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Energen Corporation (NYSE:EGN)

Q2 2011 Earnings Call

July 28, 2011 11:00 am ET

Executives

Julie Ryland – VP, IR

James McManus – Chairman and CEO

John Richardson – President

Chuck Porter – CFO

Analysts

Gabriele Sorbara – Keybanc Capital Markets

Tim Schneider – Citigroup

Carl Kirst – BMO Capital

Becca Followill – US Capital Advisor

Craig Sheer [ph] – Tony Brothers [ph]

Collin [ph] – Harvard [ph]

Dwayne Griffith [ph] – Susquehanna [ph]

Operator

Good morning. My name is Mitchell and I will be your conference operator today. At this time, I would like to welcome everyone to the Energen Corporation 2011 second quarter 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. Vice President of Investor Relations, Ms. Julie Ryland, you may begin your conference.

Julie Ryland

Thank you, Mitchell and good morning. Today’s conference call is being held in conjunction with Energen Corporation’s announcement yesterday afternoon of the results of operations of the three, six and 12 months ended June 30, 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 the 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. A lot of really excellent things to talk about today; good second quarter numbers; increased earnings and cash flow guidance for 2011; a big jump in Energen Resources’ 3P reserves that still does not include Avalon shale potential. A first look at capital and drilling plans for 2012 and 2013 and how they translate into double-digit production growth. Let’s go in reverse order.

Energen Resources’ preliminary and development plans for the Permian Basin support capital investment of approximately $800 million in 2012, $765 million in 2013. In our other areas, the San Juan, Black Warrior Basin, and North Louisiana, all of which are predominantly natural gas producing regions, we are looking at capital investment in the neighborhood of $115 million in 2012 and $125 million in 2013.

In the Permian, our preliminary plans for 2012, include drilling a 155 net Wolfberry wells, 30 net Bone Springs wells, six to seven net Avalon shale test wells. In 2013, the drilling plans look very similar for these plays at this point in time, 160 net Wolfberry wells, 30 net Bone Springs wells and six to seven net Avalon wells.

In the Delaware Basin, we anticipate going from our four-rig program to running an eight-rig program beginning early next year. We likely will continue using seven, maybe eight rigs in the Wolfberry Trend. Obviously, this increase in rigs in the Bone Springs is due to our increasing confidence in this particular play.

Based on these preliminary capital and drilling plans, we could see our 2013 oil and natural gas production total 12 to 13 million barrel of oil equivalents. That would be a 70% to 85% increase from 2010 levels. I would point out that previously we were estimating a 60% increase. So, again, with our increased confidence in the Wolfberry performance and Bone Springs, we are now increasing that to 70% to 85% increase from 2010 levels.

In terms of total production, we are currently estimating double digit organic increases in 2012 and 2013. Our estimated 2012 production is 23 to 25 million barrel of oil equivalents and our estimated 2013 production is estimated to grow to 25 to 27 million barrel of oil equivalents; there is table in the news release that breaks down our preliminary 2012 and 2013 production estimates by commodity.

The model then for our major areas of focus Wolfberry and 3rd Bone Spring are detailed in our news release and the data is based on our results today, our internal engineering analysis, our preliminary drilling plans in 2012 and 2013 is sort of a go-forward model.

We treat reserves and well cost and product mix a little bit as you and we expect that to continue to change as get more data. Let’s go ahead at this point and look at our results in 2011. In the Wolfberry, we drilled 75 net wells so far this year; 67 have been completed; eight awaiting on completion; 54 producing; 80 net wells remain to be drilled this year. These wells are very producers, very predictable. Initial rates from the 54 producing wells drilled and completed in 2011 have exceeded our model IP risk rate of 55 barrels of oil per day and a 110 Mcf per day of wet gas. They’ve exceeded our model by 25% to 30% so far.

We have completed, in the Bone Spring, we completed 10 net Bone Spring wells so far this year; two were drilled in late 2010 and eight in 2011. Two more wells are awaiting on completion and we plan to drill those wells, net wells by year-end. The only stabilized rate of the 10 producing wells completed in 2011 is approximately 300 barrels of oil per day and 900 Mcf per day of wet gas. This exceeds our model by 10%, 15%. And we will talk a little bit more about this in the Q&A detail, but our last four wells have exceeded that 300 barrels per day of production.

In the Avalon, as you know, we drilled a step-out well in Winkler County to test the far-east portion of our leasehold. This is acreage that we don’t expect to be held by the Bone Spring production and really is in the far eastern edge where people think the Avalon could be productive.

We had some completion problems with this well. We are not currently happy with the list we’ve got in place. Despite these issues, the well has been producing over the last 45 days some 100 to 110 barrels of oil a day, and 400 to 600 Mcf per day of wet gas. Our engineering analysis suggest that by correcting the completion problems and improving the list system, production could well improve significantly to make the Avalon shale economically viable in this area of the basin. We are encourage by what we are seeing in this particular well. In the eastern section of our acreage, we will spud another Avalon well by year end and hopefully, correct some of the problems we experienced on this well.

Meanwhile, we’ve drilled a new Avalon test well in western Reeves County on the far western side of our acreage. This is waiting on completion and we are drilling another Avalon test well in Loving County north of our acreage. So, with only one producing Avalon well under our belt, we obviously don’t significant data to put out a model that we are comfortable with. This activity our current drilling plans for only 13 Avalon wells over the next two years. However, if the initial results of those 13 wells are positive, as we become more comfortable with this particular play, our preliminary Avalon plans could be accelerated. We are obviously not accelerated that much in the model we put out for 2012 and 2013.

Regardless of our preliminary capital plans for 2012 and 2013, continue to underscore our focus on oil and liquids production in the Permian Basin. For another two years, we are looking to invest approximately 85% of our capital in the Permian Basin with particular emphasis on the Wolfberry and Bone Spring plays, as well as testing the Avalon. We are very pleased with the results of our Wolfberry program. We continue to learn more each day about the Bone Spring play and while the well results in the Bone Spring have varied, we are encouraged by the overall program to date and by our prospects of having a very successful Bone Spring development program.

