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Executives

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

Julie S. Ryland – Vice President Investor Relations

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

Johnny Richardson – President & Chief Operating Officer

Analysts

Gabriele Sorbara – Caris & Company

Mario Barraza – Tuohy Brothers

Holly Stewart – Howard Weil Inc.

Tim Rezvan – Sterne Agee

Timm Schneider – Citigroup

Duane Grubert – Susquehanna Financial

Carl Kirst – BMO Capital Markets

Joseph Magner – Macquarie Research Equities

Energen Corporation (EGN) Q1 2012 Earnings Call April 25, 2012 3:00 PM ET

Operator

Good afternoon, my name is Melissa, and I will be your conference operator today. At this time, I would like to welcome everyone to the Energen first quarter 2012 earnings and operations conference call. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question-and-answer session. (Operator Instructions.)

I would now like to turn the call over to Julie Ryland, Vice President of Investor Relations. You may begin.

Julie S. Ryland

Thank you, Monaca and good afternoon. 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, 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 materially from those anticipated. Please refer to the company’s periodic reports filed with the Securities and Exchange Commission 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 T. McManus, II

Thanks, Julie, and good afternoon to all of you. There is a lot of news and a number of very positive developments to cover today. So I am going to jump in and talk first about our Permian Basin activities. In short, we remain very pleased with our Permian Basin operations, our vertical Wolfberry Wells in Midland Basin and our third Bone Spring Wells in the Delaware Basin continue to meet or exceed our expectations.

In the Delaware Basin, the performance of our third Bone Spring wells continues to improve as we focus operations in our core area in Ward, Winkler and Loving counties far east of the Pecos River.

In the first three months of 2012 we tested seven gross 3rd Bone Spring wells. Their initial stabilized rates ranged from 514 BOE per day with 61% oil to 1,737 BOE per day with 76% oil. The average rate was 1,004 BOE per day, of which 73% was oil. At 1,737 BOE per day this Ward County well is our top initial performer today. The well is tested on a 16/64" choke at a pressure of 4,400 PSI. Five of the seven wells we tested in the first quarter had sufficient production history to generate an average 30-day production rate of 783 BOE per day with 72% oil.

To better reflect the gross reserve potential of the 3rd Bone Spring wells to be drilled in this core area, east of the Pecos River over the next several years we have adjusted estimated average ultimate recovery to 475,000 BOE per well and we estimate the product mix to be 66% oil, 18% liquids and 16% dry gas.

We’d released a post-plant type curve and cumulative production curve for our 3rd Bone Spring wells scheduled to be drilled in 2012 through '14. You can see these curves on our website. The key takeaway, I believe, is about $100 oil and $4 of natural gas. We estimate these wells will generate an outstanding return of 72% before-tax rate.

We are adding four wells to our 3rd Bone Spring drilling schedule in 2012, four net wells. This brings the total number of wells to be drilled this year to be 47 gross or 43 net. In the first quarter we drilled 11 gross wells. Our rig count will continue at five to seven in Delaware Basin this year.

We also have lowered our target drilling complete costs for the 3rd Bone Spring wells for the remainder of 2012 to $6.9 million. We expect cost savings for the remainder of the year to come from continued stimulation optimization and a water recycling program.

On the east side of the Pecos River, we have approximately 30,000 net acres of which 17,300 undeveloped. Based on the likelihood of 160-acre spacing there we estimate that there are 92 potential locations remaining to be drilled.

Turning next to the Midland Basin, we have a play that is in full development generating solid results that meet our expectations. We plan to drill 177 gross or 170 net vertical Wolfberry wells this year. During the first quarter, we drilled 33 gross wells, 33 net and we plan to keep seven to eight rigs busy in the Midland Basin this year.

During the first quarter, we tested 51 gross, or 50 net Wolfberry wells. The initial stabilized rates of the wells averaged 88 BOE per day with 73% oil and averaged 30-day gross production rates were 73 BOE per day was 77% oil.

