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Executives

Julie Ryland – Vice President Investor Relations

James McManus – Chairman & Chief Executive Officer

Chuck Porter – Vice President, Chief Financial Officer, Treasurer

John Richardson – President and Chief Operating Officer

Analysts

Gabriele Sorbara – Caris & Company

Tim Schneider – Citigroup

Karl Kurz - BMO Capital

Duane Grubert – Susquehanna Financial

Sean O’Malley - WEDGE Capital

Brian Lively – Tudor, Pickering, Holt & Company

Mario Barraza - Tuohy Brothers

Energen Corporation (EGN) Q4 2011 Earnings Call January 26, 2012 11:00 AM ET

Operator

My name is Katie and I will be your conference operator today. At this time I would like to welcome everyone to the Energen 2011 conference call. (Operator instructions.) Julie Ryland, Vice President of Investor Relations, you may begin your conference.

Julie Ryland

Thank you, Katie ,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 its 2011 fiscal year and the three months ended December 31, 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, 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 McManus

Thanks Julie and good morning to you all. 2011 was an important year for Energen Corporation. It was the first year in which we could expect to see meaningful results of our strategic shift away from gas to oil and natural gas liquids. And we did see meaningful results in 2011.

Energen Resources produced a record 20.45 million BOE in 2011. 42% of the 2011 production was oil liquids, up from 37% in 2010. In 2010 the Permian Basin contributed 30% of total production. Today 38% of our production comes from the Permian Basin.

Year end credit reserves totaled a record $343 million BOE. Our product mix changed dramatically in 2011. At the end of 2010 47% of our crude reserves were oil or liquids. A year later our crude reserve mix is now 54% oil or liquids.

For years the San Juan Basin has been home to the majority of Energen’s prude reserves and that too changed in 2011 as we began to realize the impact of the strategic shift we made in 2009 to oil and liquids.

At year-end 2011, 64% of our crude reserves are in the Permian Basin. After Permian Basin reserves increased 38% by year-end to $183.6 million BOE. The invested record drilling capital of $810 million in 2011, approximately 85% of those dollars went into the Permian Basin. And we required some $300 million of addenda prude and un-prude leasehold in the Permian Basin in 2011.

Based on our operating results we achieved in 2001, Energen is now well positioned to continue realizing the benefits of our shift and focus to oil liquids. We’re very pleased with the progress we’ve been a making in developing the vertical Wolfberry Basin. In 2011 we drilled 153 net Wolfberry wells and completed 100 of them. We also completed 22 wells that were started in 2010; in other words we brought 122 wells online in 2011 and we currently have 53 net wells in various stages of conclusion and hook up.

Initial stabilized rates of the 39 wells brought online during Q4 and 65 barrels of oil per day and 150 mcf per day of wet gas. To remind you Energen’s risk model initialized stabilized rate was 55 barrels per day and 110 mcf per day of wet gas. So obviously we continue to outperform our model.

We have approximately 32,000 net undeveloped acres in the Wolfberry Play offering some 800potential drilling locations based on 40 acre spacing. Our estimated cost of drilling complete on Wolfberry Well in 2012 is $2.3 million. This is slightly higher than previously estimated due to cost pressure of higher oil prices. Back when we did the negotiating, if you remember, oil prices had dropped down to 80 but then they very quickly rapidly moved back up into the 100 range.

We continue to see positive results on our third base spring wells, the wells we had drilled on the east side of the Pecos River are performing better then are the majority of wells drilled this year on the left side of the river. There’s less infrastructure over there and we encountered higher amounts of water.

In general nine of the twelve wells drilled on the left side of the Pecos River have experienced steeper than expected declines and our efforts to maximize their production have been somewhat hampered by limited infrastructure. Later in the year however we drilled three water disposal wells and recently installed pumps on three of our West Side Bone Spring wells as we continue to try to work to improve that production.

However, taking collectively our 3rd Bone Spring program is generating very good results. We drilled and concluded 18 net 3rd Bone Spring wells in 2011 and concluded two additional wells that were started in 2010, another five wells are drilling or waiting on completion or testing.

The initial stabilized rate of the 20 net wells brought online in 2011 averaged approximately 400 barrels of oil per day and 1035 mcf per day of wet gas. This exceeds our risk weighted average model rate of 260 barrels per day and 735 mcf per day of wet gas.

We brought seven wells online during Q4 of 2011; two on the west side, five on the east side. These wells had an initial stabilized weight of approximately 485 barrels per day and 1085 mcf per day of wet gas, again outperforming the model substantially.

We have approximately 68,000 net undeveloped acres that are perspective for the 3rd Bone Spring sands or approximately 210 potential drilling locations based on 320 acre spacing.

The estimated cost to drill and complete a well in 3rd Bone Spring trim will be $7.5 million in 2012. This represents about a $200,000 increase and is due to our plans to drill longer laterals and increase the number of fracs as well as rising oil prices also adding to cost pressure.

Our third Avalon shale well in 2011 was drilled in Loving County and had an initial stabilized rate of 200 barrels of oil per day and 750 mcf per day of wet gas. This well has not been able to sustain this oil rate as much as we would have liked and is currently producing about 75 barrels a day and 750 mcf a day of wet gas. We designed the completion of this well with smaller fracs in an effort to reduce produced water and try ot maximize hydrocarbon production. Instead, hydrocarbon production may actually have been hampered by the use of smaller fracs.

So the Avalon potential on our acreage remains unclear. Given how low gas prices have fallen, you would expect us to redeploy our 2012 Avalon capital to the DEPA Wolfcamp shale formation. Wolfcamp shale is thought to have a higher mix of oil to gas and so we think the Wolfcamp would be a better use of our exploratory dollars. Also Wolfcamp production will hold the shallow Avalon shell for future exploration.

