Energen's (EGN) CEO James McManus on Q3 2016 Results - Earnings Call Transcript

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Energen Corporation (NYSE:EGN)

Q3 2016 Results Earnings Conference Call

November 04, 2016, 11:00 AM ET

Executives

Julie Ryland - VP-IR

James McManus - Chairman, President and CEO

John Richardson - President and COO, Energen Resources Corp

Charles Porter - CFO, Treasurer and VP

Analysts

Neal Dingmann - SunTrust Robinson Humphrey

Tim Rezvan - Mizuho Securities

Chris Stevens - KeyBanc Capital Markets

John Freeman - Raymond James

Sam Burwell - Canaccord Genuity

Chris Stevens - KeyBanc Capital Markets

Irene Haas - Wunderlich Securities

Daniel Guffey - Stifel

Drew Venker - Morgan Stanley

Jeanine Wai - Citigroup

Charles Meade - Johnson Rice

Gail Nicholson - KLR Group

Michael Glick - JPMorgan

Operator

Greetings and welcome to the Energen Corporation Third Quarter Financial and Operating Results Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded.

I would now like to turn the call over to your host, Ms. Julie Ryland, Vice President, Investor Relations for Energen. Thank you. You may begin.

Julie Ryland

Thank you, Melissa, and good morning. Today's conference call is being held in conjunction with Energen Corporation's announcement yesterday of its operating and financial results for the three months ended September 30, 2016.

The third quarter 2016 supplemental slides can be found on Energen's homepage at www.energen.com. These slides will form the basis of the Company's prepared remarks this morning.

Today's conference call will include comments expressing expectations of future plans, objectives, and performance. Such comments 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 materially from those anticipated. Please refer to our periodic reports filed with the SEC for a more complete discussion of the risks and uncertainties that could affect Energen's future results.

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

James McManus

Thank you, Julie. Welcome to the call everybody.

I'm going to be referring to the slide deck that Julie referenced and I'm going to start on Page 2 of that deck where we're looking at our 2017 and three year outlook. As we've given some guidance in the press release, estimated annual production growth increased to 20% for 2017. Assumes Generation 3 completion costs but not potential Generation 3 production uplift. So there's obviously some upside in what we put out on that three year model.

Our exit rate increased to 40%, 4Q 2017 to 2016 very strong there. Drilling and development capital range estimated to be 700 million to 800 million for DUC completions and drilling program in completions associated with 5 to 7 rig program.

We've strengthened our hedge position with additional three-way collars and some natural gas basin specific contracts and NGL swaps. I will cover that a little bit later.

On the three year outlook, annual production estimated to grow to three year CAGR of just over 20% again without Generation 3 production uplift built-in. I would note we expect the commodity mix to stay the same during that three year period at 65% oil.

2019 production is estimated to approach 100,000 MBOE per day which is effectively almost doubling our production over the three year period. Drilling and development capital you see on the slide ranging from 900 million to 1 billion in 2019. We would add a little bit of additional color not on the slide 2018 range would be 750 to 850.

And our recent strip prices, the Company estimates will be near cash flow neutral in 2018. Now the strip prices that we used for this forecast for 2017 was $52.75 a barrel for 2018 $54.50 and for 2019 $52.25. I think importantly the estimated EBITDAX at year end '19 is close to 1 billion which is 3 year CAGR of more than 50% on EBITDAX.

We'll now flip through Slide 3, we'll talk a little bit about some impressive third quarter well result. In our core Delaware basin we've seen really excellent response to Generation 3 completion, more than a 30% uplift on a 2 million barrel EUR curve for 10,000 foot lateral. We've got two wells after 30 and 20 days of cumulative production respectively.

If you remember the four wells that we drilled in Delaware were required to be drilled to hold. One of those wells was the Checkers 701H which is a Wolfcamp B in Reeves County drilled to completely lateral length of just under 9400 feet with a peak 24-hour IP of 2384 BOE, pre-stream 61% oil with the peak 30 day IP of 2072.58% oil, very well very impressive well.

In the Razorback 604H Wolfcamp A that we drilled in Loving County had completed lateral length of just under 9000 feet. You can see the numbers on their peak 24-hour IP very aggressive with 3111. This one was 27% oil, I’ll talk about that a little bit more in just a second. Peak 30 day IP of 2524.49 with 26% oil.

