SM Energy Co (SM) 2015 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the SM Energy second-quarter 2015 earnings conference call.

(Operator Instructions).

I would now like to turn the conference over to your host for today's call, David Copeland, General Counsel.

Sir, you may now begin.

Thank you, Marcus.

Good morning to all joining us by phone and online for SM Energy Company's second-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 afternoon, 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.

Other 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, the Senior Director of Investor Relations.

I will now turn the call over to Jay.

Good morning.

Thanks to all of you for joining us.

Man, we had a great quarter and our results year to date provide more evidence of our continuing top-tier performance.

I am on slide 3. We've got a strong balance sheet, ample liquidity, and a solid operating plan which will help us avoid shareholder dilution.

We have decades of production at our current levels of production in economic drilling inventory and we have a clear and credible path to replacing and adding substantially to that inventory without the need for acquisitions.

Our entire focus is on creating long-term, differential shareholder value.

I'm going to turn the call over in a minute and let Wade walk you through the quarter and our revised guidance, but let me just point out a couple of highlights.

On slide 4, first, we have experienced improving well performance in both the Eagle Ford and the Williston Basin, which is translating into higher-than-projected production.

This outperformance is a result of our increasing success in improving lateral placement and completion techniques.

Second, we have seen encouraging new well results in our core development areas, which we believe will translate into material growth in our economic drilling inventory.

And I am going to cover those results in more detail later in the call.

Third, our costs are way down, with substantial progress in reducing both capital and operating costs.

Fourth, our current financial position is excellent, especially compared to our more levered peers.

Our debt to trailing 12-month EBITDAX is at 1.7 times and we have very little drawn on our revolver.

And lastly, we are positioned to perform differentially, we believe, in 2016.

Our current projections indicate that our portfolio can deliver production growth during 2016, investing only our EBITDAX, even assuming today's depressed strip pricing.

With that, I will turn it to Wade.

Thanks, Jay.

Good morning.

So starting on slide 5, as Jay said, it was an outstanding quarter.

Operational execution was the key factor.

Well performance and associated higher production, combined with achieving sizable cost savings and LOE, led to EBITDAX and earnings to beat our projections.

I believe much of the detail you all need is in the release and the 10-Q, but let me give you a little color on a few topics.

Production for the quarter was 16.5 million BOE, which was 500,000 ahead of our guidance.

We had indicated that production would go down about 5% from the first quarter, due to planned maintenance and simultaneous operations that would require Eagle Ford shut-ins.

The plant downtime was completed on schedule and well performance continues to exceed earlier type curves, as reflected in the production.

Obviously, better wells means better production.

Going forward, we have raised our annual production guidance from a midpoint of just under 62 million BOE to just under 63 million BOE.

This implies second-half production of about 28.3 million BOE to 30.8 million BOE, which will reflect, first of all, the stepdown associated with the second-quarter asset sales of just under 1 million BOE per quarter, which was all gas, and then an expected decline of about 2% to 3% per quarter as a result of the reduced activity.

LOE for the quarter at $3.26 per BOE is really a demonstration of the hard work our team is putting into efficiencies and cost savings.

First, we're rebidding and negotiating the best possible costs at all levels of the Company and we are seeing real savings across the board.

Secondly, our Williston team has driven cost efficiencies in our acquired properties significantly below the previous operator, on which our cost forecast was based, primarily savings in reduced water hauling costs.

As a result, we have made a sizable reduction in our overall LOE guidance for the year, from a midpoint of $4.52 per BOE down to $3.80 per BOE.

Clearly, the combination of strong production and low cost drove favorable EBITDAX and adjusted earnings for the quarter of $337 million and $0.49 per share, respectively, both well above consensus estimates.

G&A expense before non-cash compensation of $35.4 million includes about $5 million in charges related to the closing of our Tulsa office and we expect to record another $1 million or $2 million in the third quarter.

We slightly lowered G&A guidance to range, on average, $2.40 to $2.70 per BOE for the full year.

DD&A came in within guidance for the quarter.

We are raising our full-year guidance to reflect the impact of lower commodity prices on PDP reserves.

Moving to slide 6, capital expenditure activity is on schedule at operated properties with second-quarter capital at $339 million, and that's down 30% from the first quarter.

FX activity was heavily weighted to the first half of the year, with roughly two-thirds of the 2015 program now completed.

Expenditures total $819 million year to date.

We started the year with 17 rigs and the higher 2014 cost structure.

We are now down to nine rigs and expect to release two more rigs in the fall.

Currently, drilling and completion costs are down about 30% in the Eagle Ford, compared with similar wells drilled last year.

In the first half, we exceeded budget by about $50 million related to higher facilities cost at nonoperated properties and for higher partner nonconsents.

Partially offsetting this, we are drilling wells faster and gaining efficiencies.

Net net, we raised our capital guidance by about $50 million to reflect non-op and nonconsents that were charged in the first half of the year.

Capital expenditures in the third and fourth quarters are expected to be about $460 million, stepping down in the third quarter and then stepping down further in the fourth quarter, for a total-year budget of now $1.28 billion.

Let's move on to the balance sheet on slide 7. As Jay mentioned, and this is probably one of my most important points this morning, debt to EBITDAX remained at 1.7 times and we have ample liquidity with a borrowing base of $2.4 billion and only $122 million drawn.

Net proceeds from the Mid-Con asset sale, which closed in the quarter, were $317 million and were applied to the revolver.

Also during the quarter, we had a few timely bond transactions.

We redeemed all of our outstanding $350 million 6-5/8% senior notes that were due 2019 and issued $500 million of 5-5/8% senior notes due in 2025.

