Energen's (EGN) CEO on Q2 2014 Results - Earnings Call Transcript

Aug. 1.14 | About: Energen Corporation (EGN)

Energen Corporation (NYSE:EGN)

Q2 2014 Results Earnings Conference Call

July 31, 2014 11:00 AM ET

Executives

Julie Ryland - VP Investor Relations

James McManus - Chairman and CEO

Chuck Porter - Chief Financial Officer

Johnny Richardson - President and COO

Analysts

Ryan Oatman - SunTrust

Irene Haas - Wunderlich Securities

Jeb Bachmann - Howard Weil

Timm Schneider - ISI Group

Michael Glick - Johnson Rice

Eli Kantor - Canaccord Genuity

Jeffrey Campbell - Tuohy Brothers

Cameron Horwitz - U.S. Capital Advisors

Operator

Greetings, and welcome to the Energen Corporation's Second Quarter 2014 Earnings Call. At this time all participants are in a listen-only mode, a question-and-answer session will follow the formal presentation. (Operator Instructions). As a reminder this conference is being recorded.

It is now my pleasure to introduce your host, Ms. Julie Ryland, Vice President, Investor Relations for Energen Corporation. Please go ahead.

Julie Ryland

Well, thank you, Melissa, and good morning. Today's conference call is being held in conjunction with Energen Corporation's announcement yesterday of its latest well results and financial and operating results for the three months and six months ended June 30, 2014. Locator maps showing our latest Wolfcamp exploratory well results can be found on our homepage www.energen.com.

Today's conference call will include comments expressing expectations of future plans, objectives and performance. Such comments constitute forward-looking statements made pursuant with the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. All statements based on future expectations are forward-looking statements. 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 our periodic reports filed with the SEC for a more complete discussion of risks and uncertainties that could affect Energen's future results.

At this time I will turn the call over to Energen's Chairman and CEO, James McManus. James?

James McManus

Thanks, Julie. Good morning to you all. We have a lot of exciting news to share this morning. It’s been a long time since I said this but first let’s take a look at the San Juan Basin as most of you know Energen is a 50% non-operated partner in four oil wells that have now been drilled this year by WPX in the Mancos formation in south-central San Juan Basin. The first two of these four wells are producing, and the results are very encouraging they suggest that this horizontal oil play in northern New Mexico could generate returns that compete with our extensive opportunities set in the Permian Basin.

Chaco 2308-09A number 145H and number 146H wells targeted the Mancos formation at vertical depths of approximately 5,500 to 5,800 feet. The number 145H generated a peak 24-hour 3-stream of 1,155 BOE per day and a peak 20-day average rate of 752 BOE per day. The products mix for both periods was 62% oil, 20% NGL and 18% gas. The number 146H tested a peak 24-hour IP three stream of 914 and at a peak 20 day average rate of 766 BOE per day. The product mix for both periods was 78% oil, 11% NGL and 11% gas. Neither well was on gas lift during the testing phase. It is very likely now, that we will deploy a drilling rig in San Juan Basin in 2015 to begin testing or approximately 75,000 net acres with potential in the oil window of the Mancos formation. Very encouraged by our on-going analysis of these first two wells and we are increasingly optimistic that Energen could have a viable, horizontal oil play in the San Juan Basin.

Let's go now to the Permian Basin. In the Midland Basin, we had three solid wells most notably our first Wolfcamp A test in Howard County with a completed lateral length of 6,930 feet. The Smith SN 48-37 #101H generated a peak 24-hour IP three stream of 955 BOE per day and the 30 day average rate of 868 BOE per day. The product was very oily, with a mix of 84% oil, 9% NGL and 7% gas for both test periods.

We also tested our second Wolfcamp A well in Martin County, it is approximately 15 miles east of our Jones-Holton well. The Wilbanks SN 16-15 #101H had a completed lateral length of 6,930 feet and generated a solid peak 24-hour IP three stream of 970 BOE per day. The product mix was 79% oil, 12% NGL, and 9% gas. The Wilbanks tested at a peak 30-day average of 745 BOE per day and had a product mix that was 82% oil, 11% NGL, and 7% gas.

In southern Glasscock County, we drilled the Daniel SN 10-3 #101H with a completed lateral length of 7,700 feet, this Wolfcamp A generated a solid 24-hour peak rate of 775 BOE per day and was 81% oil, 11% NGL, 8% gas. This peak 30-day average rate was 594 BOE per day and 79% oil, 13% NGL, and 8% gas.

We currently are testing multiple sections of a Cline well drilled on the Eastern Shelf in Glasscock County. Another Cline test, this one in Martin County, is completing. Other exploratory wells under way in the Midland Basin include A- and B-bench in Martin County and B- and C-bench in southern Glasscock County.

In addition to our Wolfcamp and Cline testing, we plan to test the Lower Spraberry formation, which is a shale in the Midland Basin in late 2014. One Lower Spraberry well is slated to be drilled in Martin County late in the third quarter and the other in Midland County late in the fourth quarter. We also plan to test the Lower Spraberry in Glasscock County in early 2015.

All in all our 2014, Midland Basin exploratory plans include a total of 22 gross 21 net wells, eight Wolfcamp A wells, five Wolfcamp B wells, four Wolfcamp C wells, three Cline wells, and two Lower Spraberry wells. I also would note that three of our Midland Wolfcamp wells are scheduled to be drilled to lateral lengths of 10,000 feet now and test the A, B, and C benches of the Wolfcamp in Southern Glasscock County.

