David W. Copeland - Secretary, Executive VP & General Counsel Javan D. Ottoson - President, CEO, COO, Director & Executive VP A. Wade Pursell - Chief Financial Officer & Executive Vice President.

David R. Tameron - Wells Fargo Securities LLC Welles W. Fitzpatrick - Johnson Rice & Co. LLC Subash Chandra - Guggenheim Securities LLC Michael Anthony Hall - Heikkinen Energy Advisors Mike Kelly - Seaport Global Securities LLC Pearce Wheless Hammond - Simmons & Company International Jeb E.

Bachmann - Scotia Howard Weil Paul Grigel - Macquarie Capital (USA), Inc. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc. James A. Spicer - Wells Fargo Securities LLC Michael Scialla - Stifel, Nicolaus & Co., Inc..

Good day, ladies and gentlemen, and welcome to the SM Energy Third Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, there will be a question-and-answer session and instructions will follow at that time. As a reminder, today's call is being recorded.

I would now like to turn the conference over to David Copeland, General Counsel. Sir, you may now begin..

Thank you, Shannon. Good morning to all joining us by phone and online for SM Energy Company's third quarter 2015 earnings conference call and operations update. Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance.

These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday, the presentation posted to our website for this call, and the Risk Factors section of our Form 10-K that was filed earlier this year and our Form 10-Q filed earlier this morning.

We will discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday.

Company officials on the call this morning are Jay Ottoson, President and Chief Executive Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; and Jennifer Samuels, Senior Director of Investor Relations; and myself, Executive Vice President and General Counsel. I'll now turn the call over to Jay..

Thank you, David, and good morning. Thanks to everyone for joining us this morning.

Look, I know it's easy to be gloomy and really short-term focused right now because of all the volatility in commodity prices and the low level of commodity prices; but if you're going to be in a ship in a storm, SM Energy is not a bad ship to be on and we're actually really excited about some of the improvements we're making in our business, which we think are going to have long-lasting positive impacts for shareholders.

We did have another solid quarter. Our focus on operational execution and intelligently applying technology is having a super positive impact on our cost structure and improving our well results.

Those improved well results are driving corporate level performance and we're convinced that they'll also result in increased drilling inventory over the longer term. Our balance sheet is simple and strong. Our leverage projections for year-end have been improving.

We have ample liquidity and we have a sustainable operating plan at low commodity prices. This morning, Wade's going to discuss our quarter results and update you on where we stand against our plan for 2015, and then I'd like to spend a few minutes highlighting some of our efficiency gains and updating you on our inventory expansion efforts.

Wade?.

Thanks, Jay. Good morning. So excellent third quarter results were again an outcome of our strong operational execution. We continue to see improved well performance and positive results from pilot test wells in our quarterly production. We're focused on what is within our control and on optimizing returns in this environment.

I hope most of the detail you need is provided in the 10-Q, the earnings release, and this slide presentation. Of note, we added a new schedule in the appendix of this presentation that provides more detail by area on wells drilled, fully completions and drilled and incomplete inventory.

It was a pretty straight-forward quarter but I'll add a little color on a few items, starting on slide four. Production for the quarter was 16.1 MMBOE or 174.5 MBOE per day. Production was up sequentially as adjusted for the second quarter asset sales, while we had forecasted a 2% to 3% decline from that level.

Production was up despite a higher than forecast 11% decline from our non-op Eagle Ford. Our operating production beat was largely driven by continued well performance plus the contribution from Eagle Ford pilot test #1 and #3.

14-Well test #1 reached peak rates during the quarter and pilot well test #3 initiated production with some good preliminary rates. In turn, the location of these test wells drove a higher component of natural gas and the production mix for the quarter.

As a result of strong production year-to-date, we have raised our annual production guidance to 63.6 MMBOE to 64.4 MMBOE. And that's up over a (one) MMBOE at the midpoint.

This implies a step-down in the fourth quarter production that reflects the faster declines at non-operated assets as well as the conclusion of completion activities across our operated Eagle Ford program.

In terms of commodity mix, going forward we'll likely utilize the capital from the slowdown in the non-op Eagle Ford to increase activity in the Permian and/or Williston Basins. This should actually result in more oil volumes once we get beyond the time associated with redeployment of this capital.

LOE for the quarter was $3.86 per BOE, which was right in line with guidance. LOE is down 16% year-over-year as we continue to focus on operating efficiencies. Sequentially, LOE per BOE increased due to planned work-overs in the quarter and the sale of low cost Mid-Con production, and we saw significant increase in our Eagle Ford non-op costs.

LOE guidance remains unchanged, with a midpoint of $3.80 per BOE. G&A expenses were $37.8 million or $32.4 million before noncash comp charges. We remain on track with internal expectations and G&A guidance remains unchanged as well. As discussed last quarter, DD&A increased as expected.

There are a number of moving pieces that affect reserves and therefore DD&A at year-end. Guidance for the year remains unchanged at $13.75 to $14.25 per BOE. On the income tax line, we booked a tax benefit related to the Mid-Con sale of about $4 million.

As we are currently experiencing a book loss, this benefit increased our effective tax rate, which is reflected in full year guidance as a smaller increase to 39.4% to 40.6%. Regarding hedges, on slide 5. We benefited in the third quarter from the propane and butane hedges added earlier this year.

NGL realizations had a $0.94 per barrel uplift from those. During the third quarter we added natural gas hedges. Details are in the IR presentation if you want to look at those.

While we did not have our operating plans set forth for 2016, generally assuming an exit rate production for 2016, we have hedges in place for about 30% of our oil, 50% of our natural gas, and 50% of NGL production, which feels like a pretty good place to be in a current strip environment. Looking at slide 6, CapEx activity is on schedule.

Our guidance remains just under $1.3 billion. We spent $277 million in the third quarter and spent $1.1 billion through the first nine months of this year. Currently we have seven rigs running. We have concluded completion operations in the Eagle Ford for 2015 and had one frac crew in the Three Forks/Bakken.

Our total DUC count is now estimated to increase by 80 wells during 2015 and that's up from a 70 well increase estimated last quarter. This is clear evidence of the improvements we are seeing in drilling efficiencies. Jay will discuss more on that in a few minutes.

In order to get ahead of winter weather in North Dakota, we may initiate completions of our DUC inventory before the end of the year. Switching to the balance sheet on slide 7, we remain in the top tier among peers in terms of debt to EBITDAX at 1.9 times, as of the end of the third quarter. Fourth quarter we expect to spend less than EBITDAX.

As well, we expect to close a small asset sale of non-core Permian properties for about $26 million. So we're now forecasting to end 2015 at around 2.2 times debt to trailing 12-month EBITDAX, which is better than the 2.3 times we expected last quarter.

We're very focused on keeping our debt metrics in line, particularly in preparation for a potential lower for longer price environment. As we've discussed, our plan for 2016 is to align CapEx with EBITDAX and maintain debt metrics near current levels going forward. I'll briefly summarize the already announced bank redetermination.

Commitments on our revolver will remain unchanged at $1.5 billion. The borrowing base was reduced to $2 billion from $2.4 billion, largely due to the adjustment from the midyear Mid-Con asset sale for $324 million. So we've ample liquidity, with only $184 million drawn as of the end of the third quarter.

