Energen's CEO Discusses Q3 2013 Results - Earnings Call Transcript

Oct.30.13 | About: Energen Corporation (EGN)

Energen Corporation (NYSE:EGN)

Q3 2013 Earnings Call

October 30, 2013 10:30 AM ET

Executives

Julie Ryland – VP, IR

James McManus – Chairman and CEO

Charles Porter – VP, CFO and Treasurer

John Richardson – President and COO

Analysts

Ryan Oatman – SunTrust Robinson Humphrey

Gabriele Sorbara – Topeka Capital Markets

Eli Kantor – IBERIA Capital Partners

Tim Rezvan – Sterne Agee

Cameron Horwitz – U.S. Capital Advisors

Jeffrey Campbell – Tuohy Brothers Investment

Christine Cho – Barclays

Operator

Good morning, ladies and gentlemen, and thank you for waiting. Welcome to the Energen Third Quarter Conference Call. All lines have been placed on listen-only mode, and the floor will be open for your questions and comments following the presentation.

Without further ado it is my pleasure to turn the floor to your host, Ms. Julie Ryland. Ms. Ryland, the floor is yours.

Julie Ryland

Thank you, Amanda, and good morning. Today’s conference call is being held in conjunction with Energen Corporation’s announcement this morning of its most recent Wolfcamp shale well result in the Permian Basin, as well as the financial and operating results of three months ended September 30, 2013. Locator maps for our Wolfcamp wells can be found on Energen’s homepage, www.energen.com.

Our comments today will include statements expressing expectations of future plans, objectives and performance. These constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. All statements that are based on future expectations are forward-looking statements and these are dependent on certain events, risks and uncertainties that may be outside the company’s control and could cause actual results to differ materially from those anticipated.

Please refer to the company’s periodic reports filed with the SEC for a more complete discussion of the risks and uncertainties that could affect the future results of Energen and its subsidiaries.

At this time I will turn the call over to Energen’s Chairman and Chief Executive Officer, James McManus. James?

James McManus

Thanks, Julie. Good morning to you all. Energen tested four new Wolfcamp A wells on the Permian Basin during the third quarter of 2013. All produced at attractive initial rates and oil accounted for more than 50% of the product stream in each well. We remain very encouraged by the strong results we are achieving in the upper Wolfcamp shale in both the Midland and Delaware basins.

The bodacious well in the eastern half of Reeves County was particularly impressive. With a peak three stream 24-hour IP of 2029 BOE per day this is the best Wolfcamp IP reported to date in the southern Delaware basin to the best of our knowledge.

We plan to accelerate the pace of our Wolfcamp drilling in the Midland basin in 2014. We’re seeing great consistency in the Wolfcamp Bay results in Glasscock County and we focus our development efforts there. At the same time we will continue to explore all benches of the Wolfcamp, as well as the Cline, as we work to delineate our 70,000 net acres in the Midland basin with Wolfcamp potential.

While our budget is still a work in progress we anticipate having at least a four-rig horizontal program in the Midland basin in 2014 and this rig count could go as high as six. The results of our exploratory efforts in the southern Delaware basin this year are very attractive, although we still need to drive down well costs. There remains much to learn about the performance of the various Wolfcamp benches in the southern Delaware basin, and I expect us to move forward in 2014 with an exploratory program similar in scope to 2013 that will focus on retaining leasehold and further delineating our 110,000 net acres in the southern Delaware basin.

All-in-all we’ve identified approximately 184,000 net acres in the Permian Basin with Wolfcamp potential. If the play is successful on a large scale on multiple benches, Energen’s potential unrisked drilling inventory could exceed 5,300 locations on 80-acre spacing and 4,400-foot lateral lengths.

Let’s run through the results of our four newest Wolfcamp wells starting in the Midland basin with the Llano 8-8A 101H. Our second operating operated Wolfcamp well in Glasscock County is performing very well. It is consistent with the performance of the Lavaca well disclosed last quarter as well as last year’s Yellow Rose in which we had a 21% non-operated interest. These are practically sister wells.

The Llano well had a peak 24-hour initial production rate three stream of 784 BOE per day. This IP was composed of 69% oil, 17% natural gas liquids, and 14% gas. The Llano well’s 30-day peak average rate is an attractive 683 BOE per day, 65% oil, 19% NGL, and 16% gas. The Llano was drilled to a lateral length of 4,250, stimulated with slick water and immediately placed on gas lift. It further confirms – affirms our belief that our 28,000 net acres in Glasscock County are well suited for development of this multi-bench play.

