Energen (EGN) James T. McManus II on Q4 2015 Results - Earnings Call Transcript

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Energen Corp. (NYSE:EGN)

Q4 2015 Earnings Call

February 12, 2016 11:00 am ET

Executives

Julie S. Ryland - Vice President-Investor Relations

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

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

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

Analysts

Ryan Oatman - Cowen and Company

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Kyle Rhodes - RBC Capital Markets LLC

Timothy A. Rezvan - Sterne Agee CRT

Charles A. Meade - Johnson Rice & Co. LLC

Irene Oiyin Haas - Wunderlich Securities, Inc.

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

Jeb Bachmann - Scotia Capital (NYSE:USA), Inc.

Gail Nicholson - KLR Group LLC

Operator

Greetings and welcome to the Energen Corporation's Fourth Quarter 2015 Financial and Operating Results Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow formal presentation. As a reminder, this conference is being recorded.

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

Julie S. Ryland - Vice President-Investor Relations

Thank you, Matt, 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 and 12 months ended December 31, 2015. In addition, Energen disclosed a variety of information including its 2016 capital plans, appraisal well highlights, updated potential drilling inventory and year end 2015 reserves.

Supplemental slides can be found on Energen's home page at www.energen.com and they will be referenced during this call. Today's conference 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's Chairman and CEO, James McManus. James?

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

Thank you, Julie. And let me add my greetings to all of you as well. While these are certainly challenging times, I believe Energen is in good position to weather the storm of low prices. Let's jump right in. First up, what are we going to do in 2016.

We plan to invest roughly $250 million to $350 million of drilling and development capital in 2016. As you know, we do not budget for leasehold or other acquisitions. The plan was detailed in our press release, the $250 million plan. This $250 million allows us to hold our acreage in the Delaware and Midland Basins, allows us to complete 46 net depths. It allows us to drill and complete one additional Lower Spraberry well in Martin County in order to finish the pad and also allows us to invest in some associated facilities.

If oil prices increase later this year, we'd like to invest capital closer to $350 million and resume drilling in the Midland Basin. We estimate that internal rates of return on Wolfcamp A and Lower Spraberry wells with 7,500 foot lateral lengths are in the low 20%s at assumed strip pricing of $36 per barrel in 2016 rising to $40 per barrel in 2020, and assuming current estimated drill and complete cost of $6 million to $6.5 million.

Using those same pricing assumptions for Wolfcamp A and Lower Spraberry wells with 10,000 foot lateral lengths and assuming current estimated dry hole and completion cost – I mean, drilling and completion costs of $7 million to $7.5 million returns are approximately 30%. So you can see on our longer laterals, even at strip pricing, we've got pretty good return numbers when we do resume drilling.

We estimate that we will have a funding gap between capital investment and after-tax cash flows of approximately $225 million to $325 million depending on which of those scenarios we go with, the $250 million or $350 million. To fund this gap, we anticipate selling non-core assets. We have sales processes underway to sell our remaining San Juan Basin assets as well as acreage in the Eastern Delaware Basin in Texas. We estimate the cash proceeds could be $400 million. As most of you know, we are largely unhedged, therefore, our debt to EBITDAX multiple is highly sensitive to changes in oil prices. An average 2016 oil price is at $40 per barrel, we estimate that we can achieve a year end 2016 debt to EBITDAX multiple of approximately 2.5 tons. That does assume that we successfully sell our identified non-core assets for around $400 million.

To help drive down expenses in 2016, we've implemented a variety of cost cutting measures. These include a workforce reduction across our three-state area, which we implemented in January. And we expect additional savings when we realize our exit from the San Juan Basin. We estimate that our net salaries and G&A expenses excluding pension settlement charges and severance payments will decrease 25% year-over-year to approximately $89 million in 2016. So let me be clear, that includes everything we've done along with the sale of the San Juan, leads to that 25% reduction to $89 million in 2016. To further enhance our capital discipline, we've decided to discontinue paying our small cash dividends.

Adjusting both periods for our planned asset sales, year-over-year production is estimated to be essentially flat at a midpoint of 19.9 BOE or 54,437 BOE per day. Comparable production in 2015 was 20.2 million BOE or 55,397 BOE per day. We see 25% production growth coming from our horizontal drilling and development activities in the Midland Basin. And this is offset by natural declines in the vertical Wolfberry, 3rd Bone Spring Sands, Delaware Basin and Central Basin Platform where we're obviously not investing any capital.

DUC completions are scheduled to occur during the first half of the year and therefore 2016 production is expected to peak in the third quarter. We estimate a 12% decline in our 4Q to 4Q exit rate. Next, I want to spend a few minutes reviewing our decision to exit the San Juan Basin and become a pure play Permian operator. As you may recall, we sold approximately 70% of the San Juan Basin assets last March. The remaining assets are primarily natural gas production with some upside potential in the Mancos oil play.