The performance of our vertical Wolfberry play today, it supports our estimated average EUR of 155,000 BOE per well. We estimate that the product mix is 61% oil, 23% liquids and 16% dry gas.

At $100 per barrel of oil and $4 per Mcf of natural gas, we estimate that our Wolfberry program over the next several years will generate a 33% before-tax rate of return. A post-plant type curve for wells scheduled to be drilled in 2012 to 2014 as well as a cumulative production curve is also available on the our website.

Our estimated cost to drill and complete a vertical Wolfberry well in 2012 is $2.3 million. The drill and complete cost reflects six to eight frac stages.

In total, we had approximately 49,000 net acres in the Midland Basin that are prospective for the Vertical Wolfberry play. Approximately 33,000 net acres remain undeveloped. Based on 40-acre spacing, we estimate that there are 825 potential locations remaining to be drilled. The potential for 20-acre spacing across our acreage position could add 675 potential drilling locations to that inventory.

As you know there is growing excitement about the horizontal Wolfcamp and Cline potential in the Midland Basin. We currently are participating as a non-operated partner with Laredo in the horizontal Wolfcamp well near our Glascot County acreage, actually we had 25% of it, so it’s in our Glascot County acreage, the early results are encouraging and we’re pleased to be getting some data points that will help us to better assess the potential on our acreage.

We also are closely monitoring Cline activity in the Midland Basin, obviously, a success of either this plays on our acreage could impact our future drilling plant in the Midland Basin.

Company’s 3P reserves are continuing to grow. At year end 2011 our proved probable and possible reserves totaled a record 941 million BOE, proved reserves stand at 343 million BOE, probable at 182 and possible at 416.

Some 20 MMBOE of probable and possible reserve additions represent 160 acre spacing in our current 3rd Bone Spring program area. Not included in our 598 MMBOE of unproved reserves is any potential for our Wolfberry down spacing the 20 acres and a horizontal Wolf Camp Cline or Avalon potential.

Turning next to guidance, we are raising our estimated range for 2012 after-tax cash flows to $795 million to $824 million on a consolidated basis and $694 million to $723 million at energy and resources. The increase from prior guidance is do in large part to a 6% increase in estimated oil production, partially offset by lower realized commodity prices. The main factor driving us towards potentially lower realized oil prices is a wider Midland to Cushing differential. This differential has grown since the end of 2011 from less than $1 a barrel to as much as $9 a barrel for a brief period in April.

Our sweet oil and unhedged sour oil production, which is about 65% of our estimated oil production for the remainder of 2012 is exposed to this differential. However, as additional pipeline capacity is added this year and 2013, we believe the differential will move closer to its historic price.

We do expect oil production in 2012 to increase from our prior guidance of 8.5 million BOE to 9 million BOE. This increase comes on the strength of our 3rd Bone Spring volumes and existing production from the February Wolfberry acquisition. Partially offsetting these items is the expected decrease in natural gas production resulting from capital spending cuts in the San Juan Basin.

Speaking of capital, we are increasing our estimated capital investments in the drilling and completion of our existing properties from $890 million to $950 million. The $60 million increase primarily is related to four additional 3rd Bone Spring wells we are adding to our 2012 plans as well as to acquisition-related development in the Midland Basin and modest increases in non-operated Permian properties.

A table of our news release details our new production and capital guidance by play. You will also find, in our release, estimates of our 2012 operating expenses, details of our hedge position for the remainder of the year, and the sensitivity of our after-tax cash flows to changes in commodity prices.

I would note that approximately 60% of our estimated production for 2012 is hedged. Assumed prices for unhedged oil and natural gas volumes for the remainder of the year are $95 a barrel and $3 per Mcf. Our assumed price for unhedged liquids is $1.06 per gallon.

At this time I’d like to turn the call over to Chuck Porter, our Chief Financial Officer to review the first quarter financial results. Chuck?

Charles W. Porter, Jr.

