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Resolute Energy (NYSE:REN)

Q3 2013 Earnings Call

November 5, 2013 4:30 p.m. ET

Executives

Michael Stefanoudakis – SVP, General Counsel and Secretary

Nick Sutton – Chairman and CEO

Ted Gazulis – CFO and EVP

James Tuell – Chief Accounting Officer and VP

Analysts

Noel Parks – Ladenburg Thalmann

John Freeman – Raymond James

Jason Wangler – Wunderlich Securities

Ron Mills – Johnson Rice

David Tameron – Wells Fargo Securities

Ryan Oatman – SunTrust Robinson Humphrey

John Nelson – Citigroup

Operator

Good afternoon, and welcome to the Resolute Energy Third Quarter 2013 Earnings Conference Call. (Operator Instructions) Please note this event is being recorded. I would now like to turn the conference over to Michael Stefanoudakis. Please go ahead.

Michael Stefanoudakis

Good afternoon, everyone. My name is Michael Stefanoudakis, I'm the Senior Vice President and General Counsel of Resolute. I'd like to read the forward-looking statement before turning the call over to Nick Sutton, our Chairman and CEO.

This investor conference call includes forward-looking statements within the meaning of the Safe Harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Words such as expect, estimate, project, budget, forecast, anticipate, intend, plan, may, will, could, should, poised, believes, predicts, potential, continue and similar expressions are intended to identify such forward-looking statements.

Forward-looking statements in this conference call include matters that involve known and unknown risks, uncertainties and other factors that may cause actual results, levels of activity, performance or achievements to differ materially from results expressed or implied by this investor conference call. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this call. A listing of the material risk factors faced by Resolute appears in our Form 10-K and is updated periodically in the Form 10-Qs and our other public filings.

At this time, I'd like to turn the call over to Nick Sutton, our Chairman and CEO.

Nick Sutton

Thank you, Michael. Good afternoon and welcome to Resolute’s third quarter 2013 earnings conference call. In our earnings release that went out last night we covered in detail our quarterly progress and results. Therefore in deference to your time we will limit our comments before turning to Q&A.

In my way of thinking the most important development during the quarter was our successful transition to drilling horizontal wells, both in the Permian basin and in the Powder River basin. During the third quarter and spilling over into Q4, we successfully drilled and completed four horizontal wells, three in the Permian and one in the Powder.

We discussed early results in the release but for purposes of your models, you might note that on a program basis, the Gardendale wells cost approximately $7 million each reach. Reeves County wells will be more costly at $8 million to $9 million due to more difficult drilling conditions and greater depth. And the Turner/Frontier wells should come in slightly more than $6 million.

Wells early in the program are expected to have extra expenditures for science, such as logging, micro-seismic, and diagnostic fracture testing. As noted in the release during the quarter we added to our Permian basin acreage position, and we expect that activity to continue. Also you will recall that we have about 45,000 acres in the Powder River basin, all of which is held by production. In other words, our current acreage footprint gives us years of visible growth and we expect to add to that position in future months and quarters.

I know that you are anxious to hear about our plans for 2014. We currently are in the midst of our annual planning cycle. We expect that we'll have our board signed off within a month or so. In the meantime, I can tell you that our expectation is that we will continue our horizontal focus and likely we will accelerate our level of activity. Permit cycles in the Powder can take time as much as the land is federal. But as noted, we have two more permits in hand with about half a dozen more in process. Permit cycle time in the Permian is much more manageable.

Aneth Field continues to deliver extremely impressive surprises for a field that has been under secondary and tertiary recovery for decades. But that’s the nature of a giant oil field. Looking around the globe, fields of this size and quality have a way of experiencing reserve expansion. Now as to whether the impressive wells that we drilled this quarter reflect new reserves, reserve acceleration is the topic for engineering discussion. Suffice to say for now, peak IPs of 350 to 650 barrels of oil per day are sweet particularly at an average cost of about $1.5 million per well.