So with that, I'll turn the call back over to Jay to discuss more detail on operations and execution.

Jay?.

Thank you, Wade. So I'm now on slide number eight. As Wade mentioned, we're seeing tangible evidence of our improving drilling efficiency in our DUC well count. We're also making great progress in making better wells through optimizing our landing zones within the reservoir intervals we're pursuing and optimizing completions in those zones.

Our core development assets all have either thick pay or multi-pay opportunities which are particularly amenable to disciplined exploitation through technology application and repetition. I'd just like to review some of our results so far this year for you.

So let's start with our operated Eagle Ford programs, our biggest program in the company, and details are on slide nine.

On average, we're drilling about 14% faster per foot of measured depth on these wells than we were a year ago, which if you think about it is really a remarkable year-over-year improvement given the maturity of our program in that area.

We actually apply a lot of techniques from Lean Sigma manufacturing in our drilling efforts there and it really has been paying off for us in reducing variability and improving time to depth. Total drilling cost per lateral foot is now down almost 30% versus cost a year ago. Our completion efficiency and costs are also showing dramatic improvements.

Total completion costs per lateral foot are now down 54% for total completions from our 2014 average. Overall, our drilling and completion costs per lateral foot in the operated Eagle Ford are down 46% plus from levels of a year ago.

And we've talked a lot about how our wells in the Eagle Ford are getting better as well and I'm going to show you some more details on that here in just a minute. Turning to the Bakken/Three Forks operating area. We again continue to make progress on drilling our wells much more quickly.

Our drilling days now for a two-mile lateral well are down 11% from 2014. And you can see how that number has declined steadily over the past several years in both our deeper and shallower well areas. We've recently drilled several wells in the Divide County area right around – actually a little under 10 days, total depth.

Our total drilling cost per foot is down 22% in the Bakken/Three Forks areas and we expect those numbers to go even lower as we renew our current rig contracts at lower day rates in the first quarter of 2016.

On the completion side in the Bakken we have moved solidly into the camp of doing cemented plug perf type completions now and we're getting really good at it. Combined with alternating zipper jobs on multi-pad wells, we've increased the number of stages we can pump in a day by a pretty staggering percentage over the last year.

Overall, our completion costs in the Bakken/Three Forks are down by a little less than 50% year-over-year. And we think about 60% of that saving is really just due to our improvements in pumping efficiency. So we think we can keep that even if prices go up. We're making better wells in the Bakken/Three Forks as well.

I've shown the next slide, slide 12 before, but here's an update on how our newest Three Forks completions in Divide County are performing, versus our older sliding sleeve completions. Fortunately, we have a lot of inventory remaining in front of us on which to apply our newer and improved completion techniques.

Turning to the Permian, we're looking forward to getting back to drilling in our Sweetie Peck asset there now that we've gotten our activity levels adjusted down to our cash flows. Although I don't have an updated cost story here yet because we've been inactive for a few months, we are bidding and we certainly see costs coming way down.

Starting on slide 13, I think you should see how good our stuff there really is, and how we've accomplished that. Most of the wells we've drilled to date are Wolfcamp "B" wells, although we have a proven good Lower Spraberry interval with terrific economics and have yet to test several other highly prospective zones as well.

We have a middle Spraberry well there right now drilled but not completed. If you just look at the Wolfcamp "B", however, it is very clear that our disciplined completion testing program has produced great results. We are doing a lot of detailed petrophysical work on all our plays.

And we're focusing a lot of attention on exactly where in the reservoir we land our wells in order to achieve the best performance, maximize recovery and stack more wells into each spacing unit. What we found in the Wolfcamp "B" is that landing zone has a big impact on penetration rate in drilling and in well performance.

And that combined with high sand loading, largely slick water completions, we've been making some really big wells. In fact, if you turn to slide 14, you'll see that we're making some great wells compared to anybody in the basin on an initial rate basis, and I'll say that our longer term production performance is hanging right in there as well.

Again, this asset has some great geologic characteristics that certainly help us here but our folks have done a good job in maximizing the rock's deliverability. Okay. Switching gears here for a minute, I just want to update you on our inventory ad testing.

We don't have a lot of new test results this quarter, as we're waiting on wells to clean up and to get enough production time to make a valid (14:39) judgment on those. Typically our gassier wells tend to clean up a lot faster so we get data earlier and are able to discuss it quicker.

Our oilier stuff, say in the northern Eagle Ford and some of the Bakken wells we're drilling, are going to take a little more time because it takes longer for oily wells to clean up. But I wanted to show you specifically how our previously announced results are holding up first.

So if you go to slide 15, which shows our planned Eagle Ford pilot testing.

The only update I want to give you on this slide is that our planned 12-well pilot #5 in the north area which we currently – we've been completing and are turning to production, ended up turning into an 11-well pilot instead of a 12-well pilot a few weeks ago when we found a casing problem in one of our outside wells and could not complete it.

As I said, that well, fortunately, was an end well in our stack stagger pattern. Shouldn't have a material impact on our pilot results and obviously disappointing but really won't have much of an impact on the final conclusions that we need to make. So we changed that, it's now an 11-well pilot.

So we've got those wells completed and we'll have results on them in a few months. Our results from our 450 foot well spacing pilot #1, which we've talked about before, continue to look really good.

I'm going to skip to slide 18 which shows the latest flowing pressure data, plotted versus cum production, which is the plot that I care the most about here because it really tells you the strength of the well, and you can see interference on this plot if there is any.

But we're not seeing any interference between these wells that are at tighter spacing than we've drilled before in this area. And this is right in the center of the eastern portion of our acreage, a great acreage position.

As we've indicated earlier, if you just take 450-foot offsets versus what we've said across our entire Eagle Ford position, that would be about a 25% uptick in well inventory across our whole position. So very encouraging results here, continue to look good. And what it tells you is we're going to at least be going to 450s in this area of the play.

Our next Eagle Ford test that I think we'll be able to talk about is pilot #3. And again, this is in a southern, kind of gassy area of the play. These wells clean up quickly. That's why I'm confident we'll have early results here. It's shown in cross-section on slide 19. A really interesting test.

It's a five-well pilot, as I said drilled fairly far south on our acreage. So, it's a high gas area. It is a test of 312-foot direct offset spacing with landing zones staggered between the Lower and Upper Eagle Ford. And you can see the exact facies that we're landing there.

There's seven facies in the Eagle Ford in that area and we're basically landing them between facies two and three and facies six and seven. Now we don't have an update of cleaned up production yet to show you but I can tell you the pressures on the wells all look good.

The Uppers look as good as the Lowers, and the wells are making more than 10 million a day each in terms of gas rate. So a lot of gas being produced here early on.

I'm excited about the test because I think if it works well, this is going to have very positive implications again for future inventory on at least that south and eastern portion of our acreage, which is of course, again some of the most valuable acreage in our operating position. So we'll have data on that pretty soon here.

We're tubing those wells up. And I think we're pretty encouraged so far with what we've seen. Still very early. Another quick update for you on slide 20 on our Bakken testing in Divide County, North Dakota. Our first nine wells, that we've already discussed, continue to perform very well, outperforming our Three Forks side curve for the area.