Thank you, James. A 40% increase in oil and liquids production and a 12% increased in the realized price of oil were major contributors to our adjusted net income of $96.1 million, or $1.33 per diluted share. Prior year first quarter results were $94.3 million or $1.30 per diluted share.

Our GAAP net income in the first quarter of 2012 was $57.4 million or $0.79 per diluted share and included a couple of non-cash items specifically after tax mark-to-market hedge losses of $25.3 million or $0.35 per diluted share and an after tax write-down of natural gas property in East Texas totaling $13.4 million or $0.19 per diluted share.

This write down was the result of today’s very low natural gas price environment and limited prospects of a speedy turnaround. Consolidated adjusted EBITDA totaled $262.8 million when compared with $222.1 million in the prior-year first quarter. Energen Resources adjusted EBITDA was $173.3 million in the first quarter of 2012, up 27% from the same period a year ago.

Excluding the non-cash items, Energen Resources adjusted first quarter net income totaled $48.2 million in 2012 as compared with $49.7 million in 2011. While Energen Resources production increased 22% year-over-year, including a 43% increase in oil production and a 32% increase in liquids production, net income was negatively affected by 29% decline in realized natural gas prices, higher LOE, increased DD&A expense and increased interest expense.

For units, LOE in the first quarter of 2012 decreased approximately 2% from the same period last year to $12.30 per BOE with based LOE, marketing and transportation expenses decreasing about 1% to $9.84 per BOE. Commodity price-driven production taxes declined approximately 5% on a per unit basis.

DD&A expense per unit increased approximately 35% from the same period last year to $14.44 per BOE. And this increase generally reflects the year-over-year increases in development cost and increased production. Additional details on first quarter average realized prices and production are detailed in our news release.

Before I wrap up my comments, I would note that our natural gas utility generated first quarter net income of $46.9 million in 2012. This slight increase from $44.2 million in the first quarter of the 2011, primarily due to the utility’s ability to earn on a higher level of equity partially offset by the timing of rate recovery.

And that as a brief look at the first quarter and so at this time, I’ll turn the call back over to James.

James T. McManus, II

Thank you, Chuck. Obviously, we are excited about the results that we had to share with you here today. And now I would like to move into a Q&A. To facilitate this, I will turn the over to Melissa for instructions. Melissa?

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Gabriele Sorbara from Caris & Company. Your line is now open.

Gabriele Sorbara – Caris & Company

Good afternoon, guys. Great quarter and I think we all appreciate to add a disclosure. On the 3rd Bone Spring well, the one that [IP'ed] over 1,700 barrels in Ward County. Can you talk about what led to the outperformance, was it location? Did you guys do something different with the completion or target a different sand, any color would be appreciated?

James T. McManus, II

Yeah, I’m going to let Johnny talk about that, Gabriele I will add this we tested that one on the tighter choke than most people test them on and have 440 accounts pressure on them, so there is no telling what amount of test that have we opened up too. So Johnny do you want to speak to that question for a minute?

Johnny Richardson

Gabriele we continue to work on our completions. We continue to adjust our clusters, our size fracas, but, frankly, all the wells in this area is very good area. So I think geography and geology have a lot to do with, it is just where it is but we like the east side a lot but this is probably our, we are going to have a hard time find an area better than where this well is located.

Gabriele Sorbara – Caris & Company

Okay, great. And some operators have talked about 800 plus 1,000 barrel type well, can you again talk about that you offer on this well?

Johnny Richardson

Well I don’t have the EUR right in hand on this well. Of course it vary beyond that I think you could look at our type curve and know it will be above that range. So it will be one of those slow the average to where we sort of put it, it is going to be a higher in performer.

Gabriele Sorbara – Caris & Company

Okay. What would your range be in terms of EURs throughout the east side?

Johnny Richardson

I frankly do not recall the scatter of points. But we are using a pretty large database of that. So I just don’t recall.

Gabriele Sorbara – Caris & Company

Okay.

James T. McManus, II

And again we will obviously exchange what we’ve done is based on all the data that we’ve gathered on that particular side, we’re very comfortable with the average EUR type curve of 475 and obviously this one is going to perform above that level and some perform below that level but I don’t remember the tightness of the scatter either.

