SM Energy Co (SM) 2015 Q3 法說會逐字稿

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.

(Operator Instructions)

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 begin.

Thank you, Shannon.

Good morning to all of you joining us by phone and online for SM Energy Company's third-quarter 2015 earnings conference call and operations update.

Before we start, I would 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 Operating Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Jennifer Samuels, Senior Director of Investor Relations; and myself, Executive Vice President and General Counsel.

I 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 are going to be in a ship in a storm, SM Energy is not a bad ship to be on, and we are actually really excited about some of the improvements we're making in our business, which we think are going to have long-lasting positive impact 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 will 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 is going to discuss our quarterly results and update you on where we stand against our plan for 2015.

Then I would 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 are 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 to this presentation that provides more detail by area on wells drilled, flowing completions and drilled and incompleted inventory.

It was a pretty straightforward quarter, but I will add a little color on a few items, starting on slide 4. Production for the quarter was 16.1 million BOE or 174.5 thousand BOE 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 tests number one and number three.

14 well test number one reached peak rates during the quarter and five well test number three initiated production with some good preliminary rates.

In turn, the location of these test wells drove a higher component of natural gas in 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 million BOE to 64.4 million BOE, and that's up over 1 million BOE 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 will 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 workovers in the quarter and the sale of low-cost MidCon production, and we saw significant increase in our Eagle Ford non-op costs.

LOE guidance remains unchanged with the midpoint of $3.80 per BOE.

G&A expenses were $37.8 million or $32.4 million before non-cash 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 MidCon 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 small 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 plan 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 the 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 have one BRAC crew in the Three Forks/Bakken.

Our total debt count is now estimated to increase by 80 wells during 2015, and that's up from 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 deck 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.

In the fourth quarter, we expect to spend less than EBITDAX.

As well, we expect to close a small asset sale with non-core Permian properties for about $26 million.

So we are 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 are very focused on keeping our debt metrics in line, particularly in preparation for a potential lower or longer price environment.

As we have 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 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 MidCon asset sale for $324 million.

So we have ample liquidity with only $184 million drawn as of the end of the third quarter.

So with that, I will 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 8. As Wade mentioned, we are seeing tangible evidence of our improving drilling efficiency and our duct well count.

We're also making great progress in making better wells through optimizing our landing zones within the reservoir intervals we are 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 would 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 the details there are on slide 9.

On average, we are drilling about 14% faster per foot of measured depth on these wells than we were year ago, which, if you think about it, it's 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 a time to depth.

Total drilling costs per lateral foot is now down almost 30% versus costs a year ago.

Our completion efficiency and costs are also showing dramatic improvements.

Total completion cost 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 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 for 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 of the Bakken, we have moved solidly into the camp of doing cemented plug-and-perf type completions now, and we are getting really good at it.

Combined with alternating zipper jobs on multi-pad wells, we have 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 are making better wells in the Bakken/Three Forks as well.

I've showed 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 are 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 today 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's 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 are 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've 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 have been making some really big wells.

In fact, if you turn to slide 14, you will see that we are making some great wells compared to anybody in the basin on an initial rate basis, and I will say that our longer-term reduction 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 rocks' deliverability.

Okay.

Switching gears here for a minute, I just want to update you on our inventory add testing.

We don't have a lot of new test results this quarter as we are waiting on wells to clean up and to get enough production time to make a valid judgment on those.

Typically, our gas heater wells tend to clean up a lot faster, so we get data earlier and are able to discuss it quicker.

And our oilier stuff, say in the northern Eagle Ford and some of the Bakken wells we are 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 number five in the North area, which currently we have 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, and our stack stagger pattern shouldn't have a material impact on our pilot results.

And obviously disappointing, but it 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 will have results on them in a few months.

Our results from our 450-foot well spacing pilot number one, which we 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 are not seeing any interference between these wells that are in tighter spacing than we've drilled before in this area.

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 are going to at least be going to 450s in this area of the play.

Our next Eagle Ford test that I think we will be able to talk about is pilot number three, and again, this is in a southern gassy area of the play.

These wells clean up quickly.

That's why I'm confident we will 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 are landing there.

There are seven facies in the Eagle Ford in that area, and we are basically landing them between facies two and three and between facies six and seven.

