Abraxas Petroleum's (AXAS) CEO Robert L. G. Watson on Q2 2014 Results - Earnings Call Transcript

Aug. 6.14 | About: Abraxas Petroleum (AXAS)

Abraxas Petroleum (NASDAQ:AXAS)

Q2 2014 Earnings Call

August 06, 2014 11:00 am ET

Executives

Geoffrey R. King - Chief Financial Officer and Vice President

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

Analysts

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

Will Green - Stephens Inc., Research Division

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

Kim M. Pacanovsky - Imperial Capital, LLC, Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

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

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Operator

Good day, ladies and gentlemen and welcome to the Second Quarter 2014 Abraxas Petroleum Corporation Earnings Conference Call. My name is Tony and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded.

I would now like to turn the conference over to your host for today, Mr. Geoff King, Vice President and Chief Financial Officer. Please proceed.

Geoffrey R. King

Thank you, Tony and welcome to the Abraxas Petroleum Second 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, Operations, Engineering and Exploration available to answer any questions that you may have after Bob's overview.

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

I'd like to remind everyone that any statements made during this call that are not statements of historical fact are considered forward-looking statements and actual results could vary materially from those contained in these statements. Factors that could cause our actual results to vary are described in our filings with the Securities and Exchange Commission. I would encourage everyone to review the risk factors contained in these filings and in our press releases.

I will now turn the call over to Bob.

Robert L. G. Watson

Thank you, Geoff. Good morning. Second quarter, we generated some pretty good production numbers, 5,000 barrels a day, roughly, versus 4,200 barrels a day in the first quarter, that's up 20%. Not only beating the street, but we beat our own guidance. And in addition, we were a little bit oilier than we had anticipated. So that combination of increased production and the oilier growth generated some pretty good financial numbers. I won't go into the details on those.

During the quarter, we had 6 significant wells come online, actually late May, early June. So they didn't contribute much to the second quarter. Three of those wells were in the Bakken, 3 in the Eagle Ford, 1 of which was an older well that we had shut in during a drilling and frac-ing operation that came back online. But it's because of that, it's easy to see why our July production was about 6,600 barrels a day, which is up 57% over Q1.

And you can also say that we're fairly comfortable with our Q3 guidance, which is a midpoint of 6,600 barrels of equivalents per day. And we're equally comfortable with our year-end exit rate guidance of 8,000 barrels a day, and that's an average for the month of December, which would be up 90% over Q1. All of this growth has been done with a very pristine balance sheet, I might add.

Important to us and a measure of our own operations quality and efficiency is a significant decline in lease operating expenses. Here at Abraxas, we split direct lease operating expenses away from production tax and report them separately. Some people add them together and call it all LOE. But direct lease operating expenses, we have some sort of control over and production tax, we have none.

So let's just take a look at direct LOE by itself. During the quarter, we averaged $12.72 per Boe, which was down 19% approximately from the first quarter. Interestingly, June by itself, was less than $10 per Boe. This is actually a combination of selling off some high LOE properties. That process is almost completed now. But more importantly, we spent a lot of time in operations and one reason we don't like to be a non-operator. To make sure that we do everything possible to be as cost-efficient and operationally efficient as possible. This is -- it brings out an interesting point and an important point between those 2 efficiencies. And a lot of occasions, you can cost today, but you hurt yourself in the long run. So we make sure that the cost savings that we see -- we're receiving today continue on and don't hurt our long-term operations.

As an example, water disposal, we plan ahead and try to make Abraxas-owned water disposal in place and available early on in the life of a well, generating significant savings over the years as the well produces. That's especially important in the Bakken, where trucking water in the winter is a costly business. Due to this longer-term vision of LOE, we expect to see LOE to continue to improve over time.

Now let's go on to some of the specifics of our operations. In our Jourdanton, Eagle Ford area, Atascosa County, Texas, our average well still produces above our type curve. We still don't have any definitive reasons for the performance of 2 of our wells, the Spanish or the Eagle, especially compared to the performance of our rock star, Snake Eyes. We have some possibilities. We've -- there are some areas in the laterals of those wells that could have communicated with other rocks during the frac jobs, possibly down into the Buda. In our recently completed 2-well Ribeye pad, we actually designed the frac stages to avoid similar-looking areas in the respective laterals.