Based on preliminary flow back data, the other two wells that we drilled up before were drilled right next to the Razorback, they are right beside. There is another Razorback and another Humpback well that are right beside each other. And these three wells were drilled in what we talk about as a fairly confined area of 2500 acres that has a higher GOS then the bulk of our footprint. And you would say, well, how do you know this?

We've got terrific well-control in this data. We got XY data, on the XY seeing in the Wolfcamp, which when we drilled it in this particular area was gassy as well. Now we didn’t know for sure whether this shale would be. But there was a good possibility, there’s a small feature here that we think contributes to that.

But again we’ve got Wolfcamp show, Wolfcamp XY and third Bone Spring tremendous amount of well data that leads us to the highly confident that this is a small area and I would also say that several self side analysts have plotted maps confirming management's comment that this is a very small combined area. And I would also point out that these are really great wells in spite of the fact that they’re gassy and the returns will be extremely good on these wells also.

Then moving to the Midland Basin, where we’ve got 90 days of production history, normalized to 7,500 foot, our cumulative production on our 12 Lower Spraberry wells on Gen 2 frac continues to track a very impressive 900 MBOE EUR type curve. And then in Glasscock County, our wells drilled down there with Gen 2 frac have exceeded our type curve by more than 20% after 190 days. I think these well results continue to highlight the quality of the acreage that Energen now has in the core Delaware and Midland basins and that we plan to continue to execute on.

If you then flip to Slide 4, we just kind of show you those two wells I talked about, in the Delaware and again impressively, they are outperforming a 2 million BOE type curve, which is going to make these some outstanding returning wells and it makes it really exciting for us what this says about the quality again of our acreage in the core Delaware Basin.

We then move on to Slide number 5. We’ve updated our returns to foot. In there the current cost of the D&C on Gen 2 for the various plays we're drilling most of the wells. And then we bracketed it with the D&C cost on Gen 3. Again these are at current cost, don’t include wellhead of equipment which is approximately a 200,000.

I would want to point out though that the returns and type curves are not based on our latest highest intensity frac that based on Gen 3. They’re compilation of Gen 1 and Gen 2. So there is certainly some upside there and again we don’t have any service cost increases that might come built into these numbers as well. These are based on current cost.

But if you look at just the Delaware, Wolfcamp A, B for a minute and you just look in there at all the numbers, really the returns are outstanding there. If you move down or Lower Sprayberry, again extremely good returns even at a flat $45 oil price and also good returns in the Wolfcamp A, B in Glasscock County.

We then turn to Slide 6, talk a little bit about the third quarter financial and operating highlights, a very good quarter for us. Production exceeded the guidance by 2%. Cost efficiencies continue to work their way through from an LOE and a G&A standpoint, with the guidance midpoint being lowered by 10%.

Adjusted EBITDAX outperformed by about 11% and also exceeded our internal expectations. And I think importantly the last bullet, I want to emphasize is we continue to do a really good job of picking up acreage at a low cost basis within the core areas that we’re in. Picked up almost 8,000 acres, you can see there, 14,600 acre, it would have been a lot lower, except that that number has in it the 21,000 acres we acquired at the New Mexico lease sale that we paid $35.5 an acre for, which only has 12.5% royalties, which is why we got to that level, at that particular price. So the team continues to do a good job of adding acreage.

We then turned to Slide 7, just look at third quarter of 2016 expenses, production versus guidance, pretty nice beat there kind of all the way around on SG&A LOE again. And if you look at our production, we were pretty much right on the button on oil and we outperformed a little bit in NGL and natural gas.

So then looking at Slide 8, updated 2016 guidance, again good progress, good movement on the SG&A side, the LOE side. We also give you as we always do a breakdown by basin, so you can see how we trend in each one of those. I would also break that G&A down in the lower purple by cash and non-cash. But everything moving in the direction you would like for it to go.

If we then turn to Slide 9, talk a little bit about capital plan for this year. And again we’ve been able to pick up some leasehold and so $135 million of extra capital there. We’ve got cash on the balance sheet. So it’s a good thing to be able to do, particularly the prices that we’re picking up for. And then you can see our plans really haven’t changed a whole lot in the Midland Basin and the Delaware Basin, where we’re really focused on long laterals, high working interest, building back our DUC inventory, moving into next year and then also having a pretty good.

