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Energen Corporation (NYSE:EGN)

Q4 2013 Earnings Call

February 12, 2014 11:00 AM ET

Executives

Julie Ryland – VP, IR

James McManus – Chairman and Chief Executive Officer

Chuck Porter – VP, CFO and Treasurer

John Richardson – President and COO

Analysts

Ryan Oatman – SunTrust Robinson Humphrey

Phillip Jungwirth – BMO Capital Markets

Gabriele Sorbara – Topeka Capital Markets

Jeffrey Campbell – Tuohy Brothers Investment

Irene Haas - Wunderlich Securities

Cameron Horwitz – U.S. Capital Advisors

Operator

Good morning, ladies and gentlemen, and thank you for waiting. Welcome to the Energen Corporation Quarterly Conference Call. All lines have been placed on listen-only mode, and the floor will be open for your questions and comments following the presentation.

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

Julie Ryland

Thank you Wes and good morning. Today’s conference call is being held in conjunction with Energen Corporation’s announcement yesterday of its latest Wolfcamp results in the Permian Basin. It's 2014 guidance, its year-end 2013 reserves and of course it's financial and operating results for the calendar year and three months ended December 30, 2013. Locator maps showing our latest Wolfcamp wells results can be found on Energen's homepage at www.energen.com.

Also posted there, our updated tables with potential Wolfcamp and Cline locations and associated potential our net acres.

Today's conference call will include comments expressing expectations of future plans, objectives and performance that constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. All statements based on future expectations are forward-looking statements that are dependent on certain events, risks and uncertainties that may be outside the company’s control and could cause actual results to differ from those anticipated.

Please refer to our 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. Good morning to you all. Energen has tested six new Wolfcamp wells in the Permian Basin. All produced at extremely attractive initial rates. They're continued to be encouraged by the excellent results we are achieving in the Wolfcamp Shale in both the Midland and Delaware basins.

The Winchester 57-10 #1H, a B bench well in western Reeves County was particularly impressive. With a peak 3-stream 24-hour IP rate of 2,387 boepd. This is the best Wolfcamp IP reported to-date on the southern Delaware Basin to the best of our knowledge.

Its product stream was 41% oil, 27% NGL and 32% gas. Also impressive was the Winchester's peak 30-day average rate of 2,186 boepd (3-stream), 38% oil, 28% NGL and 33% gas. About 10 miles to the south in slightly west of the Winchester well, the Tisdale 56-8 #1H tested at a peak 24-hour IP rate that 2,081 boepd.

This 3-stream rate was 30% oil, 33% NGL and 36% gas. The Tisdale peak 30-day average rate 3-stream was 1,804 boepd 30% oil, 34% NGL and 37% gas. It's important to note, the lateral length of the Tisdale was only 3,242-feet, so haven't got any ideal length. It obviously should have been a better well then the great well it's turned out to be.

Heading to the east in Reeves County, just a couple of miles north of the previously disclosed Bodacious well. Energen drilled the Red Rock 6-6 #1H in the A bench of the Wolfcamp shale. The Red Rock is a solid well that tested at a peak 24-hour IP rate of 1,471 boepd. The 3-stream rate was 65% oil, 18% NGL, and 17% gas. The peak 30-day average rate 3-stream was 1,137 boepd 64% oil, 18% NGL, and 17% gas.

The last two wells in Energen’s 2013 exploratory program are A bench wells in Reeves County, the one is drilling and the other one is awaiting completion. The company’s 2014 exploratory program in the Delaware Basin consists of 12 gross (10 net) Wolfcamp wells. The first two wells in the 2014 exploratory program currently are drilling.

In the Midland Basin, we also had two more strong, 24-hour IPs from exploratory well in southern Glasscock County. Our first two Wolfcamp B wells in southern Glasscock County as well as the first two wells that were drilled to 7000-foot laterals have generated again excellent results.

The San Saba NS 37-48 #205H and #204H tested at attractive peak 24-hour IP rates of 1,387 boepd 80% oil, 10% NGL, and 10% gas and 1,205 boepd 79% oil, 11% NGL, and 10% gas, respectively. The #205H has the highest peak 24-hour IP drilled by the company in the Midland Basin to-date. The Guadalupe 48 #101H is an A bench well with a 5,300-foot drilled lateral length. Its peak 24-hour IP was a solid 1,000 boepd 74% oil, 14% NGL, and 12% gas.

We do not have 30-day rates for these wells yet because we are fracture-stimulating neighboring wells before bringing them on production. But given the consistency of results we are seeing in our Glasscock County wells. We are comfortable disclosing just the peak 24-hour IP.

The last two wells in our 2013 exploratory drilling program in the Midland Basin are flowing back and awaiting completion.

As we look at our 2014 exploratory drilling program in the Midland Basin. It consists of 17 gross (16 net) Wolfcamp wells and 2 gross (2 net) Cline wells. The first three wells in the 2014 exploratory program currently are awaiting completion or drilled and include our first test well in Martin County and our first Cline well.

