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Executives

Julie Ryland – VP, IR

James McManus – Chairman & CEO

Chuck Porter – VP, CFO and Treasurer

John Richardson – President and COO, Energen Resources Corporation

Analysts

Gabriele Sorbara – Caris & Company

Becca Followill – U.S. Capital

Tim Schneider – Citigroup

Duane Grubert – Susquehanna Financial

Greg Share [ph] – Tree Brothers [ph]

Energen Corporation (EGN) Q3 2011 Earnings Conference Call October 27, 2011 11:00 AM ET

Operator

Good morning. My name is Andrea, and I will be your conference operator today. At this time, I would like to welcome everyone to the Energen’s third quarter earnings 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) Thank you. I would now like to turn the call over to Julie Ryland, Vice President of Investor Relations. You may begin your conference.

Julie Ryland

Thank you, Andrea. 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 ended September 30th, 2011. 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 with some uncertainties that may be outside the company’s control and could cause actual results to differ materially from those anticipated. Please refer to the company’s periodic reports filed with the SEC for a more complete discussion of the risks and uncertainties that could affect the future results of Energen and its subsidiaries.

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

James McManus

Thanks Julie and good morning to you all. The dominant takeaway from yesterday’s quarterly news release is really this

We are delivering on our strategic shift to oil and natural gas liquid production. We made this shift in 2009 to capitalize on the superior value provided by oil and natural gas prices relative to natural gas.

Beginning with the acquisition of Range Resources Fuhrman-Mascho interest in 2009 and including the two Wolfberry acquisitions we announced yesterday and plan to close by year-end, we have invested almost 800 million to acquire largely undeveloped assets in the Permian Basin. We have been drilling and developing our liquids-rich assets for almost two years and now the results are very positive, with oil and natural gas liquids production jumping 30% year-over-year in the just completed third quarter.

In 2012, we not only plan to invest approximately $680 million in the Wolfberry play and in the 3rd Bone Spring and other Delaware Basin trends, and we estimate that, that oil and natural gas production will rise 33% from 2011 levels. By the end of 2013, given our current outlook for capital investment, we expect to realize an 86% to 100% rise in our oil and liquids production from 2010 levels. The Wolfberry play is currently moved to the development stage, much of our planned capital investment in 2012 is going into the Wolfberry and this play is a major driver of our estimated production growth in 2012.

Moving up the learning curve, with respect to drilling in the 3rd Bone Spring sands division, the geologically complex Delaware Basin offers us Avalon shale, Wolfcamp shale horizontally and vertical Wolfbone opportunities. In 2012, we are looking to the Delaware Basin to contribute almost 10% of the company’s total estimated production.

And really like our Wolfberry play in the Midland Basin, and as we said, we will be open to other opportunities there, and are pleased to be adding to our assets. We signed a purchase and sale agreement to buy two Wolfberry packages from private sellers for a total of 212 million plus standard closing adjustments. The properties are in Martin, Howard and Glasscock Counties. Associated 3P reserves total 25.4 million barrel of oil equivalent. The two packages include 31 producing wells at an estimated 194 undeveloped drill locations. We expect the acquisitions to close by the end of the year. They will not have a material impact on 2011 production.

During the first nine months of 2011, we drilled 123 net Wolfberry wells and 84 wells are producing and 39 are waiting on completion. We plan to drill another 40 net wells by year-end, bringing our 2011 total to 163 net wells. 30 Wolfberry wells were brought online during the third quarter at IP rates averaging 63 barrels of oil a day and 170 Mcf per day of wet gas. Our risk IP rate is 55 barrels of oil per day and 110 Mcf per day of wet gas.

Including the new acquisitions, we now have some 32,000 net undeveloped acres in the Wolfberry play giving us 800 potential drilling locations based on 40-acre spacing. Our estimated cost to drill and complete a Wolfberry well is 2.2 million.