Gabriele Sorbara – Caris & Company

Okay and you guys booked $45 million barrels here in the first quarter, do you have the production mix there and the development costs associated with that?

James T. McManus, II

May need you to repeat the question Gabriele, I’m sorry you broke up in the middle, your first quarter production, we have the production….

Gabriele Sorbara – Caris & Company

The 45 million barrels you guys are really above, you guys very classified, potential reserves as approved. Do you have the production mix there or the proved reserved mix?

Julie S. Ryland

The 45 (inaudible) possible and approved not readily available and we can probably get that up 40 Gabriele.

Gabriele Sorbara – Caris & Company

Okay, thanks. And just a last question, you guys have some legacy acreage in Mitchell, Harvard county just curious how much of acreage you guys have there and it looks like just looking at some wells you guys drilled in the past, you only drilled through the Cline, can you talk about what you thought while drilling through the Cline any thoughts on prospectivity of horizontal development

Johnny Richardson

We do have a some like you said there, I don’t have that acreage position right in front of me. We only have a few deep tests that is a shallower water flood and we are going to had to check into what we own there deeper, we go to few injection wells, we’ve seen that section – we are studying a section now. But I don’t have really any really insights on that Gabriele.

Gabriele Sorbara – Caris & Company

Okay, Thanks guys. I will jump back in queue.

James T. McManus, II

Thank you.

Operator

Your next question comes from the line of Mario Barraza from Tuohy Brothers. Your line is now open

Mario Barraza – Tuohy Brothers

Hey, guys. Good afternoon.

James T. McManus, II

Afternoon.

Mario Barraza – Tuohy Brothers

Just want to follow-up on the Bone Spring wells’ cost coming down from a $7.5 million to $6.9 million. I see that happening, but the basement CapEx budget from the original that you provided at the end of the third quarter is going up $75 million. So if I had those four Bone Spring wells, I only get $28 million. What’s the different there?

James T. McManus, II

Yeah, I’m going to let Chuck detail that for you. We’ve got a breakdown of the capital increase. Part of it’s going to be acquisition that we did and, well, Chuck, you go ahead.

Charles W. Porter, Jr.

Well, we have a $25 million. We are calling about $24 million on the four Bone Spring wells. We also had about $10 million worth of additional facilities cost, predominantly saltwater disposal well. And then there was another, roughly $17 million of other non-operated capital that was scattered in both in the Delaware Basin and in some Central Basin water flood that was not originally budgeted.

Mario Barraza – Tuohy Brothers

Okay. And then, thanks for the updated type curve. So what’s the new initialized stable rate that you guys are going to be using in that? You guys have been providing that and in the last presentation, what you had was 338 barrels a day. I mean, what’s the new number we should think about using there going forward?

Julie S. Ryland

Mario, this is Julie. We hope to be able to move more towards a 30-day average rate as we are getting increasing amounts of data.

James T. McManus, II

Yeah, I think the problem is that everybody is disclosing those rates on different chokes, just what we pointed out. Ours was a 16/64" choke on sort of our record well and a lot of more open shows. And so, I think we are going to move a little bit more to the 30-day rate, but we are still disclosed some of that information as well. Johnny?

Johnny Richardson

Yes, James, that’s what we’ve got. I think that’s more meaningful piece of data.

Mario Barraza – Tuohy Brothers

Okay. I think that’s all I had right now, hop back in the queue.

Johnny Richardson

Okay, thanks.

Operator

Your next question comes from the line of Holly Stewart from Howard Weil. Your line is now open.

Holly Stewart – Howard Weil Inc.

Good evening, gentlemen, Julie or afternoon gentlemen I guess.

James T. McManus, II

Hello.

Holly Stewart – Howard Weil Inc.

Hello. A couple of questions, first on the Wolfcamp and the Delaware Basin, I know you’ve talked about potentially doing a – starting compressing in the first half of the year any update there?