We don't have enough days 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, of course, again, is some of the most valuable acreage in our operated positions.

So we will have data on that pretty soon here.

We are tubing those wells up and I think 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 we have already discussed continue to perform very well, outperforming our Three Forks type curve for the area.

We do have two more wells drilled further south.

One of those is completed and flowing back.

And the other is completing.

Should have more results there, again, to share in a couple months.

Takes a while to clean these up.

So before I close, I would 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 the Bakken to take advantage of our better oily economics there.

We are going to be completing our duct wells.

As Wade indicated, we are 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.

I, again, 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 will 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 duct 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 will continue to take advantage of every opportunity we have to reduce costs and improve our well performance.

And, of course, we will keep you posted on our inventory situation as that evolves.

All right.

We know you are 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 will 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 will open the floor for questions.

(Operator Instructions) David Tameron, Wells Fargo.

So if I look at this -- I was just looking at that slide you provided, and thanks 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 everybody is focused on what your production mix is, quote-unquote, and it looks like there's a sharp percentage of DUCs that are more oily, if you will, than what you have got in the Eagle Ford.

So if I just think about the next couple quarters and I think about 2016, it feels like you have to get oilier.

Can you talk about that at all?

Or you don't have to get oilier, but it feels like your mix is going to get a little more oilier going forward.

Can you talk about that and put any guidepost around that at all?

Sure, Dave.

Yes, 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 are 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, and so we are going to start completing those.

I think we will 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 will work through the winter or we might take a break in January sometime when it gets cold.

But we are going to start those DUC completions during the fourth quarter.

I want to back up a little bit.

We have always said that our mix in 2016 would look very similar to 2015.

Okay, we sold some gassy assets in 2015.

So clearly, we were anticipating the fact that as you balance this out, the Eagle Ford is a big -- operating Eagle Ford is a big part of our business -- that the mix would get slightly gassier in the earlier part here as we made this transition toward picking up Permian rigs and completing the DUCs.

So we've always -- our budget -- frankly, our oil rates this month, 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, based on these tests, do you need more data from these tests before you start drilling everything on 450s, or how are you thinking about the development plan for the next, call it, two to three quarters?

I think in that Eastern area we are going toward 450s.

That's where we will be 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.

As we move toward just development in that area, I'm pretty sure we will be at 450s if not tighter, frankly.

I'm really excited about where this 312-foot offset test goes.

And pilot number two, if you remember, is the infill test, and we have yet to have results there.

So that's, again, very best geology in 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 will 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 are at seven.

I think in general, if you are thinking three rigs in the Eagle Ford, two rigs in the Bakken, we are going to start out at one rig in the Permian.

I think we may be at two within a quarter or so.

So that kind of seven number.

We're going to be transitioning our rig out of the Powder River Basin early in the year and moving it.

Again, I think that activity will end up in the Permian.

So it will be a 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.

Welles Fitzpatrick, Johnson Rice.

Two quick ones on the Eagle Ford.

One just for my own clarification, 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 towards the Permian and the Bakken?

Well, we've said and I've said we are going to go from four rigs to three at the beginning of the year in the Eagle Ford, and that's our current plan there.

We only need to run about a two and a half rig program, I think, to hold all that 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 the non-op Eagle Ford is coming down, most of the capital is actually coming from there, but that's how it will balance out.

It's about a three -- we will 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 talked about with 450-foot spacing -- does that include infill drilling like in test two, or is that just on relatively undrilled acreage?

That's just on undeveloped.

I should always say that when I quote that number.

But the 25% uptick is just taking what we had currently -- had planned to drill at 625 and 550, taking those areas to 450.

And again, we still need to prove that in that 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 it'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.

Subash Chandra, Guggenheim Securities.

Just trying to think about the math here on infills.

So when I see the 420-acre infill's 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 6 or 7 Bs, and just tell me where I'm wrong here.

But if I think about the type of total gas that you are expecting to recover on 10 to 15 wells at 6 to 7 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.

So I threw those numbers out there.

Please correct me where I'm not dotting my I's and T's.

Well, I don't know what you are using for in-place numbers is the problem.

We think we can get to 50% type recoveries in that area, in the gassy area.

So, again, I don't know you're using for in-place numbers.

What we've seen here in, say, the Woodford, where we had a pretty gassy kind of bias there in that production as we call it, in excess of 40% type recoveries, in that kind of area.