We decided to exist the San Juan Basin after completing our assessment of the early performance of the exploratory wells we drilled in the latter half of 2015 to test the oil play's potential on portions of our acreage. The bottom line for us is that outside a small core area the current Mancos production, we do not find the results to be competitive with our other high quality assets in the Midland and Delaware Basins.

As I discussed earlier, we're also planning to sell non-core Delaware Basin acreage, for the appropriate value we are also open to the sale of other assets in our portfolio that are outside our Midland Basin and core Delaware Basin holdings. So, as I said, we've got planned sales of about $400 million, but we've got other assets that we would be open to if necessary.

For the next three minutes, I would like to walk through the supplemental slides that are posted on our website. On slide two, we present our updated un-risked potential drilling inventory of horizontal locations by county in the Midland Basin. So that's on our website, again, I'm talking about slide two. You're going to see that at year-end we have 4,440 net locations, 2,504 in the Midland Basin, 1,936 in the Delaware Basin and we give you the number of drilling locations by country. Obviously, this excludes the assets that we plan to dispose of. These potential drilling locations are engineered based on the company's existing acreage and spacing plan.

We then move to slide three. Obviously, we've got great potential here in the Midland Basin, in excess of 1 billion BOE and I would point out that's net not gross. We show you the number of wells on the left hand side of that slide that we've drilled in each formation. So for example, the two Jo Mill wells we'll talk about in a minute, you can see those there. You can see we've been more active in the Wolfcamp A and B with our drilling program last year. And then you can see what we define currently as the net acreage where that potential zone is due to the testing and work that we've done. We then give you the net locations by zone and we give you a type curve range by zone. And then we show the resource potential.

Now, importantly at the bottom of this slide, 60% of our net locations, that 1,430 have an average lateral length of 8,100 feet and an average working interest of 75%. So we've got a really strong inventory of long laterals. And then a subset of that, 19% of our net locations or 477 locations, have a net lateral length of 10,000 feet with an average working interest of 79%.

Then if I turn to slide four, we'll take a look at sort of what we call our northern acreage, which is Midland, Martin and Howard counties, where we have 39,000 net acres. And this is kind of a gun barrel presentation, where we see the potential, if you look at the bottom right hand side of the slide, for 36 wells to 50 wells per section.

And then we're turning to slide five, which we define as our southern, which is Glasscock County, where we've got 29,000 net acres and I would point out, we've actually got more acreage in the north than we do in Glasscock County. But we've got a potential there for 34 wells to 40 wells per section on the gun barrel that you see there.

We then take you to slide six and talk a little bit about our Delaware potential, you'll see where we've identified a net greater than 1 billion barrel of BOE, and you can see there that we've identified long laterals of 143 net that have a net average lateral length of 9,700 feet and an average working interest of 100%.

I'd point out in the Delaware Basin, in particular, we continue to work with lessors, we continue to work on trades, and we would expect the number of longer laterals here to rise as we continue to do that work.

On the next several slides, slide seven, we highlight the performance to some of our recent appraisal wells. Our first two Jo Mills wells were drilled in Martin County, tested in the fourth quarter. The rates of these two were quite impressive, averaging a peak 24-hour rate IP of 1,062 BOE per day, and an average 30-day peak of 943 BOE per day. Importantly, the oil content was high at approximately 75%. Then in northern Midland County in an area of approximately 2,000 acres of high Spraberry depletion, we drilled a Wolfcamp A test well that confirmed the positive results generated by the B well that we talked about last quarter confirming that there was no impact on the Wolfcamp in that particular area.

Turning to slide eight, we show the locations and results of a 10,000 foot Lower Spraberry test in Glasscock County. This well is located approximately 5 miles north of our first Lower Spraberry test wells here in Glasscock County. You'll see it's the Daniel well there, generated a 24-hour IP of 1,460 BOE per day, 74% oil, with a peak 30-day rate of 1,213 BOE, 70% oil. It's a very nice Lower Spraberry well in Glasscock County, in fact, I think it maybe the best one that's ever disclosed to-date.

I would note that the Daniel well is performing much like our Lower Spraberry wells we've drilled on the northern half of our acreage position. It's a 10,000-foot lateral. It's tracking a 1 million BOE type curve through some 60 days. So, again, very, very good well there.

The next slide, shows, slide nine, shows our cumulative oil performance for our first two Jo Mill wells, as well as our first two Middle Spraberry wells that we disclosed last quarter. It's a little difficult to see on the slide. The black line which we have the least amount of data, about half of what the green line is, is right on the 1.2 MBOE curve, that's the Jones Holton #811H and you could see the Jones Holton #807H is actually tracking above that curve. And then you'll see our Jones Holton #601H, which is a Middle Spraberry and our Dickenson well which is also a Middle Spraberry as well.

