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Executives

Julie Ryland - VP, Investor Relations

James McManus - Chairman & CEO

Chuck Porter - VP & CFO

John Richardson - President & COO

Analysts

Duane Grubert - Susquehanna Financial Group

Holly Stewart – Howard Weil

Irene Haas - Wunderlich Securities

Mario Barraza - Tuohy Brothers

Ryan Oatman - SunTrust Robinson Humphrey

Gabriele Sorbara - Topeka Capital Markets

Joe Magner - Macquarie

Tim Rezvan - Sterne Agee

Cameron Horwitz - U.S. Capital Advisors

Energen Corporation (EGN) Q1 2013 Earnings Call April 29, 2013 11:00 AM ET

Operator

Good morning, ladies and gentlemen, and thank you for waiting. Welcome to the Energen First Quarter Earnings 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 over to your host, Ms. Julie Ryland. Ms. Ryland, the floor is yours.

Julie Ryland

Thank you Wes, this is Julie Ryland. Good morning. Today’s conference call is being held in conjunction with Energen Corporation’s announcement this morning of the results of operations of the three months ended March, 31, 2013.

Our comments today will include statements expressing expectations of future plans, objectives and performance that constitute forward-looking statements made pursuant to the Safe Harbor provision act of the Private Securities Litigation Reform Act of 1995. All statements based on future expectations are forward-looking statements that 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 Chairman and CEO, James McManus.

James McManus

Good morning to you all. The first three months of 2013 were both encouraging and challenging. The results of the 3rd Bone Spring and Wolfberry wells we tested in the first quarter were excellent. The nine 3rd Bone Spring wells we tested had an average initial stabilized rate of 1,230 BOE per day, 74% of which was oil and the 30 day average production rate of five wells tested was 625 BOE per day, 71% oil.

In addition, two of our 3rd Bone Spring wells were particularly impressive with an average initial stabilized rate close to 2,000 BOE per day. Our Wolfberry wells responded very well to our recent switch to slick-water based stimulations. We tested 42 gross wells at an average initial stabilized rate of 123 BOE per day, 75% oil and over the first 30 days the wells averaged a 109 BOE per day, again 75% oil. This is well above our typical type curve.

Turning next to our horizontal Wolfcamp exploratory programs; we are very excited about assessing the potential of the Wolfcamp shale in the Delaware and Midland basins. We believe that our previous success at even one of these basins holds significant positive implications for Energen given our excellent acreage position in both areas. We continue to drill, complete and test Wolfcamp shale wells in the Delaware Basin and are preparing to start our first Wolfcamp well in the Midland Basin this week.

In the Delaware Basin, the four wells remaining in the 2012 drilling programs are in various stages of completion or testing. In the first well in our 2013 program is waiting completion. Our Delaware Wolfcamp program is designed to test a variety of locations in the upper and middle air holes of the thick Wolfcamp formation. We have increased the number of Wolfcamp wells we planned to drill in the Delaware Basin to 10 gross, eight net. At the same time, we are eliminating one of our planned vertical Wolfbone wells.

In the Midland Basin, drilling is scheduled to begin Wednesday. The well will have a 4,400-foot lateral length and test the upper Wolfcamp. It will be located in Glasscock County near an existing Upper Wolfcamp well in which Energen has 21% non-operated working interest. We plan to drill six gross, six net Wolfcamp wells in the Midland Basin this year; of those six wells, four are scheduled to be completed in 2013 as well.

Extreme cold weather in the San Juan Basin and some interference issues between the few new and old 3rd Bone Spring wells pressures first quarter production below our expectations. We will of course repeat the long San Juan volumes during the year and we have remedied the interference issues.

Otherwise, production in the quarter was essentially where we thought it would be after revising down our 2013 production estimate in December. As you may recall, we frontloaded the downward division into the first half of 2013 due to problems we identified in the fourth quarter of 2012 that we expect it to continue into ‘13. These include infrastructure concerns, high ethane rejection and Wolfberry completion delays.

Oil takeaway capacity began to improve in the second half of the first quarter as evidenced by the narrowing of the WTI Midland to WTI Cushing differential. High levels of ethane rejection continued throughout the first quarter and expected to persist through mid-summer when the initial fractionation capacity and takeaway capacity are added. And catch up on our Wolfberry completions we are going to spend some unbudgeted capital to add a frac crew to get these wells on production.

As we look ahead in 2013, we expect our volumes to increase such that we could reach 26.5 million BOE by year-end. The main drivers here are continued strength of our 3rd Bone Spring and Wolfberry wells. Acceleration of Wolfberry completions and the addition of 20 low-cost, Mancos oil pay-adds in existing vertical wells in the San Juan Basin. To reflect this potential today we have established a production guidance range for 2013 of 26.1 to 26.5 MMBOE; I would note to you that our current daily production rate is inline with this range.

