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Executives

Geoffrey R. King - Chief Financial Officer and Vice President

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

Analysts

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

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

J. Curtis Brewer - BLB & B Advisors, LLC

Abraxas Petroleum (AXAS) Q4 2012 Earnings Call March 15, 2013 11:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2012 Abraxas Petroleum Corporation Earnings Conference Call. My name is Shaquana, and I will be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to your host for today's call, Mr. Geoff King, Vice President and CFO. Please proceed, sir.

Geoffrey R. King

Thank you, Shaquana, and welcome to the Abraxas Petroleum Fourth Quarter and Year-End 2012 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 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 the 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 Commissions. I would encourage everyone to review the risk factors contained in these filings and in our press releases.

I will now turn the call over to Bob.

Robert L. G. Watson

Thanks, Geoff, and good morning. I don't intend to spend a whole lot of time on Q4 results. They are what they are. We're certainly disappointed in the production level, but we also understand that our industry is prone to delays beyond our control such as weather and mechanical issues.

The good news is those delays have been rectified. February and March production levels are very pleasing. I've heard comments that our production is relatively flat over the last 3 years, and so I thought I would dig you a little bit deeper into our production profile. And I think you'll see that we have increased liquids production over that time period 65%. But it just so happens that our liquids adds on a Boe basis have been about what we have lost on a Boe basis from natural decline of our gas production. We've spent all of our money in the last 3 years on liquids projects while we've neglected our gas projects, but that doesn't mean that they're not substantial. They are. They're just not a priority for us at this point in time with gas prices where they are.

Now that we're putting on high-volume oil wells in both the Eagle Ford and the Bakken on a relatively regular basis, we've now overcome this offset phenomenon, and we're seeing significant overall production growth. Q1 will be a bit lower than originally anticipated as year-end production issues still remained in January. But February, March levels give us confidence to keep overall 2013 guidance in place of 4,900 to 5,200 Boes per day average for the year. We will issue a March exit rate when that is available.

This 4,900 to 5,200 Boe average for the year would indicate an increase of somewhere between 20% and 28% year-over-year. In addition to setting up production growth, we've had a good year for adding proved reserves. Despite losing approximately 3 million barrels due to low gas prices, the gas is still there, they just are not economic, the prices we had to use under the SEC basis. And an additional loss from the sale of our Nordheim Eagle Ford assets, we still grew reduction of -- we grew proved reserves 3% and specifically, oil reserves, 30%.

In the Eagle Ford and South Texas and McMullen County, we drilled our first well early last year. In the first 10 months, the well has produced about 150,000 barrels of oil. With this encouragement, we started a one-rig continuous drilling program during the fourth quarter. We've now drilled 6 additional wells and are on a rig move to the seventh as we speak. We plan to continue this program through 2013, and we are adding wells production at a rate of less than one month per well.

We currently have 5 wells on production, one well starting flowback today and one waiting on a frac, which will be about mid-April. It is our practice to produce these wells on a restricted choke. None have been produced at a choke size larger than a 22/64-inch to date, and the last 4 wells have all tested in excess of 1,000 Boes per day each. These results to date far exceed our expectations.

On 80-acre spacing, we currently have about 60 gross (15 net) additional locations. And in addition, we have driven our cost down substantially to around $7 million or less, some of them even closer to $6 million for a completed well. These drilling economics, combined with Brent-like pricing of our Eagle Ford crude, is yielding some very compelling economics.

In the Jourdanton area, in Atascosa County, we are finishing a 3D seismic survey over our 100%-owned 4,500-acre block targeting the Beulah formation, as well as the Eagle Ford. We have one producing Eagle Ford well at Jourdanton. Up north in the Bakken, Three Forks and McKenzie County, North Dakota, our company-owned drilling rig walked this week to the Lillibridge 3H after successfully drilling the lateral in the Lillibridge 4H into the Three Forks Formation. After the 3H, 2 more laterals remain, which should put us on schedule to frac all 4 wells in May and on production shortly thereafter.

