Energen (EGN) James T. McManus, II on Q2 2016 Results - Earnings Call Transcript

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Energen Corp. (NYSE:EGN) Q2 2016 Earnings Call August 9, 2016 11:00 AM ET

Executives

Julie S. Ryland - Vice President-Investor Relations

James T. McManus, II - Chairman, President & Chief Executive Officer

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Charles W. Porter - Chief Financial Officer, Treasurer & VP

Analysts

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Carlos Newall - Raymond James Financial, Inc. (Broker)

Derrick Whitfield - GMP Securities LLC

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Jeanine Wai - Citigroup Global Markets, Inc. (Broker)

Kyle Rhodes - RBC Capital Markets LLC

Ben Wyatt - Stephens, Inc.

Chris Dendrinos - KLR Group LLC

Operator

Greetings and welcome to the Energen Second Quarter 2016 Financial and Operating Results. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation.

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

Julie S. Ryland - Vice President-Investor Relations

Thank you, Doug, 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 June 30, 2016.

The second quarter 2016 supplemental slides can be found on Energen's homepage at www.energen.com. If you haven't already gotten a copy of these slides, please do so now as these will form the basis of the company's prepared remarks.

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 Securities and Exchange Commission 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 Chief Executive Officer, James McManus. James?

James T. McManus, II - Chairman, President & Chief Executive Officer

Thanks, Julie. Good morning to you all. Energen just completed another great quarter of production outperformance, declining costs, and capital efficiency gains. These trends are key components of the bigger Energen story, a story of financial strength, asset quality and long-term growth potential.

I'm going to kind of run through the slide deck with you now. If everybody would turn to slide number two in the deck. Just to touch on our second quarter 2016 highlights, strong production growth. We've seen very good response to our Generation 2 frac designs. 2Q 2016 production exceeds the guidance midpoint by 4%; 2Q 2016 production up 7% sequentially and we revised the calendar year up 2% or 900 BOE per day.

We continue to see broad-based efficiency gains. LOE declines 27% in 2Q 2016 from the guidance and we dropped the calendar year by 11% on LOE, continues to be a very good story there. Completion optimization continues to evolve. DUC completions in 2017 are expected to use more sand, fluid, tighter frac stages and clusters. We've seen very good results from Generation 2. We'll be starting to test Generation 3 in 2017 as well.

Core Delaware Basin. We've optimized our surface facilities there to help boost our estimated internal rates of return for our longer lateral wells. Those are some of the best things we've got in the company now that we have cored up the Delaware Basin. We've got a lot of conviction around our lease position out there in the Delaware Basin.

Capital efficiency improvements continue. D&C costs continue to improve. I'll give you two wells that we just recently drilled that indicate that in just a few moments. Obviously attractive drilling times in both basins. I also mentioned bolt-on acquisitions. We've now acquired 4,500 net acres year-to-date in our core positions in the Delaware and Midland Basins and that was acquired at a little over $6,000 per acre. Obviously, that's a much more attractive price than what you've seen recent transactions trade at. We continue to try to increase our positions in both of those basins.

We now turn to slide three. LOE, including marketing and transportation, down 27% from the guidance midpoint. A basically lower water disposal, gathering, electrical power costs and fewer workovers. Production of 56 MBOE per day exceeded production guidance midpoint by 3.9%. As part of that, oil production was up almost 5% relative to the guidance midpoint. Production increased primarily driven by Midland Basin horizontal plays which were up 7.1% over production guidance. The remaining DUC inventory of 14 wells were completed in the second quarter. 24 DUCs were placed on production. 22 in Martin County, targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B zones, and two Glasscock County targeting the Wolfcamp A and B.

Lateral length of the Martin County wells placed on production averaged about 6,700 feet, and the Glasscock County wells had an average lateral length of approximately 7,600 feet. Based on early production result, these wells are outperforming internal expectations due in large part to the company's Generation 2 completions.

In Martin County, for example, six Lower Spraberry DUCs with more than 60 days of productive history are averaging a 900 MBOE EUR estimate. In their first 90 days of production, the nine Glasscock County DUCs completed in first quarter 2016 have outperformed the type curve.

We then turn to slide four. Guidance midpoint was lowered by 11%. Net SG&A, midpoint range up slightly. I want to explain this. Primarily due to adjustments in performance-based compensation. Our non-officer compensation is sensitive to the share price, and as the share price has gone up, so has that expense. All other expense categories largely unchanged.

Full-year production guidance increased 2% to 54 MBOE per day. 4Q 2015 to 4Q 2016 exit rate decline continues to shrink and is now estimated to only be 8%. I would also note on this slide, we continue to break out our cost by basin and our cash and non-cash G&A so that proper comparisons can be made to other companies who may not operate in the Delaware Basin or in the Central Basin platform.

We now switch to slide five. We're now putting out some data to support and back up our type curve and our core acreage in the Delaware Basin. Energen's decision to allocate increasing amounts of capital to its core Delaware Basin is a result of strong performance by five wells we drilled in the core and from approximately 20 wells drilled by offset operators. So we got 25-well history data here which is a lot. As well as from expectations of continued efficiency gains.

This graph summarizes what we saw in the performance of our five wells drilled in Reeves County in the core of our acreage footprint. It shows the average cumulative production of these five wells and our 1.5 MMBOE EUR potential type curve normalized to 7,500 foot. These Reeves County wells have been producing for a long time, for approximately 12 to 24 months, and include the Wolfcamp A, B, and C. So we got a lot of productive history.