Over the two years, we plan to continue testing the Avalon shale and look forward to gaining sufficient data points to fully assess that opportunity.

Let’s turn next to our probable and possible reserves, as you may recall, we reported year-end 2010 proved reserves of 303 million barrel of oil equivalent and probable and possible reserves of 388 million barrel of oil equivalent. We considered the P2 and P3 reserves to be conservative, because they did not capture any of the Bone Spring acreage we picked up at the end of 2010 and early 2011 nor do they include Avalon potential. So, we capture these additional potential reserves, outside reserve engineers for independent reserve review.

We now have significantly more probable and possible reserves, that number has moved to 591 million barrel of oil equivalent, that makes Energen Resources’ 3P a record 894 million barrel of oil equivalent or in terms of gas, 5.4 Tcfe. The new probable and possible reserve total still don’t include Avalon reserves, Ryder Scott that did not include some 64 million barrel of oil equivalent of Avalon shale potential at this time really due to limited, basin-wide well data. We expect that to change with the test that we are drilling and others may be drilling, and if successful, we’d hope to add that to our 3P as well.

Bone Spring additions increased our possible reserves by 63 million barrel of oil equivalent. This puts our total Permian Basin probable and possible reserves at just over 200 million barrel of oil equivalent. Our possible reserves got the biggest boost from a gas base, the Mancos, our Niobrara Shale in the San Juan Basin, 130 million barrel of equivalents together with the existing possible reserves in the Mancos of approximately 52 million barrel of oil equivalents. Our 3P reserves include more than of Mancos Shale potential and there have been some good things happening out here. But, as we previously stated, we don’t have any plans at this time to pursue the Mancos at current gas prices. All this potential is held by production from other places in the San Juan; we are glad to have it officially in our inventory. We certainly hope that we will get to pursue this trend in San Juan at some time in the future.

Next up is earnings and cash flow guidance. Yesterday, we released our 2011 guidance ranges for earnings and after tax cash flows to reflect higher assumed commodity prices applicable to our unhedged production for the remainder of the year. Our new earnings guidance is $3.60 to $4 per diluted share and our new after tax cash flow guidance is $690 million to $790 million. The new price assumptions we would lay for the remainder of 2011 are $4.50 for gas, $95 a barrel for oil and $14 per gallon for NGLs.

The new guidance also reflects year-to-date results, recent hedge additions, commodity prices and basis differentials, slight increases in LOE and DD&A, and decreased G&A. These are the key assumptions embedded in our guidance, are listed in our news release along with sensitivities of our earnings and cash flows to changes in commodity prices.

With respect to capital, Energen Resources’ capital investment in 2012 estimated to settle approximately $875 million or $92 million more than the prior estimate. Almost half of the increase, $42 million is related to the acquisitions of small Wolfberry property and unproved leasehold in the Bone Spring, Avalon Trends.

Another $20 million is associated with increased Wolfberry drilling cost, largely due to service cost increases and additional frac stages that we performed on the wells.

New facilities totaled $30 million including additional fake models in the Wolfberry area, a water injection system at (inaudible) two water disposal wells and gathering and disposal lines to facilitate Bone Spring production. This well cost settle some $30 million.

Before I turn the program over to Chuck to talk about the results of the second quarter and year to day, I want to mention that our hedge positions for the remainder of ’11, ’12, ’13 and 1’14 are detailed in our news release. I would notably continue to pursue hedging opportunities in forward years as new production is added. Within just the last week, we were able to add oil hedges in 2011 to 2014 at NYMEX prices between $100 and $103 per barrel. We also added natural gas hedges in 2014 at NYMEX equivalent price of $5.42.

We expect to invest considerable capital over the next several years. We’ve already laid down our preliminary plans for 2013 for you here today. The hedges we have in place and that we hope to keep adding will help to ensure that we maintain our excellent financial strength and continue to provide with us the financial capacity to pursue both double-digit organic growth and acquisition opportunities.

Actually, I think the company really is better positioned than we are right now, we are making the transition to becoming a heavily liquids based company. We’ve got great opportunities in a multi-pay Basin, in the Permian and I think we are very excited about what the future holds for Energen.

At this time, I would like to turn the call over to Chuck Porter, our Chief Financial Officer for a closer look at our second quarter and year to date financial results. Chuck?

Chuck Porter

Thank you, James and we will be quick so we can get to our Q&A. For the three months ended June 30, 2011, Energen’s net income totaled $63.3 million or $0.87 per diluted share. This compares with net income in the same period a year ago of $55.5 million $0.77 per diluted share. The file period included a $10 million or $0.14 per diluted share non-cash after tax write-off on the leasehold.

Energen Resources’ net income in the second quarter of 2011 totaled $63.1 million as compared with reported earnings of $56.8 million in the same period last year. Excluding the non-cash write-off in the prior year second quarter, Energen Resources’ net income declined $3.7 million.

Despite an 8% increase in production, earnings were negatively affected by lower realized natural gas sales prices, some increased following some higher DD&A expenses. Production in the second quarter of 2011 totaled 5 million BOE, our liquids production increased 19% over the same period last year, while natural gas production was relatively flat. Permian Basin production increased 21% in the second quarter of 2011 to 1.8 million BOE. This was primarily due to our 2010 acquisitions and the associated development.

The San Juan Basin production increased 6% due to new well development and better than expected performance from certain proven cold wells. Production in the other areas showed small decreases in actual volumetric terms. This simply reflects our capital focus in the Permian Basin and normal property declines.

Our unit LOE in the second quarter of 2011 increased approximately 9% from the same period last year to $12.98 per BOE. Base LOE and marketing and transportation expenses increased about 5%, largely due to increased repair and maintenance expenses and higher gathering system costs. Commodity price driven production tax has raised 24% on a per unit basis. DD&A expense per unit in the second quarter of 2011 increased 3% over the prior year second quarter to $10.96 per BOE and per unit G&A expenses increased 8% in the current year second quarter to $3.02 per BOE, largely due to performance based compensation and increased labor cost.