Moving next to the Delaware Basin, we have completed 13 net wells in the 3rd Bone Spring sands during the first nine months of 2011. A 14th wells is testing and another is waiting on completion. We expect to drill 12 more net wells by year-end, bringing the total number to 25 net wells in 2011.

We have brought four wells online during the third quarter of 2011 at initial stabilized rates of approximately 525 barrels of oil per day and 1.285 Mcf per day of wet gas. These rates reflect consistent flow after the cleanout of stimulation fluid. The initial stabilized rate for all 14 net wells brought online in the first nine months of the year averaged approximately 360 barrels of oil per day and 1,000 Mcf per day of wet gas. Our risked, weighted average, 3rd Bone Spring model initial stabilized rate is 260 barrels of oil per day and 735 Mcf per day of wet gas.

We have approximately 72,000 net undeveloped acres that are prospective for the 3rd Bone Spring sands and approximately 225 potential drilling locations based on 320-acre spacing. Our estimated cost to drill and complete a well in the 3rd Bone Spring for 2012 is $7.3 million.

With respect to Avalon shale, we drilled and completed two Avalon shale wells during the third quarter of 2011. High water production from the well drilled and completed in Reeves County to test the western edge of our acreage position rendered the well non-economic. The second well we drilled is in Loving County, in an area with existing Avalon production, and is in the early stages of flow-back. We plan to spud two vertical test wells in the far Eastern section of our acreage by year-end to look at the total stratigraphic section that includes the Avalon shale, Bone Spring and Wolfcamp intervals.

We have approximately 110,000 net undeveloped acres that are prospective for the Avalon shale and approximately 340 potential drilling locations based on 320-acre spacing. The company's estimated cost to drill and complete a well in the Avalon shale, since we are in the testing phase, is listed at $6.1 million. We would expect outside the testing phase, these wells would be much closer to the $5.5 million that we talked about earlier, but because we are going to perform additional science and testing on these wells, we estimate their cost to be higher.

In addition to these three plays, we are monitoring Wolfcamp and Wolfbone activity in and around our acreage positions and believe these plays offer Energen additional drilling potential.

We now have completed our preliminary 2012 budget. Our current production and capital outlook are materially different from our preliminary numbers we provided last quarter. In Energen Resources, in 2012, we plan to invest approximately $900 million of capital drill and complete our assets in the Permian and San Juan Basins. The bulk of this planned capital investment approximately $820 million targets the Permian Basin. Natural gas prices are low and we expect them to remain low for the foreseeable future. As a result, we plan to invest only $80 million in 2012 in those areas that are predominantly natural gas. In fact, all of $80 million is going to the San Juan Basin. This level of capital is expected to keep San Juan production essentially flat in 2012.

We plan to run seven to eight rigs in the Midland Basin to drill approximately 170 net wells in the Wolfberry play. We are now looking at running five to seven rigs in 2012 to drill 39 net wells in the Delaware Basin. This decrease in rigs and increase in net wells largely reflects efficiencies we have gained by reducing the number of days to drill in the 3rd Bone Spring.

In the Central Basin Platform, including the North Westbrook Unit and the Fuhrman-Mascho field, we expect to run one to two rigs to drill 86 net producers and 33 net injectors wells. We estimate that our 2012 production will increase 17% to 24 million barrel of oil equivalent, Permian Basin production is expected to increase some 44% to 11.2 million BOE, with our Wolfberry production more than doubling to 4.1 million BOE.

In yesterday’s release, we initiated guidance ranges for consolidated after-tax cash flows and earnings in 2012. These ranges are $769 million to $798 million and $3.40 to $3.80 per diluted share respectively. Our guidance excludes unrealized non-cash mark-to-market impacts. Approximately 59% of the company’s total 2012 estimated production is hedged, including 74% of our estimated oil production at an average NYMEX equivalent price of $86.93, and 37% of our estimated NGL production at $0.88 per gallon.