As you can see, the 377-day average cumulative production of the five Energen Wolfcamp wells normalized to 7,500 is closely tracking the 1.5 MMBOE EUR type curve. Upside potential in the majority of the wells completed with the Delaware Basin Generation 1 frac design. So in this particular case, most of these were all Generation 1 frac design, so we've got some real hope as we move to Generation 2 and perhaps Generation 3 in the Delaware Basin.

We then move to slide six. We're very excited about the outstanding internal rates of return we see on the Wolfcamp A and B in the core Delaware Basin. These returns reflect EURs estimated to approach 1.1 MMBOE for a 4,500-foot lateral, 1.5 MMBOE for a 7,500-foot lateral, and 2 MMBOE for a 10,000-foot lateral. They're shown for a variety of fixed prices from $35 to $65 per barrel flat and reflect current and targeted D&C cost.

Yesterday, we announced that we've increased our estimated internal rates of return for 7,500-foot and 10,000-foot lateral lengths in the Wolfcamp A and B wells in our core Delaware Basin as a result of increasing flow rates, primarily by optimizing surface facilities. When we originally came out with the curves, we were a little bit more conservative. We've now worked out the ability to produce the longer lateral at higher rates in early time.

We're making progress towards our targeted D&C costs shown on this graph. We've now drilled a 9,000-foot Wolfcamp A well in the core Delaware in 22.4 days, spud to TD. We plan to complete this well in the third quarter with a Gen 3 frac design at an estimated D&C cost of $7.2 million, which is very attractive from a return perspective.

We now move to slide seven, looking at our completion design in each one of these basins. I'm not going to walk through slides. They're pretty self-evident. Gen 1, Gen 2, Gen 3 and, of course, in all of them, you see more proppant, tighter staging, more fluid and tighter cluster spacing as well.

In the Midland Basin, we've done some testing of Gen 3 this year, although the majority of DUCs estimated in the first half of this year were using Gen 2 design. The four drill the whole wells in the Delaware Basin will be completed with Gen 3 frac design. Anyway, we continue to look at this, continue to work on it, continue to look at the extra costs versus the extra EURs. And I think what we're doing here is very consistent with what some other folks are doing in terms of completion design.

We then flip to slide eight. We continue to increase our 2017 oil hedge position in the second quarter by adding 3-way collars for 1.1 million barrels of oil production at an average call price of $65.67 per barrel, an average put price of $45 per barrel and an average short put price of $35 per barrel. This brings the company's total oil volumes hedged in 2017 to 8.2 million barrels.

We also have added 2.4 Bcf of Permian Basin specific contracts to our 2017 natural gas hedge position at an average contract price of $3 per Mcf. This brings our total natural gas hedge position in 2017 to 13.2 Bcf of basin-specific gas at an average contract price of $2.85. Assuming a $0.15 per Mcf differential, the company's NYMEX equivalent price for 2017 gas hedges is $3 per Mcf.

The point here, the company's got a very strong hedge position moving into 2017, which leads us to slide nine where we don't just have a strong balance sheet. I think we've got one of the strongest in the E&P industry. Just to kind of walk you through this slide for a minute. If you look at our net debt at the end of 2015, $775 million. Our capital investment now stands at $485 million including our drill and complete plan of $450 million. You can see the net proceeds from the equity offering. Of course that's done. Net proceeds from asset sales is now completed. We closed our last sale yesterday. And so all those funds have now been received and the proceeds are in house. So happy to have that behind us for $538 million and foot it on down and you can see that net debt to EBITDAX is estimated to be only 0.5 at the end of 2016.

We recently also – and of course we've got nothing drawn on the revolver. Long-term notes outstanding of $554 million and a borrowing base potential of $1.050 billion. You can see on the right hand side of that slide, no real significant maturities and I would also point out that Moody's recently upgraded the company on July 29 from B1-negative to Ba3-stable.

We then go to slide 10, which discusses the rebuilding of our DUC inventory. Drilling is currently underway on the 54 to 58 net DUCs that will be available for completion in 2017. By the end of August, we'll have 11 rigs running. Five of those rigs running in the Delaware Basin and six in the Midland Basin. We expect to have a total of four to five rigs running at the end of the year split evenly between the two basins.

Estimated capital investments for drilling and development activities were approximately $450 million. Approximately $37 million invested through July 31 to acquire acreage and renew leases, including adding again, as I've discussed, more than 4,500 net acres in the core Delaware and Midland Basins through bolt-on acquisitions at extremely attractive prices, particularly compared to what prices are being paid right now or in recent transactions.

In July alone, we added another 851 net acres to our core Delaware Basin footprint. Most of the new DUCs in the Midland Basin will be 10,000-foot lateral-length wells in Martin County, targeting the Jo Mill, Middle Spraberry, Lower Spraberry, Wolfcamp A and B. The average working interest in the new drills is estimated to exceed 97%.

In the core Delaware Basin, new drills will focus on Wolfcamp A and B in Reeves and Loving County, and all but two potential DUCs will have an average lateral length in excess of 9,500 feet. Energen's working interest in the new drills in the Delaware Basin is approximately 100%.