In the oilier areas of these plays, you're going to be more like 10% to 20s%.

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 are pretty darn high relative to the oily parts of these reservoirs.

Okay.

So as we adjust our expectations further west, we probably need to address that, say, from -- I think the numbers -- so 40%-50% type recovery factors, and 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 is 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 the Permian or some of these other plays, you are more like 4% to eight.

But again, we have a little more gas drive here.

So I think you are 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, whether it was really reservoir or not.

We know the porosities are Lower.

What we are finding out is it's actually productive.

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

Got it.

So you think, throughout your Upper Eagle Ford, there is a meaningful amount of self-sourcing taking place rather than just migrated (multiple speakers)?

Yes and I'll tell you why we think that is, 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.

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 has been heated up.

It's not going to be to really 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 will see significantly different yields between the Lower and Upper, and the Upper is always higher.

That's one of those wildcards 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 is, 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 are testing.

Right, right.

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

You know we know that some of the facies in the Upper are actually more brittle than the Lower, and they frack easier, frankly, than the Lower dose.

Now, the frack recipe might end up being a 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 is productive.

In doing the foot-by-foot kind of work, we do, petrophysical work, there's a lot of really good rock up in that Eagle Ford.

So we've seen Upper Eagle Ford wells that are every bit as productive as Lowers.

There's a trade-off, I think, between -- the porosity is a little Lower out there, so the storage may be a Lower.

But you may be able to make better completions.

So, again, today what we are seeing so far, at least, is that the Upper and the Lowers look about the same in terms of projected EURs.

So there's a trade-off there, I think, between fracability, I'll call it, real technical term, and storage that actually makes the wells 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, so is it specifically the less shaley intervals of the Wolfcamp B that you are targeting?

Well, it's more brittle rock, and it's really a mechanical properties issue.

And there's probably -- there's three different landing zones, I think, that we have targeted within the Wolfcamp B. It turns out that the Lower one and the Upper one performed better than the middle one, and that's probably as far into the technical detail as I can get on that.

Okay.

Terrific.

Thank you.

Michael Hall, Heikkinen Energy.

Just wanted to talk a little bit more about the DUC inventory and how you are thinking about the pace of pulling that down in the various areas in 2016.

In the Eagle Ford you've got 64, 47 in the Williston.

Are you going to pull those down at a similar pace?

When will that -- 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 are 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 will 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 are 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 will just keep right ongoing.

So I think we will probably have most of our Bakken DUCs completed by midyear.

Okay.

And then in the Permian, a similar story?

The Permian, again, is a very similar situation.

As we pick up the rig in January, we are going to immediately start completing DUC Wells, and we will get those done, I would think, in the quarter, in the first quarter.

And then we will 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.

We want to start these rigs up one at a time and 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 have provided, three rigs in the Eagle Ford, two in the Bakken, one to two in the Permian, what is a normal backlog relative to those rig counts, would you say?

We were pretty normal coming into this year with where we were.

We really didn't start building DUCs intentionally until the beginning of this year.

So if you look at that DUC count at the beginning of that slide, which, by the way, those numbers change 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 -- is that right?

We had 60 coming in the year?

It was 40, the way we used to count it.

Yes, 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.

Got it.

And as you look at oil volumes in 2016, you had a small sequential decline this quarter.

It seems like that probably happens again in 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, we forecast -- overall our production is going down in the fourth quarter.

We do have this big pilot in 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 quarters and then start back up.

When we start coming back up, a lot of that will be oily because we are completing the DUCs and then we are getting back into the Permian.

So when you get to the back half of 2016, our rates 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 are going to be at this little Lower oily level here, percentage-wise, for a couple of 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, it's a bit higher than, I think, your average working interest typically in the Divide County area.

Do you expect -- I'm assuming there are 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 a special situation there in that one of our partners is having financial difficulties in Divide County.

So I don't know how to project exactly what they will do.

Certainly, we are prepared to accept their interest in these wells.

That's what we've been doing.

To be clear, while we earn when we do that is we pick up their interest upfront, they get back in after like three times payout; I don't remember the exact numbers.

So it's not like we earn their acreage; it's just it's a wellbore 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 are not -- we are 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, on my end, I was just curious.