As for the sequential decline in production, over half of that is directly attributable to the Bakken asset sale. However there's no denying that operational considerations impacted our Q3 production. As just one example of an operational consideration, we mentioned the impact of delays in Gardendale. I’d remind you that we assumed operations of Gardendale the beginning of the second quarter. We kick-started at the 19-well vertical program from scratch. So there was a period of time during which we weren’t exactly on schedule with service providers. We were, in fact, in a state of early mobilization. That has largely been rectified at this time, so in upcoming quarters I wouldn’t expect us to experience delays comparable to those in the third quarter.

We have dealt with most of these operational considerations and we came out of the quarter with production on an uptick. October production was up significantly from the Q3 average and we should expect to see an increasing impact of activities that took place late in the quarter. For example, many of the Gardendale vertical wells were turned online late in the quarter and the contribution from the horizontal wells will be felt in Q4 and into 2014. As a result, we remain reasonably confident to being able to reach at least low end of our previously announced guidance of roughly 12,000 to 14,000 boe per day.

To summarize, we have a diverse portfolio of oil prone assets giving us the ability to direct capital into projects having very attractive returns. So it’s an exciting time for us as we ramp up the horizontal activity. We began to convert a significant resource we have captured into production and value. I will now turn the call over to Ted Gazulis to discuss the drivers of our financial results. Ted?

Ted Gazulis

Thank you, Nick. In keeping with Nick’s approach rather than reciting the financial section of the press release back to you, I will focus on the big picture. To find more granularity go to our website www.resoluteenergy.com where an investor presentation has been posted that contains supplemental statistical information.

Nick talked about production and we discussed revenue in the press release. So let’s turn to costs where we saw positive result. Aggregate lease operating expense declined 2% sequentially mainly as a result of a lower sequential production as Nick discussed earlier. The per boe metric increased by 11%. This is a theme that ripples through most of the per-boe metrics. Aggregate production taxes decreased as well by 14%, partly as a result of growing production from lower tax areas, partly due to lower production. Product tax per boe actually decreased by 3%.

Aggregate G&A costs were down by 3% as well, while G&A per boe increased by 9%. I would note that as we continue to grow our staff to develop and optimize our production needs, aggregate G&A is likely to decline. Although we believe that increased production will result in decreased G&A per boe over time.

We believe it’s important to note that early fourth quarter production volumes have increased materially over what we reported for the third quarter and pro forma for the sale of the Bakken properties were ahead of our second-quarter production needs. This is due to our drilling in the Permian basin, our Turner/Frontier well in Hilight and our the operational gains in Aneth. We expect our per boe cost numbers to show improvement in the fourth quarter as that increase in production was through our financials.

Cost improvements helped maintain cash flow and our adjusted EBITDA, a non-GAAP measure, was $38 million in the third quarter or 44% higher than the same quarter last year. At $35.88 per BOE, third-quarter adjusted EBITDA was 4% higher than the second-quarter and 17% higher than the same quarter last year, despite revenue net of realized derivative loss, was decreasing 8% and 9% respectively.

This might be a good time to make a comment about our hedge fund. As you’re probably aware, we restructured certain derivatives contract at the end of August. As a result, our average weighted swap price for oil increased from $79.41 per barrel at the end of the second quarter to $97.02 per barrel at the end of the third quarter. That higher swap price only affected one month of third quarter result, but it will be applicable through the rest of the year.

Turning now to our capital program, we invested $83.9 million during the third quarter, primarily into the growth initiatives at Aneth and in the Permian basin, bringing our total capital investments through the first nine months of 2013 to $186.9 million. The total does not include the $258 million used to acquire oil and gas assets in the Permian basin earlier this year. Based on expenditures through the first nine months, we anticipate total operational CapEx for 2013 to be at or near the upper end of our guidance range $195 million to $220 million.

Finally, let me talk about liquidity. At September 30, 2013 we had $285 million drawn on our revolving credit facility, which have a borrowing base of $415 million. We are engaged in our regular semi-annual redetermination process and I do not expect the borrowing base to change. Based on anticipated cash from operations and existing liquidity, we’ve got financial resources sufficient to fund our capital program for 2013.

Thank you for your time and your interest in Resolute and I will turn it over to Nick.

