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Abraxas Petroleum (NASDAQ:AXAS)

Q2 2012 Earnings Call

August 09, 2012 3:00 pm ET

Executives

George William Krog - Chief Accounting Officer and Treasurer

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

Peter A. Bommer - Vice President of Engineering

Analysts

Will Green - Stephens Inc., Research Division

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

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

Irene O. Haas - Wunderlich Securities Inc., Research Division

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

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

J. Curtis Brewer - BLB & B Advisors, LLC

Operator

Good day, ladies and gentlemen, and welcome to the Abraxas Petroleum Corporation earnings conference call. My name is Carol, and I'll be your coordinator for today. [Operator Instructions] As a reminder, ladies and gentlemen, this conference is being recorded for replay purposes.

It is now my pleasure to turn your presentation over to Mr. Bill Krog, Chief Accounting Officer. Sir?

George William Krog

Thank you, Carol. Good afternoon, and welcome to the Abraxas Petroleum Second Quarter 2012 Earnings Conference Call. Bob Watson, President and CEO of Abraxas, joins me today for the call. In addition, we have our VPs of 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

Thank you, Bill, and good afternoon. First thing I wanted to do today was walk you through a couple of transactions that we announced yesterday. The first one will be the Eagle Ford transaction with Blue Eagle Energy, and I think a full cycle summary is probably in order.

Two years ago, we formed a joint venture with a private equity-backed Denver independent, Abraxas contributed 8,300 net acres, and keep that number in mind, and the -- our partner contributed cash. In that time, we've -- since that time, we've now drilled 4 wells, 3 of them were operated by Abraxas and we own -- the joint venture owns 100%. And one of them was operated by Talisman in which the joint venture owned 44%. We derisked a considerable amount of our acreage. During that time, we also acquired an additional 4,000 net acres.

And about 6 months ago, the Eagle Ford was really hot in the transaction business and we decided we would capitalize on that hot market and so we started the sale process. We have very valuable properties and we expected a very high value. We actually received several offers that met our value expectations and a couple of which we agreed to negotiate further. During the negotiations, the oil market took a nosedive and the market turned into a risk-off mode. Transaction volume in the Eagle Ford as well as other areas in the country dropped precipitously and unfortunately, our offers went down as well, below our expected value.

So we now have done the next best thing. We've entered into an agreement with our partner to dissolve the joint venture, distribute the assets fairly to where each party can use them to their utmost benefit, and now we are here 2 years later to the month -- 2 years to August. When this deal closes, hopefully in early September, Abraxas will walk away with 8,000 net acres, 205 barrels of equivalent production, which is 73% oil and liquids and approximately 6 million barrels of equivalent 2P reserves, and these are D&M year end reserves, they're not in-house. And at our midyear, we expect the proved reserve portion to grow substantially. One of our areas has no booked reserves, so it definitely has acreage value without double dipping into the reserve value. And another area only has one PDP producing well given reserves and nothing else. So therefore, it has upside for acreage value as well, without double dipping into reserve value.

And finally, we're going to walk away with $8 million to $9 million cash. If you'll notice, nowhere in this summary did I say anything about Abraxas investing $0.01 in cash. So I would say this is a pretty good rate of return for Abraxas and our shareholders. We still have fabulous properties and a great rate of return play for another day. And although failure to consummate a transaction in our numbers is somewhat frustrating to me, I think given the times and the asset quality, I'm very comfortable with the outcome. We now have 4 -- 3 focus areas, the South Texas, including the Eagle Ford; Williston Basin, including the Bakken; and West Texas. And all of our other areas, we feel comfortable in transacting on one way or another.

The other transaction we announced yesterday was in West Texas, and I go back to 1994 when Abraxas originally brought -- bought these legacy assets in Ward County, properties that have, for the most part, previously been owned by major oil companies. We soon thereafter found a shallow oil field on them. It's called the Abraxas Cherry Canyon field, and that field has now produced over 5 million barrels of equivalents to date and still producing.

In 2000, a large independent approached us to farm out our deep rights for cash and a carried interest. If that deal had been done today, it'd been called a joint venture. But anyway, back then we called it a farm out. That major independent successfully drilled 7 horizontal gas wells into the Montoya formation, and since that time, we've jointly operated the field. Opportunities to buy out a partner don't come around very often, especially at a very low point in the natural gas price cycle. We were able to buy these properties for $7.2 million, which was about plus or minus $7 million after closing adjustments, and we got 6.9 Bcf of D&M PDP reserves. These are long life, very low decline rate gas wells, currently producing about 240 barrels of equivalents per day, about 95% gas.