Rig cadence, I won’t touch on the acreage acquisition again. We’ll just go ahead and move on to the next Slide, which is 10, which kind of outlines the Company’s hedge position. You can see here, we’ve got oil swaps in place for 2017 at 4.1 million barrels at 47.97 a barrel and then we’ve added to the three-way collars that we’ve got and I know you’re all familiar with this call price of average $62.18, put price $45, short put price $35. So we like the hedge position we’ve got going into 2017. And then you can also see kind of the natural gas, and natural gas liquids that we’ve hedged Company.

So I would summarize, I think a really good quarter for Energen. I think a really dynamic looking three year outlook that has a lot of upside potential, if higher intensity fracs continue to work I think again it speaks to the quality of our properties and I think the team continues to execute in a very good way.

So at this point, I would turn it over to Melissa for any questions that folks may have. Melissa?

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Neal Dingmann with SunTrust Robinson Humphrey. Please proceed with your question.

Neal Dingmann

Good morning guys and great quarter, say James just wondering I guess I’m looking at that EBITDAX you laid out now from 2019 of about $1 billion. What does that two things around that? What does that assume for sort of well cost inflation? And then secondly just in broad terms, if you – I know you’re not including that Gen 3 production uplift. If you would include that, how much would that factor? How much of that change?

James McManus

Yes, so Neal, one of the things we haven’t done really is put any kind of quantification on that Gen 3. It’s early yet, and that’s why we kind of leave that as an upside. I think we are - it’s a little bit conservative, obviously we’ve got Gen 3 costs built-in and we do have a little bit of an escalation on the service costs side built into our numbers as well.

So we’re hoping that everything proves to be on the conservative side. Even though I think pretty impressive growth rates and the fact that we could go cash flow neutral in 2018 is also pretty impressive and again I think it’s speaks to the potential capital efficiency and quality of the properties. But we don’t have a - I mean the only thing we can show you as we’ve had an early time 30% uplift in the Delaware on Gen 3, but it’s too soon to know what ultimately how that’s going to turn out. But it’s very encouraging what we see, very encouraging.

Neal Dingmann

Very good, and then just lastly, you had said too much on the Central Basin platform, just activity wise, how do you see that playing out for 2017?

James McManus

Yes, so for us, that’s not going to be a big capital draw. We’ll continue to do a small work out there that economic like acid jobs and things of that nature. Again as I’ve mentioned previously that’s an asset that the company in an appropriate oil price environment could monetize, could use to fund either accelerated work or could use to fund some type of acquisition that we were to make. I mean the Company is in a position to be acquisitive that wants to.

So far we’ve decided to do that on a more cost effective basis on the smaller deals as opposed to the larger deals. But I think the Central Basin platform is a lever that we can pull that provides us, probably with a lot of flexibility toward still, maybe shifting that lower growth asset to a higher growth asset at the appropriate time.

Neal Dingmann

Very good. Thanks James.

Operator

Thank you. Our next question comes from line of Tim Rezvan with Mizuho Securities. Please proceed with your question.

Tim Rezvan

Hi, good morning folks. Thank you taking my call. I was hoping to follow-up on Neal’s question on the Gen 3 completions. Can you step back a bit and talk about where you’ve implemented those tests so far? And any dispersion you’ve seen as far as the uplift in different horizons in different parts of the basin? We’ve seen some different results reported by some of your peers. I’m just curious what you have all seen recognizing that it’s early days?

James McManus

Yes, so let me break it into two parts and I’ll ask Johnny to comment on this as well. I think in the Delaware Basin, we just got these four wells and obviously we’ve seen very good results. But we’ve also been watching other operators in the area and we seen this move towards higher intensity frac yielding more results. So I think we’re very hopeful there that this was going to be very attractive to our performance.

In the Midland Basin, we do have a few Gen 3 fracs going on there. They are small in nature and they’re just in the stages of starting to flow back. So it’s premature to talk about those. But the bulk of our Gen 3 fracs will be on the DUC’s that we’re drilling this year all of those are going to be completed with Gen 3 fracs in early 2017. So we’ll get a little bit of read from a small number of wells, but it’s our intention at this point to use Gen 3 going forward. Johnny, did you have anything to add?

John Richardson

Yes, only – Tim that when we look at Delaware and James mentioned that we are a little ahead in our confidence level of response in the Delaware during the period, earlier in the year, we weren’t very actively. We were monitoring of course trends and we saw in the Delaware that a lot of people have moved into this completion area with the smaller stages and bigger jobs. That was definitely the trend there and the results have been very nice.

