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Energen Corporation (NYSE:EGN)

Q3 2012 Earnings Call

October 25, 2012 11:00 am ET

Executives

Julie Ryland – Vice President, Investor Relations

James T. McManus, II – Chairman and Chief Executive Officer

Charles W. Porter, Jr. – Vice President, Chief Financial Officer and Treasurer

John S. Richardson – President and Chief Operating Officer

Analysts

Gabriele Sorbara – Caris and Company

Timm Schneider – Citigroup Global Markets

Cameron J. Horwitz – U.S. Capital Advisors LLC

Tim Rezvan – Sterne, Agee & Leach, Inc.

Operator

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

Without further ado, it is my pleasure to turn the floor over to your host Ms. Julie Ryland, Vice President of Investor Relations. Ms. Ryland the floor is yours.

Julie Ryland

Thank you, Erin, and good morning. Today’s conference call is being held in conjunction with Energen Corporation’s announcement yesterday afternoon of the results of operations of the three months and nine months ended September 30, 2012.

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

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

James McManus

Thanks, Julie, and good morning to you all. Positives for this quarter for Energen. Our third quarter oil production grew at 33% year-over-year. Year-to-date, Permian production is up 45% from the same period last year. Our 3rd Bone Spring and Wolfberry wells continue to perform very well. The test rates are in from our first horizontal Wolfcamp well on the east of the Pecos River in the Delaware Basin. These early rates are very encouraging. I’m going to dive deeper into these items in just a few minutes.

First of all, I want to review with you our preliminary 2013 budget plans, our official 2013 budget will not be finalized until this December and is obviously subject to change. But at this point, we plan to invest $900 million of capital at Energen Resources and $75 million at Alagasco, some $875 million will be invested in drilling and development our Permian Basin assets.

This capital will cover the drilling of almost 300 net wells facilities testing and other items. A subset of this capital approximately $130 million will be used to test the Wolfcamp and Cline potential in the Midland Basin and to continue unlocking the Wolfcamp potential on the Delaware basin on an operated and non-operated basis.

Due to continued low natural gas prices, we currently have no plans to invest drilling capital in any of our dry gas basins. We will be investing some $25 million in these areas primarily for 40 pay-adds in the San Juan Basin that have excellent economics even in today's low gas prices. We are looking at maintaining our active rig count in the Permian, running 10 rigs in the Midland Basin, 5 to 6 rigs in the Delaware Basin and a couple in the Central Basin platform.

In 2013, we’ve got very strong production guidance of 26.5 million barrel of oil equivalents, an 8% increase in total production for 2012 as to be expected. Our natural gas production likely will decline significantly about 4% next year since we’re not spending any capital there, which shows you also have still in the 8% increases because it includes that 4% decline in gas. But importantly our oil and natural gas liquids production is expected to increase 21% and for the first time, it will comprise more than half of our total calendar year production.

Given our substantial potential drilling inventory 2013 is going to be an important and exciting year for Energen. We will be testing several emerging plays and concepts in the Permian Basin. Results from these test wells will help frame our future pace of development.

As we test these emerging plays in 2013, we will continue to develop our successful vertical Wolfberry and horizontal 3rd Bone Spring plays programs. We expect production from these two plays to once again drive substantial double-digit growth in oil and natural gas liquids. A $26.5 million barrel of oil equivalents or 2013 estimated production is at the high end of our early guidance range that we issued last year. And as I’d noted earlier reflects greater liquids to gas mix.

When we first put our very preliminary 2013 production guidance out, we noted that we believe we could come announce in early 2011. We can come close to doubling our oil and natural gas production from 2010 levels. As we have successfully implemented our plans and transition to the company to become a major liquids focused player in the Permian. We now expect our oil and liquids production in 2013 to be more than double comparable levels in 2010, 7 million barrels to 14.3 million barrels in 2013, quite an accomplishment for a company that had a mix that was much more natural gas in 2010.

Consolidated after-tax cash flows in 2013 should range from $945 million to $975 million, including $845 million to $875 million of Energen Resources and 100 million in Alagasco. As you can see, our capital plans asset proved property and leasehold acquisitions are largely funded by our expected cash flows. Approximately 69% of our total estimated production in 2013 is hedged at very attractive prices. We’ve hedged 82% of our estimated oil at more than $90 a barrel, 30% of our estimated NGO production at $1 a gallon and 68% of our natural gas at close to $4.65 per Mcf.

We also have hedged a portion of our suite to WTI Cushing oil differential at just over $3 a barrel, as well as some of our exposure to the WTI Midland to WTI Cushing differential at about $1 a barrel. We expect about 65% of our production in 2013 to be sweet oil. Our small utility will once again have an opportunity to earn a loud after-tax rate of return on equity between 13.15% and 13.65%. In 2013, we estimate the utilities average equity will be approximately $375 million to $380 million in 2013.