And speaking of the Ribeye 1 and 2, both wells were successfully drilled during the quarter, 7,000-foot laterals. They've both now been successfully frac-ed, a total of 49 stages. We placed 100% of the design prop. Now 49 stages and 7,000-foot laterals or 2 7,000-foot laterals doesn't seem like it fits, but keep in mind, though, we left some gaps in those laterals to avoid the areas that I previously mentioned. Both of those wells have now been drilled out or had the plugs drilled out and they should commence flow back in the very near future.

At Dilworth in McMullen County, we've got about 40 days of production history on our Henry #2. It's a good well, we'd hoped for better. It is higher oil cut than we expected and maybe we're thinking that our frac job needs to be tweaked on future wells to improve performance. Along those lines, we've currently shut the well in for a long-term pressure buildup survey, which hopefully, will give us some information that we can use on making our frac more efficient.

We have acquired additional acreage at Dilworth. We're in sensitive negotiations on another piece. So I can't give you details yet. We'd hoped to by now, but we're not there yet. And it's not an insignificant piece compared to the original 440-acre lease. Most importantly, it increases our inventory and it gives us the ability to drill longer laterals. We find that longer laterals are generating a better rate of return in the Eagle Ford than shorter laterals do.

At Cave, we're currently drilling our #3 and #4. This morning, we're below 15,000 feet on the #3. We've got surface casing set at 4,500 feet on the #4. During the quarter, the #1 well came on. It's a good well, it's right on the 580,000-barrel type curve that we've generated. It's still early, not quite as strong as the #2, which is still above that type curve. But it's a direct offset to a Marathon well that's been producing for 3 years. So maybe it's been affected by it. We don't really know at this point.

Performance on the 3 and 4, which are further away from the Marathon Wells, could shed some light on that situation.

With the current pad drilling of the 3 and 4, we hope to cut cost significantly, which will certainly improve our return on investment.

On the Dutch -- or Cave prospect Dutch lease, we are now selling gas through an Abraxas-owned gas-treating facility. We expect the 3 and 4 to be online by the end of third quarter. When completed on the 3 and 4, the rig will go back to Jourdanton for our first test in the south fault block, which will be named the Cat Eye #1H.

Up in the Bakken. Very smooth and efficient operation with our company-owned Raven Drilling Rig #1. We completed drilling on the 4-well Ravin pad, in which Abraxas owns a 51%. Coincidentally, it's called Ravin, but it's spelled different. They really have no relation other than just how they sound.

This is the first 660-foot spacing test. All 4 wells are in the Middle Bakken. Wells 5, 6 and 7 were successfully frac-ed with 33 stages each. Again, 100% of the design prop was placed. We did not see any significant communication indication between the wells during the frac. The flowback started yesterday.

Well #4, after 7 stages of successful frac, when we were going in the hole with the frac plug for stage #9, the plug got stuck up hole. In an attempt to pull it free, one of the 3 perforating guns fired. It certainly wasn't supposed to. Obviously, it was miswired, creating a short. Luckily, it fired shots into the liner hanger assembly and not deeper in the liner. It probably doesn't deserve the concern that it's receiving from the sell side analyst. It should be a relatively easy repair job and then we'll finish the frac and put it on production. It does require a workover rig, and we can't move that in until the flowback is finished and the other 3 wells are connected to the lease production equipment.

Basically, represents a little bit of an extra expense and about 2 months' delay in getting the well on. The rig successfully moved to Stenehjem pad, which Abraxas owns a 71% interest to drill wells 2, 3 and 4. The #1's been on production for several years. It's currently shut in during the drilling and frac-ing operations. To date, one well has had the intermediate casing set through the curve. The second well is finishing the curve today, then we'll set casing, we'll walk the rig to drill the intermediate hole and curve on the last well and then continue on with the laterals. We hope to have these wells on production by November.

And with that, I'll throw it open for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Mr. Ryan Oatman of SunTrust.

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

I apologize if you mentioned this, I hopped on the call a little bit late. But that first cable that you had on production, the Dutch 2H, how is that well performing once you've brought it back online here?

Robert L. G. Watson

It said -- I said that it is still quite a bit above the type curve, so it's doing very well. And we are selling gas from both wells through an Abraxas-owned treating facility. So the flares have gone away.

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

That's very good. And then just looking at the broader M&A environment around, you guys have had success picking up bits and pieces from other operators near you, specifically in McMullen County. Can you just describe how the environment is and whether you expect that to continue in the coming months?