So just looking at what other people have done anecdotally little bit further ahead in the Delaware, but our results in the Delaware back that up. And as James mentioned, we continue to monitor what people are doing in the Midland Basin. Even though that’s not quite as obvious to us, besides jobs are running is obvious, but the results are in and we’re just now beginning to see results from our own work.

James McManus

I mean I want to leave you with the impression that we’re very optimistic about what we see, very mystic and my hope is that our uplift numbers prove to be as strong as what we’re seeing and that provides a good bit of upside in our three year look.

Tim Rezvan

Okay. That’s helpful. I appreciate the color there. The second, just from a modeling point of view, you are guiding to a sequential decline in the fourth quarter, it looks like with 2016 guidance you sort of pulled that production up to 3Q. What are the drivers on your 4Q outlook here for production?

James McManus

Yes, so Tim, it’s always actually been that way, 4Q has always been down because as you remember in 2016 all we did this year was complete our DUC at the beginning of the year. We didn’t really have an active drilling and completion program in this particular year. So it’s always been projected to drop and in fact, we got it projected down to drop less than it was going to drop at the beginning of year because we’ve had some better performance.

But it’s always been on that cadence, because we sort of stopped our drilling at the beginning of the year. Then we started our drilling back, we’re really not doing any completions on that drilling program in 2016. So we’ve got eight completions that we may make at the end of this year. It won’t have a material impact on production, but it will help set us moving into 2017.

Tim Rezvan

Okay, thank you.

Operator

Thank you. Our next question comes from the line of Chris Stevens with KeyBanc Capital Markets. Please proceed with your question.

Chris Stevens

Good morning guys. I guess how do oil prices play into the three-year growth outlook? What oil price would you tap the brakes a little bit? What price would you accelerate beyond the current scenario?

James McManus

Yes, Chris I think if you look at – if you go back to kind of Slide 5, you see some pretty robust returns on there and we had talked about wanting to corporately have 30% pre-tax return. So I guess that’s been the bar that we’ve sort of used. And you can look at the slide there and see that our best stuff holds up really well even fairly low oil prices and we’re also hedged going into 2017.

So I think it’s going take a lot to make us alter off of this plan. We’ve got a really strong balance sheet as well and so I think we’re going to set sail and I’m not going to say we wouldn’t change our mind about something but with the balance sheet, the hedges and the returns we've got, I just don’t see a case where we’re going to be looking at scaling back unless we have an absolute complete collapse in the oil market. It could happen, happen before.

Chris Stevens

Okay. And then I guess in terms of the upside, I mean if these Gen 3 completions drive further improvements here for rates of return, would you be willing to outspend a little bit more to drive additional growth over the next couple of years?

James McManus

Well, I think as we always take a look at, plans could certainly be altered. This plan is a work in progress. I would say, one of things we’re doing now is we’re testing a lot of spacing. We don't want to get too far ahead of ourselves in terms of getting these wells on the right kind of spacing from a development perspective. So there is always a balancing act with that going on, but I think if oil prices came robust, we would certainly look at how we might think of accelerating, but I can’t tell you specifically how that would be.

Chris Stevens

Great, thanks a lot guys.

Operator

Thank you. Our next question comes from the line of John Freeman with Raymond James. Please proceed with your question.

John Freeman

Hi, everyone. I appreciate you’re providing this three-year outlook. It’s very helpful. When we’re looking at - that the three year outlook roughly what should we assume went into that for kind of capital allocation between the Midland and the Delaware? I know you have kind of talked about potentially I guess 60/40 split Midland Delaware. Is that kind of roughly what we should use?

John Richardson

John, that is correct. It's been a roughly over that period about 60/40 split, 60 Midland, 40 Delaware, could change a little bit that's within the balance of what we got model right now.

John Freeman

Great.

John Richardson

Half-and-half on the rigs, 60/40 on the capital.

John Freeman

Perfect. And then just one follow-up for me, has there been any update on the Howard County acreage? I know you were hoping to get a ruling in October.

John Richardson

We did. I’m glad you asked that question. The judge entered his final ruling in that course as we all know that’s appealable, but that happened matter of fact I think that happened just this week. So now we’re waiting for the party to appeal. In fact they will appeal. As I talked about before that can take a while eventually could wind up going to the Texas Supreme Court. But we are at least now ready to move out the lower court.

John Freeman

Excellent, thanks. Well done John.

Operator

Thank you. Our next question comes from the line of Sam Burwell with Canaccord Genuity. Please proceed with your question.

