SM Energy Company (SM) Q2 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the SM Energy Second Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we'll conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] I would now like to turn the conference over to your host for today's call, David Copeland, General Counselor. Sir, you may 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'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations, and assumptions regarding our future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted on 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, Senior Director, Investor Relations. I'll now turn the call over to Jay.

Well, good morning. Thanks to all of you for joining. Man, we have a great quarter and our results year-to-date provide more evidence of our continuing top-tier performance. I'm 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've 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've seen encouraging new well results in our core development areas, which we believe will translate into material growth in our economic drilling inventory. I'm 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're positioned to perform differentially, we believe, in 2016. Our current projections indicate that our portfolio can delivery production growth during 2016 investing only our EBITDAX even assuming today's depressed strip pricing. With that, I'll 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 in associated higher production combined with achieving sizable cost savings and LOE went 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'd indicated the production would go down about 5% from the first quarter due to plant maintenance and simultaneous operations that would require Eagle Ford [indiscernible]. 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've raised our annual production guidance from a midpoint of just under 63 million BOE to just under 63 million BOE. This implies state ahead production of about 28.3 to 30.8 million BOE which will reflect first of all the step-down 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 the 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 in to efficiencies and cost savings. First, we are rebidding and negotiating the best possible cost at all levels of the company and we're seeing real savings across the board. Secondly, our Williston team has driven cost efficiencies in our acquired property significantly below the previous operator on which our cost forecast was based. Primarily, savings and reduced water hauling costs. As a result, we've 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 the 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. CapEx activity was heavily weighted to the first half of the year with roughly two-thirds of the 2015 program now completed. Expenditures totaled $819 million year-to-date. We started the year with 17 rigs and a higher 2014 cost structure. We're 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 non-operated properties and for higher partner non-consents. 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 non-consents 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 reflected the revolver. Also, during the quarter, we have a few timely bond transactions. We redeemed all of our outstanding $350 million, 6.625% senior notes that were due 2019; and issued $500 million, 5.625% senior notes due in 2025. These actions termed out our unsecured debt with the nearest maturity now in 2021, and it reduced our average coupon rate to 5.9%. Lastly from me on slide 8 regarding hedges. We added NGL hedges in the quarter specifically relating to propane and butane. There's a schedule with details of all of 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, and 46% of NGL or gas to 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 hedged revenue and added $15.3 million of second quarter realized hedges. So, now, I'll turn the call back to Jay to discuss more details on our operations and our growing inventory. Jay?

Thank you, Wade. Well, 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 in Permian acreage while we've 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'm 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 than 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'm going to start with our operated Eagle Ford testing program. Slide 10 shows the number and geographic spread of the pilot test 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 plan 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 inter-well interference at lower spacing using the frac designs we had at that time. Now, as we've shown with well test and discussed in previous calls and conferences, we now know that the upper portion of the 25 to 30-storey-high Eagle Ford shale in our area is a much more productive reservoir than we originally believed. And our pilot testing is designed to prove that up broadly across our acreage. In order to fully understand the pilot test we're now performing, however, it's also important to understand how far we've come in the last several years in improving our completion designs. As we discussed in our completion Lunch & Learn in May, we can [Audio Gap] and model the amount of [ph] prop fracture surface area we generate with our fracs. And we've 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've increased sand volumes in our frac jobs to up to more than 2,000 pounds per foot of lateral length, and we've optimized completion fluids. More recently, we've been testing smaller sand sizes, reduced stage spacing, and inter-stage diversion in our standard stage spacing completions. All of these completion improvements are driving better well performance, and we know that it contributed to our production outperformance in the second quarter. So, our pilot test program is intended to progressively prove up additional inventory by employing our high surface area closed 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'll have a progression of results to share over the next few months and quarters. Our first test, which results we can discuss, is labeled as Pilot #1 and is a 14-well test of tighter wells spacing in Lower Eagle Ford landing zones. A depiction of Pilot #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 referred to as Galvan Ranch. I should note that out 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 a pilot number 1 area is 625-foot plan view lateral spacing. And in this test, we're comparing wells drilled at that spacing with some drilled at 450-foot plan view spacing. The lateral length 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 thousand foot of lateral from a 625-foot and 450-foot spaced wells. There are nine 625-foot space wells in the average 625-foot curve and five 450-foot spaced wells in the 450-foot curve. As you can see, the rates 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're seeing flowing pressures as high or higher on the 450-foot wells as on the 625s. So, no indication of increased inter-well interference yet with down spacing. Now obviously, these early results were 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've 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 165foot stage basing completions, which is half our standard 330-foot stage basing. So, what should investors be thinking about the results of these tests so far? Well, simple math is that a move to 450-foot planned new spacing versus our current assumptions across the Eagle Ford not including infill potential between existing wider-spaced wells would increase our previously-stated operated Eagle Ford drilling inventory by about 25%. However, it's 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, leaving us to that doubling that we're 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're 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 inter-well interference. In Pilot No. 5, we're 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's 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 that results, and I should just convey that they are very encouraging as well. Now, I'm going 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've 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 geological 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're 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 days spud-to-rig-release, 10,000-foot lateral Bakken well. We are obviously very encouraged by those results and believe we're well underway to doubling our current inventory of 400 gross economic locations in this area. The last piece I want - update I want to show you today is specifically on improvements and completions and what we're seeing there in our Bakken and Three Forks wells. And here, we've 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 Country 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're 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'd just like to reiterate a couple of key points in closing. Our great performance this quarter is a 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're seeing the kind of early results we had hoped for in our inventory test pilots. And we're driving costs 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'll be happy to take your questions at this point.

