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Edited Transcript of EGN earnings conference call or presentation 8-May-18 12:30pm GMT

Q1 2018 Energen Corp Earnings Call

BIRMINGHAM Jun 4, 2018 (Thomson StreetEvents) -- Edited Transcript of Energen Corp earnings conference call or presentation Tuesday, May 8, 2018 at 12:30:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Charles W. Porter

Energen Corporation - VP, CFO & Treasurer

* James T. McManus

Energen Corporation - Chairman, CEO & President

* John S. Richardson

Energen Corporation - President & COO of Energen Resources

* Julie S. Ryland

Energen Corporation - VP of IR

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Conference Call Participants

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* Bradley Barrett Heffern

RBC Capital Markets, LLC, Research Division - Associate

* Charles Arthur Meade

Johnson Rice & Company, L.L.C., Research Division - Analyst

* Derrick Lee Whitfield

Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst

* Gail Amanda Nicholson Dodds

KLR Group Holdings, LLC, Research Division - MD

* Irene Oiyin Haas

Imperial Capital, LLC, Research Division - MD & Senior Research Analyst

* Jeffrey Leon Campbell

Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services

* Leo Paul Mariani

National Alliance Securities, LLC, Research Division - Research Analyst

* Michael Dugan Kelly

Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

* Paul William Grigel

Macquarie Research - Analyst

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Presentation

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Operator [1]

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Greetings, and welcome to the Energen First Quarter Conference Call. (Operator Instructions) As a reminder, this conference is being recorded.

It is now my pleasure to turn the conference over to your host, Julie Ryland, Vice President of Investor Relations. Thank you. You may begin.

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Julie S. Ryland, Energen Corporation - VP of IR [2]

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Thank you, Diego, and good morning. Today's conference call is being held in conjunction with Energen Corporation's announcement this morning of its operating and financial results for the 3 months ended March 31, 2018. The slide deck to be used in today's call can be found on Energen's homepage at www.energen.com.

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'll turn the call over to Energen Chairman and CEO, James McManus. James?

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James T. McManus, Energen Corporation - Chairman, CEO & President [3]

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Thank you, Julie.

Energen is off to an excellent start in the first quarter of '18. Our total production was 92.9 MBOE per day, which surpassed our guidance by 4%, primarily due to well out-performance. Oil production was 55.4 MBOE per day, exceeding the top end of our guidance midpoint by 5%.

Also, per unit net SG&A expense was $2.66 per barrel, which beat the guidance midpoint by 11%. And adjusted EBITDAX totaled $240.6 million, exceeding internal expectations by 10%. We'd also point out that the company is 70% hedged for the remainder of the year and importantly, 58% of the mid-cush differential for the remainder of '18 is hedged at $1.29. We also completed some accretive bolt-on acquisitions in the first quarter, 1,100 net leased acres for $18 million, again, primarily extending lateral lengths.

We also brought several wells on during the quarter, continuing to showcase strong execution. We had 23 net wells turn to production in the first quarter of '18 as efficiencies helped drive above-budget pace, although many of those wells had no impact on production in the quarter. They were just turned on a little earlier in the first quarter as opposed to early in the second -- I mean, late in the first quarter as opposed to early in the second quarter.

Importantly, we had 8 new Gen 3 Wolfcamp wells with just outstanding results, IP rates in excess of 440 BOE per day per 1,000 foot. Truly outstanding wells continue to be the case in the Delaware. And our performance on new Gen 3 Wolfcamp wells in the Central Midland Basin were basically in line with the type curve. We also had our first 2 Gen 3 Cline tests, which provided excellent results in both the North and the Central Midland Basin.

I'm going to move to Slide 4 of the presentation, if you're following along. Again, as I mentioned, first quarter beat by 4% on the midpoint and oil beat by 5%. Importantly, production is up over the first quarter of '17 by 76%, first quarter '18 to first quarter '17. And oil production is up 66% first quarter '17 versus first quarter of '18. I think this just continues to show the company's ability to ramp and to perform even when it has a ramp and our ability to deliver on the ramp that we expect in '18, we feel very good about.

If I then move to Slide 5, just showing you expenses here. LOE, essentially where we thought it would be, and then a decline in SG&A, as I mentioned earlier, of about 11%.

Flipping to Slide 6, we got a lot of information on this slide. Broken down on the Delaware, we show you the -- if you go to the first quarter '18 well performance, again, we've talked about the primary targets here being the A and the B. We had 10 net wells turn to production in first quarter of '18, averaged about 3 to 4 rigs, 2 frac crews during the quarter. We give you our estimated DC&E cost per lateral foot range for a 10,000-foot lateral.

And then dropping down into the well performance, you can see that the average completed lateral length for the quarter, 5,529, 3 Wolfcamp As, 4 Bs, 1 BC, with a very strong 441 BOE per day per 1,000 foot at 53% oil and then at the 30-day rate, kind of right at the mark that we typically would have in Texas since we didn't have a lot of New Mexico mixed in here of 58% oil. And a BOE per day per 1,000 foot of 392. Really, really strong wells continue for us in the Delaware and continue as we flip to Slide 7, to outperform the type curve.

Now what you're seeing here on Slide 7, obviously, is the dotted line is a Ryder Scott composite curve that we used for the 2018 program. We have updated the red slide to include all of the data on the Gen 3 wells that we completed in 2017. And then the blue line is the early results that we have from the 7 wells that were A/Bs that were brought on in '18. You can see that they're performing, right there on the red line, again, ahead of the type curve. We're very pleased with that.