In an area where Abraxas, several years ago, had to debook a significant number of PUD reserves due to the SEC 5-year rule. Those PUD upsides are still there, they haven't gone anywhere. The land is all HBP, and we didn't have to pay $0.01 for it. We now operate the entire field. I would expect some significant lease operating expense savings because of that. We've identified a number of low capital cost enhancements and production optimizations to increase production. And more importantly, gas prices are up about 50% from what -- where they were when we were doing our deal economics. This is a great gas -- natural gas option value for Abraxas and our shareholders in an area we know very well.

Now on to liquidity. Obviously, a very high priority at Abraxas, who has a goal to become more liquid over time. There are 2 ways to get that. You can shrink a company by selling assets and paying off debt, or you can grow a company and increase collateral under a borrowing base. In this market, I think you would agree that size matters. So I would argue that the latter is better than the former, which is exactly what we've done. We've been criticized in the past for running too close to our limits, but I've always felt comfortable doing this because I knew I had the Eagle Ford reserves and now the additional West Texas assets in my back pocket. And I knew I could achieve collateral value one way or another with them.

Very soon, our midyear reserve report will be finished. We've promised to get that to our bank group in -- within several weeks. Part of it's done in-house and part of it, the Eagle Ford portion, is actually going to be done by DeGolyer and MacNaughton. Our goal is to have a redetermined borrowing base done before the end of the third quarter. In the interim, the expected cash from the Blue Eagle transaction will be used to pay down debt. And on a go-forward basis, Abraxas is very fortunate in that we now operate essentially all of our assets. This West Texas acquisition was the last property of any size that we didn't operate, and we now operate it. Most of our properties, as you know, are held by production. So we feel like we are in utmost control of our capital expenditures, and we have the ability to match CapEx with liquidity. We expect, going forward, the cash flow and prudent use of our bank debt will be used to fund our capital expenditures for the remainder of 2012 and on through 2013. Keep in mind that we have this group of valuable assets outside our core areas that we feel very comfortable transacting deals on.

Now on to operations. In the Bakken, our rig is running well. We've got 2 wells down with liners and 35 packer set in each at around 21,000 feet in the middle Bakken, and we're getting ready to start a third well on the pad. This one will be targeting the Three Forks. It was a little out of order due to some crazy federal regulations that basically say, if you include one acre of minerals in your -- federal minerals in your unit, then the Feds have jurisdiction over the wells and the entire unit, even though the surface location and the well location is on private fee land. So anyway, we're a little bit out of order, but we'll have 3 wells done here shortly. Abraxas owns 50% of the first 2, 76% of the third. At that point, we plan the rig -- to move the rig to a 4-well pad, in which we currently own about a 25% interest, but we're hoping to trade that up before we spud the first well. These first 3 wells, 2 of which have now been drilled, are scheduled to frac in late September, early October. We're not in any real big hurry because the gas company, unfortunately, has been delayed in getting the gas line to the pad and we don't like to flare gas anyway. But certainly, expect these wells to be on production October timeframe.

After this 3-well pad is done, we have at least 26 more operated wells in the North Fork area of McKenzie County. And unless an opportunity comes up to where we can earn very, very beneficially, additional land by moving the rig elsewhere for a while, we plan to stay here. And at the end of that -- those additional 26 wells, we expect the rig to be pretty much paid for.

Now down into South Texas and the Eagle Ford. Our Cobra well, as we announced, in the WyCross area of McMullen County has now produced over 100,000 barrels of equivalent, 90% oil, since March, still flowing strong. Once we conclude the Blue Eagle transaction, we expect to commence a one rig continuous program for up to 10 wells. This would be about plus or minus 2 net wells to Abraxas. We hope this program will start in September. And by doing so, we will HBP all of the land in McMullen County and additionally, we will earn some additional acreage in the immediate vicinity by drilling some wells to earn it. Out in West Texas, we have one well drilling. Our Spires Ranch 89-1, in which we own 100% interest, is currently at 7,400 feet toward an objective of 10,300 feet, which would include a 3,500-foot lateral in the Strawn formation.

Finally, a comment on production growth. As we announced, including our share of Blue Eagle production, production was up sequentially 12% quarter-over-quarter; and even excluding the Blue Eagle production, it was up 10% sequentially. All of this was organic growth due to the success that we've had in drilling wells in the first half of this year. This number could have actually been a little bit higher, but due to the low gas prices during the quarter, we elected to keep some West Texas gas shut in instead of performing routine maintenance. Gas prices have now improved. The maintenance has been done and that production is back online. In the third quarter, under GAAP accounting we get to add the West Texas acquisition starting August 1, even though it was effective May 1. And if the Eagle Ford closes on time, we would expect to report the Eagle Ford production directly as of September 1. And during the fourth quarter, we expect to have 3 operated high working interest Bakken wells online for most of the quarter. So you can see the production growth for the remainder of this year looks good.