Based on 80-acre spacing, and 4,400-foot lateral lengths, we estimate that we have 347 potential drilling locations in just the Upper Wolfcamp in Glasscock County. We will be adding a second rig in the Midland basin soon and plan to drill a total of seven gross, seven net wells in 2013, all in Glasscock county.

Two spuds originally planned for late December have now been rolled into our 2014 program. Currently three wells are in various stages of drilling and completion. One is in A-bench with a 5,300-foot lateral and two are B-benches with 6,700-foot laterals.

Turning next to the Delaware basin, with three new data points of our own in the southern Delaware basin, the body of work to support the viability of a large-scale Wolfcamp play there continues to build. The bodacious C-7191-H was drilled in eastern Reeves County. This Upper Wolfcamp test was drilled to lateral length of 4,500-feet stimulated with slick water.

As I mentioned earlier it generated an outstanding peak IP of 2,229 BOE per day. The three stream product mix was 62% oil, 20% NGL and 18% gas. Its peak 30-day average rate was 1,671 BOE per day with a similar product mix. Also in Reeves County close to the Pecos river near the intersection of Loving County and Reeves County, we drilled the Benton 312 number 1-H.

It tested at a peak 24 hour IP of 1,462 BOE per day, 56% oil, 21% NGL, 23% gas. The Benton’s peak 20 day average rate was 1,163 BOE per day and with a similar three-stream product mix. This well is extremely important because it is very near our 3rd Bone Spring development and also in the center of where we’ve got some very blocky acreage if you look at the map.

On the east side of the Pecos river in Ward County, the University 25171-H produced at a peak 24 hour IP of 1,079 BOE per day. The product mix was 70% oil, 16% NGL and 14% gas. The peak 30-day average rate was 769 BOE per day with a product mix 65% oil, 18% NGL and 17% gas.

We currently have three wells in Reeves County in various stages of drilling completion and flow back. Two of these well will test the B bench of the Wolfcamp. We plan to drill a total of ten gross, nine net Wolfcamp wells in southern Delaware basin this year. When you combine the results of our own wells and recent results of other operators, we believe the outlook for success in both basins is increasingly compelling.

At this time I will ask Chuck Porter, our Chief Financial Officer, to talk about third quarter financial results and changes to 2013 guidance. Chuck?

Charles Porter

Thank you, James. There are a lot of unusual and potentially confusing aspects to the financials this quarter, so let me try to break it down for you.

We sold our Black Warrior Basin assets on October 8. As this was a complete exit from the basin, income from these operations is classified as discontinued. We also are holding our, for sale, our North Louisiana/East Texas properties and again, income from these operations is required to be classified as discontinued.

Because we’re holding these assets for sale we had to write down their book value to the estimated fair value. This resulted in a third quarter non-cash impairment charge that also is included in discontinued operations.

Next quarter we will book a gain on the sale of our Black Warrior Basin properties. This gain will more than offset the North Louisiana/East Texas write-down leaving us with a net after-tax gain on disposal of approximately $7.5 million.

On a go-forward basis we will be focusing on income from continuing operations and as required by the accounting rules, five years of historical financials will be restated to reflect the split between continuing and discontinued operations.

The numbers and period-to-period explanations are all included in some detail in our release and I don’t want to take time away from Q&A to go through all of them again here. I would point out however, that relative to our own expectations for the quarter, we fell short for two key reasons.

One is the strong rise in Energen’s stock price resulted in stock-based compensation expense exceeding our budget and two, exploration expense was higher than we expected, primarily due to writing-off approximately 4,200 miscellaneous acres of unproved leasehold. The acreage that was written-off was primarily in the Delaware Basin, the largest-single write-off of about 1400 acres was on the eastern margin of the basin.

Looking at 2013 as a whole, we reduced slightly our production guidance range to 23.4 million to 23.8 million BOE from continuing operations and discontinued operations will be approximately 2 million BOE. The decrease in the production guidance range largely reflects lower gas and NGL volumes in the San Juan Basin, lower NGL production in the Permian Basin, and less oil production in the Delaware Basin.

In the San Juan basin production is less than expected largely due to unanticipated workovers on some high volume wells, unscheduled third party plant down time, pipeline imbalances, and delays reduction in scheduled pay adds. Most of these impacts were felt in the third quarter.

Lower NGL production in the Permian Basin is due to drier gas being produced by some 3rd Bone Spring wells and price-driven ethane rejection in the Midland Basin. The impact of these factors was felt in the third quarter and expected to continue for the remainder of the year.