James T. McManus, II

Yeah, now you’re talking Delaware or you’re talking Midland Basin.

Holly Stewart – Howard Weil Inc.

I’m talking Delaware.

James T. McManus, II

Delaware. We probably will do our horizontal Wolfcamp completion on the east side in the first half of this year, absolutely.

Holly Stewart – Howard Weil Inc.

Okay. So no change really.

James T. McManus, II

No change.

Holly Stewart – Howard Weil Inc.

Second, any updates to the progress on the west of the Pecos, I know you’re talking about drilling a handful disposal wells?

James T. McManus, II

Well, we’ve got disposal wells. We’ve got three wells on pump Holly, but we’ve not seen as of yet any meaningful change in the productive characteristics of those wells.

Holly Stewart – Howard Weil Inc.

Okay. Okay. And then I have to ask regarding the potential joint venture you’re participating in three wells with BHP right now, any update on the progress there?

James T. McManus, II

No, nothing there.

Holly Stewart – Howard Weil Inc.

Okay. And then finally one last, one, gas production continues, I think to do certainly better than we’ve been modeling. I know you’ve got some associated gas related both in the Permian and the San Juan. How should we think about when the gas volumes starts to decline or when should we think about gas volume really starting to decline?

James T. McManus, II

Yeah, you're going to have a better feel for this when we put our 2013 numbers out, but so far what we've looked at is if we do not invest any capital in 2013 in the San Juan basin, we would expect about 0.7 MMBOE drop, 700,000 barrels of oil equivalent drop in gas production in 2013 and from then on it's close to like a 10% decline.

Holly Stewart – Howard Weil Inc.

Okay, so kind of your normal overall natural decline for the company. Okay, perfect, thanks, guys.

James T. McManus, II

Yeah, okay.

Operator

Your next question comes from the line of Tim Rezvan from Sterne Agee. Your line is now open.

Tim Rezvan – Sterne Agee

Good morning folks just had a couple of follow-ups. You disclosed your partner on the horizontal Wolfcamp on the Midland Basin. You had not disclosed that before. Can we expect to hear something on the well soon from them, do you have any insight on that?

James T. McManus, II

Tim, I am going to something right now, I’ve been waiting on this questions. So, Johnny Richardson is going to tell you. It has been tuned up. It has been on for a while, it's been pretty steady. So we feel comfortable giving you some rates on that, Johnny?

Johnny Richardson

Hi, Tim, yes, had to come in Loredo, I think they did a very nice job on this well; it’s a 4,000 foot lateral upper Wolfcamp well in Glasscock County. The well, as James as alluded as since it’s been tuned up, it’s been about 17 days and that's pretty early to talk about the well but this well was been so consistent, don't mind doing it. Its production is a little over 560 barrels of oil a day with another 800 Mcf, very nice stable rates, less than 20% water recovery or frac recovery so far. So very strong the water is tailing off, so don’t mind talking about this well, it looks like a very good job at Loredo and I think it bodes well for the area there and it is contiguous to our acreage, in fact we 25% or 20% owner of this well.

Tim Rezvan – Sterne Agee

Okay, I appreciate the color. And then, how flexible I guess is the rest of 2012 spending to may be capitalize, and so if you think it’s an opportunity you want to pursue? I guess you have plan in place or is it kind of pending the joint venture decision?

James T. McManus, II

Well, Tim we’ve got, this is obviously as you pointed out, this is Midland Basin and we’ve got a program in place where we are drilling 170 net Wolfberry wells and we are just going to have to watch and see right now we are not planning on changing anything in 2012, I mean, all the acreage we’ve got is going to be held by production. So it’s just an opportunity out there that we can capitalize when we want to. But no change in course right now.

Tim Rezvan – Sterne Agee

Okay, okay, thanks. I guess we will stay tuned on that. And then changing gears a bit on that one, I may have missed it earlier in projects, but DD&A picks up in the first quarter. Give us kind of insight on how we can see that play out rest of the year?