We do have two more wells drilled farther south. One of those is completed and flowing back, and the other is completing. Should have more results there again this year in a couple months. It takes a while to clean these up. So before I close, I'd just like to make a couple comments about where we're going over the next few quarters.

In general our rig count is about where it's going to be for a while. Although we will be shifting activity toward the Permian and Bakken, taking advantage of the slowdown, frankly in the non-op Eagle Ford to shift capital toward the Permian and Bakken to take advantage of our better oily economics there.

We're going to be completing our DUC wells, as Wade indicated. We're probably going to start on our Bakken completions in the fourth quarter. It won't have a big capital impact, because again, the non-op is slowing down.

But we're going to try to get some of those done in North Dakota before we get into the really cold weather portion of the year of 2016.

Again I don't foresee any material impact on our overall investment level in 2015 to do that because our non-op activity is going below our original capital spending forecast, but it'll have a positive impact on oil rate early in the year and certainly the most economic thing in our portfolio right now is to complete those DUC wells.

In the current price environment trading dollars from the non-op to our operated oily assets is a net positive. So as we move into 2016, actually slowing down the non-op and picking up oily activity on our operated acreage is a good thing. We'll continue to take advantage of every opportunity we have to reduce cost and improve our well performance.

And of course, we'll keep you posted on our inventory situation as that evolves. All right, we know you're busy today, so I'm going to wrap up by just saying, hey, we had another strong quarter. Our balance sheet is in good shape and we have a lot of liquidity.

Our focus as we go forward is going to be on maximizing cash flow while limiting increases in our leverage, as Wade indicated, and we'll do that by focusing on completing our very best return projects. We are excited about the fact that we can continue to build inventory here even at the bottom of the cycle.

With that, I'll open the floor for questions..

Our first question comes from David Tameron with Wells Fargo. You may begin..

Morning..

Hey, Dave..

Hey. So if I look at this, I was just looking at that slide you provided. And tanks for that. Slide 27, where it's got the DUCs versus, it's got the full completion schedule. And where I'm going with this is just obviously everyone's focused on what your production mix is, quote unquote.

And it looks like there's a higher percentage of DUCs that are more oily if you will, than what you've got on the Eagle Ford. So if I just think about the next couple quarters and then think about 2016, it feels like you have to get oilier.

Can you talk about that at all? You don't have to get oilier but it feels like your mix is going to get a little bit more oilier going forward.

Could you talk about that and put any guideposts around that at all?.

Sure, Dave. No question. If you look right now and you say, okay, what's the most economic thing to do in our portfolio, going to complete those DUCs is it. And we're going to be aggressive in going after those. Specifically, most of those DUCs are in the Bakken, where we had rig contracts this year that were expiring.

So we've compiled up a whole bunch of Bakken DUCs there. So we're going to start completing those. I think we'll be starting in December some time to complete those wells. We're going to try to get a few of them done before the winter weather.

Depending on how the winter looks we'll work through the winter or we might take a break in January sometime when it gets cold. But we're going to start those DUC completions during the fourth quarter. You know, we have always – I want to back up a little bit. We have always said that our mix in 2016 would look very similar to 2015.

So we sold some gassy assets in 2015. So clearly we were anticipating the fact that as you kind of balance this out, the Eagle Ford's a big operating part of our business, that the mix would get slightly gassier in the early part here as we made this transition toward picking up Permian rigs and completing the DUCs.

We've always, our budget, frankly our oil rates this quarter, were very close to our budgeted levels. We just made a lot more gas than we expected to.

I think we will be down a little bit and then we start coming back up and as we start to grow toward the back half of 2016 a lot of that growth is going to be oily growth as we complete Permian wells and we get our DUCs completed, and our Bakken activity is basically going to be flattish, two rig kind of program for the year.

So what we see here happening is that we do get oilier throughout the year of 2016..

Okay. No, I appreciate that. And then one follow-up on the Eagle Ford. Just based on these tests, or can you talk about if you have say, three rigs going into 2016 or whatever number, three to four rigs.

Based on these tests, do you need more data from these tests before you start drilling everything on 450s feet or how are you thinking about the development plan for the next, call it two to three quarters?.

You know, I think in that eastern area we're going toward 450s feet. That's where we're going. We still have a number of pilot wells to be drilled there.

We've got some down spacing wells to drill or infill wells to drill and we have a number of pilots to complete, that when we move toward this development in that area, I'm pretty sure we'll be at 450s feet if not tighter. Frankly, I'm really excited about where this 312 foot offset test goes.

And pilot #2 if you remember, is the infill test, which we have yet to have results there. So that's again, the very best geology and the play is that eastern area, and it looks to us like it's going to get tighter. So that's a good thing. I think we'll probably be at about three rigs in the Eagle Ford for most of next year.

And a lot of that activity will be getting these pilots drilled and moving forward, starting to move forward on what happens from the results of those. So if you look at rig count, we're at seven rigs. I think in general if you're thinking three rigs in the Eagle Ford, two rigs in the Bakken.

We're going to start out at one rig in the Permian, I think we'll maybe at two within a quarter or so. So that kind of seven rig number. We're going to be transitioning our rig out of the Powder River Basin early in the year. And again, I think that activity will end up in the Permian.

So it'll be a kind of three rig Eagle Ford, four rig oily kind of program for most of next year..

Okay. I'll let somebody else jump on. That's helpful. Thanks, Jay..

Thank you. Our next question is from Welles Fitzpatrick with Johnson Rice. You may begin..

Hey. Good morning..

Good morning..

Two quick ones on the Eagle Ford. One, just for my own clarification.

You guys, are you guys downshifting the operated Eagle Ford or is that just really the non-op that's allowing you to put a little bit more capital toward the Permian and the Bakken?.

Well we've said, and I said yesterday we're going to go from four rigs to three rigs at the beginning of the year in the Eagle Ford. That's our current plan there. We only need to run about a 2.5-rig program I think to hold all the acreage and meet all our commitments there. So, about a three-rig program.

And just to balance the capital out, in order to put the rigs in the Permian that we want and with the fact that we'll let the non op Eagle Ford is coming down, most of the caps are actually coming from there. That's how it will balance out, about a three rig.

We'll probably have four rigs sometime maybe in the Eagle Ford during the year, but three rigs there and four rigs in the oilier stuff during 2016..

Okay. Perfect. And just one more.

The 25% bump in location count that you guys talk about with 450-feet spacing, does that include infill drilling, like in test #2? Or is that just on relatively undrilled acreage?.

That's just on undeveloped. I should always say that when I quote that number. The 25% uptick is just taking what we had currently had planned to drill at 650 foot, or 625 foot and 550 foot, taking those areas to 450 foot.

And again, we still need to prove that in the northern area, but I'm pretty comfortable with that kind of spacing right now in the east, and again very encouraged about where this 312-foot offset testing might go as you stack stagger.

I think what's really notable, as I said earlier, that the Upper Eagle Ford wells in that new pilot look as good as the Lowers. So, really encouraged by that result..

That's perfect. Thanks so much..

Thank you. Our next question comes from Subash Chandra with Guggenheim Securities. You may begin..

Hey, Jay. I'm just trying to think about the map here on infills.