In the Delaware Basin our oil production is being hampered by interference issues and highly-fractured areas in the 3rd Bone Spring play. Energen’s revised guidance range for 2013 consolidated after tax cash flows, excluding disposal gains and losses is $889 million to $904 million. Energen Resources after tax cash flows are estimated to be $788 million to $803 million. And Alagasco is expected to generate after tax cash flows of approximately $101 million.

In addition, the company has received net proceeds of approximately $150 million from the October sale of its Black Warrior Basin assets, and these proceeds have been used to reduce short-term debt. And we have not yet sold the North Louisiana/East Texas properties, but to provide some indication of value we would expect proceeds of less than $50 million for these properties.

And with that I’ll turn the call back to James.

James McManus

Thank you, Chuck. The two questions we get most often from the investment community relate to our Permian operations and our corporate structure. We do our best to lay out our activities and plans related to the former. We have also communicated the options management has with respect to the latter. It’s pretty simple. We maintain our corporate structure as-is or we separate our businesses either through a spin or sale.

We also have noted that management will likely assess these options in 2014. Having said that, beginning today we will not respond to any questions regarding our corporate structure until such time as we deem it appropriate.

So with that said, let’s open the lines for Q&A. For instructions, I’ll turn the phone line to the facilitator, Amanda.

Question-and-Answer Session

Operator

Certainly. (Operator Instruction) Our first question is from Ryan Oatman of SunTrust. Go ahead, Ryan.

Ryan Oatman – SunTrust Robinson Humphrey

Thanks. Good morning.

James McManus

Good morning, Ryan.

Ryan Oatman – SunTrust Robinson Humphrey

We do talk a lot about the horizontal wells, but you did show a pretty marked improvement in 30-day rates on the vertical Wolfberry wells. If looks like those moved from less than a 100 barrels a day to over 120 barrels a day. James or John, why is that?

James McManus

Yeah. Johnny, why don’t you comment on that? I think it’s our completion technique…

John Richardson

Yeah. We, of course – I think we’ve talked about it the last couple of calls, and we’ve seen a steady march-up in those rates. Two things, one is, in the northern areas we’re drilling a little bit deeper, picking up a few more formations and – but it may be even a more significant impact is changing over to the slick water completions, which has been a general pickup across the board. So a combination of doing a little bit better geology work, finding the right targets and also the completion techniques, have really picked that program up.

Ryan Oatman – SunTrust Robinson Humphrey

Okay. That’s good. And then on the 3rd Bone Spring, you did mention some interference issues in some highly-fractured areas. Can you elaborate on that?

John Richardson

Yeah. I’d appreciate the chance to do that. Of course, we talked to you guys in the past about things when we frac a well, getting interference. That’s common in almost all of these horizontal plays whether it be shales or particularly in the Bone Spring. Most operators cooperate. Well, if they’re going to frac and offset a well, they will give us a call and tell us they’re about to frac.

And we, sort of, over time mitigated some of that by shutting wells in, letting the pressures build up. But as we picked up activity, so we’ve got two things going on, as we picked up activity in the third quarter, we’ve had to shut a few more wells than anticipated because of offset fracking. But also in the third quarter we were impacted by actually some drilling we did.

And there has only been a handful of five or six instances of this where we’ve drilled through a fracture zone and actually affected the well next to it and wound up having to shut that well in next to it. And remember, we’re talking about a 4,000-foot lateral, and we’re only – the fracture zone is only an inch or so wide, and that’s probably an overestimate.

So we’re not affecting the ultimate reserves on these wells. We’ve never seen – when we’ve had the offset impact, the wells, the offset wells have always come back. As you can see from our reported results we’re certainly not seeing it in the initial rates of the well that we’re fracking. It’s just really a timing problem. It happened to impact us in this quarter more than we had estimated.

So we thought we would mention it. But I do appreciate the chance to tell you that we’re not affecting the long-term performance of these wells. We’ve seeing no evidence that we’re drilling too densely. There has really only been three or four areas where this has happened to us in five or six wells out of the 100 and some-odd we’ve drilled. So it’s not an overarching problem. It’s just an impacted problem to this quarter, something we mentioned, it has no long-term effects.

James McManus

And bear in mind, Ryan, this is a sand which is more permeable and porous. We would not expect this to be a problem in a shale, which is much tighter.

John Richardson

Right. And that’s a good point, James. We’re not affecting the Wolfcamp at all. Even when we go back in and drill Wolfcamp wells in this area, these areas where we’ve experienced this in the Bone Spring we can’t imagine that this problem would affect us in the Wolfcamp.

So we see this as isolated to the Bone Spring, mainly in certain areas, and I want to emphasize focused areas where we might have a fracture in between wells that we are encountering it as we drill. We don’t know where it will be, but we’re learning how to handle those problems as we encounter them.