Of our gas generated net income of $43 million in the second quarter of 2011 as compared with a net loss of $23 million in the same period last year, the utility remains on track to earn (inaudible) of return on average equity at the end of the rate year.

For the six months ended June 30, 2011 Energen’s net income totaled $157.6 million or $2.18 per diluted share. This compares with net income in the first half of 2010 that total $173.3 million or $2.39 per diluted share and included the $10 million non-cash write-off (inaudible).

Energen Resources’ net income in the year to date 2011 total $112.8 million as compared with $128.4 million in the same period last year, now the gas net income of $44.4 million in the first half of 2011 was up $0.5 million from the same period a year ago. For details on the year-to-date and the trailing 12 month, I would refer you to yesterday’s news release. And with that James, I’ll turn it back to you.

James McManus

Thank you, Chuck. Let’s move now into Q&A. To facilitate this, I would like to turn the call over to Mitchell for instructions. Mitchell?

Operator

(Operator instructions) And your first question comes from the line of Gabriele Sorbara from Keybanc Capital Markets. Your line is open.

Gabriele Sorbara – Keybanc Capital Markets

Good morning, guys.

James McManus

Good morning.

Gabriele Sorbara – Keybanc Capital Markets

First question, I guess going to your opening remarks, you talked about the last four Bone Spring wells having better IPs [ph], can you discuss those results?

James McManus

Yes, I think we can. We had averaging somewhere around 270 to 453, so the average on the last four was about, let’s give that for you real quick, calculate that real quick, it’s 300. Part of what we’ve got built into models, let me talk a little bit is, we got the entire acreage being developed. So, we do have – this is what we plan to drill in ’12 and ’13 and we do have some areas that are pretty far out from the core built in. So part of our risking, pulls those rigs down a little bit from what we might be experiencing in the heart, it’s like that 350 the last four cost.

Gabriele Sorbara – Keybanc Capital Markets

Is that including the gas portion?

James McManus

No, that’s just the oil.

Gabriele Sorbara – Keybanc Capital Markets

Okay.

James McManus

I’ll give you in just a second, let’s calculate it a real quick for your, Gabriele. Go ahead.

Gabriele Sorbara – Keybanc Capital Markets

And also, just you guys report the wet gas, can you guys give me the uplift from the processing on the gas portion or maybe the Btu value would help?

Chuck Porter

The Btus are running around 1300 a little plus, we currently unfortunately are able to market a lot of this gas right now. We are still talking about moving that to the plant, so I can’t give an exact NGL split at this point. As we move west, literally do not currently have a gas transportation system that should be up and running the first of – early in September.

James McManus

Yeah. We’ll have a better feel September 1. Right now, we are winning the gas west of the river and just producing the oil.

Gabriele Sorbara – Keybanc Capital Markets

Okay, great. You guys provide EURs – I think you took down the top end from 500000 to 450000. Did those EURs include the uplift from processing or is that just the wet portion?

Chuck Porter

I am sorry, I was looking at this but, could you repeat that for me one second?

Gabriele Sorbara – Keybanc Capital Markets

Sure. Just in terms of the EURs in the third Bone Spring, it looks like you lowered the top end from 500,000 barrels to 450,000 barrels, do those EURs include the uplift from processing?

Chuck Porter

Yes, they will. They will, yes.

Gabriele Sorbara – Keybanc Capital Markets

Okay.

James McManus

Currently, to answer your earlier question, the average on those last four has been 1.3 million a day of gas.

Gabriele Sorbara – Keybanc Capital Markets

Okay. And also, on the first four wells, you guys announced last quarter. Can you guys provide 30 or 60 day rates or some sort of production history?

Chuck Porter

Well. There were – we report until the state and we don’t have those handy right now, but as we get these wells up and to sales, there will be public data.

James McManus

We’ve been looking right now, Gabriele, to announcing a basket of wells, because we’re still sort of in the learning stage of Bone Spring. I will give you an example. We got one we drilled to the west that is just low as 152, there was the D Sand [ph] completion only. One of the things we are looking at and one of our high rate wells, I think one at 452 Sand [h] completion. We think really everything west of the river, we are going to do it (inaudible) and so you really can’t look at any one particular well, because we’re still learning about this particular play. We probably wish they were probably about two or three these in our number, maybe four that we wish that we drill as excess now that we’ve kind of seen that it’s probably better to go in the X sand [ph] and get the D sand [ph] along with X and possibly get a less water as well. So, I mean, we are real early in this. So we are really looking at instead of well by well, we’re really disclosing basket of well results.

Gabriele Sorbara – Keybanc Capital Markets

Okay. And in terms of driving down cost on the Bone Spring, I think you talked about 7 million well cost. How low you think that you guys can take the cost?

James McManus

Well, I hope we could take them low, I will tell you this. I’ve got Johnny sitting to my left here, this is James, but the last three have been slightly under seven. So we are making some head way in that regard. I think our target is six-and-a-half. I don’t know if we’re going to hit that number, but we’re trying to move towards it.

Chuck Porter

Our original target was of course seven-and-a-half this year, seven next year, and we are on the seven million target, we would like to keep moving downward. Our days are falling nicely. Our efficiencies are going up. We have a target on drilling days of somewhere around the forty day mark, or maybe a few more and we’ve met that on the last well, last three, as you just pointed out, all been under the $7 million mark. Cost, the reason that question is hard to answer is we’re getting much more efficient, we’re driving cost down, but we know that the service costs are also escalating. So where that middle ground is, I don’t exactly know but we continue to drive our side of the cost down.

James McManus

Gabriele, I am leaning hard on the sky to the left of me, by the way, I just want to let you know (inaudible) answer.

