Abraxas Petroleum Corporation
Q3 2014 Earnings Call Transcript

Published: 5 Nov 2014

[Operator:]

Good day, ladies and gentlemen, and welcome to the Q3 2014 Abraxas Petroleum Corporation Earnings Conference Call. My name is Whitley, and I'll be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I will now turn the call over to your host for today, Mr. Geoff King, Vice President and Chief Financial Officer. Please proceed.

[Geoffrey R. King:]

Thank you, Whitley, and welcome to the Abraxas Petroleum Third Quarter 2014 Earnings Conference Call. Bob Watson, President and CEO of Abraxas, joins me today. In addition, we have our Chief Accounting Officer and our VPs of Land and Exploration available to answer any questions that you may have after Bob's overview. As a reminder, today's call is being taped and a webcast replay will be available immediately after the conclusion of the call. I'd like to remind everyone that any statements made during this call that are not statements of historical fact are considered forward-looking statements and actual results could vary materially from those contained in these statements. Factors that could cause our actual results to vary are described in our filings with the Securities and Exchange Commission. I would encourage everyone to review the risk factors contained in these filings and in our press releases. I will now turn the call over to Bob.

[Robert L. G. Watson:]

Thanks, Geoff, and good morning, everyone. I want to start off by saying that our management team has been here before, but we've never been in as good a financial condition. Abraxas had a great third quarter, and in the fourth quarter is looking great as well. Our projects are still economic at $75 a barrel, just obviously not as much though. That being said, we're not stupid and we plan to only drill wells going forward that have a satisfactory return on investment. This morning, we announced the board approved CapEx budget for 2015 of $200 million. I won't go into the details of that; it is contained in our press release. But with continuing softness in commodity prices, we're in a very good position to cut capital in all of our areas. We have no long-term drilling or service contracts. We have no expiring leases to worry about, and we also recognize that rate of return is highly dependent on upfront costs, including acreage and revenue from first year of production. So first year of production at low prices just doesn't do it for us, and we're certainly prepared to make changes on a go forward basis depending on commodity prices. At $75 oil, our Eagle Ford projects produced return on investments of between 10% and 25% and that's assuming no service cost reduction, which we feel we will see if commodity price weakness continues. On the other hand, our Bakken projects are still well above 30% return on investments and that's without considering the profit from our company-owned drilling rig that's drilling our wells. Those of you who saw our press release this morning noticed that we're planning some Permian Basin work next year. We completed an extensive field study of Abraxas's oldest producing area, Mitchell and Scurry County, which is the western edge of the eastern slope of the Midland basin. We identified over 100 vertical new drills and recompletions. We're proposing in our 2015 budget, 29 of those projects in a project that's, well, scheduled to start around April 1. But again, that's going to be dependent on where oil prices are at the time. These are all held by production leases. They've been sitting there for years. There's no hurry for us to start the program in a low oil price environment. Our newest corporate presentation will be 8-K-ed in the very near future, or it has been. Okay, it was this morning already. So I encourage you to take a look at that. We've got some more information on the Scurry and Mitchell County project as well as our -- what we now see as our horizontal inventory in the Delaware Basin of far West Texas. We also announced today that we've started the sales process of our Powder River Basin assets in Wyoming. The project is being handled by Petrie Partners. Those of you who remember, we tried to swap these assets for some additional Bakken and Eagle Ford assets. We initially had some good interest, but we weren't able to consummate any deals. But during that process, we had a very good indication of a number of people that wanted to buy these assets for cash. So if we're successful, and I want to reiterate this, and we get our price, we're definitely not selling these on the basis of $75 oil. Those proceeds would be used for incremental Bakken and Eagle Ford opportunities that we've identified. Also today, we announced a record quarterly production, but it had a slightly higher percentage of gas than some expected. And I wanted to explain that this is not a function of drilling gassier wells, but actually a good thing in that we're merely capturing and selling rather than flaring a higher percentage of our associated gas in both the Eagle Ford and the Bakken. Now for a quick look back at third quarter, which generated a great operational and financial results. In the Eagle Ford, our first pad in the Jourdanton area was a 2-well pad, the Ribeye 1 and 2. They're 330 feet apart. We thought -- saw this as a great opportunity to do some experimenting to see if we could improve our results or drive our costs down. So we actually used completely different frac protocols in hopes of learning something that would help us on a go forward