These results really underscore our excitement developing A and B benches of the Wolfcamp shale in southern Glasscock County of 2014. Our 2014 Wolfcamp development program is focusing on drilling stacked laterals in A and B benches with lateral lengths of 6,700 feet and 7,500 feet.

The estimates of the unrisked (EURs) for these development wells will range from 550MBOE to 750 MBOE for a 6,700-foot lateral and 650MBOE to 850 MBOE for a 7,500-foot lateral.

We have updated our potential Wolfcamp and Cline locations in the Midland Basin to reflect varying drilled lateral lengths on 660-foot spacing. Our unrisked map locations now total 2,475, 1,650 represent Wolfcamp wells and 825 are Cline wells.

At our inner goals [ph] we estimate that we have 751 potential locations, the 7500-foot drilled lateral lengths, 543 for 6,700-foot laterals and 1,181 for 4,400-foot laterals. We combine with more than 3,100 potential locations with 4,400-foot drilled lateral lengths on 660-foot spacing in the Delaware. We estimated our total potential Wolfcamp and Cline locations unrisked to see 5500.

This is tremendous inventory for the cost of company of our size and we are really looking forward to accelerating the pace of development in the Midland Basin still further in 2015 and yet another year of delineation in the Delaware Basin that we believe could lead to a very good development program that we are starting in 2015.

Let's turn next to examination what we see ahead for 2014. We see total company capital investment in 2014 running about $1.1 billion. The bulk of that amounts $1 billion, $5 million represents drilling and development of our E&P assets approximately $75 million is utility system maintenance, information technology and construction of new service centers in Birmingham.

As we accelerate our horizontal drilling in the Midland Basin. We are committing 45% of our investment Energen's running six rigs that will drill 55 net Wolfcamp shale wells and 2 net Cline wells. The average drill-and-complete cost of a Wolfcamp well in 2014 is estimated to be $8.5 million; 24 net Wolfcamp wells have a planned drilled lateral length of 6,700 feet, while the other 31 are to be drilled to 7,500 feet. The drill-and-complete cost of the two, planned Cline wells with 7,200-foot drilled lateral lengths is estimated to average $9 million.

Our Wolfcamp and Cline program is split into exploratory and development drilling. Our 2014 exploratory drilling plan in the Midland Basin consist of 17 gross, 16 net Wolfcamp wells, two gross, two net Cline wells.

As I mentioned earlier, the first three of these wells in the2014 exploratory program currently are drilling are awaiting completion. Two rigs will handle our exploratory program in the Midland Basin. Another 40 gross, 39 net Wolfcamp development wells are scheduled to be drilled in 2014 in southern Glasscock County.

These development wells will focus on drilling 20 pairs of stacked laterals and A and B benches. We have four rigs currently drilling. Our horizontal development plan in the Midland Basin is designed to maximize drilling and completion efficiencies, optimize spacing, workflow, rig utilization and maximize stimulated reservoir volumes for enhanced fracture complexity and minimize stimulation impacts.

To accomplish these objectives, wells will be closed on production after offset wells have been fractured stimulated. As a result of this process. The growth contribution for our Wolfcamp development further will not be seen largely until the second half of the year.

Also in the Midland Basin, we are scaling back our vertical Wolfberry program in 2014 as transition to the horizontal program. Two vertical drilling rigs are expected to drill an estimated 49 net wells, which is sufficient to meet our continuous drilling obligations in the Wolfberry play.

In the Delaware Basin, we are planning to invest approximately $108 million to drill 10 net wells that will further delineate our 106,000 net acres and secure our expiring leases. Still in the exploratory phase, these wells are expected to cost approximately $10 million to drill and complete, and install surface facilities.

We plan to drill another 22 net 3rd Bone Spring wells in the southern Delaware Basin and two net 2nd Bone Spring wells in the northern Delaware Basin in New Mexico for approximately $173 million. Our 3rd Bone Spring program has been one of the major drivers of the company’s oil and NGL production growth over the last three years since 2010, we have drilled more than 100 operative 3rd Bone Spring wells, but this program as we've already informed as nearing its owned after the drilling, we are going to plan 22 net wells this year. We only have 5 net locations left. The conclusion of this excellent development program will have a free up additional capital to investing in our newer, faster growing horizontal plays.

Energen’s legacy Permian Basin assets are in the Central Basin Platform, where the company plans to invest $17 million to drill 13 net producers and 8 net injector wells in 2014. And in finally in the San Juan Basin, which is home to approximately 65% of the company’s net proved natural gas reserves. We will only be investing only $15 million in 2014 and of that amount, 40% reflects the company’s 50% working interest in two non-operated Niobrara oil shale wells to be drilled by WPX Energy.