Sam Burwell

Good morning, guys. I just wanted to get your quick take on what you think of the M&A market, especially out on the Delaware. I mean realizing that you guys have done a good job of picking up acreage more cheaply, but have you guys looked at any of the splash year deals? If you have an opinion on where things could possibly go from here, I would appreciate that as well.

James McManus

Yes, Sam, we’ve certainly been abreast to the market and that we get a chance to look at everything that that’s out there for the most part. And I’m going to tell you, we’ve looked at every single one of them. I mean our view thus far has been that we got really high-quality inventory of the company and we are wanting to pick up acreage if we can at cheaper than some of the headline prices that have been paid and that's kind of been our mode.

As John just asked on the last question, we’ve also got just point out, not built into any of our inventory numbers or anything this 10,000 potential acres in Howard County in a very, very good position. But I wouldn’t want to comment on anybody deals specific. Except to say I think we’ve all been caught a little bit.

We’ve all been a little bit surprised at how quickly the price of acreage has accelerated, particularly in the Delaware basin. I think it's a good read-through in our acreage. And frankly as I would tell anybody, I wouldn’t trade our core for anything that’s been bought. I think our core will perform as well as anything out there.

Sam Burwell

Okay. And then just a stab at cost escalation, you said that the 2017 CapEx budget includes some escalation. Just wondering if you could possibly quantify that a little bit or any other expectations you have with regards to costs going up next year?

James McManus

Yes, really don’t want to quantify it. But I can tell you this I mean we don’t see a lot of rig pressure right now. We’re still in that 14,000 to 15,000 a day. So right now we’ve assumed that stays there. As you know that's not as important in the overall well cost as the completion side of things and we do have a modest increase built-in there for completions, but we’re still in the throes of negotiating that and I’d rather not talk about what we’ve got built in there.

Tim Rezvan

Okay great. Thanks guys. Great quarter.

Operator

Thank you. Our next question comes from the line Chris Stevens with KeyBanc Capital Markets. Please proceed with your question.

Chris Stevens

Hi guys. Are there any other zones that you guys are testing out in the Delaware Basin on your acreage? It looks like there’s some offset operators drilling Second Bone Spring right next to you guys and I know you guys have historically drilled some Wolfcamp XY wells around some of your acreage in Loving and Ward, but have you tested that at all in the Reeves County stuff? And I mean does that also have some potential there?

James McManus

Chris, we’ve drilled pretty much the XY sand on our acreage position. We did that several years ago and a little confusing because that was back at a time when most people characterized that as a Third Bone Spring. XY sand Wolfcamp is kind of at the top or the bottom of the Third Bone Spring, and then you’ve got the Wolfcamp shale, which what we’ve been focused on are the wells that we’ve been talking about now.

We certainly think there maybe some potential. A lot of operators are talking about the Third Bone Spring shale, which is not something we’ve tested. It’s something we’ve got on our acreage. We’re not planning to test it any time soon that because we’ve got out hands full moving forward on the good stuff that we know is going work. So we’re watching all of those tests and we do certainly have Second Bone Spring potential that we’ve not drilled.

Although the Second Bone Spring tends to come and go down where we’re in the Delaware Basin. The other zone I would mention that’s not one we’re planning to test anytime soon, but we certainly believe that as you move up into Loving County, the Avalon has potential for us as well. But right now we’re on our highest return step with our longest laterals and so we’re watching all that keeping an eye on all that, but we don’t plan to test that in the next year.

Chris Stevens

Okay. And then in regard to the wells that you completed this past quarter in the Delaware, what was the completion design that you guys used on those two wells?

James McManus

Gen 3.

Chris Stevens

Do you have the amount of past…?

James McManus

Chris, I am sorry. Well, I think it’s going to be pretty close to the 1,800 pound sand, but I’ll turn to Johnny here.

John Richardson

It’s in that range. We did run some higher sand cost inflations in one or two up James. It’s still within the 1,800 to the 2,400 pound range and this is sort of buried in that range for what we’re trying to test any 12 bore.

James McManus

And it would have been Chris, close to the 200 staged spacing 33 foot cluster spacing and 40 pounds per foot that we show on the slide there.

Chris Stevens

All right. Got it, thanks a lot.

Operator

Thank you. Our next question comes from the line of Irene Haas with Wunderlich Securities. Please proceed with your question.