Energen Resources has approximately 110,000 net undeveloped acres that are perspective for Avalon shale, which generates approximately 340 potential drilling locations based on 320 spacing. Speaking of lower gas prices, we’ve revised our 2012 cash flows and EPS guidance down largely due to lower assumed natural prices applicable to our unhedged volumes.

The net after tax cash flows and earnings guidance ranges for 2012 are $764 million to $793 million and $3.15 to $3.55 per diluted share, respectively. Our guidance of course excludes potential non-cash mark-to-market impacts. In addition to lowering our gas price assumption from $4 to $3 per mcf, we raised from 85 to 95 our assumed oil price. Our estimated DD&A expense increased as well which is largely due to higher cost and weaker than expected results from some of the west side 3rd Bone spring wells.

Approximately 63% of our 2012 estimated production of 24 million BOE is hedged and sensitivities on our cash flows and earnings to changes in commodity prices are detailed in yesterday’s news release. I encourage you to view not only this information but also the look at the excellent hedge positions we have in place for 2012, 2013 and 2014.

At this time I’d like to turn the call over to Chuck Porter, our Chief Financial Officer, to briefly review the results of 2011 and Q4. Chuck?

Chuck Porter

Thank you, James. Energen’s 2011 net income totaled $259.6 million or $3.59 per diluted share. Including in these numbers are non-cash market-to-market hedge losses of $23.4 million after tax or $.32 per diluted share. Net income in 2010 totaled $290.8 million or $4.04 per diluted share and included non-cash write-offs for capitalized unproved leasehold of $24.8 million after tax, or $.34 per diluted share.

Adjusting both periods were the non-cash items net income total of $283 million or $3.91 per diluted share in 2011 and $315.6 million or $4.38 per diluted share in 2010.

Despite significant growth in 2011 oil and natural gas liquids production, earnings were negatively affected by 21% drop in realized natural gas prices. Higher LOE and production taxes and increased DD&A expense.

Our 2011 production totaled $20.45 million BOE and was essentially on target with our forecasted production of $20.5 million BOE. Reflective of our focus on oil and liquids production in the Permian Basin, oil volume increased 23% and NDL volumes rose 16% and natural gas product increased only 1%.

Consolidated net cash provided by operating activities, before changes in operating accidents and liabilities totaled $736.5 million at the end of 2011 and compared with $740 million in the same period last year. Energen Resources adjusted net income totaled $236.4 million in 2011 as compared with $270.1 million in 2010.

While energy and resources production increased 8.6% year-over-year, including a 21% increase in oil and EDL production, net income was negatively affected by 21% decline in realized natural gas prices. Higher LOE included production taxes and increased DD&A expense.

Permian Basin production in 2011 increased 27% year-over-year largely due to the company’s 2010 acquisitions and associated development, increased development of all other Wolfberry properties and new well development at Fuhrman-Mascho. Stand one basin production increased less than 3% primarily due to new well development. And decreased production in our other areas was small in terms of volume and reflected the company’s capital investment focus in its Permian Basin oil property and normal property declines.

Total LOE per unit in 2011 increased approximately 5% in 2010 to $12.57 for BOE. Base LOE in marketing and transportation expenses increased about 2% to $9.88 for BOE. Commodity price-driven production taxes rose 18.5% on a per unit basis. A DD&A expense per unit in 2011 increased approximately 11% from the prior year to $11.75 per BOE reflecting year-over-year increases in development costs and production. Per unit net G&A spend increased approximately 13% in 2011 to $3.15 per BOE due in part to performance based compensation and the increased labor cost.

Alagasco, our natural gas utility generated net income in 2011 to $46.6 million. This concurred with earnings of $46.9 million in 2010. This difference is due to the timing of rate recovery largely offset by the utility’s ability to earn on a higher level of equity.

Turning next to Q4 of 2011, for the three-month ending December 31, 2011, Energen’s net income totaled $14.4 million or $.20 per diluted share and included non-cash market-to-market hedge losses of $9.8 million and that is $56.6 million after tax or $.78 per diluted share.

Excluding the non-cash items, Energen’s Q4 2011 net income totaled $71 million or $.98 per diluted share. Prior year results totaled $80.3 million or $1.11 per diluted share. Energen Resources adjusted net income for 2011 totaled $59.9 million as compared with $70.6 million in Q4 of 2010. This decline largely was the result of the lower realized natural gas prices and higher DD&A expense partially offset by 11% increase in production.

Permian Basin production increased 31% in Q4 year-over-year. Total LOE per unit in Q4 of 2011 was essentially unchanged relative to the same period in 2010. A base LOE in marketing and transportation expenses in 2011 declined 3% to $9.12 per BOE while commodity price-driven production taxes increased 9% to $2.58 per BOE.

DD&A expense per unit in Q4 of 2011 increased 26% over the prior year Q4 to $13.38 per BOE. This increase reflected increases in development costs and production.

Alagasco’s net income in the last three months of 2011 totaled $11.3 million and compared with net income of $10.1 million in the same period last year. This increase primarily is due to the utilities ability to earn on a higher level of equity.

And that’s a bird’s look at the financials for the year and Q4. And with that I will turn the call back over to James.

James McManus

Thank you, Chuck. As we look back on 2011 we’re pleased with our accomplishments; we managed to pass our key guidance projections. We were awarded Dixie well for our decision in early 2009 to refocus our efforts on oil and liquids in the Permian Basin. We’re excited about our results on the Wolfberry and 3rd Bone Spring place and while we wish we had a little better clarity on the Avalon, we’re excited about taking a closer look at the Wolf Camp shale as well. Another play that has, we believe, a great potential in the Delaware basin.