Flip to Slide 8, we'll talk about the Midland Basin. And on the map, you can see there we sort of circled where the activity is taking place. Primary targets here have been the A/B and the Spraberry package. We had 13 wells turn to production in first quarter of '18. Again, over here, we utilized an average of 3 rigs and 2 frac crews during the quarter. 67% of these wells were pattern wells, and we give you our DC&E cost per thousand foot for a 10,000-foot lateral at $790 to $875.

If you kind of look down at the first quarter well performance, you see we had a Wolfcamp B brought on in the North, but importantly, a northern Midland Basin Cline was brought on in the north. This well is performing extremely well. It's an early well, but we like what we see. 212 BOE per day per thousand foot, 87% oil right now. It will be interesting to follow this well along and see how oily it is. It is in the north. We would expect it to be more oily than the central part.

And then you've got the Central Midland Basin where we brought on most of our wells in the Wolfcamp A and B. And then we had a Central Midland Basin Cline again that performed extremely well with 353 BOE per day per 1,000 foot and at 30 days 188. Very encouraged by those 2 wells, which I'll talk about here in just a minute.

So if we then flip to Slide 9, take a look at a minute at the Wolfcamp A/B wells. Again, at or above the type curve. You can see there in the north, we only had one. It's early, but it's doing extremely well. And then we had 11 wells in the center that tend to be sort of right where they need to be.

So if we then flip to Slide 10, the only reason we have this slide on here is because again, we updated the red lines for all the performance of the '17 wells. We don't really have any performance right now to talk about in the '18 program, for the Middle/Jo Mill and Lower Spraberry, although we will. But you can see that the '17 program continues to outperform the type curve quite nicely.

If we then go to Slide 11, again, we did drill a couple Cline wells. One of the reasons we drilled was we needed to hold. And in areas where we don't have a lot of vertical penetrations, we will occasionally drill a Cline well. We wanted to see how these wells would perform on a Gen 3 Frac design, and they performed really, really well.

You can see the previous sort of type curve we had on previous generations there. If you look in the north, we had it estimated at 0.8 MMBOE or 800,000 barrels, with 0.5 being oil at this point. We've drawn our own internal curve at 1.2 MMBOE or 800,000 barrels of oil. And these look extremely economic, even though they're a little bit more cost -- they are obviously more cost to drill because it's a little deeper. If these kind of production rates and type curves hold up, these will be really economic wells for us as we move forward in the future.

So if we then look at the Central Midland Basin, you can see the FoxTrot 405H on the right-hand side of the slide is outperforming an internal curve that we have at 1.5 MMBOE. And as you might expect since it is in the Central Basin, Midland Basin, we project it to have a lower oil percentage but still 700,000 MMBOE of oil. So very excited about these results in the Cline.

If we then go to the topic du jour, which is something we've been asked about, I guess, in every conference that we've participated in and is what kind of flow assurance do we have in the basin. We feel very good about our flow assurance. The company currently has 85% of its Permian Basin oil production on pipe. 80% of the Midland and Delaware oil is sold to Plains All American. Energen is a top 5 customer with them. We've never had any trouble moving our oil in the past, and they have told us that we should not have trouble in the future.

As it relates to gas, particularly in the Delaware, we're an anchor tenant with Vaquero Midstream. We have firm transportation and plaque capacity in the Delaware Basin to meet our needs, and we have no concerns about moving gas. We also have excellent access to extensive gas gathering and processing in the Midland Basin where, as you know, many of you know there's a spider web network over there, and you don't tend to have the bottlenecking problems.

Additionally, the company is hedged, as I mentioned on the first slide. We've got 58% of the remainder, the mid-cush hedged at $1.37. And we have 6.8 million BO hedged in 2019 at $1.11. And gas, we do have a gas hedge in place of 24% for the remainder of the year.

Also importantly, I would point out 95% of all produced water is on pipe. The company has permitted disposal capacity of 1.4 MMBWPD or barrels per day. By year end 2018, we don't anticipate any problem in the 3-year plan or beyond for that matter with saltwater disposal. So we feel like we've got a good hedge on the mid-cush differential, and we feel like the company is strongly positioned to deliver flow assurance.

If we then move to Slide 13, it shows our production guidance range. We did pick up what we were over in the first quarter and included it to the end of the year, left the rest of the guidance the same. If you look at the right-hand side of the slide, you'll see the completion cadence for the company has not changed that dramatically. We still have a pretty good ramp going into the third and fourth quarter. Feel very confident with that ramp though. We currently have all 10 rigs we plan to utilize working. Four of the frac crews and the fifth one that comes in July are all under contract. And so services have been accounted for, for everything that we need to complete this plan for this particular year.

If we then move to Slide 14, capital guidance remains unchanged at $1.1 billion to $1.3 billion. Down at the bottom, we give you a little color of the lateral lengths. As you know, this year was going to be a little bit shorter for us at 8,000 feet because we had some drill-the-hole wells in the Delaware. They're a little shorter than the program was last year. But as you can see, our year end 2018 DUCs move back up to 8,900, and we would expect that in '19 and '20, we would average much closer to 9,000 feet again as we move through some of those drill-the-hole wells that we've got to complete in this particular year.

Also, I'd point out on this slide on the pie chart in the upper right-hand side, you can see that the Central Midland Basin, even though that's where we had a number of wells coming on this year, just to -- because of the way we did the work, that is only 10% of our overall capital budget with a full 90% going to the North Midland Basin and the Delaware Basin. You can see the split there, 50, 40, respectively.