Perhaps our most exciting Wolfcamp result is in the Delaware Basin, where our Wolfcamp B well in Ward County generated top-tier rates. The University 16-17 #1H generated a 24-hour IP of 1,896 BOE per day, the three stream product mix was 78% oil, 11% NGL, and 11% gas. The peak 30-day average rate of the University 16-17 was 1,081 BOE per day 71% oil, 14% NGL, and 12% gas.

Our weakest performer this quarter is the Enterprise C19-5 #1H in Reeves County. This well tested at Wolfcamp B and generated a 24-hour IP three stream of 634 BOE per day the product mix was 30% oil, 26% NGL, and 44% gas. The peak 20-day average rate was 533 barrel of oil per day 24% oil, 28% NGL, and 48% gas.

Our engineers and geologist continue to monitor and analyze the wells performance, our current thinking there was the lateral was not optimally landed. Energen currently is completing its first Wolfcamp C well in Reeves County and three other Reeves County wells that are targeting the Wolfcamp A and B benches are drilling or flowing back. We plan to test the second C-bench well in Reeves County later in the year we also will test longer lateral lengths in two Ward County wells to be drilled later this year. Our 2014 Delaware Basin Wolfcamp drilling plans now include a total of 15 gross 14 net wells, five Wolfcamp As, six Wolfcamp Bs, and two Wolfcamp Cs, and two to be determined later. Our exploratory Wolfcamp programs in the Permian Basin are proceeding very well. The drilling and performance data being generated gives us increasingly optimism over the potential for economic Wolfcamp Shale development in both obviously the Midland and Delaware Basins.

As you know we’re already in development in southern Glasscock County in the Midland Basin. We’re drilling 55 net wells this year, stacked A and B-bench laterals from pads. Our drilling program has designed to minimize the impact of fracking on nearby wells. Our approach is to drill several locations ahead before going back and fracking the earlier wells. This in essence provides us with a halo of approximately 1,900 feet.

Through the first half of 2014 we’ve drilled 19 gross, 18 net wells in our Wolfcamp development program, 4 wells with sufficient production history two of which are A-bench laterals and two are B-bench laterals generated average peak 24 IP rates of 1,237 BOE per day. The product mix was extremely overly at 87% oil 7% NGL and 6%. The peak 30 day average for the four wells was 700 and average rate for the four wells was 794 BOE per day, 78% oil, 12% NGL and 10% gas. Importantly, these four wells are outperforming and continue to outperform our internal expectations, very pleased with these results.

In addition, during the second quarter, we realized spud-to-total drill depth times of as few as 14 days as we continue to work to gain efficiencies. Unfortunately we experienced significant failure in drill pipe in one particular well located in the middle of the drilling pad. This pipe failure was unusual and there were multiple failures occurring almost simultaneously within the pipe that presented serious complications. This led to a significant delay in the timing of completions for a group of adjacent wells. As a result, production from the development program in 2014 is estimated to be negatively impacted by about 500,000 BOE. The ramp up we had expected to occur in the third quarter of our development program has been pushed out to the fourth quarter.

Now we do not expect our total production to be affected though this is because we’re approximately 300,000 BOE ahead of our estimated midpoint through the first six months of the year. And we anticipate increases in our vertical Wolfberry production in the second half of the year.

To help ensure similar pipe failures do not occur again. We further strengthened our inspection process. These measures should mitigate similar issues going forward and thus far they have.

At this point, I am going to turn this over to Chuck Porter, our Chief Financial Officer to run through the results of our second quarter and discuss adjustments to our 2014 guidance numbers. Chuck?

Chuck Porter

Thank you, James. For the three months ended June 30, 2014, our adjusted income from continuing operations totaled $35 million or $0.48 per diluted share. This compared with adjusted income from continuing operations in the second quarter of 2013 of $46.9 million or $0.65 per diluted share.

Just to be clear, these non-GAAP income numbers exclude the net loss for the quarter at Alabama Gas Corporation. Alagasco's earnings are now reflected as discontinued operations due to its pending sale.

Relative to the same period last year the second quarter of 2014 benefited from a 14% increase in oil and NGL production, but this benefit was more than offset by higher DD&A expense, a 4% decline in realized oil prices largely due to water Midland and Cushing differentials increased production, marketing and transportation expenses, higher production and ad valorem taxes and increase in SG&A expenses.

Energen’s adjusted EBITDAX from continuing operations totaled $204.1 million in the second quarter of 2014, up approximately 3% from $200.3 million in the same period last year. Total production in the second quarter was 6.3 million BOE. Oil production increased 9% year-over-year as new drilling in the horizontal Wolfcamp in the Midland and Delaware Basin more than offset declines in the mature Central Basin platform.

NGL production increased 31% year-over-year, largely due to less ethane rejection and new horizontal Wolfcamp drilling. Natural gas production was essentially unchanged, as associated gas production in the Permian Basin was offset by declining San Juan Basin gas production.

The biggest increases in production by play in the second quarter, year- year-over-year resulted from horizontal Wolfcamp drilling in the Midland and Delaware basins. The vertical Wolfberry and 3rd Bone Spring also demonstrated improved production; and, as expected, production declined in the mature Central Basin Platform and the San Juan Basin.

Average realized sales prices from continuing operations in the second quarter were essentially flat, year-over-year, with respect to NGL and natural gas. Realized oil prices were lower by 4%, primarily due to the impact of wider Midland to Cushing differentials.

In the second quarter of 2014, LOE essentially unchanged from the same period a year ago at $10.20 per BOE. Per-unit production taxes and ad valorem taxes in the second quarter of 2014 increased approximately 10% over the same period in 2013 to $4.42 per BOE.

Per-unit DD&A expense from continuing operations in the second quarter of 2014 totaled $21.31 per BOE, increasing approximately 12% from the same period last year, largely due to year-over-year increases in development costs.