[Operator Instructions] Our first question comes from the line of Pearce Hammond from Simmons & Company. Please proceed with your question.

All right. Good morning, guys. Great quarter. And thank you for taking my questions.

You bet, Pearce.

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?

Yeah. Pearce, this is Javan, and we do think it'll be down and roughly to level of our EBITDAX, that's right about where we think it'll 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 cost 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 and 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 had been on optimizing the trucking and water out of those assets and just where we drilled wells and how we 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 cost per barrel and our people have really stepped up to the plate and driven that number down. We're well below our budget 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.

Our next question comes from the line of David Tameron from Wells Fargo. Please proceed with your question.

Hi. Good morning.

Hi, David.

So, Jay, just to make sure, so when you're talking about your staggered test, are you doing kind of one [indiscernible] 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 like a Chevron-type pattern or can you give me a little more? Just to refresh my memory on that.

Well, David, yeah. This is Javan. That is probably the easiest way to think of it. There are several different landing zones in the Lower Eagle Ford.

Yeah.

In a particular case, these wells here, we didn't stagger much. There was a little bit of different variation between the landing zones. I think what's really driving the well performance, the lack of interference we're seeing earlier on here is that our completion designs are just so much better than it were a couple of years ago. Look, I know that there was a lot of - there were some guys who went out three years ago - two, three years ago, with all their frac designs, and went to a very tight spacing and were very aggressive in their pace of development. And I'm sure a lot of those guys wished 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've got a lot thicker pay than a lot of people. We've got a lot of undeveloped, very thick pay, and quite frankly, we are a learning machine. And we are 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's 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, how many pilot tests? I mean if you - if these pilot tests work this year, I mean you're talking about doing these across the basin, at what point do you feel comfortable saying it's...

No. I...

...in a widespread program?

That's exactly the same kind of question we're asking ourselves, how much do we have to have to - you don't want to ever claim victory prematurely or - I will say that in a sense, a bit of a downturn that we've had in activity levels, certainly our cash flows have come down, too. We're 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're going to be looking very hard at what are the impacts of this on our infrastructure planning. And we'll be working with our infrastructure partner there to think about, okay, if we go to really intensive development per section, what does that mean?

Yeah.

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 the sort of a very simple single-landing zone, planned U-type spacing to more 3D [ph] chest if you'll say that way in our development. But man, really exciting, a 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, 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 just a final question, just as I think about the - I guess the upper part of the lower and realize that I'm generalizing here, but what's the - if these were not to work, I mean, obviously, the initial results reflect the [ph] work-in but what's the geologic risk? I mean, is it fracking into that? I don't know what that frac barriers right above the upper part of the lower - between that and the upper, but is that - could there be something in there that you're fracking into or why looking six months down the road would this not work? I think the biggest risk of 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 over drilling. So, you want to make sure that you don't go nuts here and go to a rapid-pace, down-spaced development too quickly. I think a lot of those risks are mitigated for us because we're not talking about a single landing zone development anymore here. We're talking about staggering. We know that the Upper is productive. One point I want to make here, as we went back, as we've gone back and really looked at how we've landed a lot of our Lower Eagle Ford wells, we did land a number of them toe up. We'd come in and then start drilling up dip. 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's a lot of risk from that standpoint of if we stagger these wells some, and we're just careful not to down space too far, I think we can manage that risk. Again, a little bit of slower activity period we have here gives us the chance to do thorough testing and to make sure that we're not getting ahead - or too far over our skis. But I think it's something that we can clearly manage. Frankly, we've 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'll let somebody else jump on. Thanks. Thanks for all the color.