Equally important is that 53% of our estimated natural gas production is hedged at just under $5 per Mcf on a NYMEX equivalent basis. Details of our 2012 hedge position are included in our release and I encourage you to review that data. We have assumed prices applicable to our unhedged volumes at $85 per barrel for oil, $1.11 per gallon for NGLs, and $4 per Mcf of natural gas. The net income impact changes in commodity prices also are detailed in our news release.

Our estimated exploration and production expenses per BOE in 2012 include LOE including production taxes of $12.01 and DD&A expense of $14.64. We also assume some level of dry hole expense, about $1 per barrel of oil equivalent in 2012 and hope that it doesn’t materialize. Everything else being equal, less dry hole expense will possibly impact net income, please refer to our release for additional expense estimates.

In 2012, our natural gas utility continues to have the opportunity to earn and return on average equity between 13.15% and 13.65%. We estimate that the utility’s average equity in 2012 will be approximately 360 million. Capital investment at the utility in 2012 is estimated to be some 75 million. This covers normal distribution and support system needs of about 65 million and another 10 million or so of technology related and other projects designed to improve customer service.

Just a few moments here about 2013. Energen Resources’ preliminary capital plans in 2013 are $885 million and production of 25 million to 27 million BOE. We plan to invest more than 85% of that capital again in 2014 in the Permian Basin. Our 2013 Permian plans currently include running seven to eight rigs, drill approximately 170 net wells in the Wolfberry play, and five rigs to drill 31 net wells in the Delaware Basin. We expect to run one to two rigs to drill 49 net producers and 34 net injectors in the Central Basin platform. Based on these preliminary capital drilling plans, we estimate that 2013 oil and natural gas production could range from 13 million to 14 million BOE. These levels represent a three-year compound growth rate of 23% to 26% a year.

At this time, I would like to turn the call over to Chuck Porter, our Chief Financial Officer to briefly review the results of the third quarter and our outlook for the current calendar year 2011 as a whole. Chuck?

Chuck Porter

Thank you, James. Energen’s third quarter net income and 2011 and 2010 included some non-cash items. In the 2011 period, oil prices moved away from us generating a non-cash mark-to-market gain on some of our hedge instruments that totaled $53.2 million pre-tax, or $33.1 million after-tax. Net income in the prior-year third quarter included a non-cash write-off of unproved capitalized leasehold of $14.6 million after-tax.

Adjusting for these non-cash items in both periods, net income totaled $54.5 million, or $0.75 per diluted share, in the third quarter of 2011 and $52.9 million, or $0.73 per diluted share in the same period a year ago. The dominant drivers are earnings growth in the current year third quarter of a 30% increase in oil and natural gas liquids production coupled with a 13.7% increase in realized oil and natural gas liquids prices. Consolidated net cash provided by operating activities before changes in operating assets and liabilities totaled $530 million at September 30th, 2011 and compared with $547 million in the first nine months of 2010.

Energen Resources adjusted net income totaled $63.7 million in the third quarter of 2011 and compared with $60.9 million in the same period last year. Third quarter 2011 production totaled 5.25 million BOE in 2011, which was up 11.4% from the same period last year. Our Permian Basin production totaled 2.1 million BOE or an increase of 40%. This was due mainly to our 2010 acquisitions and associated development. San Juan Basin production was essentially unchanged at 2.4 million BOE and slight production declines in our other areas underscore our Permian focus as well as normal declines.

Total LOE per unit in the third quarter of 2011 increased approximately 7% from the same period a year ago to $13.12 per BOE. Base LOE and marketing and transportation expenses increased about 3% to $10.39 per BOE, primarily due to increased repairs and maintenance, while commodity price-driven production taxes rose 23% on a per-unit basis.

DD&A expense per unit in the third quarter of 2011 was $11.78 per BOE. This 10% increase from the same period last year reflected year-over-year increases in development costs and production. Per-unit net G&A expense fell approximately 2% in the current-year third quarter to $2.54 per BOE.