Ryan Oatman – SunTrust Robinson Humphrey

Okay. I mean, so this is nothing like a steeper decline for existing wells or lower IPs for new wells. I mean, it sounds like this is solely timing.

James McManus

And it’s really just related to a small area in our 3rd Bone Spring drilling. That’s a really high and one of the reasons it’s really high rate area is it’s highly fractured. And what John is really talking about here, Ryan is sometimes you’ll have some of the drilling mud leak off through the fracture system and knock out the other well and it takes you a while to get it back online, but we don’t see it as any serious long-term issue.

Ryan Oatman – SunTrust Robinson Humphrey

Okay. And then you did speak to this Benton test, this Wolfcamp A, as being fairly close to your Bone Spring development. Are there any insights to be gained from that Benton test in terms of how well the Wolfcamp A works with your existing operations out there?

James McManus

Well, let me just comment, and then I’ll have Johnny add in. I think that, for us, that was a very important test. We moved to the center of the basin where we have a lot of existing infrastructure related to our 3rd Bone Spring development, which means that wells drilled in that area are going to be easier to hook up.

Like I say we’ve got water infrastructure and we’ve got gas pipeline infrastructure. And so the fact that that well came in oily in that part of the neighborhood where we’ve got some really blocky acreage to me was a really, really encouraging sign for us.

John Richardson

Yeah. And we’re well down in the A, the lower third, so we’re – you know, we don’t think it will – we will see any impact as we move into where we built our Bone Spring wells from this interval.

Ryan Oatman – SunTrust Robinson Humphrey

Great, I appreciate the answers. I’ll hop back in the queue here.

James McManus

Thank you, Ryan.

Operator

Great. Our next question is from Gabriele Sorbara of Topeka Capital Markets. Please go ahead Gabriele.

Gabriele Sorbara – Topeka Capital Markets

Good morning, guys.

James McManus

Hey, Gabriele.

Gabriele Sorbara – Topeka Capital Markets

Just thinking about kind of the budget next year. It sounds like you’re going to have a minimum of four horizontal rigs in the Midland Basin. How should we think about the Delaware Basin in terms of the Bone Spring and the Wolfcamp?

And then with the activity in the San Juan Basin picking up, it looks like some very interesting well results. Do you allocate some capital there next year and drill a horizontal well potentially?

James McManus

Yeah, so Gabriele, let me just kind of give you, again, the budget process. It’s very fluid. We have not completed it. We will continue to work on it, but in general, let me just go basin-by-basin for a minute. In the Delaware Basin, currently we probably plan to run two exploratory rigs, continuing to delineate. We think that the Delaware becomes more of a development play, hopefully in, 2015. We will run three rigs in the 3rd Bone Spring, continuing to drill, so five horizontal rigs in the Delaware Basin in total, two exploratory rigs, three development rigs.

If you move to the Midland Basin, we’ve talked about running two vertical Wolfberry rigs over there, anywhere from four to six horizontal rigs in the Midland Basin. So there would be six rigs running over there, two vertical, four horizontal. I think again, still a fluid process, probably capital budget, somewhere 950 to $1 billion is what we will be look at, plus or minus a little bit.

In the San Juan Basin, at this point, WPX may drill a little quicker. The two non-operated wells that we’re in could be some time in the early second quarter. So at this point, I think we’re content to participate in those two wells and see what kind of results we get and based on what we learn and garner, that might well be a place in the future that we might want allocate some capital to, but we’re still discussing that. We’re still looking at the results but right now, we’ve got two 50% wells we will participate in, we think, fairly early in the year.

Gabriele Sorbara – Topeka Capital Markets

Okay, great. I appreciate all the color there. And can you maybe run the same exercise for well cost what you’re currently seeing them in the Midland Basin for the horizontal wells and in the Delaware Basin and maybe where you see a good target for well costs?

James McManus

Yeah, so in the Midland Basin I think we’re looking at – and Johnny, you can confirm this – I think we’re looking at probably $7.5 million for these longer laterals, somewhere in that neighborhood.

John Richardson

8.5.

James McManus

Excuse me, 8.5 for the longer laterals. I think it was 7 to 7.5 for the 44 to 53 but why don’t you go ahead.

John Richardson

Well, I think right now Gabriele, the way we’re looking at it from our experiences, we’re a little under 7 for the 4400-footer, target about 6-8 for that. We have a series of wells that we will drill at 6,700 feet. We’re targeting it because of the way some sections lay out. We would think those would be 8 million or just about and then the 7500-footers, about $8.5 million. So – and of course, we’re early. I think we’ll see those costs drive down, but that’s our current view right now.