Per-unit net G&A expense of $5.29 was approximately 12% higher than in the same period a year ago, largely due to increased salaries and stock-based compensation.

Interest expense in the second quarter of 2014 totaled $8 million, down $2.2 million from the same period last year. This primarily was the result of a reclassification of certain interest expense in each period to discontinued operations. On a per-unit basis, interest expense decreased approximately 28% in the second quarter of 2014 from the same period last year to $1.26 per BOE.

I will refer you to our news release for details on year-to-date results. With respect to guidance, we have tweaked our capital spending plans for 2014 to $1.4 billion to reflect additional projects and changes in scope; increased non-operating working interest; year-to-date acquisitions primarily of unproved leaseholds and other miscellaneous items.

As James mentioned, our guidance for production from continuing operations for the year remains unchanged at 24.9 million to 25.9 million BOE with the mid-point of 25.4 million BOE. However, the delay in the Midland Basin Wolfcamp development program has lowered the third quarter production estimates and altered the contribution by formation to total Midland Basin production.

There is a great deal of detail on our capital and drilling plans and production expectations in our news release and I'd encourage you to review that information. Our revised 2014 guidance for after tax cash flows and earnings reflect numerous adjustments including the year-to-date results and the timing and composition of annual production, increased absorptions for key basis differentials and reduced interest expense.

We now estimate that after tax cash flows from continuing operations in 2014 will range from $833 million $855 million and that earnings from continuing operations will range from $2 to $2.30 per diluted share. We have approximately 77% of our estimated production mid-point hedged for the second half of 2014.

In addition to these commodity hedges, we also have hedged the WTS Midland to WTI Cushing or sour oil differential for 0.6 million barrels of production at an average price of $3.30 per barrel and the WTI Midland to WTI Cushing sweet oil differential for 1.2 million barrels at an average price of $3.08 per barrel.

Our new guidance incorporates increased sweet and sour oil differential assumptions of $6 per barrel each for the remainder of the year. We estimate that approximately 74% of our oil production for the remainder 2014 will be sweet and our guidance also incorporates narrower gas basis assumptions of $0.05 per Mcf in the Permian and San Juan basins. Please see on news release for sensitivities to changes in commodity prices and Midland to Cushing differentials.

And with that, I'll turn the call back over to you James.

James McManus

Thank you, Chuck. Before we open the floor to your questions, I want to give you an update on sale of Alagasco and the unanimous decision that three-member Alabama Public Service Commission last week approved the sale of Alagasco to The Laclede Group that means the sale is on track to close by September 30, 2014.

So with that said, let’s open the lines for Q&A. For instructions, I will turn the phone line over to our facilitator, Melissa?

Question-and-Answer Session

Operator

(Operator Instructions). Our first question comes from the line of Ryan Oatman with SunTrust. Please proceed with your question.

Ryan Oatman - SunTrust

Hi, good morning.

James McManus

Good morning.

Chuck Porter

Good morning.

Ryan Oatman - SunTrust

In the San Juan Basin, those look like some very good make as well as in that Southeast portion of San Juan County. Can you speak to how the play changes as you move to the Northwest towards Farmington?

James McManus

We don't have a lot of data over there. But we don't think it changes a great deal. As you get on further up to the stream northwestern parts of the basin (inaudible) and there you'll see the change but there is a lot of distance between there and Farmington. And we think as long as you’re on the oil window there, we would expect the formation big or similar. Performance, we don't know; but the formation will be similar.

Johnny Richardson

Yes. Same holds true Ryan, as you move to the East over towards where what we call sort of our base load or pick area, now there may actually be some other potential targets in addition to the one that was targeted in the two wells that we disclosed.

Ryan Oatman - SunTrust

So there should be additional targets in addition to the…

James McManus

Well, it would be within the Mancos. The Mancos is a pretty large section. And the target in these two wells and I'll get John to check me as something that folks -- we've been calling the Niobrara Sea would be the particular target within the Mancos, because it’s a little confusing, because people call it different things, but it is within the Mancos section. And there could be a broader section as we move out to the East, we just have to find out there as we go out there and test.

So I mean we know we've got that one section present throughout the acreage. As Johnny mentioned, we don't know its productivity yet as we move to the East and to the far West, because we have in tested out there, but we really like what we see from these two wells and we've got two more that we'll have results for next quarter.

Johnny Richardson

Yes, I mean the sea is a very silty interval. And we see that pretty much across our acreage position to both the west, the northwest and the east as James say. There is some stress ends that come ago. So the question is how prevalent, how meaningful they do the production, we can't predict where they will be, but the silty interval, the main body is going to be there. And then as James pointed, out and we move east, some other parts of the Mancos become very interesting, particularly in a more traditional shale play.

James McManus

More of a mud stone there, Ryan. So just to be clear about our acreage, we have a pretty small amount in that south central section as we call it about 5,000 acres and then up to the Southwest moving towards Farmington about 18,000 acres and then to the Southeast another 52,000 acres and that's kind of a ballpark of our 75,000.

Ryan Oatman - SunTrust

Very helpful. And I would take that you to guys would plan to target the southeast acreage first but do you have any thoughts on how you're going to tackle it?

James McManus

Well, Ryan, I think we're still formulating those plans, but to give you a little color on that, I suspect that we’ll drill some Southwest Basin wells in 2015 and we'll probably look to test the East and the West side in ‘15.

Ryan Oatman - SunTrust

Very good, very good. One last one for me -- I am sorry?

James McManus

No, go ahead.