So when I see the 420-acre infills and possibly – foot, I'm sorry, possibly going to 300 and change, so that implies somewhere, 10 plus, maybe up to 10 to 14 wells per 640, just on the simple math there? But then when I look at the anticipated gas EURs out in the east, I believe that curve was six or seven Bs.

And just tell me where I'm wrong here, but if I think about the type of total gas that you're expecting to recover on your 10 to 15 wells at six to seven Bs, it would be an exceptionally high recovery factor of gas in place? If I'm thinking of gas in place correctly, around 150 Bs per section, but – so I threw those numbers out there.

Please correct me on where I'm not dotting my Is and Ts..

I don't know what you're using for, if the in-place numbers is the problem. We think we can get to 50% type recoveries in that area, in a gassy area. So I don't know what you're using for in-place numbers..

Okay. So....

What we've seen here, say, the Woodford where we had a pretty gassy kind of bias there in that production. We, well in excess of 40% type recoveries in that area. In oilier areas of these plays, you're going to be more like 10% to 20% recoveries. And that's frankly why these wells are so productive.

You've just got a lot more throughput capacity inside the rock to be able to do this. So the gassy areas tend to get much higher recoveries. It's not as high as conventional numbers but they're pretty darn high relative to the oily parts of these reservoirs..

Okay.

So as we adjust our expectations for the west, we probably need to adjust that, say, from I think the numbers – so 40%, 50% type recovery factors, you would think up to 20% in the oilier parts of the play?.

Well, I think 10% to 20% is probably not an unreasonable number. And I will tell you the difference between 10% and 20% is a huge number. And a lot of that's going to depend on the success of these stack stagger tests.

I think the low numbers that you hear from a lot of people, if you go to Permian or some of these other plays, you're more like 4% to 8%. But again, we have a little more gas drive here so I think you're likely to get higher recoveries.

I think what we've come to the conclusion of, originally when we did the work in the Eagle Ford, we weren't sure the Upper Eagle Ford really had that much pay. It was really whether it was really reservoir or not. We know the porosities are lower. What we're finding out is it's actually productive.

So I think our general feeling is that the recoveries are going to be higher than we had originally anticipated in some of this rock, just going through this stack stagger completions..

Got it.

So you think throughout your Upper Eagle Ford there is a meaningful amount of self-sourcing taking place, rather than just migrative ...?.

Yeah, and I'll tell you why I think that. We are seeing in some of these areas, higher yields in the Upper than in the Lower, which would tell you that the maturity is probably lower in the Upper, I think, which would imply self-sourcing. Right.

So I think that all that tells you that that rock up top there, actually is a self-sourcing reservoir, did have – maybe didn't get heated quite as much but that it's not necessarily just a receptacle for Lower Eagle Ford production. It actually does self-source to some extent..

Got it. Okay. So then that's interesting. So we shouldn't then just assume that where you have dry gas Eagle Ford that you will have dry gas Upper Eagle Ford..

Well, I think in the dry gas section, that stuff's been heated up. It's not going to be materially different in terms of yield. But as you go north, I think there will be significant – and we have seen some tests where, at least on initial tests, you'll see significantly different yields between the Lower and the Upper. And the Upper is always higher.

So that's one of those wild cards as we go through this testing for the pilot testing program and start really completing a lot of wells in the very upper portions of the Eagle Ford, what's that yield going to be? Generally, it's going to be higher.

I don't know, again there's this balance between productivity and yield on the economics of these wells, that's really what we're testing here..

Right. Right.

But do you think an offsetting characteristic versus yield and productivity, or versus productivity Upper Eagle Ford is just that you might have a better reservoir rock interbedded with the source rock, so it's easier to produce?.

We know that some of the facies in the Upper are actually more brittle than the Lower and they frac easier, frankly, than the Lower does. Now the frac recipe might end up being little different in the Upper than it is in the Lower, so we may have to spend some time exactly getting that right, but we know the Upper Eagle Ford's productive.

And doing the foot by foot kind of work we do, petrophysical work, there's a lot of really good brittle rock up in that Eagle Ford. So we've seen that Upper Eagle Ford wells that are every bit as productive as Lowers.

And there's a tradeoff, I think between, the porosity is a little lower up there so the storage may be a little lower, but you may be able to make better completion. So at the end of the day what we're seeing, so far at least, is that the Uppers and the Lowers look about the same in terms of projected EURs.

And so there's kind of a tradeoff there, I think between fracability, I'll call it, real technical term and storage that actually makes the well work out about the same. But I do think in general, the yields in the Upper are going to be higher..

Okay. And the final one for me on your lateral targeting.

Is it specifically sort of the less shaley intervals of the Wolfcamp "B" that you you're targeting?.

Well, it's the more brittle rock. It's really a mechanical properties issue. And there's probably, three different landing zones, I think that we've targeted within the Wolfcamp "B". Turns out that the lower one and the upper one perform better than the middle one. And that's probably as far into the technical details as I can get on that..

Okay. Good. Terrific. Thank you..

You bet..

Thank you. Our next question is from Michael Hall with Heikkinen Energy. You may begin..

Thanks. Good morning..

Good morning..

Just wanted to talk a little bit more about, I guess the DUC inventory and how you're thinking about the pace of pulling that down in the various areas in 2016. In the Eagle Ford you've got 64 DUC, 47 DUC in the Williston.

Are you going to pull those down at a similar pace? Or will you have a regional bias early on with the Williston and then the Eagle Ford is later in the year?.

Generally the pace is going to be faster in the Bakken. We're going to go after the oily ones early. The Eagle Ford, we always have a higher level of drilled but not completed wells there anyway and that'll be pretty steady through the year, but right now the most economic thing in our portfolio is to go complete Bakken DUC wells.

And we're going to do that starting here right at the end of the year and try to get a few of them done before the weather turns bad and if the weather doesn't turn bad we'll just keep right on going. So I think we'll probably have most of our Bakken DUCs completed by mid-year..

Okay.

And then in Permian, similar story?.

Permian, again, a very similar situation. As we pick up the rig in January we're going to immediately start completing DUC wells and that'll be a very – we'll get those done, I would think, in the quarter, the first quarter..

Okay..

And then we'll be completing basically along with our drilling program. And I'm really thinking that the way this could work out is we end up picking up a second Permian rig, maybe second quarter.

Just want to get – we want to start these rigs up one at a time and kind of get our feet under us there, but I think you could have higher activity levels in the Permian by the time we get into the second half..

Okay.

And how should we think about, given the rig count numbers you provided, three rigs in the Eagle Ford, two in the Bakken, one to two in the Permian, what's kind of a normal backlog relative to those rig counts, would you say?.

Well, we were pretty normal coming into this year with where we were. I mean we really didn't start building DUCs intentionally until the beginning of this year.

So if you look at look at that DUC count at the beginning of that slide – which by the way those numbers changed a little bit just because we decided to track pad wells versus individual wells a little differently. But that count we had at the beginning of the year, which I think we count now as 60 DUC.

Is that right, Wade? 60 DUC coming in the year? It was 40 DUC, the way we used to count them..

That's about right..

Yeah. So that level is a pretty normal level for us and most of that is Eagle Ford, but that's pretty much where we would expect to end the year, in 2016..