Gabriele Sorbara – Topeka Capital Markets

In the Delaware Basin there?

John Richardson

Well, the Delaware, as far as the Bone Spring – I mean, we think our target on those are in the $6 million but in the Delaware we are…

James McManus

On the Wolfcamp wells, we’ve been pretty clear that we’re targeting $10 million right now on the exploratory wells. We’ve got pilot holes and additional testing going. Some of those early on turn out to be more expensive than that. We know, Gabriele that we need to drive that cost into the $8 million to $9 million range any additional commentary on that, Johnny?

John Richardson

No, we’re looking always at ways to drive that cost down. Of course, we went through that with the Bone Spring. We think we’ll be equally successful at driving those costs down in the Wolfcamp as we do more of that.

James McManus

And that well cost’s probably not going to be driven down until we get more into the development stage, although we are looking at some ideas right now to drop some of that. Any time we drill a pilot hole you’re talking about $0.5 million to $1.5 million. In development stage obviously, you wouldn’t have to do that.

Gabriele Sorbara – Topeka Capital Markets Okay. And that $10 million is for short lateral I assume and all the wells drilled were short laterals. Any plans to drill a long lateral in Reeves County or east of the river?

John Richardson

We’re looking at that. Looking at East of the river in particular. I can’t remember if we had one of those on the drawing board or not.

James McManus

Yes. I think we did 7,500?

John Richardson

Yeah. I think the land will work out to allow us to do – but it will be a longer lateral.

Gabriele Sorbara – Topeka Capital Markets

Okay. One more question, if I may. The bodacious well, very nice 30-day IP rate, can you differentiate between the rock quality in that area versus kind of the completion method?

John Richardson

Well, the completion method has been pretty constant. We do tinker with it a little bit, but I think the bodacious well I think is a good combination of good rock. I think the fluid mix is right for it. I think a lot of good things just happen there. I think our completion helps, but I think the rock quality and the pressure we have there certainly make it the well it is. So I think its geology. I think it is rock and I’m sure our completion method helps because we’ve seen it be successful across the board.

Gabriele Sorbara – Topeka Capital Markets

Great, thank you very much.

James McManus

Thank you, Gabriel.

Operator

Our next question is from Eli Kantor of IBERIA Capital Partners. Go ahead Eli.

Eli Kantor – IBERIA Capital Partners

Good morning, guys.

James McManus

Good morning, Eli.

Eli Kantor – IBERIA Capital Partners

Wondering what kind of production growth you would expect based on your preliminary plans to spend $950 million to $1 billion next year.

James McManus

Yes, I think what we’ve said is in transitioning from vertical to horizontal and again, it’s not fully baked, that we would probably expect lower double-digit growth in `14 followed up with higher double-digit growth in `15.

Eli Kantor – IBERIA Capital Partners

For oil and liquid.

James McManus

For oil and liquids. We’re not worried about gas growth. We’re talking about oil and liquids, yeah.

Eli Kantor – IBERIA Capital Partners

And then in terms of CapEx, how much of your spending next year is going to be for infrastructure and facilities and is it possible to get a breakout between each of your different basins?

John Richardson

Don’t have that yet, Eli. I haven’t finalized the budget.

Eli Kantor – IBERIA Capital Partners

Okay. Looks like you scheduled about, called 50 million of infrastructure spend this year. Should we just directionally – would you expect that to go up or down next year?

John Richardson

Well, I think any time you have a plan change, you’re going to have some different approach to infrastructure. And so I’d – I don’t recall – I mean, as James says, we’re working through it, trying to figure out as we switch from the vertical plan to the horizontal and where we do it and how much existing infrastructure there is, all those things are – there’s just a lot of variables, but we will spend the appropriate amount of money on infrastructure and I would anticipate to be greater next year.

Eli Kantor – IBERIA Capital Partners

Okay. That’s helpful. In terms of your Delaware Basin Wolfcamp activity, I thought I heard your guys mentioned that next year’s program will mirror this year. Should I take to assume 10-gross, nine net wells? You also mentioned two exploration rigs will be active in that area, kind of curious is to what that other exploration rig will be targeting?

John Richardson

Well, I mean, we’re currently working two rigs in the Delaware now. And these are – according to where we’re and what we’re doing that it will take two rigs most of the year to execute that 10-well program.

Eli Kantor – IBERIA Capital Partners

Okay. Last question for me. Just the two Midland Basin B-bench wells, curious what counties those wells will be located in.

James McManus

They’re all in Glasscock right now.