Gabriele Sorbara – Keybanc Capital Markets

Great. In other people’s testing zones, such as the Wolfcamp, (inaudible) any plans to test any other zones later this year or next year?

James McManus

Well, yes, I think we’ve talked about that a little bit. Let me color it a bit, I’ll let Johnny chime in. I think that our acreage is going to contain Wolfcamp potential. I think if you look at Cimarex in particular and their target area, they talk about the Wolfcamp, it includes a good bit of our acreage particularly in the Delaware Basin to the south and west. And that’s something that we will be looking at and watching. We know that the Cimarex drilled has been rumored to be a pretty successful, Wolfcamp well, can’t confirm that, but the clearly the advantage to being in the Delaware Basin where we’re is the stack phase, and I mean don’t only talk about really the Bone Spring, we talked about the Avalon. And we not really talked a lot about the Wolfcamp, but I think there a lot of people very excited about the upper and lower Wolfcamp in the Delaware basin and that is something that we’re studying very carefully. And again I think if you believe some of the math that you’ve seen about potential, I think we are going to have some acreage that lies within that potential.

Chuck Porter

And I will add that we do realize that a portion of our acreage is in the Wolf, Bone play and as James mentioned and there is the produce areas, the emerging Wolfcamp horizontal play, that is basically the same acreage, we haven’t drilled well in that area. We will need to see basically what’s most the prudent use of capital whether to develop that horizontal Wolfcamp or to lay more toward the Wolf, Bone type play.

Gabriele Sorbara – Keybanc Capital Markets

Okay. Any thoughts on the horizontal Wolfcamp in the Midland basin?

Chuck Porter

Not really. We still consider the Midland basin, the right approach to that so far has been verticals and the traditional Sprayberry [ph]. We continue to look at the Wolfcamp, especially in certain areas of the Basin, for it – potential however that may is a little south of us. So we think that where we are positioned in the Midland Basin, our approach with the traditional Wolfberry play is the still the right one.

James McManus

Yeah. I would add this, Gabriele. We are pretty far north of where El Paso, Petrohawk, Conoco are playing, that particular Wolfcamp in the Midland basin. But down, if you look at our map, our recent acquisition was of Fives Stones and some of our acreage down there, particularly the Midland Basin is big. But if you look at the southern port portion of our acreage, we do think that acreage probably has some possibility being down spaced 20 acre from 40 to 20, that’s probably our best acreage from that perspective because probably not all drained. So that’s probably more opportunity there we see right now than we see at horizontal Wolfcamp.

Gabriele Sorbara – Keybanc Capital Markets

Great. I appreciate the color. And just down over to the Avalon shale, can you guys talk about the conclusion issues encountered on that well?

James McManus

Yes. We absolutely do and will talk about it, because just frankly now we’re encouraged by what we see there. And I’m going to let Johnny talk a little bit about what we think can happen to us in spite of all those difficulties that we had, that well has been very encouraging. Johnny?

John Richardson

Yeah. I will just walk through a little bit. This well was completed mid March. We did a 10 stage frac. Two of those stages were actually in the heel toward the upper portion of the Avalon. And in retrospect, we had a little communication problem with some overlying strata. Consequently, the well produced mainly from those two fracked, the two stages we know that because of the main portion of lateral was bridged off. So we had – we need to go in and squeeze those upper two stages, which took approximately a month to get that completed. So we did really start to produce this well till mid-April, it flowed for about a month and then it loaded up and dotted away (inaudible) and got good success on loading the well with the rod pump. However, the wells is a little too strong for that, we had to put them and we are falling around which wasn’t efficient way to flow the well. So we didn’t went back in with a submersible pump and a electric submersible.

And in those things, you have to get those lines out right. We’ve been on that about a month. We don’t think we have got our efficiencies lined out just exactly. I’ll also add that leaving 9,000 barrels of completion on this well for a month was, we know couldn’t have helped it. So we do think we can, number one, do more efficient job of fracking. We are looking at different fracking designs, a little bit better treatment for the well. We can do a better job of turning it around and completing it early. And we are working with this well to understand the lift in this part of the basin. And what we need to do all those things combined, we’re, as James said, encouraged about the way this well performed in the face of all those adversary instances. So we think there is plenty of reasons to be optimistic about the future of Avalon over here and to try it again.

James McManus

Yes, we’re really trying, Gabriele, to define the eastern most boundary of the Avalon. And that well is probably – nobody shown that far to the east. And the next two we’re drilling, we’ve got one to the far west; we’ve got one to the North which is a little bit more traditional. We haven’t completed those wells yet, but everything we see on laws and data looks very good on those particular wells. So I mean we really picked our riskiest one to drill first and have really a calamity of things on the completion. As Johnny said we left the frac fluid on the formation for almost a month even after all of those difficulties, the well is still producing 100, 110 barrels a day. We think we need about 200 barrels a day from these wells to make them economic along with the piece of gas. And so, we are going to another shot at it.

Gabriele Sorbara – Keybanc Capital Markets

All right. I just have one final question, can you just speak towards the rock quality and maybe the thickness, given this well was really far east?

James McManus

Yes, I’m going to Johnny talk about that, because we don’t have both the upper and lower Avalon to the east. Johnny?

John Richardson

Right. We are – gross thickness, that’s down a little bit and I apologize, I can’t be real specific. I don’t have those numbers in front me. But we – as James said, we don’t have the lower member of the Avalon. We did really the targeting right, the lower portion of the upper member is actual target. We overall don’t have average net feet, but only – we have, let’s say, 80% of the net feet they see out in the heart of the basin. So, we are comfortable that we have enough to complete, enough to go after that should perform well, and our analysis shows we’ve got plenty of reserves in place. We just got to be a little more efficient about listing and moving those – the hydrocarbons around.

Gabriele Sorbara – Keybanc Capital Markets

Okay. Great. I’ll jump in queue. Thank you, guys.

John Richardson

Thank you.