So then if we turn to slide 10. We've got the cumulative performance of our five Lower Spraberry levels that we drilled earlier in 2015 in Midland and Martin and Howard counties. If you remember, again, we had a small area in Midland County where we knew there was some drainage that took place, and that Epley well on the bottom of the chart is where that was, we're still pleased with that well. We might have expected even more drainage impact, it was not as severe as we thought. We followed it up. Well, we didn't follow it up, but the Dickenson well was also drilled there around that area, it's tracking at 770 MBOE curve and of course the other ones we drilled are well above the 900 MBOE curve as you can see there from a performance perspective. So very excited about our Lower Spraberry results as well.

Lastly on slide 11, we have slightly adjusted Wolfcamp A/B type curve for you. This one is normalized to 7,500 foot. This curve has an EUR 890 MBOE, which was reviewed by Ryder Scott. The inventory production mix is a little lower than our previous curve at 52% oil with the A-bench having a higher component than the B-bench, but that's the average of the two. Our 19 latest Wolfcamp A and B development wells in Glasscock County, all with 7,500 foot laterals generated average peak 24-hour IP rates of 1,242 BOE per day, 83% oil and peak 30-day average rates of 875 BOEs per day, 71% oil.

Next, I would like to direct you to our new release for a detailed information on year-over-year results for the fourth quarter and the calendar year. I would highlight that production from our horizontal plays in Midland Basin where we have focused the majority of our capital in drilling and development activities over the last couple years increased 114% from 4Q 2014 to 4Q 2015 and 248% from calendar year 2014 to calendar year 2015. LOE declined substantially in the fourth quarter and calendar year as we continue to work to reduce operating costs. G&A was down year-over-year and as I noted earlier, is estimated to decline another 25% to approximately €89 million at yearend 2016 as a result of targeted cost-saving measures.

As we look at the fourth quarter of 2015 relative to our internal expectations, I want to point out that our earnings were negatively affected by a fourth quarter DD&A adjustment, that totaled $0.17 per share and was driven by the impact on reserves of low commodity prices at year-end. Absent that, Energen's adjusted fourth 2015 earnings would have been $0.44 per diluted share. And I suspect others will experience that reduction due to the drop in commodity prices and higher DD&A.

We did fall just short of our guidance mid-point on production, more than compensating for this, however, was decreased LOE, lower ad valorem and production taxes, greater-than expected realized oil prices, lower exploration expense and lower G&A expense. Production was short of the midpoint by approximately 3% for a number of reasons.

First, some of our Wolfcamp B wells in a select area near the Glasscock/Reagan county line where higher gas rates and lower oil rates were encountered, underperformed our expectations. I would note that we have completed our drilling in this localized area, and would not expect this to continue.

Fourth quarter production also was negatively affected by winter storm around Christmas and the timing of flow back of fourth quarter development wells. These factors were partially offset by continued strong performance from 3rd Bone Spring and Wolfcamp wells in the Delaware Basin.

Before opening the phone lines for your questions, I want to mention our year-end proved reserves which totaled 355 MMBOE. This reflected only a 5% decrease from 2014 even though we lost 58 MMBOE, primarily due to substantially lower commodity prices and another 68 MMBOE to the sale of proved reserves in the San Juan Basin in March of 2015. Excluding the San Juan Basin's divestiture from yearend 2014 proved reserves, we actually saw 16% increase. This was due to reserve additions of 132 million BOE, primarily due to Wolfcamp and Spraberry drilling in the Midland and the Delaware Basin. These additions replaced production by 550%. I would also note that our proved oil reserves increased 17% in 2015 and now represents 59% of total proved reserves.

Okay. We've covered a lot of ground. I'm going to start now and move to Q&A. I would ask Matt to please give the appropriate instructions at this time. Matt?

Question-and-Answer Session

Operator

Thank you. Our first question comes from the line of Ryan Oatman from Cowen. Please go ahead.

Ryan Oatman - Cowen and Company

Hi, good morning. And thank you for taking my questions. I'm trying to reconcile the 1Q guidance with the 4Q actually production and the divestiture. I was just wondering if you can help me walk through the math of how the 4Q production of about 65,000 barrels a day goes to 53,000 in 1Q 2016?

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

Julie wants to go ahead and take that or Chuck, no Julie.

Julie S. Ryland - Vice President-Investor Relations

Okay. Well, the guidance for first quarter 2016 excludes the sale property. So you had...

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

We fact out the properties moving to sale.

Julie S. Ryland - Vice President-Investor Relations

Yeah. And so, you do see, you do still see a sequential decline even on an adjusted basis from 4Q 2015 to 1Q 2016 that's associated with the fact that we're not drilling right now, we've just started completing our DUCs, so you're going to see that production from fourth quarter to first quarter decline.

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

Yeah. We – go ahead, Ryan. We expect it to rise in second quarter peak and third and then as we've pointed out, on an adjusted basis for the sale, we expect a decline of 12% 4Q 2015 to 4Q 2016. Julie is exactly right. I mean, you got to adjust – you got to excel properties out first of all and then we won't have these, these DUCs are being completed in the first half of the year, but a lot of that production doesn't hit until the second quarter, third quarter.