These actions termed out our unsecured debt with the nearest maturity now 2021 and it reduced our average coupon rate to 5.9%.

Lastly for me, on slide 8 regarding hedges, we added NGL hedges in the quarter specifically relating to propane and butane.

There is a schedule with details of all our hedges in the appendix to the slides.

In general for the second half of 2015, we have hedges in place for about 46% of oil, 41% of natural gas, and 46% of NGL forecasted production at the midpoint of our guidance.

Also to note, we unwound certain natural gas hedges tied to Mid-Con production that was sold in the quarter.

This effectively accelerated hedge revenue and added $15.3 million of second-quarter realized hedges.

So I will now turn the call back to Jay to discuss more details on our operations and our growing inventory.

Jay?

Thank you, Wade.

I mentioned earlier that I wanted to spend time talking about some new well results in our core development areas.

Those results are some early steps in what is a clear path, we believe, toward a doubling of economic drilling inventory in all three of our major development projects -- the Eagle Ford, the Bakken/Three Forks, and the Permian -- without the need for acquisitions.

While we have been deferring activity temporarily on our held-by-production Permian acreage, while we have been adjusting our capital investment pace, we have been actively drilling inventory test wells in both the Eagle Ford and the Bakken/Three Forks play areas.

I am now on slide 9.

Generally, our inventory add efforts in those two regions can be put into one of three buckets.

First, testing the opportunity to put more wells then we have previously envisioned in each section of our Eagle Ford acreage by optimizing spacing and landing zones in the thick Eagle Ford pay on that acreage.

Second, testing the Bakken interval on our Divide County acreage in North Dakota, and third, employing enhanced completion techniques in both areas to improve recoveries and enhance economics.

I am going to start with our operated Eagle Ford testing program.

Slide 10 shows the number and geographic spread of the pilot tests we have currently planned.

The economic inventory count we have previously disclosed for our operated acreage is generally based on developing the field at simple 625-foot or 550-foot planned view spacing in the southern and northern portions of the acreage, respectively.

Those spacing assumptions were based on our interpretation of results from wells drilled and completed several years ago, which were landed in a single landing zone target, essentially, in the lower Eagle Ford and which indicated likely interwell interference at lower spacing using the frac designs we had at that time.

Now as we have shown with well tests and discussed in previous calls and conferences, we now know that the upper portion of the 25- to 30-story high Eagle Ford Shale in our area is a much more productive reservoir that we originally believed, and our pilot testing is designed to prove that up broadly across our acreage.

In order to fully understand the pilot tests we are now performing, however, it is also important to understand how far we have come in the last several years in improving our completion designs.

As we discussed in our completion lunch and learn in May, we can measure and model the amount of propped fracture surface area we generate with our fracs and we have established that there is a strong correlation between surface area created and well performance.

Our newest designs are more effective in creating surface area in complex fracture networks that are nearby and connected to the wellbore.

We have increased sand volumes in our frac jobs to up to more than 2,000 pounds per foot of lateral length and we have optimized completion fluids.

More recently, we've been testing smaller sand sizes, reduced staged spacing, and interstage diversion in our standard stage spacing completions.

All of these completion improvements are driving better well performance and we know they contributed to our production outperformance in the second quarter.

So, our pilot test program is intended to progressively prove up additional inventory by employing a high surface area close to the wellbore frac designs and targeting multiple landing zones within our thick pay section to increase well density on our undeveloped acreage, and also infill previously drilled wells.

We're making good progress on getting wells completed and we will have a progression of results to share over the next few months and quarters.

Our first test with results we can discuss is labeled as pilot number 1 and is a 14-well test of tighter well spacing in lower Eagle Ford landing zones.

A depiction of pilot number 1 is shown on slide 11.

This test is in the center of the second row from the north of our development of the East area, what we sometimes refer to as Galvan Ranch.

I should note that our northern row wells in this area were generally drilled at 1,250-foot and 900-foot spacing and we will be testing infilling those wells later this year in the pilot test labeled number 2.

Our assumed spacing for our current inventory count in the pilot number 1 area is 625-foot planned-view lateral spacing, and in this test, we are comparing wells drilled at that spacing with some drilled at 450-foot planned-view spacing.

The lateral lengths in these wells were dictated by our mowing the grass type development pattern in this area and vary in length from 4,000 to 5,900 feet in length, with an average lateral length of right at about 5,400 feet.

Slide 12 shows early production results per 1,000 foot of lateral from the 625-foot and 450-foot spaced wells.

There are nine 625-foot spaced wells in the average 625-foot curve and five 450-foot spaced wells in the 450-foot curve.

As you can see, the rate so far for the 450-foot wells lay essentially right on top of the 625-foot results and all the wells are outperforming our area type curve.

Now we're not showing flowing pressure data on this plot, which is probably some of the most important data you can look at, but so far we are seeing flowing pressures as high or higher on the 450-foot wells as on the 625s.

So, no indication of an increased interwell interference yet with downspacing.

Now, obviously, these early results are very encouraging.

We are attributing much of the good performance on the 450-foot spaced wells in this pilot to our most recent round of completion optimizations.

As I said earlier, we have been optimizing our landing zone targeting within the various portions of the Eagle Ford, specifically here within the lower, and these 450-foot wells were pumped with 165-foot stage spacing completions, which is half our standard 330-foot stage spacing.

So what should investors be thinking about the results of these tests so far?

Simple math is that a move to 450-foot planned-view spacing versus our current assumptions across the Eagle Ford, not including infill potential between existing wire spaced wells, would increase our previously stated operated Eagle Ford drilling inventory by about 25%.