On the Raven Joy East pad, completion operations on the Joy 3H in the Three Forks Formation and the Raven 2H and 3H in the Middle Bakken commenced in October. The frac on the Joy went off without a hitch and the well's been on production ever since except for some weather and minor workover shut-ins. The Raven 2H and 3H, we weren't so lucky. Both encountered downhaul mechanical issues that required remedial work that resulted in a significant settlement with our third-party service provider, I might add. The fracs were completed in February, and both wells have been on production since. We're not as happy with the frac on the 2H as we were with the 3H. But the 2H is producing on our type curve while the 3H is producing well above our type curve. We'll be announcing 30-day rates on both of those wells here soon. After the Lillibridge East pad, the rig will move back to the Joy Raven East pad for 3 more Joy wells, 1 Three Forks and 2 Middle Bakkens.

Last year, we participated in 27 outside-operated Bakken Three Forks wells. And so far this year, we've participated in 11 more. Generally, no one represents a large capital commitment, but together they do. That's a planning and budgeting issue. We like to be in better control of our capital expenditure plus overall operations, so we've made the decision to sell most of our non-op Bakken interests.

East Spectrum, formally Energy Spectrum, in Dallas, is handling the sale, and the data room is scheduled to open next week. All total, we're talking about 14,300 net acres approximately and somewhere between 300 and 500 Boes per day of production.

The initial interest since we've announced the sale several weeks ago has been very strong, and we expect offers by early May and a close in June. I want to emphasize this is not a fire sale. If we don't get our value, we will not sell.

Out in West Texas in the Permian Basin, we've commenced a shallow oil well development program held by production leases on one of our deep gas fields in Ward County in the Delaware Basins. We have recently drilled 2 100% wells and set casing after encouraging shows while drilling which were confirmed by open hole logs. Completion operation scheduled -- are scheduled to commence in the near future. And if this is successful, it will lead to a multi-well drilling program for us on a 100%-owned land.

That's my update. Now we'll open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Noel Parks.

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

Just a couple of things. The last thing you mentioned was the Bakken sale, and you are not going to go through the transaction unless you're happy with the price. How long a process do you envision collecting bids and so forth before you think you'll decide one way or the other?

Robert L. G. Watson

The data room is scheduled to be opened about 4 weeks, 5 weeks. Bids are expected toward the end of April, maybe early May. I don't know that we've -- I'm sure we've set that date. I don't recall exactly what date it is. And then a close, late May, early June.

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

Okay. Great. And in the Eagle Ford, we've heard some other folks in the industry talking recently about continuing to have success staying in zone as they drill the laterals, and also recently heard something about another McMullen County operator saying that they actually were narrowing their target to a pretty defined interval that they were going after there. Can you give any insight on targeting on laterals, especially in McMullen there?

Robert L. G. Watson

Well, as you know, Noel, we do spend a lot of time staying in zone. We think that's of utmost importance for a successful completion. So yes, we do have a narrow target in the Eagle Ford that we are very comfortable that we're capable of staying in. Our geologists and -- are geo steering these wells 24/7. They've done an excellent job of staying in zone, and that could be one of the contributing factors to the very substantial success we've had on our wells so far to date.

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

Great. And can you sort of define maybe or break out the time periods where if we look in a well today and we compare it to a well, I don't know, how many months or a year ago, to sort of get a sense of before and after effect of the targeting?

Robert L. G. Watson

We have stayed in -- attempted to stay in target from Day 1. We just recognize that's very important in drilling these laterals. So I wouldn't say that any of -- none of our wells have been out of target for a substantial area yet. And I think on our website now, we do have our Eagle Ford type curve and the actual day-to-day production of all our wells. And you can see that all of them are performing well above the type curve that we've been given reserves for, and I would say that that's a pretty good proxy to the benefits of staying in zone.

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

Got you. And just one last one for me. Realized pricing was a little bit weaker than I had expected for the quarter. Was there anything going on there? I think it might have even been more pronounced on the gas side.

Robert L. G. Watson

Probably was. Actually, I thought we were a little bit higher than consensus. And that would probably have been the impact from the Brent-like pricing that we're getting in the Eagle Ford, which is currently about $12 or $13 above WTI. And certainly, as we add Eagle Ford wells going forward and that Brent-like pricing remains, our differential should squeeze considerably. So I guess our expectations, we did better than we thought. I'm not familiar with yours exactly. So it's hard to address why we busted what you thought.

Operator

Your next question comes from the line of Welles Fitzpatrick.