At this time, I would ask Chuck Porter, our Chief Financial Officer to review the key financial results of the first quarter of 2013. After that I will talk more about our outlook for ‘13 and then open the floor for questions. Chuck?

Chuck Porter

Thank you, James. Energen’s earnings in the three months ended, March 31, 2013 totalled $82.7 million or $1.14 per diluted share after adjusting for non-cash mark-to-market losses. In the first quarter of last year, excluding mark-to-market losses and a non-cash writedown of gas properties in Each Texas, our adjusted net income was $96.1 million or $1.33 per diluted share. Excluding non-cash items Energen Resources had adjusted net income of $34.8 million in the first quarter of 2013 as compared with #48.2 million in the same period a year ago.

First quarter production increased 3% year-over-year. Half of the first quarter 2013 production was composed of liquids, oil and natural gas liquids that increased approximately 16%. The other half, natural gas fell 7% relative to the same period a year ago. This reflects our focus on the oil rich Permian Basin and limited capital investment in natural gas properties.

Our hedge position for the first quarter really helped our sales revenues. We continue to benefit from strong gas hedges and related oil revenues our hedging of the Midland-to-Cushing differential went a long way toward mitigating the full impact of the basis blow out that began last year. Without these hedges, our realized oil price in the first quarter would have been about $5 less. This operating expense in the first quarter of 2013 was up significantly from the same period last year. On a per unit basis, base LOE marketing and transportation increased about 40% to $13.77 per BOE. This was largely due to increased workovers and repairs, increased water disposal, higher ad valorem taxes, and increased equipment rental expense.

DD&A expense per unit in the first quarter of 2013 was up 21% from the same period last year excluding the non-cash writedown of gas properties. This increase primarily reflects year-over-year increases in development cost and production. Energen’s utility generated net income of $47.2 million in the first quarter of 2013 and is on-track to earn within its allowed range of turn on equity at year-end.

James has already outlined our prospects for producing 26.5 million BOE in 2013, along with the drivers that we think can get us there. Two of these drivers are performing additional Wolfberry completions by adding a frac crew and performing 20 low cost Mancos oil pay-adds in the San Juan. These items along with additional working interest and other miscellaneous changes in scope are in turn driving a $50 million increase in Energen resource capital spending in 2013. We also expect to incur another $50 million of capital associated with end of year timing of expenses. This is largely the result of a slowdown in the completion of our calendar 2012 Wolfcamp wells, the Wolfberry completion delays and some delays in the drilling of salt water disposal wells. We treat our guidance range for 2013 primarily to reflect the impact of the bonus depreciation extension on Alagasco’s cash flows.

Our guidance for the consolidated after tax cash flows is now $930 million to $959 million. Energen resources after tax cash flows are estimated to be $826 million to $855 million and Alagasco is expected to generate after tax cash flows of approximately $104 million. We did not really change our net income guidance. We did however exclude $0.31 per diluted shares of potential dry hole expense that we had previously included. So the prior range of $3.03 to $3.43 becomes $3.34 to $3.74. Given the size of our exploratory drilling program in 2013, our dry hole potential does exist, but any estimate we placed on dry hole expense is it is emphasized at .best. So in the interest of clarity and simplicity we remove the dry hole estimate from our earnings guidance.

With that I will turn the call back over to James.

James McManus

Thank you, Chuck. An important part of our financial picture in 2013 is our excellent hedge position. Approximately 70% of our total estimated production for the remainder of the year is hedged. You can see the breakdown in our release. We've strengthened our hedge position for 2013 earlier this month by taking advantage of the uplift in natural gas prices, we also added to our 2014 natural gas hedges.

Earlier in the year with the oil features in 2015 at just over $90 a barrel, we layered in our first hedges for that year and I would fully expect to continue to increase our position in 2015. Given our substantial potential drilling inventory, 2013 is going to be an important exciting year for Energen, our testing of the horizontal Wolfcamp in the Delaware and Midland basins is underway and our results will help frame the future pace of development. Success in even one of these basins holds meaningful potential for our company.

Outside the Permian basin, we believe the long term optionality we have in the San Juan basin makes us stronger still. In case you missed Encana’s announcement last week, they said the oil plays of Niobrara in the San Juan basin is now a commercial horizontal play. Encana has two rigs in the play and may add another by year end. Clearly this is of great interest to us as we have approximately 82,000 net acres in the play and it’s all held by production. So we have the luxury of allowing Encana to continue to derisk play and we will be monitoring their activity closely.