Ryan Oatman - SunTrust

One last one for me. There have been a few deals in Glasscock County recently. Can you describe your appetite for M&A in general in the current environment? And then also if you care to speak to if you guys looked at those two specific Glasscock County deals?

James McManus

We did look at some Glasscock County deals, I don’t know if this was that you are talking about. But one of the criteria that we have got -- and we do have appetite at the right price, the right measure of control, all those issues matter to us, how much operating control you have how much working interest you have got, where they lie, particularly in Glasscock County but we are open Ryan to acreage acquisitions. And in fact part of our, not the majority but some of our capital boost up is some acreage that we’ve been able to pick up here recently. So we are looking in both basins and we are trying to be cost effective on what we buy. And so sometimes we might like it and if the price is too high, obviously we are not going to go for that. And sometimes there might be other reasons we find it unattractive, could have operatorship, control that kind of thing, may not be able to drill long enough laterals. There is a lot of factors that come into play but we are actively looking at things that will be for sale acreage wise in both basins.

Ryan Oatman - SunTrust

Very good. I will hop back in the queue. Thanks.

James McManus

Thank you, Ryan.

Operator

Thank you. Our next question comes from the line of Irene Haas with Wunderlich Securities. Please proceed with your question.

Irene Haas - Wunderlich Securities

Hey, good morning. I would like to have a follow-up question on the San Juan Basin.

James McManus

Sure.

Irene Haas - Wunderlich Securities

My question -- yes, congratulations. Those are actually really fantastic wells considering how shallow they are. And so you -- go ahead.

James McManus

Go ahead, Irene.

Irene Haas - Wunderlich Securities

So my question is, you are going to deploy one rig, and I was wondering how many days it takes to drill one well, granted that these are pretty shallow wells too. So does it work as easily as those Niobrara wells up in DJ Basin, understanding that you are just starting out? So I was wondering how many, what kind of rig you use, probably don't have to have the really fancy ones, and how many days it takes to drill one well. And really in this assess case if you have a bundle of wells that are good, what is the lead time to get production hooked up and to sale? Those are my questions.

James McManus

So Irene, you are exactly right, these are pretty shallow quick drills less than 15 days. The reason we are very excited about this potential play is the production breaks are extremely high, the drilling costs are relatively cheap talking about $6 million to $6.5 million on these wells. So I think it could be -- if we can prove it up over a large portion of our acreage, it could be very attractive. And as we mentioned in the call, could compete with our returns in the Permian Basin In terms of -- one of the issues you do have to deal with out here and one of the things that we have already started to do is permitting. It does take a little longer to get permits out here. Federal permits can take anywhere from three to six months which is longer than we experienced in our normal operations. And then if you are on tribal lands and some of our good bit of our acreage is on tribal lands, it can take anywhere from 9 to 24 months. So one of the things we have got our folks doing right now in San Juan is obtaining permits, so we can kind of get ahead of the game so that if this program turns out to be successful, we can add more capacity to drill more wells out there. In terms hook up times, et cetera, I might turn that to Johnny, I am not sure what that will be.

Johnny Richardson

Irene, right now, there is infrastructure here. Of course this is a gas country, so there have been a lot of gas wells drilled here. The systems are older and so right now there is capacity. And it’s a matter of identifying who the carrier is and it takes a little bit of time because they want a sort of a broader scale view of what you are going to do in just a one-off well. So you have to sort of work through that simultaneously with the permitting process. So right now, there is capacity, as we move forward of course, these systems were smaller and older. So we could put a strain on these systems in the future if this were to really take off. But going forward in the short-term, we have pretty good infrastructure here. Not in every situation but most situations.

Irene Haas - Wunderlich Securities

Got you. And since you have been producing in this area for a while, granted, it is natural gas, you would have the crew on ground to deal with the regulatory agencies as such, right?

James McManus

We are very used to the process of obtaining permits. And so yes, we have got a team of people who have been in the habit of doing this. And since everything we have is virtually on federal and tribal land and we know exactly how that process works.

James McManus

Yes, I mean when it comes to all the situations it’s a little bit different, of course this has not been a huge oil province. There have been, it's a good oil wells real particularly on the margins of the basin. But and so yes, all is going to be a little bit different story heavily depending on trucking and maybe rail in the future, some things like that. But that will come of course with production.

Irene Haas - Wunderlich Securities

Great. Thank you.

James McManus

Thank you.

Operator

Thank you. Our next question comes from the line of Jeb Bachmann with Howard Weil. Please proceed with your question.

Jeb Bachmann - Howard Weil

Good morning everyone.

James McManus

Good morning, Jeb.

Jeb Bachmann - Howard Weil

James, following on Irene's question on San Juan, looking at personnel, geologists, G&G that kind of staff up in that area, do you guys have enough capacity there to run a multi-rig program on a yearly basis at this point?

James McManus

We believe, we do, yes. I mean we'll start with this one rig and we'll move from there. But our team out there is not as busy as they use to be, because we haven't been investing in gas. And so actually we've got some capacity out there to take on some drilling.

Jeb Bachmann - Howard Weil

Okay, great. And then moving down to Glasscock with this Daniel well. Just wondering, it was a bit lower than the San Saba and Guadalupe wells in the Wolfcamp Bay, that were further I guess, Southeast of the Daniel, just wondering if the kind of geologic characteristics as you move west. Does it change for the A and maybe become more of a prospective for the B in your mind?

James McManus

We really just don't know at this point Jeb, I mean certainly that was a little bit lower than what we have been experiencing, there is going to be variability in these wells and I think when we get more wells down across the section, we'll be able to be more enlightened as to whether there really are differences or whether this one is just a little bit of an abnormality. So, John has got any color to add to that.