Nick Sutton

Thanks, Ted. Before we head into Q&A, I want to let you know that we plan to provide you with an operations update in December that will include updated results from our horizontal wells along with any other developments at that time.

With that, I will turn the call back to the operator for Q&A.

Question-and-Answer Session

Operator

(Operator Instructions) The first question comes from Noel Parks of Ladenburg Thalmann.

Noel Parks – Ladenburg Thalmann

Just a couple things. The completion on the first horizontal, the Midkiff 1818, did that go roughly as expected? I think if I remember from the last quarter the TD early August?

Nick Sutton

I will say it went as expected as much as one can have an expectation from something as complicated as completed one of these horizontals wells. We got off the stages that we anticipated, somewhat more smoothly than others. But overall the results were in line with what I would expect to be sort of normal results from a horizontal well.

Noel Parks – Ladenburg Thalmann

And for Ted, I just have a question on the interest. Was the capitalized interest figure lower this quarter than it had been previous quarters? The GAAP interest expense on the income statement was higher than I expected.

Ted Gazulis

That’s a more technical question than I am prepared to answer at this point. I am going to – let me think about that and have Jim Tuell, our VP of accounting have some numbers out and I will try to answer that as we go forward through the Q&A.

Noel Parks – Ladenburg Thalmann

And I guess just the one last thing then. With the Turner well, it seems like a real nice horizontal out there. I remember back at the analyst day you guys were talking about your seismic work led you to a better understanding of sort of how the reservoir, Turner reservoir varied across the acreage. I was wondering, did your success in this well, did it have any implications for sort of validating the seismic you’d done?

Nick Sutton

Good question. I think that at the analyst day, what we discussed was how the seismic doesn't necessarily identify prospective Turner versus non-prospective Turner as much as it can help eliminate certain areas. In other words, you can look at one well versus another well with various seismic attributes. So it’s not a magic bullet. The thing that we’re looking for is there anything in the seismic signature which would cause us to question our ability to achieve certain results relative to other wells that have been completed in the Turner in the general vicinity. So I would say that the first well is positive in that going into it, we didn't see anything in the seismic that would cause us to have questions or concerns. And I think the initial results certainly are positive in that respect.

I'm not sure at this point because it's very early and we’ve got a lot more work to do, just how far we can really run with that project and how much the seismic will help us in that evaluation. As I recall back at that analyst day meeting, we anticipated that we would have something like 12,000 of our 45,000 acres being initially prospective and we would move across that 12,000 acres and let the reservoir speak back to us in a way that then we can continually evaluate and reevaluate the extent to which we might be able to run with the program in the Turner on that acreage. So all in all, very positive results, we’ve got what appears to be a nice well. We are getting good oil cuts. But it is, I would emphasize, real early in the production history of this well. But I would also then underscore today as we have in the past, we have 45,000 acres all HBP. So we can let this program unfold in a very judicious manner. So all in all, great place to be, great acreage position and a great start, more to come in future months and quarters.

Operator

Our next question comes from John Freeman of Raymond James.

Nick Sutton

Before we go to John, Jim Tuell can answer that interest question that Noel asked.

Jim Tuell

No, with respect to interest capitalization, we disclosed in the 10-Q that we capitalized $4.7 million of interest in the second quarter and that number was reduced to $4.3 million in the third quarter. Generally accepted accounting principles allow us to capitalize interest on qualifying assets that are not subject to amortization. And so you can see that number or a number that’s very close to that number, as unproved properties on our balance sheet and you can see then by looking at the two balance sheets, that at the June quarter we had about $300 million that was eligible for capitalization and at the end of the third quarter only $270 million eligible for interest capitalization, and therefore yes, we capitalized less during this quarter.

Nick Sutton

Thank you, Jim. Now let’s move on to John.

John Freeman – Raymond James

Congratulations on the first Permian horizontal, especially on the cost side on these initial wells. On the Midkiff, you mentioned the completion part of it was $4.2 million, but that included the micro-seismic. What would that be ex the micro?

Nick Sutton

Roughly 350,000 for the micro-seismic.