With that I'm now going to move into Q&A. We will turn the phone line over to our facilitator Wes. Wes?

Question-and-Answer Session

Operator

(Operator Instructions) The first question comes from Duane Grubert [Susquehanna Financial Group].

Duane Grubert - Susquehanna Financial Group

In terms of the interference that you've talked about in the Bone Springs, could you give us a little more detail, did that involve a discovery during a frac job or how the production behaved or exactly what was that.

James McManus

Duane, I will call on Johnny to comment on that.

John Richardson

Good morning, Duane. It's not new phenomena, Duane, we've seen this, a lot of shale play see this; I know that Bakken does specifically. But as we frac the wells primarily, we do see a pressure front move through and since these are open hole wells, these are (inaudible) plus completion, you have drilling mud of course behind this system. When the front moves through, it seems that you can get drilling mud in the wells; you have to go and clean them out. I think it's not new to us, but as we've gone back through and looked at the infield drilling.

As I mentioned last time, we are now going back to second and third well on these leases. We probably didn’t anticipate that very well. We did see some pressure front move through. We usually shut the wells and even when an offset operator fracs a well, it will communicate with each other, shut the wells and let them build up pressures to producing wells for a few days then do the frac job, and we did that on this time but with these interior wells, we just didn’t really anticipate that very well. We've now started staggering out wells. We do have that option with two sands or three sands present. We'll now stagger out well from sand to sand with a different target as we drill them, and that’s done a lot to mitigate the problem.

Duane Grubert - Susquehanna Financial Group

Okay, that makes a lot of sense and that leads me to my second question. There is still leasing going out there in the Bones Spring area. Is there a lot of best practice sharing across companies or are people still pretty proprietary about the way they complete things.

John Richardson

Well, there are more conferences; actually the Bone Spring though will be in a fairly developed play. There is not as much sharing of that technology, I think in the Bone Spring, particularly, people sort of know what to expect. But you still do share data with companies you have a closer relationship with, particularly now we are beginning to see more of the partner having more partners in your well, where everybody was just mainly drilling a 100% wells there for a while. So you are seeing sharing that way.

Operator

The next question comes from Holly Stewart [Howard Weil]. Holly the floor is yours.

Holly Stewart – Howard Weil

First question James, let me just gives us a little bit a help on the NGL side. What do we need to see there, seems like a big pick up throughout the rest of the year. Should may be just help us understand what's going on the NGL side?

James McManus

Well, there are several large facilities or fractionation coming on at the middle of the year. Our marketing groups looked at it and we think its starts to alleviate itself. Ethane rejection as we mentioned in the first quarter was we would call it severe, it was worse than what we anticipated and pretty close to what we anticipated. But we see facilities coming on to correct that in the middle of the year, and I think that’s pretty consistent with the way other Permian players are doing it.

Holly Stewart – Howard Weil

So I know you guys don't give quarter-to-quarter guidance, but may be kind of continue with that second half of the year pickup on the NGL side, is that what you think about it?

James McManus

Yeah definitely.

Holly Stewart – Howard Weil

Okay. And then I guess may be kind of sticking with the whole kind of quarterly thought process. You talked about some weather impact in the San Juan, how does that mean we should think about second quarter volumes in terms of the gas side?

James McManus

Well, I think we would expect this chart to improve, and we don't have a lot of growth in gas per say, but we expect to snap back from the part that we loss in the coal.

Holly Stewart - Howard Weil

Okay.

Chuck Porter

Holly let me add, the impact there was sort of two fold, when it’s not so much our gathering system but we did see how line pressures from our gathers that impacted us. The other thing is in a lot of these areas we have a wintering time as you know and we can't back into work over wells. We did some wells go down on us in the first quarter and we couldn't get into work on them, sot the combination of those two things sort of put us a little bit behind. Now gas, we anticipate making that up as we go through the rest of the year.

Holly Stewart – Howard Weil

Okay, great, it’s helpful. And then maybe moving on the comments on the release on the Wolfberry, this slick-water stimulations, why the change there maybe just a little bit of color and then any adjustment to cost and is this a permanent change going forward?

James McManus

Yeah, Holly I am going to ask John to add a little color. I think we think it’s going to be a permanent change because the results are so much better; the formation just tends to respond much better from a productivity standpoint. As we outlined, our initial IP rate is 30 day rates, 60 day rates, all of our rates look in even at 90 days are better on the slick-water frac and the traditional frac we have been using and so the question is going to be whether we are getting acceleration here or whether we eventually modify the reserves and we don't have enough time for that, we don’t have long enough to determine yet whether we are just accelerating. But the acceleration is enough increase in the overall return to keep going on slick-water. I will let Johnny comment a little bit about some of the logistics, that’s one of the reasons that we slowed down at the end of last year, as we were looking to change over to this process, John.