John Richardson

And let me follow up and tell you that I don’t know – we will have rig in and out, but those two rigs may not be there the whole year. They will be there the majority of the year. And I think when we talk about we’ll be running two rigs most of the year next year, they may not be there the whole year.

Eli Kantor – IBERIA Capital Partners

Okay. That’s helpful. Thanks a lot guys. I appreciate it.

James McManus

Thank you, Eli.

Operator

Our next question is from Tim Rezvan of Sterne Agee. Go ahead Tim.

Tim Rezvan – Sterne Agee

Hi. Good morning, folks. First question I had was, kind of following up on Ryan’s on the Benton well. What are you all kind of seeing – were you surprised by, I guess, the oil cuts that you saw in that well and how confident do you feel that is repeatable over that kind of larger blocky acreage you have closer to the river?

John Richardson

From the data we’ve got, we think that’s going to be – we would anticipate wells as we move into maybe held proper to look a lot like that Benton well. We’ve got – everyone knows we’re oilier on the east and we’re gassier in the west just as two end points. So what do you have in the middle, the Benton well is a nice – we like the oil cut there. We’re very glad – I mean, very pleasing well and we think that bodes well for the property that blocky acreage that you’re talking about. But we do know as we move west, we’re going to find more gas. We just don’t know where that will be.

James McManus

If you look, Tim, between the Brady well and the Benton 312, we just don’t know where that transition is at this point, but we do know that as we move into the center, we’ve got a lot more oil, which is what Johnny said.

Tim Rezvan – Sterne Agee

Sure, sure. Okay. That’s helpful. Geologically speaking, have you seen anything distinct about – in those two wells to help you conceptualize the difference?

John Richardson

No. No. I mean, remember, we’re in a shale. It’s very hard description, geologically. We target similar zones; similar characteristics, so from this, the petrophysical view, they look similar and our targets are similar for those wells. So basically, it’s fluid composition and rock properties that we just have to measure sort of intuitively by well performance.

Tim Rezvan – Sterne Agee

Okay, thanks. And then switching gears real quick to the Midland Basin, you’ve talked about four to six rigs there next year. Obviously you have a focus on Glasscock County. Can we expect to see one rig and maybe migrate up to the Midland Martin County area, given the operator – the industry’s results up there?

James McManus

Yeah. We’ll do some testing next year in other areas, Tim. All those won’t be in Glasscock.

Tim Rezvan – Sterne Agee

Okay.

James McManus

We’ll have – if we decide to run six, a couple of those will be doing exploratory work in other areas.

Tim Rezvan – Sterne Agee

Okay. And then can you talk about what decision points might be on six rigs versus four rigs, given that it is pretty healthy CapEx commitment? You are fairly well hedged so I’m just curious what would drive that decision. It’s just early results or would you actively look to lever up, if you like what you’re seeing out there?

James McManus

Well, I think we could run the higher end of that without too much of an overspend from a cash flow perspective. I think we could do that and still be in the 950 million to 1 billion range based on some preliminary stuff.

Tim Rezvan – Sterne Agee

Okay, thanks. That’s all I had.

Operator

Okay. Our next question is from Cameron Horwitz of U.S. Capital Advisors. Go ahead, Cameron.

Cameron Horwitz – U.S. Capital Advisors

Hey, guys, good morning.

John Richardson

Yeah. Hi, Cameron.

Cameron Horwitz – U.S. Capital Advisors

Just back to the bodacious well, more southeast of the majority of your acreages, just curious if you had any desire and/or ability to be able to add acreage there?

John Richardson

Well, of course, we’re trying. And we are very active in leasing and looking at opportunities down there, yes.

Cameron Horwitz – U.S. Capital Advisors

Okay. And then, Johnny, can you just give us your view on the Wolfcamp B member in the Delaware Basin, and just maybe give us some comments about the rock property versus the A, and maybe thinking about commodity composition and just a view of cross activity across the acreage?

John Richardson

I don’t know how much insight I can give you. We’ve got some B wells that we reported early on the eastern side, and of course the B, EOG and others have reported B results out in the western side or along the Reeves County line to the west. And, of course, the B is very productive there. Back where we are in the center portion here, we haven’t tested the B yet. We do think the B needs, I think it’d be interesting to look at the B with our new completion techniques. We’re anxious to do that. It will be part of our program going forward.

But right now, I couldn’t be very definitive about the B anywhere except the gassier production you’ve seen from what EOG and others have reported out to the west. I think the B back into the center part of the Basin and the east is still somewhat unidentified.