basis. Specifically, the Ribeye 1, which we announced a 30-day rate of 240 barrels of equivalents per day, the frac was designed to bypass areas in the lateral that could be a lower stress, and hopefully, to avoid fracking out of zone possibly even into the Buda. That design resulted in 21 stages over a 7,000-foot lateral. It was at lower cost, but the Ribeye #2 where we fracked all zones with 28 stages, a little bit higher cost, resulted in a 30-day rate, 60% higher. Keep in mind, these are only 330 feet apart to 389 barrels a day. So in analyzing these results, I would say that we've learned more not what to do than what to do going forward. The Jourdanton area is still in a derisk mode. We're still way down the learning curve. Everywhere we drill, we learn something positive to add to our development plans going forward. We're very encouraged by our good wells. One well, actually, has produced well in excess of 100,000 barrels already and will pay out in less than a year. But we're still perplexed by why the poorer wells are the way they are. The good news is our average well is still above our type curve. That's economic even in this commodity price environment. We plan to go forward with a very focused development program in both the north fault block and the south fault block. We're very encouraged by the latest well we drilled, the Cat Eye #1, which was the first well in the south fault block where we have no booked reserves. We drilled the pilot hole and ran a full suite of logs. We do not have any vertical wells in the south fault block to look and see what the Eagle Ford looks like, but we do now. We were encouraged that we had a good-looking reservoir, thick, a little bit deeper than the north fault block. But importantly, while drilling this well, we had some very encouraging gas shows that required us to wake the mud up considerably higher than what we've done in the north fault block wells. So we're looking forward to an early December frac date for this well to see what ultimate results will be. The rig moved from this well to another 2-well pad, the Grass Farms 2 and 3, both of which are in the longer lateral category, and they're also the direct West offsets to our best well, that being the Snake Eyes #1. Down south in McMullen County, our Dutch lease, our Cave prospect, is now fully developed, and with the successful drilling of the Dutch 3 and 4, both of which have 9,000-foot laterals, they were given 74 frac stages between them. The plugs have been drilled out and they're currently running tubing to commence flowback in the very near future. And to remind everybody, all of our Eagle Ford activity is currently 100% owned by Abraxas. Thus, each well is very impactful to us. Now going up north in the third quarter in North Dakota, we successfully drilled the Stenehjem 2, 3 and 4, the 20,000-plus feet each with 10,000-foot laterals, and I might say that Abraxas owns a 73% working interest in the Stenehjem pad. The fracs on these wells are scheduled to start next week, approximately 100 stages between the 3 wells of our hybrid design frac, which is -- turned out to be so successful on our other areas in the area. From the Stenehjem, our company-owned rig was moved to a 4-well Jore Federal West pad, and has commenced drilling the Jore Federal 5, 6, 7 and 8. Surface casing has now been set on all 4 wells to 2,000 feet. We'll be drilling out under surface to drill the immediate -- intermediate hole on the #8 today. Abraxas owns a 76% interest in the Jore Federal West pad. After the Stenehjem fracs next week, we do not plan on any other fracs in North Dakota until next spring. This is a performance-enhancing and cost-saving mode. We feel like it's well worth waiting out the wintertime before we complete these wells. The rig will, however, continue drilling throughout the winter. Thus, we'll have a nice inventory of wells to complete next spring and bring on production during the second quarter. Last quarter, I mentioned one well on the Ravin West pad where Abraxas owns a 53% interest, specifically the Ravin 4 had suffered a mechanical issue, which prevented the completion of the frac. I said at the time, I didn't think it was a serious issue, and that it had a simple solution, but it had to be fixed. I'm pleased to say that it did turn out to be an easy solution. It was fixed easily, and the cost was paid for by the third-party service company that created the problem to begin with. The frac was completed during this third quarter, and we announced the 30-day rate of over 1,100 barrels a day on this well, very similar to the other 3 wells on the Ravin West pad. I might remind you that the Ravin West pad was our first downspacing test for the Middle Bakken, and I can say today that these 4 wells are performing better than all other Middle Bakken wells in the surrounding area, not just the ones that Abraxas operates but all other operators as well. We're pretty convinced that Middle Bakken downspacing works at this point. On the Stenehjem pad, 2 wells are a Three Forks downspacing test. So hopefully after the fracs that start next week, we'll have similar results in the Three Forks as we have in the Middle Bakken. In closing, I have to repeat that I've seen all of this before. Crisis does create opportunities. If the current downcycle persists, those that have the balance sheet, which we do, and the capacity, which we do, to take advantage of opportunities, will come out the winners. And I certainly expect Abraxas to be one of those. Now we'll open it up for questions.