Let’s move now to Q&A. to facilitate this, let me turn the call over to the operator for instructions. Operator-

Question-and-Answer Session

Operator

At this time I would like to welcome everyone. (Operator Instructions.) Our first question comes from the line of Gabriele Sorbara from Caris and Company. Your line is now open.

Gabriele Sorbara – Caris & Company

I’ve got two questions. Maybe we can kick it off with the Avalon shale. It sounds like the well- you guys had a completion issue with that well. Can you maybe give a little bit more color on that and then maybe talk about the geology you saw in that well, maybe the shale thickness and compare it to the previous well you guys had in Reeds County.

James McManus

Let me let Johnny talk a little bit about that and I’ll add a little color to that as well. Johnny?

John Richardson

The shale thickness actually is better in this well then what we’ve seen in our two previous wells. And the Avalon shale is very nice looking interval. It’s going to be gas here, as James mentioned. And we did do a smaller frac job trying to sort of maximize our completion and we may not have quite achieved stimulating the whole zone. But it’s still an economic well in its current status, it’s just probably best that we deploy that capital elsewhere given the gas prices. We’ll hold the Avalon with our date for drilling. We have deeper drilling opportunities in most areas where we have the Avalon.

So I think it’s prudent to probably move away from that, to save that for a later day. It’s not- I mean it’s still a valid target in our minds, it’s probably just not the right target for the occasion.

James McManus

I would add that when you compare it, at this point, the results you’ve seen, it is skinnier than some of the other targets we’ve got. When you add to it the fact that it tends to be a little bit gassier in what we’ve seen happen to gas prices, as Johnny said, it just makes a lot more sense for us to pursue the more oily zones right now at this time. It doesn’t mean we won’t look at it again. It doesn’t mean we don’t test it again. But right now at this point we’re going to focus on Wolfberry, Bone Springs and testing Wolfcamp, which basically has the potential to have a very broad application over our acreage in the Delaware Basin if that formation turns out to be productive.

I’d also say from the data that we have taken on vertical test wells, cores and logs, you know it’s only a supposition based on that data but the Wolf camp looks like it’s got better productive capability in our mind. It doesn’t mean the Avalon can’t one day be productive. We’ve got the right initial rate, the decline was a little bit steeper. If it had fallen off over six months instead of several weeks to the 75 barrels we’d had more of what we were looking for.

But even in that particular arena you’re talking about something that doesn’t necessarily compete that well on a return basis with some of the other products we have. As Johnny mentioned, on a go-forward basis we probably had kind of a marginal situation, low double-digit type of return from that well. But we’re looking for more than that right now. With gas prices where they are, we think it’s appropriate to redirect at this point.

Gabriele Sorbara – Caris & Company

Fair enough. Agree there. How much acreage do you think is perspective for the horizontal wolf camp and what really gets you excited in the plays better than the Avalon and that it’s oilier?

James McManus

In general we’ve done some vertical wells that would suggest that it can have pretty wide applicability to our acreage in the Delaware.

John Richardson

I think the roughly 110,000 acres that we talk about, we don’t see any reason that the majority, if not all, of that is not perspective for the Wolfcamp. If we follow the Wolfcamp sort of around the horn from the southern midland basin where you’ve seen success that others have had there, we look at that shale and the characteristics we see, the Wolfcamp there, we follow it through the Wolfbone area down in the southern part of the Delaware basin as we come around we look at our shale that we have. We’ve got some petrophysical data on and we think that our shale is attractive when compared to that. It’s very, very similar. So we’re hopeful that we have similar productive characteristics.

James McManus

We will definitely do some testing in the Wolfcamp over the course of this next year, there’s no doubt about it because we need to find out if that deeper zone is productive because again you can hold everything [up hole]. And I want to point out the part of the Wolfcamp that we’re really targeting is the upper Wolfcamp because that’s a pretty big section. We think the upper looks better. From the characteristics we’ve seen, we think it’s got potential to be oily in character just like what you see on the southern side of the Midland Basin. And we are excited about the prospects for that.

Having said that, we’ve got a endeavor to see if we can product something economic from that formation.

Gabriele Sorbara – Caris & Company

Any sense of expectations and what are the AFEs on those wells?

James McManus

Well it’s a little bit deeper, obviously, then the Bone Spring so you’re going to be more in that neighborhood or a little bit more.

John Richardson

We’re still developing our contracts on completion. That’s going to impact it. I mean I think initially we’ll see costs probably $9 million plus but I think that’s to start out, just sort of scoping. I think we’ll see these settle back. They’ll be more expensive then the Bone Spring well James says. But they shouldn’t be extremely more expensive. There are deeper- we haven’t worked out the completions in our mind yet, that could be a little bit more expensive. So I guess right now we’re still sort of in the theoretical development. We’ve got some testing to do and it’s probably a question we can answer better in the future.

James McManus

The other part of that theory is due to the thicknesses that you see and some of the rates you’ve seen in the middle of the basin and of course we’ve got to prude this out. I think the economics will support that cost because our expectation is if this turns out to be productive the rates would be better than what we see in the Bone Springs.

Gabriele Sorbara – Caris & Company

Moving over to 3rd Bone Spring, I just want to get a sense of those wells. How far west of the river were those wells drilled? Was it kind of fringe acreage where you had the underperformance on some of those wells?

James McManus

Well in general we think that there’s a pocket to the west of the river. And you know some of those wells were good, but there’s a basket that were not as good as what we had on the eastern side, we encountered more water. As we mentioned, we just recently been able to add pumps to three of those wells and we’re going to watch that particular performance. We’re still learning about that particular area. We think in general what we hit though is an area where there seems to be geologically more water production and we don’t know how extensive that’s going to be but we definitely have encountered that on the western side. And as you know on the western side our drilling plans for ‘12 and ‘13 are for eastern side wells. And so we don’t expect that to impact any of the targets we’ve got out there on production. But let me let Johnny add some color that I may have missed on that as well.