However, it is probably more appropriate to say at this time that the early results of this test, combined with solid results we already have for upper Eagle Ford wells, simply points to a much higher likelihood of success in higher density drilling on our acreage, leading us to that doubling that we are talking about.

Now there will be some skeptics out there who will say, yes, but what about those other guys who tightened up spacing a few years ago, drilled a bunch of wells, and now wish they hadn't?

To be clear, what we are talking about doing with our Eagle Ford development is an entirely different thing.

Our plan is to stagger well completions between different landing zones in the lower and upper Eagle Ford, which should reduce the potential for interwell interference.

In pilot number 5, we are currently completing a 15-well test in a development pattern with some wells that are literally stacked on top of one another in the upper and lower portions of the pay.

And there is just lots of exciting news still to come here.

Before I leave the Eagle Ford story, I want to note that our operating partner to the north, Anadarko, is testing additional inventory in the upper Eagle Ford as well.

We have the opportunity to see their results and I should just convey that they are very encouraging as well.

Now I'm going to turn to slide 13.

This is our work in Divide County, North Dakota, where we have a massive and very contiguous position and where we have been improving completions and testing Bakken wells, in addition to our normal Three Forks interval development.

I want to just remind you again that the center of Divide County is a geologic sweet spot and that wells here are shallower and cost much lower than southern portions of the Bakken/Three Forks play area.

On slide 14, we are showing average results on nine total wells now drilled and completed on our acreage in Divide County in the Bakken horizon.

As a reminder, to date all of our previously stated economic inventory in this area is in the Three Forks.

As the slide depicts, our Bakken wells drilled to date on average are outperforming our Three Forks type curve for the area.

Also interesting to note, Bakken wells are slightly shallower than Three Forks wells and the Bakken Shale is easier to drill.

In fact, we just set what we think is a North Dakota state record, drilling more than 4,300 feet of horizontal lateral in one day on a less than nine-day spud to rig release 10,000-foot lateral Bakken well.

We are obviously very encouraged by those results and believe we are well on the way to doubling our current inventory of 400 gross economic locations in this area.

The last piece I want to -- update I want to show you today is specifically on improvements and completions and what we are seeing there in our Bakken/Three Forks wells.

And here, we have been moving from sliding-sleeve open-hole completions to plug-and-perf cemented liner jobs.

In order to show this on slide 15, we graphed our recent plug-and-perf results in Divide County Three Forks wells versus our current type curve, which is based on sliding-sleeve completions.

Although plug-and-perf jobs are a little more expensive, about $0.5 million more per well than sliding sleeves, the increasing productivity of our wells is yielding economic wells at even lower prices.

We are generally seeing this kind of production uplift across our operated assets in the Bakken/Three Forks play area and our good stuff just keeps getting bigger and better.

Turning to slide 16, I would just like to reiterate a couple of key points in closing.

Our great performance this quarter is the result of our continuing intensive focus on our core assets, great operational execution, and improving well productivity in our development project areas.

Our balance sheet is strong and we have ample liquidity.

We are seeing the kind of early results we had hoped for in our inventory test pilots and we are driving cost down to the point where we can grow profitably within our EBITDAX during 2016.

SM Energy has consistently been in the top quartile of our peer group for generating debt-adjusted per-share growth and production reserves and cash flow, and our entire focus is on delivering that kind of differential performance for our shareholders going forward.

We will be happy to take your questions at this point.

(Operator Instructions).

Pearce Hammond, Simmons & Company.

Great quarter and thank you for taking my questions.

Jay, if the current forward strip holds, do you think CapEx will be down year over year in 2016?

And if so, what do you think is a rough percentage?

Pearce, this is Javan, and we do think it will be down and roughly to the level of our EBITDAX.

That's right about where we think it will be.

And then, Jay, can you please elaborate on why the LOE guidance improved so significantly this quarter?

When we bought those assets in North Dakota last year, those assets weren't set up quite like ours and, frankly, their operating costs were very high, and we were unsure how long it was going to take us to really get them in shape to where we could drive those costs down to anywhere near the level that we were operating at.

So we were pretty conservative in the way we budgeted for that.

As it turns out, our guys have just done a terrific job in a lot of ways up there and have driven those numbers a lot lower than we expected a lot sooner than we thought.

A lot of those cost savings have been on optimizing the trucking of water out of those assets, and just where we have drilled wells and how we've handled that has really saved a lot of money.

Plus, generally our LOE is just down significantly across the board.

We have an internal goal this year of just really driving down total cash costs per barrel, and our people have really stepped up to the plate and driven that number down.

We are well below our budgeted numbers in every area on cash cost, so just really going in a really positive direction and we're really happy that we can lower our guidance as a result.

Thank you for the color, Jay.

David Tameron, Wells Fargo.

So Jay, just to make sure, so when you are doing -- when you are talking about your staggered tests, are you doing one, is it fair to say, in the lower Eagle Ford and then one in the upper part of the lower Eagle Ford?

Is that the right way to think about it, kind of in like a chevron type pattern, or can you give me a little more -- just refresh my memory on that?

David, yes, this is Javan, that is probably the easiest way to think of it.

There are several different landing zones in the lower Eagle Ford.

Yes.

In the particular case, these wells here, we didn't stagger them much.

There was a little bit of different variation between the landing zones.

I think what is really driving the well performance, the lack of interference we are seeing early on here, is that our completion designs are just so much better than they were a couple years ago.