Capital efficiency gains continue. I'd point you to the two bullets at the bottom of the left-hand side. As I previously mentioned, the Delaware Basin well in 22.5 days at a D&C estimated cost of $7.2 million and a 7,500 foot Glasscock Wolfcamp A DUC drilled in 13.1 days, completed with a Generation 3 frac design at a D&C of $5.2 million. Now, these aren't trending or leading-edge costs. These are pretty much actual costs.

If we then turn to slide 11, it's to summarize the 2017 outlook. Armed with one of the best balance sheets in the business and an excellent 2017 hedge position, we're very excited to be focused on bringing forward the value of what we believe are one of the highest quality asset bases in the Permian Basin and we will also be looking at the potential to pursue some bolt-on acquisitions that we've continued to work on in our core areas.

As we look to 2017, we'll target those projects that offer long laterals in combination with high working interest. At a minimum, we'll require a pre-tax internal rate of return of 25% to 30% on wells drilled. Obviously, they greatly exceed that right now. And to ensure balance sheet strength at the end of 2017, we're targeting a net debt-to-EBITDAX from drilling and completion activities near 1.0, although we're not a slave to that. While our plans for 2017 are still evolving, we believe that completing our DUC inventory in the first half of 2017, combined with additional drilling and development supports solid year-over-year double-digit production growth in 2017.

At this time, what I'd like to do is turn the call over to Doug for Q&A. Doug?

Question-and-Answer Session

Operator

Thank you. Our first question comes from the line of Neal Dingmann from SunTrust Robinson Humphrey. Please proceed with your question.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Morning, James. Nice quarter. Say, James, obviously, with the potential, just the strong balance sheet you have, you talked about running the DUCs up towards year-end. Could you talk about as much as you can say on 2017 as far as do you think you would knock out most or all of those DUCs? And then talk about potential, the new well completions that you would see during the year as well.

James T. McManus, II - Chairman, President & Chief Executive Officer

Yeah. So, Neal, I think right now, with the oil prices where they are and the stability and the hedge position that we've got in the balance sheet, we would expect to complete the DUCs in the first half of 2017 in a pretty quick process like we did this year with the DUC inventory.

And then obviously with the hedge position and the balance sheet we've got and the returns we've got, we'll have some type of – right now, we would look to have some type of drilling program in 2017. And again, we've kind of hinted at what that might be by saying that we'd let debt-to-EBITDAX run up to about 1. So that'll give you a little bit of a feel of what we might be willing to outspend by.

In terms of completions, I think what we'll be doing is we'll be doing some – continue to do some Gen 2. And we'll be experimenting with the Gen 3 completions all at the same time and so there'll be a mixture in there as we look at the results that we get from some of the Gen 3 wells that we've got this year. So, I think we're going to continue to be pushing the envelope towards more and more to the point, to make sure that it pays for itself and we'll be looking at that as we move forward. The Gen 2 fracs have been great so far. And we'll be looking at pushing the envelope towards those Gen 3 fracs.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Perfect. Thank you.

James T. McManus, II - Chairman, President & Chief Executive Officer

Thank you, Neal.

Operator

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

Irene Oiyin Haas - Wunderlich Securities, Inc.

Hey. Good morning. Congratulations on just a great quarter. And looking forward, I would like to zoom in on Delaware Basin. How many wells in total you have drilled now excluding the 2016? And you mentioned that one of your best wells you can drill in 22 days and $7.2 million. As we look into 2017, should we expect more improvement because we're early? And also have you done any spacing test in Delaware Basin say for each of the interval like Wolfcamp A, B and C?

James T. McManus, II - Chairman, President & Chief Executive Officer

Yeah, so several questions there, Irene. This one that we drilled in 22 days was part of the four drill the whole wells that we were drilling in 2016. Now, we're obviously drilling right now, building that DUC inventory. I'll let Johnny talk a little bit about the spacing test. But we've had continued drilling improvement and we're hopeful that we'll be able to continue to move in that direction. But Johnny, let me let you comment on that a little bit.

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Yeah, Irene. I would tell you, you know we've just gone back to work in the Delaware with a new fleet. And you got to get your team established. The fact that we were able to do this, accomplish this 22-day well this early is very encouraging. We think there's more upside in the Delaware drilling times and getting our program together. I think you'll see us continue to improve there and we plan to improve.

As far as spacing test goes, as we're continuing our 2016 drilling, we will begin to do some spacing tests. We have not done any meaningful spacing thus far; others have. We're looking at that data, but you'll begin to see us do that with the wells we're drilling now and we'll continue that into 2017.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Okay. May I have one follow-up question? You were able to get some bolt-on acreage for, what, $6,000 per acre? Now, with a very distilled acreage footprint in the Delaware Basin, would you venture to guess how much you can fetch in the open market if you were to sell your core? I'm just looking for general numbers.

James T. McManus, II - Chairman, President & Chief Executive Officer

Oh, my gosh, Irene. I think our core is really, really great stuff. So I don't think it would – I think it would go for way more than the highest prices I've seen. Without giving you a number on that, the highest price I've seen for Delaware acreage thus far has been $35,000 an acre. Do I think ours is worth a lot more than that? Absolutely. How much? I don't know, but it's worth more than that.

Irene Oiyin Haas - Wunderlich Securities, Inc.

And bulk of your remaining stuff is in Loving, Reeves and a little bit of Ward. Is that right?

James T. McManus, II - Chairman, President & Chief Executive Officer

Yep. That's right.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Okay, great. Thank you.