Production from continuing operations in 2014 is estimated to range from 24.4 MMBOE to 25.4 MMBOE, with a midpoint of 24.9 MMBOE. At the midpoint, this reflects a 16% increase year-over-year in total Permian Basin production and an 8% decline in the gas rig San Juan Basin.

In the Midland Basin, where we are transitioning from our vertical Wolfberry focus to a focus on the Wolfcamp and Cline shale's. We estimated 45% jump in production. In the Delaware Basin, where growth from the maturing 3rd Bone Spring program is slowing in 2014, we estimated year-over-year production rates were approximately 15%.

Production from Energen’s legacy oil assets in the Central Basin Platform is expected to decline some 16%. Oil and NGL production is estimated to grow 12% in 2014, while natural gas production is expected to remain essentially flat as a result of associated gas in the Permian Basin offsetting natural gas declines in the San Juan Basin.

In total, where we expect production to be relatively flat during the first half of 2014 for picking up steering, as our Wolfcamp production accelerates in to the second half of the year.

Our 2014 average December production rate at the midpoint is estimated to be approximately 73 MMBOE per day up from some 64 MMBOE per day mid-year that is based on average June production at the midpoint.

Energen's 2014 guidance range for consolidated after-tax cash flows is estimated $907 million to $937 million. Energen Resources' after-tax cash flows are estimated to be $812 million to $842 million, and Alagasco is expected to generate after-tax cash flows of approximately $95 million.

Consolidated earnings from continuing operations in 2014 are estimated to range from $200 million to $230 million, or $2.74 to $3.14 per diluted share, with Alagasco’s utility operations contributing approximately 20%.

Our news release has a lot of details on capital and production as well as financial guidance in hedge details and the interest of time. I'm not going to run all of them here, but I encourage you to review this important information. At this time, I'll ask Chuck Porter, our Chief Financial Officer to talk about calendar year on financial results. Chuck?

Chuck Porter

Thank you, James. For the 12 months ended December 31, 2013 Energen's adjusted income from continuing operations in 2013 totaled $216.9 million or $2.99 per diluted share. In 2012, the comparable adjusted income from continuing operations totaled $218 million or $3.01 per diluted share.

Non-cash and non-recurring items in 2013 included non-cash, mark-to-market revenue losses. A gain on the sale of the companies Black Warrior Basin assets partially offset by the non-cash impairment of properties held for sale in North Louisiana/East Texas. A gain on the sale of the companies Birmingham utility service center and income from discontinued operations.

In comparing 2013 with 2012 the impact of 10% increase in 2013 production from continuing operations including a 20% increase in all the natural gas liquids and higher realized all of the natural gas products were essentially offset by higher DD&A, LOE and production factors, increased net administrative expenses and increase exploration expense primarily associated with write-offs of miscellaneous partials of leasehold expiring in the first half of 2014.

Relative to our calendar year guidance issued on October 30, 2013. Adjusted income from continuing operations fell below the net largely due to the impact of two Permian Basin ice storms approximately $0.10 per diluted share and a write-off of approximately 5,000 miscellaneous acres of unproved leasehold which was approximately $0.06 per share.

There also with some other moving parts, they were basically offsetting these lower net G&A expenses positive change in the effective tax rate and higher commodity prices that were offset by slight decrease in expected production and greater than anticipated LOE. With that, I'll turn the call back to over to James.

James McManus

Thank you. Chuck. I mentioned earlier that we got into extensive inventory of unrest potential drilling locations in the Wolfcamp and Cline shale and the Permian Basin. Frankly this is the deepest best inventory we've ever had in the history of the company. The magnitude of this inventories reflected in a 172% increase of our year end 2013 contingent resources.

Contingent resources are to be defined as those qualities of petroleum estimated as a beginning date to be potentially recoverable from non-accumulations of the applied projects and not yet considered mature enough for commercial development due to wanted more contingencies.

After consultation with its, the third party was determined much about Wolfcamp and Cline potential where Midland Delaware Basin does not have sufficient wealth insurances for 3-feet classification yet. This conclusion was based on the limited number of wells drilled and completed in the two basins.

Now drilling in the continued exploration and development drilling should further increase the body of geologic and engineering data for these plays. We are going to expect our contingent resources to begin leaving into 3P reserved categories in a fairly significant way.

At the end of the day, we feel very good about our inventory and the growth potential it offers. Energen's proved reserves that even in 2013 counted 348 MMBOE and we are little change from the prior year. Record production and divestiture is essentially offset the addition of previously classified unproved reserves and contingent resources and upward price related revisions.

Oil and NGL reserves at year end represented more than 65% of our total proved reserves and we expect this downwards to increase further, as we continue to focus on exploration and development of the liquids-rich Permian Basin.

So with that said, let's open the lines for Q&A. for instructions, I'll refer to line back over to our facilitator, Wes.

Question-and-Answer Session

Operator

(Operator Instructions) First question comes from Ryan Oatman from SunTrust. Ryan, the floor is yours.