John Freeman – Raymond James

And then looking at sort of your acreage position, I realize that in some cases you've got lease line constraints that don't allow you to take a lateral out further. But in certain areas where you do, just based on some of the success at some of your offset operators have had with longer laterals, do you have any near-term plans to test that concept?

Nick Sutton

Yes, in certain respect, John, we are going to let the acreage sort of dictate that. We believe that we have the capability to go out with a long reach laterals. We’ve got -- our drilling team has been performing extremely well, don’t have any issues there. So in effect, the acreage is going to dictate and guide how far out we go with the laterals.

John Freeman – Raymond James

And then moving on to the Turner, it was a pretty exciting well. Can you just give me more specifics on that well in terms of what the design of it was, the lateral, what the well costs?

Nick Sutton

Sure. The lateral was 4400 feet. We completed that with 17 stages, 3.4 million pounds of sands, 47,000 barrels of water, pretty much that describes it. There was a sliding sleeve completion.

John Freeman – Raymond James

Sliding sleeve, and what was the completed well costs?

Nick Sutton

It’s expected to come in at about $6.3 million and that includes some logging.

John Freeman – Raymond James

And maybe I might have to wait until your operational update next month for this, but seeing as how that well has been online for, I guess since it was completed nearly a month, do you have a current production rate on that? I'm just trying to comp it against the other wells that you provided in your presentation.

Nick Sutton

It has not been online for a month. By the time as we go through all the steps that need to be gone through in order to get the well completed and then on production, it’s been on production for roughly a week. And we’ve said that, that’s the IP; in fact, it’s going up and down, but tomorrow produce more than what we said was to date but the one day high.

John Freeman – Raymond James

And so for the operational update in December, in addition to those horizontal Permians that are finishing up, will we get an update on maybe the 30-day rate on this Turner?

Nick Sutton

I would hope so. Absolutely we hope so and I hope we will be able to give you little bit more granularity on how things are going on in Reeves county and whatever else we can provide you with at that time.

Operator

Our next question comes from Jason Wangler of Wunderlich Securities.

Jason Wangler – Wunderlich Securities

Talking to you guys a couple months ago, the rig that you were using for these horizontals was doing pretty well in the Midland basin. I'm just curious what are your drilling days for those first three wells? And then did you use the same rig as you moved over to the Delaware?

Nick Sutton

Yes, we talk about in the press release how that rig and our team have performed over in the Midland basin bringing the spud to TD day count down considerably. So getting good efficiencies, things are working very well with that rig. And so we decided it was well worth to hold onto it and to move that over and hopefully perform as well for us over in Reeves county.

Jason Wangler – Wunderlich Securities

And then just curious on the acreage pickup. Are you still seeing more around your current spreads that get pick up some more opportunities, or maybe where you even got those opportunities that came up?

Nick Sutton

Yes, it’s a great question but it’s a question that I always dodge it, Jason, it’s kind of like leasing is competitive and I love to be able to tell you that we’re just leasing on the moon and that way we can deflect all the questions that might come or the big noses that are trying to get under the tent to figure out what we're doing where we doing it. So I will let you figure out what probably makes sense from a business standpoint and you probably are even pretty close.

Operator

Our next question comes from Ron Mills of Johnson Rice.

Ron Mills – Johnson Rice

You talked about, obviously the focus on the horizontal program for next year. As we look ahead to 2014, is the steady state just to assume a one-rig program? If so, how should we handicap a Reeves county/Delaware basin versus the Gardendale/Midland Basin activity, as you would see it now?

Nick Sutton

First of all, as I mentioned earlier, we are in the process of our planning cycle. We intend to live within our means. But that said, we look at – all of the activities that we have that are competing for capital, and certainly these horizontal wells rise up toward the top and we will get a lot of our attention, whether that is one well or one rig, two rigs, or even three rigs, remains to be seen. Our planning process will – we will evaluate those options and we will act accordingly. Now I will tell you what my personal sort of gut feeling is right now at this very preliminary stage. In other words, I am giving you a bunch of weasel words that, I can say well, I said maybe.