Relative to our utility operations, Alagasco generated a net loss of $9.1 million in the third quarter of 2011 as compared with a net loss of $7.1 million in the same period last year. September 30th also marked the end of the utilities rate year. Alagasco’s earned return on average equity totaled 13.3% and of course fell within its allowed range of return of 13.15% to 13.65%.

With only a couple of months remaining in the current year, we have narrowed our guidance ranges for after-tax cash flows and earnings to $697 million to $712 million and $3.70 to $3.90 per diluted share, respectively. This guidance is based on strip prices for the remainder of the year that are lower than our previously assumed prices. Our guidance also excludes unrealized, non-cash, mark-to-market impacts.

We have a solid hedge position in place for the remainder of 2011 that significantly limits our sensitivity to changes in commodity prices for the rest of the year. Energen Resources' capital investment in 2011 is estimated to total approximately $1.1 billion. The variance from the prior estimate of $875 million largely is due to the Wolfberry acquisitions we plan to close by year-end and approximately $38 million for additional Permian Basin drilling and other projects.

Energen Resources’ full-year expenses per BOE are estimated to be $12.63 for LOE and production taxes, $11.79 for DD&A, $0.75 for unidentified exploration expense in the fourth quarter, and $3.03 for net G&A, and $1.47 for interest expense.

Our year-to-date financial results are detailed in our news release from yesterday, and I will encourage you to review that information. And with that, I will turn the call back over to James.

James McManus

Yes, thank you, Chuck. Before we take the questions, I want to point out the substantial hedge positions we have already built in ’13 and ’14. Our capital spending levels in the Permian likely will remain near-record levels in 2013 as I outlined earlier and in 2014. These hedge positions will help us implement our capital programs, generate attractive returns and achieve targeted production growth regardless of periodic price volatility.

As you can see in yesterday’s release, we have $89 and $90 oil hedges in 2013 and 2014 as well as natural gas hedges that average more than $5 in 2013 and $5.50 in 2014. Some might say that we are leaving a little upside on the table, but to that observation, frankly we say great. We want commodity prices to rise above our hedge prices. Our own hedge volumes will benefit from higher prices and we will be in an even better position to implement our drilling and development plans, and we will protect our shareholders from the risk of falling commodity prices.

With that said, let’s move now to the Q&A. To facilitate this, I will turn the call over to Andrea for instructions.

Question-and-Answer Session

Operator

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

Gabriele Sorbara – Caris & Company

Good morning guys, good morning, Julie.

James McManus

Good morning, Gabriele.

Julie Ryland

Hi Gabriele.

Gabriele Sorbara – Caris & Company

On the 3rd Bone Spring wells, you had nice sequential improvement there. Are you guys doing anything different in terms of completion method and can you give a sense of where those wells are located? Are they close together or are they kind of spread out across your acreage block?

James McManus

Yes, Gabriele, let me do this. John Richardson is with us here, President of Energen Resources and I will let him address both of those questions. Johnny?

John Richardson

Thank you, Gabriele. To address where they are, Gabriele, we are not – we have a very large acreage position that’s about 45 miles, about 40, we are more or less in the center of that acreage position, they also the fourth quarter are not right adjacent to each other, they are spread out in that central bark of acreage we have there. And as far as different, we have started targeting a little bit lower sand in the 3rd Bone Spring. That’s the major difference between this last quarter and the first generation of Bone Spring wells we drilled in this area.

James McManus

Gabriele, this is James. If I could follow up, I will ask Johnny to add a little color. There is a good bit of variability here, and we have talked about it here in some of the areas we believe that the B-sand is the best target in some areas, the D-sand in some areas, the X-sand, and we still are in the learning process in this particular play. I think the last four were drilled on the eastern side of the river from –

John Richardson

Again, yes, if you look at the Pecos River as sort of the demarcation line, two of these wells around the east and two around the west. They were all – they have been one D, but there were three X sands there, as James, and the X-sand is the lower sand package as we denoted. And James is correct. On the far east side of our acreage position, we believe the B-sand is probably the proper target as we move west, we begin into an area where we think the D-sand is the target. And then, as we move further to the west, we see the X-sand blossoming, and that’s sort of the color on that.