If we then go to Slide 15, expense guidance updated. We had a little bit of change in DD&A. And then over on the lower left side, while we didn't change the overall LOE range, we did make some changes within each basin to adjust for how things stacked up in the first quarter. We also give you on the right-hand side of the bottom of the slide, obviously, our G&A expenses, which as most of you know have been on an extreme downward trend for the last couple of years.

If we then move to Slide 16, we do factor in some of the increased cash flow due to pricing and production. And our net debt to EBITDAX, we've adjusted down at the end of the year to 0.9 to 1.1. I think previously, we made that an upper range of 1.2, no real additional changes there to that particular slide.

So then I would take you to Slide 17, where we highlight the hedge position by quarter. Obviously, I'm not going to run through this, but I would point out kind of in the middle of the slide, over on the right. Again, you can see in cal '18, we've got 11.9 million barrels of mid-cush hedged at $1.29 for '18; and then '19, 6.840 million barrels at $1.11.

If we then go on to 18, I do want to highlight a little bit of what we did in '17 again. Proved reserves were up 40%, on the right-hand side of the slide. Daily production was up 39%. Adjusted EBITDAX was up 123%. LOE was down 16% on a unit basis, and SG&A was down 29%. We plan to continue this performance moving into '18.

But also on Slide 19, if you look at kind of where the company was in '17, peer-leading drill-bit economics, this is from Seaport Global. And you can see that Energen was #1, having the lowest among our peers' adjusted PDP finding cost per BOE. And you can see that we were #2 in recycle ratio for 2017. Really highlighting the kind of year that we had overall in 2017.

If we then go to Slide 20, our 3-year outlook remains the same. We really didn't adjust the prices in that, but we do add one metric that points out that the company would achieve cash flow neutrality in 2020 at a $57 oil price. For those of you who are familiar with this outlook, it projects extremely strong growth over the next 3 years at 28%. We feel like we've got excellent returns, good inventory to drill, and that with our balance sheet, we should continue to bring value forward.

We have extremely high exit rates as well, and we think that the exit rate approximates 170 MBOE per day in 2020. And importantly, the 3-year CAGR growth for EBITDAX exceeds 35%. And we do all that while maintaining a debt to EBITDAX ratio between 1 and 1.5.

Then go to Slide 21. Really just sums up why we think Energen is a compelling investment. Again, we're moving to move NAV forward. We've got an extremely strong balance sheet. We think we've got top-tier assets in the basin, very good strong 3-year outlook. We've been a leader in pattern development, which we think reduces degradation of the parent-child well issue.

Current Gen 3 Frac design is achieving stand-alone performance on pattern wells. We've also done a good job of unlocking new formations. I think these 2 Cline wells continue to demonstrate our ability to do that. The company also, again, has good takeaway capacity as well.

So with that, I will wrap up the presentation and turn it over to Diego. At this time, if anybody has any questions, I'm going to turn it over to you, Diego.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from Neal Dingmann with SunTrust Robinson Humphrey.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [2]

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Nice quarter. James, I think on your prior call -- I forget, either the last call or a call before that, you suggested that given that prices continue to be quite positive and your free cash flow continues to be as good that you would think about potentially taking spending up a bit.

Just wondering where do you sort of sit -- I know you've reiterated guidance here on slide -- I'm looking at Slide 14. Obviously, you have a very active program this year. But given as well as you all have on the financial position and in prices, maybe if you could just talk about the potential for boosting that a bit.

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James T. McManus, Energen Corporation - Chairman, CEO & President [3]

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Yes, Neal. I think it's a little early right now in those terms. I don't think we had plans of really accelerating a tremendous amount. We're kind of pleased with the plan we've got out there for the 3 years. It's something that we'll constantly look at and reevaluate. But at this point, I wouldn't signal anything that says we're going to up capital at this time.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [4]

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Got it. And then just...

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James T. McManus, Energen Corporation - Chairman, CEO & President [5]

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For '18 -- yes, go ahead.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [6]

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Okay. I'm sorry. Finish up.

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James T. McManus, Energen Corporation - Chairman, CEO & President [7]

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No, go ahead.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [8]

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And then just lastly on -- great sight on that Slide 12. I'm sure just the typical questions you're getting on the takeaway. For you, Chuck, how do you think about potential for '19? I mean, are you looking at -- at today's levels, would you think about further basis dips or potential FT for '19? Or what's your thought as far as if these spreads sort of continue, what you would do as we get towards the end of the year?

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James T. McManus, Energen Corporation - Chairman, CEO & President [9]

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Yes. I think our position, Neal, has been, again, not necessarily to contract for FT and pay for that and be sort of in a take-or-pay situation. We wanted to maintain flexibility. And so the way we've dealt with it classically has been to hedge but also be sure that we feel like we have flow assurance.

I mean, we'll be looking at all those issues to see what we think the best way to deal with it is. Our practice has been basically to hedge, and we'll just have to look at wherein there are opportune times potentially to do that.

I think we feel good about our flow assurance going forward really throughout the next 3 years. We don't have a problem with that. Obviously, it does hurt us when [the stakes] flow out, and we have volumes unhedged.

But that's been the way we have typically dealt with that because the problem you run into as soon as you go contract for FT and oil price goes down, and you cut back your activity, you're paying for that. I mean, it's not free. And so it's a balancing act, and we've always wanted to maintain flexibility.

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Operator [10]

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Our next question comes from Leo Mariani with National Alliance.

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Leo Paul Mariani, National Alliance Securities, LLC, Research Division - Research Analyst [11]

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Just wanted to follow up on the oil price exposure question here. Just trying to understand where outside of your basis hedges, if I sort of ignore those, what the main price points are for your oil here.