I would say that it’s not likely that we’re going to stay at one rig. I think that we’ve got capability financially, I think we’ve got the capability operationally. I think we’ve got the capability from a running room standpoint to go above one rig and whether that means two, or three rigs, remains to be seen. As to Delaware versus Midland, certainly to this point we are relying on -- in the Delaware basin for horizontal, we’re relying on information that we have relating to our colleagues out there, other operators. And we are participating with another third-party in a well a little bit south of the main part of our acreage block, plus we are drilling in our area, slightly further north. That’s going to be our first in-house information, where we really have the granularity we like to see.

And so that's kind of a long-winded way of saying in certain respect the wells are going to tell us where the capital is going to go. We have the three over in the Midland basin and by the end of the year we should have two in Delaware basin and frankly, in our capital allocation process we look at which opportunities rise to the top subject to various other considerations, like lease expirations and what not. But we frankly don't have any significant lease expirations in that area, so that’s not a driving factor for us at this time at least.

Ron Mills – Johnson Rice

I guess that's why you have a Safe Harbor statement, Nick?

Nick Sutton

That’s right.

Ron Mills – Johnson Rice

As it relates to what you just said about the running room, I know you have presented your inventory differently than some other companies. In the Permian, you talk about 70 to 75 locations, although that would be from one zone. Can you remind what that's based on in terms of spacing and is the incremental -- potential incremental running room really a function of the stacked pay opportunity, or is there opportunity that even just from your primary zone, that 72 locations in your latest presentation is even higher?

Nick Sutton

Well, the answer is yes to both. When we look at our locations, you’re absolutely right. We’re looking at just locations and they have tended to be on four locations per section. Now there are operators talking about tighter spacing and as you know, Ron, that the discussions in the engineering panels and the SBE conferences and what not on these activities, a full of papers being presented as people are struggling to determine what is the optimal spacing with these unconventional plays. We think our forward perception is relatively conservative. And so we could see additional down-spacing in that sense.

The other part of it, as you touched on is just the different zones, and one area we are doing Wolfcamp A and another area, you are doing Wolfcamp B. To a certain extent we like to be a fast follower, and that's always a sort of a difficult decision how fast you move and to try some of these other formations. We would just assume let some of our colleagues with deeper pockets do some of the testing on the vertical section. But there is no doubt that the industry does believe that there are numerous potential targets in that, very think stratigraphic section in Permian basin. And when we say 70 locations time will tell whether that's 50 as opposed to 70 or 100 as opposed to 70 and time will tell how many laterals we can get out of one location as we go deeper or shallower in the sections.

Ron Mills – Johnson Rice

Are you restricted by any depth, Nick, in terms of -- people are talking about Wolfcamp A, B, C, D. Joe Mills, Sprayberry [ph], do you have rights to all depths, or do you not have access to some just based on the lease terms?

Nick Sutton

We have access with certain restrictions to all zones, there's only one area that comes to my mind where it's a non-operated area and there's a little donut hole on the acreage where we don't have the deeper rights. Now that said, we are subject to few clauses and things like that. Now in our Reeves county acreage, you will recall particularly in what we refer to as our Mustang block of acreage. We’ve drilled a number of vertical wells and so we’re able to hold down to the deepest section that we penetrated and are getting some production. And so that gives us quite a bit of vertical let’s say coverage, and the same thing in Gardendale, we’ve got good vertical coverage. So it's not like we’re starting out, we’re going into the Denton [ph] and yet that doesn’t hold B or deeper. In some areas that will be a consideration that we will deal with as we deem appropriate. But by and large we’re in pretty good shape.

The other complication, of course, that you run into in this area that you're sure aware of is, you run into drilling obligations. So that’s just one of the other things that we have to factor into our allocation of capital. But we’re in pretty good shape from vertical coverage.

Ron Mills – Johnson Rice

And then lastly, just to make sure I'm comparing apples to apples, for both the Turner and the Gardendale type curves that you have, just trying to compare the data from your wells. In that type curve, are you assuming the 4,000-foot to 4,500-foot lateral in both areas? Just so I can just try to triangulate the IP rates that you have provided, and once we get 30-day rates from those wells, make sure that the type curves are based on the way you are currently drilling the wells, not potentially longer laterals?