Operator

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

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Hey. Good morning, guys. Great quarter. Just given that you guys have a pretty large cash balance at this point on the balance sheet and when you think about the typical delay from spud to sales and you're completing all these wells on large pads. Why not maybe start completing some of the wells a little bit earlier this year to get a head start on production as opposed to waiting until next year to start completing those wells, especially when you think about the return profile that you're seeing in the current environment?

James T. McManus, II - Chairman, President & Chief Executive Officer

Yeah. Chris, let me get Johnny to comment on that. There's some physical issues around having the number of rigs that we've got working and the way we do the cadence of our completions that doesn't allow us to do very many of those this year. But I'll let Johnny explain that.

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Yeah. Chris, as James mentioned, we have 11 rigs working now. So we've drilled all these wells in the back half of the year. We're very busy. The short story is we just can't get out of our own way. We got rigs still drilling in areas where we know that we need to keep – observe our halos. We know how these wells act. We've done a lot of density drilling, more than anyone else. So, we know what footprint we need, what the halos need to be and we just can't materially complete any meaningful number of wells this year because we're just on top of ourselves.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Okay. That's understood. And then in the Delaware Basin, on these upcoming wells that you're going to be completing this quarter, are we going to actually get some results with earnings in the third quarter? And can you just provide a little bit of color in terms which zones you're going to be landing those in and whether the proppant concentrations are going to be closer to that 1,800 pounds per foot or 2,400 pounds per foot?

James T. McManus, II - Chairman, President & Chief Executive Officer

I'll let Johnny comment on the proppant, Chris. I can tell you the results. We won't have any next quarter. I mean, those wells are just starting to flow back and be cleaned up and we like to have a good bit of data before we put anything out. So I suspect not this quarter. Whether we have something at year-end or not, we'll just have to see. But I think most of these are going to be closer to Gen 3. Where in the Gen 3, I'm not sure.

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Yeah, they're going to cover the gamut. I mean, we're going to see something, if you look at what we've given you for those frac designs, we're pretty much going to look at everything in that spectrum with these four wells.

James T. McManus, II - Chairman, President & Chief Executive Officer

So, Chris, basically, that means we're going to do probably one up to 2,400 pounds per foot, probably one at 1,800 pounds per foot and maybe one at 2,000 pounds per foot. I mean, we're going to be in that range, on the lower and upper bound.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Are they all in the A-bench, and are you planning those in the lower...

James T. McManus, II - Chairman, President & Chief Executive Officer

They're As and Bs, I believe, primarily.

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Yes. That's right. Yeah.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Okay. Appreciate it. Thanks.

James T. McManus, II - Chairman, President & Chief Executive Officer

Thank you, Chris.

Operator

Our next question comes from the line of Carlos Newall from Raymond James. Please proceed with your question.

Carlos Newall - Raymond James Financial, Inc. (Broker)

Morning, guys. Congrats on a good quarter.

James T. McManus, II - Chairman, President & Chief Executive Officer

Thanks, Carlos.

Carlos Newall - Raymond James Financial, Inc. (Broker)

Referring to the slide on where you show average Wolfcamp A, B, and C wells tracking against the type curve, is there a wide range in well results between different intervals, or is it more or less consistent?

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

The A and B is pretty consistent. The C is – there are not as many C wells in this body of work. But the C tends to be a little bit gassier, but I – my memory says that on a BOE basis, it's right in there with the others. It's just a little bit different product mix. But the A and the B are very similar.

Carlos Newall - Raymond James Financial, Inc. (Broker)

Thank you. And just a quick follow-up. You mentioned this briefly earlier, but could you quantify what kind of EUR uplift you're looking for to justify Generation 3 frac designs in the Midland Basin?

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Well, we haven't – I mean, we've got some targets inside the company. A lot of that depends on just the economic. So as we actually get there, what can we do the drilling cost for and the completion piece. But you're going to have to see another 10% or 15% uplift at a minimum, I think, to justify going there.

Carlos Newall - Raymond James Financial, Inc. (Broker)

Great. Thank you. That's it for me.

James T. McManus, II - Chairman, President & Chief Executive Officer

Thank you, Chris, or Carlos.

Operator

Our next question comes from the line of Derrick Whitfield from GMP Securities. Please proceed with your question.

Derrick Whitfield - GMP Securities LLC

Good morning and great update, guys.

James T. McManus, II - Chairman, President & Chief Executive Officer

Thanks, Derrick.

Derrick Whitfield - GMP Securities LLC

What are the price assumptions underpinning your initial 2017 outlook for double-digit growth?

James T. McManus, II - Chairman, President & Chief Executive Officer

Well, we looked at it a different way. As I mentioned, we're looking at it as a return threshold. I mean, we've been managing the company that way from a return basis. So, we got a soft return of 25% to 30%, which we think sort of covers a lot of the other costs that you have out there that aren't included on a single-well model.

So, we use that as our – so it's not really a price-dependent. But if you look at our returns, you can see that we can go pretty much at 40%, 45%, there's no problem. You're going to have to get down to the 30% range or below before you start pushing those types of returns, if I remember the numbers correctly. So if you want to relate it to price, you can by looking at the projected returns we've got on our slides. But we're really thinking about it from a return perspective which, of course, price factors into your return.

Charles W. Porter - Chief Financial Officer, Treasurer & VP

Derrick, this is Chuck. As it relates to – just to build on that, as it relates to the comment that we made relative to the debt-to-EBITDAX target, we're running the company's model more or less at a recent strip of $45, plus or minus.