With that, I'll open it for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question will come to you from the line of the Will Green of Stephens.

Will Green - Stephens Inc., Research Division

I guess starting on the Eagle Ford, is the plan to kind of pad drill that -- the McMullen drilling schedule you've got, is the plan to pad drill that and zipper frac?

Robert L. G. Watson

Not initially. We will be in a acreage retention and earning mode for the first set of wells. And then once those wells are drilled, all of the acreage will be owned and held. And at that time, we can consider a pad development program. We recognize that that is the way people are moving. But in this one specific area, we have an opportunity to earn a whole bunch more acreage by drilling wells and we want to do that.

Will Green - Stephens Inc., Research Division

Got you. Can you expand a little bit on the drill to earn down there?

Robert L. G. Watson

I can't yet because those negotiations are still ongoing.

Will Green - Stephens Inc., Research Division

Got you. Then jumping over to the Bakken, I guess you mentioned September, October timeframe to get those first 2 or 3 completed. Do you have someone in mind that's going to complete those for you? Or is that -- is there a set date yet?

Robert L. G. Watson

Yes, we have frac dates already with one pumping service company that's done a lot of work for us already. They're excited to do the work, and we're going to frac all 3 of them at one time.

Will Green - Stephens Inc., Research Division

That's great. How are AFEs running for those these days?

Robert L. G. Watson

They were about 1/2 of what they were 6 months ago, Pete?

Peter A. Bommer

Yes, frac cost has fallen by -- well, a significant amount, at least 1/3 pulling that entire completion AFE down probably by that much.

Will Green - Stephens Inc., Research Division

So where does that take total drilling complete once you're all up and running?

Robert L. G. Watson

Well, we'll be in a better position to answer that when we get these 3 wells done because this is kind of the break-in crews for our drilling rig, so we're still learning, getting more efficient. I think the next pad will be a very telling on how much more efficient we're going to be. But I'm somewhat amazed at some of the numbers that people have been announcing, they still seem to be extremely high. I hope we can beat those numbers.

Will Green - Stephens Inc., Research Division

That's good. We'll look forward to that progress.

Operator

Your next question will come to you from the line of Hsulin Peng of R.W. Baird.

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

So first question is can you just tell us what your current production is? And with the Blue Eagle -- well, I guess with the Eagle Ford assets coming to you in September, how does that impact the third quarter production, if any?

Robert L. G. Watson

Well, it certainly is going to have a positive impact. But keep in mind under GAAP accounting, we cannot report production until the deal closes, even though it has a prior effective date. So West Texas was effective May 1. We got paid for that production, but we can't report it until the deal closed, which was end of July. So we'll only have 2 months in the third quarter of that 240 barrels a day. And then assuming that Blue Eagle closes to allow us to start counting its production September 1, we'll have 1 month of about 200 barrels a day. So that's just shy of 500 barrels a day additive to the 3,900 plus that we reported, excluding Blue Eagle. And that should give you a pretty good handle on where we are.

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

Yes. Okay, got it. Perfect. And then the second question is, in terms of your 2012 CapEx, previously -- well, you had said $70 million before, and now that with the Eagle Ford, I was wondering if you still plan on keeping that $70 million and just shift, reallocate among the different plays, or how should we think about that?

Robert L. G. Watson

It will not be additive. We're going to be challenged to get to the $70 million anyway, even including the Eagle Ford. So I don't see any change in CapEx for 2012.

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

Okay, well, that sounds good. And the last question is on Pekisko. So you had mentioned in the press release that you're deferring completion until oil price bounces back. So I guess the first question is what oil price do you need to see to do that? And second of all, do you still plan on divesting that asset after you finish the 6 wells?

Robert L. G. Watson

The -- obviously, the Pekisko is in that group of properties that we would feel comfortable transacting on. The timing, we still have some work to do in that play. We have 2 wells yet to frac, 1 well yet to drill. Don't know when that's going to happen. Oil prices have improved considerably up there. We actually have a rig started in the field yesterday, doing a pump lowering operation, which we have found to be very effective on these wells. So we're just going to enjoy the cash flow off of it for a while and make the decision as time goes on. And I can't be more specific than that because I'd -- it would just be a wild guess. But it certainly is a divestiture candidate at sometime in the fairly near future.

Operator

Gentlemen, your next question comes from Welles Fitzpatrick of Johnson Rice.

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

How much West Texas gas was shut in, in the second quarter?

Robert L. G. Watson

It was a partial quarter, Hudgins was down what, 2 months? So about 100 barrels a day of equivalents. I thought Hudgins was more than that.

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

And you said that that was back online now? Will it be back for the full third?