John Richardson

Yeah, Holly and let me, the results as James pointed out are very compelling. This is the trick, but we are beginning to pursue its paid dividends, it does take more water, so you have a longer lead time. We actually have shifted our wells if you looked at our plan at the original part of the year and you saw the dots on the map, you’d say that after the first quarter those dots are in a different place and what we've done is we've located our wells back to where we have a little better infrastructure. If we were out in a remote area, I think you would see capital increase, but hopefully we will mitigate that. It takes more water to do this, about three times more water and you do have the more water to dispose on the back side. Of course you are going to produce that water.

So we are going to move back into areas where we have more infrastructure where we can -- we have the larger frac ponds that are required, the larger flow back ponds. James mentioned that was one of the reasons we just weren't equipped for the shift earlier in the year and late last year. So now we are getting ourselves realigned. We've got some catch-up to do. And then going forward, I mean, with shales, particularly in a shale dominated area, the slick-water with its procedure and how it actually stimulates the formation is just a superior treatment and we are going to move towards that treatment recipe.

James McManus

Holly, in terms of, just to give you a little flavor on that, you know in terms of IP, we're 48% higher on IP, 58% higher on 30-day performance and 59% higher on 90-day performance. So it’s really quite a difference there and we just think economically we want to do them this way from that one. There's no reason to deny.

Holly Stewart – Howard Weil

Okay. Well, then, maybe just a follow-up to that, how long before, how much time do you need before you start thinking about changing assumptions?

John Richardson

Well, I think part of this is already factored in the guidance, production increase. Now James, I think addressed the long-term recovery, you know the ultimate reserves, so don't need a little more time to understand if this is going to hold up over time or whether it is sort of an acceleration of, I don't think we've seen enough data to and neither has the industry I think could make that assumption.

Operator

Next question comes from Irene Haas [Wunderlich Securities]. Irene, the floor is yours.

Irene Haas - Wunderlich Securities

Yes, good morning. I have two questions for you. In terms of the Mancos play in San Juan basin you already hold acres as such and just want to see your thoughts on vertical versus horizontal, because it looks like you are going in vertical first and any idea as to how much recovery you will have and how much of cost per well in your vertical program? Then secondarily, can you remind us the first Wolfcamp well in Glasgow County in Midland basin, it's next to an existing well, which well that was if I -- I remember the test rate was really strong?

James McManus

Irene, starting with your last question, the Yellow rose is the well that Laredo drilled that we had a 21% interest in, I believe we are going to be within a couple of miles of that particular well with our well. As it relates to the Mancos, we are actually drilling back into vertical wells that we had already drilled for other formations and we are [pay-adding] the Mancos. So we are not really drilling new wells vertically. These are just pay-adds that our guys have been experimenting with over time that we have had some success with and we are -- obviously with oil prices where they are, we are going to add these. But it doesn't really – we’re not really launching into full scale development of the Mancos shale in the way that Encana is. We believe that drilling of those wells would be horizontal, were you to go into that play based on what Encana is doing. So what we are doing really is just pay-adds in some already existing vertical wells.

Irene Haas - Wunderlich Securities

So economics, I mean, that work should be phenomenal because you are going in, probably spending a small amount of money?

James McManus

This is a $10 million program.

Irene Haas - Wunderlich Securities

And do you have a feel as to how much recovery you should expect out of Mancos oil zone?

James McManus

Well, I don't know if I’ve got EUR information as Johnny does. We’ve got about 100,000 barrels of production built in for this Mancos 3 completions for the year. I don't know about the EURs.

John Richardson

Irene, I don’t recall the EURs. This is sort of a dual system. We think we've done a handful last year and we saw some nice initial rates. We think this is a good way to look and these are scattered out. It's a good footprint. We think this is a good way to look and make sure the Mancos is productive in certain areas before we enter in to a vertical play. So it's sort of a dual thing here. It's a nice pick up in production for a not a lot of capital, but it's also a good testing program.

Irene Haas - Wunderlich Securities

Are you -- do any quarry?

John Richardson

Well, these are definitely completions. So we're not having that opportunity.

Irene Haas - Wunderlich Securities

Got you.