Ryan Oatman – SunTrust Robinson Humphrey

Hi good morning. Very good Wolfcamp B test over there in the Delaware Basin. How prospective do you think that, zone E is across your acreage over there?

James McManus

Maybe John will comment about that little bit. Obviously, we are delighted. We just continue operate to ring the bells, in terms of our wells results out here.

John Richardson

If we look at, sort of where we are and we look at what people are doing to the west Delaware and [indiscernible] what people have done back to the east that was a main as James said, we are very encourage. We like the results, we've gotten, not saying to anyone report negative results that doesn't mean they won't but I think feel very good about the B and then in the future, we hope to test some other zones.

We've seen some C test over that way, both upper and lower C test. Since, we haven't gotten around too; we are courage about the upper Wolfcamp, the A over there. We think the B is going to be good back to the east, a long way now when we get close to the eastern shelf, we are going to have to stay to be a little bit more, but really do like both the A and the B zones.

As we get further west, we think the C zone will come in. So that's probably more than you want to know, but we are very encouraged about the Wolfcamp pretty much caused our part of the Delaware there.

Ryan Oatman – SunTrust Robinson Humphrey

No, that's perfect. You actually answered to my next couple of questions, but I guess broadly speaking in 2014. You do have 10 wells planned over there. Can you speak to what you're trying to accomplish with that program, what zones you're going to test and what would push you to increase activity over there, whether that's infrastructure or just create a well control etc.?

John Richardson

We are looking at two things, I mean one is as we've stated, we got a little bit of exploratory drilling we need to do, so about half of that is just driven by exploration. Our leases that we need to keep, but they get well with what we want to do long-term and they define, they sort of rainfence [ph] our acreage.

So and the east and the west, I mean we are excited about our program. We are doing a little bit of protection there, but if it fits in well, what we wanted to do exploratory wise and we are looking at some of these things have stress test that they can't dug them to look deeper, we are going to do some testing.

So in a nutshell, we think between the acreage we're trying to hold onto that is expiring and say the other five or six wells that we're drilling just because they're in good spots, we are very excited about this program.

James McManus

Ryan, I'll just add a little more color. This is James. We've got of those 12 gross well, five will be A wells, seven will be B test. Right now it looks like, we've got one in Winkler County, three is Ward and eight in Reeves in total.

I think one of the things we are trying to accomplish this year, that we are working on, you saw we gathered approximate $10 million drilling cost and there is our hope that over the year. We are going to try some things to manage that cost down and so one of the issues that move into the development phase and this is understanding a lot more about the formations, which I think we're going to get with Eastern Wells, but it's also our experimentation of getting the drilling cost a little bit more in line with what we need.

Now we are very encouraged by what we are seeing and as I mentioned, if we continue to get the kind of results we are getting, it's our hope that a lot of the 3rd Bone Spring activity where we've got three rigs running there, would move into Wolfcamp development in the Delaware Basin.

John Richardson

And just to comment on that, we know, when we send our exploratory group out. They have to be pretty self-sufficient in that numbers James mentioned $10 million plus, we got surface equipment in there, we got some facility, some pipelines because someone mentioned in one of the write ups that particularly we got wept, this is very much undeveloped territory and there is no infrastructure.

So these wells have to support themselves with infrastructure, water hauling in and out to do the completions. So there is some cost savings that are just automatic when we move to the development phase and also just the repetitive nature getting into development, will drive these cost down. So we are very optimistic about that.

James McManus

Yes, we've talked about ballpark on the lines in the past that we think, if we can get down to $8.5 million, we'd be in pretty good shape on these and I think that's a target that we believe is doable overtime, particularly [Audio gap] development phase.

Ryan Oatman – SunTrust Robinson Humphrey

Very good, I'll leave it at that and hop back in the queue. Thank you.

Operator

The next question comes from Irene Haas from Wunderlich Securities. Irene, the floor is yours.

Irene Haas - Wunderlich Securities

Thank you very much. Question, you know really, really encouraged to see that you guys have a totally just did a wonderful Wolfcamp test, actually two of them in Reeves County, but looking at Midland County you guys have in Midland Basin you've sort of made your tally. I was wondering, whether you have any consideration of exploring this Sprayberry trend, because Pioneer recorded yesterday and they're beginning to drove some Sprayberry well. Some really promising success rates on the Midland Basin side, so care to comment on that?

John Richardson

Irene, what we have not studied the reservoir characteristics of the Sprayberry S4 is what makes a good horizontal target. I can tell you though that if just drove a circle around what people have reported particularly Pioneer as far as our Sprayberry test, that circles encompasses a large portion of our acreage particularly the center part of the Midland Basin and some of the western areas.

So just by closeology [ph], we think we are in a good spot. I don't have a tally on that acreage because it's only the last day or two but then to look at it, but it isn't, it will be a focus for the company in the future and just off the truck, we think we are good at extended even outside that circle, but just that's pretty large circle that test have been drilled in.

