations, new permits every week. So they obviously like what they're seeing and of interest, they're also targeting some additional zones with multiple wells on same pads going to different zones. So that's an attraction to us as well.

Operator

Next question comes from the line of Ryan Oatman from SunTrust.

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

I wanted to ask on Canada here. Can you just remind us where you are in that process up there in Canada?

Robert L. G. Watson

Yes, thank you for asking that, I should have mentioned that. We have drilled a vertical well into the Duvernay Shale. We took a full core of it. That core is still sitting at Core Lab being analyzed, we don't have -- we have some of the results so far, but not all of them. And we really can't make any plans until we get all those results back. So we're not being hampered too much, road bans are on in Alberta as well, and they expect road bans to stay in place until about middle of June. So we couldn't get any work done anyway. And hopefully, by mid June, we'll have the results -- the completed results back from Core Lab and make some decisions on which way we go forward.

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

Okay. Very good. And then just following up on this down spacing in the Eagle Ford. When do you anticipate communicating results from that test?

Robert L. G. Watson

30 days production will give you -- that's our normal procedure. Once we have a 30-day average rate, we'll announce those and we'll probably talk about what our feelings are as far as the communication between the 2, and if there's an impact, then we'll start making decisions then on whether we feel like that's the way to go forward.

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

Okay. And then is there a chance to add to your acreage there down in the Eagle Ford or do you feel like most of that's pretty well leased up around you?

Robert L. G. Watson

There is some potential to add little pieces here and there we feel comfortable with, and we will certainly attempt to do that on an economic basis. And I think that's the niche that we fill, on a go-forward basis, is being able to do smaller deals than a lot of guys do because small deals mean a lot to us. You eventually drill these things on a 40-acre spacing, 640-acre track gives you 16 locations, and that's 1.5 years worth of drilling for us.

Operator

Next question comes from the line of Noel Parks of Ladenburg Thalmann.

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

Just kind of a general sort of strategic question. So you're in the process of -- or you just exited a couple areas through the auction of properties, and as you look at the emerging stuff you're working on, the Duvernay, and seeing what's going on in the Turner, and I guess, ultimately, maybe seeing what the industry is doing in the Permian, do you have a sense of -- kind of strategically, which of these might be the most suitable for you to actually proceed down a development path? Just thinking in terms of -- as we've seen, you have encountered some really good stuff that's proved to be so -- in other basins, it's proved to be so capital-intensive that it's maybe not the best focus for you guys? So just can you sort of maybe rank the areas in terms of that?

Robert L. G. Watson

I would say, just because of sheer size, the Permian probably represents more upside to us than the Turner in Wyoming because we have so much more acreage. The advantage we have and the reason we don't feel a lot of pressure to get something done is essentially all of our acreage is held by production. And consequently, we can sit back and watch the industry. We don't think we know everything about either of those plays. There's a lot of going on in the Permian that I don't think anybody knows the true answer of what's going on, so we have the advantage of sitting back and watching, letting them spend the money to prove it up. In the Turner, we would like to increase our presence, and we're working on doing that as a potential 2014 drilling program for us. But if you're asking me to rank, I would say, today, I would say it would have to be the Permian just because our presence is so much larger.

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

Sure. And the 1 trade-off about being HBP and waiting for data from other operators, of course, is that, if you're one of the earlier folks drilling and you get good news, it's easier to be a little bit more aggressive if you're looking for new acreage and so forth. Do you think though that being in the Permian or having been in the Permian so long, maybe on the land side, do you feel like you have any advantages as opposed to maybe some of the other newer entrants there?

Robert L. G. Watson

I don't think anybody has any advantages, it just takes money. And I would say that our near-term focus is increasing our presence on the operated Eagle Ford and operated Bakken. And we'll just sit back and wait to see what really happens in the Permian. I think in -- as in all resource plays, there's going to be sweet spots and there's going to be ways of doing things that make more sense than others, and there will still be time to react, although it might cost you a little bit more money, at least you know that what you're getting is worthwhile. And so in the meantime, we'll concentrate on the Eagle Ford and the Bakken.

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

Okay. And just 1 more. And sorry if this too vague a question. But just, again, with your long experience in the Permian, do you think there's still any areas out there maybe that were traditionally targeted for gas where people haven't quite gotten around to thinking about maybe horizontal oil possibilities that just aren't obvious?

Robert L. G. Watson

I think there are definite areas. We've done a lot of geological and geophysical work and engineering work. We actually have some ideas that we might want to pursue. But we're not going to take on debt to do that. We're going to wait until we have a pristine balance sheet, and then we'll make decisions on whether we go forward or not.