Can you run through what the current AFEs are running in the Divide, McKenzie, Eagle Ford and Midland Basin area?

So if they think about where you are allocating capital for 2016?

Just trying to make sure I've got the most real-time costs there.

Well, AFEs in Divide County are -- 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 cost.

And I would say that -- is that with or without?

With.

That's with the plug-and-perf.

Some of that -- I will say that $4.6 million assumes we renegotiated our rig contracts, which we are 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.

Lower Spraberry type wells in the Permian -- our current estimates there are about $7 million for a 7500-foot lateral.

I will say this.

We pump big fracks 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 drill all 10,000-footers.

I think we will be able to do some of that there.

But generally, if you are using $7 million, that's a pretty reasonable number, we think, for our current estimates, and we are not drilling right now.

We are bidding rigs right now and picking those up.

And in the Eagle Ford East, our earliest well costs there are in the mid-$5 million, $5.4 million for a 6500-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 -- the DUCs in the Eagle Ford -- do you know roughly how those are comprised and really what the composition of that is relative to Northeast, South?

If not, I can follow up later.

Yes.

Well, most of those are in those pilots that you can see on that sheet.

If you look at those pilots and where they are located, you can pretty well figure it out.

Okay.

Fair enough.

Most of those wells are drilled.

It's just that they are not all completed yet.

Got it.

All right.

Thanks very much.

Mike Kelly, Seaport Global.

I am just hoping you could maybe further frame and help set expectations for all the tests you are doing in the Eagle Ford.

I think of it as three things going on in testing -- if spacing Upper Eagle Ford's viability and really what you are going to see from enhanced completions here, and I'm curious on really how long you think it will take before you can lay out to the market what all this work should translate to in terms of updated EURs, project returns and really an ultimate inventory number in the play.

Is this something we should expect being piecemealed out here over the next few quarters, or should we set a date for a more comprehensive update?

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 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, you are going to end up needing artificial lift.

It takes longer to get results.

So the northern stuff, the oilier 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.

When we 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 -- and it's kind of confusing even for me.

Every one of these pilots has multiple objectives.

We're 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 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 best wells are the tighter stage spacing with the highest sand loading.

So we're testing completion designs in every one of these things.

And as I said, I think there's 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 will be some opportunity to continue to get better there.

Secondly, certainly just spacing in general, density is an important thing, and pilot number one we are really focused on the Lower, just trying to figure out, okay, with our newest completion designs, which we know keep our fracks closer to the well bore, 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 get 100 feet or 150 feet between the wellbores vertically, can we put them even closer together?

And I think that's where pilot number three comes in and 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 about 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 work, that's a big uptick, again, in inventory.

And then, of course, as you go into the northern pilots, you 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 different 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 are 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, and 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 are pretty confident we are going to end up with a significant growth in inventory.

Got it.

Really appreciate the color.

That's all I've got.

Thank you.

Pearce Hammond, Simmons.

Jay, previously you had 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?

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's more of an output 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 return-based.

So we are going to be working that hard over the next couple months, and that's where we are right now.

Great.

Thank you for that color.

And 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?

Yes.

It's not that much money, Pearce, and again, I don't anticipate seeing us overspending what we have 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 capital-wise to go ahead and get that done, and it's not going to be that many wells.

By the time we get it lined up and get going, you are talking about eight 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.

Like in 2017, you have 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 try to take advantage of contangoed strips when we can.

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?

Yes.

That was that Gordon 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.

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.

Jeb Bachmann, Scotia Howard Weil.

Just a couple quick ones for me, Jay, first on the Permian.

Can you tell us what technology you are using to better land the laterals and what that is 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 are able to do it with very little incremental costs because tools are good enough now and we are good enough to be able to do that.

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

And we really look at the mechanical properties of the rock across that whole interval, the porosities across that whole interval, all of 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 a frack?

And there are some trade-offs 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 are landing in the bottom or the top, you have higher few 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 has 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 percentage that you put of that lateral in the right landing zone makes a huge difference in how these wells perform.

Not something that I would have told you five years ago because my assumption was you laid 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, and it's not just us, the industry has, over the last few years.

And then P rate makes a lot of difference here, too.

If you can get it in the right landing zone, your penetration rates are much higher, and you are 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 660 feet already in the Permian, and what you will 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 will drill.