So we are encouraged to something new. It's something we haven't looked at from what makes a good horizontal target there, but we are very encouraged about acreage.

Irene Haas - Wunderlich Securities

Okay, thank you.

Operator

Next question comes from Tim [indiscernible] from ISI Group. Tim, the floor is yours.

Unidentified Analyst

Quick question, this is actually on slide three of your supplemental information. I'm just trying to get a sense as to how much of your acreage is contiguous in the Midland and the Delaware maybe and then also you said especially, I think this was in the last call in Glasscock County specifically that the pockets where it isn't contiguous. I think you guys are working pretty close with some of your neighbors in terms of slopping out acreage blocks, here and there is that still the case, can I just get a little bit more color on that?

James McManus

So Tim, we got the, we show the next broken the [indiscernible] into lateral lakes in the Midland Basin and sooner we got 1,181, 4,400, 543, 6,700, 751, 7,500. Obviously the longer you get these wells, we think economics trying to be better even though they are very good on the 4,400-foot lateral. So we feel really good about we are going to be drilling primarily 6,700 and 7,500 in the [indiscernible] phase, but obviously what we will be working towards, the ones that we've got that are 4,400 will be working towards co-operations, the better operators as I've mentioned before, we've had that discussions with one of the more prominent operators in and around us there and we've gotten the feedback that they do want to cooperate.

Coming with us, ultimately we can get cooperation or we don't know, but we do suspect that the industry will want to move in that direction and so we've got a really good inventory of long runs, but obviously we're really trying to make the shorter ones, as long as we possibly can.

In terms of the Delaware Basin, you can sort of see, our acreage position and I would mention there are spots, where we can get longer laterals in and in fact, I think we've got two plans for 2014 that will be Paul, how long are they? So we've got two 7,500-foot laterals in the Delaware Basin and that's one of the ideas, in addition to just getting the 4,400-foot down.

Obviously we get a 7,500-foot lateral that could be a much more efficient way to develop that where the possibilities exists and if you look at the eastern side of the Delaware Basin in particular, you see over there where we are pretty blocky and there are areas, where we are in the west as well.

Unidentified Analyst

Got it, so then just to make sure I got this right. So over time, you would expect that for cooperation you'll get, some of those 4,400 will actually move into 6,700 and 7,500 bucket.

James McManus

Hope so and obviously the discussion point there will be, who operates them and their maybe a situation where we have to give up operator ship to get a longer one and there may be a situation where we get somebody else to give that operator ship in the account of share that and those are some of the preliminary discussions, to happen.

But obviously, we are concentrating on the longer laterals in this development program in 2014 because we think those are the most economic.

Unidentified Analyst

Got that, next question from me just kind of San Juan Basin I see, I think it's about 8% decline rate that you're guiding to with zero CapEx is that kind of a good longer term decline rate, we should assume for that basin.

James McManus

We've got that, I think Chuck's got that here just a second, while we look that up for you.

Chuck Porter

Yes, we've got little information. Yes on the San Juan Basin. I'm going to give it to you, a couple different ways. Over the next five years we would expect about a little over 10% decline and in year one to 10 would be about 9% decline and then over year one to 20 is about 8% decline in the San Juan Basin.

So while I have it at floor, let me give you that also again this is a PDP decline as of 12/31. The total company from continuing occupation next five years with decline at 13% to 22%. One to 10 years would be 10.6% and 20 years would be 8.7% and in Canada to fill in the gaps in Permian Basin, the decline for year one to five would be 15.2%. one to 10 year, 11.7% and over to next 20 years it would be 9.2%.

So hopefully that information can kind of give you feel for how we would expect 12/31 PDP reserves kind of decline all over time.

Unidentified Analyst

Got it. And then if I look at, let's move to Delaware real quick. The B bench for all you're withdrawing, if I look at the decline rate of 24-hour IP to 30 day. I mean that came in, that decline is lot less than what we saw in some of the A wells. Can you just kind of talk to that, what's driving that is it just mix, is it pressure issues, is it choke?

James McManus

Those are, I'm going to let somebody else chime in, but those are two extremely strong wells and that's why the obvious close to 30-day rate, we've got some really good rock working on favor, to Johnny.

John Richardson

Yes, I think that's and we've got east all of a population of two, but I think what we are seeing as we move west, is a little bit better matrix from the ability out of those zones. So they are getting shallower, we don't have as much pressure, so we don't have as much near bore, wellbore pressure and sort of outrun around the wellbore.

We seem to have a little more feed-in, it is gasier [ph] that does help, it always helps when we have gas lifting aerate the columns. So the flow rates stay up a little bit more, so there is a lot of things contributing. On the downside, you have a little more, little less cut over there but on the upside you've got very strong wells looks like they've got good quality reservoir and the gas helps lift and so we see those rates stay up, higher, longer.

Unidentified Analyst

Okay, guys. Last question from me is any update on the Mancos, in terms I didn't see any CapEx allocated to that in the budget. If you guys help it?