Okay. Got it. And as you kind of look at oil volumes in 2016 you had a small sequential decline this quarter, seems like that probably happens again the fourth quarter, or potentially anyway.

So how long until you get, you think, the oil volumes back up to the 2Q level would you say?.

Well, again, when you start – we forecast overall our production is going down in the fourth quarter. We do have this big pile at the Eagle Ford coming on right now, so how much oil is generated by that in the fourth quarter is a little bit of a question.

In general, I think what you'll see is our production in general is going to decline for the next couple quarters and then start back up. A lot of what – when we start coming back up, a lot of that will be oily because we're completing the DUCs and then we're getting back into the Permian.

So when you get to the back half of 2016, our rate should be growing. A lot of that will be a little oilier than it is today. So again, year-over-year we think our mix on average is going to be about the same.

I would agree I think we're going to be at sort of this little lower oily level here percentage-wise for a couple quarters and then it's going to start back up as we get those wells completed..

Okay. That's helpful color. And then in the Williston, looking at the DUC net to gross and the net to gross in the year-to-date completions, a bit higher than I think your average working interest typically in the Divide County area. Do you expect – I'm assuming there's some non-consents going on there.

Do you expect that to continue? How should we think about that for 2016? Any indications from your offset partners on that?.

Well, there's sort of a special situation there in that one of our partners is having financial difficulties in Divide County, and so I don't know how to project exactly what they will do. Certainly we're prepared to accept their interest in these wells and that's what we've been doing.

To be clear, while we earn when we do that, is we pick up their interest up front and they get back in after like three times payout. I don't remember the exact number. So it's not like we earn their acreage, it's just – it's a well bore thing.

It works out economically for us because these are good wells and I feel sorry for them, but they may very well, if they get their act together, start coming back in and participating at some point. So we're not – we're doing our budgeting based on the idea that some of that will occur, but not maybe as much as this year..

Okay. That's helpful. And then last I guess on my end, I was just curious, can you run through kind of what the current AFEs are running in the Divide, McKenzie, Eagle Ford and Midland Basin area, just as we think about, I guess, where you're allocating capital for 2016? Just trying to make sure I've got the most real time costs there..

Well, AFEs in Divide County are – I've got – actually, I have some really cool numbers here. All right. So let's see, Divide County is $4.6 million. That's our current projected well costs..

Okay..

Yeah, and I would say – is that with or without?.

With..

That's with plug/perf, yeah. Some of that, I will say that $4.6 million assumes we renegotiate our rig contracts, which we're doing. So right now, I think our well cost is probably right at $5 million. We will be at $4.6 million here as soon as – and those rigs will get done here before the end of the year.

So Lower Spraberry type wells in the Permian, our current estimates there are about $7 million for a 7,500-foot lateral. I will say this, we pump big fracs here, a couple thousand pounds per foot, probably bigger than most people. We found at least in our Sweetie Peck area that that's very helpful. We would like to drill even longer.

If we could, we'd drill all 10,000-footers. I think we'll be able to do some of that there, but generally, if you're using $7 million, that's a pretty reasonable number we think for our current estimates. And we're not drilling right now. We're bidding rigs right now and picking those up.

And in the Eagle Ford East, our earliest well costs there are in the mid fives, $5.4 million for a 6,500-foot lateral. I mean, these numbers have come way down. So, very pleased with our cost performance in general..

Okay. Very good. Actually, one more if I might. In the DUCs in the Eagle Ford, do you know roughly how those are comprised, or like what the composition of that is relative to northeast, south? If not, I can follow up later..

Yeah. Well, most of those are in those pilots that you can see on that sheet. But if you look at those pilots and where they're located, you can pretty well figure it out..

Okay. Fair enough..

Most of those wells are drilled. It's just that they aren't all completed yet..

Got it. All right, thanks very much..

You bet..

Thank you. Our next question is from Mike Kelly with Seaport Global. You may begin..

Hey, guys, good morning..

Hey, Mike..

Hey, Jay. I was just hoping you could maybe kind of further frame and set expectations for all the tests that you're doing in the Eagle Ford. And I kind of think of it as three things going on, testing, spacing Upper Eagle Ford's viability and really what you're going to see from enhanced completions here.

And I'm curious on really how long you think it'll take before you can lay out to the market, what all this work should translate to in terms of kind of updated EURs, project returns and really an ultimate inventory number in the play.

And is this something that we should expect kind of being piecemealed out here over the next few quarters, or should we set a date for more of a comprehensive update? Thank you..

Well, I'll start with the last part first. I think you can probably expect it's going to get piecemealed over a few quarters. In a general sense, as I've mentioned earlier the gassy stuff is easier to get data on early because these wells come on pretty big early, they clean up fast.

You need about 90 days of really good stable production before you can forecast EURs and get a real sense of how effective that was. The oily side wells, typically between that time period again end up need an artificial lift. It takes longer to get results. And so the northern stuff in the earlier parts of the plays, it takes longer to get the data.

I recognize that's what everybody wants is that oily data, so do I. But it's just going to take us longer to get there. Inventory by itself this year is going to be an interesting thing. Obviously, when we did our estimates last year we did it based on the strip at the time, and the strip was fairly low.

Gas prices have moved a lot, here recently, and the strip has changed some. So when we redo inventory calculations there will be some ins and outs on that. So we will do an inventory update at year end, but it won't have all this data in it yet because we won't have it all. So I do think it will come out over a period of time.

Let me go to the first part of your question. What are we trying to accomplish here? Well first of all, every one of these pilots has multiple – it's kind of confusing even for me. Every one of these pilots has multiple objectives. We are testing improved completion designs in almost every one of these pilots in some way, shape or form.

Even in this pilot number one that we just showed, a couple of those wells had significant – had higher sand loadings. And I will tell you that those two higher sand loading wells are performing at the very top of our projected EUR distribution. We tested tighter stage spacing as well.

Those wells are also performing better than the – the best wells are the tighter stage spacing with the higher sand loading. So we're testing completion designs in every one of these things. And as I said, I think there is some opportunity in the Upper to fine tune our designs in the Upper to make those wells better as well.

So as we drill more of those wells, there'll be some opportunity to continue to get better there. Secondly, certainly just spacing in general. Density is an important thing. In pilot number one we were really focused on the Lower, just trying to figure out okay, with our newest completion designs which we know will keep our brass closer to wellbore.

How much closer can we put these wells without interference? And that's a real positive result. Then the next phase of that is okay. Now if we stagger these wells, Upper, Lower, Upper and we did 100 feet or 150 feet between the well walls vertically.

Can we put them even closer together? And I think that's where pilot number three comes in and it tells you, hey, 312 feet if these wells look good, and again too early to call, but at least the very early data, the Uppers and Lowers look a lot the same, the question will be, do we see interference here as we go out in time.

And that's the next big step on that. If the 312s foot work, that's a big uptick again in inventory. And then, of course, as you go into the northern pilots, you're literally again even thicker pay. Some wells literally stack on top of one another. The questions there are going to be in the Upper, we've landed in several difference facies.

Is one facies going to work better than another? Does the straight up stack? Do we see interference there? And again, those are oilier wells. They're going to be on artificial lift at some point during the test period. It's going to take longer to get data. That's just the nature of the beast. So, a lot of different things going on there.