Johnny Richardson

Right. Jeb, we look at this well. Of course, its peak rate is 30 day, it was a little bit under what we would have wanted or expected. However, as it clicks along, it is a pretty flat little well as you might guess, since it didn't have a huge, high peak. But as we project, the economics on this well from what we think the characteristics of the go forward are, it's still a very economic well.

And so, from that aspect we are not disappointed. It probably doesn't have the rates of the ones to the Southeast as you point out, but it is still a very economic well.

James McManus

And I think Johnny makes a good point. If you look at the peak the 20, 30 day rate, but this has been a holding up a little stronger than the characteristics of some of the others. So it's kind of, but we're still we're not unhappy with well at all, just a little bit different than it's character.

Jeb Bachmann - Howard Weil

Great. I appreciate the color guys.

James McManus

Thank you, Jeb.

Operator

Thank you. Our next question comes from the line of Timm Schneider with ISI Group. Please proceed with your question.

Timm Schneider - ISI Group

Hey guys, good morning. First question is follow up on the San Juan. I'm kind of realizing it may be early on, but you guys have transformed yourself into essentially a pure-play Permian players. Or should we look at this as potentially another leg of the Energen story, or is this something that you would be willing to dispose at the right price? And this is specifically to Mancos?

James McManus

Yes, good question. Now as I have said countless times I mean in terms of the gas portion of our properties out there, that's something that one day, because we don't have the opportunity to ramp up drilling out there and so gas prices we believe will be above $6. That's something that could be monetized in the future. This oil play to us looks so good, I would view it as a third leg of the stool, I would not look to monetize it. It's returns are very attractive, when you throw the factor in the drilling cost being between $6 million, $6.5 million, I mean they are quite strong, if we were able to approve this up over a large portion of our acreage at anything close to the rates that we are seeing from these two first non-operated wells, it would be really, really good Timm. So, I think we would look at as a third leg of the old stool, Delaware, Midland and San Juan.

Timm Schneider - ISI Group

Got it. And then secondly, I’d just like to follow-up on the drill pipe issue a little bit more specifically. I mean, is this something that was more in your drilling contractor, or what exactly happened there?

James McManus

So, basically our drilling contractors provide the drill pipe as you know and we're allowed to have inspections to the drill pipe and we had very unusual failure in the integrity of this drill pipe. We are still looking and examining what that was, but in order to, we have some suspicions but we’re not going to go into that here. But what we did is basically really briefed our testing level up on the drill pipe that we require and make sure that doesn’t happen again and in fact it has not happened again. It was a very unusual thing that happened. We do get stuck with drill pipe, sometimes we pour out whole and we part it, but this was that times ten and we just don’t we don’t see that problem again with the inspection levels that we’re doing right now. We have problems again, but not this one, this one was very very unusual, we wound up being on a well in extraordinary long time because of the way this pipe parted when we were pulling out the hole, but just a very unusual situation that we’ve not here to fore encountered. Johnny?

Johnny Richardson

Yes, Tim. You’re going to have some issues, this as James pointed out this was sort of a multipoint failure just within a very short period of time. It not only so stuck us, we could do much with well we sort of we had to fish it out in a particularly slow manner, we’ll then well so long our first attempt to fix the wellbore failed. We then went back and ran an intermediate string and got trouble spots and got the well completed but by that time we were two wells behind in anytime you’re sort of doing pad drilling is wonderful, pad drilling is driving down cost and make it more efficient. And we will ultimately you will see our production really start to increase. But this is as others have mentioned one of the issues with pad drilling in the middle of a pad if you have a failure like this, it not only impacts because well is not being drilled but wells not being completed in rhythm and sort of the way you set them up and you really do have to be sensitive do fracking and drilling in close proximity or you cause yourself a lot trouble. And so that just sort of puts us behind our schedule we will catch up. But unfortunately, in the short-term we’re going to have to catch up.

Timm Schneider - ISI Group

This was Glasscock County then, right?

James McManus

It was.

Timm Schneider - ISI Group

Okay.

Johnny Richardson

Right and the at the A, B stacked laterals that we’re doing.

Timm Schneider - ISI Group

All right. Okay, thanks guys.

James McManus

Yes. Thank you Tim.

Operator

Thank you. Our next question comes from the line of Michael Glick with Johnson Rice. Please proceed with your question.

Michael Glick - Johnson Rice

Good morning.

James McManus

Good morning Michael.

Michael Glick - Johnson Rice

Just wondering if you guys could provide an update on what you are seeing on the well cost side in the Delaware Basin Wolfcamp.

James McManus

Sure.

Johnny Richardson

Well, we’re still trying to drive cost down there. We still have some of the issues that we are remote with some of these properties and some of these areas that we’re drilling. But we are seeing cost come down. We’re trying to get our drill and complete cost under the $10 million mark. And we are having success with that. We’re getting those costs driven down, some of that is repetitive some of that is in different areas some of these are still though remote we have to build roads and we have to install power and we have to truck water in and out. So, but we are seeing those drilling complete costs to come more in line with what we think a reasonable.

James McManus

Michael this is James. Just add a little more color on that. We’ll probably have one of the rigs in 2015 doing some development work and then when obviously when you’re bouncing around basin and you can see some of the basin, you bounce around the basin it’s hard to take what you want drilling one well and then fully resolve have optimize the drilling of that well. But you can do when you’re in a development program and we’ve talked about in the Midland Basin we started off at 8.5 targeting 8 now moving hopefully towards $7.5 million there. And so when you get to the development phases when you’re really going to drive it down but we’ve seen some improvement and exploratory phase but our drill and complete cost here and not unlike other operators, still probably in the $10 million range. And then you’ve got some pretty heavy facilities cost on top of that because as Johnny talked about some of these are in pretty remote locations. But we think we can get there. That’s what we’re working on and we’ll get a chance to implement that a little bit more in ‘15 as we move to the development phase hopefully in few of the areas where we are.