Irene Haas

Congratulations on a really strong quarter and a very, very bullish outlook. And my question for you is that you ramp up and I noticed that G&A has shrunk somewhat. Do you have enough sort of human resources to get you up and running again on with a higher rig count? Do you have any needs to add human resources? And then also the second question is with this very, very bullish outlook. What crude price would cause you to pause and reconsider?

James McManus

Yes, so Irene the first question is we think we can execute this plan with a very minimum number of personnel add, so it’d be less than 10 people. So we’re not looking at a big number of ads to and in fact we expect that as we grow production on a unit cost G&A will continue to shrink over time. So I think the answer is we can do this plan pretty easily with very minimum ads.

On the second question as it relates oil price, coming back to again that our returns on Slide 5 are really, really strong and we typically like to see a 25% to 30% pre-tax internal rate of return before we go forward. Oil would have to really collapse the levels back that we had in January, February before we would I think cap the breaks. So I think we will be moving forward.

The other thing we’ve got in our favor, two things that we didn’t have at the beginning of 2016 is we’ve got an extremely strong balance sheet right now with cash on the balance sheet and we’ve also got a pretty robust hedged position. So all those things point to and can take a real negative backdrop for us to tap the brake.

Irene Haas

Great, thank you.

Operator

Thank you. Our next question comes from the line of Dan Guffey with Stifel. Please proceed with your question.

Daniel Guffey

Hi guys. Congrats on a good quarter. Just wondering if you can talk a little bit about spacing your density caches you are currently drilling or planning to drill in 2017 and then just your thoughts on where ultimate spacing or the optimized spacing may end up per zone.

James McManus

Yes, so Dan I’ve done a lot of talking about this that Energen has been on the right - I really think we’re very much in the early innings of this. We talk about the 23 wells that we drilled in the section in Martin County in the most of any Permian - 25 in the most that any Permian operator has drilled in a single section so far.

So we’re kind of a little bit, I think on the cutting edge of that. And we've got a number of different down spacing set that we're going to be looking at on half sections and three quarter sections as we move into 2017 and I think it's going to be a long time before we know exactly. I’m going to kind of duck the question on spacing at a long time or know exactly what the right spacing and the right frac job is and it may vary by zone with Lower Spraberry maybe different than Wolfcamp A, different than Wolfcamp B in terms of even the type of frac that we put on it.

So I think we’re in the early stages of that. I would ask Johnny to comment with any additional color that he would want on that.

John Richardson

Yes, I think that’s exactly right. We see and appreciate some of the top end numbers out there and we think they're certainly theoretically possible. We're trying to ascertain whether they’re physically or mechanically possible to drill that kind of density and so we look at this as a cube and it’s fairly integrated problem that we’re going to solve but it’s going to take a little more data, little more time.

James McManus

Dan, I would follow-up with one comment that I was going to make, quality of what we’ve got in the Northern Midland Basin and in the Delaware Basin is as good as anybody's and my view is that whatever ultimate density one being a lot tighter than what we currently have in our inventory or somebody else is going to be that type for us and in fact we got a lot of folks wanting to trade information with Energen on the 25 wells we drilled in Martin County to see what kind of - what we learned from that particular situation.

So I don't think anybody knows, then I don't think anybody is going to know optimum spacing for a long time but I think that’s one of the reasons that you want to have a prudent program as you move through, but you just don’t want to go drill everything on one particular spacing because you may come back and wish you'd done it either a little tighter or a little looser.

And so our process has been the way we're thinking about it right now is we’re going to –experiment with moving a little tighter, but we’re going to go slow with that.

Daniel Guffey

Okay, great, thanks for all the color. Last one for me, just curious on infrastructure constraints in the Delaware. I know there's - a lot of infrastructure is going to need to be built over the next few years, whether that's gas processing or water lines or saltwater disposal. Just kind of wondering if that - if you think that could be a governor for your growth, or - and then how should we allocate spending to that infrastructure over the next couple of years?

James McManus

Yes. So we really don’t think. So I mean I think we did in both basins over the next two, three years and I would say my comments there would be very consistent with other operators in the basins, a lot has been done to alleviate infrastructure problems in both basins in terms of our facilities, in terms of water disposal salt water. We typically like to think about 8% to 10% of our capital in any one year is going to go for that type of thing.

Daniel Guffey

Okay, great. And congrats on a good quarter again guys.

Operator

Thank you. Our next question comes from the line of Drew Venker with Morgan Stanley. Please proceed with your question.