I know it's complicated. It's a complicated asset, and an enormous amount of opportunity within that asset to optimize. Some of this stuff will probably not work. A lot of it we think will, and at the end of the day we're pretty confident we're going to end up with a significant growth in inventory..

Got it. Really appreciate that color. That's all I've got. Thank you..

Thank you. Our next question is from Pearce Hammond with Simmons. You may begin..

Good morning, Jay. Thanks for taking my questions..

You bet, Pearce..

Jay, previously you made the statement on 2016 that you thought you could grow production from exit rate 2015 to exit rate 2016, and that was keeping CapEx and EBITDAX aligned.

Is that still the case?.

Hey, Pearce. It's Wade. I'll take that first, and let Jay add anything he wants. I guess the first thing I would say is I think we still could. But obviously since we made that comment prices have fallen, especially natural gas. That comment, the growing production part at least, that is more of an outlet of our program.

As you know our priority is to maximize EBITDAX not production, and our capital plan is going to be very returns focused and returns based. So we're going to be working that hard over the next couple of months. And that's kind of where we are right now..

Great. Thank you for that color.

Then with the planned completions of some of these oily DUCs towards year-end 2015, will that result in some carryover CapEx into 2016? Or is that spending for completing the oily DUCs already in your 2015 capital budget?.

Yeah. It's not that much money, Pearce. And again, I don't anticipate seeing overspending, what we've already said. The non-op Eagle Ford is slowing down, frankly a little faster than they had originally told us. So I think there's some room capitalized to go ahead and get that done.

And that's not going to be that many wells, by the time we get it lined up and get going, you're talking about 8 or 10 wells we might get completed this year. On a net basis just not that much money..

Thank you, Jay. That's helpful. And then it looks like you layered on some real nice gas hedges during the quarter and in 2017 you've got some hedges above $4.

I was just curious how you got such attractive hedge pricing?.

Well, the hedges at $4 were done a while ago..

Right. We take advantage of the – we try to take advantage of contangoed strips when we can and those $4 prices are obviously from a year or two back but that's how we manage the program. We look out five years and try to layer in when we like the price..

Excellent. And last one for me. Jay, you had mentioned you had sold some non-core Permian, or Wade had mentioned that I think for $26 million, $28 million.

Can you tell us a little bit about that?.

Yeah. We sold our – that was that Borden County stuff that we had, the Mississippian play that we had played around with for a couple years. We sold that acreage for about that amount of money here recently. And our conclusion finally on that was that there wasn't significant shale potential and we just needed to get out of that..

Great. That's all for me. Thanks, guys..

Thank you. Our next question comes from Jeb Bachmann with Scotia Howard Weil. You may begin. Jeb Bachmann, your line is open. Please check your mute button..

Yeah. Sorry. Morning, everyone..

Hey, Jeb..

A couple quick ones from me, Jay. First on the Permian.

Can you tell us what technology you're using to better land laterals and kind of what that's doing to the cost there per well if anything?.

I'll answer the last part first. What we found is that the drillers never want to have a really tight landing zone because the argument is well, it costs more, you've got to work harder on directional.

What we found is that in general we're able to do it with very little incremental cost because we're – tools are good enough now and we're good enough to be able to do that.

The way we'd address landing zones is really we have taken a lot of core, we have done a lot of log core correlation and we're looking at this stuff foot by foot to look at what are the different facies in each of these different shales, which is not only true in the Permian, it's true in all these areas we're operating in.

And we really look the mechanical properties of the rock across that whole interval, the porosities across that whole interval, all the good geologic data we can collect. And we target then which of these things is going to have the highest penetration rate and the best brittleness, I'll call it, on frac. And there is some tradeoffs in that.

But in general in the Wolfcamp "B" there's about three different obvious landing zones there from top to bottom and what we found, and I think it's really interesting, is that if you're landing in the bottom or the top, you make – you have higher fee rates and better wells than if you land in the middle.

That is actually a really good thing from the standpoint of being able to push these wells in a stack stagger pattern closer together because you can land in the Lower portion and the Upper portion and kind of do a chevron pattern there.

So it's just been fascinating to me, and we just had our technical conference here a few weeks back, how much better we are getting at a lot of this stuff. And landing zone is really, really important.

It makes a lot of difference in the performance of the well if you land it in the best, the percentage that you put of that lateral in the right landing zone makes a huge difference in how these wells perform.

It's not something that I would have told you five years ago, because my assumption was that you kind of lay it in the middle and you get the whole thing, and that's really not true. And so that's one of the key findings I think we've had. It's not just us, the industry has over the last few years. And then P-rate makes a lot of difference here too.

I mean if you can get it in the right landing zone, your penetration rates are much higher and you're drilling a lot faster. So, a lot of things that go together here to make better wells..

Should we expect a down-spacing pilot test maybe in the Permian here in the next year?.

Well, we've actually done some. We've drilled down to 660 feet already in the Permian and what you'll start to see from us is more of a stack stagger chevron development in some of this.

Early on here in the first few wells we still have some non-pad wells we'll drill, but once we get the pad drilling you will start to see, I think when we pick up that second rig it will be when you probably start to see it. Some multi-well kind of pad development that would be sort of a staggered chevron type opportunity..

Okay. And then I guess the last one for me, just on the cost side.

Do you guys see another 5%, 10% coming out of service costs at this point or do you think that you've seen as much as you're really going to get at this point?.

Well, I think you'll see, if prices stay where they are you're going to see costs go down. No question. I don't know about percentages. But and you can look at, I think that plot, actually that we're showing there of our costs over the year is pretty instructive. Our third quarter costs are down from our average for the year still.

We see a lot of pressure per cost to go down if prices stay low. If prices don't stay low, I think you'll see costs come back up fairly quickly. One of the best indications we have of what the service companies are thinking is they're not real excited about signing contracts that are much longer than six months to a year right now.

Because I think they think things will get better. But in the near term I think costs are still on that downward trajectory unless prices change..

So I guess just this last one following on that.

Just based on your comments earlier and kind of the slide deck, it looks like the Bakken has the best chance of keeping costs lower than the Eagle Ford maybe because you're seeing more internal operational efficiencies in the Bakken, is that fair?.

No. I don't think that's fair. I think the issue with the Eagle Ford is we've been at a fairly high activity level for quite some time. We've driven, we are very efficient already there, so I guess from the standpoint of can we get better, faster in the Bakken, maybe there's a little more of that.

On the drilling side, we continue to make really good progress in the Eagle Ford. On the completion side, we've been doing plug/perfs, cement liner completions for a long time and we're really good at it. It's hard to see us pumping a lot more stages per day versus what we're already doing. We're already doing a pretty spectacular job.

So from that standpoint maybe you don't get a whole lot more efficient there.

If we do go to these, for example, if we go toward this pilot where we're literally drilling 12 wells in a half section, I think you could anticipate some cost efficiencies associated with a more intense pad drilling environment that could benefit us, but that's probably more than a year out for us right now because we're still in the pilot stage..

Great. I appreciate it, Jay..

Yeah..

Thank you. Our next question is from Paul Grigel with Macquarie. You may begin..

Hi. Good morning, Jay.