Look, I know that there were some guys who went out three years ago, two, three years ago, with older frac designs and went to very tight spacing and were very aggressive in their pace of development, and I am sure a lot of those guys wish they had a do-over today, that they could go back and re-space or widen their spacing, change their landing.

That, clearly, if you had a small position and you were being really aggressive in your pace and development, you could get to that point.

We are not in that position.

We have a much larger acreage position.

We have got a lot thicker than a lot of people.

We have got a lot of undeveloped, very thick pay, and, quite frankly, we are a learning machine.

And we're going to put the very best job, very best completions we can at the very best landing zones staggered across this acreage, and I firmly believe that that is going to result in a lot more inventory than we are currently getting credit for.

Okay.

And I know I'm getting way ahead of myself, but when you start thinking about -- how much data do you need to see and how many pilot tests?

If these pilot tests work this year, you are talking about doing this across the basin.

At what point do you feel comfortable saying it is a pretty widespread program?

That's exactly the same kind of question we are asking ourselves.

How much do we have to have to where you don't want to -- never claim victory prematurely.

I will say that, in a sense, the bit of a downturn that we have had in activity levels -- certainly our cash flows have come down, too, we are slowing pace a little bit, so it gives us time to incorporate all these learnings into our development planning.

And as we move into 2016, we are going to be looking very hard at what are the impacts of this on our infrastructure planning, and we will be working with our infrastructure partner there to think about, okay, if we go to really intensive development per section, what does that mean?

So, I think 2016 is going to be a really key year for us in terms of really turning the boat a little bit away from this very simple, single landing zone, planned-view type spacing to more 3D chess, if you will say that that way, in our development.

But, man, really exciting, lot of opportunity, and what I think is really important here is that as we develop more and more inventory, what that gives you the ability to do is high grade more and more even within your portfolio.

It helps you maintain the kind of high returns that we've had historically and I think that's a part that we really are looking forward to as well.

Okay, and then just final question.

Just as I think about the upper part of the lower, and realize I'm generalizing here, but what is the -- if this were not to work -- obviously, the initial results look like they're working, but what is the geologic risk?

Is it fracking into -- I don't know what that frac barrier is right above the upper part of the lower, between that and the upper, but is that -- could it be something in there that you are fracking into or why, looking six months down the road, would this not work?

I think the biggest risk to the program is always that you make a judgment based on data too early, frankly, and are overaggressive.

The big mistakes people make in oil and gas development are generally overdrilling, so you want to make sure you don't go nuts here and go to a rapid-paced downspace development too quickly.

I think a lot of those risks are mitigated for us because we are not talking about a single landing zone development anymore here.

We are talking about staggering.

We know that the upper is productive.

One point I want to make here, as we went back -- as we have gone back and really looked at how we landed a lot of our lower Eagle Ford wells, we did land a number of them toe up.

We would come in and then start drilling updip.

In a number of our lower Eagle Ford wells, a good portion of that wellbore is actually above the lower upper interface, and we've had some really terrific wells among those wells that we toe up.

So we know that the upper Eagle Ford is very productive, just above the interface.

So I don't think there is a lot of risk from the standpoint of if we stagger these wells some and we're just careful not to downspace too far, I think we can manage that risk.

Again, the little bit of slower activity period we have here gives us the chance to do thorough testing and to make sure that we are not getting ahead of our -- or too far over our skis.

But I think it is something that we can clearly manage.

Frankly, we have always been more conservative on spacing than other people anyway.

That's just part of our nature, and we're going to do the right work to get this right.

Okay, I will let somebody else jump on.

Thanks for all the color.

Subash Chandra, Guggenheim Securities.

Yes, Jay, again, nice job.

Your 3D chess, nice analogy there.

Could you remind me if you have or plan to do a large-scale microseismic survey in monitoring the results?

Subash, we have done a lot of microseismic out there and have done -- and have tracked a lot of it.

At this point, we don't have a lot of microseismic to do associated with this.

We really more focused on just getting wells landed and completed in the various areas and focusing very hard on the surface area, what we call [AC Route K], in generating these complex fractures.

We really think that the measurements we can do using pressure and volume relationships can tell us a lot about where our fracture going and how that's going without having to spend a lot more money on microseismic at this point.

Got it.

Okay, and so in reference to slide 12, just want to confirm, so the 425s versus the wider spaced, the completion recipe on the infills were actually less stimulated than the offsets?

Is that what you --

No, no, no, no.

Now I think that's back (multiple speakers)

You think that's backward?

The 625 wells were generally completed at 330-foot stage spacing.

And we did have some in there that were done at the 165-foot stage spacing, so it's sort of a mix.

The 450s were essentially all done at the 165-foot stage spacing, so some of them were done with exactly the same sand loading per foot.

Some of them were done with a little bit higher sand loading per foot, so there's a couple different tests going on there.

We didn't show all that data yet because a lot of it is just not conclusive yet between various wells.

These are averages.

But in general, the 450s had -- were drilled at tighter stage spacing.

Now, one of the most interesting things we are doing right now and we have done some work already -- I mentioned it, I think -- was that we are doing some work looking at wider stage spacing, but using interstage diversion, using various materials that several of the frac companies have, and we've seen some really good initial results on that.

And in fact, the 15 well pilot we're going to be doing up in the northern area, we're going to be using 330-foot stage spacing with interstage diversion on all those wells, based on the results we have seen so far.

That would be a less expensive way to basically accomplish the same kind of lower stage spacing.

So, again, we're just going to be driving on, innovating on, and improving these completions and there is more stuff to come on that.

Okay.

Divide County, the water handling, I imagine you have gone from perhaps trucking all of it to maybe a better way of disposing of it.