Nick Sutton

That’s right. We are basing our type curve on the laterals that we’re currently drilling, and we would expect the type curve to hopefully go up as we go to longer laterals.

Ron Mills – Johnson Rice

And then Ted, share count – just noticed the share count of 73 million shares is lower than what it showed on your second quarter 10-Q as of that filing date. Is there something going on in the share count that you reported in the income statement that I'm missing?

Jim Tuell

I will go ahead and take that one. Obviously briefly accounting principles tell you to always report the worse EPS number you can, or that the worse one that you can possible derive. And if you have income for the quarter you use the most shares as possible, including potentially diluted shares and warrants etc. that are out there. When you have a loss you start clawing back all of those things, plus even performance shares and other things that are subject to profit in the future, or whatever. So it’s really just a change from income one quarter to a loss one quarter and taking those securities in and out of the calculation.

Ron Mills – Johnson Rice

And so in reality, it really is performance-share related, because the warrants and stuff wouldn't be included in that basic shares, correct?

Jim Tuell

You are right. You have asked a GAAP question that really is through the – you go through all the GAAP literature and it tells you what to do and by swinging from a positive to a negative it affects your share count.

Operator

The next question comes from David Tameron of Wells Fargo Securities.

David Tameron – Wells Fargo Securities

I'm going to leave Permian and Powder alone, because I think we beat that to death. Can you just talk about Aneth, and some of the issues during the second quarter or third quarter, and then how we should think about the production profile over next couple quarters?

Nick Sutton

Aneth has performed really very, very well. We had – we refer to operational considerations -- we were drilling a couple of locations in the Aneth unit. And you can see some of the results that we've gotten from some other drilling in Aneth field, that encouraged us to drill and also some of these are drilling for an injector support. We had a couple of these wells being drilled in an area of very high pressure and for safety and operational considerations, we decided we had to drawdown the reservoir pressure in that vicinity in order to drill these wells effectively and safely. And we deferred injection in some of the surrounding injection wells.

Well one of the things about a CO2 flood is when one stops injecting one does impact production. And it impacted production somewhat more quickly and somewhat greater than we might have otherwise thought. As you know CO2 floods are incredibly complex as the fluids process through the reservoir and it's not like a matter of turning a valve on or off an injector and getting in on off in the producer. And so as I said we stopped injecting an area for safety reasons, we got the wells drilled, and we started injection again. And just as we saw a rather quick response – on the downside we saw a rather quick response on the upside. And so as we exited the quarter, I believe that our production from that area was pretty much back where it was before we had to terminate the injections. So that’s just one example of what went on in Aneth during the quarter.

David Tameron – Wells Fargo Securities

I guess you've addressed the production's back on line. I guess that's -- everything else was asked and answered. So congrats on the horizontal success. Nice wells in both.

Operator

The next question comes from Ryan Oatman of SunTrust.

Ryan Oatman – SunTrust Robinson Humphrey

You've alluded to the October current production significantly above the 3Q average. Do you have that number on hand and could you share it?

Ted Gazulis

It’s getting a little bit more granular than we choose to get in call like this. Let’s leave it production is up significantly as I said on the call. That’s about as granular as I think appropriate for a call.

Ryan Oatman – SunTrust Robinson Humphrey

And then with Reeves county, can you talk about what you are targeting with this first test? I know there has been, obviously, a lot of success in both the Wolfcamp A, Wolfcamp B. Just curious as you move that rig over there your thoughts on different zones' prospectivity, and what the plan is for that rig?

Nick Sutton

In Reeves county, we are going to go initially for Wolfcamp A and you're right when you suggest that some other operators around this have drilled and move some of the other ventures. We think there is good prospectivity there and -- but we’re targeting right now the A and we can move onto the B in due course but perhaps another -- some other targets in that section.

Ryan Oatman – SunTrust Robinson Humphrey

And do you plan a similar sort of 4,500-foot lateral type well out there, or does your leasehold allow you to go longer, or would you try something different in terms of the frac stages, sand volumes, et cetera?