But once we get to pad drilling, you will start to see, I think when we pick up that second rig would be when you would probably start to see it, some multi-well pad development that would be a staggered Chevron type of opportunity.

Okay.

And then last one for me, just on the cost side, do you guys see another 5%, 10% maybe coming out of service costs at this point, or do you think that you have seen as much as you are really going to get at this point?

Well, I think if prices stay where they are, you are going to see costs go down, no question.

I don't know what the percentage is.

And you can look at -- I think that plot, actually, that they are 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 still see a lot of pressure for costs 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 are 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 a downward trajectory unless prices change.

Just last one following on that, just based on your comments earlier and the slide deck, it looks like the Bakken has the best chance of keeping costs Lower than the Eagle Ford, maybe, because you are 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 have been at a fairly high activity level for quite some time.

We've driven our -- we were very efficient already there.

So 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 have been doing the plug-and-perf cementliner completions for a long time, and we are really good at it.

And it's hard to see us pumping a lot more stages per day versus what we are already doing, and we are 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 are literally drilling 12 wells in a half section, I think you can 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.

Paul Grigel, Macquarie.

Just to follow up on a point from earlier, 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 a dip and then an increase in the back half of the year?

Yes, 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 shipping 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 the 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 are still waiting on completion, just realizing (multiple speakers) --

We just started our flow back, literally within the last couple of weeks.

It took a long time to get all the wells completed.

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 are looking versus making an actual (inaudible)?

30 days on these -- you barely get through cleanup in 30 days.

You've got to get the load off all these wells, and there's a significant frack load that you've got to get through.

These wells don't produce 10 million a day like these southern gas wells.

So it takes a while to get them cleaned up.

And we will do it as fast as we can, as prudently as we can.

We are not going to make any comments -- I can tell you I'm not making any comments I have to eat later on any of these wells.

Okay?

So 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 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 colder winter weather, how much additional cost is that on a -- per completion for each well to heat the water, etc.?

It would be $100,000 to $200,000 per frack.

That doesn't sound like that much money, but you are talking about fracks that only 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 would 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.

[Matt Purtillo], PPH.

Just a quick question on the full-year guidance, just wanted to make sure we're thinking about Q4 correctly.

Jay, I think you've reversely 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.

I think you mentioned essentially going on a pretty solid frac holiday across all of your assets.

And I guess the 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.

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 are 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?

Our PDP decline -- if you just stop doing everything, our DDP decline is in the high [30s].

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 [30s].

So 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 is going to be in the $200 million to $250 million a quarter kind of range as we get back to normal completions.

We do have a number of wells we are bringing on that we have completed in the third quarter, in the fourth quarter.

So I don't think people should assume that we are plummeting in the fourth quarter.

As Wade said, what we have guided is exactly what we had guided essentially for the fourth quarter before.

There is some uncertainty associated with a lot of these new pilot wells we are 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 could 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 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 we think about the Permian/Bakken and Eagle Ford, how are those stacking up today as you think about strip pricing or the commodity price environment you're looking at into 2016 and how that could potentially influence your decision making process around capital allocations?

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 look at new drilling today, Bakken and Three Forks and Divide County and the stuff we are doing in the Permian have very similar economics that basically are 20%-plus returns in the $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 in a good spot, and obviously costs are continuing to come down.

In the Eagle Ford East, again we ran those numbers and had that 20% return at $50.

That was using a $3 strip.

The strip -- gas prices, obviously, have been hugely volatile.

The strip is a little Lower than that today.

So if we had to stack them out today, we would say, hey, does the Midland, Bakken and Divide County look a little better, say, than our Eagle Ford stuff.

Our Eagle Ford stuff still 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, the oilier stuff looks pretty strong right now.

So in general, we are going to follow the course in terms of rig count that we described earlier today.

Great.

And then I just like to leave it on the Permian.

You guys have had some great results there so far in the Wolfcamp B. Can 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 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 is going on from an industry perspective, trying to get a better sense of the resource there?

Well, I'll say I think if you ask our folks right now what are you going to drill in 2016, they will say 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 would 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 are probably on the high-end of that.

Our experience corporate-wide has been the high sand loadings are really leveraging slick water, and 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.

It would be an interesting test.