Next, I’d like to discuss our Permian operations beginning with the 3rd Bone Spring. Our 3rd Bone Spring program in the third quarter continue to generate strong results. As you know we're developing the 3rd Bone Spring Sands on our core acreage in the Delaware Basin, east to the Pecos River.

We tested 12 gross wells during the quarter, initial stabilized rates ranging from 622 BOE per day, 61% oil, to 1593 BOE per day, 77% oil. The average initial stabilized rate was 954 BOE per day at 70% oil and the 30-day average production rate of nine wells tested with 639 BOE per day at 67% oil.

Through the first nine months of 2012, we have drilled 32 gross, 30 net wells including one dry hole that we expensed this quarter. The average initial stabilized rate of the 28 gross wells tested with 1,040 BOE per day, 70% oil. The 25 wells with sufficient production history generated a 30-day average rate of 687 BOE per day, 68% oil. Obviously, we are very pleased by these results. We may not have had a through the roof well like Black Mamba or Cadenhead in this particular quarter, but we had 12 solid performance with initial rates all over 600 BOE per day.

Wolfberry story is also a very good one too with well performance continuing to meet expectations. Through September 30, we have drilled and completed 135 gross, 130 net Wolfberry wells. The average initial stabilized rate of these wells was 84 BOE per day, 73% oil and the average 30 day rate was 69 BOE per day, 76% oil.

As many of you know, we have been testing the Wolfcamp potential east to the Pecos River. We had originally planned to drill three test wells this year and have now expanded that to five. Most of the wells have been drilled and on various stages of completion now. Only one has been tested so far, we drilled the University 36-20 #1H in Winkler County, its initial rates were and all encouraging. The initial stabilized rate was 735 barrel BOE per day, 84% oil, and the well had a 30-day average rate of 487 BOE per day, 83% oil.

Production has since declined more rapidly than expected. We think this is a phenomenon related to permeability of the area in which we zone and which we completed it. The Wolfcamp shale is obviously at very thick interval, it can be tight in some places and part of the learning curve for us is determining the optimum horizontal target within that interval. But we had good hard recovering potential; hit a tight streak in that particular well, still had good initial rates.

Energen Resources have a 50% working interest in the BHP operated State C19-15 #2, which have been shut-in for tubing installation earlier this year, but was recently placed on production. This Reeves County well is located near the Pecos River.

Prior to shut-in, the well had a flow back rate, I think that we reported earlier at 6 BOE to 650 BOE per day, 60% oil, after being brought online this State C19 produced at a 30-day average rate of 316 BOE per day, 62% oil. While it’s initial rates were not as impressive as the University 36-20, its subsequent production decline has not been at steep.

We are looking forward to testing more of the Wolfcamp in the Delaware Basin. As we perfect our techniques and learn from others drilling in the area, we will be in a much better position to understand the shale’s full potential in the basin.

At this time, I’m going to let Chuck talk about the financial results and outlook for the full year as a whole. Chuck?

Charles W. Porter, Jr.

Thank you, James. Excluding non-cash mark-to-market losses on open hedge contracts Energen’s adjusted net income for the three months ended September 30, 2012 totaled $31.8 million or $0.44 per diluted share. This is in comparison with third quarter 2011 adjusted net income of $54.5 million or $0.75 per diluted share.

Realized natural gas and natural gas liquids prices in the quarter were significantly lower this year. Gas prices were down 30% and NGL prices were down 23%. In addition, DD&A and LOE were higher. Together, these items more than offset a 15% increase in production.

Consolidated adjusted EBITDA totaled $172 million and compared with $168.6 million in the prior year third quarter. Energen Resources had adjusted EBITDA of $173.6 million in the third quarter of 2012 as compared with $170.1 million in the same period a year ago.

Permian basin production in the third quarter 2012 increased year-over-year by 32%. And this largely was due to our 2011 Wolfberry acquisitions and associated development and increased 3rd Bone Spring development in the Delaware Basin.

Our natural gas regions saw only slight volume increases in production and this of course is due to the company’s focus on oil and NGLs in the Permian basin. The total LOE per unit in the third quarter of 2012 decreased approximately 2% from the same period last year to $12.92 per BOE. Our Base LOE and marketing and transportation expenses increased approximately 2% to $10.58 per BOE. While commodity price driven production taxes declined approximately 15% on a per unit basis.

DD&A expense per unit in the third quarter of 2012 increased approximately 31% from the same period last year to $15.38 per BOE and generally reflects year-over-year increases in development costs and increases in production. Per unit G&A expense increased approximately 11% in the third quarter of 2012 to $2.82 per BOE, primarily due to performance based compensation.