Derrick Whitfield - GMP Securities LLC

Very helpful color.

Charles W. Porter - Chief Financial Officer, Treasurer & VP

Derrick, I want – yep. Yep.

James T. McManus, II - Chairman, President & Chief Executive Officer

Yeah. Okay.

Derrick Whitfield - GMP Securities LLC

Yeah.

Operator

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

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Morning, guys, and congrats on a good quarter.

James T. McManus, II - Chairman, President & Chief Executive Officer

Thanks, Dan.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

I guess a question is at what point will you have an active development on the Eastern Ward and Winkler areas of your Southern Delaware Basin? And I guess, what are your expectations for this Tier 1 acreage?

James T. McManus, II - Chairman, President & Chief Executive Officer

Well, I think most of our program for this go-round is going to be Reeves. Some of it will be...

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Yeah. That Reeves Ward area.

James T. McManus, II - Chairman, President & Chief Executive Officer

Reeves, Ward area. So I mean that's where most of our DUC inventory that we're building this time is going to be.

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Reeves, Loving.

James T. McManus, II - Chairman, President & Chief Executive Officer

Reeves, Loving, Ward. I'm not quite sure. Are you talking – what specific area are you talking about because – you talking about far to the east?

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Yeah, I guess, just in your Tier 1, so yes, further to the east; what you guys are considering to be Tier 1.

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Well, nice thing about that is all HBP over there. We're focused more toward the heart of our acreage. I don't think we've got any current plans to go over there, primarily because we want to stay where we've got the synergies. Part of the beauty of the Delaware Basin, or part of the key to unlocking it, is to have enough synergy to really get your facilities in place, your water disposal and your gas takeaways. And given the fact we have no pressure to drill in the east, we don't have any short-term plans to move that way.

James T. McManus, II - Chairman, President & Chief Executive Officer

And, Dan, those are, right now, projected obviously to be a little bit lower EUR type curve range. We've got 800,000 to 1 million in there. Whereas in the core, we've got 1.2 million to 1.5 million. I think we got plenty to do in the core right now. And as Johnny said, no pressure to drill on the east side because it's all HBP. I mean, one of the beauties of what we did when we trimmed our Delaware acreage position is we got rid of things that had quick expiring leases, things that were gassy, areas where we didn't believe we could drill long laterals, and those were the criteria.

And so, with the new cleaned up acreage, there are some drilling requirements, but they're very modest compared to what we would have had on the whole package previously, in addition to coring up into what we think is the best area.

But I think Johnny's right. We don't have any plans to move on that far eastern side right now in Tier 1, although we're watching very carefully what's going on. There's really no reason to head out there right now when you've got great stuff to drill in the core.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Okay. Great. Thanks. And then, I guess, asking the acreage question a little bit different. I mean, do you have any desire to use your strong balance sheet to grow and/or consolidate acreage positions in the Southern Delaware or Midland Basins? And if so, I guess what areas are your land team currently focused on that consolidation?

James T. McManus, II - Chairman, President & Chief Executive Officer

Yeah. So we do have that capacity and we are actively looking, and we'd like to do it on a good value proposition, not to say we wouldn't do a larger one as well. We're thinking more in terms of the $100 million to $200 million range, but we're also very satisfied with picking up the smaller pieces. And no surprise, we would be looking in and around where we currently are, which is where we think our core acreage is. And so, we're looking more to positions that would add to our current positions than we are moving necessarily into a new area.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Okay. Great. And then, last one for me. Just wondering if you can provide any update on the Howard County acreage. We saw a nice acquisition from one of your competitors recently. Just wondering where that's at.

James T. McManus, II - Chairman, President & Chief Executive Officer

Yeah. So we won the initial ruling in the lower court that the lease had expired. I believe right now the judge is determining primarily what the vertical wells that the previous party is going to hold, whether they're going to hold 80 acres, 160 acres. Once that has been determined, and we hope to get a ruling on that sometime in October, then most likely, it will be appealed to the appeals court, and that can take a while, and ultimately it could be appealed to the Texas Supreme Court. So we've always said this isn't going to be quick. This may take a year or so to work its way through the system. But that's the only – nothing has happened other than now the judge is looking to rule on what the vertical well holding of the previous owner was.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Okay. So maybe a potential resolution by the end of 2017?

James T. McManus, II - Chairman, President & Chief Executive Officer

It's possible, but it could go longer. You never know with the legal system. I mean, I think the other party is wanting to move it through quickly as well as we are, both wanting to settle it. We're just excited that, so far, round one, obviously the judge ruled in our favor.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Great. Thanks for all the color, and congrats again, guys.

James T. McManus, II - Chairman, President & Chief Executive Officer

Okay. Thanks.

Operator

Our next question is a follow-up question from the line of Derrick Whitfield from GMP Securities. Please proceed with you question.

Derrick Whitfield - GMP Securities LLC

Yep. Thanks, guys. So just one quick follow-up regarding the higher returns you're expecting in the Delaware. Can you offer insight on specifically what benefit you're targeting through optimized surface facilities?

James T. McManus, II - Chairman, President & Chief Executive Officer

Yeah. Let me explain it in a more simple way, Derrick. It's just when we originally did those, there were more constraints. We had not done a long lateral. We were a little bit conservative with those. We weren't fully producing the wells at their full capacity, and we knew we thought we could design around that, and we feel comfortable that we can now. So, it's really just a basis of being able to produce some at higher rates initially. And that's what bumps the return up. You're in an over pressured reservoir and it's not that it was that complicated to work out, but last time, we just had not done the design yet and now we're confident in the design is a simple way to explain it.