Ryan Oatman - Cowen and Company

That's a good point. And then it seems to me and I think you touched on it bit that the production guidance provided corresponds with the low-end of the capital plans, specifically, that $250 million, can you just confirm that that's correct?

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

That is absolutely correct. That's the $250 million plan. We're hopeful that we'll get some kind of rebound if we're able to implement the three rig program that we talked about in the latter half of the year because obviously that would do a lot help to set us up going into next year. But, yes, absolutely the production numbers are predicated on the $250 million. We also would tell you that the $350 million because you do drill those later in the year, and you complete it in batches, it would not have a lot of impact on 2016 production although would obviously going into the next year 2017.

Ryan Oatman - Cowen and Company

Okay. And one more for me, and this maybe looking a little too up far out in the future, but if you did spend that $350 million, let's say, in 2016 and 2017, do you have a sense as to what 2017 will look like under such a scenario?

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

Yeah. We're not giving any information out on that right now, Ryan, I mean, we're talking about 2016 right now. We have no idea what 2017 is going to look like, because we don't know what our plans are going to be at this point.

Ryan Oatman - Cowen and Company

No, fair enough. I appreciate the color.

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

Thank you, Ryan.

Ryan Oatman - Cowen and Company

Thanks, guys.

Operator

Our next question is from Neal Dingmann from SunTrust. Please go ahead.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Good morning, guys. James, two quick ones here. First, how do you all think about just simply maintenance CapEx today, just on your spend. I know you talked about the $250 million , $350 million plan, but if you think about a simple maintenance CapEx, what are you thinking about?

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

Yeah. That's actually a very decent range for kind of go forward maintenance CapEx. I'll ask Chuck to comment on that as well. But I think $250 million, $350 million is not that far off if you spend most of that capital at the beginning of the year.

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

Yeah. That's pretty much correct. The $250 million is probably a little bit on a lighter side, given that it's more heavily influenced by the DUCs this year. So on a more normal run rate basis, it's probably in the $350 million plus or minus range.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. I mean, one-time, I think, you all were saying closer to $450 million or $500 million, so I just wanted to double check that.

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

I don't think it's as much anymore, Neal. One of the things you might have experienced, it's not a big impact or when you do so to San Juan, you're selling a declining asset that you don't have to fight the decline on that anymore.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. And then speaking of decline, how do you all look – I'm looking at the slide from one of your – the prior presentation, it shows that, James, that PDP decline rate slide that you all have. And it shows for the 5 year, 10 year, 20 year, but I'm trying to get a sense on a sort of a shorter period how you view kind of the typical Delaware PDP decline for kind of that 1 year to 5 year period. I think on this chart Delaware it shows the 5 year being 19.4%, how you all think about that?

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

I think Chuck has got that, just a second.

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

Yeah. Well, on the entire Permian Basin kind of a one year decline rate, we would estimate at kind of 18.5% going over on – of a 5 year period the total would be 16%. And then when you get to the 10 year and 20 year, it would be 12.5% and 10%. So we'll update that slide in our presentation eventually but that's where it is right now.

Specifically, the Delaware Basin is a little bit higher than that, than the total average out of the Permian. The Delaware Basin is about 27% in the first year and then it goes to 18%, 14%, 11% on the 5 year, 10 year and 20 year basis respectively.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

And then to your point Chuck, the Midland certainly as it indicates on that slide would be a bit better than that certainly?

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

Correct. Although, there's a good bit of weighted production there. So it's fairly close to the overall company average or Permian Basin average.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. It makes sense. And then last one I know, James you said, obviously and I agree, that you certainly don't want to go out there and putting 2017 out at this point, especially with this kind of volatile market. But I just want to try to clear something up. Looking out there I think, there is a lot of maybe, potentially confusion as far as how you all are looking. You mentioned that you – that production peaks in the third quarter yet you put that production guidance out for the fourth quarter of 12% lower year-over-year. So I guess, what I'm getting at if you look at that third quarter to fourth quarter decline, just I want to make certain – again, while – certainly no 2017 is out there. It's probably fair to say that's not the same decline we should think about from third to fourth continuing from fourth to first or first to second, I would assume?

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

I agree. Yeah.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

And is that more just on timing or, again, why shouldn't we think of that as being sort of a linear decline there?

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

What you're going to have in the third to fourth quarter of this year as we bring the new DUCs on in the second and third quarter, those would be brand new wells. They're going to scream off (25:52) higher, so to speak, than they will once they flatten out. So when we go out into 2017, you won't have the same significant decline rates that you'll have just going from the third quarter to the fourth quarter of 2016.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Chuck, you mean into the 2017, you wouldn't have that same significant...

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

Right. Contrast, yeah, compared to 2017.

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

I think, it's going to flatten. You're going to see your steepest decline from third quarter to fourth quarter if you bring those rates on – those wells on, but if we bring them on in the second quarter and they peak in the third, they'll moderate down and so you won't have the same sort of drop.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Great, guys.