And very excited about the university 1617 a lot of improvement in that particular well based on the way we fracked it, the frack technique that we have evolved to in the Delaware Basin. That well was really surprisingly good to us.

Michael Glick - Johnson Rice

Maybe you can provide a little bit more color on that front. What did you do differently in the university well?

James McManus

So some of the other wells over there had been hybrid fracs for slick water we've gone to slick water we just hadn’t come back to the East side we've focused our drilling more to the West. We also gone too much tighter cluster frac spacing I think 253 feet, a little bit deep pretty big same job and we think we landed that well in a part of the Wolfcamp that was pretty attractive.

Johnny Richardson

Exactly, when we drilled the first generation, and but all wells particularly B wells were more still using the sort of Bone Spring approach before we went to the slick water, high density more stages more clusters prior to higher rates and horsepower it worked very well in this particular instance and we think we're on to something over there.

James McManus

And you know Michael while just to confirm just to address the enterprise that was pretty weak well disappointing well in our view, I said it in the remarks and this is a large area there is a lot of learning to do, a lot of exploring to do and sometimes we will have a concept on landing a well that we think is optimum that may not turn out to be that way when get back we get the result and that's the case on the enterprise.

We probably would not target that particular zone again in a well right to next door, but we did learn something from it and at the time based on data we thought it probably optimum landing zone was got a different take on that but the area changes a lot out here as you move from east to center at west so this is not even close to the development phase so you're going to have some disappointments out here as you move through things. But we will also have some very, very strong results out here as well that gives us a lot of encouragement.

Michael Glick - Johnson Rice

Got it and just jumping on the Midland basin real quick on your stacked laterals and Southern Glasscock County just curious how the performance of the stack laterals has compared kind of on a relative basis to similar wells that weren't stacked.?

James McManus

Well let me talk while John is just going to jump in here. I mean the performances outperform that model and with the first four wells that we've disclosed we think those results have been really good. Now in terms of what you may be asking us how to perform a little bit differently than when you don't have other wells around and you just got a single well out there. And I am not sure that Johnny is looking right now to see we can.

Johnny Richardson

Well we only have four.

James McManus

We only have four.

Johnny Richardson

And it just at a glance of just some of statistics, I would show you that there is not a lot of difference particularly for that area. We are very pleased with these wells they're above sort of what we anticipated them to be and so we are very pleased with them right now.

James McManus

So the answer is lot of different right now we're seeing.

Michael Glick - Johnson Rice

That's helpful, thank you very much.

James McManus

In terms of one-off well. Okay, thank you.

Operator

Thank you. Our next question comes from the line of Eli Kantor with Canaccord Genuity. Please proceed with your question.

Eli Kantor - Canaccord Genuity

Hey good morning guys.

James McManus

Good morning Eli

Eli Kantor - Canaccord Genuity

How is the Niobrara oil acreage was between federal and travel land?

James McManus

Yes we got about let's call it 4,500 acres in round terms it's stay fit so there is small a travel is about 37,000 federal is about 33,000. I would point out that about half of that federal that I just gave you 33,000 does have some nappy which is Navajo surface issues that you have to deal with as well. So that's kind of the breakdown.

Eli Kantor - Canaccord Genuity

And how does permitting that nappy…

James McManus

Let me split the travel for you just a little bit, the majority of that travel is going to be (inaudible) reservation and they tend to be a little bit faster they might be 12 months for those guys.

Sometimes the Navajo can be a little bit longer but since we're just dealing with them on surface we're not sure how long that might take we'll be working on that. And then federal is three to six months.

Johnny Richardson

Yeah we got to do the archeological survey we've had guys to working on this already and we're in the process of submitting a number of permits so that we'll be ready in 2015.

Eli Kantor - Canaccord Genuity

And then in terms of balances on capacity how many horizontal rigs do you think you cold ultimately ramp up to before gathering become some kind of bottleneck on growth.

James McManus

Just on that, I mean I'm not saying there is a bottleneck on growth I'm just not sure how many rigs eventually we would run out here, I don't know somebody else has got any answer to that, I don't have any answer to that.

Chuck Porter

It will be a situation like we've seen in the middle, any basin that undergoes redevelopment. The carriers will have capacity and then we'll fill it up and then they will have capacity. So it's a constant upgrading both in production and in capacity and this basin will go through that too. At what point it starts to happen at what point we see there initial movement I don't know.

Eli Kantor - Canaccord Genuity

Okay, fair enough last one for me. Can you give a little more color on what zone you landed this enterprise well and how it sort of compares to the previous three Wolfcamp B tests in Reeves County?

James McManus

This one was a little bit lower in the B, it was not exactly a lower B, but it was in the lower portion and it was in the zone that we thought of interest. The upper B is that we think still viable and perspective zone to look at. So really this zone and where we have traditionally been in the upper B, we still think we have that more traditional shot here.

Unidentified Company Representative

Eli if I'm getting this correctly, the E. J. Brady was more of the upper B and so even though its right an explore, we have landed that the enterprise a little bit deeper. So it's not, we didn't land at the same place as the Brady.

Eli Kantor - Canaccord Genuity

Okay. Thanks very much.

Unidentified Company Representative

Thank you. Excuse me Brady was in A, it would have been at lower A.

Eli Kantor - Canaccord Genuity

Okay.