Are you pretty much effectively getting WTI Midland? I know you have the agreement with Plains, but I wasn't sure if that allows you to access other markets contractually and might give you some better pricing. Can you just talk a little bit more about the oil price dynamics?

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James T. McManus, Energen Corporation - Chairman, CEO & President [12]

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Yes, it doesn't. We get WTI Midland.

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Leo Paul Mariani, National Alliance Securities, LLC, Research Division - Research Analyst [13]

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Okay. And I guess, just looking at production here in 2018, obviously, you guys have some pretty specific quarterly guidance. But when I sort of look at some of the well cadences, you obviously brought on a fair number of wells this quarter. You're bringing on a lot of wells in third quarter as well.

But when I kind of look at your guidance, you're kind of expecting production not to really move up too much until a big fourth quarter surge. Can you maybe just provide a little color around that just given -- especially given the high number of completions in 3Q, I would have thought third quarter production might be a little better.

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [14]

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Well, we're bringing on some very large developments third quarter, which contributes in the fourth quarter. But a lot of those wells will flow in the third quarter, but they won't impact production materially till the fourth quarter. And therefore, the reason you ramp up is you get a full quarter of production. So it's just a timing issue. It's the way our patterns are working out for us later in the year.

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James T. McManus, Energen Corporation - Chairman, CEO & President [15]

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I think in terms of outperformance possibilities, I mean, those are certainly there. I mean, if the wells hold up or continue to outperform the type curves, there's certainly possibilities for outperformance.

I really talked about that being later in the year because the more wells you bring on, the cumulative effect of outperformance can be felt more when you have more wells as opposed to fewer wells, even though we did relatively well this quarter.

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Leo Paul Mariani, National Alliance Securities, LLC, Research Division - Research Analyst [16]

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Okay, that makes a lot of sense. And I guess, just lastly on your acquisition of some of the acreage here. You picked up 1,100 acres, I guess, in the first quarter. Could you give us a little bit more color in terms of where those were?

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James T. McManus, Energen Corporation - Chairman, CEO & President [17]

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Yes. About 70% of that was in the Delaware, so it tends to be Delaware-weighted; about 30% in the Midland Basin. And again, we continue to try to lengthen the laterals of our bolt-on acreage that's right next to ours. It gives us a little bit more size and scale. But in this case, I think it was primarily lengthening laterals, which is really good business for everybody.

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Operator [18]

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Our next question comes from Mike Kelly with Seaport Global Securities.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [19]

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Congrats on the continued positive operational momentum. These Delaware wells look real good this quarter. James, I was hoping you can maybe kind of pick that apart a little bit and differentiate between the results you saw in the Wolfcamp A, B and C.

And I'm just curious what you're the most encouraged with and really what your current thoughts are on how you sequence the development of each one of these drilling units in the Delaware, what zones you target and how that all looks right now.

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James T. McManus, Energen Corporation - Chairman, CEO & President [20]

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Yes. Let me get -- Mike, I'm going to ask John to comment on that. I would say that our program is going to continue to be heavy A, B. Occasionally, we drill C to hole. The Cs do tend to be a little bit gassier, so we're going to focus on the higher rate of return formations. But I'm going to ask John to give you a little bit more color on how we're thinking about that particular development.

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [21]

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Yes, James, you're exactly right. I mean, we're very pleased with our Wolfcamp As and Bs. They continue to produce very well, and they're holding up very well. We're very pleased with our late '17 wells, their contribution in the first quarter as far as outperformance goes on just holding up. And they're -- what can you say about them? They're phenomenal wells.

We -- James is right. We do every now and then drill a deeper well, a BC, a C, mainly to hold acreage where that's necessary. Our focus is on the A and B. We see that we should develop those together.

We continue to learn about that area. We're not quite as far along in the Delaware as we are in the Midland as far as interaction between wells, but we're figuring that out rapidly. And other people are beginning to endeavor in that, so we're getting a lot of outside data on that. Go ahead, James.

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James T. McManus, Energen Corporation - Chairman, CEO & President [22]

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No. I was just going to say, Mike, I think one of the things -- we did one of the first I think it was 5 or 6 across in the A, and that performance was really, really good. That was in the '17 program and in the '17 results. And we'll continue to look at that.

Although this year, we're hopping around a little bit because, as I said, we've got a little bit more drill-the-hole work, which is kind of shortening our lateral lengths. So we don't have as much pattern work this year, although we'll have some. But I don't think anybody's as far along in the Delaware in terms of determining what the patterns are. I think we're still in the early stages of that.

I do think in the Midland Basin, we feel really comfortable with the patterns we've got. And as you know, the Cline is not really -- if I mention the Cline here for a second, those are some pretty good-looking wells in the Cline. And while it's a little bit costlier to go down to the Cline in terms of drilling, those EURs are looking competitive with the other formations.

And we don't feel that, that has to be developed at necessarily the same time. So we've got some flexibility on the Cline since it's got enough separation that we don't really feel the parent-child issue. I know you didn't ask that, but I just thought I'd throw that in.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [23]

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Yes. Well, you stole my second question, James. So I was going to go to the Cline.

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James T. McManus, Energen Corporation - Chairman, CEO & President [24]

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Oh, I'm sorry, Mike.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [25]

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No, that's great. That's good lead in. I just...