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

And of course, if we're able to put some rigs to work later this year that changes the picture dramatically.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

James, are you able to say at what price you would bring those rigs back?

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

Well, it's a pretty complicated matrix as you might expect, but I would think it needs to have a four on the front of it.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Okay. Very good. Thank you all.

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

Thank you.

Operator

Our next question is from the line of Kyle Rhodes from RBC Capital Markets. Please go ahead.

Kyle Rhodes - RBC Capital Markets LLC

Hey, guys. Good morning.

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

Hey, Kyle.

Kyle Rhodes - RBC Capital Markets LLC

I had a quick question for you on the non-core Delaware assets being sold. Can you give a acreage number and current production number for those assets? I'm just kind of trying to get a sense of how much of the $400 million in asset sale value you guys are ascribing to PDP versus acreage?

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

Yeah. It's going to be mainly an acreage sale, but I'll let John tell you the acreage and PDP.

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

It's about 35,000 acres that we're looking to market there and somewhere between 1,200 barrels a day and 1,400 barrels a day, so not very much production at all.

Kyle Rhodes - RBC Capital Markets LLC

Okay. Great. That's helpful. And then you guys just kind of mentioned the price you needed to get pre Midland rigs back to work by yearend 2015, had to have a four handle on it. I guess, assuming we get there hopefully, where would those rigs be concentrating to go back to work.

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

Another great question. We've talked about that. Let me kick that one to Johnny as well.

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

Yeah. I mean, we've got options, nice thing about our asset base, but I would say, put it this way, this is not a decided this long time, we've still got some decisions to make. But I would say two-thirds of them will be north and two-thirds of them will be longer laterals approaching 10,000 feet. So you have to consider where our facilities are developed because you don't want to spend extra capital in this time to overload facilities or to build a lot of facilities out. But we have enough inventory, enough capacity to execute that kind of program. It could change, it could – we've got some options, but today that looks like at least two-thirds in the north and two-thirds 10,000 feet or so.

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

I sort of talked a little bit about the – chime in here a little bit – I sort of talked about the returns early on in the press release. But I think if you look at our returns on 10,000 foot laterals that are matching the Permian operator out there that I've seen so far. I think quality of the assets we've got is outstanding. Unfortunately, we've got to protect our balance sheet in this situation and we need a higher oil price to go after those, but they're there and the quality of the assets is strong.

Kyle Rhodes - RBC Capital Markets LLC

Great. I appreciate the color, guys.

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

Thanks.

Operator

Our next question is from Tim Rezvan from Sterne Agee. Please go ahead.

Timothy A. Rezvan - Sterne Agee CRT

Hi, good morning, folks. Actually, I want to follow-up a little bit on Ryan's question. I was wondering if you could sort of walk through the different kind of oil cuts that we're seeing in 1Q production versus the full year? I guess, it sounds like there's sort of been a pause of completions in the first quarter and that's why the oil maybe a bit lighter in first quarter over the whole year, can you comment on that?

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

Well, I wouldn't say we had a pause of completions in the first quarter, we're working on those completions, they just – it takes time by the time you fracked to the time you turn these around and there is a tempo, there is a message to bringing wells on. And so you'll see those wells that are mainly in our northern areas which are oilier begin to contribute in second quarter and third quarter, as James pointed out. One thing about the gas mix right now is, our Central Basin Platform, the Bone Spring, and the Delaware, even our Wolfberry wells are declining. And they're heavily oil weighted, so we're actually seeing a decline in some of our older production and that is sort of weighing on our mix right now. But as we begin to bring new properties on, you'll see that reverse out we believe.

Timothy A. Rezvan - Sterne Agee CRT

Okay. That's helpful. And then on, I guess, this is maybe a function of the production kind of growing throughout the year, but on the unit expense guidance, almost all the items are sharply higher in the first quarter versus the full year, is that just a function of the production ramping higher throughout the year?

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

No, it's a little different to that. Let me kick that to Chuck, I think it's specific on each one, but Chuck, go ahead.

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

Well, as it relates to the SG&A expenses in the first quarter, it is higher in the first quarter. And as it is certain unusual items, we had some additional payroll taxes that are paid. We also have additional salaries in the month of January related to the fact that the reduction in force did not take place until towards the end of January. There were some other kind of one-off items and that kind skewed the quarter up. And that's – and then we expect it to kind of level out. So for the G&A, it's really more related to the product. I mean, the actual expenses as it related to (32:10) production.

Timothy A. Rezvan - Sterne Agee CRT

Okay. For all the other items as well, the kind of cash OpEx number, should we see a similar sort of trend (32:20)?

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

Yeah. Cash OpEx – the cash OpEx number, you would be correct. I mean, we basically have on our lease operating expenses once adjusted for the property sales, we kind of have our operating expenses somewhat being held flat. And so to the extent that the production varies by quarter that's why you would see changes on the quarter versus the year.