You bet.

And our next question comes from the line of Subash Chandra from Guggenheim Security. Please proceed with your question.

Yeah. Thanks. Yeah, Jay, again, nice job. Your 3D [ph] chess, nice analogy there. Could you remind me if you have or plan to do sort of a large-scale micro seismic survey in monitoring the results?

Yeah. Subash, we've done a lot of micro seismic out there and have done - and have tracked a lot of it. At this point, we don't have a lot of micro seismic to do associated with this. We're really more focused on just getting wells landed and completed in the various areas, and focusing very hard on this surface area, what we call, [ph] 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 frac, about where a fracture is going, and how that's going without having to spend a lot more money on micro seismic at this point.

Okay. And so, in reference to slide 12, just want to confirm, so the 425s versus the wider space, the completion recipe on the infills were actually less stimulated than the offset. Is that what you...?

No, no, no. I think that's...

That's how you think about [indiscernible].

Yeah. The 625 wells were generally completed at 330-foot stage basin. We did have some in there that were done at 165-foot stage basin. So, it's sort of a mix. The 450s were essentially all done at the 165-foot stage basin. 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 of different tests going on. 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're doing right now is - and we've done some work already, I mentioned it, I think, was that we're doing some work looking at wider stage spacing, but using inter-stage 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 inter-stage diversion on all those wells based on the results we've seen so far. And that would be a less expensive way to basically accomplish this same kind of lower stage spacing. So, again, we're just going to keep driving on innovating on improving these completions. And there's more stuff to come on that.

Oh, okay. At Divide County, the water handling, I imagine, you've gone from, perhaps, trucking all of it to maybe a better way of disposing of it, and if that's correct and if that's an ongoing project or if it's 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 [Audio Gap] 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's actually room to reduce costs even further as we go down the road. But we'd 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'll take a little bit of issue with your comment, competitive. The reason it is what it is because we didn't pay any capital for this process and so our costs are higher because we didn't pick 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 of that five years, there is a significant drop in our gathering fees. Basically, we get to the point where we help the midstream folks pay for their system, and we do see a drop back in like the 2021 timeframe where we see a pretty significant drop in gathering fees.

Okay. Yeah. That's a very good - that's a very fair point. True. And then finally, do you have Eagle Ford non-op production breakdown this quarter or...

It would be [indiscernible] do we break out...

The non-op.

No. Sorry, Subash. I don't have it off the top of my head here.

Okay. All right. Thanks again, guys.

And our next question comes from the line of Matt Portillo from TPH. Please proceed with your question.

Good morning, guys.

Good morning, Matt.

Just two quick questions on guidance into the back half of the year. I think previously on production, you had mentioned kind of an expectation coming into the third and fourth quarter that volumes would be down 1% to 2%, and I think kind of implied it, as you mentioned, in the guidance you've provided now that volumes could be down 2% to 3% per quarter. So, just wanted to get a sense of kind of what's driving the change there especially given the well outperformance and kind of how you guys think about that.

Yeah. This is Wade. I mean, we - 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 didn't - had not completed the Mid-Con divestiture yet. And for now, we're just - that's - the activity is reduced and we're reflecting that in our guidance. So, that's kind of it is what it is.

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

Again, kind of looking at the guidance numbers that implied that there's a pretty significant ramp coming into Q3 and Q4, but kind of all the commentary and the calls suggested this is structural. Can you just give us some incremental color as we think about kind of Q3 and Q4 guidance around LOE? What's [indiscernible] that higher?

Sure. I mean - look, I mean, obviously, we're very pleased with the second quarter results, significantly below what we expected. We have lowered the guidance somewhat. I think at this point, we're 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 can provide some context around what drove that, I guess, specifically. I know you guys do midyear reserves. Just trying to get a little - a better sense of kind of what was the change there, whether it was kind of PUD or PDP kind of revisions, just trying to get some color.