Derrick Whitfield - GMP Securities LLC

Thanks. That's all for me.

James T. McManus, II - Chairman, President & Chief Executive Officer

Okay.

Operator

Our next question comes from the line of Jeanine Wai from Citi. Please proceed with your question.

Jeanine Wai - Citigroup Global Markets, Inc. (Broker)

Hi. Good morning, everyone.

James T. McManus, II - Chairman, President & Chief Executive Officer

Morning, Jeanine.

Jeanine Wai - Citigroup Global Markets, Inc. (Broker)

Going back to, or starting with the Central Basin Platform, I know we don't talk about it too much. But previously you commented that, yes, that is up for sale under the right price condition and the right situation. So, digging into that a little further, is that asset close to being free cash flow neutral in the current environment? And what would the effect be on the base decline next year if you sold that asset understanding that it's one of the lower defined assets in your portfolio?

James T. McManus, II - Chairman, President & Chief Executive Officer

Well, Jeanine, let me clarify a little bit. We haven't said it was up for sale yet. We've said that in our portfolio, whether we keep that in the long run or not and whether it fits in, is something that's an open question. I think when you look now at how strong our balance sheet is, we don't really need the cash, but it could be a source of cash in the future for the company. And so I don't think there's any immediate plan. We don't have any immediate plan to sell that. You obviously, the higher the price of oil is, the more that asset is worth. But due to the fact that we exceeded the proceeds on our sales package, we raised much more than the $400 million we thought we were originally going to do. That's really not, per se, on the table in the near term, although it could be in the medium to longer term if we chose to do it.

In terms of its breakeven point, I don't have that particular number, but it has certainly gotten better as the LOE has declined out in the Central Basin platform. It is a slower decline asset in the 8% to 10% range, but it's not a huge contributor to production either. I think we've got it at about 8,000 to 9,000 barrels a day. The benefit of it is it's pretty oily production. It's in the 90-plus percent range. But we don't have immediate plans right now to divest of that asset with the strength of our balance sheet and where we are right now today.

Jeanine Wai - Citigroup Global Markets, Inc. (Broker)

Okay, great. Thanks. And then last quarter, you quantified that the new Midland wells were – and I think, presumably those Gen 2 wells, were outperforming the type curve by more than 30%. And just wondering if you had a similar estimate for the new wells that you did in 3Q.

James T. McManus, II - Chairman, President & Chief Executive Officer

Yeah. I mean, they continue to outperform by about 25%. That doesn't necessarily translate into EUR. Right now we would expect that we might get an uplift of EUR out of these Gen 2 fracs if they continue to hold and maybe on the order of 10% to 15%, but the early time outperformance is really good and, of course, helps internal rate of return.

Jeanine Wai - Citigroup Global Markets, Inc. (Broker)

Okay. That's it for me. Thank you for taking my call.

James T. McManus, II - Chairman, President & Chief Executive Officer

Sure.

Operator

Our next question is a follow-up question from the line of Dan Guffey from Stifel. Please proceed with your question.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Hi, guys. Wondering if you could talk about your rig contract or service contract structures as you head into 2017. And I guess, what is your ability and/or desire to enter into any longer term contracts currently?

James T. McManus, II - Chairman, President & Chief Executive Officer

So, great question. They're all short-term right now. They're well-by-well. We don't have any long-term rig contracts, and as you might expect, there's not a lot of desire with the service companies to enter into long-term contracts at the bottom of the market. And so, I don't think that we're going to have anything under long-term contract. That could change possibly if they get a little bit more willing to do that. But right now, they've not been willing to lock in at the bottom of the market.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Okay.

James T. McManus, II - Chairman, President & Chief Executive Officer

Or what they perceive the bottom of the market. I mean, they're not going to lock in at a year at the current rates. I mean, they might be willing to do something for a few months. But thus far, we haven't really done than that.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Okay. So, I guess no desire to maybe pay a little bit above market to lock in for a longer rate. I guess no need because of the excess capacity on the service side currently.

James T. McManus, II - Chairman, President & Chief Executive Officer

Well, so far, that's the way we felt about it. I mean, we certainly could change our mind. There hasn't really been a lot of discussion with the service companies making offers to lock in a little bit higher rate for a longer period of time. I mean, I think their feeling is that things may come back a lot stronger. Johnny, you got something there?

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

James is exactly right. But I will say that is we're now beginning to talk about 2017 as our plans become a little clearer with the service companies and who knows what'll be proposed and where we'll wind up by the end of the year. But James has described to you the current situation. But I will say that we're just opening the dialogue as we get closer and 2017 gets its range with what will be the best business approach.

James T. McManus, II - Chairman, President & Chief Executive Officer

Course, the advantage is, you know, Doctor Obvious here, if you lock it in and it runs north, you save some money. The disadvantage is it takes away your flexibility to curtail your activity if you so chose to because you saw some type of a precipitous decline. Current day rates are very attractive right now. They're in the area of $15,000 a day.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Okay, great. And then just last one for me, wondering on infrastructure projects as you ramp completion and drilling activities into 2017 and possibly throughout 2017. Are there any large capital projects for infrastructure that are going to be required in 2017 and/or 2018? And then how should we think about the midstream spend next year and beyond?