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

I know it's probably minutia, but just to get a number, the production on the May clearinghouse package, do you guys have a number on that?

Robert L. G. Watson

Yes. It's been the -- it's in our offset data, I think. It was about...

Geoffrey R. King

For the March auction? 2.9 million.

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

2.9 million, thanks.

Robert L. G. Watson

That was the dollars. What was the production associated with it?

Geoffrey R. King

Sorry, 27 barrels a day and about I think 200...

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

I'm sorry. I apologize. I'm talking about the one that you mentioned doing at the next clearinghouse auction.

Robert L. G. Watson

That's a smaller amount of gas volumes. It's all gas, though. There's no oil in the May auction.

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

Okay, perfect. And then, am I eyeballing the type curve right to say that the Raven 2H is going to be about 500 over its first month and then the 3H will be north of that when you say that it's meeting or exceeding?

Robert L. G. Watson

I don't have that right in front of me. I would say that the Raven 2H is -- do you remember? Right on the curve or…

Geoffrey R. King

Yes, we think it's 6 more barrels of oil, which 400 barrels of oil a day.

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

Okay, perfect. And then one last one, and I know this is kind of old news because you guys had already released that 6.1 number, but obviously with the well result, it becomes a little bit more important. Can you give us a reminder where that -- those savings were coming from to get down to the 6.1?

Robert L. G. Watson

Well, pumping costs are down substantially, and our drilling efficiency is up substantially. We're using considerably less days to get these wells drilled. Our bit selection is excellent. We're getting most of the well drilled with one bit. So when you can do that and avoid extra drilling time, you can really save a lot of bucks.

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

Perfect. So now that's coming from design, then?

Robert L. G. Watson

We're always tweaking our design, but I think our design is dictated by what we've tried from a mechanical standpoint in previous wells. And what's working, we're implementing in newer wells, and that's speeding us up that much more.

Operator

Your next question comes from the line of Curt Brewer.

J. Curtis Brewer - BLB & B Advisors, LLC

I just had a couple of questions. One is, I was reading an article recently about -- I think it might have been Devon, but I don't recall exactly who it was, one of the larger producers, that they have gone through experimentation to a process of drilling the laterals from drilling long 3,000-, 4,000-foot laterals to drilling much shorter laterals kind of on a radial basis around the core borehole. And in some cases, have been able to get flows of upwards of 6,000 barrels a day. For how long, I don't know, but is that technology something that we're looking at?

Robert L. G. Watson

Well, we're following it, Curt. I don't think it's applicable in the shales that we're working in. I'm not aware of it anywhere in the Eagle Ford or the Bakken. I think they're experimenting with that in some of the West Texas shales. So certainly, it's something -- we're always looking at what the industry's doing. It's not always easy to get that information. Some of the bigger companies keep it pretty confidential. But I think we're on top of what's going on in the Eagle Ford and the Bakken, and that's what counts for us.

J. Curtis Brewer - BLB & B Advisors, LLC

Yes, it sounds like it when I see the flows that you're getting, well above your anticipated curve. The only other question I had has to do with, again, the result of some study of -- seeing quite a bit being written now about the Permian, that there are now 400 rigs drilling there and a lot of excitement having to do with the Cline Shale indicating that perhaps there's another 35 million barrels of oil down in there on top of the 35 that have been taken out of the play since 1917 or whatever. And I know we have activities in the Permian. Are we in an area that would include the Cline Shale and is what I'm reading viable or is it a little bit of hype?

Robert L. G. Watson

I think it's certainly of interest. It's still early stage. And specifically for Abraxas, 2 of our rather large held-by-production acreage blocks have now been offset by Devon, Cline Shale wells. One of them is on production. We're getting daily production from that well. It appears to be very commercial. It's within less than one mile of our Millican Reef held-by-production acreage. Our Spires Ranch has been offset by a direct offset, 500 feet off our lease line by a Devon, Cline Shale well. And at our last report, they were installing artificial lift equipment on that well and building a tank battery. It's not quite on production yet, but we're certainly watching them very, very closely.

Operator

I would now like to turn the call back over to Mr. Geoff King.

Geoffrey R. King

Okay. Thank you. We appreciate your participation 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 your participation in today's conference. This concludes the presentation. You may now disconnect, and have a great day.

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