Yeah. Certainly nothing related to PUDs. I mean, we do look at our reserves again at midyear and that's actually essentially PDP only. I mean, 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 kind of in anticipation. I will say that back to the cost guidance, the cost following so significantly, there is a chance that'll have an offsetting effect when we go into year-end reserves and really do a much more thorough analysis at that point. That's really the reason.

Thank you very much.

Sure.

And our next question comes from the line of Mike Kelly from Global Hunter.

Hi. Good morning.

Hey, Mike.

Hey, Jay. Great ops update. And I 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'd ultimately expect to see out here. And I respect that its early days here. I 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 can ultimately stack up against your Permian acreage, which I think is commonly thought of as amongst the best shale acreage in the U.S., how Eagle Ford can ultimately compare [ph] versus that?

Well, that's a great question. And I'll just say up-front, we have been really surprised as we've gone through sort of our mid-year updates on type curves and well costs and how well our returns on a lot of these - on the best portions of our acreage and a lot of it's really good. But on the very best portions, how high those returns have continued to stay. And it's a little scary frankly from an industry standpoint that when we look at a quality acreage like ours that we can still make really decent returns. And a lot of that is 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're [indiscernible] these wells now for under $5 million apiece and it's really an astonishing number. So, they will have very high returns. In comparison to the Permian - and honestly, when we run the numbers today, they're very, very similar. Our Permian wells do have really high returns, particularly, at lower Spraberry stuff. And we're going to get back to drilling that as quickly as we can at high density. It keeps rolling in pieces here. But I think if you'd stack everything up today, our Bakken, Gooseneck stuff, our Permian lower Spraberry stuff in this area and Eagle Ford are all going to have very, very good returns. Obviously, everything - the values of all these stuff are down because cash flows are down. But when you look at returns on capital employed, these things all have pretty good returns apiece even at low price.

Got it. And I think it might beg the question a little bit if, ultimately, the returns are very similar to Permian, just look at where the stocks trade right now. I think you guys sort of really - one of the cheapest names in the midcap space and your Eagle Ford inventory might be doubling or tripling here with competitive returns. Is the Permian makes sense [indiscernible] have in the portfolio, or is that something that if M&A is to be bid out there, it's really attractive that you potentially look to monetize or really clean up the balance sheet and accelerate new? Thank you.

Well, let me - we'll go back first to your question. A, we don't need to clean up the balance sheet. We got almost as strong as balance sheet in our peer group. And we have no intention at diluting our shareholders. We have an operating plan. It doesn't require us to do that. So, we're 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. We believe that our Permian acreage is very high-value acreage, that there are significant additional intervals that we can prove out there that will expand the value of that and that that piece of property would 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 can 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're expanding inventory. That's the game we're playing. Our balance sheet's in good shape and clearly, we're not really in the mode of selling all the inventory at the bottom, and that's what we would be doing if we sold that asset right now.

Yeah. Fair enough. Thank you.

Okay. Our next question comes from the line of Michael Hall from Heikkinen Energy. Please proceed with your question.

Thanks. Good morning.

Morning, Mike.

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 grade to get there, drop it further, rely more heavily on drawing down that [indiscernible] count or just any additional color around the activity and investment levels associated with that high level guidance.

Sure. Well, I'm happy to do that. I think our current plan for 2016 would envision something between a seven- and eight-rig program. So very similar to our program, say, in the third and fourth quarters of this year. As we've said, we think we'll be spending around our EBITDAX number, which ballpark number is in $1 billion kind of range. We will certainly be drawing down duck count in 2016. We're building out. We're actually going to end the year as I think we said with even a higher duck count than we had planned so we're - okay. Bad joke. We're getting our ducks in a row. And we're 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'll be drilling on the Eagle Ford at a reasonable rate that we'll have some Permian activity and some Bakken activity in that mix. And again, I think we'll be growing quarter-over-quarter during 2016.

Very helpful. Appreciate it. And I guess, is it may be 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? And are you through in the exit rate versus exit rate? I'm just trying to...

No. I think we'll be pretty much flat on retained assets.

Year-over-year.

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

And nice growth exit-to-exit.

Yeah. Yeah. The exit-to-exit growth looks pretty good on the scenarios we're looking at.