James McManus

Now having said that, I think we're quite excited about in Canada’s announcement. We're going to be looking very closely. If they are resolves and if go back to their press release or their conference call, I am not going to go in all the details of what they talked about on the play, but it's encouraging to us if they think they’ve got something and of course with our 82,000 acres out there, if they got it, we got it.

Operator

The next question comes from Mario Barraza [Tuohy Brothers]. Mario, the floor is yours.

Mario Barraza - Tuohy Brothers

I know you really don’t provide quarterly guidance, but what are you targeting now for accelerated Wolfberry completions per quarter and then what do you think could be potential exit rate on production for this year?

James McManus

Yeah, we typically don’t give that quarterly information, Mario. You are right; we don't really have that information to give you. I mean we have also -- I don't think we have given the year-end exit rate before, I can tell you this, our exit rate in the last few days was very consistent with our confidence in the new range of 26.1 to 26.5.

Mario Barraza - Tuohy Brothers

Okay. And I know you primarily sell at the wellhead, you don't really have with adding these, with these accelerated completions, you don't have any possible midstream concerns?

John Richardson

Well I think as James said, we hope our midstream concerns are mitigated by mid-summer, and so I don't think we are exacerbating problem if our information is correct. So yeah, we are making that assumption that we are going to have those problems cleared up.

James McManus

Mario, these are ongoing -- we have got a VP of marketing, she is in ongoing discussions with the firms that are building this and talking to them as our other operators in the Permian, I think this is very much like what happened to the Cushing to Midland differential, (inaudible) and people suspected once the pipeline capacity was added that that would narrow, it has narrowed. And the question is, is it going to happen in June, is it going to happen in May, is it going to happen in July? But hopefully based on all the discussions that we have had and others have had, it looks like this summer, this pickle with ethane starts to clear itself.

Mario Barraza - Tuohy Brothers

Okay and then...

James McManus

That’s what we're budgeting. If it doesn’t happen, then obviously we're going to have ethane rejection.

Mario Barraza - Tuohy Brothers

Okay. And then just coming back to your Wolfberry type curve, you recently raised the EURs from 155 to 165, so this upside is type to these new EUR share?

James McManus

No, a little bit of it is. Part of that is -- part of that is factored into some of the wells that we did, but in terms of [165] that’s primarily last year’s model which would not have included very many slick-water fraction there at all. And so I mean I can give you the order of magnitude which I don't mind giving you if everything continue to work. In other worlds, all the outperformance on the 90 day were to sort of bounce in and hit our curve and we didn't lose any oil on the rest of our curve. We have been talking about somewhere up near, about 180 to 200 instead of the 165 that we use it.

Mario Barraza - Tuohy Brothers

Okay, I appreciate.

James McManus

We are not ready to go there yet.

Mario Barraza - Tuohy Brothers

Okay.

James McManus

We need to be sure, but I guess my point is even if it stays at 165, I mean you guys all understand internal rate of return. This is much better from an internal rate of return perspective. Obviously we won't get the oil back as fast as we can, get cash flows back as best as we can.

Mario Barraza - Tuohy Brothers

Okay. I appreciate the color, guys. I hop back into queue.

Operator

Next question comes from [Tim Schneider]. Tim the floor is yours.

Unidentified Analyst

First question is on the CapEx increase, I guess how comfortable are you guys that this is kind of event for 2013 and how much contingency is built in for moving parts that may or may not happen?

James McManus

Well, Tim, I think it could be higher, I mean obviously we don't include any acquisitions or leasehold that we pick up and so who knows what we're going to wind up, picking up this year. I think the other thing that we are looking at carefully and we’ve not revised yet for is whether we might increase our exploratory efforts in the Delaware basin and particularly on the western side with the EOG success over there, that’s not really factored in. So I think it could give up some from where it is today.

Unidentified Analyst

Got it. Thank you guys for waiting, now let’s talk about the Western side real quick on a BHP well, any color there and have they (inaudible)?

James McManus

They have not, they are still waiting to complete that well. They have not completed it.

Unidentified Analyst

Last question from me, are you guys worried at all about running into kind of Btu constraints on the pipeline side if ethane rejection continues to go on like it has been or is that not an issue for you guys?

John Richardson

Well, I think we have seen some flair in places. Now that's sort of the plant’s option, so I think you know I don't know what our direct impact is, yet from there it shouldn't be that large, but we have seen some flaring and I think that's the way the plant handled that. So again their short-term and we are talking a matter of months, hopefully to have more plants coming online and increase capacity so we hope that it didn't get to be an issue.

James McManus

I mean, I think this is kind of how we answered it the whole time; we figured there wouldn't be short dislocations, but its in everybody’s best interest including the company's that process is there, the volume are there, they want to make money too so they are going to provide the facilities and the plants and so the hope here is that the dislocations tend to be fairly short term in nature.