[Operator:]

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

[Will Green:]

I wonder if you could talk a little bit about the Bakken. You said about a 30% rate of return at $75 crude. Where do you see a breakeven price for those operations going forward?

[Robert L. G. Watson:]

Well, breakeven with no returns probably in the $50 somewhere. Breakeven with a 10% returns, probably around $60.

[Will Green:]

Great. And then, I also wanted to touch on the Permian. And you guys have about $10 million of CapEx budget there next year. Looks like you guys are doing a handful of things, recompletes and that sort of stuff. On the new drills, can you help us with the economics there? How are you guys thinking about a new drill cost? Are these all the different depths? Are these mostly Clearfork? How are you guys thinking about EORs? Just some stuff that gives us some meat around that.

[Robert L. G. Watson:]

Yes. Will, it's in our presentation that's been 8-K-ed. I know you probably haven't had a chance to take a look at it, but roughly $600,000 to drill and complete. Roughly 30,000 barrels per well is what we're using in our economics, although the surrounding wells are 75,000 to 100,000. So it generates a very good rate of return. But we're not anxious of -- because of the impact of initial production on that rate of return number, we're not anxious to get started in a low commodity price environment. So we'll be very reflective of commodity prices before we kick that program off. I might add that we have already started some of the recompletions and have had very good success. So we're anxious to get started on this, and it's pretty low-hanging fruit for us.

[Will Green:]

Got you. And can you talk to some of the uplift that you're seeing on the recompletes you have seen success on so far?

[Robert L. G. Watson:]

Yes. All we have is one that has any length of production to it, and it happened to be a well that I drilled, one of the first wells that Abraxas drilled in 1978. And the uplift was -- we completed in an upper zone, and the production performance has been almost exactly like the performance was in the lower zone in 1978. The lower zone is still economic where it is 4 years later. So -- and it's made close to 100,000 barrels. So we're hopeful that we'll see similar reserve results in the upper zone as well. We've got another 7 wells to do before year end, I think. So this is a project that I knew was there. We just haven't had the time to put engineering and geology together on it. That is now done, and we've been able to prioritize the projects, and we're pretty excited about it.

[Will Green:]

Great. And can you help me with the completion cost? It's probably in the presentation as well, but can you help me in the completion?

[Robert L. G. Watson:]

The $600,000 is drilled and complete.

[Will Green:]

On the recomplete, though.

[Robert L. G. Watson:]

On the recompletes, it's about --

[Geoffrey R. King:]

150.

[Robert L. G. Watson:]

$150,000.

[Operator:]

Your next question comes from the line of Steve Berman with Canaccord.

[Stephen F. Berman:]

Just one housekeeping item. The four Jore wells. I'm sorry, are those being completed before winter or in the spring?

[Robert L. G. Watson:]

They'll be spring. They'll be completed in the spring. They'll be drilled down, and then we'll move to another pad and drill those wells. And hopefully, we'll have 7 or 8 wells to frac in the springtime.