Our natural gas utility generated a net loss of $10 million in the third quarter of 2012 as compared with a similar net loss of $9.1 million in the same period last year. For the rate year that ended September 30, Alagasco earned an after-tax return of 13.6% on its 13 month average equity.

Our outlook for the remainder of the year remains largely unchanged, given that we are now in the final quarter of the year, we narrowed our guidance range for after-tax cash flows to $805 million to $820 million on a consolidated basis. Energen Resources estimated after-tax cash flows of $700 million to $715 million.

We also re-affirmed our estimated 2012 production of $24.5 million BOE. We do of course have some production issues in the third quarter, the surrounded delays in pipeline hooks up in the Delaware Basis, which have now been resolved. We had an inventory build in the Delaware Basin that we expect to clear up in the fourth quarter that will allow some ethane rejection and we also had gathering system bad pressure issues in the Midland Basin, which will be resolved we think by the end of the year, but they have already been accounted for in our estimate of Wolfberry production for 2012.

We also are planning to accelerate some completion. So those are the third-quarter issues and that would be why we still feel comfortable with the $24.5 million BOE of production in 2012, as an achievable goal.

We have increased our plant capital investment in 2012 to reflect a variety of items that fall into three comparably sized buckets. Number one, we had some additional project; these include revised project plans that will benefit us in 2013. This covers such things as additional projects, additional saltwater disposal wells, drilling of those wells and some increased non-operated activity. Number two, we did have some increased cost and experienced some drilling problems in the third quarter and then number three is the timing of Interwell completions.

We now estimate that consolidated capital investment in 2012 would be approximately $1.4 billion, this includes $1.2 billion of non-acquisition, oil and gas exploration and production capital, a $100 million for the year-to-date acquisition of proved properties and unproved leasehold, and $70 million of the utility capital spending.

Approximately 70% of our total estimated production for the remainder of 2012 is hedged and we assume the process to our unhedged oil and natural gas and NGL volumes for the remainder of the year are $91 per barrel, $2.60 per Mcf and $0.90 per gallon respectively.

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

James T. McManus, II

Sure. Thank you, Chuck. So there you have a brief rundown of the latest developments at Energen. In short, 2012 is on track to be an excellent year marked by significant production growth in the Permian Basin. The performance of our 3rd Bone Spring and Wolfberry programs is very solid and is driving our substantial growth in 2012 and 2013.

Our preliminary 2013 budget shows another strong year. Non-acquisition and capital investment in the Permian Basin that approximates cash flows and we are testing the Wolfcamp shale in the Delaware Basin and we will expand our horizontal testing to the Midland basin in 2013. Results of these test programs will help to frame our future phase of development.

At this time, I’d like to move into Q&A and we will turn the phone line over to our facilitator Erin. So, Erin, if you would take over please?

Question-and-Answer Session

Operator

Certainly. The floor is now open for questions. (Operator Instructions) Your first question comes from Gabriele Sorbara. Gabriele?

James T. McManus, II

Hello, Gabriele.

Gabriele Sorbara – Caris and Company

First question, 2013 production guidance looks good to me, looks beautiful too, but when I look at the 2013, Chuck did mentioned, you guys are comfortable with that and you reaffirmed it obviously. But it looks aggressive to me that it implies over 10% or by 10% sequential growth. Can you talk on that a little bit and can you talk about current production maybe?

James T. McManus, II

Yeah, Gabriele. I’m going to let Chuck to add a little bit of that in his explanation. Why don’t you Chuck rerun over that and I’d be happy to add some color.

Charles W. Porter, Jr.

Yeah, we were a little bit sure of course in the third quarter, we laid out some of those items for us. Probably compared to (inaudible) models were probably around 270,000 or so barrels equivalent short, most of that is probably going to be in the Delaware basin where we had the pipeline issues that we talked about. That with the kind of the inventory deal, we guesstimate that to be about 140,000 of the short fall and again we think that pipeline issue was taken care of and that we’ll be able to serve and move that inventory deal in the fourth quarter.

Now the reminder of it is going to relate to the issues on the Midland basin and those will probably not be fixed before the end of the year and some ethane rejection. But as I mentioned, we are planning to accelerate some conclusion activities to try to make up for that, so the end result about whether we actually hit the $24.5 million will basically relate to have well some of those how strong, some of those additional completions come on.

James T. McManus, II

Yeah, let me add in a little bit, Gabriele we think we're going to be very close to the 24.5 million, it's not on the button and the pipeline issue has been fixed, it’s not we think it's going to be fixed, it’s fixed. Those wells are hooked up, we think we can do a little bit of a better job moving some of the oil inventory that’s been sitting in tanks, and so we got the question continuously about where we were running as we’ve been in the meetings, aren’t you going to be about 24.5 and we have basically held to the 24.5 because some of these issues are things that have been ongoing.