Operator

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

Tim Schneider – Citigroup

Hi, guys. Thanks for taking my question. First question I have is on CapEx side, you’ve identified around $800 million in 2012, so when I just look at the well counts you put in the release, that’s around $575 million, I’m just wondering how should I think about that delta, I think it’s $225 million, is that just for legacy kind of water floods, is there some infrastructure in there, is there acreage purchase assumptions?

James McManus

Well, there is no acreage assumption in there. You do know we’ve got the gas properties that we stated were $115 million and I think $125 million, so you got to back that out of the numbers. And then we do have our legacy Permian Basin properties in there as well.

Tim Schneider – Citigroup

Okay. So, the $800 million does include the gas properties?

James McManus

The $800 million does not.

Tim Schneider – Citigroup

Okay.

James McManus

No, it doesn’t.

John Richardson

Yes, it does (inaudible) $100 million or so in the gas properties and $115 million or so in the legacy properties.

Tim Schneider – Citigroup

Okay.

James McManus

Well, let’s check that real quick and see, we’ve got so many numbers, Schneider, in here. Go ahead, Julie.

Julie Ryland

If I could, I think we are talking different things. The Permian capital number is different from the everything else number. So, you have to add those together to get total company capital.

Tim Schneider – Citigroup

Yes, because I thought the Permian was $800 million on its own by that –

James McManus

It’s going to be legacy Permian, it’s going to be our, it’s going to be our exiting water floods and everything else, exactly right.

Julie Ryland

Permian is $800 million.

James McManus

Just look at 2012, you got –

Julie Ryland

Permian at $800 million and everything else at roughly $115 million, so the total company for existing properties of $915 million.

Tim Schneider – Citigroup

Okay, perfect. That makes sense. Have you guys put out yet how many remaining locations you have in that kind of legacy Permian position?

James McManus

We’ve not.

Tim Schneider – Citigroup

Okay.

Tim Schneider – Citigroup

But have that number.

John Richardson

It’s John, and just to go back and clarify in our total capital numbers, I mean, we have – we initially made a small additional Wolfberry acquisition and as we’ve gone along this year, we have incurred some additional unproved leasehold that we’ve incurred in the capital budget. So, that is going to be.

Tim Schneider – Citigroup

Okay, guys.

James McManus

2011, not in 2012.

Tim Schneider – Citigroup

2011 and 2012?

James McManus

For 2011, yes.

Julie Ryland

We don’t budget or make any kind of assumptions surrounding unproved leasehold acquisition or regular property acquisitions past that acquisition.

Tim Schneider – Citigroup

Right.

James McManus

There is some in 2011, but obviously we did in 2011, but not in 2012.

Tim Schneider – Citigroup

Why is the CapEx declining if I look at 2013 and production certainly up?

James McManus

Well, a good bit of which you drill in 2012 comes on line in 2013, 2013 is a long way out there. That’s just on what we have on table to do right now. I just think as we work our way through the remainder of ’11 and ’12, the ’13 number will go up, that when we draw it out, that’s what it comes out to be.

Tim Schneider – Citigroup

Okay. Then with the respect the Avalon wells, you think you have results on the Q3 (inaudible) the ones you are drilling right now?

John Richardson

It’s possible, it’s possible.

James McManus

These are pretty long flow backs on these wells. We hope so. If we do, we’ll it share with you.

Tim Schneider – Citigroup

And the last question I had, can you just speak to crude quality of the Bone Spring, Wolfberry and the Avalon and how that compares to the stuff in the legacy? Does it –

James McManus

I’m going to let Johnny talk about that, but I think it is sweeter.

John Richardson

Yes, in general terms, they are a good quality gravity and we are sweeter than we are in the legacy. Basically, all the legacy is sour, from our water floods and so forth. So, this well is a little bit better quality out of the Bone Spring and the Wolfberry.

Tim Schneider – Citigroup

So, you will get WTI price for that?

John Richardson

Yes.

Tim Schneider – Citigroup

Okay. Perfect. That’s it for me. Thank you.

John Richardson

Thank you.

Operator

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

Carl Kirst – BMO Capital

Thank you. Good morning, everybody. Nice results. I think a lot of my questions were hit, maybe James, I just want to clarify something, you were talking about the Avalon well, and the Winkler, the stuff off the east (inaudible), did I hear you correctly say that in order to kind woo the economically viable, we need to have roughly 200 barrels of oil, plus gas, maybe call it 300 all it –?

James McManus

Yes, that – we are looking at 200 max, so we need to double the oil rate from where it is at 100 to 110 to 200 and then I think the gas portion, we are looking at somewhere between 500 and 700 a day, but it’s really driven the oil piece as you might imagine, but we still need the gas light too, but the gas light is still not pretty good, it’s the oil we need to double up on.

Carl Kirst – BMO Capital

Okay. Fair enough. And then just on that and understanding that, I guess, the stuff is not to be held by production with the Bone Spring, I mean, at what point do you wind up starting to lose some of that acreage, and I’m just –?

James McManus

Well, we – yes, some of that is three, some of that is five years, some of that started a while back, but basically the reason we are going to drill another well out there hopefully this year is to kind of figure out what our attack plan would be if we turn that into an economic play out there. I think we can hang on to it. I’m going to turn it to Johnny here, I think we put it together a plan that allows us to, and of course, you are exactly right. One of the reasons we went out there and drilled Avalon is that acreage really doesn’t in our view yet have any other potential other than Avalon and unless that changes, we would need to figure out what to do so that we don’t lose it. Johnny?

John Richardson

Yes, we have a template to where we can hold this acreage provided we have encouraging results in the near future from (inaudible).