Unidentified Company Representative

Yes.

Operator

Thank you. Our next question comes from the line of Irene Haas with Wunderlich Securities. Please proceed with your question.

Irene Haas - Wunderlich Securities

Yes, just sort of one more question on the Delaware Basin side. Understandably, the Wolfcamp is twice as thick on the Delaware side, as versus the Midland side. And right now, if we look at everybody, we are seeing certainly Wolfcamp A on the Texas side, and B is getting [decipher], C and D. And my question for you is, judging from what I heard on the B interval, are there multiple benches like within each zone? And if yes, are they laterally expensive or do you even have an idea right now, as to how the whole layer cake is going to turn out to be, if at all? I mean, so I am just trying to gauge as to how far along are we in this whole exploratory process?

James McManus

Irene, its James it's very early. I mean we're calling as we've talked about before it gets confusing because operators distinguish the A, B and C sometimes differently. But I think they are thinking of that you could have multiple wells within C to B out in the Delaware Basin if it's turn to be perspective in more than a certain part of the section. But I think we're super early, we've got an off a lot to learn, I think we learned something every time we drill a well lot here.

As we move to the development phase in 2015 with some of our rigs, I think we're going to get a lot more answers in particular areas. But as you know, it's a huge area from an aerial extent perspective and our acreage expands across the entire basin, so we're still learning a lot.

Unidentified Company Representative

We're just beginning earning.

Irene Haas - Wunderlich Securities

Right. So therefore, what do you have out there in terms of your drilling inventory I suppose, it’s still kind of room to improve to fine-tune and possibly expand?

James McManus

Absolutely.

Irene Haas - Wunderlich Securities

Okay. Thanks.

James McManus

Thank you.

Operator

Thank you. Our next question comes from the line of Ryan Oatman with SunTrust. Please proceed with your question.

Ryan Oatman - SunTrust

Hi. Thanks for taking a follow-up. A very quick one for me. I just want to circle the square on well costs. Can you speak to your current well costs on the Midland Basin side, maybe just two categories of exploration and development?

James McManus

Well, exploration wise, we are in the $9 million range for the Wolfcamp, because we of course that's what we want off out there, but as we get into the pad drilling, we are looking at sub $7.5 million of wells right now. So we've seen costs come down and we really like our development program and what we're doing there Hiccup aside the drilling cost are coming down nicely.

Ryan Oatman - SunTrust

Very good. And then one final one for me, I am realizing it is early can you speak to what you are seeing on the eastern shelf with your Cline tests there and remind us of your acreage position over there?

James McManus

Yes we can, we have got nine contiguous sections over there so nine times 640 roughly… I would say Ryan just to remind everybody that is sort of outside with the normal Cline play we had leases expiring up there and so we went up there tested, we don’t have anything to share with you at this point.

Ryan Oatman - SunTrust

All right. Very good. Thank you.

Operator

Thank you. (Operator Instructions) Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers. Please proceed with your question.

Jeffrey Campbell - Tuohy Brothers

Good morning.

James McManus

Hey.

Jeffrey Campbell - Tuohy Brothers

Regarding the much talked about, the two most recent Mancos wells. You have been with WPX on a number of wells. I just wondered what was your sense of how much of that strong performance was just hitting the right rocks, being tier one as opposed to maybe improved completion methods that have been evolving out there.

James McManus

Actually Jeff it is the only two wells we participated with, these are the first two and we have two more. So we have only been with them potentially on four wells right now so don’t have any…

Jeffrey Campbell - Tuohy Brothers

I thought you had been on some prior ones. I am sorry.

James McManus

No, no, no these are our first two wells with them now, as you talk to them and that is a very great question we think that there is that they have improved but we will find that out as we start to test ourselves but I think if you look at both Encana and WPX their results have kind of been steadily improving and Encana has I just recently read going from they had one rig at one point they now have four by the of the quarter and WPX is going to pick up the other one so as with most of these plays you have sort of seen steadily improving results I would hope that we are not unlucky enough that the two wells that we want that participating with them in just happen to be in the best geological area in the whole basin.

Jeffrey Campbell - Tuohy Brothers

Right. Well, actually, one of the reasons I asked that is, because Encana said over their last couple quarters that their tier 1 is actually expanding and it’s surprised them to the upside. So the geology is…

James McManus

I suspect we are even earlier stages they are than we are similar to the Delaware basin I suspect we have all got a lot to learn and hopefully things will continue to get better. We know that the drilling in completion that Encana and WPX have both done has gotten a lot better because we have been proving to a lot of information relative to kind of how they have improved we’ll confirm the rock situation I think as we start to drill.

Jeffrey Campbell - Tuohy Brothers

Okay. And my next question was with regard to the Smith well that you drilled up in Howard. Unlike some of the other successful second quarter 2014 results this doesn't look like it is drilled in an area with a prolific amount of acreage. So I was just wondering to what degree does this success derisk other acreage in the area or increase your appetite --.

James McManus

No, no. Actually it’s a pretty nice data point because if you look at our map we are kind of testing the edge of that blue line and if we can move that blue line up a little bit further to the north we have a nice little jump there in Martin County in the Northeast corner and we’ve got some acreage down below it. So I mean I think it’s helpful.

Jeffrey Campbell - Tuohy Brothers

So the take away is that this result can help derisk some of that acreage over in?

James McManus

It can but there is probably this is the large map there are a lot of opportunity as far as even where this well is I mean we do have I mean I forget the number of opportunities but this would be, this would be a nice program in its own right it’s not as broad I mean we are lucky to have very contiguous acreage in most of our acreage box this one won’t be to that extent but this will still be a multiple well opportunity for us.