Gabriele Sorbara – Caris & Company

Great. (inaudible) And then can you just speak in terms of EUR maybe on this last generation of wells? I know this is little back grade, but can you give any sense of where they would land?

James McManus

Well, given with all the early data, we don’t see any reason to change our overall model at this point on an average basis.

Gabriele Sorbara – Caris & Company

Okay. Thanks Just on the Avalon well, did you have any completion issues there or drilling issues with that well?

James McManus

Gabriele, we did not. Actually, the section, the Avalon section looked pretty good. We just encountered a wet zone to up-hole to basically drown the well. I am going to let Johnny talk a little bit about what we think that condition might be.

John Richardson

James is right. If we address just the Avalon formation on its own, it’s a very attractive formation. It really is a nice Avalon section compared to other wells that we have noted in the whole basin there. However, we did encounter some strong water flows up-hole in that well, and so, and as a matter of fact, basically all we produced out of the well over a prolonged test period was water. We never really saw the Avalon formation kick in. We believe that, that is a localized event, geologic structural event, but nonetheless all we produced from that well is water. We don’t think that has any bearing on a wide basis to the Avalon formation. In fact, we are very sure of that. This is a localized event that’s, we don’t know how localized, we don’t know in that particular part of our acreage is spread to other wells, but on this particular well, we did produce a lot of water and no hydrocarbons.

Gabriele Sorbara – Caris & Company

Okay. Great. Appreciate the color. I see the math in your acreage position there, but can you give me a number in terms of what kind of acreage you have in that western flank in Reeves County.

John Richardson

We don’t have a lot of acreage that we think this well would influence. So, we got two or three adjacent sections where this well is drilled. And so, on a localized manner, it’s not widespread.

Gabriele Sorbara – Caris & Company

Okay.

John Richardson

We do have two other wells though in the same area, one is an X-well that we are currently testing, and we are seeing a very different response from that well. And we do have a vertical well where we wanted to see the whole section, including the Wolfcamp. This Avalon well is in the middle of those two wells. So, this well is bounded on either side, we will find out more information on.

James McManus

Gabriele, this is James. I am sorry, we don’t have that number, but you can sort of get a pretty good eyeball, because that math we give you is based on sections, but I don’t think we have that number right at the tip of our tongue.

Gabriele Sorbara – Caris & Company

Okay. Nice Wolfberry acquisition, but can you give me a sense or can you provide some color on M&A going forward?

James McManus

Repeat that end part of that question.

Gabriele Sorbara – Caris & Company

Can you just provide your views on M&A going forward?

James McManus

I think, Gabriele, we are in pretty good shape right now. We have got an awful lot of inventory. I think we would continue to look at leasehold potential in the Delaware Basin, also leasehold potential in the Wolfberry play. But we did do a pretty good bit of capital investment on these last two acquisitions and feel like we are in good shape, but if we see something really good in the Permian, we certainly would look at those two types of opportunities. I don’t think we are really looking for anything right now outside of this basin, because I think we need to see how these plays in the Delaware mature. For example, when you think about the Delaware Basin, and we said it in the press release, you have got the Avalon shale up-hole, you have got 3rd Bone Spring, we know we have got the potential for horizontal Wolfcamp in a good bit of our acreage, and then there is also the vertical Wolfbone play. So, if several of those are or all of those work in some area where our acreage is, that’s a good bit of capital investment going forward. So, I think we want to see a little bit how that play is out.

Having said that, we would look to increase our positions in either one of them. When we think about these two basins, we think of the Midland Basin – and really three – the Central Basin platform, better and butter very predictable, very statistical. When you think about the Delaware Basin, much more in the exploratory phase. You are going to have a lot of variability and we are working on the learning curve over there. Interestingly of course, not by ourselves, there are a number of companies who are going to be testing Avalon wells, 3rd Bone Spring X-wells, Wolfbone wells, and perhaps horizontal Wolfcamp wells as well, and we are watching all of that in the basin also.