James McManus

I would like to make this point while you are on the line as well, we really are ratcheting up things here a good bit, I don’t want that to be lost and everybody. Our last testament again was to take 2010 liquids production about 60% by 2013, we are talking out 70% to 85% and our commitment to the Bone Springs is obviously solidified with us going from four rigs to eight rigs. And yes, we don’t have a lot of Avalon shale built in here. So, should those results start to become positive and were to able to ramp that up, there’s a good bit of upside. I just can’t think of a better time, we’ve never had this kind of organic production growth, this type of liquids growth, these types of opportunities that we are looking at, doesn’t include what could happen in Wolf camp, record 3P reserves for the company. I mean, I am pretty excited about where we are, want to convey that to you all.

Carl Kirst – BMO Capital

That’s great. And maybe on that, and you guys have always sort of had sort of acquisitions in your DNA, you’ve had obviously a phenomenal track record, as we sort of ramp up the spending, we go after these organic opportunities, does that in any way change your posture on either the amount or the size of acquisitions that you are going to –?

James McManus

It’s a great question, Carl. I think as always, we said this and we behave this way. Unless it is a good deal, we don’t want to do it, and we got great organic growth right now. So, we are in a posture where we can be very opportunistic. I think we are going to continue to look at acreage interval and where we are, particularly in the Bone Springs, particularly in Wolfberry, but if there is a value acquisition, we’ve not over-levered the balance sheet where we couldn’t take on a significant size acquisition, we couldn’t do a $1 billion deal, but in the several hundred million dollars, I think we could still be that – if that fit into a good value situation on the mine perspective. So, we are not limited, but also, don’t go like we need to move to that necessarily in order to really accomplish a lot at the company. So, opportunity driven as always.

Carl Kirst – BMO Capital

Great.

James McManus

We do have some capacity is what I’m saying.

Carl Kirst – BMO Capital

Understood. Understood. And then just lastly we’ve talked about the well cost coming down a little bit for the Bone Spring. Is there any opportunity to sort of do that for the Wolfberry as well? It looks likes that crept up a little bit, but there was the mention of the additional frac stages, let it know if that was service cost related to or just well design?

James McManus

Here is the deal. The frac – per frac has gone up a good bit. And then when you add to the number of fracs, of course, we now perform so far and part of that has been hopefully conservative modeling. Part of that has been that we’ve done a few more fracs and we hope that we’ve gotten the benefit from that. I don’t see a lot of possibilities to drill the Wolfberry cost down. They are pretty certain. We are pretty efficient in that particular game right now. Frankly, those returns are excellent even at the increased cost level, but I’m not seeing us, Johnny may a bit differ, I’m going to let him chime in and answer. I think we are very efficient there right now.

John Richardson

Yeah. The (inaudible) sort of different Wolfberry, we are fighting hard to stay even there and of course, the Bone Spring, we are still looking to push those down. So, James

James McManus

I mean, when you only got – when it only takes a few days to drill a well, there is not a lot of saving to do, whereas when you got to one – maybe we started out at 75 days and we’re hoping to be at 35 days that’s a lot of money you could save. There is just not a lot to work with there on the Wolfberry.

Carl Kirst – BMO Capital

Great. Thanks guys.

Chuck Porter

Having said that, we look at everything all the time, completion techniques, materials used. We’re constantly looking at that cost.

Operator

Your next question comes from Becca Followill from US Capital Advisor. Your line is open.

Becca Followill – US Capital Advisor

Hi, guys.

James McManus

Hi, Becca.

Becca Followill – US Capital Advisor

Hi guys. A couple of questions for you. One on, can you talk a little bit about what kind of takeaway capacity you had in the Permian in terms of liquids, gas, and crude, you are hitting your getting different products out?

Chuck Porter

Becca, we are in some areas – of course, our traditional areas and then the northern part of the Wolfberry, we are in very good shape. As we push to the south eastern part of the Wolfberry, we’re a little bit constrained right now. Trucking is an issue, trucking is very competitive thing. We are doing okay, but we have a lot of growth ahead of us. And we are constantly looking that is an issue, I can’t deny that getting pipeline – gas pipeline hookups and all trucks are moved in the – Midland Basin is an issue. We’ve done okay so far. We had a few bubbles [ph], but overall we are moving our product there.

James McManus

Yeah, Becca, there is not a lot that we’re not moving. I mean, we’ve might have had a little bit more oil in storage at one time not significant, but not as efficient as we would like to be. I think the biggest issue that we hope to resolve in September and we are going to continue to work on this is gas pipelines out and that’s out of the world, as I mentioned, we are flaring gas from four, five wells on the western side right now that we’d love to be selling and we hope to have that pipeline in place in September. And then I think additionally, importantly some of the wells to the west we’ve have to get bit more water production and we are drilling water disposal wells and since we hook that up, we expect that oil production from those wells to rise as we pump water out. So there are going to be infrastructure issues as we move to the west. Now, we think we factored all that into the models that we’ve given you for 2011 and 2013. So we feel comfortable with our estimates and we build some of that in. But there are – this is not a – it is a work in progress.

Becca Followill – US Capital Advisor

Okay. Thank you. And then on well costs, we’ve seen the creep in Wolfberry, coming down a little bit Spring, you factored in your guidance for CapEx for 2012, 2013, are you assuming that well cost to stay flat or are you assuming an increase in there?

James McManus

No. We’ve got inflationary increases. I think, Chuck – have this stated in 2011 numbers…

Chuck Porter

Yeah, the dollar numbers of $7 million and $2.1 million in 2011 numbers. And we believe the class of general inflation plays to that, but we haven’t – I mean if we get another 15%, as we have not built that

James McManus

We don’t have hyper inflation, but we do had inflation built. We don’t set them to stay flat, but we have inflation build into our numbers in 12 and 13.

Becca Followill – US Capital Advisor

It is simply – existing market inflation, it is not oil inflation?

James McManus

That’s like 3%, it’s like just regular inflation. So we’re trying to hold those costs down. But certainly if they continue to accelerate, we will undershoot those unless we offset it with efficiency.

Becca Followill – US Capital Advisor

And the additional rigs, as you’re ramping up from four to eight rigs, are you expecting higher costs in those rigs or you already got those secured, lined up? Where do you stand in terms of service?