Robert L. G. Watson

Well, I think that work was done in July, so late July.

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

Okay, perfect. And then on the 2 areas that you talked about adding 1P for the midyear reserve report in the Eagle Ford, how many incremental wells are in those 2 areas? Or is it more going to be kind of PUD booking? You mentioned the one proved develop location that didn't have any offset.

Robert L. G. Watson

Yes, that one is -- was just a PDP and the McMullen County was all probable at year end because we had not finished the first well. So that well is now in production PDP and the offsets will be PUDs. We've not seen the D&M report yet, so I can't tell you how many are going to be PUDs and how many remain as probables. But I expect the proved portion of that 6 million barrels, which I think was 2.4 million proved and 3.7 million probable, I expect that 2.4 million to go up as the same number that the 3.7 million will go down.

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

That's fair enough. And then on the new rights in Ward County, do you have the deep rights on that or no?

Robert L. G. Watson

Yes. No, we produced -- all those leases are held by Ellenburger wells, which we have operated since 1994. What we acquired was the Montoya -- well, we already had an interest in it. We acquired a bigger interest in everything, is what we did. But we acquired a bigger interest in the Montoya zones and in some of the up-hole zones below the Cherry Canyon. It was a very, extremely complicated landownership situation, which we've now solved in one fell swoop.

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

And barring a dramatic gas recovery, are there any other prospects on there that kind of piqued your interest? Or is it really more for the gas optionality as you said in the top of call?

Robert L. G. Watson

Well, the majority of it is gas. We do have some Wolfcamp oil on production on those properties, which may or may not be amenable to horizontal drilling. Don't know yet. There are some other companies drilling within a couple of miles of this block, horizontal wells, so we're going to watch those very closely. But there's -- almost everything from grassroots to basement produces in this field area. So we will now be justified in spending more time in coming up with exploitation ideas that we didn't spend time on before because of the complicated ownership with our partner which has now been alleviated.

Operator

[Operator Instructions] Your next question comes from Irene Haas of Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

I have 2 questions. Firstly, do you guys have some acreage sort of in the greater Cline Shale area on the Midland Basin side? Then secondarily, how is this sort of credit line issue going to resolve, sort of timeline, when are you going to go back your lender? And ultimately, how would you reduce your leverage, and what kind of timetable we're looking at?

Robert L. G. Watson

Well, let's see. I said earlier that we were going to submit our midyear reserve report to the bank here in a couple of weeks, and we expect to have the redetermination done before the end of the third quarter. And I also said earlier that there are 2 ways to delever, one is to pay off debt and the other is to increase your borrowing base without incurring any additional debt. And that's what we're doing with these transactions. And I think that -- in this environment, a bigger company is better. It gets more attention. So we're going to be a bigger company. We'll have the same amount of debt, but we'll have more assets.

Irene O. Haas - Wunderlich Securities Inc., Research Division

And do you have any potential locations on the Midland Basin aside for Cline Shale?

Robert L. G. Watson

Yes, we do. It's not concentrated. Our one concentrated block, we farmed out to Pioneer a number of years ago for Wolfberry wells, and they've been drilling us a lot of wells in which we have a nice overwrite under. But we have some scattered acreage that's perspective in the Cline. It's not a focus area for us. All of our acreage is held by production. It's not going anywhere. But we've got plenty to do elsewhere.

Operator

Gentlemen, your next question comes from Ryan Oatman of SunTrust.

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

Hey, Bob, this is actually Neal. Say, just a quick question, what have you said, I guess, recently about over the Niobrara and the Turner? Was wondering on activity you're talking about, maybe if you could talk about locations, if anything has changed there. And just, now the way you see that as far as the economics sort of stack up, maybe versus something like the Eagle Ford.

Robert L. G. Watson

Well, I think the economics are the best we have to start with. EOG has been very active in and around this. They've announced a number of new wells. They've announced a number of completions. Our well is holding up extremely well. We're very excited about it. I think we have 26 gross locations and 9 -- 26 gross locations, 9 net left on our HBP acreage. We're just kind of keeping that in our back pocket for when the time seems right. It's pretty gassy, as you know. It's slightly less than 50% oil and NGLs, so the gas component is pretty high. But the liquids alone make it an economic venture. So we're very pleased with that and would look forward to developing it one way or the other in the next couple of years.

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

What -- Bob, what do you think for well costs or EURs, any estimates there?

Robert L. G. Watson

$7 million all in.

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

And now, EURs, any estimates yet, or too early?

Robert L. G. Watson

I think it's too early, but I think they're higher than what we used -- you want to throw out a number?

Peter A. Bommer

I think we estimated early on that the oil would be around 110,000 barrels and the gas, slightly over 2 Bcf. That first well looks stronger. We're still evaluating those trends. So I think it's maybe a little early to bump it up, but it's a good-looking well, relative to its neighbors.