Gabriele Sorbara – Caris & Company

Great, thanks for the color. I will jump back in queue.

James McManus

Thank you, Gabriele.

Operator

Your next question comes from the line of Becca Followill with U.S. Capital. Your line is open.

Becca Followill – U.S. Capital

Good morning. On the Avalon shale, well cost is 6.1 million. Is that based on just the well that you have drilled so far or is that your expectations for 2012?

James McManus

We have only got a few Avalon test wells slated for 2012 and the operative word there, Becca, is test wells. So, we will perhaps stay coarse in these wells, we will do a good bit more geological work than we ordinarily do, and that’s why those wells are so much higher. We do anticipate more of a drilling-produced stage, they will be lower than that, and it will be much closer to our 5.5 million, because we built our budget for 6.1 million because that’s what we have had in some of the early test wells, because we have done a lot more work in those wells than we would when we move into a drill and complete stage.

Becca Followill – U.S. Capital

It’s a fully-loaded kind of, not kind quite exploration, but really an evaluation well?

James McManus

Yes, that’s exactly how I would – that’s a good term. It’s a fully-loaded evaluation well. That’s a great term.

Becca Followill – U.S. Capital

Thank you. We can just maybe copyright that. And then on the Bone Spring, I think that somebody asked it, just to clarify, you have got 13 wells that you have brought online in the first time of 2011 and the rates are, I would say, materially higher than your model. At what point or how much data do you need to see before you change EURs or is that all if you do change them?

James McManus

Yes, I will let Johnny. I think Johnny made a comment earlier that we are still in the early stage of production on those wells, and you don’t know how quickly they are going to decline at this point. So, we are going to need to watch those, but the average EUR number that we are using I think we still feel comfortable with. Now, Johnny, what would you say about that?

John Richardson

You are certainly correct. And Becca, yes, we have in aggregate beaten the model that we have put out there; however, you know, again we have been doing this for less than a year now, we want to watch these, be sure there will be some variability. Overall, we feel good about the model and that’s where we are sort of standing right now.

Becca Followill – U.S. Capital

Okay, great. Thank you.

James McManus

Thank you.

Operator

Your next question comes from the line of Tim Schneider with Citigroup. Your line is open.

Tim Schneider – Citigroup

Hi guys, I joined a bit late. It’s already been answered, apologies, but I was just wondering what was driving the improvement in the Bone Spring if you look at the overall results?

James McManus

Yes, Tim, I am going to let Johnny talk about that a little bit as well.

John Richardson

Tim, we did a little earlier a little more color on the earlier answer, but basically we are targeting – these last quarter wells we sort of changed our landing zone from D to X on three of the four wells, and we are of course continuing to learn. We are continuing to try to tweak our completion techniques to yield better results, and I think that’s added something to these rates. But I think mainly moving from the D on three of these to the X as we move a little bit around – a little bit further to the west and south has paid out for us.

James McManus

We have got some, and I think we have made this remark on the last conference call. We had some of the west that we drilled originally as D-wells that are lower performers than the model a little bit in the variability of things, and we wished if those had been Xs and if we did them again, we do them as Xs, and what we found out is on the western side, the X is far more productive than the D.

Tim Schneider – Citigroup

All right. Thank you.

Operator

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

Duane Grubert – Susquehanna Financial

Yes guys. On the Avalon, you mentioned in past that you may take some coarse going forward. Is it correct to assume that right now you have got a little bit more reservoir characterization uncertainty than you thought you are going to walk into or how would you characterize really what’s going on with your testing versus on easier goal to date?