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James T. McManus, Energen Corporation - Chairman, CEO & President [26]

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The thing about the Cline well in the north that I think -- we are hoping that it's going to perform oil-wise. We -- on our curve, we project it to be much more oily than the central part. So even though it has a lower projected EUR, when we look at strip pricing returns on those wells, they're attractive.

And I think what it gives you more comfort about is it kind of expands our overall inventory. I mean, at one time, we were talking about the Jo Mill, the Middle and everybody's like, "Oh, I don't know about those." And I think people have gotten comfortable. We obviously were comfortable early on that those were going to be good formations for us, and we've proven that to be true. And certainly, we're early stages in the Cline, but these are some encouraging wells on Gen 3.

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [27]

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But I will add that this is -- we've got other Cline wells in the area, which we base some of our analysis on. There is a marked difference between the -- there -- and they're very close by between their performance and this particular well and it's due to the different frac procedure.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [28]

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Okay. That's great. Maybe just on that Cline well, how much exposure do you think you have in the Midland? How much of your...

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James T. McManus, Energen Corporation - Chairman, CEO & President [29]

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Well, we've got our inventory between the 2 areas. It's over 500. Let me just give it to you here. So in North, we've got 290 net locations on Slide 25 of the presentation. And by the way, the EURs that we have in there, the old ones that we had previous generations, we have not updated those yet to the new ones. And then in the Central, we've got 269 wells.

So you're talking about 550 locations in total between those 2 that, frankly, I don't think we get a lot of credit for in our NAV. And I'd suggest people we look at that as an economic formation now. I used to always comment that it took a higher oil price to get there, but Gen 3 makes it economic today.

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Michael Dugan Kelly, Seaport Global Securities LLC, Research Division - MD and Head of Exploration & Production Research [30]

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Great. And any more tests slated for the Cline this year?

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James T. McManus, Energen Corporation - Chairman, CEO & President [31]

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Yes, we've got one more. And again, it's a drill-the-hole situation. So where we've got lower vertical penetrations that aren't in the Cline, that's what prompted us to drill the one in the north. And plus, we had a curiosity about how would the Cline do on Gen 3 and we're just delighted that its performance has been so much better.

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Operator [32]

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Our next question comes from Jeffrey Campbell with Tuohy Brothers.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [33]

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Congratulations on the quarter. Since we just sort of discussed the Cline in really good detail, I'll just ask one question. From the press release, it mentioned that some of the wells were placed on production ahead of schedule. I was wondering if this implied any compression of your previously expected cycle times or was there some other reason why the wells got on early?

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James T. McManus, Energen Corporation - Chairman, CEO & President [34]

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There was an overall compression. I'll get John to add a little color to that. I think it was a lot of small things in a lot of different places.

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [35]

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We were -- in our frac crews, we brought 4 new crews in. They performed very well. We also -- our drilling rigs performed well. And our facilities were ready to go, and we were just a few days early on some of these wells. But everything lined up for us. And operationally, we performed very well with very few glitches. And we were ready to go, so we brought them on.

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James T. McManus, Energen Corporation - Chairman, CEO & President [36]

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Yes. If I could add this, Jeffrey, I think some people said our overage in production was all due to bringing them on early, and that's not really the case here. About 60% of the overage was performance and about 40% roughly was being a little bit ahead of schedule due to efficiencies.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [37]

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Well, let me follow that up. I mean, I appreciate that last point. I guess, kind of where I'm going here is I think you said 40% of the production in the quarter was on the...

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James T. McManus, Energen Corporation - Chairman, CEO & President [38]

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40% of the B.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [39]

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The multi-zone -- 40% of the B was a multi-zone. So I guess, what I'm really getting at is: a, do you -- are you seeing a line of sight that because of this pad organization and as you increase the amount of pads and your workload time that you're going to be able to drive costs down with the kind of efficiencies that you showed in this quarter?

And I guess, b, separately, because we've had some questions about CapEx, is there the possibility that maybe some 2019 wells might get pulled into the late '18 program, again, because of the efficiencies?

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James T. McManus, Energen Corporation - Chairman, CEO & President [40]

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Well, I think on your latter point, let me comment, too soon to know right now. A lot can happen in the year, but we're -- we did see efficiencies in the first quarter. On the first point, I'll let Johnny comment.

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [41]

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Yes. I think overall, we will get -- continue to get more efficient. And we will continue to be more economic and get cheaper as we drill. And particularly our pad work is a very economic approach.

However, there are other pressures out there that could cause you to not see those savings. But we will mitigate their cost increases that we never know that are coming down the road. Sometimes, they sort of disguise what we're doing on the efficiency side. But yes, left in a static world with costs, we would definitely see those costs come down with efficiencies.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [42]

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Okay, Johnny. And I'll just finish that last point that you made, another way we could think of it maybe is that because of the efficiencies, over time, it's going to give you potentially a little bit more of a buffer or a little bit more leeway if we see continued service cost inflation in the area.

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [43]

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Yes.

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Operator [44]

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Our next question comes from Charles Meade with Johnson Rice.

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Charles Arthur Meade, Johnson Rice & Company, L.L.C., Research Division - Analyst [45]

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I wanted to go back to the Cline results and see if you guys could perhaps elaborate a little bit more on how you pick the locations and not just, I guess, the locations but also as I understand it, the Cline particularly in Glasscock can be a pretty thick zone.

And James, I know you touched on some of this in your prepared comments, talking about some of these were kind of lease retention wells. But my understanding is most of the offset Cline activity has been in Glasscock, and there has been relatively less up in Martin. And so can you talk about why you picked each of those -- each of these locations kind of in X/Y? And how you pick the landing zone inside there?