[Stephen F. Berman:]

Okay. And moving to the Eagle Ford. The 2 Ribeye wells, what were the total costs on those? Roughly.

[Robert L. G. Watson:]

Roughly $8 million. One of them was less than that. I don't have them right here in front of me. But there was a lot of science done, and certainly, that's not indicative of our costs going forward.

[Stephen F. Berman:]

Okay. And if the -- on the southern block, if the Cat Eye well turns out to be -- widely exceeds your expectations, I mean, how much flexibility is there in your 2015 plan? Would you -- I mean, the northern block is HBP-ed, right? So would you consider doing more in the southern block if that Cat Eye well turns out to be lights out?

[Robert L. G. Watson:]

That's what we project doing. We do have a lot of flexibility on our drilling schedule in the Eagle Ford. The Bakken is pretty much set. We know where the rig is going to go and very predictable, I might add. But we're anticipating having some decisions to make in the Eagle Ford, whether we go down the Delaware or go to the north fault block or the south fault block. My personal objective would be to get all of the acreage in the south fault block HBP-ed this year, even though we have 2 or 3 years left on the leases. I'd just like to have that all done and behind us.

[Stephen F. Berman:]

And how many wells would you have to drill to get that all HBP-ed?

[Robert L. G. Watson:]

5 or 6 more.

[Stephen F. Berman:]

Okay. And then the last one for me. What's the associated production and total acreage on the Powder River package you have for sale?

[Robert L. G. Watson:]

I -- yes, we have about 2,300 net acres in the area called Porcupine, and then 14,700 acres in an area called Brooks Draw. And the production is 250 barrels a day of equivalent, but it's 1/3 oil. About that.

[Operator:]

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

[Noel A. Parks:]

I was wondering about the Grass Farms 2 and 3. Based on the information you've gotten from Snake Eyes nearby, do you have a sense of how those wells are completed in the zone that you want might look? Do you think they might be comparable, better, or be more conservative?

[Robert L. G. Watson:]

I would hope they'd be comparable. In my wildest imagination, I couldn't expect it to be better than the Snake Eyes. The Snake Eyes made about 120,000 barrels already and will pay out in less than 1 year. So something that's comparable to that would bring big smiles to our face.

[Noel A. Parks:]

Great. And let's see -- and now with some drilling history, I know it hasn't been so long for many of the [indiscernible] Honeywell's. [ph] How far away do you think you might be from revisiting the type curve for that area?

[Robert L. G. Watson:]

I think we need some more time. I think we're comfortable that it's reasonable at this point. If we figure out how to get more Snake Eyes wells and less Ribeye 1 wells then that would certainly have a positive move on the type curve. But we're a ways away from it yet. This is still very much in a derisking mode and very much a learning curve mode. So we're still excited about it, and when you have wells as good as the Snake Eyes, you know you're in a decent area. It's just a matter of how you can replicate that and avoid the poorer wells.

[Noel A. Parks:]

Right. Great. I just wanted to ask about the Ravin 4 well with the problem being resolved out there. Is there any accounting implication for the third party paying for it for you? Or...

[Robert L. G. Watson:]

We just got a big credit. Yes, we use them quite a bit so they just gave us a big credit to take care of it.

[Noel A. Parks:]

Okay, great. And then, I guess one other question I hadn't really thought about out in the Bakken before. For your rig, now that you've been operating it for a while now, is -- I'm sorry if you specified this, is there any CapEx envisioned? I don't know if you need to do any major maintenance on it just as it's getting a little bit older, or is that just routine, sort of part of ongoing quarter-to-quarter expenses?

[Robert L. G. Watson:]

I think all we're looking at is routine preventive maintenance. We do replace the drill pipe as it gets worn out, but that's just part of the business. But I certainly don't foresee any major capital expenditures required on the rig.

[Operator:]

Your next question comes from the line of Evan Richert with Sidoti.