And if that's correct, and if that is an ongoing project or if it is largely done?

Well, actually, a lot of what we did in reducing costs was just figured out ways to reduce the distance we were trucking.

We were able to acquire -- develop some more water [hauls] such that we didn't have to haul the water so far.

We still have some -- and we're not going to do this in the short term, but we still have some capital we would like to spend over the next few years in developing a water pipeline system on a lot of the acquired acreage.

We already have that on our previously operated acreage.

So I think there is actually room to reduce costs even further as we go down the road, but we would have to spend a little more capital to do it.

Got it, okay.

And thanks for taking all the questions, just a couple more, if I could.

Just one on the -- I think the $7 per barrel or something like that transport cost in the Eagle Ford properties, when do you shake that?

Is there a time when you shake that and can you get something more competitive?

Well, I will take a little bit of issue with your comment, competitive.

The reason it is what it is is because we didn't pay any capital for this process, and so our costs are higher because we didn't pay capital costs.

So I think it is actually a very competitive contract, based on the fact that we didn't have to put up the money.

Second, when you get out about five years, there is a significant drop in our gathering fees.

Basically, we get to the point where we have helped the midstream folks pay for their system and we do see a drop back in the 2021 time frame where we see a pretty significant drop in gathering fees.

Okay, yes, that's a very fair point.

True.

And then, finally, do you have the Eagle Ford non-op/op production breakdown this quarter?

It would be in the Q, and do we break out?

The non-op.

No, I am sorry, Subash.

I don't have it off the top of my head here.

Okay.

All right, thanks again, guys.

Matt Portillo, TPH.

Just two quick questions on guidance into the back half of the year.

I think previously on production you had mentioned an expectation coming into the third and fourth quarter that volumes would be down 1% to 2%, and I think implied, as you mentioned in the guidance you provided now, that volumes could be down 2% to 3% per quarter.

So just wanted to get a sense of what is driving the change there, especially given the well outperformance and how you guys think about that?

Yes, this is Wade.

First of all, obviously the second quarter is a significantly higher number than we were talking about back in the first quarter.

We did have a great quarter.

And before we were -- I think last time we were talking, we weren't -- we had not completed the Mid-Con divestiture yet, and for now we're just -- the activity is reduced and we're reflecting that in our guidance.

So, that is what it is.

Okay, perfect.

And then, I guess, secondarily on the LOE side, I know that you guys have talked about some of the structural changes you saw in the LOE drop into Q2, which has been a huge improvement quarter over quarter.

Again, looking at the guidance numbers, that implies there is a pretty significant ramp coming into Q3 and Q4, but all the commentary on the call suggests that this is structural.

Can you just give us some incremental color as we think about Q3 and Q4 guidance around LOE?

What is it (multiple speakers) higher?

Look, obviously, we are very pleased with the second-quarter results, significantly below what we expected.

We have lowered the guidance somewhat.

I think at this point we are just being a little cautious on baking all of that in at this point.

Okay, great.

And then, just last question for me.

DD&A had an uptick.

Just curious if you could provide some context around what drove that, I guess, specifically.

I know you guys do midyear reserves.

Just trying to get a little better sense of what was the change there, whether it was PUD or PDP revisions.

Just trying to get some color.

Yes, certainly nothing related to PUDs.

We do look at our reserves again at midyear and that is essentially PDP only.

As prices have fallen significantly over the last year, that does have some impact on the -- really on the tails of the PDP.

So we decided to raise the guidance in anticipation.

I will say that, back to the cost side, with costs falling so significantly, there is a chance that will have an offsetting effect when we go into year-end reserves and really do a much more thorough analysis at that point.

But that's really the reason.

Thank you very much.

Mike Kelly, Global Hunter.

Great ops update and was hoping you could expand upon some Eagle Ford data a little bit here.

And I think really just trying to get some context on potential returns you would ultimately expect to see out here.

And I respect that it is early days here and you probably don't want to peg a specific IRR at $50 oil or something like that, but maybe if you could compare this -- the returns, how they could ultimately stack up against your Permian acreage, which I think is commonly thought of as amongst the best shale acreage in the US, how Eagle Ford could ultimately compare versus that.

Well, that's a great question and I will just say up front we have been really surprised as we have gone through our midyear updates on type curves and well costs at how well our returns on a lot of these -- on the best portions of our acreage, and a lot of it is really good, but the very best portions, how high those returns have continued to stay.

And it is a little scary, frankly, from an industry standpoint that when we look at quality acreage like ours that we can still make really decent returns.

And a lot of that is just because costs are so much lower than they were.

This acreage here that we had drilled in this pilot is right in the gut of the eastern portion of the Eagle Ford and these wells have very high returns, and we are AFEing these wells now for under $5 million apiece, really an astonishing number.

So they will have very high returns.

In comparison to the Permian, honestly, when we run the numbers today, they are very, very similar.

Our Permian wells do have really high returns, particularly that lower Spraberry stuff, and we're going to get back to drilling that as quickly as we can at high density.

I will keep throwing in pieces here.

But I think if you would stack everything up today, our Bakken Gooseneck stuff, our Permian lower Spraberry stuff, and this area in the Eagle Ford are all going to have very, very -- very good returns.

Obviously, everything -- the values of all this stuff are done because cash flows are down, but when you look at returns on capital employed, these things all have pretty good returns at these -- even at low prices.

Got it.

Now if you could -- might beg the question a little bit if ultimately the returns are very similar to the Permian and just looking at where the stock is trading right now, I think you guys are really one of the cheapest names in the mid-cap space, and your Eagle Ford inventory might be doubling or tripling here with competitive returns.