James T. McManus, II

Well, we gave you a DD&A rate estimates for the whole year, that’s how we see it truly that is pulling that number. Our DD&A was expected to trend up as we’ve got legacy gas prices or gas DD&A rate and as we are drilling higher F&D on the oil side, we were anticipating those to go up.

Johnny Richardson

Yeah, we were estimating the 2012 DD&A to be $16 a unit?

Tim Rezvan – Sterne Agee

Okay. Yes, it came in below I guess in the – okay, okay we can talk offline then, I don’t want to get into that here, and then one last one. Is there anymore down spacing potential on the 3rd Bone Springs net of 160 acre spacing, is that kind of the...?

James T. McManus, II

Yeah, we think we’ve got it optimized now it we go to 160s on the east side. So the question is how much potential there will be in 3rd Bone Springs on the western side. So I think, Johnny, we’ve got to categorize properly on the east. I don’t think right now we are thinking that 80s are going to be possible, but…

Johnny Richardson

We don’t see it. We’ve got a good deal of history and we are very comfortable looking at all the parameters at 160. I wouldn’t anticipate that, let me say, until we get a lot more results in on the 160, but I just don’t anticipate it going lower than that right now.

Tim Rezvan – Sterne Agee

Okay. Thanks for the color, guys.

James T. McManus, II

Thank you.

Operator

Your next question comes from the line of Timm Schneider from Citigroup. Your line is now open.

Timm Schneider – Citigroup

Hey, guys. How is it going?

James T. McManus, II

Hi, Tim.

Timm Schneider – Citigroup

I have a quick question. First of all, the down spacing on the Wolfberry. I know you’ve identified 675 locations in today’s press release. In the past it was closer to 550. I was just wondering if there’s any more signs that you guys have now that let you to up that to 675 or just more acreage that you think is perspective for that and also what the timing in that would be?

James T. McManus, II

The latter, it’s more acreage perspective. We’re [down] a little bit more looking over our broad swap of acreage and before we had just included Glascot and Regan County, now we believe there are areas outside that would be potential for 20 acre down spacing. And of course, again we got that any time we want it. Now we’ll say this. You’re probably not going to do 20 acre down spacing in the Wolfberry and horizontal Wolfcamp and Cline. So we’ll be studying which approach is better economically before we decide how to go. They are not incremental opportunities. Probably it’s one or the other and we don’t have to make that decision any time soon. Go ahead.

Timm Schneider – Citigroup

Got it. And then, quick question, if I look at the west side of the Pecos, irrespective of the joint-venture, are you guys thinking about drilling a horizontal Wolfcamp there on your own or…?

James T. McManus, II

Well, I think what we’re going to want to do right now Tim is see what kind results we get from the wells that are underway before make that decision. So right now, we don't have plan to, even that could change.

Timm Schneider – Citigroup

Okay, I just want to understand the timing parameters of this. So it’s kind of May 1, is that the set deadline is that set deadline come for BHP to come back to you guys or couple of days legal room or how does that work?

James T. McManus, II

They have the opportunity to exercise that option up until May 1.

Timm Schneider – Citigroup

Okay, what happens if they don’t? Is that just done with?

James T. McManus, II

If they didn’t, then they have carried us in three wells for $30 million and we own the all the acreage.

Timm Schneider – Citigroup

Okay, got it. Last question is if you have it available, what your current production is in 3rd Bone Spring?

James T. McManus, II

Well I’m going to see if we have it. I don’t know. We've got it estimated for the year Timm at 3 million barrels of oil-equivalent. That’s our 3rd Bone Spring, estimated production for 2012, does that help?

Timm Schneider – Citigroup

Yeah, so that works. Okay, that’s it from me. Thank you.

James T. McManus, II

Thank you, Tim.

Operator

Your next question comes from the line of Duane Grubert from Susquehanna Financial. Your line is now open.