And as Chuck pointed out, we do not anticipate the pipeline constraints in the Wolfberry being fixed until the beginning of the year. And yet we still think we can make our numbers and so we’re holding to the 24.5 at this time because the pipeline problem has been fixed, we’ve got planned recompletions that we have moved up. And so we think that we can do that.

Gabriele Sorbara – Caris and Company

Okay, great. Thanks guys. And then on the CapEx obviously increase to $155 million. Can you dig into that a little bit?

James T. McManus, II

We can, we can. What I’m going to do is let Jonny talk about that in a little bit more detail. We can add some color on the particularly the increased drilling costs. And obviously, one of the main – it really falls into three buckets, you mentioned the $155 million, and we talked about this in the press, one is additional projects that we decided to do in 2012 related to salt water disposals, some related to some of these completions, we are pulling forward in other items. But Jonny, why don’t you talk a little bit in particular, I mean, and the third of it is the cost in drilling overruns and then we had some inter period things that I’ll ask Jeff to address. But let me let Jonny address the drilling side first.

John S. Richardson

Good morning, Gabriele. James has pointed out that approximately $50 million is drilling cost overrun. A couple of things, production has been very good in the Delaware Basin from the oil and liquid side, but also came a little more water with that. So we’ve had a little higher water disposal cost that’s been a problem that’s sort of plagued us this year. But we’re a little bit higher according to our (inaudible) just for water disposal, there in the Delaware.

And then the – but we did have some drilling problems, that are direct drilling problems, particularly as we moved into an area over on the eastern side of the basis where some of our Wolfcamp exploratory wells are – and some of our Bone Spring wells, it’s specifically an area there where we’ve gotten into an over Delaware producing field and we’ve had some depleted zone shallow and some over pressured zone deep, and we’ve had a difficult time balancing. We ran through a phase of several wells there where we had some real issues. Our last throughput wells in that area, it looks like those issues have been resolved. We figured that out and we are doing much better there. But we did have a particular time there where we had some very difficult drilling there.

And then in the – a little bit of the same, not the same type issue, but a little bit of more difficult drilling as we go a little deeper in the Midland Basin. In some of the northern properties, we have – we encountered a few drilling surprises there and we had that through, they just happened on sort of coincide there in the third quarter, some things came to lose there and the number went up.

James T. McManus, II

Chuck, why don’t you cover the inter?

Charles W. Porter, Jr.

Yeah, on the timing issue related to kind of the inter area well completion and other activity, we basically had estimated a certain amount of capital to come in to 2012 from 2011. And we are making that estimate last year. And we kind of got a little bit behind and so we had in the fourth quarter of 2011, so we had more money that came over from 2011 into 2012.

And we were basically thinking with the similar activity level that we probably had the same kind of amount of money going out into 2013. But as we’ve gone through the budgeting process here recently and done what we needed to do on some of the acceleration, we are now having less, an anticipate less amount of money going out of 2012 into 2013. And so that’s again, roughly about one-third of that amount that you mentioned of the increase of the $155 million for the quarter.

James T. McManus, II

Gabriele, I would point out, we feel very good about our 26.5, which is at the high-end of our range in 2013. And we don’t have a tremendous amount of contribution built-in from our test wells in the Wolfcamp and Cline in that number. So and I think that’s a pretty strong number, but anyway is that helpful?

Gabriele Sorbara – Caris and Company

Yes. Thank you. Just getting back to CapEx, just one more item on the Wolfberry you are spending about $490 million, I mean, if I get into the number there for just drilling and completion cost it get about $384 million, what’s the variance, what other costs are in that $490 million?

James T. McManus, II

Let Johnny address that.

John S. Richardson

Well, I think, basically you have facilities costs there and some – just trying – it sure was a big year acceleration wise there and so we did have good many facilities as we moved into new properties that will – that would make the bulk of that number.

Gabriele Sorbara – Caris and Company

Okay. Thanks. And just one more question. As you drill in – you are planning to drill in the Midland Basin horizontally in 2013, have you take the Wolfcamp and Cline wells, I guess where are you drilling those wells, can you talk about that? Is it at the Eastern shale area or is it more kind of that Glasscock County area where Loreto has been active?

James T. McManus, II

Well, at this point, the bulk of them we have planned in our acreage that is in Glasscock County that would be very south and north of Loreto, we made some testing outside of that area as well, but we will definitely do some testing in the area where the results have been good.

Gabriele Sorbara – Caris and Company

Okay. Great. Thank you guys. I will jump back in queue.

James T. McManus, II

Okay.

Operator

Your next question comes from [Marian Baratta]. Marian?

Unidentified Analyst

Hey, good morning, guys.

James T. McManus, II

Good morning, Mario.

John S. Richardson

Good morning.