[Evan Richert:]

Just wondering if you could touch on what kind of drilling times you've been seeing in both the Bakken and Eagle Ford.

[Robert L. G. Watson:]

The Bakken, our drilling time's -- we're drilling 4 wells at a time. So it's hard to say what one specific well is doing. We look at groups of operations specifically like the -- on the Jore Federal, we drilled 4 2,000-foot surface holes, walked the rig and did whatever we needed to do in less than 8 days. So obviously, 2 days per well to get the surface all done. And then I think we're drilling these as fast as anybody could expect now from out undersurface to the end of the lateral basis. But specifically, what one -- do you have any idea what one well would...

[Geoffrey R. King:]

I have no idea because we drill surface, surface, surface and intermediate, intermediate, intermediate and lateral, lateral, lateral. So...

[Unknown Executive:]

[ph] You'd have to divide it by 4.

[Robert L. G. Watson:]

Right. Yes. You'd have to take the total time on the pad, divide by 4, and I don't have that information in front of me. But we're pretty pleased with the efficiency of that drilling rig and we'll make a statement that we'll put that rig up against any other rig in the Williston Basin right now.

[Geoffrey R. King:]

The surface holes that we just drilled were record time, those were [indiscernible]

[Robert L. G. Watson:]

Yes, those are record -- less than 8 days to drill 4 surface holes. And the Eagle Ford is a -- the Eagle Ford's a little different because you have such a variability in lateral lengths, and I don't know how people are coming out with a drilling time because, obviously, it takes longer to drill a 9,000-foot lateral than a 45,000-foot lateral. But I don't think we're being beat by many people, if anyone, as far as actual drilling time goes -- number of hours rotating. Some people will give you that number versus the number of days the rig's on location. We tend to look at thing as the number of days the rig is on location, which would also include the time to run casing, cement and all that kind of stuff. So we're probably looking at 20 days -- 20 to 22 days rig on location per well.

[Evan Richert:]

Okay, that's helpful. And then, taking the lateral length aside, do you expect going forward to have roughly the same times to the next -- for the foreseeable future?

[Robert L. G. Watson:]

Yes. I don't know that we can see doing anything quicker than the way we're doing it. So I think we're pretty comfortable that we've got these in place now. We're still experimenting with completion, obviously, in Jourdanton, and that experimentation will probably go on for the next year or so before we really get comfortable with the crack-the-code-type completion procedure.

[Evan Richert:]

Okay, great. And then as for the CapEx, you talked about maybe, depending on the price environment, maybe pulling back on the drilling and looking at maybe acquisitions. If you do decide to pull the trigger on that, what would be the first project to drop? Would you -- would that be the Eagle Ford or would you look to kind of balance that out across both?

[Robert L. G. Watson:]

We probably wouldn't even start the Permian project because we wouldn't want to start it and stop it. It's very easy for us to stop the Eagle Ford project at any point in time because we don't have a long-term rig contract. And so that would probably be the first target, I would guess.

[Evan Richert:]

Okay, and then last one for me. Obviously, with the price environment we're in, you're pretty well hedged out to '16 and even into '17. I'm wondering if you could just give some color on a longer-term view, or whether you think the current price environment is going to be with us for a while.

[Robert L. G. Watson:]

Well, I've seen this before. I saw it in the '80s and I saw it in the '90s. And I've been telling people for 6 weeks or so that Saudi Arabia is going to try to do something to gain market share back from the U.S. shale plays and from the Canadian oil sands. And I think what they said this week is just testimony to that. And so I think it's going to depend on how much pain they can take with lower oil prices and what their social budget is for running the country. And it could take a year or so. I don't see it lasting much more than that. The shocks that we saw in the '80s didn't, and the shocks that we saw in the '90s didn't. So we're very lucky that we're very nimble at this point, and we can handle as long as it needs to be handled.

[Evan Richert:]

Okay. And then, it's safe to say you're not in a rush to roll out any more hedges for '17 right now. So you think it's the last...