John Richardson

I think you described it well. It’s a matter of just water cut. I think you’ve heard that from others besides us as you move west of the Pecos River there. And as James pointed out, we’ve got to do some more science; we’ve got to understand that area more. It’s not an area we’re abandoning but it is an area that we probably should study and see if we can reorient the wells or come up with a different completion strategy as we understand it more so that we can increase our oil cut. We just make more water over there.

And as we have commented in the past, as we go west across the Pecos River, we do run out of infrastructure both with electricity, roads and water disposal. We made some good progress in late ’11 and we’re still continuing to make progress to get electricity and water disposal capabilities over there so we’ll be able to test these wells a little bit better and give them some artificial lift. Right now they’re just basically running with their natural lift and they’re decline has been steeper than what we see on the eastern side of the river.

James McManus

And Gabriele I would say you’ve seen our maps of where we drilled and it’s not far west. We didn’t go far west; we just kind of went a few miles west of the river. So I don’t want to give you the impression we’re all the way over on the far western side of the basin. There just seems to be a geological event in that particular area that has occurred that causes more water production. Can we isolate it, can we figure out where it’s coming from, can we avoid it, is it just a certain part of that western side; all of those are open issues at this point. I guess I think one of the important things to remember is a backbone of the production that we’re going to be delivering in 2012 and 2013. We talk a lot about the Delaware basin beneath the Midland Basin, which is highly predictable. Again we got results above the model and we do have the Bone Spring built into our production estimates for 2012 and 2013. But we’ve got enough location that we think are going to be very predictable to deliver those results.

Now the question is how much running room is the company going to eventually have and how extensive will the Bone Springs be on our acreage and does the Wolfcamp develop as a potential play and all those are issues about future develop-ability. But the kind of targets that we put out there about doubling oil and natural gas liquids production from 2010 to 2013, we feel very confident about making those targets and I want to continue to make that point that a lot of these other things are important to the value of the company because they’re going to impact our running room in the future. But as it relates to our ability to deliver on the results that we put out there, we feel very confident about that.

Gabriele Sorbara – Caris & Company

I was a little bit surprised that you guys are drilling in an area where you have limited infrastructure. Was that to hold leases?

James McManus

It was. If you recall when we bought Sand Ridge we had about 5000 acres over there that was expiring very quickly. And at that point we had no reason to believe that there was any geological difference between that acreage and the acreage that we were acquiring on the eastern side. And so we did move over there fairly quickly to drill some wells to hold that acreage. And if you recall we were in fact flaring some gas for a while until we got gas pipelines out there and were able to hook up the gas. So it was definitely we moved in that direction first to hold on to that acreage.

Gabriele Sorbara – Caris & Company

Okay. Can you quantify how much of the end of performance was related to limited infrastructure?

James McManus

Well we don’t know at this point because what’s occurring is we put three of these wells on submersible pumps and we’ve had them on there for I think about 30 days. We’ve seen a marked pick up in the water production and we’re waiting to see if there’s going to be a marked pick up in the oil production and whether we’re going to be able to lift more oil with those pumps on or not. And that’s still an open question.

John Richardson

Right. James is exactly right about the mechanical lift. We’re in the evaluation phase now. It’ll take a little bit more time to look at those wells definitive. And we’re only working on three of nine or ten wells or so, so we’ll expand that program in the future.

But from a reservoir standpoint we don’t see a lot of marked difference from one area to the next. So the reservoir seems to be rather consistent but yet what’s happening above or below the reservoir seems to be our main issue as far as the conductivity to the water bearing zones or what’s going on over there, natural fracture system. It may be a problem that we can understand and adjust. It may not be in the future. And the lift; it will be very interesting to see how we perform under the artificial lift on that side.

Gabriele Sorbara – Caris & Company

I appreciate the color. Thanks.

Operator

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

Tim Schneider – Citigroup

I just wanted to dig a little deeper on this 3rd Bone Spring. So if I look at a map that you guys put out in your recent presentation, page 12 I think it was showing the Delaware basin. It seems like the acreage on the west side and the east side of the river is split fairly evenly, just eyeballing it. Do you guys have an exact number?

James McManus

It’s probably about 55,000 acres roughly.

John Richardson

Yes. Yeah it’s about half.

James McManus

About half. I think you’re right on that.

Tim Schneider – Citigroup

Okay. And then if you could, if you have the data, would you mind sharing what the actual kind of stabilized rates were in the east versus the west.

James McManus

We don’t really have it split that way. In general the ones that have been weaker have been in the west from a perspective of initialized rate. Although some of the wells, three of the wells that we built in the west had pretty good rates on them. But in the basket they were weaker. And I don’t have that particular number unless Johnny does.

Tim Schneider – Citigroup

I just want to jump over to the Wolf area real quick. I mean you guys are still kind of trending ahead of the risk models at this point, still kind of your largest drilling inventory play. What are the chances of you guys maybe speeding up drilling there, kind of front end loading that and the potential of upping that EUR guidance there given that you consistently have been coming in over what you’ve guided to?

John Richardson

I think this; I think we’re still a little early on the EUR. Obviously we need a good bit of productive history to see if we move that. But the trend is in the right direction. It’s better to start off with more production as we have. I think the possibility of ramping it up is a little bit. It might be out there but dramatically ramping it up beyond what we’ve got is probably not do able. We’re operating at pretty full capacity out there doing 170 wells a year. And it’s not like we can double that number. We don’t have the service to do that or the manpower at this point.

Again we feel very good about the services that we do have to execute the plan we’ve got on the table, which again is a record for us. We’ll be the fifth most active operator in the Permian Basin based on the rigs that we’ve got and work out there. We’re going at a fairly fast pace. So I don’t see a lot of acceleration potential in the Wolf area beyond what we’ve got built in.