Robert L. G. Watson

I think we have a number of -- I know we have a number of projects that are in-house, currently, some are closer than others to getting done. I would say that our group that is responsible for doing that is not lacking for opportunities to investigate and pursue. We think that, that environment should last for another couple of years. The additional acreage at Dilworth that I just announced is testimony to the success of what we're trying to do. And I think the 4 well cave lease, which is a small piece of ground but it -- we've added significant value on it. So it's proof that we don't need a whole bunch of acreage, expensive acreage I might add, to generate a good rate of return and significant growth for the company.

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

Very good. And then taking a look at Atascosa County, you've got 2 blocks up there. Any difference in terms of your thinking on the southern versus the northern blocks at this point?

Robert L. G. Watson

I would say, at this point, we're optimistic that the southern will be even better than the northern because the average lateral length will be considerably longer. And we're finding that extra lateral lengths can be drilled at considerable savings. And thus, the return on the investment of the entire well is higher with the longer laterals than it will -- than it is with a shorter lateral well. Our best well, the Snake Eyes, is only about a 4,400-foot lateral. We'll have some that are in excess of 7,000 feet in the south fault block. So we're very hopeful that it's going to be a positive move for us and hopefully, by the end of this year, we'll have results from the first well.

Operator

Your next question comes from the line of Mr. Will Green of Stephens.

Will Green - Stephens Inc., Research Division

So great news on adding the additional Dilworth or at least getting close to adding that acreage. I understand it's sensitive, but when -- if you can give us a timeframe, when would we expect to see that kind of added to the inventory?

Robert L. G. Watson

Well, actually, the biggest lease is already been paid for. So it's in inventory, I can't give you any specifics about it because it's tied to another lease that we're trying to get done. I would say that we're fairly close. It's probably a matter of days rather than weeks. I'm looking across the table at Steve Wendel, our VP of Land. But it's very near term.

Will Green - Stephens Inc., Research Division

That's great news. And then on the Ravin 4H, I didn't catch if you said it or not, but what -- does that affect the overall stage count you guys are able to get off on that well?

Robert L. G. Watson

No. We will get back on it and continue on and the planned stages will be 33 on that one as well. 7 of which have already been pumped away. So we've got 26 more to go. And all we have to do is pull the frac string, pull the liner hanger out, run in with a new liner hanger, tie back the frac string and then we'll be ready to start frac-ing again.

Will Green - Stephens Inc., Research Division

Great. And then one final one for me. On the Powder River, it seems like there's still a lot of interest out there from other operators. Are you guys participating anything non-op here recently or seeing any activity that excites you? Just any color there would be great.

Robert L. G. Watson

We've actually seen a couple of permits that would result in us having a non-op interest. We have not received anything from the operator that permitted those wells. We're still actively trying to swap that acreage for additional Bakken or Eagle Ford acreage. We have a number of parties that have indicated an interest in pursuing that. So it's a front burner project for us and hopefully, we'll have something before the end of the year reflecting some success doing that.

Operator

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

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

On -- can you remind us exactly how much acreage you guys have in Ward, it seems like a lot is moving in y'all's direction. And also whether there are Pugh clauses on those leases?

Geoffrey R. King

There are no Pugh clauses in Ward County. All of it's held by production and I'm going to guess it's 8,000 or 9,000 maybe 10,000 acres. So it's around that number.

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

Okay. Perfect. And then, nice move on LOE this quarter. Obviously due to those sold assets. As you kind of move the rest of those out of the portfolio, how much do you guys see that being able to drop kind of by year end, I guess?

Robert L. G. Watson

I think we have one remaining high-LOE asset that we're in the sales process on and that's Canada. Once we get that done, all the high-LOE properties for the most part will be gone. But a significant amount of that is just watching our operations on our recently completed wells, which are all high-volume wells, obviously. So as long as we continue to do that, we expect that LOE number to continue drifting down.

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

Okay. That's perfect. And then just last one on the Dutch 1H and 2H, vis-à-vis those Marathon wells. It -- I'm trying to look at the map. Was the 2H, was the bottom hole to the southwest of the top hole and the 1H was the opposite or were they both facing the same direction?

Robert L. G. Watson

No. They both face the same direction. They're on the same pad, that's why we had to shut the #2H in while we drilled and frac-ed the #1H. They're only 30 feet away. But the 1H, the most recently drilled well, goes right down the lease line, which is also the closest to the Marathon Well, which goes down the leased line on the adjoining lease. So they're pretty close together.