Cameron Horwitz – U.S. Capital Advisors

Okay. And then can you just talk about the infrastructure situation in that western part of Reeves?

James McManus

Well, it’s interesting. It’s very remote. And we’re going to have in some areas to go do some testing and wait on some infrastructure, but don’t think that will be a huge period of time as we move south there – from where EOG has done their testing.

But from where that is north, we think infrastructure is something we can certainly handle and don’t look for a lot of delays. It will be a challenge, but we don’t look for a lot of delays there. Most of our acreage in the – from – where EOG was with the Harrison Wells to the north.

Cameron Horwitz – U.S. Capital Advisors

Okay. And then just quickly on the Midland side, do you have a preliminary view of the mix between longer and shorter laterals for `14?

John Richardson

No, no. I don’t think that we concluded exactly I mean, we – really, it’s an interesting concept, but we don’t have any real definitive plans of where and when.

James McManus

I mean we’ll be looking to go longer, but we haven’t completely formulated that yet.

Cameron Horwitz – U.S. Capital Advisors

Okay. And then just lastly from me, do you have – are you going to pursue an 80-acre downsizing pilot or will you let industry kind of dictate that?

James McManus

I think we will do some testing at 660-foot spacing.

John Richardson

In the – which basin?

James McManus

In the Midland Basin, if that’s what you’re talking about.

Cameron Horwitz – U.S. Capital Advisors

That’s right.

John Richardson

Yeah.

Cameron Horwitz – U.S. Capital Advisors

Yes. Well, appreciate the color, guys. Thanks a lot.

James McManus

Okay. Thank you.

Operator

(Operator Instructions) Our next question come from Jeffrey Campbell of Tuohy Brothers Investment. Go ahead.

Jeffrey Campbell – Tuohy Brothers Investment

Hi, guys. Good morning.

James McManus

Hi, Jeffrey.

Jeffrey Campbell – Tuohy Brothers Investment

Most of my questions have been answered. So I’m just going to ask one and it’s kind of just another way to attack the well costs in Delaware. One thing I thought was really interesting was when I compared the Ward County well, which was the weakest 30-day collection of wells, it actually was better than the Llano well in Glasscock but I know the costs are an issue. So I’m just wondering what should we be looking for and what kind of number do we need to see for the Reeves wells to really compete with Glasscock for capital?

Charles Porter

Well, I think I had said it earlier. We would hope that you could get these down to 8 million to 9 million and then they are going to begin start to look pretty economic.

Jeffrey Campbell – Tuohy Brothers Investment

Okay. Good. That’s just an across-the-board goal for the Delaware.

James McManus

Yeah.

Jeffrey Campbell – Tuohy Brothers Investment

Okay, that’s helpful.

James McManus

It’s going to be different drilling costs depending on whether you’re on the east or the west side. You’re deeper in some areas shallow in other areas. Rocks are little harder but in general, that’s where we need to get to.

Jeffrey Campbell – Tuohy Brothers Investment

Okay. Well, that’s helpful. That’s it for me, thanks.

James McManus

Thank you.

Operator

We have another question that just came through from [Mo Dahani] of Wunderlich Securities. Go ahead.

Unidentified Analyst

Yeah, thank you. Congrats on a good quarter.

James McManus

Thank you.

Unidentified Analyst

I have two quick questions – one really, on the pricing and if you can comment on the Midland to Cushing differential, it started to widen I think last month. If you have any additional comments on that, and going forward, will you see the price going for oil?

James McManus

Yeah. Let me kick that one to Chuck.

Charles Porter

Yeah. This is Chuck. The differential has widened and we’re obviously pleased that we went ahead and locked in a lot of hedging on that differential for the remainder of 2013. We are not hedged though on that differential for 2014 and that we’ll just have to look at that as we start to finalize the budgets and to come up with a good assumption. But don’t really have a lot of additional color to add.

We kind of expected that we would have these bouts of volatility, if you will, but the industry continues to move to add capacity. And sometimes it’s temporary with just pipelines being taking off or refinery downturn. So that’s still to be determined for 2014.

Unidentified Analyst

Okay, thanks. Second question, this is about Midland Basin. Do you guys have any plan on targeting other formations other than the Wolfcamp in 2014?

Charles Porter

Yeah. We will probably test the client in 2014, at least in a couple areas.

Unidentified Analyst

Okay. That’s it for me. Thank you.

Charles Porter

Thank you.

Operator

We have another question from Christine Cho of Barclays. Go ahead, Christine.

Christine Cho – Barclays

Good morning, everyone.

James McManus

Hey, Christine.