Tim Schneider – Citigroup

How about the down spacing potential? The 20 acres?

John Richardson

Yeah I think there is potential for that. I think that comes later once we work our way through the 40s. But as I’ve talked about particularly down in, I believe it’s Glascot County of the middle of the basin that we believe that the spray berry is not as productive down in Glascot and Regan County. If you look at our map in the presentation you can see we’ve got a very good holding in that position.

And I would also mention that there are people doing some horizontal things down there in the Wolfcamp, in the [Klein], some people call it the Pinshell. That’s something that we’ll be looking at as well to see if there’s some additional potential to go horizontally in that particular formation as well. So I think down the road there is going to be the potential for some 20-acre spacing. I don’t think it relates to all of our acreage. I think up in Martin in Midland County where you have highly productive Sprayberry formations down spacing is less likely. It’s more likely in the areas of Glascot and Regan for us. But I think we’re going to have some potential to do that. Absolutely.

Tim Schneider – Citigroup

So if I look at a county map, I’m jumping over to the Wolfcamp right now, Texas. How far west do you think the Wolfcamp extends there?

John Richardson

Now are you in the Midland Basin looking west of Midland or are you west of Delaware?

Tim Schneider – Citigroup

I’m looking west of kind of Glascot and Regan.

John Richardson

Well as you know, Pioneer is drilling some horizontal wells in Midland County right now in Uptown. So I believe it looks like it could be pretty extensive in that basin as well. It trends over to the Delaware basin and of course we drove some vertical test wells to identify if the Wolfcamp is present in some areas and we’ve identified that it’s present on the eastern most side of our acreage and also that it seems to be present on the most western and southern side of our acreage. So as I mentioned earlier, we feel pretty good about the fact that that formation is pretty pervasive in the Delaware Basin as well.

Tim Schneider – Citigroup

Okay so do you guys plan on drilling anything in Windclair and Ward or Reeves at all? Just testing it?

James McManus

We will do some tests in the horizontal Wolfcamp in the next year. I don’t want to talk about where right now at this point but there’s no question we’ll do some.

Tim Schneider – Citigroup

Okay, thanks.

Operator

Your next question comes from the line of Karl Kurz from BMO Capital. Your line is now open.

Karl Kurz - BMO Capital

Most of my questions have been hit but maybe just a few clarifications and I’m not sure if, James, you’re going to want to give any more color; but just even with respect to the Deepwolf camp not wanting to give location certainly. But with respect to timing, is that something that you can speak more to as far as first half of the year and second half of the year?

James McManus

I don’t want to get anymore specific right now. I will say it’s more likely than not that we’ll do it the first half of the year.

Karl Kurz - BMO Capital

Fair enough. Just another clarifying question on the west side Bone Spring with respect to the pumps that were added. How long do you think it might take of observation to know whether or not it’s having the desired effect? Is that something where you think you’ll know in 60 to 90 days? Is it something where it’s going to take a lot longer?

James McManus

Well Karl the real answer is we don’t know. We’re going to watch it very carefully and the thing you wonder about if it happens to be a contained situation, there may be some form of dewatering that could occur over time if it’s a formation that recharges itself through rain and is very permeable to the surface. It may be difficult to get any kind of improvement and that’s something we don’t know at this point, what kind of oil cut improvement we’re going to get. So I really can’t tell you whether we’re going to know in 60 to 90 days. Now if these wells are on for six months and we don’t see any improvement, that’s going to tell us that it probably is not likely to improve. And if we see water rates that stay extremely high and don’t tend to come down. But we’re just too early in it to know when that might happen.

John Richardson

And what we would like to have is for the oil-bearing zones to respond and to begin to pick up their contribution as we see some of these water [barrier results], whatever, however extensive they are as James has mentioned. You know we had no idea of the size of the volume of what we’re dealing with. So what we’d like to see is for, you know, for that cut to change. That’s what we’re looking for. We’ve got good lift now, we know we’ve got to have sufficient lift, we’re going to have sufficient disposal, what we need to see is for that oil contribution to really pick up. And as James pointed out, that’s sort of a little bit of a wait and see. We’re very hopeful with the theoretical work we’ve done indicates that should be the case but we now need to see that actually come true.

James McManus

We do have some seismic information in this area. And I will point out that while it’s not definitive because we’ve not done one, we don’t see the same type of event in the Wolfcamp which makes us feel a little bit better about the fact that we may not have the same water problem in the upper Wolfcamp on the western side. We’ll have to see. But based on some of the limited date we have, we think that it’s less likely to be the same type of event that might be occurring in the bone springs in this one-pocketed area just west of the river.

Karl Kurz - BMO Capital

Fantastic. Thank you. One other quick one if I could just because you made the mention that you think the Wolfcamp may be over the entire 110,000. Is there any non-overlapping piece of the Avalon? I mean if we do kind of think of the Avalon perhaps as a future option on gas. Is there reason-

James McManus

No, the Avalon we think- I mean we hadn’t drilled enough wells to know everything about where the Wolfcamp is but everywhere we’ve drilled one we’ve seen it. And we’ve drilled in some pretty far off places relative to our acreage positions. So at this point we have no reason to believe that Wolfcamp is not present where Avalon’s present.

Now I would point out to you that one of the Avalon wells we drilled on the far western side is completely wet and we wrote that well off last quarter. So now obviously the one we drilled in Loving County was not wet. It had oil production, it had gas production and so to some extent we don’t know on the western side how extensive the Avalon may be. There’s got to be some more testing there to find out was that an area that is localized and small or is it a broader area.