Chuck Porter

Well, we have indentified different people. We do not have the remaining four secured and we are moving toward that and sort of have our vendors sort of lined up. I think we are okay with that cost provided all other things stay where they are. We are talking to them now, it’s not six months away. So we’re pretty comfortable there with the price level we are at. However, if there is another push, because oil price goes up gain, then we’ll have to balance that out, product will go up, services usually follow.

Becca Followill – US Capital Advisor

Okay. And I am sorry, I’ve got two more quick question. On financing, you will be out with your cash flow, really meaningfully the next three years, your debt to capital great, I assume you guys are going to finance the shortfall with all of that?

Chuck Porter

That won’t be correct.

Becca Followill – US Capital Advisor

Okay. And then you talked about that your well flowed at Bone Spring, the wells I guess for this quarter that you drilled were coming in better than expected or better than models, same thing with Wolfberry, but you lowered the top end of your guidance on Bone Spring and kept EURs flat at Wolfberry, is that because you’re looking at a broader area or you want more incremental?

James McManus

Yeah. That’s actually right, Becca. We are looking at broader area. We’ve got small more risk on things as we leave out away from the core and hopefully we are conservative on that. What I mentioned is our last core Bone Spring wells had performed a little better rate wise and these are estimates we put down there. We are trying to be sure that we hit the mark, and so, I certainly hope we performed better, but we feel comfortable with these numbers.

Becca Followill – US Capital Advisor

Thank you. And then the last one is the Mancos, big increase in probables and possibles there, any plans to accelerate drilling there given –?

James McManus

Well I don’t think so, again because we’ve got that all held by production. Williams has drilled two wells that look pretty good. Their well cost, I’m not sure I remember. Johnny may remember. One of those wells got away from a little bit was pretty expensive, the other was pretty good. I think it is just a recognition that that particular resource space is there, obviously we’ve got it in the possible category. There is another well, I believe, being drilled out there that may be a Mancos Shale test to the east of our particular acreage. We just don’t continue to monitor. I mean, I think it’s is a great think to have an inventory. It is probably the math that we use to show about Marcellus, Permian, Haynesville. We’ve said consistently that probably the thing we think that we are most excited about was the Mancos gas, or the our Niobrara gas and the San Juan Basin and the recognition of that now based on two wells Williams has drilled, but not really something (inaudible) any time soon with gas prices where they are today. Gas prices will rebound up. They will get up $6, $7, then I think it becomes very interesting to look at or if see people able to drive that drilling cost down, but now what we’ve got to do in the Permian, we will probably just watch that.

Becca Followill – US Capital Advisor

And where are their wells relative to your acreage?

James McManus

Of course, you can see that on some of the IR presentations that we put out previously, they are very close. You have – I don’t have that math with me here. But, Johnny, miles wise, they are just a few miles from our acreage.

John Richardson

And mainly we are talking – didn’t look at math. They bracket our 3o and 4 unit in the San Juan which is probably – but they key is the Williams wells to north of our large acreage holding of our and the well that James referenced is to immediate south and maybe a little east. So we’re in good position there. And of course, a lot of acreage is North of the Williams wells, but geologic was – we do have a lot of data, and we’re comfortable that we have a lot of what they have there.

Becca Followill – US Capital Advisor

Yeah. I think I hit on page 16.

James McManus

Yeah.

Becca Followill – US Capital Advisor

Great. Thank you, guys.

James McManus

Thank you.

Operator

Your next question comes from Craig Sheer [ph] from Tony Brothers [ph].Your line is open.

Craig Sheer – Tony Brothers

Hi, good quarter.

James McManus

Yeah.

Craig Sheer – Tony Brothers

Most of the questions have been asked, but given the need to – if it is I can (inaudible) BP, Avalon, it sounds like you’re going have to be making some decisions based on some of your well testing in the not too distant future. Can you kind of describe the timing for a kind of do or die decision to really develop this earnest?

James McManus

Well I think as it relates to eastern side we’d remember it is only about – yeah, 20,000 -30,000 acres over there in ballpark in it and I am not giving the exact number, because I don’t remember. The bulk of our acreage is in the more of the heart – of hopefully what will the heart of the Avalon play. This eastern side, 20,000 30,000 acres, we are going to drill the southern well that we talked about hopefully to get it down by the end of this year and see if with this new completion technique, we don’t get a better result. If we do get a better result, then we will come up with the game plan for the (inaudible) eastern side in trying to delineate how far east the Avalon shale actually gets, it will be a normal process of stepping out. We think that we can get that done. These wells are a little bit deeper, they are a little shallower, they are quicker to drill.

Craig Sheer – Tony Brothers

And what is your lease position in the heart of the play. You’re pretty much all…

James McManus

On the math, what we showed was, I think 90, 000 acres if I’m remembering roughly of Avalon shale potential, 90…

Craig Sheer – Tony Brothers

Yeah.

Chuck Porter

So 60 would be in the heart.

James McManus

So 60 is in the heard. We’re defining as (inaudible).

Chuck Porter

Yeah.

James McManus

I wouldn’t call it heart, because most of the Avalon shale well drilling is to the North, but there is a test being drilled on the southern end of acreage. We are drilling one to the western end of our acreage. But where it spins on the eastern side 30,000 acres, we believe both upper and lower present and the other 60,000 acres.

And so far – just to mention, I think I have mentioned this before, the well that we drilled them in the western side, we haven’t fleeted that well yet, it is awaiting completion but everything looks very, very good from everything we saw in the logs and testing that we did and now we’ve got to turn that into production, but looks encouraging.

Craig Sheer – Tony Brothers

Great. And then in the center basin that you are describing, what is your current lease position, I mean do you any issue about when you need to start developing in earnest?