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James T. McManus, Energen Corporation - Chairman, CEO & President [46]

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Yes. Well, I'll give you the generalities, and then Johnny can comment. But effectively, a unit we call the Tiger Unit is where we drill the Cline in the north, which sort of offsets our Jones Holton lease up there. And again, it was a drill-the-hole situation in the north. And we were also curious to see how Gen 3 might perform. So it kind of worked perfectly for us up there.

In Glasscock County, another peer operator had, had a relatively good well in the Cline. And so we wanted to see how a modern generation frac would perform not too far away from that well, and that's why we decided to do one in Glasscock. So those are the generalities and then where we landed it specifically, I'll...

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [47]

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Yes, Charles, James is right. We play in a low [clausology] in Glasscock. We saw a good trend. We thought we wanted to extend that trend onto our acreage, and we wanted to look at the new frac design. And again, really encouraging there.

In the Martin County area, that was a drill-to-hole deeper acreage. And -- but as far as we have drilled some very nice Cline wells or some encouraging Cline wells in Martin County prior, we thought we could improve upon that with a new frac generation. It turns out to be true.

And we'll -- we still got a long way to go with the Cline. That's the encouraging thing, I think. We've got landing zones, we've got more to understand about exactly where to target these wells, particularly in Martin County because there has -- have been so few completions.

We're sort of the leader up there again, but we think we've got a long way to go to make these wells better, to improve them, to get them economically competitive. And I think we'll see as we learn about the nuances of drilling there, we'll see the capital cost also come more in line with what we're doing in the Wolfcamp.

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James T. McManus, Energen Corporation - Chairman, CEO & President [48]

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Yes, Charles, James. I think there's a lot to work with here. I mean, they are more expensive to drill because it's deeper. But as Johnny said, I think that cost can be worked down. And I think with the results that we're seeing, again, we're encouraged that this is a very economic formation, which I would not have said 12 months ago on a non-modern Gen 3 Frac. And so we're excited about them. We think they enhance our inventory.

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Charles Arthur Meade, Johnson Rice & Company, L.L.C., Research Division - Analyst [49]

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Yes. I know it was kind of an elaborate question. But there's -- it's really interesting stuff you guys are doing here. And if I could just push on one aspect of that with my second question, how many different landing zones in the D or in the Cline did you evaluate?

And is there a chance that there will be kind of a chevron kind of development somewhere down the line where you have like an upper D, middle D, lower D kind of thing?

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [50]

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I think definitely so, Charles. We see several opportunities to -- you target these petrophysically and you look at them. You also look at the stresses within that rock and try to find a good drillable, repeatable zone but also gives you good production.

And we're figuring that out. You can't tell everything just looking at logs. You need some experience. We don't have a lot of experience with it. We'll need to invest that in the future. But as -- you're right, this is a very thick zone. We see more than one landing zone. We see several zones to develop, and we think that will be a good healthy way to develop that, sort of like we do the Wolfcamp A and B.

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James T. McManus, Energen Corporation - Chairman, CEO & President [51]

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So Charles, if I toot our horn a little bit again, I think we were the leader in the Jo Mill and the Middle in the North, and I think we may be the leader for the Cline in the North.

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Operator [52]

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Our next question comes from Irene Haas with Imperial Capital.

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [53]

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Yes. More on the Cline, and congratulations on these wells. And my question is the Martin County well is it towards the eastern part of the county? And generally, the client footprint, is it still confined to the Eastern part of Midland Basin? Is it sort of a discrete sweet spot or more blanket-like in the way it's deposited?

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James T. McManus, Energen Corporation - Chairman, CEO & President [54]

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Irene, let me refer you to -- I'm looking for the page, it's got the Midland County map on it, here just for a second. And hopefully -- so Slide 8, if you were to go -- if everybody can -- I don't know if you all can all get there, Slide 8, if you were to look at the circle to the west, there's 2 circles in Martin County, do you see them, Irene?

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [55]

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Yes.

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James T. McManus, Energen Corporation - Chairman, CEO & President [56]

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So the circle to the left is where that Cline well is. So it's sort of right there in Martin County, kind of in the center northern portion of Martin County. Is that helpful?

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [57]

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Yes. So to follow up really, how extensive is the Cline formation? Does it kind of extend now to the middle of the basin eastward? And is it like more discrete sweet spots or sort of blanket-like in nature?

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [58]

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So our experience with the Cline -- we've been doing this 3 or 4 years. Most of our experience is right here at sort of central northern Martin, our personal experience. We do map it, though, both east and west.

I mean, we see the Cline as being a rather extensive zone. We don't have enough data right now to really start to parse it down on where the real opportunities are, but we think it's a good blanket zone, much like the Wolfcamp, maybe not as quite as extensive as the Wolfcamp on where it will be productive, but it's got a lot of running room.

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Irene Oiyin Haas, Imperial Capital, LLC, Research Division - MD & Senior Research Analyst [59]

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And if I may ask one more question, is the growth interval thickness -- what are the ranges for the Cline?

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [60]

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You know, Irene, I'll have to -- I don't recall right off, but I'll find it back here if you give me a moment. We're about 400 feet, particularly down in the Central Basin area. And at thicker, maybe 450 up in the North Midland Basin.

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Operator [61]

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Our next question comes from Derrick Whitfield with Stifel.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [62]

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Congrats on a strong start to 2018. James, on the gas marketing side, could you confirm that you have FT for your residual gas through the (inaudible) and if so, where to?