John Richardson

But it is the same issue. It was not contribution from the Avalon itself which is a nice looking zone. But we just couldn’t shut the water off from a pole. So same similar issues but a little bit more exacerbated I guess then what we’ve been talking about in the Bone Spring.

Chuck Porter

If you want to refer to our most recent presentation, you’ll see that the same outline on the Delaware Basin graphic that we denote Avalon area’s interest is also Wolfcamp area’s interest which I think I heard in part of your question.

John Richardson

But I do think there is a good bit of optionality on the Avalon from a gas price perspective and again we’ve got some other things to do so our thought is let’s not spend a lot of capital on it right now because it looks a little bit more marginal compared to our opportunities relative to gas and oil prices and the overall mix. And so not to say we’re not going to come back to it at some point. The beauty of it is all the Bone Spring wells that drill hold the Avalon. Had we gotten stunning result from the Avalon we might have redirected part of our program there but since that’s not the case, we’d rather look at the one that we consider to be higher perspective right now, which would be the upper Wolfcamp.

Karl Kurz - BMO Capital

Great. Thanks.

Operator

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

Duane Grubert – Susquehanna Financial

I’d like you to talk a little bit about the constraints you’ve got about doing the science in multiple places at once. You know you had to do a little science in the Avalon and now you’ve got some of your neighbors looking at things like decline specifically. What are you guys doing different at Energen now then a year ago in terms of staffing or studying what you’re going to do next and what best practices you’re most excited about?

John Richardson

That’s a good question. I will tell you that we have tried to align our company over the last year and specifically the last three months to focus more on the technical side of what we do. You know we do the obvious things, we’re in the right consortiums, we’re sharing data we think with the right people, we’re getting the right petrophysical database built. And your question is right on, this is a very broad are between the Midland Basin and what’s going on there between the Delaware Basin. There are a lot of interesting things to look at, a lot of great opportunities and we are aligning ourselves. Of course you’re always trying to achieve the best results you can drilling wise. We’re beginning to focus more and we’re beginning to bring in some focus effort on the completion side and on the rock side, the petrophysical side and try to start to break down some of these areas scientifically.

So yes I mean to answer your question very broadly, we are focused on exactly the topic you bring up, how to get better technically and how to get a better understanding technically because there are a lot of opportunities.

Duane Grubert – Susquehanna Financial

And then kind of along those lines to de-risk some of the uncertainties but still be playing in multiple places, have you guys talked about farm-outs at all?

John Richardson

There’s always the concept of joint venture, you know, there’s a number of people who are exchanging information and we’ve done that before. That would not be outside the realm of something that we would consider if the right type of attractive situation presented itself.

Duane Grubert – Susquehanna Financial

And just a little bit more on the manpower thing. What specifically do you guys see as a type of employee that you’re short on? Is it engineers or geologists or land men or what would you love to have a bunch of resumes on show up at your door?

John Richardson

We’re not understaffed as we sit here today. However, we’re a growing company and we have manpower projections and we do need, you know, our technical expertise in our company and the more the better. And so we have growth plans and we have plans to look for people in all the areas. We’re focusing, like you said, on completions right now. We’ll need some geology help in the future and we always need good quality engineers to get more, cheaper. So we’re always looking to grow.

James McManus

To give you an example of something we set out to obtain and did obtain is obviously with the cost of wells in the Delaware basin. Your drilling expertise, your drilling time makes a huge amount of difference. And one of the things we’ve been able to achieve in 3rd Bone Spring is a dropping in the number of days of drilling those wells from 90 days to 40 days. And part of that was people we had but part of that was expertise that we also brought in house. And so as Johnny said, we feel really good about the drilling side of things now that we’ve got the right expertise there to maximize the value there. And to the extent we can supplement what we got from the completion side, we can also work to do that as well.

Duane Grubert – Susquehanna Financial

And finally I guess I’d like to give you guys yet another opportunity to kind of fan the flames on the Avalon. Much of the by-side Clint that I am talking to about the Avalon has sort of written it off, you know, with your wet well and some disappointments both by you and others. Yet you guys correctly say hey I still have a large position there. Can you give us reasons, one more time, why to be enthusiastic, longer view anyway, about Avalon?

James McManus

Well here’s how I look at it. It is a much gassier play and I think Karl said it the right way. Gas prices back up in the $5 area do a lot of improvement to the Avalon area. Avalon is shallower and if you are able to get your completion cost and your well cost down a little under $6 million and you have a lot of consistency, you figured out the right kind of recipe, you can have something that could achieve in turns high double digit returns, maybe up into the low 20s. And if it became very predictable and very cookie cutter oriented like the Wolfberry, you could have a lot of running room there. That’s the hope for it.

It don’ts have, at this point from what we’ve seen, the kind of potential that the upper Wolfcamp might have or even the 3rd Bone Spring. But if you turned it into a much more predictable play like the Wolfberry, we had not a lot of variability in drilling cost, not a lot of variability in completion, you were able to hone that down, it could be a very nice adder.

John Richardson

And let me fan the flame just a little bit more. The Avalon’s going to be HVP first. We’re going to see it hundreds of times or we’re going to see it a lot of times out here. Gradually be able to build that database as we move forward. In the future that’s a good thing to keep our eye on. That’s a good adder in the future as James just pointed out, under the right conditions. We’re going to see it a lot, we’re going to get a better understanding of where and what it is.

Duane Grubert – Susquehanna Financial

Just in terms of following up a little bit on your down spacing comment, you mentioned that near Glascot you could see more down spacing possibilities rather than up there like in martin county. Do you guys see yourselves as being one of the leaders in pursuing finding that out or are you going to wait for the play to come to you? Who is it that’s going to try to down space it? Somebody else or you?