James McManus

I did actually mention now, we've got two wells that we'll be participating in WPX in the Mancos through Niobrara in the San Juan Basin. We may have, something on one of those in the next couple of quarters.

Unidentified Analyst

Got it, thank you.

Operator

(Operator Instructions) the next question comes from Phillip Jungwirth of BMO.

Phillip Jungwirth – BMO Capital Markets

You didn't mention in EUR in the Delaware for the Wolfcamp wells, but just trying to back into one using their resource potential in that location, looks like it's around 600,000 barrels and just wanted to see, if that's in the ballpark of what you would expect ultimate recoveries to be there for the Wolfcamp?

James McManus

I think that's on the other side.

Phillip Jungwirth – BMO Capital Markets

Okay. In the Midland given the big ramp in the second half, can you talk about the timing of when the 59 horizontals are going to be coming on production, how many of those are going to be coming on in the second half?

James McManus

Well, I don't know that we've got that specific relative to wells, but we don't get a lot of production from those for several months because of back and drilling close together, frac stimulating in there pretty tight and so most of those are up to full capacity in RM for several months into the year, as I recall.

Chuck Porter

Yes, we don't have the numbers.

James McManus

Maybe five or six months before they're [indiscernible] and that's the reason, you've got such a big ramp up at the end of the year. I mean, you got a pad drilling and you're drilling A's and B's close together, you got to be careful in terms of when you fracture stimulating these wells, when you produce them.

Phillip Jungwirth – BMO Capital Markets

Okay and then, when you talk about acceleration in 2015. How much of govern where it will cash flow be and what's your willingness outspend next year?

James McManus

Well, I think it's just too early to say, I mean I think we need to see what kind of results we've got and I think our view is that we would like to ramp up above what we are dealing in 2014 and 2015 depending on the results.

Phillip Jungwirth – BMO Capital Markets

Great, thanks guys.

James McManus

Like to increase the pace.

Operator

(Operator Instructions) the next question comes from Gabriele Sorbara from Topeka Capital Markets. Gabriele the floor is yours.

Gabriele Sorbara – Topeka Capital Markets

Just a quick question, I want to think about your down spacing plans for the Midland Basin in this year. How should we think about that? How tight you test and what you think your optimal development is going forward for you guys? I know you guys have 80-acre down spacing, but just wanted to get any thoughts around that?

James McManus

Yes, effectively we are dealing 6,650-feet which is effectively 80 acres. Now we know some other operators who talked about little bit tighter work than that here recently and you know to be something looking at, study it as well, but right now we are going to proceed forward on the 80 acres.

I think some other operator came out with a 60 acre plan.

Gabriele Sorbara – Topeka Capital Markets

Okay, the first Martin County well, what zone are you completing that in?

James McManus

Just one second, here A.

Gabriele Sorbara – Topeka Capital Markets

Okay and I think your entire program is going to be in the A, B and the Cline correct. Nothing else?

James McManus

We've got three C's slotted for Glasscock County.

John Richardson

Yes, we are testing C workers here Gabriele in a place or two.

James McManus

So Gabriele, if you talk about the Midland Basin, we've got eight A's slotted in the exploratory program, six B's and three C's and two Cline's.

Gabriele Sorbara – Topeka Capital Markets

Okay, great. You guys did change around some of your acreage positions in both the Midland, Delaware Basin. It looks like you took a write-off on 5,000 acres, was that in a Permian Basin, can you give us some color on that?

John Richardson

Yes, Gabriele what that was is basically southern Delaware sort of on the southern trench and it was very, I mean there were no large box of acreage they were just sort of stag orders that had to come to us in different forms and so, we didn't see any way there, little bit out of the trend as we saw it and they were very small acreage blocks, they were a multitude of them basically that we wrote off.

Gabriele Sorbara – Topeka Capital Markets

Okay, so one quick question actually. On the first Cline well, is that located in Glasscock County?

James McManus

Yes.

Gabriele Sorbara – Topeka Capital Markets

Okay, thank you guys. Appreciated.

Operator

Next question comes from Jeffrey Campbell from Tuohy Brothers Investment. Jeffrey, the floor is yours.

Jeffrey Campbell – Tuohy Brothers Investment

I want to return the San Juan gallop just briefly. I'm just wondering, if you could provide some color with regard to your decision to take greater exposure on couple of wells, as supposed to maybe taking smaller interest on a larger number of wells?

James McManus

Yes, so basically what was going on out there as you know, WPX is been moving forward the program out there, that they have disclosed some results and look pretty appealing, we've met with them and basically, we have fairly, we've been going into 2014 based on our discussions that we were having they would probably proposed, some wells that were on us in 2014 and so our view is this is very good way to step up the learning curve and they've already got the rig out there.