Operator

Next question comes from the line of Hsulin Peng from Robert W. Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

So Bob, you had mentioned that several of your Eagle Ford wells are performing above your type curve. And I think your type curve is currently at 5 75. So I was wondering if you can kind of help us quantify what -- a bit on the production rates, what the equivalent EUR you would -- you think would be for the wells you have drilled so far, and when do you think you can revise the EUR?

Robert L. G. Watson

I think all of the wells that we have in the Eagle Ford are performing above our type curve, so I think we have a lot of ammunition for our midyear reserve report, which we'll have a June 30 effective date to have an increase in reserves. What that ultimately will be, I don't know, I have not seen the work, we have not done the work yet. But I feel pretty comfortable from a directional standpoint that it will be a nice upward revision. And that, hopefully, will impact our pud bookings as well.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. So we'll wait for midyear reserve report?

Robert L. G. Watson

Correct.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. And then shifting to the Lillibridge pad, you mentioned that well cost there is $8.5 million average each. I was wondering, does that include the impact from your own rig, the cost savings on there? And if not, can you quantify that cost savings on your own rig?

Robert L. G. Watson

Well, according to SEC, we cannot do that. We tried to give an indication of the value that, that rig is adding in our press release from a profitability standpoint. But the $8.5 million does not include that impact. And if you take that $1 million of cash flow in the quarter and divide that by 3 wells that we were drilling, you're going to knock off $300,000 per well on our well costs. That's the way the SEC makes us book it. On a cash flow basis, it's actually even a little bit more than that because the $1 million was actual earnings. So on a net cash out the door, maybe it goes down to $8.1 million, $8 million.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay. Got it. And then last question is regarding infrastructure build out ahead of the pad drilling. I think you generally have all the gathering lines ready prior to completion. Can you just talk about how you'd do that? And also in -- and yet you've seen this help [ph] generally, how you make sure you -- if you have the infrastructure ready for Lillibridge pad?

Robert L. G. Watson

The infrastructure is in the works, they're being delayed by the road bans unfortunately. But hopefully, by the time we're ready to produce, they'll be ready to take both the gas and the oil. As you know, we don't like to flare gas, that's money going up in the air. We've had pipelines into our other pads before we were ready to produce. so I -- hopefully, we'll continue with that. Unfortunately, you can't predict weather. But certainly, that's our goal to have both the oil and gas gathering lines into the battery when we're ready to turn them on.

Operator

Next question comes from the line of Evan Richert with Sidoti & Company.

Evan Richert - Sidoti & Company, LLC

I heard you talking about the 1 well you had drilled in just 12 days. I didn't catch the name of that one. But I was wondering if you could just talk generally about the trend you're seeing in drilling costs either per Boe or on Mcf basis?

Robert L. G. Watson

It was the Corvette A1H down in McMullen County. And yes, that was our record so far, 12 days from spud to total depth. That's probably right at 7 days or a little bit less than 7 days of actual drilling time in that time period. Costs on a service company basis, they've kind of plateaued at a lower level. The costs that we are saving now are principally from our learning curve, being able to do things a little bit quicker and knowing which corners we can cut and which ones we couldn't. Hopefully, that will continue. I don't see that we're going to see a dramatic decrease in costs from here, like we've experienced over the last 6 or 8 months. Hopefully, pad drilling will allow some. It's not going to be a huge decrease. But these wells at $6 million are extremely economic. And so there is certainly no reason to change our plans because of the cost structure that we're currently experiencing.

Evan Richert - Sidoti & Company, LLC

Sure. And as far as the balance sheet goes, obviously, you made it a priority to delever a little bit. I was just wondering, going forward, as production goes up and cash flow goes in, if you're happy generally with the kind of the level you're at now with the balance sheet or if you'd looked to offset that in addition to obviously spending on land and drill bit?

Robert L. G. Watson

The game plan here is to sell the extraneous properties and pay down debt. And then it goes to cash flow. We see several years of good solid double-digit production growth in the commodity price environment, cash flow growth, with just spending our cash flow. So our goal is to delever and keep it delevered going forward. And then if we get to be the size of the company we want to be, then we'll certainly look at financing growth opportunities in the future wherever it makes sense.

Evan Richert - Sidoti & Company, LLC

Okay. But you don't expect any sizable difference in the near-term really, that's more of a long-term?

Robert L. G. Watson

Correct.

Evan Richert - Sidoti & Company, LLC

Okay. And as far as hedging strategy, any change there as gas prices have been on the way up within the last month or so, generally, they've been coming up, any changes to your plans there?