Drew Venker

Good morning, everyone. Hi. James, I was hoping you’d just talk about the approach toward spending going forward. You talked about getting close to cash flow neutrality by 2018. Is the idea beyond 2018 to just spend the cash flow? You can talk about the appetite there.

James McManus

Well, not necessarily Drew. I think one of the things you want to be able to demonstrate that shows kind of the strength of your - the properties you have is that if you can grow at high rates within cash flow just I think speaks to the capital efficiency of what you guys and so we wanted to highlight this. But with our balance sheet and when we combine that with the Central basin platform as we move through this plan, there's a lot of opportunities for Energen to press on the accelerator, if we choose to.

So we've got a balance sheet that as we model and as we stay in the release that tends to de-lever itself and so the other thing that it affords Energen, the opportunity to do is be opportunistic that acquisitions and we've been - we’re doing it a little a little chunk at a time, at very good values, but the acreage that we’re picking up is in all the right places. And if it were one big package it would have gone for a lot more than what we paid for and we’ve been trying to hit that value proposition as opposed to some of the headline prices that are being paid today.

So I mean I think that’s an open issue as we move forward through this plan whether we decide later in the plan to put more capital to work than we've got currently in here and I think it’s also a function of how good we feel about, our knowledge about how we want to base and complete these wells.

So it’s pretty complicated matrix, but I think the takeaway I would leave with you is I think we've got one of the best balance sheets in the business. If oil prices were to be around the strip pricing that I disclosed or even a little bit lower that balance sheet is going to continue to look good and we don’t have even in thinking about that balance sheet delevering, we don’t have any kind of production uplift built in there for Gen 3 frac. So it actually could be better than what we’re showing if we wind up with good success in Gen 3, so I think it’s all positive.

Drew Venker

Okay. So comfortable with some leverage as long as the balance sheet remains strong?

James McManus

Absolutely.

Drew Venker

Okay. And for next year, can you give a little more detail on the drilling program in the Midland basin where you plan to focus activity and what zones?

James McManus

Yes, I think and I’m going to let Johnny to jump in on this as well. We’ll clearly be in all three of what we consider the Sprayberry package in the Middle, the Lower in the Jo Mill where we talk about will also be in A and B in the north. And then we’ll have some drilling in Glasscock County, probably more focused on the A, but they’re will be a few B’s in there as well. And then in the Delaware Basin, I think it’s going to be a combination of A’s and B’s.

John Richardson

Correct.

James McManus

It sounds like I got it right, Drew.

Drew Venker

Okay. And then just could you talk about some of the recent Wolfcamp wells that you completed in Martin County? I think you had completed a number of wells earlier this year. I just don’t think I saw any color in the performance?

James McManus

Yes, we’ve really not talked about those. At this time, we don’t really have a type curve out there. It might be something that we decide gives more clarity on later. But right now at this point we’re not really talking about those.

Drew Venker

Okay. Thanks for the color.

Operator

Thank you. Our next question comes from the line of Jeanine Wai with Citigroup. Please proceed with your question.

Jeanine Wai

Hi, good morning everyone. I just wanted to go back to your previous comment. When you said on infrastructure that you think that you’re covered for the next three years for your plan? Does that mean that you don’t see any constraints on getting the right infrastructure in place in the basin or that you already have had a capacity or contract signed up and in placed?

James McManus

Well, Jeanine, I think it would be that we don’t see any bottleneck over the next three years. We think that are number of things that happened in the Delaware. They are more ability to move natural gas and process gas. So we’re basically - we’re not in that business. We typically sell at the wellhead. So we think there’s good infrastructure. In my comments surrounding 8% to 10% capital really relate to our facilities to dispose of water, tank batteries and things of that nature turned around 8% to 10%.

Jeanine Wai

Okay, great. And then my second question you just mentioned next year in the Delaware, you would be doing a combination of Wolfcamp A’s and B’s, so in terms of what the activity might look like throughout the basin, will you be testing a lot of different areas or do you think you’ll be in concentrated kind of development mode, trying to catch more of the efficiencies then just sticking to one area?

James McManus

We’re not totally spread out across the whole footprint. But we are not concentrated either we’re going to look at some spacing in test. I mean we’re very confident that the A and the B is going to be a great producer across our footprint. But we will look across the footprint as far as trying to determine a little bit of spacing and a little bit of development rhythm there. So next year will be sort of dedicated that.