Does the Permian make sense to even have in the portfolio or is that something that if M&A -- if the bid out there is really attractive, that you'd potentially look to monetize and really clean up the balance sheet and accelerate in the Eagle Ford?

Thank you.

Let me -- I'm going to go backwards through your questions.

A, we don't need to clean up the balance sheet.

We got almost the strongest balance sheet in our peer group.

And we have no intention of diluting our shareholders.

We got an operating plan that doesn't require us to do that, so we are not in a position where we need to go sell assets to clean up the balance sheet.

With that said, we don't sell oily inventory at the bottom of a price cycle.

Everything we own is always for sale, and certainly we look at all the opportunities to maximize value (multiple speakers).

We believe that our Permian acreage is very high-value acreage, that there are significant additional intervals that we can prove up there that will expand the value of that in that that piece of property will be worth a lot more money at higher prices.

And so at this point, we don't see any compelling reason to be selling our Permian position.

In fact, we're going to get back to drilling it.

As quickly as we can get within our cash flows, we're going to get back out there and do it.

And we're excited about the opportunity that we think to potentially double or more our inventory in the Permian, and as you said, our acreage is in the very best portion of the Wolfcamp B trend in the entire Midland Basin and the lower Spraberry stuff looks even better to us.

So, again, we are expanding inventory.

That's the game we are playing.

Our balance sheet is in good shape, and clearly we are not really in the mode of selling oily inventory at the bottom and that's what we would be doing if we sold that asset right now.

Yes, fair enough.

Thank you.

Michael Hall, Heikkinen Energy.

Good update.

I think Matt addressed a number of my questions.

One question, though, on the 2016 outlook, just curious what sort of additional color maybe you could give on the activity level that would be implied by that within EBITDA spending level.

Would you drop rigs to get there, drop rigs further and rely more heavily on drawing down that [buck] count?

Or just any additional color around the activity and investment levels associated with that high-level guidance.

Sure, happy to do that.

I think our current plan for 2016 would envision something between a seven- and an eight-rig program, so very similar to our program, say, in the third and fourth quarters of this year.

As we have said, we think we will be spending around our EBITDAX number, which, ballpark number, is in the $1 billion kind of range.

We will certainly be drawing down DUC count in 2016.

We're building out -- we're actually going to end the year as, I think we said, with even a higher DUC count than we had planned, so we are -- okay, bad joke, we are getting our DUCs in a row.

And we are planning to complete a lot of those wells in 2016, which certainly increases our capital efficiency during what we think is basically the bottom of the trough for cash flows.

And then as we come through 2016, our projections would suggest that we're going to be growing quarter over quarter in 2016 and we're back on a growth trajectory at that point.

So, I think you can expect that we will be drilling in the Eagle Ford at a reasonable rate, that we will have some Permian activity and some Bakken activity in that mix, and, again, I think we will be growing quarter over quarter during 2016.

Very helpful.

Appreciate it.

And, I guess, is it maybe too early to ask, but if we were to, let's say, strip out the Mid-Con for 2015, is that year-on-year annual growth as well?

I know you threw in the exit rate versus exit rate?

I'm just trying to --

No, I don't.

I think we will be pretty much flat on retained assets.

Year over year.

Year over year.

That 10,000 barrels a day is hard to come up with, but I think on an average year-over-year basis we will be pretty much flat on retained assets, but --

And nice growth exit to exit.

Yes, the exit-to-exit growth looks pretty good on the scenarios we are looking at.

Okay, that's very helpful.

And then, I guess in the Eagle Ford, the stage spacing differences you outlined, is there any cost differences between the 330-foot versus 165-foot or you are just spreading out a similar amount of sand over more stages or how does that work?

It does cost more money to pump more stages, and a little more wireline work and a little more time on location, although, quite frankly, our efficiencies have gotten so high out there now.

We have had days we're pumping 12 stages a day, so just -- numbers that two years ago, three years ago, you would have just laughed about that you were never going to get there.

So our well costs are continuing to get down.

It is a little more expensive to pump tighter stage spacing.

It is one of the reasons we are really, really interested in this interstage diversion products that we are experimenting with.

Just basically, you can get the same kind of impact.

To be clear, what we are chasing there is more frac initiation points, spreading that sand out better near the wellbore.

And the reason that's so important if you get a more complex frac close to the wellbore and you have less frac extension, you can put these wells closer together.

That's what we are all chasing.

And our surface calculations that we are doing are suggesting to us that that's working for us.

Okay, so the sand first stage is static, I guess, between the two spacing configurations?

We have done it -- yes, I am sorry to interrupt.

We have done it several -- two ways.

In some of these wells, we actually just cut the sand per stage in half or the volume per stage in half, and in a couple of the wells, we actually stepped up the sand -- the frac size per stage a little bit to see what the impact of that is.

So we are going to be looking at data that for a half-stage exact same job, essentially, and half-stage slightly larger job, and then looking at those results and seeing, okay, given the cost of each of those, does that work?

I will tell you early on the results, there are some differences and it pretty much tracks with how much money -- the more money you spend, the better the well you got, but the results are so close together this early in the life of the well, it is probably too early to draw a conclusion on economics there.

Okay, fair enough.

Lots of tinkering.

Sounds good.

And then, oil differentials were pretty improved in the Eagle Ford and the Rockies.

Are those pretty sustainable, do you think?

Will the Eagle Ford track the LLS/WTI differentials still, you think, or how -- just any additional (multiple speakers)

I know the Eagle Ford looked better.

I would emphasize to track the LLS there.

I think the LLS versus WTI was a little different during the second quarter, so I would just point you to that.