Operator

Next question comes from Ryan Oatman [SunTrust Robinson Humphrey]. Ryan, the floor is yours.

Ryan Oatman - SunTrust Robinson Humphrey

Just wanted to confirm a statistic on the slick water fracs, what was the improvement in 90-day rates again?

James McManus

Yeah, the 90-day improvement was 59%. We were going from about 63 to 64 barrels at 90 days to 102.

John Richardson

That's a 90-day average.

James McManus

Yeah, 90-day average.

John Richardson

That's not a rate after 90 days.

James McManus

Yeah, excuse me 90-day average.

Ryan Oatman - SunTrust Robinson Humphrey

Got it, got it. How does that inform your horizontal program at all in the Midland Basin and in the Delaware Basin?

John Richardson

It basically has no impact.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. And then shifting to the utility side; can you speak to the rate re-determination process, kind of where we are with there and any updates on the other Alabama Gas Utilities?

James McManus

Yeah. In terms of that, we are still looking at fall of this year for our determination, I think Mobil Gas has just concluded their process and it’s not definitive yet when those order may come out, but they may get something here in the May-June time period. And then Alabama Power is next and then we are last.

Ryan Oatman - SunTrust Robinson Humphrey

Okay. And then taking a step back, I know the utilities is only a small part of your cash flow, but how do you guys weigh the advantages and disadvantages of keeping that asset under corporate structure versus a potential sale or spin-off of that asset?

James McManus

Well, that's evolving; in the prior times, the advantages have been to stay investment grade, obviously Moody’s just reaffirmed our investment grade on a negative watch, if you saw that. The other thing is it’s had a particularly high rate of return which we thought have competed with the Wolfberry on a cash sale basis. The tax basis has been relatively low. So there will be good bit of leakage on the spin process; it would be a fairly small utility. And having said that I think under the right circumstances any of those can be on the table. What I am saying it’s evolving; I don't think it’s a -- we are never going to separate, we are never going to, we are always going to keep the two companies together, that's not the thinking right now.

Operator

(Operator Instructions) The next question comes from Gabriele Sorbara [Topeka Capital Markets]. Gabriele, the floor is yours.

Gabriele Sorbara - Topeka Capital Markets

Just a quick question; if you can quantify the production that was impacted during the first quarter and try and just, could you clarify on the production volumes being in line with full-year guidance. Does that imply that you are currently at about 71,000 barrels, 72,000 barrels a day?

James McManus

I don't know that I have a broken out like that. I don't think we got a daily volume like that. We did look at the last several days, Gabriele and compared that to what we were targeting for the 26.1 to 26.5 as it was based on kind of on our budget and felt good that we were seeing the kind of increase both from having a 3rd Bone Spring fully back up and also feeling some anticipating what we're going to do in the Wolfberry from a perspective of adding a frac crew, picking a lot of the wells up and then accelerating some of the completions.

Gabriele Sorbara - Topeka Capital Markets

Maybe, could you give me some color on the backlog in the Wolfberry and how that gets worked on throughout the year?

James McManus

Johnny talked about that that because a lot of work has been down to make sure that that backlog is going to get worked down.

John Richardson

It's just a matter of two things, Gabriele. It's sort of catching up and adding their crews necessary to catch up and then its decreasing cycle time sales we go forward and almost across the board and leaving that to those crews in place as we move forward that accelerates our shorts our cycle times between spud and first delivery.

Gabriele Sorbara - Topeka Capital Markets

Okay, do you have a number count in terms of the current backlog?

James McManus

Number of wells not completed.

John Richardson

There is probably in the order of -- no I don't because of April is when we started to clear out the backlogs, so I don't have a running tally. But I think we see that backlog being cleared out by mid-summer and that backlog came in at probably around 20 wells to actually stimulate.

James McManus

In terms of hook-up.

John Richardson

Yes.

James McManus

Well, in terms of hook-up how many do we have...?

John Richardson

Well we had an inventory of probably 51, we are going to see that drop precipitously, but mid-summer I think we see that completely gone and we start to accelerate the last type for the year.

James McManus

So let me summarize that Gabriele and I will look to Johnny be sure summarized it correctly. We had about 50 wells that were not have done, that have been completed then we had 25 that were not completed or hooked-up.

Gabriele Sorbara - Topeka Capital Markets

And just hoping over to the Midland Basin and the horizontal that first well in Glasscock County; are you completing that wells similar to the rate of I guess in terms of how many frac stages are you putting into that?