John Richardson

One of the things we’ve charged are technical teams here in the Wolf area this year as they begin to study that. I mean we’ve grown a lot here, we’ve been adding to our inventory. You know you do first things first. Now we’ve gotten the nice holding. We do like the area James pointed out because if you just look at the Wolfberry on its space, you see where Sprayberry production is stronger, you can get some nice drainage in the Sprayberry so you don’t want to down space that too much.

Having said that, even in the northern areas up in Martin and so forth, where that [advanced spacing] is less likely as we develop deeper horizons there, down spacing might come into play a little bit more and more. But where we really focus our comments on down spacing is down in Glascot and Regan where the Sprayberry may be a little less productive but we see the deeper the Wolfcamp decline, those things coming in and being a little more productive, we do see obviously intuitively we would think there’s where we should look to down space. And we’re going to start that steady. But as a rule, we’re still getting a lot of acreage HVP with our current drilling plans, getting infrastructure in, coding a lot of territory and the down spacing I think will begin as soon as we get done with those studies and get comfortable with it. But I don’t see it as something we need to do. Now we got a lot of primary opportunities, if you will, to date.

James McManus

You know the way I think about what Energen’s done here from a macro perspective is we basically valued some wolfberry properties we bought. We’re getting better than what we valued those properties results. We basically bought into the Delaware Basin on the 3rd Bone Spring alone and then acquired leases at fairly attractive rates early in the play. Both of these basins are chock full of multiple opportunities and the prospect of finding something beyond what we’re talking about delivering in our production targets I think is good because there’s so much potential and so much to do out here. And to get overly excited or pessimistic about one of these opportunities when there are multiple opportunities seems to me to be a little bit short sided when you think about the overall nature of this basin and how many times it’s come back to life and how many new plays have been developed.

I mean I’d love to tell you that we got in the Delaware Basin because we thought it had Wolfcamp potential. It wasn’t something we thought about. We didn’t value the Avalon. We knew the 3rd Bone Spring was there and we were very comfortable with what we were paying on that and we’re out performing our model there. And we’ve got two plays, one that hasn’t developed red hot yet. The Avalon play, but now the Wolfcamp play, which seems to be very, very attractive over in the Midland Basin and the question is does that same formation ability and characteristics translate itself to the Delaware Basin? So I’ve never been more optimistic about our ability to hit our targets and about our opportunity set of things to do beyond what we paid for when we moved into these properties.

Duane Grubert – Susquehanna Financial

Great. Thank you very much.

Operator

Your next question comes from the line of Sean O’Malley from WEDGE Capital. Your line is now open.

Sean O’Malley - WEDGE Capital

A little earlier one of the questions was asked on why the development was focused on the west of the river despite the lack of infrastructure. And I think you mentioned you had some leasehold requirements that needed to be met. Besides the lack of infrastructure did you also have any geological suspicions about the area west of the river or was it purely just the lack of infrastructure on the west side?

James McManus

We did not have any indications that it was going to be any different than what we saw on the east side. In fact as Johnny remarked earlier, the bone spring formation looks pretty much the same on that side. The difference is we’ve got some type of conduit, some type of change that’s introducing more water into the system then we had on the eastern side and we did not suspect that.

John Richardson

And neither did anyone else. I mean we’re not the only people over there and I’m sure you’ve heard comments from others. But we’ve got wells that look very similar to other wells that have been drilled in the particular area we’re talking about.

Sean O’Malley - WEDGE Capital

Okay. And in terms of the drilling plan for this year, how much of it is directed towards the west side to Puglise acres versus how much of it would you be concentrating in other areas back?

James McManus

At this point it’s all contemplated to be directed on the eastern side over the next two years. The acreage that we went to hold on the western side was acreage that was expiring in like 60 days if we didn’t drill. It was acreage that was a part of the Sand Ridge package that we didn’t value at all because we weren’t sure we could hold it. So we didn’t give it any value but yet we were hoping we were going to hold acreage that was going to be identical to that just across the river and it turned out to be a little different because of all the things we’ve discussed about the water over there versus an oil cut being lower over there versus what we’ve encountered on the eastern side.

We don’t have any expiring acreage in the next year on the western side that we need to run over there and hold.

Sean O’Malley - WEDGE Capital

Okay, great. That’s exactly what I was going to ask. Thank you very much.

Operator

Your next question comes from the line of Brian Lively from Tudor, Pickering, Holt. Your line is now open.

Brian Lively - Tudor, Pickering, Holt & Company

Thank you for the details, just a few clarifications. On the [Middlin Basin] acreage and specifically in Glasscock, have you guys considered drilling for the [Klein] yet in terms of your horizontal opportunity set?

John Richardson

We complete the [Klein] vertically when we’re out there and we see the right characteristics. The [Klein] horizontals are something that we are studying along with the Wolfcamp horizontals in certain areas of our acreage, and we have seen some encouragement from others or some rumored encouragement. We haven’t seen a lot of data but yes, we have it, we complete it. We’re going to also study, look at that to see if it would be better developed horizontally and that’s something we will be studying as we move along in the near future because we do see it, we completed a lot in our vertical section but it might be one of those areas that would better respond horizontally. We’re doing an evaluation on that.

James McManus

Brian, this is James. We’ve got a good bit of acreage out there. There are other operators where we may wind up participating in a horizontal well with somebody next year; it wouldn’t surprise me if that happens because there’s so much going on out there.

Brian Lively - Tudor, Pickering, Holt & Company

It just seems like there’s so much commentary on the Wolfcamp for good reason but there’s quite a bit of wells now even from some of the bigger companies that have drilled some horizontals in that area. So it seems like it could be interesting. Not to beat a dead horse here but I did have a very specific question on the Avalon. In terms of holding the oil rates, it looks like the gas stays constant and the oil came down. Is that a nature do you think of the rock itself? Does this thing just kind of gas out? Or is it a mechanical type issue?