Yes, we sell Eagle Ford oil based on an LLS benchmark, so WTI is interesting, but it's not necessarily relevant.

Okay, and then, do you have a completion count, by chance, in the JV that is associated with the production there?

46 net?

Is that a net number?

Gross, gross.

46 in the (multiple speakers) -- yes, I am looking at James Edwards here.

So 46 gross wells in the APC JV in the second quarter.

Okay, that's the number.

And those would be at varying working interest for us.

Do you have an average working interest, by chance?

Not at hand.

Fair enough.

I will follow up.

Appreciate the time.

Mike Scialla, Stifel.

Jay, on the pilot number 1, if that continues to track your 625-foot spaced wells, what is the next step there?

If I heard you right, it sounds like you feel pretty confident about the upper Eagle Ford potential?

Is the plan to go try an upper Eagle Ford well in between those lower Eagle Ford wells?

Or can you extrapolate from the other pilots that you are doing, if those work where you are testing upper Eagle Ford and lower Eagle Ford tests, can you assume that it is going to work in that eastern area as well?

Great question, Mike.

I think in that eastern area, there's a couple different things we are doing.

As I said earlier, a number of the wells we drill over there do have some -- were completed in the upper portion of the lower and they tail up into the upper.

So as we look at the opportunity, say, for infill and development there, certainly for infill, what we're probably looking at is more of a lower, lower Eagle Ford infill program between those existing wells.

In the undeveloped areas, certainly, we need to look more closely at landing some wells more staggered lower, upper, lower, upper, and that's the test we need to do that we probably won't get done this year.

It's probably a 2016 kind of time frame for us.

Obviously, we will learn a lot from the pilots we're doing a little farther to the west where we are doing exactly that to see how that works out.

When we were planning this initial pilot, we were really focused on just testing spacing in a near well -- near landing zone area, and so we didn't get that piece in.

I do think there is potential in the East in an upper, lower staggered to potentially even push these wells closer together, and at some point we need to test that.

If you look at the pilot tests -- I'm going to look for a slide here, I think that's slide 8, is that right, slide 8 or 9 where we show the pilots.

I think it's pilot number 3, which is in the -- it is just a little bit south of the East area.

We call it a South area test.

That well is a lower, upper, lower staggered test.

I think it is a five-well test, if I remember right.

Is that right?

So we will have some true lower, upper, lower.

Those wells will be at a 312-foot planned-view spacing, so in the same lower or upper landing zones, it will be at 625 feet.

So, here we will be testing a W, essentially, at 312-foot planned view versus the 450 that we just showed here.

So those results will be really informative and help us see, okay, do we -- how much harder do we want to chase even tighter lower, upper stagger in the East?

Got it, okay.

Then switching over to the Bakken, it looks like you're getting some pretty encouraging results there.

You have got a couple of stepout wells planned, I believe, to the south.

I am just wondering the timing of those.

And if the nine wells continue to track your Three Forks -- or, I guess, beat your Three Forks type curve, if it looks like these stepouts work, is that enough data to say this is likely going to work over the majority of your acreage?

Well, the two wells that you are referring to that are farther south are going to be completed in August and September, so we will have data -- give us 90 days on that and we will have some data there.

I think based on what we have seen so far with Three Forks wells down in that area, we're pretty -- we have a pretty high chance that those are going to work for us.

Type curves this early are really tough and we're resisting drawing a type curve through those Bakken wells so far, just because a lot of them are on the north end and it is still early.

But yes, we have certainly seen a lot of encouragement there.

And I think by the time we get to summing up our inventory at year-end, we're going to be adding quite a bit of Bakken inventory.

Very good, and then last one.

You spoke a little bit about the Permian.

I believe you had -- and it sounds like you are very encouraged on the lower Spraberry.

I believe you drilled a middle Spraberry well before you let that rig go.

Has that been completed yet and any early signs there?

We haven't completed that well, Mike.

It is in our row of DUCs.

Got it.

Okay.

Thanks a lot.

Congrats on the quarter.

Chris Stevens, KeyBanc.

I was hoping you could maybe break down a little bit the components of the inventory expansion opportunity out in the Eagle Ford.

You mentioned 25% you could add by the downspacing, but I guess how much could you add from the infill between producing wells?

How much from staggering in the lower, and then, also, how much of the upper Eagle Ford?

Well, now, if you really add all this up and you look at, okay, what could it all be, you are talking numbers that are two or three times our current inventory.

And so, it just depends on what spacing you end up with and how many upper versus lowers you drill.

The current number of wells we have already drilled at, say, 900-foot spacing is in the 100, 150 kind of range, I think, so there is a couple -- probably 125 infills or something like that you could do.

And the numbers get really big.

The point I wanted to make with that 25% number is, look, that is just easy math.

And in fact, what we are testing is orders of -- really an order of magnitude different than that.

So we haven't laid out -- even for ourselves, really, we haven't laid out a completely unrisked stack four wells in every -- 12 wells in every section kind of thing because, again, it is that 2D versus 3D problem, but the numbers are big.

What we are hoping people will get out of this is that when we say double, that is not an unreasonable expectation.

The problem is if you're going to throw out some really big numbers, then everybody will go off and risk them to nonexistence, and that doesn't really get you anywhere, either.

But I really do think if you think about what we have shown on our upper Eagle Ford productivity, what we are showing about the potential to move these wells closer together with better completions, that a double is a pretty easy thing to get your mind around.

And if we can get people to accept double, for right now that's fine.

Okay.

And just looking at the upper Eagle Ford, how many wells do you have producing at this point?