James T. McManus, II - Chairman, President & Chief Executive Officer

Yeah. The way we've typically tried to guide that is it typically averages about 8% to 10% of the capital budget, and I can't give you any better guidance than that right now because we haven't decided what we're going to drill in 2017 yet.

Daniel Guffey - Stifel, Nicolaus & Co., Inc.

Okay. Thanks again, guys.

James T. McManus, II - Chairman, President & Chief Executive Officer

So I'd use 10%. Thank you.

Operator

Our next question is a follow-up question from the line of Chris Stevens from KeyBanc. Please proceed with your question.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Hey, yeah. Just wanted to touch on the Martin County acreage that you guys have. QEP has some pretty tight spacing assumptions out there right next to you guys, and I was curious if you had any plans to test some significantly tighter spacing on your acreage. Any sort of pilots that you might have upcoming or any thoughts on that?

James T. McManus, II - Chairman, President & Chief Executive Officer

Well, Chris, we did do a 10 across Lower Spraberry. We're not really prepared to talk about that yet. That's about as tight as we've gone. I've looked at some of their slides. We don't have any plans to test anything as dense as what I've seen on their slides at this point, but we'll be watching their results, of course.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Okay. And then I guess as you get into 2017 and you're building your DUCs later this year, is most of the focus in Martin going to be on the Spraberry, or is it going to be pretty evenly split between all the different zones out there?

James T. McManus, II - Chairman, President & Chief Executive Officer

It'll be pretty split. It'll be Lower Spraberry, Jo Mill, Middle Spraberry, Wolfcamp A, Wolfcamp B. I mean, we've actually – this latest Jones Holton production that we're bringing on, we drilled a good many of those formations as well. We had Lower; we didn't have as many Middles. We might have had a couple of Jo Mills in there. We had several Wolfcamp A and Bs. So, I mean, we're testing the cube concept, as Johnny mentioned.

We are a little bit ahead of some others in that regard, when you think about kind of a one-mile section and how many wells can you put in there. We're still learning about that, but we're moving forward with some of that as we drill this DUC program in Jones Holton next year – this year.

Chris S. Stevens - KeyBanc Capital Markets, Inc.

Okay. Great. Thanks a lot.

James T. McManus, II - Chairman, President & Chief Executive Officer

Thank you.

Operator

Our next question comes from the line of Kyle Rhodes from RBC. Please proceed with your question.

Kyle Rhodes - RBC Capital Markets LLC

Hi. Good morning, guys. Obviously, there's been a lot of positive news flow in valuation markets in Howard County lately. Can you just remind me your current acreage position there, just pre Quinn Ranch, and then if you've got any development plans planned for the back half of 2016? Thanks.

James T. McManus, II - Chairman, President & Chief Executive Officer

So it's about 7,000 acres out there, roughly, I'm guessing. This is a CEO swag, so, I mean, we have that information somewhere. That's absent the 10,000 acres that we've got this potential to pick up that we believe we leased and it had expired. And I'm not sure yet whether we're going to have any 2017 plans in Howard County.

I think probably not because we've got a lot more of our infrastructure available in some other areas. So I'm not sure. I can't tell you we won't have any plans up there, but right now, my thought is there wouldn't be a lot in 2017 in Howard County, unless we were to win this lease. If we win this lease, then we certainly would start drilling up there. But again, as I pointed out, that could be 12 to 18 months out.

Kyle Rhodes - RBC Capital Markets LLC

Got it. Just in terms of that lease, is the 10,000 net acres the right number to think about, or should we be backing out some HBP'ed acreage for the vertical development?

James T. McManus, II - Chairman, President & Chief Executive Officer

It could be a little smaller than that. I mean, it might wind up being – depending on what happens and when that judge rules, we'll let you know what he says was held by the previous operator on their vertical wells. So, I don't know if it's going to wind up being 9,700 acres instead of 10,000. We've used 10,000 net. It's kind of the ballpark. It might be a little bit smaller than that.

The thing that we really like about that lease position, and you know we put it on a map last time so you could see where it is. It's in southwestern corner of Howard County, which is a great location, particularly for the Lower Spraberry and it's a very contiguous ranch. It's going to be very good long lateral country and it's one lease owner. So, we really like that block and we think that as materially if we win that suit ultimately adds materially to our position in a very, very good way in the Midland Basin.

Kyle Rhodes - RBC Capital Markets LLC

Got it. Appreciate it, guys.

James T. McManus, II - Chairman, President & Chief Executive Officer

Thank you.

Operator

Our next question comes from the line of Ben Wyatt from Stephens. Please proceed with your question.

Ben Wyatt - Stephens, Inc.

Hey. Good morning, everyone. Julie, good morning. Looking at slide five here. You guys have, obviously, an average type curve here from these five wells. If you were to break those out per well and then even take it a step further and break it out based on the commodity mix, just curious if there'd be any surprises, anything that would jump out at you? Does the oil decline stand a little flatter than you thought? Really just curious on any detail you could give us on this chart.

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Well, the type curve has 25 wells in it. So obviously 20 of those are outside operated. Our five are in the type curve and then we plot it against the type curve. I wouldn't say there's any surprises. I mean, we've said that we're in the upper-50s on the oil cut. But the surprising thing about these wells is as we reviewed them, they just kept outperforming our estimates. So we make estimates and they outperform, outperform. Very strong wells. Just a lot of good surprises. I wouldn't say there were a lot of negatives here, and that's why we're so excited about the area.