Unidentified Analyst

Hey, how is it going?

James T. McManus, II

Very good.

Unidentified Analyst

It’s good to hear. I just wanted to follow up a bit more; I think Gabriele touched on this in the last question. Some of the jumps you guys have in CapEx for the fourth quarter are – there are decent side just for one quarter. Can you kind of just walk back through – Chuck, you were saying a couple of minutes ago about a third of the increase this year being at $155 million and that having to do with carryover from last year?

James T. McManus, II

A third is $50 million; the full is $155 million. So just to be sure [Marian] this is James. We’re talking about a third of the $150 million, let’s just call it $150 million, $50 million of it being drilling, over $50 million of it being additional projects that we’ve moved into this year and then $50 million of it being what Chuck talked about. I’ll let Chuck talk about that one more time.

Charles W. Porter, Jr.

Yeah, you’re right. The one-third of the $150 million or roughly $50 million or so is related to what you’d have to call timing, where we – when we originally put the budget together for 2012. We thought we’re going to have a certain level of activity. We were putting that number together back in, say, October 2011 and so we ended up having some delays in the fourth quarter. And so we had costs that we thought would be incurred in ’11 actually come into 2012.

Originally, we were thinking, okay, we had a kind of a similar activity level that we might have the same amount of money going out in 2013, but we really haven’t experienced kind of the delays. On the other hand, we are actually kind of trying to accelerate things into 2012. And so the net of those two amounts is roughly that $50 million. I know that’s confusing, but it’s the best I could really try to give you a little color on it.

Unidentified Analyst

Okay. And then, can you just talk a little bit more about – last quarter, you had said, you had some back pressure issues and it looks like those have cut up again. That’s primarily in the Wolfberry and so next year the growth rate that you have forecasted for the Wolfberry with what you’re – what it sound like you’re looking to implement right now on the fourth quarter and early next year, that should cover your, growth profile for next year?

James T. McManus, II

Yeah, we knew that those problems, we know that those problems weren’t going to be fixed until the end of this year, we expect that they will be taken care of at the end of this year, and that’s one of the reasons we weren’t upping our guidance after the 24.5. We knew that was going to be continuing to be a problem until the end of the year. And so at this point we would plan on having those solved at the end of the year, and that’s not really – we don’t anticipate solving them before the end of the year. We expect to make the 24.5, as I pointed out because we have now gotten some wells up to pipeline that we delayed. We plan to clear some inventory and we’ve got some additional completions in this year.

Unidentified Analyst

Okay, and then just lastly on the sort of your exploration CapEx, I mean, will the horizontal Wolfcamp in the Delaware Basin, is that, I mean right now in the third bounce frankly. You have a couple of years left drilling inventory east of the Pecos and so basically, once you further delineate the horizontal Wolfcamp that will likely take a front seat as opposed to west of the Pecos where you guys had some of the encountered the heavy water fill last year.

James T. McManus, II

In particular, we encountered water in the 3rd Bone Spring. Now yes, I think the likelihood of something taking off in the Delaware basin is more Wolfcamp related at this time than 3rd Bone Spring west side. But bear in mind, we’ve got and we talked about this, we expect and they told us and we’ll see if they do it.

We expect them to do it. BHP will drill three wells at our Horizontal Wolfcamp test on the west side that we’ll have a 50% interest in. In addition, we are now doing 5 in 2012 in total, we disclosed one and we got 4 more in various stages of completing. And that we plan to run a rig in the Wolfcamp horizontally primarily on the east side in 2013. So the remainder of ’12 and into ’13, there is going to be a lot more information about the Wolfcamp.

In addition, we’re not the only one doing it. We’ve talked about the Concho [Rawhead] well to the south of us and there are other wells that are in various stages of completion by other operators that we only have rumors on and not hard information, but we hope that as the year progresses we will see more hard information on that that as well. So there’s going to be a lot of activity in the Wolfcamp and you are right. Our hope in this particular basin is that the Wolfcamp turns out to be a very good formation for us and that we are able to move that at some point from the exploratory stage that it’s in now into more of a development stage.

Unidentified Analyst

Okay. Thanks very much.

James T. McManus, II

Thank you.

Operator

The next question comes from Timm Schneider. Tim?

James T. McManus, II

Hi, Tim.

Timm Schneider – Citigroup Global Markets

Hi, guys how is it going?

James T. McManus, II

Good.

Timm Schneider – Citigroup Global Markets

All right. So first question is kind of can you provide a bit more color on this horizontal Wolfcamp well, lateral length, what the cost was, what pressures you were seeing, kind of the issues you were having in that area, if any and I guess what you learned from this first one?