Robert L. G. Watson

Well, we're completely unhedged on gas. Geoff and I look at it quite frequently as to what to recommend to our board to do. We have a board meeting this next week, so certainly, it will be a topic of conversation. On the oil side, we are heavily hedged out for a number of years. We feel very comfortable with that position. We've hedged most of our production on a WTI basis. But we've also started layering on a Brent hedge because our Eagle Ford oil sells on a Brent-like basis. And so we feel pretty comfortable with that. Right now, today, we're at about 90% of our crude oil production is hedged. If it continues to grow like it's growing, by the end of the year, that will be down in the 50% to 60%, and so we'll look at layering on some more hedges during that interim period to keep us pretty heavily hedged.

Operator

Next question comes from the line of Steve Berman from Canaccord.

Stephen F. Berman - Canaccord Genuity, Research Division

Bob, any -- the Ward County acquisition certainly looking good with gas in the 4s. Any update on those 2 Yates wells, 2 Wilkes wells you're drilling?

Robert L. G. Watson

We just perforated the last -- or not the last, the middle -- there's 5 zones that we wanted to test. We tested the first -- the 2 lowest zones which were -- had the poorest shows and determined that they were not commercial. We're now testing the third zone from the bottom where we had pretty good shows. We are getting some oil out of it, so we'll be looking at stimulation opportunities here shortly. And we've got 2 more wells -- 2 more zones up hole [ph] where we also had good shows while drilling, which we'll be testing individually, and the purpose of the individual tests is basically to design a development program going forward. We want to know which zones to concentrate on and which ones not to spend any money on.

Stephen F. Berman - Canaccord Genuity, Research Division

All right. But as you sit here today, any further plans to drill more wells or is that all dependent on what happens with these 2?

Robert L. G. Watson

Yes. It just depends on what happens to these 2. We want to see, not only if they're productive, but how productive they are and give us an idea on the reserves, we pretty much know what it's going to cost us to develop them. We think it's a very, very economic project, but we just need to prove that to ourselves first.

Operator

Next question comes from the line of Joel Musante of Euro Pacific Capital.

Joel P. Musante - Euro Pacific Capital, Inc., Research Division

Yes, I just had a few questions about liquidity and capital spending position. How much of your $70 million budget was spent so far and how much is left? And if you expect the borrowing base to get redetermined higher? And then just if you can comment on the working capital deficit if -- how much of that is just mark-to-market derivatives and how much of it might come due in the next year?

Robert L. G. Watson

I'll let Geoff answer that.

Geoffrey R. King

Our capital spending throughout the year is pretty stable, I guess, you could say on a quarter-to-quarter basis. It's not going to go -- be a lot higher this quarter or next quarter, just given the nature of what we're drilling. As far as the working capital deficit goes, one of the strategies we implemented was to bring down our payables periods pretty substantially. So now, all 60 days and under, which is probably top decile for E&P companies out there. So we feel pretty comfortable with where we are on a working capital basis and where our payables are. So I think you'll -- given -- that crept up mostly just given our level of activities. So I think, heading forward, you can just anticipate that will stay pretty steady. So that's where we are there.

Robert L. G. Watson

And as far as redetermination goes, yes, we do expect an upward revision next redetermination, just because we had very little impact to our borrowing base from our Eagle Ford wells last redetermination, and we feel like there's substantial increase due for that one. And hopefully, by the end, the Lillibridge wells will be on production, so we'll get a substantial increase from them as well. So we feel pretty comfortable with our bank group and with the borrowing base and feel like that we'll have more available to us should we need it. And we'll determine that in August, September timeframe.

Joel P. Musante - Euro Pacific Capital, Inc., Research Division

Okay. And then just on the CapEx, -- I guess, what you said, I mean, did you spend about, I don't know, $18 million during the first quarter or I mean somewhere around that or?

Geoffrey R. King

Yes, it was about there, and I'd just anticipate that'd be relatively stable throughout the year. I was just going to say, the only one-off thing in this quarter was just those 2 Ravin completions, which came through.

Joel P. Musante - Euro Pacific Capital, Inc., Research Division

Okay. And what -- that well in the Eagle Ford that -- what was -- I didn't get the payout period for that, it was 55,000 barrels and 53 days?

Robert L. G. Watson

About 3 months. And that's a combination of the production rate plus Brent pricing on the crude. It's throwing off pretty good amount of cash. And against a $6.2 million total well cost, you can do the math and see how it gets there.

Operator

[Operator Instructions] Thank you very much, ladies and gentlemen. I'd now like to turn the call back over to Geoff King for closing remarks.

Geoffrey R. King

Thank you, Karen. 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 for joining today's conference. This concludes the presentation. You may now disconnect. Have a good day.

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