Just to follow-up on a point from earlier on, on the oil production in 2016 from exit rate to exit rate at current strip would it be fair to assume it's probably flat from exit rate to exit rate on the oil side with kind of a dip and then an increase in the back half of the year?.

Yeah, that's probably within the range of accuracy that we can call at this point. That's probably fair. You've got the non-op Eagle Ford coming down some clearly and you've got us shifting capital at least that capital plus a little more to the oily stuff.

I think it is going to be back-end weighted because of completion of the DUCs, but within the level of accuracy that we can predict things I think your characterization is probably fair..

Okay.

And then on the northern test in the Upper Eagle Ford when we look at where those wells are, are they all fully completed and flowing back at this time or are you just accumulating data? Could you just give a little bit of color on maybe where they stand if we're still waiting on completion just realizing ...?.

We just started our flow back, I mean literally within the last couple of weeks. It took a long time to get all the wells completed and so we're just getting the wells flowing back and I anticipate a significant period of time to get them cleaned up and really get them on a stable production.

So it's going to be a while before we have a lot of data there. We might be able to talk about what the rates are at some point here during this quarter, but in terms of actually making projections about which of the wells look best and how they all stack up against each other, it's going to be a little while..

And will that be the difference between 30-day results and 90-day results on how they're looking, versus making an actual call in?.

Thirty days on these. You barely get through clean up in 30 days. You know you've got to get the load off all these wells and there's a significant frac load that you've got to get through. And these wells don't produce $10 million a day like these southern gas wells. So it takes a while to get them cleaned up.

We'll do it as fast as we can, as prudently as we can, and we're not going to make any comments. I can tell you I'm not making any comment I have to eat later on any of these wells, okay. We're going to make sure that we know what we're talking about before we say anything. So it will be a while before you'll hear a lot of commentary on it..

Okay. And then one last quick one, just on the Bakken if you choose to plow through the cold and winter weather.

How much additional cost is that on a per-completion for each well to heat the water, et cetera?.

It would be $100,000 to $200,000 per frac. And that doesn't sound like that much money, but you're talking about fracs that cost $700,000. So it is a material amount of money.

So that's why we would love to – and I know the guys in Williston will love to hear me say this – we would love to avoid the really cold part of the weather and try to get some done early here and then maybe take a hiatus when the weather gets tough. And that's certainly our plan.

Our whole purpose of deferring a lot of this activity was to try to catch the lowest cost part of the cycle. So it makes sense to try to not complete them in the dead of the winter..

Okay. That's all I have. Thank you..

Thank you. Our next question comes from Matt Portillo with TPH. You may begin..

Good morning, guys..

Hey, Matt..

Just a quick question on the full year guidance, just wanted to make sure we're thinking about Q4 correctly. Jay, I think you previously talked about a couple percent quarterly decline in the back half of the year. So, just wanted to true that up with the Q4 numbers here.

And I think you mentioned essentially going on a pretty solid frac holiday across all of your assets. And I guess a second follow-up to that question. Just as we think about your corporate profile, how should we think about the PDP decline rate? Because it looks like the Q4 number might be mirroring that to some degree.

But just trying to get some context around that..

Hey, Matt. It's Wade. I'll take a stab at that first. Our fourth quarter production number, if you go back to last quarter and do that math that you just said, taking out the Mid-Con, going down 2% or 3% each quarter, the number for the fourth quarter is pretty much the same. We've chosen not to change that number.

We've raised the full year guidance based on the beat in the third quarter. And we're taking a cautious approach there. Activity has been reduced. The non-op Eagle Ford activity has certainly been reduced. So that's the approach we took to the fourth quarter guidance.

And what was your second question?.

Just as we think about your corporate profile, how should we think about PDP declines across your asset base?.

Well, this is Jay again. Our PDP decline, if you just stop doing everything, our PDP decline is in the high 30%s. And so whatever that gives you, and you see that, frankly, you see that in the non-op Eagle Ford too. When they stop drilling, it looks to us like they decline in the high 30%s. It's very consistent with an Eagle Ford type decline.

I think we have stopped completing – if you look at capital, and I think this is important for people to hear. We have an oddly low quarter in the fourth quarter because we're not completing a lot. We're going to start completing some DUCs toward the end of the quarter.

If you think about run rate in 2016 our capital's going to be in the $200 million to $250 million a quarter kind of range as we get back to kind of normal completions. We do have a number of wells we're bringing on that we have completed in the third quarter in the fourth quarter.

So I don't think people should assume that we're plummeting in the fourth quarter. As Wade said, what we've guided is exactly what we guided essentially for the fourth quarter before. There is some uncertainty associated with a lot of these new pilot wells we're bringing on and with what's going on in the non-op.

So we've chosen to be a little, hopefully, conservative about the fourth quarter..

Great. That's very helpful. And then if I can just squeeze in two additional questions.

On the corporate side of things, Jay, just was curious if you could comment and remind us again how you think about kind of the return profile on a well level basis? I know that you guys still have some of the details in there on the Bakken but as you think about kind of the Permian, Bakken and Eagle Ford, how are those stacking up today as you think about kind of strip pricing or kind of the commodity price environment you're looking at into 2016, and how that could potentially influence your decision making process around capital allocation?.

You bet. Well if you look at the slide deck, it's not in our current deck here today but it has been in the last couple of quarters, we show the internal rate of return numbers for the Permian, Bakken and Eagle Ford, Eagle Ford East, which is where most of our activity has been and will be.

And if you look at that, we basically are making 20% returns or a little higher than 20% returns on all of those assets at $50 oil. That was using $3 gas for the Eagle Ford East for the strip.

So if you look at it today, I would say clearly the highest economic thing we can do is go complete our DUCs, but if you exclude – if you look at new drilling today, the Bakken and Three Forks in Divide County and the stuff we're doing in the Permian have very similar economics.

They basically are 20% plus returns in a $50 world, okay? So we can make 15% returns at even lower and that's really – our corporate hurdle is 15%. We can make those returns at even lower prices, literally where we sit today at spot..

And cost coming down..

And costs, you know, obviously costs are continuing to come down. In the Eagle Ford East, again, we ran those numbers and had that kind of 20% return at $50. That was using a $3 strip. The strip, the gas price has obviously been hugely volatile and the strip's a little lower than that today.

So if we had to stack them out today, we would say, hey, the Midland, Bakken in Divide County look a little better, say, than our Eagle Ford stuff. Our Eagle Ford stuff still meets our – would meet our hurdles in the strip case and I think it looks strong.

But in general, the oilier stuff looks really – given where gas has been over the last few weeks, oilier stuff looks pretty strong right now. So in general, we're going to follow the course in terms of rig count that we described earlier today..

Great. And I'd just like to leave it on the Permian. You guys have had some great results there so far in the Wolfcamp "B".

Could you just remind us, as you head into 2016, some of the things your team is looking at in terms of additional zone delineation and kind of some of the opportunities that you either see based on your acreage and your results so far, or maybe some of the offset peers, just what's going on from an industry perspective? Trying to get a better sense of the resource there..

Well, I'll tell you, I think if you ask our folks right now, what are you going to drill in 2016? They'll tell you, they want to drill Lower Spraberry wells. Our Lower Spraberry stuff looks even better, actually has lower decline rates. Really good looking opportunities there on the early wells we've drilled.