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

Got it. And then Bob, just sort of lastly, a broader question on -- you've maintained pretty solid hedges all along, is that continue -- or are you just kind of keep them on it? Are you adding hedges more on the out years, or will you continue to be at, whatever 50% to 60% hedge? Or what's your thoughts around that? And kind of where's your comfort level on the debt side?

Robert L. G. Watson

Well, I -- the hedges are going to be determined by the amount of debt that we have. Right now, we're at about 80% to 85% of our crude oil is hedged. We don't want to go any higher than that, but if we grow production like we think we will, it's mainly going to be oil. So at the end of this year, we might be down in the 70% range. We might look at layering some more on, if the prices look well. But we don't have a specific plan that we have to hedge a certain amount on a certain date. We just try to be -- to capture the good market.

Operator

I have 2 lines, one of which is named Noel Parks from Ladenburg Thalmann. I have 2 under that name, so I'll take first one.

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

I just have a few things. Sorry, if I missed this. What -- for the leases you have on the Eagle Ford, what's the timing remaining on them, on those lease terms?

Robert L. G. Watson

A lot of our Eagle Ford acreage is HBP already. The drilling program that we're planning in McMullen County will HBP everything we have there, which leaves our Jourdanton block, which you're familiar with because you've been there. And those leases all start coming up in the next 6 months or so, but they have 2-year extension periods. So we'll be exercising those extensions. It's going -- if we extend everything, which we don't have to because one of them's HBP. But if we extend everything, it's about $0.5 million to buy us 2 more years of time on those leases. That would also include extending the Pearsall rights as well.

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

Okay. And in your other plays, since -- just keeping the Eagle Ford has sort of shuffled the portfolio a little bit, is -- do you have any other acreage that's not HBP at this point?

Robert L. G. Watson

Well, our stealth shale play in Canada, which we feel like we're going to be able to talk about here in the next month or so, is all lease acreage. So it's -- none of it's HBP, but it's all new leases. We've got 4-plus years left on the entire block. And we have some in the Alberta Bakken. Those are all long-term leases as well. So again, we're not in any big hurry to do anything. And do we have any -- we've got some scattered ones here and there, I guess, but nothing of any size anywhere else.

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

Okay. And so then, the -- all of the Williston Basin, Bakken is set at this point?

Robert L. G. Watson

Yes, for the most part. We have some in-fill leases in our -- in and amongst our HBP leases that we will be HBP-ing by this set of wells that we're drilling right now.

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

Okay. Great. And does -- as you look sort of beyond your immediate activity, does having the Eagle Ford back in the picture just as far as, just time and attention, does it in any way sort of slow your Bakken development plans looking out into maybe next year?

Robert L. G. Watson

I don't think it does. We're pretty much set on a plan for the next 2 or 3 years, and we've got people that are dedicated just to the Bakken. Those wells are -- take a long time and they're expensive. So one guy can handle more than one well at a time. And we feel comfortable that we can handle both the Eagle Ford and the Bakken with our existing staff and don't have to staff up to handle it.

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

Okay. And any thoughts on plans for the Turner and has there been any additional activity near you recently? And actually, how's your first well doing?

Robert L. G. Watson

Our first well is doing remarkably well. It's still producing the same thing it was producing when we put it on in April. Very little pressure drawdown and we're extremely pleased with it. EOG has announced a number of new location permits directly offsetting us. They've had some new completions in the immediate area. I think it would be a more active play if it wasn't locked up by EOG and a little bit by ourselves. But we've got 26 gross and 9 net locations left on our existing HBP acreage. Don't have any plans to do anything right now, but that doesn't mean that plans could change overnight, and we drill another well or 2.

Operator

[Operator Instructions] You have a question from the lines of John Brewer of BLBB Advisors.

J. Curtis Brewer - BLB & B Advisors, LLC

As you know, here in Philadelphia area, we're kind of right in the middle of the Marcellus shale activity. And there's been quite a bit of anti-frac-ing protests and so forth here. And New York state, among others, temporarily prohibited frac-ing and so forth. And so I have a couple of questions that relate to that, particularly in the Bakken. And in light of the droughts that apparently has been going on in the upper Midwest and so forth this year. Is the utilization of the water-based frac-ing solutions potentially a threat to our ongoing development in that area? In other words, is there adequate water supplies available? I'm almost dumbfounded when I look at those projected numbers, gallonage that is, to frac a well. And of course, disposal issues.