James McManus

Well, here is the situation. Most of that overlaps with the Bones Spring, attention that we’ve got. So as we drill the Bone Springs deeper than the Avalon, we will hold the Avalon. So our plan right now is to drill the Bone Spring with earnest, test the Avalon, see how expensive it might be, but hold it with the Bone Spring well that we drill, also, if we wound that drilling in the Wolfcamp well, that would hold the Bone Spring and the Avalon, because the Wolfcamp is deeper.

Craig Sheer – Tony Brothers

Very good.

James McManus

Our plan is to drill the Wolfcamp, but the plan would be other than that 30,000 acres to the East, all the other acreage, we think as perspective at this point in time for Bone Spring, that turns out not to be the case for Bone Spring or not Wolfcamp then we have to drill the Avalon shale in order to hold it.

Craig Sheer – Tony Brothers

And that Bone Spring gives you entire vertical after that.

James McManus

It’s everything uphold from the Bone Spring and Wolfcamp.

Craig Sheer – Tony Brothers

Thank you very much.

James McManus

Thank you.

Operator

Your next question comes from Collin [ph] from Harvard [ph]

Collin – Harvard

A lot going on this morning, James.

James McManus

I hear you.

Collin – Harvard

Just two quick ones and James you might have already addressed this, but I know there is nothing in your 2011 guidance for the Avalon. Do you guys have anything factored into ’12 and ’13 yet for the Avalon?

James McManus

It is a little bit, very small. As I said we’re only drilling 67 wells in ’12 and 13. So what production we’ve got in there is miniscule on the Avalon.

Collin – Harvard

Okay. And then finally other question here on the list was, lots of results now starting to come out of West Virginia, still sitting tight there?

James McManus

Sitting side and watching, I mean if I were to say our second best potential after the Mancos Shale, I would say that the West Virginia parts of that West Virginia acreage, I hope, one day might prove interesting. We’re pretty far up to the east, we are in no man’s land out there a little bit as it relates to infrastructure and it is owned in fee. So we shall sit and wait.

Collin – Harvard

Okay. Perfect. Thanks guys.

James McManus

Thank you.

Operator

Your next question comes from Dwayne Griffith [ph] from Susquehanna [ph]. Your line is open.

Dwayne Griffith – Susquehanna

Yeah guys you’ve talked about Wolf Berry wells exceeding your expectation, but could you talk a little bit about the variability across the different parcels you have. And if there is any material variability what drives that is it more thickness or the quality of the rock?

James McManus

If there is some variability – I will let John…

John Richardson

There is variability, but statically there – they very – we’re sort of – North and then to South East. And we did to the South East we may do a lot gas here down in that area, but overall roughly speaking our well performed statically on average about science in the two area. We have more data in North, we are just now beginning to develop because we have only acquired the south eastern properties over the last, say nine months or so. But we’re pleased – what we’re seeing down there is good. There is sometimes you – rough place what produces a whole different whether the Spray Berry is going to dominate but it does back in the central or [indiscernible] being kind of production in some areas, but overall the models are pretty much the same. Yeah, I mean little bit variable but fairly tight.

James McManus

I mean this is manufacturing right now for us.

Dwayne Griffith – Susquehanna

Okay. And kind of along those lines. You’ve got enough wells now where you mentioned the Avalon having a frac including information which is not ideal. Do you guys have a philosophy about – you bring them on you’ve got some other operators talk about that particularly on –. You guys have a differentiation of how you are bringing the wells on versus maybe your peers.

James McManus

Again a little bit of this philosophy and a little bit of it – because we’re a little bit constrained with our water holding capability. But if you look at the Bone Spring particularly as we move west it has been pointed out it was that our rates are always what we – are always somewhat more conservative than some of the other companies, but – One is, yes we pay a lot of money to frac these wells and we want to bring them on in a judicious manner based on our philosophy, which usually means that we throw back our wells against a smaller choke which means we have higher flow tubing pressure, which ultimately mean we have less reported rate. So the rates that we report to give are fairly conservative choke and a pretty in tubing pressure and I couldn’t be specific about an offset operator but it many cases those wells would allow to flow much harder early on against the large choke maybe five or six thousand larger and a lot less tubing pressure, maybe another 1000 tons of (inaudible) with a smaller – some of that is because they got out earlier that we get in and have more water we’re going to catch up in that area. So we tried to pick a rate that sort of so bring among judiciously.

Dwayne Griffith – Susquehanna

And then one kind of related issue, in that you’ve got the experience of tighter insulin that you give on Central basin platform. Have you thought yet about some piloting of tighter in filled on either the Wolf Berry or maybe even the Bone Spring?

James McManus

Well, I think where we are in our development we are still in the primary phase of that. So we are still on the larger spacing. But yes down the road where those two eventually wind up as far as spacing is still a – we will have to approach that through proper engineering, look at our resource and what we’re getting. We did believe in – little bit tighter spacing that what we’re currently thinking, but where that’s –.

Dwayne Griffith – Susquehanna

And then finally on the water disposal is a problem right now, does each operator have his own disposal levers. Is there any possibility of somebody kind of consolidating that fixing that bottle neck that way or maybe even you guys taking the third party water.

James McManus

Well, chance to take. Yeah, there are commercial water disposal wells. Particularly if we went out to Delaware Basin and Bone Spring they are there and all of sudden they have been overrun with a water down there is that area. So we do the plan and process of drilling and permitting our own water disposal. We – by the end of the year that we have water handle and problem taking care of. We will take care of our sales first and then we will look excess capacity and there will other operators if they needed that. But we are in this sales pretty much right now. So we’re going to make sure we’ve got proper water and the facility in the near future. In the Midland basin which is more – we prefer to drill our own water disposal well where we can it is just economic for the long term. And we are a long term players. That will be our philosophy in Midland basin and Bone Spring.

Dwayne Griffith – Susquehanna

Yeah. Good. Thank you.

James McManus

Thank you.

Operator

And there are no further questions. I will turn the call back over to Mr. McManus.

James McManus

Well, thank you again for your attention and joining us today. And we have covered a lot of ground.

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