James T. McManus, II

Yeah, we will. In terms of – this is – these wells are going to have a lot of testing, we are not really going to talk about costs on these wells in particular, but we will talk about what we saw relative to production on this particular well. It’s one well, obviously as you well know, Tim, you need a lot of different tests to see it. So very thick formation and the next four that we drilled, we plan to test various areas within the formation, but I’m going to let Jonny talk a little bit about in terms of this particular what we saw and how it performed.

John S. Richardson

Yeah, Tim. Bear in mind that the upper Wolfcamp 400 to 450 feet thick, the middle 400 and 450 feet thick, the upper lower has some good pay before you may get into what we think maybe wet. So 1,000 feet of interval here.

We first sort of shot over there. We picked something we liked, initially this well looked great. We knew that the way it’s treated, it might be a little tight, but the initial production was outstanding. But it just decayed much faster than very high oil cut, nice strong well, but just decayed a little bit faster or a lot more faster than we would have liked.

And so, I guess, we conclude that we found a hydrocarbon barring formation, very attractive in that sands with a lot of hydrocarbon in place. But I think that target we’ve chosen at least in this particular area is just high, we need a little more permeability. So that’s just sort of going to be – we need to look at our intervals, look at both geologically and geographically, what this well holds and what we glean from it. First shot out of the box, I think, we will improve a great deal.

But we did encountered good oil in place. We encountered plenty of pressure, but just on the permeability to use that pressure efficiently and – but we’re encouraged overall about the system on the eastern side.

Timm Schneider – Citigroup Global Markets

Got it. And where are you guys drilling the other ones, is that more of a delineation of the play or it is right around this one?

James T. McManus, II

Well, it’s a delineation of the play on the eastern side, Tim. So – and we are not really talking about where those locations are, but we’ll spread out on that farther eastern side, I would say. Jonnie?

John S. Richardson

And that’s a huge area.

James T. McManus, II

Yeah.

John S. Richardson

And again, we’re looking at 1,000 feet, so you know you got lots of options.

Timm Schneider – Citigroup Global Markets

Got it. And then just switching gears for a second, I guess there’s a lot more data points just industry wide with respect to the horizontal Wolfcamp and the Cline in the Midland Basin. So my question is, why not focus more on those in the interim given that you already have data from other operators, wouldn’t that be kind of picking low hanging fruit or how do you guys think about that?

James T. McManus, II

Well, I think, we’re going to move forward in the Midland Basin this year and definitely Tim, I think, you’re right in terms of I’ve talked about, if you talk about a baseball game for a minute, certainly, the Midland Basin is further long. We got lot more data, we got lot more results and we’re going to move into an area where that’s going to happen.

Now in terms of Delaware Basin, obviously, one of the issues is the inventory starts to run out as [Marian] was pointing out. And we do think we need to find out how prospective the Wolfcamp is, which we like it right now and see if we can delineate it enough to move in into the development phase. So I think the prudent thing to do is actually to go forward on both fronts, which is what we plan to do.

Timm Schneider – Citigroup Global Markets

Got it. And then just switching real quick to the expiration expense in the quarter. Can you just go over what you think caused the dry hole, what the structural issue was on that?

James T. McManus, II

Yeah, I mean, we’re very near the river. We just hit a bad spot there. It’s been unusual. We don’t think it is indicative of anything relative to the bulk of our inventory. Jonny, do you want to add any comments on that?

John S. Richardson

Yeah, we’ve talked in the past, that we know there is a structural event probably playing out of the deep seeded spot that comes through approximately where the river is, then at the river’s depth, the surface is not exactly where it is. We had some land that was jetted out a little bit to the south and west closer to the river. We sort of knew when we encountered the event in the wellbore and we just couldn’t over come the water cut. And unfortunately, we just could never get the oil cut to perform for us, we just got too close that event.

James T. McManus, II

I mean, Tim when you think in terms of the number of wells we’ve drilled out there to have one dry hole is pretty darn and good.

Timm Schneider – Citigroup Global Markets

Yeah, that’s right. I mean it seems like, this one seems to be, this was probably the closest one you guys drilled to the Pecos, is that right?

James T. McManus, II

Yeah.

Timm Schneider – Citigroup Global Markets

Okay. The only other question I had on the NGL side, can you tell us what’s your transportation cost is to Bellevue on a gallon basis, if you have that?

James T. McManus, II

Actually I’m looking around, I don’t think we have that, but Julie can follow back up with that with you Tim, we don’t have that sorry.

Timm Schneider – Citigroup Global Markets

Yes, sure. That’s okay. I will follow-up with Julie offline and I will get back in the queue. Thanks.

James T. McManus, II

Thank you, Tim.

Operator

Your next question comes from Cameron Horwitz. Cameron?

Cameron J. Horwitz – U.S. Capital Advisors LLC

Thanks a lot. Good morning, guys.

James T. McManus, II

Yeah, hi, Cam.