Duane Grubert – Susquehanna Financial

Yeah, guys. If we think about the infrastructure challenges in certain places being real, and in other places not really being a problem at all. Can you walk us through a little a little bit about what worries you, if everything was to be successful on the stuff that you are starting on now and maybe some of the JV stuff? What are the infrastructure gaps that we would expect you guys to focus on whether it’s power or water disposal of...

James T. McManus, II

Yeah, we are doing obviously power something. We got a plan for you. We obviously we got a power, have power out of these wells. You got to have water disposable, but that’s ordinary course of business for us. You got it arranged for all it to be trucked I think you get the pipelines hooked up. We’re not anticipating infrastructure problems in the Midland Basin at this point in time.

So let’s put that in one box. On the eastern side of the Delaware Basin we feel confident that there is infrastructure out there, not that you don’t have to work hard to get the things done and get things moved, whether it’s the least developed infrastructure, and we talked about it consistently is the far west side of the Delaware Basin. So that would be more and where there need to be a lot of work done to bring anything to market.

Duane Grubert – Susquehanna Financial

And really it’s kind of everything. It’s not specific to one element of the midstream change?

James T. McManus, II

Right.

Duane Grubert – Susquehanna Financial

Okay. Thank you very much.

James T. McManus, II

Thank you.

Operator

Your next question comes from the line of Carl Kirst from BMO Capital. Your line is now open.

Carl Kirst – BMO Capital Markets

Thanks, good afternoon, everybody. Actually just a couple of follow-up questions on the Bone Spring, and I apologize that this has already been asked, but when would we be going down to 160 acre drilling in Ernest, would that be something that would be more of a 2013 event or would we be doing that in 2012 as well?

Johnny Richardson

The way the geography is, we’ve already seen some of those wells being drilled, and we will see more just because if some of the way these sections are very long and narrow and in affect, we’re already seeing some of that spacing now. But over the next, we will – as far as drilling in a regular 640 down spacing there would probably be a ‘13 type event will continue on with our major program and then come back and in fill in ‘12.

James T. McManus, II

Carl, as Johnny suggested that we've got better almost 160 is now, which is why we feel comfortable with going forward with this program.

Carl Kirst – BMO Capital Markets

No, that is fair. I appreciate the color there. And then actually just a question on the reduction in the drilling and completion, which is always great to see. Just to make sure kind of understanding this, I think in times past you guys have said is you would ramp up. We would likely see something below $7.5 million, and I didn't know if that had to do with kind of more sort of becoming a manufacturing process if you will.

And so what we're seeing right now, the $6.9 million is that the fruits of that or is that more because you perhaps done some optimization where perhaps you didn’t expect, which means that as you continue to ramp up the $6.9 million can drop even further. And I just wanted to make sure, I had the right feel for that.

James T. McManus, II

Carl, I think is the biggest drop in the drilling comps that we experienced was due to lowering the number of days drilling. And we continue to work on that but are largely optimized. Now the work was on water cost using recycled water that saves money, and optimization on the completion side ranging from how many fracs to what type of profits that we’re using to get an effective frac. So it would not surprise me absent other cost increases that might pressure up, if we are able to continue to optimize the wells we have no idea how far down we can take that. We just know right now we feel comfortable with $6.9 million.

Carl Kirst – BMO Capital Markets

Great, and the days drilling is that still at roughly 40?

Johnny Richardson

We are there more consistently and even being at on occasion now. So yes, I mean but also I think we’re seeing that, the lower side of that cycle more and more and really 40 is a pretty good number. It ranges 40 in a few days either side. So we’re right there.

Carl Kirst – BMO Capital Markets

Perfect, you know that‘s…

James T. McManus, II

So Carl, this has got a lot more to do with how we complete the wells and water.

Carl Kirst – BMO Capital Markets

Perfect, okay that’s perfect color. Can I ask just a micro question and this is just to make sure I’ve got an understanding of it In looking at the financials, I just had a question on the oil price realization and looking at the number that was given for, the oil revenue unit prior to hedging impacts it was $77, kind of much lower than the 100-ish of oil and that seems to be of a big departure from quarters past and I didn’t know what was influencing that or we can take it off-line that…

James T. McManus, II

We’re looking

Charles W. Porter, Jr.