Operator

Your next question comes from the line of Kim Pacanovsky.

Kim M. Pacanovsky - Imperial Capital, LLC, Research Division

Back to Dilworth, can you just remind us what the remaining locations are there? And I know you can't add a lot of detail about what you've acquired and what you're acquiring as far as additional leasehold is concerned. But how will that affect location?

Robert L. G. Watson

The -- on the existing lease, we have 4 total locations, 1 of which is drilled, obviously. That number gets multiplied by a pretty nice factor when you consider the additional acreage that we're -- some that we've already bought and paid for. And I think once we announce it, you'll understand why we're having to be coy on the next piece. But it'll end up with -- being a nice block for us.

Kim M. Pacanovsky - Imperial Capital, LLC, Research Division

Okay. Great. And then, you talked about your higher IP rate wells in Jourdanton versus your lower IP rate wells in the possible -- the frac possibly going into the Buda. How are those lower IP rate wells declining? Are they flatter? Will they still have any kind of a reasonable IRR on them? Or are they declining similarly to Blue Eyes and Snake Eyes?

Robert L. G. Watson

Actually, the decline rate is a little bit flatter, but a less rate. I think it's way too early to tell what potential IRR could be. And it could very well be that this play we have to consider it on an average well basis. We're still scratching our heads trying to figure out the difference. We've compared frac treatments between the wells; we've compared mud logs between the wells; we've compared seismic, 3D seismic between the wells; and we just can't find the correlation between poor well and good well. And it could be just one of those tricks that mother nature plays on you. You're going to have some good ones, you're going to have some poor ones. But as long as your average is at or above your type curve, it's a very economic play.

Kim M. Pacanovsky - Imperial Capital, LLC, Research Division

Sounds like the data from Ribeye will be very valuable. And can you just remind me, Bob, where is Cat Eye on the southern block? Is it in the western -- is it one of those western locations?

Robert L. G. Watson

It's kind of right in the middle.

Kim M. Pacanovsky - Imperial Capital, LLC, Research Division

It is. Okay.

Robert L. G. Watson

Yes. Yes. It might be east middle.

Operator

Your next question comes from the line of Mr. Steve Berman.

Stephen F. Berman - Canaccord Genuity, Research Division

Moving up to the Williston. A lot of companies up there continue to dabble with their completion methods. Can you talk about what you're doing up there in that regard? Are you trying anything new, et cetera?

Robert L. G. Watson

What we did on this 4-well pad is we did a hybrid sleeve and perf and plug for a number of reasons. And I would say with the success we had with it, we'll probably continue to do that. It really helps your costs. But we're not convinced yet that we need to cement the liners. We're not convinced yet that, that does add either reserves or initial production. We did increase our proppant from about 100,000 pounds per stage to 130 pounds per stage. And we got it all pumped away. So obviously, the well was comfortable receiving that additional sand. So let's wait and see how these 4 wells do and compare them to earlier wells and see if there's a significant difference.

Stephen F. Berman - Canaccord Genuity, Research Division

And staying up there, where does Abraxas stand in terms of meeting some of the new requirements up there with gas flaring, et cetera.

Robert L. G. Watson

We think we're in good shape. I don't think anybody in North Dakota exactly understands what the NDIC is trying to do. In fact, I just read an article from the head of the NDIC saying that yes, they need to answer some questions and they don't have the answers yet. But I think since we are hooked up to an existing gathering system and that we are selling the vast majority of our gas right now anyway, we're well under the 26% target. I don't think we're going to have an impact. We are in pretty constant communication with One Oak, our gas gatherer. And they know what our drilling plans are and so far have said that they certainly have the capacity to take us, especially with the new plants that they're putting online. So we're hopeful that we don't have an impact from that. But until they come out with more definitive answers on what the regulations really say and mean, we can't come up with a definitive answer on where we stand.

Operator

[Operator Instructions] Your next question comes from the line of Noel Parks of Ladenburg Thalman.

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

Just a couple things. Is -- talking about, on the Ribeye Wells that you've designed the fracs to avoid some of the, I guess, sort of the spotty areas you saw along the lateral section. Is that sort of case-by-case examination, something that is particularly time-consuming? Or difficult to do or is it just something you can just sort of fold into your routine as you look at each well going forward?