Charles W. Porter, Jr.

Good morning.

Cameron J. Horwitz – U.S. Capital Advisors LLC

Can you just walk us through the assumption that are baked into the ’13 CapEx guidance in term of your well cost I guess for Bone Spring, Midland Wolfcamp and Delaware Wolfcamp if you could?

James T. McManus, II

Well, effectively we have in terms of 3rd Bone Spring and Wolfberry, at this point; we’ve left them the same. I mean we’ve left them at 6.9 I think either 2.3 or 2.4 I can’t remember on Wolfberry. We are in the process of negotiating those contracts and we will be able to affirm those numbers for you in December, but right now we’re using what the costs, what the target was for last year.

Now as it relates to the Wolfcamp, we’ve got as you might expect since we’re doing lot of coring and testing, we’ve got more built in for those particular wells than we would ordinarily expect to have on a development stage. So our targets are on a development stage and this is very preliminary, would be somewhere, let’s just call it $8.5 million. We’re going to spend more than that on these initial wells, let me just leave it at that.

Cameron J. Horwitz – U.S. Capital Advisors LLC

Okay, that’s fair. And how – do you feel like you have a decent cushion in terms of accounting for some of the issues like what you’re seeing this year, a lot of disposal in facility gathering. How are you thinking about that in the ’13, just giving yourselves a bit of a cushion there?

James T. McManus, II

Well, I think, we’ve got all of baked into ’13 in a appropriate way. So we feel very good about our ’13 numbers.

Cameron J. Horwitz – U.S. Capital Advisors LLC

Okay, okay. And then just with the – I think, okay, I think that’s it from me. I’ll get back in. Thanks a lot.

James T. McManus, II

Cameron just to say, we’ve got some contingency capital built into ’13 to account for some level of problems that we may counter. We’ve got some built in to that. Okay, Cameron is gone, Erin. I think he dropped off. Is there more questions? Next, next?

Operator

(Operator Instructions) And we do have a question on the line from Tim Rezvan. Tim?

James T. McManus, II

Yeah, hi, Tim.

Tim Rezvan – Sterne, Agee & Leach, Inc.

Hey, good morning, guys. I just had a quick question. I guess some still little unclear, is the pipeline hook up issue is different, was there compression issue on the pipelines as well.

James T. McManus, II

Well, in the Wolfberry back pressure is a compression issue in some cases and we are moving to add compression to resolve that issue. The pipeline hookup issue is we had anticipated being able to secure right away and lay pipelines in the Delaware basin to some of our 3rd Bone Spring wells and as can happen, we went on dealing with an extremely difficult landowner, it took more time and we were late with getting that pipeline in. What am I saying is, we now have it in, that issue is completely resolved and so we expect to pick up production immediately from that, the back pressure of gathering system constrains we talked about, some of that is related to compression, some of that is related to size of pipe. Both of those issues we plan to have taken care of at the end of this year.

Tim Rezvan – Sterne, Agee & Leach, Inc.

Okay. That’s helpful. A lot of questions have been addressed, thanks.

James T. McManus, II

Okay. Thank you Tim.

Operator

We have Cameron on the line again. Cameron go ahead.

James T. McManus, II

Hi, Cameron.

Cameron J. Horwitz – U.S. Capital Advisors LLC

Hey guys, one more for me, just in terms of the oil differential, you had a little bit of couple of bucks of compression, here it looks like quarter-over-quarter, how are you seeing things in the Q4, I think you’ll see continued compression there, or some stabilization?

James T. McManus, II

Cameron in particular, are you talking about the Midland to Cushing differential.

Cameron J. Horwitz – U.S. Capital Advisors LLC

Yeah, I guess I’m just thinking about your corporate differential. It looks like you did some kind of 560, half of the benchmark versus 760 last quarter, so I guess just in general?

James T. McManus, II

Yeah, just a second.

John S. Richardson

We got that somewhere around here. It basically results; the average transportation that we’re experiencing has gone up a little bit. It’s like $2.30 number; I think previously it was about $2 number. The sweet to sweet differential for the quarter was $1.70 something number and sour oil differential was fairly high this quarter. I think it was around high $3.

So when you blend all those together, waiting in for sweet, sour, we now obviously pay the transportation average on everything, that was kind of the $5 that you relate or you mention, which is about a 94% realization for this quarter, I think, 93.7%, which is I think going forward we hope that the sweet to sweet differential will continue to narrow, and we are going take any opportunity to kind of lock that basis differential in if we can. As far as the transportation, we are not seeing any major moves there.

Cameron J. Horwitz – U.S. Capital Advisors LLC

Okay. So for now kind of maybe similar levels quarter-over-quarter from what you are seeing right now, maybe some bias towards some slight improvement?