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

Yeah. So, Tim, to make sure you got that, we've got from a raw cost perspective, hopefully we're conservative. Although we have budgeted it to be the same thing as it was this year. Hopefully, that turns out to be better. But in terms of on a BOE basis since the production is lower on an adjusted basis that's why you have the rate a little bit higher.

Julie S. Ryland - Vice President-Investor Relations

Something I want to make – it may get lost in the footnotes, it's relatively small. But you will see on that, on the calendar year 2016 guidance that we footnote LOE and we've gotten this question a lot over the years and it's become – it's just I want to point out to you. If you clear (33:20) out and isolate just the Midland Basin LOE, you have a much lower number, our other, particularly some of our older assets in the Central Basin Platform really pulled that number up on a BOE basis. So I did want to point that to you, I think on an annualized basis we're guiding somewhere in the $6 vicinity for the Midland Basin.

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

Yeah. $6.10 to $6.60, I think – it's a little harder to do an apples comparison as we've got legacy Central Basin Platform properties as well as Delaware. So we do isolate our Midland out there because a lot of people are comparing us to Midland Basin-only operators and if you look at that LOE at $6.60, I mean $6.10 to $6.60, I think it compares extremely favorably.

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

Yeah. And just to build on that, I mean, the Midland Basin is again less than $7, the Delaware Basin is also still relatively attractive, going to be less than $10 whereas the Central Basin Platform being older properties and has a lot more legacy is a good bit higher than that. And therefore that definitely impacts the profitability of that property in these lower oil price environments.

Timothy A. Rezvan - Sterne Agee CRT

Okay. I appreciate that thorough explanation. And if I could just sneak one last quick one in. You sort of floated that $400 million number. Should we think about that as a pre-tax number?

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

Yeah. We're not going to have any tax leakage.

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

You think about it as an after-tax number. I mean, we're not going to pay any tax on that $400 million.

Timothy A. Rezvan - Sterne Agee CRT

Okay. Thanks so much.

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

Sure. Thank you, Tim.

Operator

Our next question is from Charles Meade from Johnson Rice. Please go ahead.

Charles A. Meade - Johnson Rice & Co. LLC

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

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

Good morning, Charles.

Charles A. Meade - Johnson Rice & Co. LLC

If I could drill down a little bit more on those southern Glasscock Wolfcamp wells that came in a little gassier. I know that didn't help the oil volumes on the quarter, but sometimes those gassier wells can be more productive. And so I'm wondering, how those results may have changed, how you're looking at where to drill in Glasscock and your appetite for one area versus another?

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

Yeah. I'm going to turn that to John, but let me kind of – when you get into Reagan County, you experience – our acreage is not really in Reagan County, but you experience this in a pretty major way. We've done a lot of mapping of this particular instance. And we did have a little finger, that came up into an area that we drilled, that we think is over with now. But I'm going to let Johnny, talk to you about it.

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

Well. Thanks for the question Charles and as James has pointed out. We view this as a localized event because we've done a lot of drilling in this area. And these wells have very different character than what we have observed. So now we've got a whole body of wells out there and we saw this a little bit at the end of the third quarter. We sort of hoped it wasn't going to be, but we got a little crazy at the end of the third quarter as we began to bring some of the wells on, and all the wells we are reporting in the fourth quarter were concentrated in one area as we've pointed out along the Glasscock Reagan County line and as James already pointed out.

And looking at this now as we've seen these results in the B we do see a definite trend sort of running south to north. We see a little finger here. We know, as James has pointed out, it gets gassier in Reagan County that's just a character. It get from north of the basin to south because of maturities and kerogen types and maybe even relative perms, who know exactly what the issue is, but you do see the gassier nature particularly in the B and Lower.

And so we see this little finger does sort of reaching up there and pointing right at us and that's the result we got. We don't expect it to be a wide spread phenomena because, again, we've done a lot of drilling in this area. These are very different character wells than what we have seen. We understand it, the fact that we see it as a continuation of some of the southern trend it sort of just fingers up into us, but we don't think it's a long-term problem for us at all.

Charles A. Meade - Johnson Rice & Co. LLC

Thank you for that detailed answer, Johnny. And if I could ask one more, James. You've made the comments earlier in your prepared comments that you are looking for the right price for those Delaware Basin assets. And I'm wondering if you could lay out for us a bit the options that you see if you don't get a price that you like for those San Juan Basin assets or the Delaware Basin assets. How would that change how you steer the ship into yearend 2016 and approach 2017?

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

Yeah. So first of all, let's talk about San Juan for a minute. It's primarily gas. I mean, I think it's going to sell, I'm not really worried about it. I'm pretty confident. I think we'll have a lot of people interested in that particular asset. We've had some early feedback on our other Delaware stuff that we've got processes started on and the feedback is very good. We'll see how it goes. I'm actually confident that we'll get to this number on these assets.