I think, in general, most people in the industry, and it's certainly true for us, we want to go longer. We'd like to drill 10,000 foot laterals everywhere we possibly can. The economics look significantly stronger to us for long wells. Higher sand loadings, I think, in general, that's where people go.

We're probably on the high end of that, just our experience corporate-wide has been that high sand loadings are really leveraging. Slick water, I think almost everybody I talk to at least is going in that direction and I think that's something, we've always pumped a lot of slick water, but I think generally we lean that way.

In terms of additional intervals, as I said, we have a Middle Spraberry well drilled, but not completed. Be an interesting test, a lot of people will tell you that in the area that we're in, the Wolfcamp "D" is maybe even a better target than some of these others. We haven't tested that yet, so a lot of opportunity there in the "D".

So we've got hundreds. I just want to say, we have hundreds of wells to drill in the Midland Basin. I know the acreage position is not that huge, but it's in some of the very best rock. We got 1,250 feet, something like that, of total pay there. It's a great asset. A lot of wells to drill.

A lot of years of drilling in front of us and we're – one of the things about our portfolio I don't think people appreciate is we have a lot of optionality within this portfolio, to be able to shift here to the highest return thing and still maintain a program that's very sustainable in a period of low-commodity prices..

Thank you very much..

Thank you. Our next question is from James Spicer with Wells Fargo. You may begin..

Yeah. Good morning. Thanks for taking my question. I wanted to just revisit the maintenance capital question in the context of prices here. And just based on some of your responses in the Q&A here, it sounds like you believe you can hold production flat to year-end 2015 exit rate levels in 2016 spending within EBITDAX.

Is that a fair characterization?.

Well we specifically did not say that we would hold production flat in this particular case. We have said that in previous releases. I think what Wade said was we're going to focus all our efforts on returns and then on cash flow.

We think there's a good chance we can keep production flat exit rate to exit rate or even up, but that's an – it's going to be an output of our allocation to the highest return projects. Clearly, as we shift from gassier to oilier, it's harder to make rate. Potentially it's better from a cash flow standpoint.

So it's going to be within a couple percent either way..

Okay. No, I got you. I got you. And just to clarify, you're expressing these intentions in terms of EBITDAX, which of course is before interest expense. So when you're spending within EBITDAX, you're still outspending cash flow by the amount of your interest expense.

Is that correct?.

That's correct. That's correct..

Correct..

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

Thanks..

Thank you. Our next question is from Mike Scialla with Stifel. You may begin..

Yeah, good morning, guys. Maybe a follow-up on that for 2016. You've given some pretty good guidance. It sounds like you're looking at maybe $800 million, $1 billion next year in spending. If oil and gas prices turn out to be lower than what you've been forecasting, just curious how you would adjust that spending.

Would you not complete some of the DUCs or would you look at dropping rigs or are there any more assets you can sell? I just want to see what the flexibility in the 2016 plan is..

Let me start out by saying, Mike, we've never guided our CapEx for next year other than to say we're going to spend EBITDAX.

And people are out there projecting numbers for what they think our EBITDAX are, and that – these people then come up with these numbers, and I don't think the range you've indicated is wrong, but I just want you to know we've never guided that number, okay? In general, if EBITDAX goes down, we're going to spend less money.

But I will tell you if EBITDAX goes down, it's because prices go down and costs are going down too. So activity levels may not change that much. And I think we're pretty confident that across the range of opportunities we see, given where we think things can go, that we can essentially do what we're saying we can do, which will be very, very close.

We'll focus on returns first, maximizing EBITDAX, and that will result in production that we think will be close to either a little bit above on an exit rate to exit rate, or very, very close. And so over that range, that's kind of where we see it.

Obviously if prices go way down from here, everybody is going to be changing plans and the costs are going down as well..

Okay. Gotcha. I didn't mean to put words in your mouth. I guess I was extrapolating from a seven-rig program and I think you'd said you were looking at maybe $200 million to $250 million a quarter, but understood..

I did say that and, but I think today is the first time I've said that out loud in a meeting and I think people have been interpolating this kind around $1 billion program and I don't think it's wrong, but we have yet to specifically guide next year..

Yep. Understood. I wanted to ask too on the – if you could quantify a little bit more maybe on the Midland? You've got some – obviously some very good IP rates relative to your peers. You do have some production history on some of those wells. Anything you can say about the – you alluded to it, I think in your prepared marks on the longer term rates.

Can you talk about EURs at all or what the longer term rates look like at least?.

Well, they hold up really well. I mean, I've looked at our plot. If you plot our production over say a family – the family of curves that a number of our competitors put out there, these wells plot way up in EURs. We tend to be pretty conservative about how we book these things.

Our EUR numbers that we're going to book has proven are not near as high as some of these press release numbers – or the – I won't call them promotional numbers, but quarterly release-type numbers that you'll see from people. But these are big numbers and I'd encourage you to plot them up, so look at the public data.

I mean, these wells plot very well against anybody's wells in the Basin..

Got it. Will do. And the last one for me, last quarter you talked about a diversion technique to accomplish some of the same impact with the complexity of the fracs that you get with tighter stages. You mentioned that your best wells you're seeing in the Eagle Ford were done with the higher sand concentrations in the tighter stages.

Just want to see if there's any update on that diversion technique.

Is that going to be a viable way to go about completing wells?.

Well, we're still testing. We did the whole 11-well pilot that we were doing up in the north was done using that technique and so we'll see how the execution of that went on those jobs and we'll get some feedback on that. At this point I will say the strongest correlation you can get on these wells is sand loading.

I mean, when you look at within a certain lateral length, the higher the sand loading you go in the Eagle Ford the better wells you get. We know there's got to be a place where that rolls over at some point, but man, there's a strong correlation there.

So getting – it makes sense to me, the more you can spread that out effectively across that lateral length by going to tighter stage spacing that makes sense. Diversion makes sense. It's just an issue of job execution and costs to get it done the most effectively as we can..

And to follow-up on that, is that $5.4 million for a 6,500-foot lateral that you mentioned, does that assume the higher sand concentration?.

That would be about 1,700 pounds per foot, and we're pumping up to say over 2,000 per foot on some of these now. So that's probably – that $5.4 million is probably consistent with about a 1,700 pound per foot staged well..

Great. Thanks, Jay..

Hey Mike, before I let you go, don't let me – I'm not trying to pick at you about this – I did say it earlier in the call, we're going to spend between $200 million and $250 million a quarter. So I mean that is $800 million to $1 billion.

But just to be clear, that depends on costs, right? That's based on our current costs, what we're spending currently. If costs went down, if prices went lower and costs moved down, we would obviously spend less. That's all I was trying to say there..

No. I understand. Probably a poor choice of words on my part saying there was guidance....

No. It's well – when I'm here I'm on the call saying the number. It is guidance, okay? When I say it, that's what it is. I'm not trying to dance around that..

All right. Thanks, Jay..

Thank you. I'm showing no further questions at this time. I would like to turn the call back over to Jay Ottoson for closing remarks..

All right. I don't know if anybody is still out there, but we really appreciate your time today. Thanks for all your questions. Have a great quarter. See ya..

Ladies and gentlemen, this concludes today's conference. Thanks for ... [Abrupt end].