Nick Sutton

The initial wells are on acreage that just by chance supports about 4400, 4500, 4600 foot lateral. And so that's what we'll be doing on the first round of wells. We do have some acreage out there that would support longer laterals. But as we rate the acreage based on the other considerations, proximity to infrastructure, for example, the shorter laterals went out. As to the exact completion methods, our approach to that, Ryan, is to a certain extent, we let the formation talk to us. We do it in there with a well thought out or what we consider to be a well thought out frac program, how many stages, how many feet between the stages, how much sand, what kind of sand, how much fluid etc. etc. etc., But as we move forward within a single well and as we go to well 2, well 3, well 4, we will have accumulated data where we let the reservoir speak back to us. And it’s common to sort of adjust the frac treatment on the fly based on what we’re seeing and in terms of reservoir response. So yes, you can expect to see changes as we move through our drilling in Reeves county and frankly in the Midland basin as well.

Ryan Oatman – SunTrust Robinson Humphrey

Great, I understand. One last one for me. Obviously, I've seen the activity around the Gardendale asset, very significant industry activity horizontally there. With your OTB asset, have you seen horizontal activity pick up in the interim? I will leave it at that.

Nick Sutton

With respect to OTB it’s not as active as around Gardendale, but gosh, it's just that -- that area more broadly speaking has got so much activity and it seems to be moving toward OTB and I would personally be very surprised if we don't see more activity around OTB from a horizontal standpoint in upcoming quarters.

Operator

Your next question comes from John Nelson of Citigroup.

John Nelson – Citigroup

Congratulations on the horizontal activity. I wanted to focus on Gardendale. You talked about earlier being a fast follower once industry is able to sort of de-risk some of these other potential intervals. I guess as you look out to ‘14, full development plan isn't in place yet, but do you think you'll stick with Wolfcamp B, or do you think you'll potentially test some other intervals at Gardendale in ‘14?

Nick Sutton

I think that initially we will stick with what we are collecting data on and getting frankly some pretty good results. But as we move through the program and the decisions like that are often made on the fly and if somebody is offsetting us with an extremely good well in a different part of the section we will pay real close attention to that and factor that into our plans for the year.

In other words, we could get down into May having drilled however many wells in the B and besides the next well, or well supported regions should be targeting a different formation, we will make that decision as appropriate given the changing circumstances that we see in the field perspective, our results and results of operators around us.

John Nelson – Citigroup

And then if I just could on 2013 CapEx actually, I was wondering if you could help me think about sequentially what would be changing that we could still stay within the current CapEx guidance. Is it just the loss of vertical wells in the Permian – Gardendale, sequentially, that's going to go down, or is there any other moving pieces there we should think about?

Ted Gazulis

That’s essentially it. I mean at the end of the day, we’ve shifted our focus in terms of what we are doing. We had considered drilling more vertical wells and we had anticipated drilling more vertical wells, and realistically based on what we are seeing, those wells are – we don’t compete wells for capital right now.

Nick Sutton

And if we look at the third quarter, we had three horizontal wells in the Permian and one in the Powder. It’s not realistic to think that we are going to spud another well in the Powder until we roll into 2014. There are some land related issues, or let’s say you get stipulations and other things and as they get in and come into play. So that program will not be consuming capital through the end of the year and we just have one well drilling in Reeves, we will drill another one in Reeves, the completion of that second one will probably spill over to 2014. So it’s just the nature of the way that the plans layout right now.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to Nick Sutton for any closing remarks.

Nick Sutton

Well, I would just like to conclude by saying thank you again for -- all of you who have been on the call. We know the time is precious this time of the year and we appreciate your interest in our company and in our progress. And we would emphasize as always that we are going to answer any questions you have, what we can answer we will answer and what we can’t for Reg FD or other reasons we can’t answer, we won’t. But that is an open invitation, contact us and if you need some additional clarification or additional information. So again thank you so much for your time and interest.

Operator

The conference has now concluded. That you for attending today's presentation. You may now disconnect.

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