James McManus

Duane, this is James. I think on the eastern side, we had mechanical difficulties in that well. WE are going to go back and look at a vertical well over there again to make sure we think we know what’s going on, but Loving well, which is currently flowing back, hopefully we will have some results on that when the next time we talk to you. That one is closer to known production. We were surprised by the localized water that Johnny talked about on the western side, but we don’t think that impacts the play in a broad way at all. So, Johnny, you want to add anything else there?

John Richardson

I think, Duane, James is right. The Avalon section looks very good from a reservoir standpoint. It’s basically confining our completion to that Avalon section and staying out of the surrounding issues, has been sort of an issue so far on both of those wells, just where they were on a localized area.

Duane Grubert – Susquehanna Financial

Okay. And then, if I look at this objectively, the timing of your Wolfberry acquisition and it not being as easy as maybe we would all hope on the Avalon to date, is it appropriate for me to think that, that maybe the Wolfberry acquisition was partly motivated to offset, if there is some uncertainty of the size of the Avalon project going forward, or would you have done the Wolfberry deal anyway?

James McManus

We would have done it anyway, Duane. It was not intended to offset it all. I mean, I think we continue to be excited about the multiple pay opportunities that we have got in the Delaware Basin. We know that this can take a while to fully develop all back, but we have consistently said we were in the hunt for more Wolfberry acquisitions and are happy to add to that inventory. At the same time, I think we have got a lot of exciting prospects in the Delaware Basin, and this is a marathon not a sprint.

Duane Grubert – Susquehanna Financial

Okay. And I know, at least one of your packages in the past, in the Wolfberry have been done from a private equity funded small player. Is there more a stuff like out there, so we might have some suspicion that you are going to continue to look at private equity guys as a source of project in the Wolfberry to acquire in the future?

James McManus

Yes, I think of these two private deals we just did, I think there will be others that we may be able to look at as well, yes.

Duane Grubert – Susquehanna Financial

All right, thank you very much.

James McManus

Sure. Thank you, Duane.

Operator

(Operator instructions) Your next question comes from the line of Greg Share [ph] with Tree Brothers [ph]. Your line is open.

Greg Share – Tree Brothers

Hi, there has been a lot of questions about the improving results in the Bone Spring, but we are also seeing good results versus your model type curves in the Wolfberry and not only that, improving results third quarter versus first half. Can you speak to that and is your guidance in the ’12 and ’13 based on the modeled IP rates across these plays, or are you tweaking that at all for what you have – even if you don’t adjust the EURs over an extended period, are you tweaking it at all in terms of more current production as you plan your drilling the next couple of years?

James McManus

Right now, we are using the model. So, I hope that turns out to be conservative, but at this point, we have to win the model, by and large.

Greg Share – Tree Brothers

And what’s driving the better Wolfberry results?

James McManus

We have got to face some variability there we know, but we have been so far in good areas, and we have got a good approach. Again, we continue to tweak our completion efforts there to try to understand what is actually contributing and how we can maximize that, and I think our guys have done a very good job that targeting the right things and production has increased production at least in the first body of wells we drilled has paid off for that.

Greg Share – Tree Brothers

Great. The results are really meaningfully different than the model and even sequentially. How many quarters of this do you need before you adjust your guidance for a couple of years?

James McManus

So, remember, recall and there are some areas that are we beginning to get very comfortable with, but we had added over the last year several acquisitions, and we are just now getting into those areas and starting our program. So, I mean, you got a valid point of should we be adjusting this model, but I think overall given the fact that we are in some new areas that’s a little bit early for that.

Greg Share – Tree Brothers

And can you remind us what’s the most recent acquisitions and any future M&A activity, how you think about minimum IR thresholds and obviously relative to your conservative type curves?

James McManus

Yes, we have been looking generally on the acquisition basis, the number we talk about is a pre-tax unlevered rate of return in excess of 11%, and we use the forward strip on most of them, and then we cap the price in the out years and sometimes frankly with the benefit of IVC, those returns look like on paper that they are more like 13% using our model, which we hope turns out to be conservative in some cases.