A lot of people will tell you that in the area that we are in the Wolfcamp D is maybe even a better target for some of these others.

We haven't tested that yet.

So a lot of opportunity there in the D.

So we've got -- 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've got 1250 B or 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.

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 things and still maintain a program that's very sustainable in a period of low commodity prices.

Thank you very much.

James Spicer, Wells Fargo.

I wanted to just revisit the maintenance capital question in the context of prices here.

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 going to be an output of our allocation to the highest-return projects.

Clearly, as we shift from gas here to oilier, it's harder to make rate potentially 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 are expressing these intentions in terms of EBITDAX, which, of course, is before interest expense.

So when you are spending within EBITDAX, you are still outspending cash flow by the amount of your interest expense.

Is that correct?

That's correct.

Correct.

Okay.

Great.

That's it.

Thank you.

Mike Scialla, Stifel.

Maybe to follow up on that for 2016, you've given some pretty good guidance.

It sounds like you are looking at maybe $800 million to $1 billion next year in spending.

If oil and gas prices turn out to be Lower than what you have been forecasting, just curious how you would adjust that spending.

Would you not complete some of the DUCs, or would you look at drop in regs?

Are there any more assets you could sell?

I just want to see what the flexibility in that 2016 plan is.

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

And people are out there projecting numbers for what they think our EBITDAX are, and people then come up with these numbers.

I don't think the range you've indicated is wrong, but I just want you to know we have never guided that number.

Okay?

In general, if EBITDAX goes down, we are going to spend less money.

But I will tell you, if EBITDAX goes down, it's because prices go down, and cost are going down, too.

So activity levels may not change that much.

And I think we are pretty confident that across the range of opportunities we see, given where we think things can go, that we can essentially do what we are saying we can do, which we will be very, very close.

We will focus on returns first, maximizing EBITDAX, and that will result in production that we think we 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 where we see it.

Obviously, if prices go way down from here, everybody's going to be changing plans, but costs are going down as well.

Okay.

Got you.

I didn't mean to put words in your mouth.

I guess I was extrapolating from a seven-rig program, and I think you had said you're looking at maybe $200 million to $250 million a quarter, but understood.

I did say that.

But I think today is the first time I've said that out loud in a meeting, and I think people have been interpolating it as around a $1 billion program.

And I don't think it's wrong, but we have yet to specifically guide next year.

Yes, understood.

I wanted to ask, too, if you could quantify a little bit more maybe on the Midland.

You've got, 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 remarks, 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've looked at our plots.

If you plot our production over, say, a family of curves that a number of our competitors put out there, these wells plot way up, way up in EURs.

We tend to be pretty conservative about how we book these things.

Our EUR numbers that we are going to look as proven are not near as high as some of these press release numbers.

I won't call them promotional numbers, but quarterly release type numbers that you will see from people.

But these are big numbers, and I'd encourage you to plot them out.

So look at the public data.

These wells plot very well against anybody's wells in the basin.

Got it.

Will do.

And the last one from me -- last quarter you talked about the 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 are seeing in the Eagle Ford were done with the higher sand concentrations and the tighter stages.

Just wanted 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 are still testing.

We did -- the whole 11-well pilot that we were doing up in the North was done using that technique.

So we will see how the execution of that went on those jobs, and we will give some feedback on that.

At this point, I will tell you the strongest correlation you can get on these wells is sand loading.

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.

Again, 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 6500-foot lateral that you mentioned, does that assume higher sand concentration?

That would be about 1700 pounds per foot, and we are pumping up to, say, over 2000 pounds per foot on some of these now.

So that's probably -- that $5.4 million is probably consistent with about a 1700-pound-per-foot stage well or well.

Great.

Thanks, Jay.

Mike, before I let you go, I'm not trying to pick at you about this.

I did say earlier in the call we are going to spend between $200 million and $250 million in the quarter, so that is $800 million to $1 billion.

But just to be clear, that depends on cost.

Right?

That's based on what we are 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.

It was probably a poor choice of words on my part saying that was guidance.

No, it's well -- here I am on a call saying the number.

I mean, 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.

I'm showing no further questions at this time.

I'd 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, and thanks for all your questions.

Have a great quarter.

See you.

Ladies and gentlemen, this concludes today's conference.

Thanks for your participation, and have a wonderful day.