James McManus

Well, the suspicion that we have is that we may have, and we don’t know this, but we may have outsmarted ourselves by making the frac quite a bit smaller than some of the others that we see in that particular area. Again, the thought was that we could get a more concentrated frac and eliminate some of the water but we believe we might not have gotten the type of conductivity by using the smaller frac that caused the oil drop off to be a little quicker, because frankly, some of the other wells up in that particular area that are close by saw the oil drop more over again a six-month period than over just a few weeks. I do think the play is gassier, I don’t think there’s any question about it; and I think as you move further to the west it may actually get gassier as well. John, have you got anything you would comment on this?

John Richardson

No, I think you’re exactly right, James. You could interpret the data we got as just a conductivity problem, gas being easier to move in the formation than the liquids. And a lot of this is condensate anyway – a lot of the liquids are going to be condensate off of this. But I think it may be indicative of just our recipe, our approach to this as much as anything else.

Brian Lively - Tudor, Pickering, Holt & Company

But do you think that you could have drawn down pressure fast enough to actually get a relative perm effect where you’re seeing gas in the reservoir itself at this point?

John Richardson

Oh no, no – no. I think it’s more that the well basically underperformed our models and offset… It’s an okay economic well as it stands today versus our AME costs but it’s not what we would have expected, and that may be indicative of just not getting enough conductivity in the reservoir.

Brian Lively - Tudor, Pickering, Holt & Company

Okay, that’s helpful. And then the last question, and you guys mentioned it in the prepared remarks but in terms of a shift I think between the service and the EMT guys the Permian’s still ramping up pretty well. Are you all seeing it now kind of in the play of your vertical program or your horizontal program? Are you starting to see at least the cost creep not going up or are you to the point where you’re starting to see it come down?

James McManus

Well, a lot of our… Well, it gets a little bit difficult here, Brian, because our hearing costs are going to be locked in. As you know, they’re not the majority of the cost of the well – a good bit of it’s completion – and some of the costs in certain contracts will have kind of floating with the price of oil. I’m going to get Johnny to address that since he’s followed it.

John Richardson

Yeah, I think if we just look at the history, recent history, we see that rate of increase slowing. I would anticipate that we would not see that rate continue to go up. I would like to say that we’ve seen the bulk of the cost increases we’re going to have. Now, having said that there’s still some very sensitive areas out there when it comes to stimulation. Sand is still in short supply; there’s a lot of horsepower constraints out there. But I will say to you that I think we’ve seen the bulk of the increase. I would expect to see prices stabilize sitting here today. As far as a decrease, I don’t think we’re there yet. If we see some decreased activity I think we may see some decreased prices but I don’t think that’s going to happen in the Perm.

Brian Lively - Tudor, Pickering, Holt & Company

Got it. Thanks a lot for the comments.

Operator

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

Mario Barraza - Tuohy Brothers

Hey guys, thanks a lot for the information today. Just one question about the oil price realization in the Permian. Even though NYMEX prices were up from Q3 to Q4 it looks like your average realized sales price went down. Can you just talk about that for a second? What was going on there?

James McManus

I’m going to kick that one to Chuck while he refers to his notes.

Chuck Porter

I’m not sure we’ve got a lot of clarity on that. Our basis differential is relative to the budget. We’re (inaudible), we’re actually better than what we thought we would have been with our budget. I think the salary differential for the whole year was a negative [$2.60] and it was actually a little bit less than $1.00. The average NYMEX for the quarter was a little bit less than $94 I believe. But we had a lot hedged and I’m not exactly sure that I can provide you much more color than that.

Mario Barraza - Tuohy Brothers

Okay, all right – that’s really all I had.

Operator

We have a follow-up question from Tim Schneider with Citigroup. Your line is now open.

Tim Schneider – Citigroup

Hey guys, just a quick follow-up on the third month spring again. I know you said you know, capital over the next two years only to the eastern portion of that play. But if I look at the western portion, it seems you only drilled really close to where the river actually runs through. You still have a decent chunk of acreage along the fringes. Is there any delineation wells you’re going to be drilling out there, any test wells on the stuff; or is there no urgency at this point?

James McManus

Yeah, as a matter of fact we’ve just actually done a couple of vertical wells over there to look for the presence of the Wolfcamp and Avalon formations, and also, Tim, the Bone Spring. And we were pleased with the results of those vertical wells so we have done a little bit of undertaking to see what might be available over there. I mean we’re not completely quitting our efforts to try to figure out what we’ve got in the total basin; it’s just our primary drilling efforts are going to be concentrated on the eastern side.

Tim Schneider – Citigroup

Got it. And do you think you’ll have an update on that progress over the next couple of calls here?

James McManus

Which progress are you talking about?

Tim Schneider – Citigroup

What you’re seeing in these vertical wells.

James McManus

In fact I don’t mind letting Johnny, I’ll put him on the spot here and I don’t mind letting him comment a little bit on what we have seen in the vertical wells. We have not completed them; we have drilled and cored and [logged] them but I don’t mind sharing with you what we’ve seen.

John Richardson

Yeah, basically as James has pointed out we are encouraged from just what the formations look like tetra-physically to us across the plate generally. We got what we expected or what we wanted to see. As we’ve said, that might be a little misleading on productivity so we’re going to do some testing out of these vertical wells to determine what might be some contributing factors there, and I wouldn’t venture to tell you when we would have that data or how we would disclose it, or whether we would just use that to piggyback with a development program.

Tim Schneider – Citigroup

Alright, thanks guys.

Operator

We have no further questions in queue. I turn the call back over to James McManus.

James McManus

Thank you, Katie. A lot of good questions today and we hope we were able to add a little bit more clarity to things, and I appreciate your attention and have a great day.

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