Robert L. G. Watson

That's a good question, John. North Dakota, luckily, is a very pro-business, pro-industry state, as you know. We've been a little bit proactive in that, in that we have actually discovered, if you will, a subsurface aquifer of water that's not quite potable, so you can't put it on your crops, can't drink it without treating it, but it's quite adequate for frac-ing wells. We are actually in the permitting process to drill a water supply well on our exiting land that we own the surface. We're in the process of building a big freshwater lake, which should be completed by next week. That well will be pumped into that lake. That lake will serve all 30-plus wells that we plan to frac in the area by pipeline. We won't have to truck it. It's a tremendous cost savings for us, and it also could be a source of revenue for selling water to other operators in the area. So we don't see any issue with water in North Dakota. We don't see any issue with water in South Texas. There's plenty of subsurface water there, despite what the media would lead you to believe. So we don't have the issues that you have in the Marcellus, plus most of the citizens in Texas and North Dakota support the industry, which again, you don't have up there, unfortunately.

J. Curtis Brewer - BLB & B Advisors, LLC

I'm fascinated with the fact of -- the ability to tap an aquifer for ourselves. I've been doing some reading about gas frac-ing, and it's been difficult to, at least from my perspective, to ascertain how effective it is and whether it is the frac-ing modus of going forward or whether it's not an appropriate approach to frac-ing wells or in the areas in which we're drilling. Now what's your thoughts on that?

Robert L. G. Watson

Well, I think it's a very novel approach. We've used it before. It's very site specific because you have to have the supply of propane or butane close by, and then you have to have an outlet for it when you flow it back or you're just wasting a lot of money. It's more expensive than water frac-ing. I guess the jury's still out on the -- on how well it does, but I think we were pleased with the one well we did it on out in West Texas. And certainly, in the appropriate instance going forward, we would certainly consider doing it. But not all areas have a pipeline outlet to flow the gas back into. And you certainly don't want to flow it up in the air and burn it because it's very expensive to frac with. But they are getting big, they're getting big in the Eagle Ford. They're building a camp down here in a little town south of San Antonio, and I wish them the best of luck. And I think it's a novel approach that's got a future.

J. Curtis Brewer - BLB & B Advisors, LLC

Good. And one last question, Bob. In the properties that we have in the Bakken, do we have rates in lower formations in the middle Bakken, which is apparently where we're currently drilling? Some of the things that I've see suggest that a formation of about 5,000 feet below the middle Bakken is anticipated to be more prolific than where most of the drilling's being done today. And I guess I was wondering whether the kind of leaseholds we have there have -- give us the rights at various depths.

Robert L. G. Watson

For the most part, all of our lands up there include all rights down to China. And you're probably talking about the Red River formation, which is probably the most prolific formation in the Williston Basin. But it's structural and it's spotty. It's not going to be a big blanket accumulation like the Bakken is. We actually have a number of Red River wells. We have a number of Red River prospects that we would drill someday. It's all on HBP land, not in any hurry, but we do have those in our portfolio.

J. Curtis Brewer - BLB & B Advisors, LLC

And just a moment ago said -- and this is my last question, but I came up with another one, so my apologies for that. Again, relates to the Bakken. As an anticipation of -- which I know is very speculative of -- which I know is very qualified expectations as to the productivity of individual wells that we're now drilling, for example, in that formation. It seems to me that most of those wells that have been heretofore drilled produced something well less than on average than 1,000 barrels a day per well. Is that correct or a correct assumption? And as a corollary, are there areas in the Bakken formations that could anticipate forward rear flow rates than that from an individual well?

Robert L. G. Watson

Yes, I think that's a very good comment because, yes, there are sweet spots. There are areas that have a higher indicated recoveries than other areas. And I would agree with you that there are a lot more wells that produce less than 1,000 barrels a day than produce more. It's just the ones that produce more are the ones that get reported on. But we look at all of them and we throw that into our database and into our calculations about whether an area is prospective for an economic well or not.

Operator

Gentlemen, your next question is a follow-up from Irene Haas of Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

On CapEx, can you tell me how much you spent during second quarter? And also, looking forward to third quarter, what would you -- your spending be? And any feel for 2013, how much are you going to be using for drilling?

Robert L. G. Watson

No feel for 2013. I would expect that we'll spend more than 2012. That's all I feel comfortable saying now. We only spent $9.5 million in the second quarter. I expect to be about the same level third quarter and then have a nice boost in the fourth quarter.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Okay. So really corresponding to that is that your base production should stay pretty flat with a little bit of addition from West Texas, the gas stuff and the sort of a contribution from Blue Eagle, but now going forward you only get probably about 25% of the total pie that you used to get?