John S. Richardson

I don’t think we can see some improvement on this sweet to sweet if it were to continue to narrow. It is very volatile. I mean, it has narrowed a good depth and we are able to lock in some hedges for 2013. Frankly here recently has borne out a little bit. So I can’t really predict where that is going to get.

Cameron J. Horwitz – U.S. Capital Advisors LLC

Okay. All right. I appreciate that color. Thanks again guys.

Operator

We have Gabriel Sorbara on the line. Gabriel?

James T. McManus, II

Hi, Gabriel.

Gabriele Sorbara – Caris and Company

One more question, on the horizontal Wolfcamp well, can you talk about maybe what it’s currently producing or maybe what you expect it to re cover? And maybe what’s kind of that breakeven in terms of at an $8.5 million well?

James T. McManus, II

I’ll let Johnny talk about both of those two things Gabriele. We’ll give you what we think on the BHP well, which is actually even though its rates were less initially and 30-day rate, I think, that’s going to actually be a better well. But Jonny, go ahead.

John S. Richardson

Well, as far as breakeven, it can be over and I think we're going to – I think to satisfy us we’re going to need something that performs more or like a Bone Spring, maybe not you don’t have to be quite that strong, but I don't really have the breakeven numbers in front of me but I can give you a sense that we need 400,000 barrels plus to be satisfied with the project once it gets full strong and certainly the resource is there.

As far as current production, the well is down to just say a 100 barrel liquid once a day most of that is oil.

Gabriele Sorbara – Caris and Company

And what about the BHP well?

James T. McManus, II

BHP well is producing between 150, 100 and 75 a day and another over 500 or 600 Mcf gas a day.

Gabriele Sorbara – Caris and Company

Well, what percent of those wells in terms of liquids? Do you have that handy?

James T. McManus, II

I am sorry Gabriele.

John S. Richardson

Percentage of liquids he is talking about, liquids and NGL’s. I think we disclosed 80% on the oil on that but I don’t know if we – do we have the – was 80% liquids or 80% oil?

Charles W. Porter, Jr.

It’s 80% oil.

John S. Richardson

80% oil, so the oil mix was very strong on an our well, the BHP well was 60% oil; I don't know if I have the liquids numbers here Gabriele.

Gabriele Sorbara – Caris and Company

Perfect. Thanks. I appreciate the color.

James T. McManus, II

The yield will be about 140 barrels per million, Gabriele usually under the step out here. I don’t know that I had a specific cash or a yield or there is data on that, we haven’t seen any data come through on the BHP well through accounting yet to my knowledge that we would know that, but that’s what the Bone Spring is running in. And we would not – we think, we would still be in that same range with what we are talking about here.

John S. Richardson

And I would just mention, Gabriele both the BHP and the well we did were middle Wolfcamp completions not uppers or lowers. We will be testing the upper in the next four wells.

James T. McManus, II

Gabriele and as I look here the C-1915 no. 2 well again if really look at the data, it’s more like a 125 barrels a day and 600 Mcf, so about 225 barrel equivalents per day. I had it rounded, that’s on a two stream model not a three, again it’s back to the yield question that I don’t know the answer to.

Gabriele Sorbara – Caris and Company

Okay, great. Actually just one more question, in the Midland Basin you guys got some wells later for 2013, obviously the place and de-risk by Laredo and some other operators, how do we think about acceleration in 2013, right now you’re really spending within cash flow, if you have early success there, do we see an uptick in the number of wells you guys drill.

James T. McManus, II

I think that’s a possibility for sure.

Gabriele Sorbara – Caris and Company

Okay, great, thank you guys.

Operator

We have Timm Schneider on the line. Timm.

James T. McManus, II

Hi, Timm.

Timm Schneider – Citigroup Global Markets

Hi, so just one more quick follow-up, of the 26.5 million barrels you’re guiding to next year, how much of that are you allocating to the $130 million of exploration CapEx meaning coming from kind of the horizontal Wolfcamp in the Delaware and the Midland.

James T. McManus, II

Not much. How about that?

Timm Schneider – Citigroup Global Markets

So basically, so it would be fair to say that the majority of that 21% liquids growth is based on 745 million of Permian.

James T. McManus, II

I don’t have the numbers sitting right in front of me; I want to say it’s less than 200,000, right around 200,000. So you’re talking about 26.3 without the exploratory step. We’ve heavily risked it and hopefully there is upside there.

Timm Schneider – Citigroup Global Markets

Got it. All right, thank you.

Operator

(Operator Instructions)

James T. McManus, II

Erin, anymore questions.

Operator

There are no questions in the queue at this time.

James T. McManus, II

Okay, well, we appreciate your interest. Thank you for being with us here today and that will conclude our call. Thank you, Erin.

Operator

Thank you. This does conclude today’s teleconference. You may now disconnect.

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