Johnny Richardson

According to the locations that we have disclosed is potential in Howard County we have got we have identified 77 net A, 77 net B, and 44 net Clines that assumes 660 foot space.

James McManus

So 150 As and Bs nothing to sneeze at.

Jeffrey Campbell - Tuohy Brothers

Really, great color. I appreciate it. If I could ask one more and I got bumped off for a little bit, so I hope this wasn't already asked. You mentioned in the press release that you and in your remarks you are testing multiple sections of the Cline well in Glasscock County. Can you just give a little bit of color as to what testing multiple sections entails in this case?

James McManus

Well, it just means that the Cline interval is extremely thick and we're testing a lot of pieces of that thick interval, we're not just -- we didn't just land the well in one particular interval within the Cline. That's what that means.

Jeffrey Campbell - Tuohy Brothers

Okay, alright. Great. Thank you. I appreciate it.

James McManus

Sure.

Operator

Thank you. Our next question comes from the line of Cameron Horowitz with U.S. Capital Advisors. Please proceed with your question.

Cameron Horwitz - U.S. Capital Advisors

Hey guys, good morning.

James McManus

Good morning, Cameron.

Cameron Horwitz - U.S. Capital Advisors

Hey, James. As we move through 2015, I know you laid out an eight rig program there preliminarily on the Midland Basin side, is that where you feel given I guess the constraints of the program, I mean is that the upper limit? Or what would be the propensity to maybe see that move up?

James McManus

Yes. Cameron, I think we’ll just have to look at that as we move through the year. I think we're planning to run eight for sure, whether we decide to add to that kind of it's something we'll look at as we put our budgets together and look at our results later in the year. So, I really can't give you much of an answer there. I do think, we continue to think about five rigs in the Delaware. As you know three of those are doing 3rd Bone Spring, so we'll have 5 Wolfcamp wells and one to add or takeaways here is a rig in San Juan, which as I pointed out, you can drill quite a few wells out there with your drilling days being less than 15. Of course we do some exploratory testing on the east and west side that will slow that down.

Cameron Horwitz - U.S. Capital Advisors

Okay. And can you just remind me on the in the Midland Basin in Glasscock County on the A-B tests, what is the interzone lateral spacing there? Was that were those 660 foot spacing?

James McManus

They were, I believe.

Cameron Horwitz - U.S. Capital Advisors

They were?

James McManus

Yes.

Cameron Horwitz - U.S. Capital Advisors

Okay. So you guys feel pretty confident now in terms of 660s?

James McManus

I think we feel confident that's -- it shouldn't be any greater than that. The question is could it be, some operators are talking about tighter spacing than that right now and I don't think we're ready to get there, but we think 660 is pretty good. Cameron, the other thing I’d point out is we will do two -- we mentioned it in our remarks, two Lower Spraberry tests, we think those will be interesting.

Cameron Horwitz - U.S. Capital Advisors

Okay. And then just lastly for me, can you just help me out in terms of thinking about modeling on the Mancos side, numbers in terms of OpEx and oil differentials? What do you guys think in there?

James McManus

Well, I can tell you the oil differential range is somewhere around 15 bucks, okay? In terms of deduct, it's in that neighborhood. I don't really -- I couldn't give you anything on operating cost right now. Other operators, I had talked about EURs we've not, they’ve talked about EURs of 500. I can tell you that need to be 500 for to be a very economic play, because we've done some kind of back of the envelope modeling. I don't know if Johnny has got anything. I don't think we've got anything on that.

Johnny Richardson

Yes, we've got some internal numbers. But since we haven't experienced that yet…

James McManus

Yes.

Johnny Richardson

So and people put different things, particularly early on, people put different things in their op cost early on. So, I'm sure in the future, we'll give you more color, but right now we are sort of sorting through that.

James McManus

And Cameron, one place to look, I mean I don't know if WPX or Encana has done a little bit of that. Those are the two that play the more extensive experience out here and I don't know if they've got anything out.

Cameron Horwitz - U.S. Capital Advisors

Okay, great. I Appreciate the color. Thanks a lot.

Operator

Thank you. Our next question comes from the line of Timm Schneider with ISI Group. Please proceed with your question.

Timm Schneider - ISI Group

Hey, guys just lastly, I was just wondering, on the last release you kind of gave out glimpse at what you thought ‘15 could do. You didn't really say anything in this release. So should we expect that you will update those numbers as you kind of get closer to the end of the year, maybe the Q3 earnings call?

James McManus

Yes. Timm, I can't promise you that. It maybe end of the year sort of when we -- I mean last time we updated all that information when we disclosed end of year results, but we have not changed our thoughts about those number being good to give with. I mean we certainly believe that is something that definitely in the cards for us, that 30% Permian growth and 25% and 26% liquids. We haven’t scaled back. In fact some of the capital that we are spending this year when we move the capital up is drilling that will contribute in ‘15 as well.

Timm Schneider - ISI Group

There was nothing, there was no assumptions for the Mancos in that initial numbers if that's right? Correct?

James McManus

Right.

Timm Schneider - ISI Group

Okay. All right. Thank you.

Julie Ryland

James, you might want to move into your concluding remarks. We have about exhausted our analysts.

James McManus

Okay. I am sorry. We have to call time on everybody. Listen, if you got follow-ups, you know Julie’s cell phone number, she can certainly get us if appropriate. We do appreciate your interest in joining us today. We are still very excited about the acreage we’ve got in the Delaware and Midland Basin and frankly now got some excitement about the San Juan oil position. And we’ll talk to you later. Have a great day.

Operator

Thank you. This concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation. And have a wonderful day.

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