John Richardson

Yes. Now we don't do, they would do specific stages, we do more clusters, but they would be the same, it will be the same volume job with the same number of total personally. If I recall correctly they do individual stages, we do more, our stages will be about 50% of that but we will have the same number of perforations or clusters as the Laredo did.

Operator

Next question comes from Irene Haas [Wunderlich Securities]. Irene the floor is yours.

Irene Haas - Wunderlich Securities

Yeah, just a follow-up couple of question; how do you feel about the natural gas market now that things seem to be firming up, would there be any decision point somewhere either first half or second half to, we think your gas drilling?

James McManus

Yeah, I think the price is still little bit low for that now certainly we are encouraged that it’s firmed up. If you look at the – that’a 425, I think to 450 if you look out several years. We really need to get little bit brought that level right now for us to get more excited on our gas projects side of things and for those projects to compete with the oil returns that we’ve got, so I think we are going to need a price in excess of 450.

Operator

Next question comes from Joe Magner [Macquarie]. Joe, floor is yours.

Joe Magner - Macquarie

I just wanted to get back on the interference, can you just talk a little bit more about the new approach, that staggered approach and explain that a little bit, and just discussed how many wells that’s actually been used on to date?

John Richardson

Sure, it basically this way. In the heart of our areas we are looking at the X and the Y sands, and they are about 80 to 100 feet apart. We do stimulate those because they are so close together, so we target one. So for instance if the payer well was an ex sand well which most are and as we put four wells in the section where there was only one, the closest well to it would now be a Y sand which would be about 80 feet off and we will keep staggering like that and it just seems to mitigate that direct sort of hot pressure wave moving through and then lessens that impact, we still see some of that. I couldn’t say, we probably drilled five or six well in this arrangement now since the first of the year.

Joe Magner - Macquarie

And I guess in terms of offset that is in between the X and Y, how the systems will there be?

John Richardson

80 to 100 feet.

Joe Magner - Macquarie

That’s vertical distance or horizontal, just trying to in between the actual (inaudible).

John Richardson

Vertical.

Joe Magner - Macquarie

Vertical, okay. And then one of the drivers of your increased production guidance you mentioned the pace of 3rd Bone Spring completion, you completed nine in the first quarter and I think originally had budgeted 28 for the year. Is there a potential increase in activity coming as you get those wells on faster or.

James McManus

Sure the Wolfberry completion we've been talking about, that we talked about earlier. Now the 3rd Bone Spring, the beauty of it is we are just outperforming right now. We've had some very, very good wells come online, because we are drilling in a very, very good areas. So it’s not so much that we are going to drill more of them, it’s just their performing well. But the Wolfberry is where we are accelerating and adding a frac crude and where we expect to get back up. And then we've got a 100,000 barrels coming from the (inaudible) completion as well and also the Wolfberry is now not only are we adding a frac crude, not only are we going to accelerate those completions but we are doing them in a fashion that's yielding more production from the slick water fracs.

Joe Magner - Macquarie

Okay, on those slick water fracs is that the cost you mentioned that three times more expensive I believe or it takes three times as much water, is that captured in the current LOE and just what's the impact on sort of the current guidance there, I just wanted to clarify.

John Richardson

Well, we are, it could but we are moving our wells back to where we have more infrastructure now to try to mitigate that, because we will be handling and disposing more water during the flow back to these wells. As far as capital costs go, they are roughly the same provided you have the infrastructure for your make-up water and your water disposal.

Joe Magner - Macquarie

Okay. And I guess looking out into the future, what could be the impact as I guess have to move back away from infrastructure and?

John Richardson

Well, I think in the future we have to go ahead and start…

James McManus

Get ahead of it.

John Richardson

Get ahead of that and build the infrastructure before we move into those areas.

Joe Magner - Macquarie

Okay.

James McManus

I want to say that it's a little bit -- you know a little bit larger frac facility and larger frac ponds and flow back ponds and a little bit more water disposal capacity.

Joe Magner - Macquarie

Okay, I'll leave there. Thank you.

James McManus

No, no, I mean just a final follow, what we've done this year is shifted to areas where those facilities are available and then we are going to be working on being sure they are available on next year’s program before we move there.

Operator

The next question comes from Tim Rezvan [Sterne Agee]. Tim, the floor is yours.

Tim Rezvan - Sterne Agee

I had a quick question just looking for a little more granularity, you are adding the frac crew, did the backlog just kind of get -- you know expand on you a little bit, kind of what caused you to sort of run behind on your completions to need you to bring an extra crew in?