[Robert L. G. Watson:]

No. We would be looking at gas more than oil at this point. We do have some room to hedge some more, but we're going to be opportunistic, hedging at $75 does not turn us on a bit. And we feel like we've got the balance sheet that can take the risk on that. But we're also concerned with all the gas coming on, even though gas is a small percentage of our production stream. We might probably take some opportunities if we have a cold snap here shortly to lock in some gas for '15, '16.

[Evan Richert:]

Okay. And then, one last one I just thought of. You mentioned you're capturing a lot more of your gas and doing less flaring. How do you see that shaping up over the next couple of quarters? Is that a trend you think is going to continue or any infrastructure being added that we should take a look for?

[Robert L. G. Watson:]

No, we've pretty much got all the infrastructure in place. There's still a little under construction at Jourdanton on our gas gathering system. Everything else is pretty much tied in. In the Bakken, we are tied in and have been. The issue there is the plant sometimes gets jammed up with gas, and they curtail everybody. So we have an automatic flare on all our leases in the Bakken that when the line pressure gets to a certain pressure, it automatically goes to flare. And we have no control over that. There's absolutely nothing we can do about it. So as far as predicting how much we're going to flare going forward, it's difficult. I know the last 3 months, we've been selling over 90% of our gas produced, which is well within the limits that North Dakota is placing on people currently.

[Operator:]

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

[Michael S. Scialla:]

Bob, you'd said you're pretty pleased with what you've seen so far in the Cat Eye 1H in terms of the thickness of the Eagle Ford, and I guess higher pressures than maybe you'd anticipated. I'm wondering too, I know going into it, you were anticipating maybe seeing fewer faults on the southern fault block, anything you can say to that?

[Robert L. G. Watson:]

Lee, answer him.

[Lee T. Billingsley:]

Yes, true. No faults within the fault block there. It drilled not exactly the way we expected, but we adjusted for what was there, but there were no faults.

[Michael S. Scialla:]

So in general, does that southern fault block, you think, maybe look quieter than the northern fault block?

[Lee T. Billingsley:]

Yes. In terms of faulting.

[Michael S. Scialla:]

Okay, great. And in terms of acreage opportunities, I know oil prices have just started to move here a little bit, but seeing any additional opportunities? And can you remind me if you ever did add that second smaller piece of acreage that you were looking at, at Dilworth East?

[Robert L. G. Watson:]

Well, we've added 92% of it at this point. We're still trying to run down the other 8%. But we feel comfortable that, that will come with time. Long before we're ready to drill it, we'll have it all buttoned up, and there are numerous other opportunities that we're looking at. And as you projected, prices should be coming in. Landowners will be getting more reasonable, and the longer the oil price stays where it is, the more reasonable they're going to get. So we're actually looking at this as an opportunity to increase our presence in both the Bakken and the Eagle Ford. And I might add that we have been successful in securing some additional interests in some units that are surrounding our North Fork operated units, and our goal eventually will be to operate -- become the operator in 1 or 2 more units, which will allow us to time the drilling and completion of additional wells, and add to our inventory of wells that we control and be able to use our own rig to drill them. So we think there's still opportunities out there. Don't envision us doing a big huge acreage buy anywhere. But certainly, when smaller things come up that we can generate our rate of return goals on, we'll go after them.

[Michael S. Scialla:]

Good. And then on the Bakken, you'd mentioned sounds like you're pretty convinced on the downspacing there. I think as of the last call, you were still debating on which completion technique you preferred. Have you decided on one there yet? And if so, what are the costs of those wells now?

[Robert L. G. Watson:]

Now the costs are between $8 million and $8.5 million, pretty consistently. That's before you book the profit from our drilling rig. So our central net cost is something less than $8 million. The frac design that we have come up with seems to be working pretty well. So I doubt we're going to change it much going forward. And it basically is the first 8 stages or so are our sliding sleeves, and that's mainly driven by the depth that you can effectively use coil tubing to drill out plugs. You can't drill them out any deeper than that. So 8 or so sliding sleeves to start with at the toe. And then perf and plug. And then each stage is a hybrid starting off with slick water and then converting to a gel system, and we're putting away about 130,000 pounds per stage, I think. I get them mixed up. I know it's 360,000 in the Eagle Ford.