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James T. McManus, Energen Corporation - Chairman, CEO & President [63]

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Yes. So the gas is wet gas, and it's got FT to the processing plants, which they've got a Caymus I and II. And then that residual gas is moved through contracts that they have with 6 or 7 different people.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [64]

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Should we think about that as firm sales type contracts or...

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James T. McManus, Energen Corporation - Chairman, CEO & President [65]

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No, we're getting -- we're subject to the differential, okay. So I think what you need to -- the way to think about it is we've got flow assurance but we're getting the price of natural gas in the Midland Basin. We're still subject to the differential in the price, but we've got FT -- we're not marketing the gas. We're selling the gas at the delivery point.

And then there -- it's a liquids -- a white gas and then they have processing plants that process it. And we get a net of proceeds on that and then the dry gas is sold in residual contracts that they have. Does that make sense?

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [66]

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It does, very helpful. As a quick follow-up, could you provide an update as to where you guys stand with regard to the Howard County litigation?

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James T. McManus, Energen Corporation - Chairman, CEO & President [67]

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Yes, great question. So as many of you know, we won the lower court verdict in Howard County. And it was appealed by the other party in the lawsuit to the appeals court in Texas, which is a three-judge panel. Oral arguments were held back, I think, towards the end of the year. And we await ruling at this point. And we suspect that we get that ruling in the next 3 months.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [68]

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Great. That's fantastic. And then lastly, referencing Page 14, how should we think about lateral length progression for the Midland and Delaware individually for the balance of the year?

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James T. McManus, Energen Corporation - Chairman, CEO & President [69]

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We don't give you that for the balance of the year. I don't have that information. I think in total, obviously, we're talking about an average of 8,000 between the 2. I think in general, the Midland Basin is longer, and the Delaware is shorter as I pointed out because we've got a lot more drill-the-hole wells in this particular year due to some leasing activity and some trades that we did.

But we'll be back up importantly to 9,000 feet in '19 and '20. So it's an unusually -- 8's not a bad number, but it's unusually a little bit lower than what we would -- what we had in 2017 and what we plan to have in '19 and '20.

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Operator [70]

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Our next question comes from Gail Nicholson with KLR Group.

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Gail Amanda Nicholson Dodds, KLR Group Holdings, LLC, Research Division - MD [71]

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Just looking at your DC&E cost, there's about a 10% spread between the low end and the high end of your ranges in both the Midland and the Delaware. What's the biggest driver there? Is it the amount of proppant loading that you're using because there is a range in the Gen 3 design? Or is there something else kind of driving that, the spread between the low and the high end of your DC&E cost range?

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James T. McManus, Energen Corporation - Chairman, CEO & President [72]

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Well, we generally have sort of tied that a little bit to the total capital range. And we're just giving a range in there to handle cost inflation or efficiencies that we might experience. And I don't have any other color than that. Johnny, unless you -- I think that's basically it, Gail.

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [73]

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Just to give you sort of a view of how we perform at sort of in those parameters.

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James T. McManus, Energen Corporation - Chairman, CEO & President [74]

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I mean, at this point, we're sticking to the midpoint of the capital guide that we have right now, but we do give a range. We haven't seen -- I would give you this comment, Gail. We haven't seen any cost inflation so far in any kind of significant way. It's early in the year, but so far, things have been pretty stable.

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Gail Amanda Nicholson Dodds, KLR Group Holdings, LLC, Research Division - MD [75]

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Great. And then looking at increase in the commodity price environment, I know you guys had a process in regards to the Central Basin Platform asset late last year, and I think it materialized because no bids were to your -- what you guys wanted to see. But have you had any renewed interest from third parties with the increase in the commodity in regards to the Central Basin platform asset?

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James T. McManus, Energen Corporation - Chairman, CEO & President [76]

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Well, I think the thought process there, the answer is we've always got some folks interested and the real question is can we get to a number that we think is the appropriate value. I think it's still difficult, Gail, because of the backwardation of the strip.

We've always thought that to get the right value for that property, it needs to be priced in more of a $60-ish outlook. And when you're -- when you have the strip and the fifth year and the fourth year going down into the low 50s, it's just hard for people to get there.

I think I commented last time we didn't feel like we were getting paid for the upside in the bids that we got. We will continue to look at it, evaluate it. Obviously, if we get to something that we like, it's an asset we've talked about monetizing. But at this point, we don't have a number that we like right now on the table.

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Gail Amanda Nicholson Dodds, KLR Group Holdings, LLC, Research Division - MD [77]

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Okay, great. And then just want to slide one more with the Cline. I'm looking at the prior curve versus the new Gen 3 type curve that you put out. There's really no change in the oil compositional mix in the Central Basin Platform, but on the Northern Basin acreage, it went up by about 4%. Is that all just due to the completion design? Or was that also driven by maybe landing in a different zone within the formation?

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [78]

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Well, it may just be due to rounding. I don't think we would see -- did you say 4%?

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Gail Amanda Nicholson Dodds, KLR Group Holdings, LLC, Research Division - MD [79]

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Yes.

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [80]

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I think that's just due to the rounding -- the numbers that we put down here. We're basing this off -- we're basing the oil percentage off actual data from our historic Cline wells. So there should be no material difference here. We're not looking at -- for the frac generation to really increase that oil percent.

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Operator [81]

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Our next question comes from Brad Heffern with RBC Capital Markets.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [82]

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Earlier in the call, you mentioned that 60% of the outperformance this quarter was from well performance. I'm just wondering if you could dig in a little bit on that. What's creating the well outperformance?