But let's assume, for example, that we don't. Energen is asset-rich. We've got a number of properties, and a number of options in addition to what we've put up here if we chose to. We've got lots of other acreage in the Delaware Basin that we don't consider in kind of what we call the core of the core. So there could be other things that we would look at there. And we also have the Central Basin Platform asset as well. Now, you want to make you're getting the right value, and you don't want to do desperation sales at this point in time at cheap prices and frankly, we're just not going to do that. But if we get a right price then as I've said, really any asset in our portfolio could be monetized in order to meet this objective. So I think we'll meet it with the ones we've got up, but we've got plenty of options outside of that.

Charles A. Meade - Johnson Rice & Co. LLC

James, thanks a lot. That's helpful insight into your thinking.

Operator

The next question is from Irene Haas from Wunderlich Securities. Please go ahead.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Yeah. I'm just wondering if you can tell us – a little more color on Delaware Basin, I understand that most of last year really has been spent in Midland Bain, perhaps a little bit of update on the well cost, where did you guys end up in the year? And then the second question is – what are you targeting as a breakeven price for 2016?

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

I'm going to let Johnny talk about the Delaware a little bit.

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

Yeah, Irene. We ended our drilling program out there basically at under $7.5 million a well and those include a little bit of a step up in frac design. So we were very happy with sort of where we ended the program. And that was, gosh, (40:33) I guess in the third quarter of the year. And so it's been some time since we drilled out there, it seems like. But we were very pleased with the trajectory of our cost and very confident that we could continue to drive those costs down in the Delaware. And so does that apply to your question?

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

Yeah. I'll tell you what, I'm going to kick that to Chuck. Irene, are you talking about cash flow breakeven, cash...?

Irene Oiyin Haas - Wunderlich Securities, Inc.

Yes. Cash flow. But one more question on the drilling costs, what lateral lengths are we talking about? And then we can go back to maybe cash breakeven question, yeah?

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

For those I gave you was one section, one-mile wells.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Okay.

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

And so – but we do and we will drill some longer wells here in the future. We're very confident that we'll see those cost savings carry forward.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Great. Thanks. And the cash breakeven?

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

Yeah. Chuck's, trying to get you the (41:40) number.

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

The cash breakeven, if you just kind of fix gas cost and natural gas liquids cost in our models as it was disclosed in the press release, the cash breakeven is approximately about $26 and some change. About $26.

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

Hear that, Irene, Chuck said $26.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Okay. That's fair. Great. Thank you.

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

Thank you, Irene.

Operator

Our next question is from Jeanine Wai from Citigroup. Please go ahead.

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

Hi. Good morning, everyone.

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

Good morning, Jeanine.

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

I just wanted to make sure I heard everything right, for the returns that you mentioned in your prepared remarks on 7,500 foot laterals being in the low 20%s. Was that on a full D&C cost?

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

Yes.

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

Okay.

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

Our drill and complete cost range of $6 million to $6.5 million.

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

And then what are the IRRs of the DUCs that you're drilling right now at $36?

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

Oh, gosh. Those are going to be up into the 40%s, up into the 40% range.

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

Okay. And then just the other question was, I think when you guys were talking the IRRs you mentioned, the Wolfcamp A and the Lower Spraberry.

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

Yeah.

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

And I was just wondering about the Wolfcamp B and how many of the 46 DUCs that you are utilizing this year in the Wolfcamp B?

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

How many are in the B?

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

I don't recall, James. Right off there is very – it's not a lot.

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

Jeanine, it's very few. I don't remember that exact number of Bs. It's mainly going to be As and Lower Spraberrys. And I'm looking now for a B number for you just a minute. So the B would be high teens, 7,500-foot lateral.

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

Okay. High teens.

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

Low 20%s on a 10,000 foot (43:42). So it's good. I mean, it's not something that we would drill right now and I think if we put three rigs back to work later in the year, the reason I gave the returns on the Wolfcamp A and the Lower Spraberrys, I think we'd stay with Wolfcamp A and Lower Spraberry because they've got higher returns.

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

Okay. That's great. And then on the updated Glasscock Wolfcamp A/B type curve and the new oil cut of 52%, can you just talk about how the GOR changes over time. Does it mostly happen within the first two to five years or kind of what – just talk a little bit more about the new oil number?

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

Sure. You're correct that we're going to start out in the – typically we're going to start out in the 70% range plus 75% range. And over the three-year period we're going to see that settle down. And in case of the As, we'll see it settle down into the middle 50% oil rates or GOR rates. So I should say oil cut rate. So it happens over the first few years of the well with the way we currently project it.

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

Yeah. And Jeanine, to be sure, it doesn't happen in the third year, it gets there quicker than that. It's moving pretty fast towards it in first 18 months.