It's going to be a lot cheaper for them to go ahead next year on, doing some whether we get to see the results. At least two and there may even been more than during the year, we're going to probably do at least two and just a great way to get a look and see what's going on there and see if that's the kind of play, we want to dedicate some capital to, as you know we've got a free substantial acreage position out there and we are hoping that, these wells are successful.

Jeffrey Campbell – Tuohy Brothers Investment

Okay, great. Thank you. If I missed this earlier, I apologize but was just wondering aside from the one Martin County, Wolfcamp Bay that's been mentioned to them. You mentioned to some C class, the Wolfcamp exploratory wells, will that be in any other besides Glasscock.

James McManus

Yes, exactly I can give you the detail there. So in Martin County we've got six wells, slotted up there in Midland County we've got two wells in Howard County we've got one exploratory well, in Glasscock we've got eight, in Reagan we've got one. So hopefully, that's helpful to you.

Jeffrey Campbell – Tuohy Brothers Investment

That's very helpful. Thank you. Last question, can I ask one more question?

James McManus

Absolutely.

Jeffrey Campbell – Tuohy Brothers Investment

Okay, great. I thought the description of the contingent resources moved to 3P was kind of interesting way to describe it and I was wondering, when you look at your exploratory Delaware and the one for Midland assuming they're both successful. Is there going to be disproportionate in fact, positive effect on reserves for one over the other and that really reason I'm asking is, it seems like you're exploratory drill in Delaware is been more likely distributed to this point, then the exploration in deadline.

James McManus

Yes, we are trying to get a handle on what those numbers are exactly in terms of what might move based on what the rules are and I can tell you, without giving you any numbers, that we think that the substantial move in proved reserves and a substantial move from contingent to 3P and that's only 2P, I really mean probable, possible.

John Richardson

The Delaware Basin, I mean that is a very large area. We are not the only people active out there, but there are as many people active in the Delaware Basin to-date as they're on the Midland Basin. You know a Reservoir Engineer I look and understand, we got a lot of dots to connect, the other side things that got a huge amount of potential. First of all frustrating how fast these things can actually move over, but the Delaware Basin gets keep in mind, there is a lot of dots to connect, there is a lot of territory in between the acreage we have.

So even though we are doing more exploratory drilling there per se, we got a lot of things to learn about that, to give them to the proved level that is required reserve classes. The Midland Basin, we are doing a lot of exploratory work. We are also doing a lot of development work, so I think the movement there will be a little bit quicker and other people are active and all of this goes into the body of data, and you have to get to these proved levels.

Jeffrey Campbell – Tuohy Brothers Investment

Okay, thank you.

Operator

The next question comes from Irene Haas from Wunderlich Securities. Irene, the floor is yours.

Irene Haas - Wunderlich Securities

Yes, thank you. I have two follow-up questions. firstly, on the Bodacious well versus Red Rock, can you give me a little color as to why the IP so different because they're right next door to each other [indiscernible]. Your Wolfberry vertical program, you guys are scaling back and when should we expect you to move some of the reserves off the book and how much?

John Richardson

As far as the two Red Rock versus the Bodacious, Irene I guess we can, we drilled them the same, we completed them the same. They're same recipe, I guess Mother Nature gives contributed a few more fractures, as far as we can tell maybe to the Bodacious well. But actually if you look at the Red Rock, it's a very nice well.

It didn't fall off, a lot in 30 days. So we are very proud of that well too. I think the Bodacious is just one of the special thank you for our cross saver now and then. When everything comes together, natural fractures that you intercept, bench goes your way and it just really blossoms for you I think, the Red Rock is a fine well also and a very good well. It will take more of those.

James McManus

Okay, I will with respect to the second question. I think that's something we will look at next year to see how many verticals we plan to do going forward and what impact that might have on the five year sort of rule as it relates to puds [ph] and so if we decide to continue to go down on the vertical program, as we may or may not do that would be sort of next year event.

John Richardson

Yes, but we currently do have a plan.

James McManus

We do, we currently have a plan.

John Richardson

We don't think that will compete from a reserve standpoint. It's a, it will just be a matter of currently our plan is to drill those, you know they're still into plan. So we're thanks there are good wells to drill.

Irene Haas - Wunderlich Securities

Okay, great. Thank you.

Operator

The next question comes from Matt [indiscernible] from TPH. Matt, the floor is yours.

Unidentified Analyst

Good morning, guys. Just a few quick questions from me. Over in the Delaware side of the basin had a question on reservoir thickness and how you guys are thinking about the potential for multiple laterals, within a particular horizon. I think we have seen some of your peers talk about potential lending, potentially two wells and in particular horizon.

Specifically the Wolfcamp Bay, I'm wondering, to just get your thoughts on that and then I guess, the second question just in regards to the natural flow that you guys are seeing on the Delaware wells. How long before you kind of look at putting these wells on artificial lift?

John Richardson

Well some of them are already on artificial lift, say some of the first wells we've drilled are going to lift now. I don't know we are probably seeing from four to six months.