And kind of the angle I'm coming at it from is you've had the Gen 3 Frac design for a while now and so is it still further tweaks to that design? Is it better well targeting? Is it just that the type curve you're using isn't necessarily accurately reflecting sort of the leading-edge Gen 3 performance? Any color you can give there?

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James T. McManus, Energen Corporation - Chairman, CEO & President [83]

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Yes. I think we're doing a little bit better than the type curve and in particular, in the Delaware. And as I mentioned, we were at 440 IP 24 per thousand. So those wells were a little bit better than the ones last quarter. Some of it could have to do with the mix.

But in general, the Delaware just continues to outperform, and you can see that the Midland Basin was pretty much on track a little bit up above the type curve. But where the significant outperformance was the Delaware up, I'd kick it to Johnny...

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John S. Richardson, Energen Corporation - President & COO of Energen Resources [84]

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That's exactly right. I mean, and like I mentioned, again, getting back to outperformance, some of our late '17 wells are performing very, very well. And they contributed a good bit in the first quarter.

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James T. McManus, Energen Corporation - Chairman, CEO & President [85]

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Yes, I mean, really, throughout, if you -- when you go back to those curves, you're going to see that for the most part, the red curves or the 2017 Gen 3 performance is beating the type curve. And so that is -- that could be a potential theme for us, we hope, throughout the year.

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Bradley Barrett Heffern, RBC Capital Markets, LLC, Research Division - Associate [86]

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Okay. I appreciate that. And then I guess, you guys have always been in the camp of pulling value forward as long as you can keep the balance sheet in good shape. I'm just wondering if we see commodity prices continue to stay strong like this, you guys are already running 10 rigs.

Is there any sort of constraint that you think about in terms of surface footprint or just organizational sort of horsepower that would keep you from running a lot more rigs? Or do you think that there's a lot -- there's not much of a limit on that front?

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James T. McManus, Energen Corporation - Chairman, CEO & President [87]

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Well, we've been actually surprised that the general availability of surfaces, it's gotten a lot better. In fact, we had multiple bidders on this fifth frac crew that we've signed up for July. So I think at this point, there would not be constraints to moving that program up.

Now I'm not committing to doing that, you are just asking are there constraints. And doubling to 20, no. But adding a few rigs and a few frac crews for the market that's out there right now, I don't think that would be impossible at all.

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Operator [88]

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Our next question comes from Paul Grigel with Macquarie.

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Paul William Grigel, Macquarie Research - Analyst [89]

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Digging in a little bit more on differentials, the press release notes 2Q at 93% of WTI before hedges and a 460 WTI Midland assumption. With pricing seemingly materially wider than that, can you provide some color on the basis for those assumptions?

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James T. McManus, Energen Corporation - Chairman, CEO & President [90]

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I'm going to let Chuck do that.

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Charles W. Porter, Energen Corporation - VP, CFO & Treasurer [91]

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So on the gas side, we used a recent strip. We increased our gas basis differential from -- I think, the budget was $1, it went up to $1.40. And then on the oil side, we've got a mid-cush differential somewhere around the $4 to $5 range on the sweet side. That's probably a little bit light at this point in time.

When we put the information together, that was the strip at the time, as you know, that has moved against us here rapidly. From a sensitivity perspective, we estimate that every dollar maybe between, say, $4.5 million to $5 million of EBITDAX. So if it were to remain wide for the rest of the year, let's assume, say, $10 so another $5, you're looking at somewhere in the neighborhood of less EBITDAX of about $25 million to $30 million. I think that shows the power of the hedges that we have in place for 2018.

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Paul William Grigel, Macquarie Research - Analyst [92]

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Okay. (inaudible) I just have one follow up on the gas side. As your Permian Basin-specific hedging roll off, what's the price points that you guys are generally getting on those? Is that a Waha, is that a perm? Is it just kind of depends where in the basin? Just a little color there would be helpful.

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Charles W. Porter, Energen Corporation - VP, CFO & Treasurer [93]

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Yes. Our production is going to be priced either at an El Paso Permian or a Waha index. And so as we move forward in layering hedges, we typically will try to -- obviously, not just do a NYMEX hedge but do the NYMEX hedge, along with the basis differential. And we'll just kind of continue to look at that as we go through the rest of 2018.

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Operator [94]

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(Operator Instructions) Our next question comes from Jeffrey Campbell with Tuohy Brothers.

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Jeffrey Leon Campbell, Tuohy Brothers Investment Research, Inc. - Senior Analyst of Exploration & Production and Oil Services [95]

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I just wanted to go back to the Cline real quick because of something that Johnny said earlier on the call. Referring to the 235 Cline locations that are estimated on Slides 25 and 26.

Since Johnny said that Energen's Cline data is still evolving, I was -- I just want to be really specific, is there the potential for Cline location upside? Or should we think of the Cline as mainly a potential EUR uplift story based on these outstanding models?

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James T. McManus, Energen Corporation - Chairman, CEO & President [96]

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I think this, Jeffrey, we've got -- actually, it's 290 net locations in the North and 269 in the Central. I'm not sure you said that. So it's a total of 559 locations. We basically identified where the Cline is present under our acreage in totality. So what the upside is the EUR and the economics as opposed to what we have stated in these inventory slides now, not the number of locations.

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Operator [97]

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There are no further questions at this time. I will turn it back to management for closing remarks.

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James T. McManus, Energen Corporation - Chairman, CEO & President [98]

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Well, thanks for joining us today. Everybody, have a great day. Thanks. Thank you.

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Operator [99]

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This concludes today's conference. All parties may disconnect. Have a great day.