Robert L. G. Watson

Well, we have 100% of one well and 25% of the others, but we're going to be drilling a whole bunch more. So I think the Blue Eagle contribution grows. We have Bakken contributions, which will be the most significant add starting early fourth quarter, and then periodic for the next number of years. So yes, I tried to give some guidance earlier on that in that second quarter, we had some gas shut in that's now back online. It would be additive. The West Texas acquisition, we can start adding as of August 1. The Blue Eagle production will be a direct add effective around September 1. Then, our first pad, a Bakken well, should come on early October. So we've got some incremental boosts already built into our system, which should show continued growth throughout the rest of the year.

Irene O. Haas - Wunderlich Securities Inc., Research Division

So are we looking at quarter-over-quarter sort of 5% growth, or any feel for the dimension?

Robert L. G. Watson

I haven't figured that out yet, but I certainly think our exit rate's going to be a pretty significant amount higher than where we are right now.

Operator

Gentlemen, you have a question from the line of Tom Maxen [ph].

Unknown Attendee

I'm just an investor. I've got a series of questions. With all due respect to you and your decision-making process regarding Mr. King, you're the new CFO, I know Davidson College is an excellent academic institution where he went to school. He's got a degree, it says here, in economics. But he doesn't appear to have an accounting background. How does his background as a chartered financial analyst with approximately 10 years experience qualify him to be the Abraxas CFO?

Robert L. G. Watson

I think Jeff is very qualified. He's very knowledgeable. He's very sharp. He's been in the small cap E&P business for a long time. We're structured a little bit differently, and I think it's the wave of the future. Accountants tend to look backwards. Financial people tend to look forwards. And it's somewhat rare for an accountant to be a successful CFO. So we have a very strong Chief Accounting Officer. He reports direct to me. The CFO is just going to be a capital markets type guy, and that's what Jeff's been doing for 10 years. And that's plenty of experience for what I was looking for.

Unknown Attendee

Okay. So what do you -- in your news release statement, you said you believe he can take you to the next level. Can you be a little bit more detailed as to what he would do to take Abraxas to the next level?

Robert L. G. Watson

We will get more exposure in the capital markets from his contacts than what we've had before.

Unknown Attendee

Okay. Help me understand your debt metrics. Were the metrics met for the second quarter?

Robert L. G. Watson

Yes, that's in the press release.

Unknown Attendee

Okay, so there wasn't any type of penalty?

Robert L. G. Watson

No.

Unknown Attendee

Okay. And the redetermination with what you've done with the Eagle Ford, I imagine that increases the ability -- the borrowing base, it increases the borrowing base?

Robert L. G. Watson

That's correct.

Unknown Attendee

Looking at the production, the first quarter production from the previous first quarter release was 3,815 barrels of equivalent and in the second quarter, it's at 4,272 barrels of equivalent and the difference is, it's added 457 barrels. I read in the press release, where the Hedgehog well is doing 385 barrels of equivalent. Is the Cobra well included in that increase? What is 457 barrels?

Robert L. G. Watson

Well, the Cobra well only came online in March. The Hedgehog well came online April 30. And the numbers you release with an individual well are the gross amounts, not the net to the company. So the net to the company on the Hedgehog is less than 385 or 395. And certainly, the net on the Cobra well is considerably less than the -- whatever number we announced on it.

Unknown Attendee

Okay. So you're -- and then additionally, you also -- I thought you mentioned that there was natural gas shut in that could have added, but obviously didn't. But in normal circumstances, do you believe you would have had a greater increase than the 457 that was presented?

Robert L. G. Watson

Yes, we were just doing a rough -- back of the envelope calculation. We think that cut our production by a little bit less than 100 barrels of equivalents per day from shut-in gas, which is now back on production.

Unknown Attendee

Okay. Turning to the Pekisko, about 4 of the 6 wells have been fracture stimulated. What is the production coming out of those 4 wells in the Pekisko?

Robert L. G. Watson

We haven't announced that yet. We're still doing some remediation work on those wells. We're lowering pumps down deeper and we're getting some very favorable response. So until that work is completed, we're probably not going to announce an assessment of that opportunity yet.

Unknown Attendee

When do you anticipate announcing that?

Robert L. G. Watson

I don't know.

Unknown Attendee

Do you -- is the production numbers from the Pekisko included in the 457?

Robert L. G. Watson

Oh, yes. Well, some of it was online before that. It's not all -- it didn't all come online in the first or second quarter.

Unknown Attendee

Okay. Yes, it's just -- I'm just trying to determine because I've never seen any production number coming out of the Pekisko, an actual number, trying to determine what that is, and you've answered that. And I thought the Baird analyst had talked about frac-ing the final 2 wells. It said in the press release that you were looking at a particular price to do, to go back in and refrac them, but it sounds like you're hedging now, and you're not sure when you will go back in to do that?