Christine Cho – Barclays

In the Glasscock County I know there are a lot of third party Wolfcamp A and Cline wells that have been reported. But are there any there any third-party Wolfcamp B wells that have been tested to-date in Glasscock? I didn’t think I saw any.

John Richardson

Laredo has got a good body of these, I think that have been tested in Glasscock.

Christine Cho – Barclays

Okay. And are you drilling any of those near your A walls, where you can determine if there is interference between A and B in both Glasscock and Reeves?

John Richardson

So we will be looking at that. We’ll be doing that this year, in fact.

Christine Cho – Barclays

Okay.

John Richardson

So Micro seismic work.

Christine Cho – Barclays

Okay. And then in the Delaware County, where are your – I mean in the Delaware Basin – where are your leasehold coming up for exploration and would it be – fair to say, that that’s where you will probably focus your 2014 wells?

John Richardson

Yeah, 2014 will be a holding exercise again and most of that is going to be west versus east, if I remember correctly.

Christine Cho – Barclays

Yes. Okay. And then if we were to think about no learning curve in Delaware, where do you think you are besides getting well costs down like probably is just more a function of getting some manufacturing mode – are you pretty satisfied with your drilling and completion that its optimizing production or are there still some other experimental things you want to do?

John Richardson

Well, it’s very early over there. We are hopeful that there are some things that we can do and that we will learn to optimize production and decrease drilling cost. I think we’re in the very early days over here.

Christine Cho – Barclays

Okay. What are some things that you’re looking at?

John Richardson

Well, I think, you know, we’ve – our objective was to look at good, successful completions, so we’ve taken – added some safety factors and we will continue to drill larger hole so that we can run an extra string of casing if necessary. We’re looking at – we are doing – sort of a high-end completion. I mean I think you attack this thing from both sides. You try to drive calls down and at the same time improve performance and we’re just in the early stages of that. We’re learning. We’ve gained experience with every well we drill and every well we complete.

We know there are some things that we’re already – we can’t do to drive the well cost down. We have been happy with our completions but we’ll keep tinkering with that to see if we can’t lessen the cost of those, understand what’s necessary – there’s a lot of factors, there’s a lot of knobs that we can turn as we go forward. We’re just – five or six wells behind us here.

Christine Cho – Barclays

Okay. I see. Thank you very much. That was it for me.

John Richardson

Thanks, Christine.

Operator

(Operator Instructions). We have a question again from Gabriele Sorbara of Topeka Capital Markets. Go ahead, Gabriele.

Gabriele Sorbara – Topeka Capital Markets

Yeah, you know, can you venture out some E awards for the Delaware Basin that award went for County area the Reeves County area You’ve had some wells online for quite a bit of time. You know, just kind of want to get a sense of how they’re holding up and how the type curve is building out?

James McManus

You know I would say they are holding it well I don’t think we’re ready to project EURs. Part of the issue will be how they respond to pump. Most of these wells are going to be on some form of artificial lift and we’ve not had them on artificial lift long enough really to want to give out EURs yet.

Gabriele Sorbara – Topeka Capital Markets

Okay. And how about comparing the University 39-17 well I think was the hybrid frac versus the more recent ones, which were the slick water completion, I think that well had one of your better IPs and one of your better 30-day rates. Can you talk about the difference between hybrid and slick water on those wells there?

James McManus

Well, 39 has been a really good well for hybrid frac. The question – and we don’t know the answer to this yet – is whether it would have been better, had it been slick water, or whether we can go hybrid frac in some of these areas and still get the same result. Hybrid frac is obviously cheaper. That’s one of the issues that we’ll be looking at to test in this upcoming year to see if we see a real difference.

We saw great results in the Midland Basin from the slick water fracs. Most of the operators over here who have been successful have been using slick water, but we think we should look at whether a hybrid frac can be just as effective.

Gabriele Sorbara – Topeka Capital Markets

What’s the cost savings?

John Richardson

Gabriel, I apologize, but I don’t know right off the cuff.

Gabriele Sorbara – Topeka Capital Markets

No worries. Thank you.

James McManus

Thank you.

Operator

(Operator Instruction) There are no question pending at this time.

James McManus

Okay, Amanda. Thanks, everybody, for joining us today. We’re very excited about the progress we’re making delineating our Permian Basin acreage for Wolfcamp potential. And the results we’re achieving are very, very good. There is still much work to be done and a lot more to be understood, but we look forward to that challenge. We’ve covered a lot of ground. We hope we’ve gotten all your questions answered. Thank you for joining us.

Operator

Thank you. This does conclude today’s teleconference. We thank you for your participation, and you may disconnect your line at this time.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!