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

Okay. Great. That's really helpful. And then if I could sneak one more in. In the prepared remarks you mentioned that you have other assets that you are also open to sell. I am assuming you're talking about the Central Basin Platform. So just kind of wondering, why that wasn't on the original list of asset sales that you had released and is it partly because you want to be a more Permian-focused player and that's why you'd rather sell the San Juan or you have other plans for it. Because I don't think that I've seen a lot of CapEx allocated to that recently?

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

Yeah. Well, let me kind of step back a minute and give you our total thinking. So the San Juan doesn't make sense to keep in the portfolio, it's now primarily a gas asset, we didn't get the results we wanted in the Mancos that would cause it to compete with Midland and Delaware. So obviously it makes sense to get rid of it. And then right now, acreage prices are pretty good for even – for Delaware assets right now. So we've got some areas that we're not going to get to where we think there's some good potential that we might be able to get a very good price for.

Now, as it relates to the Central Basin Platform, that's primarily a PDP asset. So we're just highly sensitive to the products of oil. So when I say for the right value, if we've got somebody who is willing to bet that oil is going to go north in a big way after a year that's an asset that you could consider selling. My preference would be on that asset, if we have to go there is we wait a little bit for a rebound because that one is much more highly sensitive to oil prices than acreage is right now. Does that make sense?

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

Yeah. Absolutely. All right. That's all from me. Thank you.

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

Okay. Thanks, Jeanine.

Operator

Our next question is from Jeb Bachmann from Scotia Howard Weil. Please go ahead.

Jeb Bachmann - Scotia Capital (USA), Inc.

Good morning everybody. James just a quick question for me on the acreage value that you had mentioned in the eastern Delaware. Just wondering, what you guys – or if you have a range, for kind of what you were building into that $400 million, is it somewhere in the 5 to 10 an acre or is it above that at this point?

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

Jeb, as you might expect, since we we've got active processes going on right now. I don't want to say anything about what we're expecting because I don't want to impact that process.

Jeb Bachmann - Scotia Capital (USA), Inc.

Okay. I guess, another way to put it, is the Delaware the majority of that $400 million?

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

It would be, yes. It would be, I mean, we're not expecting San Juan to go at $400 million.

Jeb Bachmann - Scotia Capital (USA), Inc.

Right.

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

So the Delaware is the bigger piece of the pot. We're not telling you exactly how much.

Jeb Bachmann - Scotia Capital (USA), Inc.

All right. I appreciate it, James.

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

Yeah. Thanks, Jeb.

Operator

Our next question is from Gail Nicholson from KLR Group. Please go ahead.

Gail Nicholson - KLR Group LLC

Good morning everyone. Just thinking about the potential of rigs going back to work in the second half of 2016 and talking about probably going after the Wolfcamp A and the Lower Spraberry. Would those be on two well pads or those would be single wells?

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

Well, they will be multi-well pads. It's just according to how we want to, we see developing the formations where they are. They'll probably be more than two-well pads.

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

Well, the pad will be set up to drill everything else. But you are right, when you say we might just – we'll just do two wells on the pad at that particular point in time, it will be set up for more than that, but we may very well do Lower Spraberry and A at the same time. Or we may have some areas where we can just do an isolated A or an isolated Lower Spraberry.

Julie S. Ryland - Vice President-Investor Relations

Are – pads are basically a landing strip concept.

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

Right.

Julie S. Ryland - Vice President-Investor Relations

Are they not running? Maybe you can talk about that a minute?

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

Well, we have gone to, where we can, more of a landing strip concept to get more stagger and more chevron-ing in the wells and we it also views as more latitude as we look at in certain areas where we want to add the Spraberry or a different formation then we have more latitude and more room to do that. But we do pre-plan all these potential wells that we're going to put on the pad at a very early stage. So when we go back, we don't have to interrupt production or laying of lines and that kind of thing.

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

But you were right with your first statement, I'm sure there'll be some where we've got an A and a Lower right close to each other and then there maybe some cases where we're drilling one-off, isolated, it just depends on where we go.

Gail Nicholson - KLR Group LLC

Okay, great. And then thinking, if three rigs start at the beginning of the second half of 2016 and you drill those through December 31, 2016, kind of a backlog at year-end 2016 is like 20 plus wells, is that a kind of fair expectation of you could be going into 2017 assuming on July 1, you just have three rigs start drilling again?

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

Just one minute. I mean, that's what we have (50:00). I think we would have about 30 DUCs, it could be about 30 wells. Can you hear me?

Gail Nicholson - KLR Group LLC

Yes, I can. Great. Thank you so much.

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

Okay.

Operator

As there are no further questions at this time, I would like to turn it back over to Mr. McManus for closing remarks.

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

Thank you again for joining us today. Again, challenging time, but I really do feel good about Energen's ability to keep moving forward. We'll continue to carefully monitor our balance sheet as we position ourselves to resume drilling, what I think is a very high quality asset base in the Midland and Delaware Basin. Thank you.

Operator

Thank you. This does conclude today's conference. Thank you, you may disconnect your lines at this time.

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