And, I guess, how have those wells been trending?

And are there certain areas where you think the upper Eagle Ford might look better than the lower Eagle Ford and vice versa?

If you look at standalone, completely landed in the upper Eagle Ford only wells, I think we have showed data on four that are out there and those wells are performing well.

The reality, as I mentioned earlier in the discussion, was that a number of our wells that were completed in the lower actually have significant portions of the lateral in the upper.

And, in fact, a number of our wells in that eastern area, the north part of our eastern area, row 1, a lot of those wells, about half the lateral is in the upper Eagle Ford.

So we know that the Eagle Ford is highly productive in the upper.

That's really not a question for us.

We drill those standalone wells to prove it to people, but we know the upper can make wells.

We are confident that we have some of the very thickest, energetic Eagle Ford pay on the entire play.

The pilot testing, as we go forward, will help us demonstrate that to people, and then what's really going to be interesting and fun is as we start to stagger these wells upper, lower is how close we can get them together in planned view, and that will end up determining your earlier question about how many wells are there really out there, and we will get more and more data on that as we go forward.

And just quickly touching back on the Permian, do you have an update on what you think you can drill wells for out there and the EUR expectations for the Wolfcamp and lower Spraberry at this point?

We think we can drill a 7,600-foot well out there right now for around $7 million.

And frankly, we don't compete in the EUR contest with people, but if you look at our wells, and I would encourage you to look at the public data on our wells, and plot them over anybody else's curves, publicly presented curves, these are big wells.

I'm not going to tell you the kind of numbers other people might tell you for that, because we don't use the kind of tail declines that other people use in their forecasts, but our production lays really nicely over some really big well curves that other people are putting out.

Right, and you also mentioned the infill out there.

Do you know what spacing you plan on using?

Well, we are still doing work on that.

In the lower Spraberry, again, we have about a 300-foot thick section there and I think you got the potential to put something like 12 wells per section in there pretty easily.

We really need to get our activity level up higher and we are doing a lot of stimulation right now as we are in this downtime period to tune up our plan.

One of the interesting issues with the Permian is when we get back to drilling there, we really want to start drilling at much higher -- at much denser spacing, which means you get a lot of wells drilled before you complete any of them.

And that is a bit of an issue here when you're in this cash-on-cash kind of business we're in right now, you want to turn cash, but certainly we want to get to an optimum development, which will be much denser, we think, in several of those intervals.

Thanks a lot.

[Brian Bailey], Capital One.

A quick question, on the $1 billion EBITDAX kind of ballpark that you mentioned earlier, Jay, for next year, what price deck -- or can you say what price deck that assumes?

Yes, we are running strip on that.

The comments we made were as of yesterday's strip.

Okay.

Yes, I apologize, but I am being told here we need to limit everybody to one question because we're running out of time.

So I'll give you another one, though.

Okay, real quick, then.

The new plug-and-perf type curve, the green line in the presentation, I believe the red line from the sliding sleeve implied a 400,000-barrel EUR.

Have you mentioned or can you quantify what the green line represents?

It is up about 15%, I believe, is the number.

All right, that's great.

Thanks for taking my question.

Paul Grigel, Macquarie.

Morning, Jay, just one quick one.

On the DUCs, getting them in a row.

What would you guys need to see to either do those ahead of time before 2016?

And then, is there any constraint, be it geologic, operational, or regulatory, on when you complete those wells or how long they can remain uncompleted?

There are some constraints.

We are not going to have a problem with that, based on the way we have it planned.

I don't think we will pick up and start completing during this calendar year.

We're pretty committed to our -- where we are on our capital program versus cash flow at this point and I don't think you'll see us make a meaningful effort to get after a lot of that until 2016.

Okay, and any color on what those constraints could be if oil were to stay lower for longer?

Well, there are some issues in North Dakota.

I think it is a year -- you have a year, if I remember right, to -- a running basis to get your wells completed.

So, we would have to get after it at some point, but we are not in any jeopardy at this point.

Okay, perfect.

Thanks for the time.

Andrew Coleman, Raymond James.

The question I had was looking at the CapEx numbers for Eagle Ford and Bakken, given the soft guidance there, flat -- I guess flat to nominal growth year on year, staying within cash flow, is there any incremental facilities capital that would be needed to be added to those well costs if you were to raise your growth expectations at all?

Are we talking Eagle Ford specifically, Andrew?

Is that the question?

I guess it is both.

I'm just curious what the runway is on the infrastructure gas handling, water handling, et cetera, as you look at those two basins.

Well, if you look at the Eagle Ford, we don't pay for our gathering stuff, so there will be no incremental capital to us.

We are continuously in the process of working with our provider there to get ahead of us as we look at this, and certainly we are sharing various scenarios with them about how fast we might be going in order to make sure that we have enough capacity out there, and they're -- BTC has really been good to work with and we are doing great there.

On the Bakken side, I don't really see an incremental cost.

Every well we drill has a certain amount of facility costs with it; it is pretty much a standalone well development.

At some point, we do want to do some water handling infrastructure up in the Gooseneck area, but that is probably a couple years off at this point.

Okay.

And non-op Eagle Ford, there is -- they have been spending some money and certainly will spend a little bit, but obviously our working interest there is fairly low.

Sounds good.

Thank you very much.

You bet.

So, hey, I think that's the last question we had and last time.

I just want to thank everybody again for the time they spent this morning and I know you're busy and we appreciate your time and attention.

Thank you very much.

Ladies and gentlemen, thank you for attending today's program.

This does conclude today's conference call.

You may now disconnect.

Everyone, have a great day.