[Geoffrey R. King:]

Yes.

[Robert L. G. Watson:]

I think it's 130,000 pounds per stage in the Bakken of proppant.

[Operator:]

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

[Joel P. Musante:]

I just had a couple of questions on your production guidance. Just in 2015, do you expect that to ramp up kind of linearly over the year? Or do you expect it to be a little more lumpy?

[Robert L. G. Watson:]

It will be lumpy because the Bakken will be all pads, and there will be no additional production added in the first quarter because of winter. But there'll be a slug of it coming on in the second quarter. The Eagle Ford will be pretty consistent throughout. Do you want to address the -- whether it's linear or lumpier?

[Geoffrey R. King:]

It's exactly what he said. It's going to be heavily dependent on the impact of bringing on 4 Bakken wells at pretty high working interest at a substantial impact to our production. So as we're pushing those first 4 completions out into the second quarter, you're going to get a big jump there, and then you'll get a big jump with the next set of completions later in the year.

[Joel P. Musante:]

Okay. And when you were coming up with your forecast, your Bakken seems to be outperforming your type curve and your Jourdanton, Eagle Ford seems to be kind of variable. How did you -- what were some of the assumptions that you used to drive that forecast?

[Geoffrey R. King:]

On some of the other assumptions we have in there, we're using our type curve for Jourdanton on average. Pete Bommer just reran that, and we're sticking right at the average so there's no issue there. Actually, on a probabilistic scenario, we would be above it, given the performance of the Snake Eyes. So very comfortable using that, not assuming the Bakken is using the internal type curve, that's the 539,000 barrels. Now that takes the average that's peaking with all our starting wells too, which were quite weak. So that's negatively impacting that type curve. But in general, obviously, probably overly conservative if we can replicate what we saw in the Ravin wells. In the Permian Basin, Bob went over that, on the assumptions we're using for that type curve. And then on top of that, we're assuming about 10% downtime, and how we get there. I know that seems quite high. But for instance, in the fourth quarter here of 2014, when we go and drill the -- and completed the Dutch 3H and 4H, we had to shut in the 1 and 2H for about 2 weeks. So impacts like that when we're shutting in wells do have an impact, and that's how we get to that 10%, which arguably is a bit too high, and we can probably do better than but we like to have it there just in case.

[Operator:]

Your next question comes from the line of Steve Berman with Canaccord.

[Stephen F. Berman:]

Just a follow-up to Joel's question about the production with no wells being completed in the Bakken in Q1. Do you anticipate the Eagle Ford offsetting that enough that Q1 should be sequentially up from Q4?

[Robert L. G. Watson:]

Yes, I think it'll be up. It won't be up as much as the second quarter, but it will be up. You got the 2 Grass Farms wells that will be fracked, say, in January. You've got the Cat Eye well, which will be fracked in December. So you're looking at -- and then, you got the 3 Stenehjem wells that will come online here toward the end of November. So they'll be all very impactful to the first quarter over and above the fourth quarter. Then it will start slowing down toward the end of the first quarter, but I don't think the average will be less. And then second quarter will depend on timing of probably 7 or 8 Bakken wells coming on. And a continuation of probably 2 wells at a time in the Eagle Ford every couple of months.

[Operator:]

[Operator Instructions] There are no questions in queue. I'll now turn the conference back over to Mr. King for closing remarks.

[Geoffrey R. King:]

Thank you, Whitley. We appreciate your participation today in Abraxas's earnings conference call. As I mentioned at the start of the call, a webcast replay will be available on our website, and a transcript will be posted in approximately 24 hours. Thank you and have a great day.

[Operator:]

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