Greg Share – Tree Brothers

And if you go way back, you actually had a lot of success meaningfully expanding the reserves from what was originally incorporated into the analysis when you bought them. So, you have got two potentials here if I understand. You are not necessarily being aggressive on what you think is in the ground when you buy it, and you are using these type curves that seem to be less than what you are experiencing over the last number of quarters. And if either of those things turn out to be conservative two years from now, those are both upside.

James McManus

There would be, and I guess the type of upside that I would talk about, if you are talking about the Wolfberry, you certainly have the possibility. If the performance continues to hold over the large area of acreage we have for that certainly to be upside. The other upside that we typically talk about in the Wolfberry that we did not really pay anything for the possibility of 20-acre spacing. The 32,000 acres and the 800 locations of inventory that we have are all done on 40-acre spacing.

As you turn to the Delaware Basin, as you know we booked Bone Spring potential in the possible category, I think 68 million barrels of oil there. A part of that was what we targeted when we bought the SandRidge acquisition but we really didn’t value any Avalon, Wolfcamp or Wolfbone potential in the Delaware Basin. So, to the extent any of those plays turn out to be viable, that’s going to be accretive to anything that we valued in any of the acquisitions that we have done. And I just feel like without any stacked panes out there and this much interest and the kind of acreage that we have, we are going to have some success in some of those plays going forward.

Greg Share – Tree Brothers

Great, I appreciate it.

Operator

And your final question is queue is a follow-up from Gabriele Sorbara with Caris & Company. Your line is open.

Gabriele Sorbara – Caris & Company

Hi again. Just looking at the Wolfberry, costs have gone up a little bit to $2.2 million per well. Just trying to get a sense of, is there any potential for you to drive down costs there, and what kind of cost inflation you guys are assuming for 2012 CapEx?

James McManus

That is our 2012 CapEx number. So, we have already built the inflation in there. So, we had $2.1 million near end of ’11 and we jumped out up to $2.2 million, and I don’t expect, Gabriele, that number to move really materially. I mean, one of the things we are looking at is the number of completions that we do in a well and if we think we are going to get more oil and we are going to keep the rates outperforming, we will go ahead and spend that capital. If we don’t think we are getting that amount of oil, there is maybe $100,000 or so that you could show up as well costs. I will mention a couple of things. When you look at those well costs, we talk to other operators in the basin to be sure that we are in the right ballpark. One of the things that we do a little differently is we set three strings of pipe just about every well that we drill. We are in this business for the long term, we want the well to perform well over the long term. Some folks will do two strings a pipe and use some type of wrapping system to protect from corrosion of water. And so, when we do it, we feel like we are using the best practice out there for the long term, (inaudible) perspective, so that you are going to have less trouble in that well going into future. But we think we are riding the neighborhood of what everybody else is doing for those particular wells, but there is not a tremendous amount of variability at this point. We have been dropping the number of days on some of the rigs that we have that were less efficient and replacing those with more efficient rigs. But I do expect it to stay in that neighborhood. I do think the 7.3 million that we are using on the Bone Springs, hope that turns out to be a little bit conservative. We built a little bit more increase in there, we are negotiating those terms right now. If you had to pin me down, I think it could be a little bit less than that, but we went ahead and built $7.3 million in the budget for 2012.

So, the numbers we gave you are what we think the ’12 numbers will be. If any of them has got a little bit of play in it, it could potentially be the Bone Springs on the downside. And certainly as Becca pointed out, we are using it evaluation cost on the Avalon well, and not really kind of a manufacturing moving into the development stage on that.

Gabriele Sorbara – Caris & Company

Great, thank you.

James McManus

Thank you.

Operator

As there are no further questions in queue, I would like to turn the call back over to Mr. McManus for any closing remarks.

James McManus

Thank you again for joining us today. We have had some great questions. I hope we have been able to answer those questions to your satisfaction, and hope you have a great day. Thank you.

Operator

This concludes today‘s teleconference. You may now disconnect.

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