Ben Wyatt - Stephens, Inc.

Very good. Appreciate that. And then maybe just another one here on the LOE, the improvement there. Just curious if you guys could give us any more detail on some of the things you guys outlined for the lower LOE. Is it just more water on pipe? Is it on the electric side? Is it a grid instead of generators? I'm just curious what you guys are doing over there that is really driving that down and how sustainable it is.

James T. McManus, II - Chairman, President & Chief Executive Officer

So, we got a good bit of water on pipe. And we're very high. I'm trying to remember whether that's 80% or 90%. But we do have a lot of water on pipe. We continue to move water on pipe. Power costs have been lower. As you might expect, a lot of power is generated with natural gas. That cost has been down. We've had a nice improvement in the Central Basin from our work-over program. We've not had the historical well failures that we'd projected. And I'd say the other thing we've done a pretty good is every time we may have somebody leave the company, we're looking real hard at trying to figure out a different way to not replace that person. So, there's been some labor savings in there as well.

I'll let Johnny comment on anything he would add to that.

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Yeah, and I think our guys have done a great job at long-term infrastructure. I mean, luckily, our acreage lends itself to building an infrastructure, particularly in the water disposal, that can be used generation after generation; and we're moving toward that in the Delaware with our more dense footprint now, where we'll drill a generation of wells and dispose of that water, and then we'll be able to use that same disposal system for several other drilling campaigns in the future years to come.

So a lot of our cost in moving the water in the Midland Basin and the Delaware Basin is a lot of the LOE, and we have infrastructure in place. We've used it once and even a second time. And James mentioned that as we look forward, we'll have to develop more infrastructure as we move out into Howard County and other places. But luckily our acreage lends itself to multiple use and you're seeing some of the benefit of that now.

Ben Wyatt - Stephens, Inc.

Very good. Well, guys, I appreciate it. Nice quarter and thanks for letting me get on here and ask a couple questions.

James T. McManus, II - Chairman, President & Chief Executive Officer

Absolutely.

Operator

Our next question comes from the line of Chris Dendrinos from KLR Group. Please proceed with your question.

Chris Dendrinos - KLR Group LLC

Morning, guys. Just a quick one on well costs. Can you quantify the difference in costs at today's dollars between the Gen 1, 2 and 3?

James T. McManus, II - Chairman, President & Chief Executive Officer

Well, the Gen 2 is baked into everything that we've got, that we've disclosed on our economic slides, which we updated the one for the Delaware Basin and it's actually pretty close to Gen 3 because the $7.2 million that we did was a Gen 3.

Now in the Midland Basin, Gen 3, if you don't pick up some savings elsewhere, Gen 3 is going to cost a little bit more. It's a little difficult for me to give you the exact range of that because it depends on whether you're at the low side of the sand side or the upper side of the sand side. But it may be a few hundred thousand dollars more to do the Gen 3 over the Gen 2. The question is can you make that up somewhere else. I mean, we thought Gen 2 was going to be a lot more expensive than Gen 1 by about $0.5 million and it wound up that we were able to, through efficiencies and other cost savings, we were able to incorporate that into our numbers and not have them move a whole lot. But Gen 3 could see a step change in costs. And that of course is one of the things you're evaluating. Are you getting enough EUR out of the extra costs?

Julie S. Ryland - Vice President-Investor Relations

However, I would note that the Glasscock County well that we refer to as having drilled it in 13 days at a drill and complete that utilized Gen 3 came in at $5.2 million. So there is – that's a very attractive price using that larger frac design.

Chris Dendrinos - KLR Group LLC

Great. Appreciate it. And I guess moving onto pad development in the Midland in Martin this quarter. I guess historically you've done three-well pads. How are you thinking about the development given that you're targeting five zones coming up this quarter and next?

John S. Richardson - President & Chief Operating Officer, Energen Resources Corp

Well, as we referred to where possible, we don't really use a pad design. We use more of a landing strip design. So it's much more akin to a continuous pad and that allows us to do multiple wells and different staggered or Chevron configuration. So if you're thinking in a conventional term of a bare spot on the Earth three well heads there, that's really not the way it is. It's more of a landing strip as we call it, in a continuous kind of pad. There are wells, there are groups of wells that are 50 feet apart or so, but it's more of a continuum than specific pads laid out.

Chris Dendrinos - KLR Group LLC

Okay. That's great color.

James T. McManus, II - Chairman, President & Chief Executive Officer

Having said that though, typically in Glasscock County, as you know, we've been doing the A and the B together at the same time; and in the Jones Holton, the wells that we're currently bringing on, we did the Lower Spraberry, the A, the B, and I think maybe a couple Jo Mill or maybe a couple of Middles, I don't remember which. But in this DUC inventory that we're building at Jones Holton this time, it'll be a combination of Middle, Jo Mill, Lower As and Bs, and they will be in that one-mile segment. And we'll be looking at experimenting with the different levels of spacing both vertically and horizontal.

Chris Dendrinos - KLR Group LLC

Okay, wonderful. I appreciate it. Thank you.

Operator

There are no further questions in the queue. I'd like to hand the call back over to James McManus for closing comments.

James T. McManus, II - Chairman, President & Chief Executive Officer

Well, thanks, Doug. Appreciate everybody being on the call. Hope you have a good day. We're excited about this quarter at Energen and what the future holds. So thank you very much.

Operator

Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time and have a wonderful day.

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