Robert L. G. Watson

I don't know what she said specifically, but we've said all along we're not going to do it until oil prices improve and -- or get back to where they were. They're not quite there yet, but we could certainly start thinking about that here if they hold where they are right now.

Unknown Attendee

Okay, yes. And then -- okay. So Abraxas retains 100% interest going to the Eagle Ford, 100%. I noticed that your acreage is about 8,000 plus, which was virtually what you started with. Is there drilling activity going on in what you own, what Abraxas owns in terms of the 100% Eagle Ford and then the 100% in the Yoakum, DeWitt County? Or is this 10-well program, is that just going to be in the Yoakum area?

Robert L. G. Watson

Right now, our current plans are to just be drilling the WyCross because that's the only one that has lease considerations to get wells drilled before a time limit. We don't feel an urge -- well, Yoakum is all HBP. Some of Jourdanton is HBP. The rest of it, we can, for a very small amount of money, extend for another 2 years, so we don't feel compelled to drill those right away either.

Unknown Attendee

The -- so the 10-well drilling program in WyCross, is that with your previous partner, Rock Oil? Is that...

Robert L. G. Watson

Yes.

Unknown Attendee

Okay. And so that's going to commence shortly. And then your working interest out of that will be 25%?

Robert L. G. Watson

Correct.

Unknown Attendee

Okay. What was that cash amount from existing production in the second quarter?

Robert L. G. Watson

The cash amount from existing production...

Unknown Attendee

Yes, cash flow. So you're -- you've said that all the drilling is coming out of cash flow.

Robert L. G. Watson

Well, the cash flow, and we announced discretionary cash flow of $7.1 million in the second quarter.

Unknown Attendee

So that would carry you into third quarter's drilling?

Robert L. G. Watson

I don't know that I understand the question, but...

Unknown Attendee

Okay. How much money do you need for operations to drill? Are you set? Are there any encumbrances to the Bakken drilling going forward?

Robert L. G. Watson

No. What I said is that we feel that cash flow and prudent use of our availability on our bank line is sufficient to cover our capital requirements for the rest of this year and all of 2013.

Unknown Attendee

And that gets you close to the $70 million CapEx that was originally projected?

Robert L. G. Watson

It's probably going to be a little shy than that. Earlier, I said we're going to be really struggling to get to that level, but it appears it's probably going to be around $60 million instead $70 million.

Unknown Attendee

$60 million instead of $70 million. And just -- so one quick question going back to the Eagle Ford and the 10-well drilling program. Rock Oil will carry all the capital there as far as drilling cost?

Robert L. G. Watson

No, they paid 75%. We paid 25%.

Unknown Attendee

Okay, so -- all right. Have you have been selling any additional unhedged natural gas in the second quarter?

Robert L. G. Watson

Most -- yes, we -- most of our gas -- well, probably half of our gas was hedged in the second quarter and half was not. I might be a little bit off on those percentages, but there was some hedge -- natural gas hedges still in place through June. Right? Yes.

Unknown Attendee

Yes. Now that natural gas has gone up to about $3, can you give me a percentage of how much more you would sell?

Robert L. G. Watson

Well, we'll sell whatever we produce. It's all going to be unhedged from this point forward.

Unknown Attendee

Okay. And then lastly, what do you sense, since the share price has really been getting hurt badly. What's our catalyst? Is it just the Bakken?

Robert L. G. Watson

I think what we announced in the last 2 days is a pretty good catalyst myself, but it's going to be incumbent upon me and Jeff to get that story out to the financial community here this fall.

Operator

Gentlemen, that is the end of your Q&A presentation. [Operator Instructions] Gentlemen, we do have a question from the line of another private investor. Would you like to take it?

Robert L. G. Watson

Sure.

Operator

Your next question comes from Jerry Agron [ph].

Unknown Attendee

A few weeks ago on a late Friday, Abraxas traded huge volume and hit $3.35. Do you have any idea what was going on then?

Robert L. G. Watson

No, we haven't been able to find out. But we were excited about it, but evidently that big buyer went away.

Unknown Attendee

So you don't know if it was a buyer, a seller, or what? Well, it had to be a buyer because it was up so much.

Robert L. G. Watson

Right, right. Hopefully, they come back.

Operator

All right. Gentlemen, your queue seems to be empty. Would you like to wait a few more moments and see if somebody else wants to queue up?

Robert L. G. Watson

No, we're fine.

Operator

All right, I'm going to conclude the question-and-answer session. I'm going to turn it back to Bill Krog for his closing. Bill?

George William Krog

Okay. We appreciate your participation today in Abraxas earnings conference call. As we mentioned at the start of the call, a webcast replay will be available on our website and the transcript will be posted in approximately 24 hours. Thank you and have a good afternoon.

Operator

Ladies and gentlemen, have yourself a great day.

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