Robert L. G. Watson

Well, I think it's going to be in our routine. Whether it's -- I think it's well worth the time we spend on it. And it's a multidisciplinary -- discipline process. I mean, the geologists, geophysicists and engineers all contribute. But it's still work in progress for us. We really don't know whether avoiding these areas has an impact or not. Hopefully, we'll get some sort of color on that by the Ribeye performance. So it's certainly something we're going to continue to work on because we are determined to find out why our performance is what it is on our various wells. And hopefully, we can use that knowledge to -- in our development going forward. But I would say at this point, every well we drill or every couple of wells we drill, are going to be -- there's a lot of education involved and hopefully, we'll learn from each one and make the next ones better because of that.

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

Got you. And I think you're talking about 7,000-foot laterals on the South Bakken at Jourdanton. Is there any ability or any practical advantage to being able to go longer? Or are there any locations you have that would support a still longer lateral?

Robert L. G. Watson

We are bounded by 2 major faults. It's not necessarily lease line at Jourdanton, it's geology that binds -- that bounds us and we have a pretty good handle because of our 3D of where those faults lie. I think some of the laterals in the south fault block might get as much as 8,000 feet and certainly, there's some shorter ones in there too, but the average is going to be considerably more than what we're seeing in the north fault block.

Stephen F. Berman - Canaccord Genuity, Research Division

Great. And just one more thing. I'm sorry if you mentioned this earlier. Are you essentially HVP on the north fault block at Jourdanton at this point?

Robert L. G. Watson

Yes. 100% of the north fault block is HVP. Now we'll start HVP in the south fault block but we've got 3 years to do that.

Operator

[Operator Instructions] Your next question comes from the line of Mr. Mike Scialla of Stifel.

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

Just wanted to follow up on Noel's question on the Ribeye Wells. You said you designed them to avoid these problem areas. What exactly is it that you're looking at there? Is it a frac barrier that's missing in those areas? Or can you just elaborate a little bit more on that?

Robert L. G. Watson

I guess, the easiest way to explain it is that this is a groven system, so it's pretty geologically complex. And there are a number of smaller faults in between the major binding -- bounding faults. And we see them on 3D for the most part. And the ones we don't see on the 3D, we see when we drill the well, so we know where they are and consequently, we know when to expect them in the offset wells. And we're thinking that those -- the frac-ing wells near those fault cuts could be a divergent of the frac energy down or up into another zone, down along that fault plane. So we're trying to keep the fracs away from contacting those faults. Also where the well wanders down closer to the Buda than perhaps we want to be, just to give us a little comfort that we're not frac-ing down in the Buda just because we're too close to it, we're avoiding those zones. And in the rare occasion where we've had to sidetrack because the steering went the wrong direction, either up or down, we feel like staying away from those sidetrack holes might be prudent as well, because they might be stealing the frac energy. No definitive answers yet, but those are some of the things that we look at when we're looking at our laterals and designing where those stages are going to be placed or not placed.

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

That helps. That seems to make sense, to me, anyway. Is there any way to tell where the frac intensity -- natural fracturing intensity might be greater or less based on the seismic data that you have?

Robert L. G. Watson

Well, the common inference would be that the closer to those little fracs, the more faults, the more micro fracs you're going to have. We don't know whether that's a good thing or a bad thing at this point. I guess the best knowledge we're going to have in a development phase is that we'll have well control and that's, by far, the best data that we can use to determine where to avoid and what not to avoid. So it's just going to be a learning experience going forward, it's a challenge, there's no question about that, but we're up to it. And we certainly think that the rewards certainly justify the risk.

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

Sounds like based on what you've seen so far, you don't really see a greater amount of faults in the wells. The Spanish Eyes really didn't have any greater faulting than what you saw in the Blue Eyes or the Snake Eyes?

Robert L. G. Watson

Yes. That's a true statement. The Spanish Eyes did wander down a little bit closer to the Buda than perhaps we should have. Spanish Eyes have a frac track in it? Yes, Spanish Eyes did have a sidetrack where we had a Buda strike and we didn't avoid it in frac-ing that well. So that was one of the reasons we decided we'd better avoid the area of a sidetrack in one of the Ribeye wells. We had a sidetrack in one of them, not in the other. And sidetracks are pretty common, especially in a geologically complex area. You don't always know where you are exactly and sometimes you get a curve ball thrown at you, and you find out too late in the game that you're too close where you want -- don't want to be. So you have to come back up hole and redrill the lateral.