We’ll do some density drilling and then we will do some one’s and two’s off in other areas, just to validate some theories. So really a pretty diverse program next year in the Delaware.

Jeanine Wai

Okay, great. Thank you very much for taking my call.

Operator

Thank you. Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Charles Meade

Good morning James and to the rest of your team there.

James McManus

Good morning.

Charles Meade

You’ve covered a lot of ground here already in the Q&A, but I wanted to go back to a comment you made earlier, I think in response to an earlier question about the rollout of the Gen 3 fracs across your program. Is that – did I understand correctly that that you’re going to do all of your 2017 wells with the Gen 3 frac and would that also imply or that will also imply that you’re going to do Spraberry completions in the Midland Basin with the higher intensity frac as well?

James McManus

So Charles, it would. I mean, that’s the plan right now, unless we saw some type of underperformance and a lot of times you’re not going to see that. I mean there is a body of data that would suggest to us that this is the right way to go. We have a few completions ourselves that we’re looking at as I’ve said, but yes, that’s the plan right now.

Charles Meade

Got it. Thank you for that clarification. And then this is going to sound like a pie-in-the-sky question, but at what point do you think you’ll have enough data on all of your Gen 3 completions across these different zones that you will look to start designing your Gen 4 or whatever next-generation. Will that be late 2017 or is that a 2018 thing or what’s your sense at this point?

James McManus

Well, I guess the true answer is the completions are very dynamic thing. I am not sure you ever unless you are way down the road and to develop the area that you actually have a cookie cutter recipe particularly not on area this diverse like you mentioned Spraberry, Jo Mill some sand, some shale, some combination of hill stones. So there will be some tailoring going on as soon as we get the foundation and so I couldn’t really tell you about the timing.

All our frac jobs are not the same for next year. We’re looking to next year at a diverse package. However, they will sort of follow this trend of going from the Gen 2 to the Gen 3. So there is always a dynamic there. Nothing is every constant. We’ll continue to look into engineer and to – when we start getting data back, the next generation of wells will be tweaked to take advantage of that knowledge.

Charles Meade

That’s helpful color, Johnny. Thank you for the detail.

Operator

[Operator Instructions] Our next question comes from the line of Gail Nicholson with KLR Group. Please proceed with your question.

Gail Nicholson

Good morning. In the press release, you talked about Midland Basin drilling times are ahead of schedule. Can you talk where its current cycle times are in the Midland today and where they were a year ago?

James McManus

They come down a good bit. I think we’re programming for rig. We’ve programmed 12 wells, I think its 18 days of well that we’re programming and that includes a diverse group of wells, but that’s on average about in the Midland Basin. I think yes, spud to release on that. And so little bit of longer in the Delaware Basis. I think we’re programming just in general numbers I think nine to 10 wells per rig in the Delaware.

Gail Nicholson

Okay, great. And then looking at the 12 Lower Spraberry wells completed in Martin County in the first half of 2016, were all those wells completed in the same landing zone or were those in different landing zones within that lower Spraberry?

John Richardson

They were in different landing zones in Lower Spraberry. You need to think of them as they were kind of wine rack.

Gail Nicholson

And is any one landing zone outperforming the other?

James McManus

It’s probably a little early.

John Richardson

Too early.

James McManus

They do seem to have a different character, but they’re too early to tell.

Gail Nicholson

Okay, great. Thank you.

Operator

Thank you. Our next question comes from the line of Michael Glick with JPMorgan. Please proceed with your question.

Michael Glick

Good morning. Just a quick one from me. In the Delaware, on that Razorback area in Loving County, could you speak to what’s going on geologically that’s driving the higher GOR in that specific area?

John Richardson

Yes, so Michael there is a small fault in there that we believe is responsible for that and again we can confirm it with the tremendous amount of well data, so we have a high confidence level. In fact if you look Matador drilled the well in the XY sand there. They had the exact same gas character that we have right next to the Razorback and Hogback, if you want to go look that well.

So it’s sort of unknown feature. It’s something that we need to do in order to hold that acreage. But I would also point out that even with that oil content on that small amount of acreage, those returns in that area are still outstanding.

Michael Glick

Got it. Thank you very much.

Operator

Thank you. Mr. McManus, there are no further questions at this time. I’d like to turn the floor back to you for final remarks.

James McManus

Well, thank you Melissa, and appreciate everybody’s interest in conference. Have a great weekend and for me its roll tide, talk to you later.

Operator

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.

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