John Richardson

Well, a couple of factors, one is the shift to slick-water did slow us down a little bit, I think it -- you know it was and ultimately that will be a good thing, we will get more wells treated with the slick-water and will -- but the shift did slow us down a little bit. We also given that we wanted to shift we were sharing a frac probe between the Delaware basin and part of our Wolfberry activity so we just sent that frac crew late last year into the Delaware basin to sort of get things moving there. And then we transitioned from one service provider to another at the first of the year, just because of competitive bidding and that new crew even though is performing very well, was a little slower getting starting just during the transition. So, we round up with a little bit of a backlog.

Tim Rezvan - Sterne Agee

I also appreciate the color on the utility discussion level. That was helpful. One last one. How do you think about the Avalon Shale now that the gas prices have rallied a bit? Is it still a matter of wanting to drill the deeper formation to secure leases or kind of how [unfitting]?

James McManus

Yeah, Tim, because everything, the Avalon is obviously up, we're going to hold it and the only thing gas prices can do is improve and we just -- we got our hands full with the more oilier plays right now and the economics are still more compelling for those plays. I think the Avalon is still a -- it's a (inaudible) shale for later down the road.

Operator

(Operator Instructions) The next question comes from Cameron Horwitz [U.S. Capital Advisors]. Cameron, the floor is yours.

Cameron Horwitz - U.S. Capital Advisors

Can you talk about what your AFE a year or your expectations for the cost of that initial Midland Wolfcamp well is?

James McManus

Yes, they’re probably somewhere in the neighborhood of $7.5 million.

Cameron Horwitz - U.S. Capital Advisors

Okay. And then are all the Wolfcamp test in ‘13 going to be in that kind of 4,000 to 5,000 for lateral or do you guys have?

James McManus

No, I think we're kind of sort of cut our T on the 4,400 feet lateral and see how it performs and then we will look to go longer. It's got to be second or the third one where we get a longer but we will look to go longer.

Cameron Horwitz - U.S. Capital Advisors

Okay. And then just lastly, outside of Glasscock County, where would you say that you are I guess most positive in terms of the horizontal opportunity that in the Midland Basin, is it the Midland County area, Martin County area?

James McManus

Well, the most positive in [Regin[,Glasscock obviously because most wells have been drilled down there, but when you look at pioneers enthusiasm up at Martin County, I am not sure they were unenthusiastic about any of, where we just, where we feel more solid about obviously where there is more well data, but I think it's possible that play goes north and goes very well north, but right now we don't have as many data points as we have in the sale.

Operator

Next question comes from Joe Magner [Macquarie]. Joe, the floor is yours.

Joe Magner - Macquarie

Thanks. I just had a couple of follow-up questions. X and the Y stands, you mentioned Bone Spring -- 3rd Bone Spring play of the wells that were drilled last year, you mentioned a lot of parent wells are X sand wells currently, how many Y sand producers do you actually have online now, and is there much difference in the productivity of those wells?

John Richardson

The answer is I really don't know, we started targeting the Y sand later in the year and there is really no difference. The Y sand is not present everywhere in our acreage, but where it is, there is really no difference between X and Y but luckily it’s present in the heart of our acreage, where we have done most of the drilling and you have seen the large wells coming or several of large wells not exclusively there, but for instance the Black Mamba 1 was an X sand, the Black Mamba 2 is a Y sand of both and we have talked about those wells in the past, they are both very good wells.

Joe Magner - Macquarie

Okay. And then one other one on the Wolfberry, the slick-water cycle time impact, has that led to a significant change in spud to first sales timeframes, or how do you see things shifting as that program moves to more slick-water completions?

John Richardson

Yes, we do see now the slick-water wells take a little bit longer to flow back, just because you are putting more fluid on them, but we do see an overall acceleration there, with the addition of this not as much downtime between spudding the well and actually stimulating and flowing the well back, that’s time we shortened.

James McManus

Yes, and Joe let me try to add on that a little bit, basically we think we can improve cycle times on our Wolfberry even though there will be slick-water, even though there is a little bit more flow back time, our whole focus here is going to be just how to get that cycle time down and that’s what we are working on.

Joe Magner - Macquarie

I was curious what been the near-term impact is on the cycle times, why you’re gaining ground or hope to gain ground over time, I was just curious what the change was from the old design to the new design and then where do you go from there?

John Richardson

We are gaining about a month of flow-back, so each well is additional well month of the period it’s on. So effectively, you are impacting production a lot over the whole program.

Operator

At this time, there are no further questions.

James McManus

Okay, well, thank you again for joining us today. And have a great day. Thank you, guys.

Operator

Thank you. This concludes today's teleconference. We appreciate your participation. You may now disconnect your lines at this time.

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