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

Yes. Okay. And then you had mentioned at I believe it was in the Cave area that you're pretty close to Marathon Well offsetting one of the wells. Can you -- do you have an estimate for it, in terms of feet, how far away you are?

Robert L. G. Watson

Yes, 660 feet away. So I think that -- I said that could be one of the reasons it's not quite as strong as the #2. Don't know for sure. If we come in with 2 real strong wells on the 3 and 4, that might give us a reason to say, well, yes, we're closer to a well that had been producing for 3 years and maybe there's some pressure depletion involved. Who knows at this point, but time will tell.

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

Given that -- I mean, maybe it's not as strong as the other well, but it still, to me, looks like a pretty strong well. What does that imply to you? Is there any downspacing potential at Cave or Dilworth for that matter?

Robert L. G. Watson

Probably not. We've already designed them to be 330 feet apart. Yes, the #1, yes, it's a good well. There's no question about it. And longer-term, if all the wells are like it, we're going to be very happy. But I can't see that downspacing any tighter than we already are, except maybe into the Upper Eagle Ford, which is getting a lot of play, as you're probably well aware. And the Eagle Ford and Cave and Dilworth area is pretty thick. So we're pretty confident that our frac link is not covering the entire Eagle Ford section. So there might be some time in the future where you screw up your courage and drill an upper Eagle Ford test to see what it will do.

Michael S. Scialla - Stifel, Nicolaus & Company, Incorporated, Research Division

Yes. Last one for me. I guess just to follow on to that, is there any potential for that in Atascosa County as well?

Robert L. G. Watson

Well, if you'll remember, the very first well we drilled in Jourdanton back in 2011, we didn't have 3D seismic, we crossed a fault pretty early and the well became up thrown, and it basically was an upper Eagle Ford test. So we're pretty comfortable that the upper Eagle Ford does work. Now whether it's economic or not, we don't know. But certainly, it's productive of oil when you're up there. It just looks like the lower Eagle Ford might be better at this point.

Operator

Your next question comes from the line of Mr. Mike Kelly.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Got a question for you on the capital program here. You came to the market to do the equity deal, increased the budget by $65 million and was announced in June. You're keeping 1 rig active full-time in the Eagle Ford now. As you move into '15 and maybe you guys add some more acreage at Dilworth, how do you think about the progression in terms of either, think about it in terms of the number of wells drilled across the board next year? Or in terms of just how many rigs you'll have active?

Robert L. G. Watson

I think there is -- if we continue with success in adding pieces of acreage here and there in the Eagle Ford, which we're pretty confident that we will, there's a good possibility that we could add a second rig starting 1st of January. I would say good success in the South block at Jourdanton would also dictate possibly a second rig there, just to move the NAV forward or the -- reserves forward and increase the NAV. So we're -- we've got 6 months or actually 3 months before we have another -- our budget board meeting and make that decision. But I'd say there's a pretty good chance we'd have a 2-rig program going in the Eagle Ford and continue our 1-rig program in the Bakken next year. But certainly, nothing definitive at this point.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Got it. Great. And maybe one more for me. It looks like July production, pretty strong from you guys. Just curious, you left the guidance at the 5,800 to 6,000 for the year, exit rate at 8,000. What are the factors in your eyes the would cause you to come in either above and below those guidance ranges that are out there?

Robert L. G. Watson

Now that's a good, tricky question. But I would say that continued performance and timing that we've seen gives us more and more comfort on beating those numbers. July production was 6,600 barrels a day, and our guidance for whole quarter was 6,600 barrels per day. Keep in mind that number includes those 6 new wells that went online late second quarter. So we're seeing some flushed production. And you can't fool yourself that you're not going to see significant declines as you see in all of these resource plays. We get comfort from the fact that we've got 5 new wells coming online this week and a sixth one as soon as we get the repairs job done. And then follow that up with the 2 Cave wells, hopefully online by the end of the quarter. And 3 new Stenehjem Wells and 1 old Stenehjem well hopefully on by November or so. So we're pretty confident in those numbers. But a lot of things can happen, early winter blizzard in North Dakota could slow things down. And I can't see what would get us terribly in the Eagle Ford. And then well performance. We're still counting on achieving the results that we've experienced so far to date. I guess there's no lead pipe cinch that, that's going to happen. I think we're confident of it. But until you get the wells on production, you never know.

Operator

This concludes the question-and-answer session. We will now proceed with closing and/or any additional remarks.

Geoffrey R. King

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

Operator

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

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