Let me address that conceptually, I’m not sure I can place my hands on the $77 number right now but at least let me – I can’t address that conceptually. Obviously the NYMEX price was up and we would have picked up some of that price on the unhedged volumes but as we mentioned in the release our estimate have the suite to suite differential from Midland to Cushing was a good bit wider than what we had anticipated.

We got a budget somewhere in the $0.55 to $0.66 range for the first quarter. It ended up averaging closer to a $1.50. So we had that as an impact on the realization. The other thing that you may not have, and your model may not be aware of is something called ineffectiveness related to any kind of hedges that are qualified for hedge accounting treatment.

We have to recognize ineffectiveness and so that basically represent, say in this case for the quarter. The fact that sweet differential widens. So we recorded roughly $3 million plus or minus after tax for the quarter, which formally impacted the realization about $1.50 per barrel that you may not be seeing, I don’t know whether that’s helpful to you, but that’s what we’re seeing.

Carl Kirst – BMO Capital Markets

I appreciate the help. I can follow-up with Julie, no worries.

James T. McManus, II

Thanks Carl.

Operator

(Operator Instructions) Your next question comes from the line of Joe Magner from Macquarie. Your line is now open.

Joseph Magner – Macquarie Research Equities

Good afternoon. I just wanted to follow up on the last question. It seems like there is more than $1 to $3 of variance in the realized prices. There are three different prices presented in the press release, but didn’t look like the definition is very clear about hedge effectiveness or not including or including the impact of derivative transactions that seems like the unrealized mark-to-market number of $40.5 million, which is added back to your adjusted income is captured in those one of those price cases. Just curious if there is a way to break it out?

James T. McManus, II

Well, I’m not sure I follow that that question.

Joseph Magner – Macquarie Research Equities

But there is an adjustment you made in the income little over $40 million for unrealized impact of mark-to-market hedge accounting, and I think it’s being captured in some form of fashion one of those oil for, I guess the combination of all your prices for oil gas and NGLs but it’s not clear which is capturing may be it’s better offline, but it seems like there is some confusion between this quarter and past quarters on the underlying prices that we should be using?

James T. McManus, II

Yeah, the $63.65 per barrel item would be with all of the hedges and then without the mark-to-market hedges, they are not related to this period that’s the $85.12, the number that is not as Carl mentioned is not making a lot of sense right now is the $77.12 and we will probably be best served to check that out and then duly follow up offline on that.

Joseph Magner – Macquarie Research Equities

And one other I guess micro question on deferred taxes, is there a way to get a breakout of what the deferred taxes were during the quarter?

James T. McManus, II

Well in the cash flow statement that will be published I think we had a deferred tax add back around when we click here real quick it should be about $23 million and most part of that is going to be driven by IDC and bonus depreciation at Energen Resources.

Joseph Magner – Macquarie Research Equities

Fair enough. Okay. One more to follow-up on oil price question later, thanks.

James T. McManus, II

Well let me mention to you that if you want to get a hand along where we think deferred income taxes are going to be for the year, you can see that in this non-GAAP reconciliation going from, to reconcile after tax cash flow so at least to give you a feel for where we think right now it will be for the year.

Joseph Magner – Macquarie Research Equities

Yeah, we saw where, it looks like you think it’s going to be for the year but it wasn’t clear how to get to the amount for the first quarter.

James T. McManus, II

Okay.

Joseph Magner – Macquarie Research Equities

Thank you.

James T. McManus, II

Thank you.

Operator

There are no further questions at this time. I would now turn the call over to James McManus for conclusion or any comments.

James T. McManus, II

Okay, thank you Melissa. Thank you all for joining us today. We covered a lot of ground, obviously excited about the results we’ve got to share with you that we got to share with you and that concludes this conference call. Thank you.

Operator

Thank you ladies and gentlemen, that concludes today’s conference call. You may now disconnect.

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