James McManus

That's kind of what you average natural. Not sure you heard that, but that's four to five months before we put them on artificial lift.

John Richardson

As far as this targets go, people look and they may define their A's, B's and C's differently than we do, I mean we do have a nice thickness in the Wolfcamp in the Delaware Basin and we will target different intervals. I think sometimes we will see, maybe we will see an upper B or lower B or that maybe run into an upper B, upper C.

I think it's according how we define and sort of where we think the best targets are, but one thing that I think we are very comfortable with, we do have multiple targets on most of our acreage in the Delaware Basin.

Unidentified Analyst

Great and then just in fact [indiscernible] of your drilling program right now, but as we think about the Delaware Basin and moving towards longer laterals, should we be watching for any longer laterals wells as we move through 2014 and then 2015 in Delaware and I guess just a quick follow-up on the well cost.

I know you guys mentioned, there is infrastructure associated with that. I was wondering, if you can put any contacts behind the science and infrastructure costs that are associated with those wells today?

James McManus

So the first question, yes we are going to two 7,500-foot laterals in the Delaware Basin. So we will do two in 2014, as it relates on the well cost side. I'll John will comment on that.

John Richardson

I mean, again we do have our targets here. The drilling mechanically speaking we'll probably we have to increase our completion. Actually the drilling won't add a lot to the longer laterals, as far as cost, but again when we are looking at driving those costs down. The longer laterals, yes will have longer term but as far as driving the $10 million cost down. Yes, a little more infrastructure, the second wells and area will share that infrastructure.

We will have to build a pit first time around. So we will share that, so you just get cost sharing as you move down and start putting multiple wells in the area. Plus, we've already changed our drilling profile a little bit. We are now drilling a smaller hole, we are running a different testing but we are still able to get the same completion.

So our penetration rates are higher and our testing program is already different, where we're basically go into 4.5-inch liner, instead of 5.5-inch all the way back up to the surface. So we are already driving cost down there. We found out, we can get by with a little bit stronger but smaller pipe still get the same completions and so we are already seeing those results and we have plans to do more things like that in the future.

James McManus

Yes, I think what I said earlier. We really want to drive these well costs into $9 million, $8.5 million and that's really a key for us in moving into the development phase or narrowing that we will move into the development phase, we can have those type of well costs.

Unidentified Analyst

Thank you very much.

Operator

Next question comes from Cameron Horwitz from U.S. Capital. Cameron, the floor is yours.

Cameron Horwitz – U.S. Capital Advisors

Good morning, guys. John, I wanted to give or take. I was curious if you were surprised with all these by the oil cut, the Wolfcamp be test there on the western acreage block. I figured, given your moving down the section and you're moving west. The gap, but it looks like they are both oiler than your Brady well to the east.

I'm just curious, if you have any color there.

John Richardson

I think we are pleasantly surprise as well and still trying to figure out a little bit more about the overall maturation that tends to be very variable across the space and I think we are pleasantly surprised, not only at the composition but the particular strength of those two wells.

Cameron Horwitz – U.S. Capital Advisors

Okay and I guess going forward, are you thinking about Reeves County has 30% to 40% oil cut type opportunities there or how are you thinking about just the average oil cut across the acreage?

John Richardson

I think internally we see sort of three different areas. Of course, we remember the Bodacious and the Red Rock also reach county well, so you can't just lump them all together. I think the further west we go, we do anticipate more that 30%, 40% oil cuts and higher gas and liquids, but and that's what we think.

So I think we see, east. We are seeing 60%, 70% oil cuts and then you transition all the way out to that 30%, 40% in the west, that's our experience. I'm sure, we will give surprise along the way and some things, but sort of drag A from east to west that's as far as the models go.

Cameron Horwitz – U.S. Capital Advisors

Okay, thanks for that. I guess, can you just remind us, in Reeves County how are you [indiscernible] constructed thinking about from HBP perspective and do you hold, how does the holding member work. I mean do you hold, with if you drill in A, do you hold the whole column, what's the setup there?

John Richardson

It's vary, some or by B it's just penetrated. Some or by just formation, if we penetrate the A, we will hold the whole section and other do have both repute, there is not as many as you would suspect out there, they both fall into the first two categories, I mentioned to. We have been able to protect pretty much ever think to-date, to the depths we are interested in with the drilling we've done and we think we can continue that, in our basin cases, where we have to go back in to start at the bottom up, but those are not.

They are pretty rare, we can protect the acreage in Reeves County usually by penetration, the current penetration we are doing.

Cameron Horwitz – U.S. Capital Advisors

Great. Thanks a lot guys. I appreciate you answering my questions.

Operator

(Operator Instructions) At this time there are no further questions.

James McManus

Okay. Thanks again for everyone joining us. We are very excited the progress we are making and the opportunities that we've got in front of you. Everybody have a great day. Thanks.

Operator

Thank you. Today's teleconference. We appreciate your participation. You may disconnect your lines at this time.

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