Okay. Very helpful. And then I guess in the Eagle Ford, the stage spacing differences you outlined, is there any cost differences between 330-foot versus 165 or is it spread now similar amount of money 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. I mean we've had days we're pumping 12 stages a day. So, just - I mean, the numbers that two years ago or three years ago, you would have just laughed about that you're never going to get there. So, our well costs are continuing to get down. It is a little more expensive to pump tighter stage basin. It's one of the reasons we're really interested in these inter-stage diversion products that we're experimenting with because basically you can get the same kind of impact. And to be clear, what we're 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, you have less frac extension, you can put these wells closer together. That's what we're all chasing. And our surface area calculations that we're doing are suggesting to us that that's working for us.

Okay. So, the sand per stage is static, I guess, between the two spacing configurations?

We've done it. Yeah. I'm sorry to interrupt. We have done it several - two ways, I mean. In some of these wells, we actually just cut the sand per stage and a half or the volume per stage and a half. And then, in a couple other 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're going to be looking at data that for half stage, exact same job essentially, and half stage, slightly larger job, and then, looking at those results and saying, okay, given the cost in each of those, does that work?

Yes.

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

Okay. Fair enough. Lots of tinkering. Sounds good. And then, oil differentials were pretty improved in the Eagle Ford and Rockies. Are those pre-sustainable you think? Will the Eagle Ford kind of attract the LLS, WTI differentials still, you think? Or how things [indiscernible]...

I know the Eagle Ford looked better. I mean, 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.

Yeah. We sell Eagle Ford oil based on an LLS-benchmark. So, WTI is interesting, but it's not necessarily relevant.

Right.

Okay. And then, do you have a completion count, by chance, in the JV that's associated with the production there?

JV?

46 net? Is that a net number?

Gross.

Gross. 46 in the [indiscernible]...

46.

Yeah. I'm looking at James Edwards here.

Yes. So, 46 gross wells in the APC JV in the second quarter. Okay. That's the number. And those would be a varying working interest for us.

Do you have an average working interest, by chance?

Not at hand.

Fair enough. So, I'll follow up. Appreciate the time.

And our next question comes from the line of Mike Scialla from Stifel. Please proceed.

Yeah. Good morning. Jay, on the Pilot No. 1, if that continues to attract your 625-foot spaced wells, what's 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're doing if those work where you're testing upper Eagle Ford and the lower Eagle Ford work test? Can you assume that is going to work in that eastern area as well?

Great question, Mike. I think in that eastern area, there's a couple of different things we're doing. As I said earlier, a lot - a number of the wells we drill over there do have some - were kind of completed in the upper portion of the lower and they tail up into the upper. So, as we look at the opportunities, say, for infill and development there, certainly for infill, what we're probably looking at is more of a 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 up or 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 timeframe for us. Obviously, we'll 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 stagger 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, that's slide 8. Is that right? Slide 8 or 9, where we show the pilots. I think it's pilot number three which is sort of in the - it's sort of just a little bit south of the east area. We call it the south area test. That well is a lower - upper lower staggered test. I think it's a five-well test, if I memorize everything. So, we'll have some true lower - lower, upper lower. Those wells will be at a 312-foot plan view spacing. So, in the same lower or upper landing zones, it will be 625 feet. So, here, we'll be testing a W essentially at 312-foot plan view versus the 450 that we just showed here. So, those results, they'll be really informative and help us see if, okay - how much harder do we want to chase even tighter lower/upper stagger in the east?

Got it. Okay. Let's switch over to the Bakken. Looks like you're getting some pretty encouraging results there. You've got a couple of step-out wells planned, I believe, to the south. I'm just wondering the timing of those. And if the nine wells continue to track your Three Forks or, I guess, bigger Three Forks type curve, it looks like these step-outs 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're referring to that are farther south are going to be completed in August and September. So, we'll have data. Give us 90 days on that, and we'll have some data there. I mean, I think based on what we're seeing so far with Three Forks wells down that area. We're pretty - we have pretty high chance that those are going to work for us. Type curves just earlier are really tough. And we're resisting - drawn the type curves for those Bakken wells so far just because a lot [indiscernible] on the north end, and it's still early. But yes, we've certainly seen a lot of encouragement there. And I think by the time we get to [ph] summon 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'd - and it sounds like you're very encouraged on the lower Spraberry. I believe you drilled the middle Spraberry well before you let that rig go. Has that been completed yet and early signs there?

We haven't completed that well, Mike. It's in our row of ducks.

Got it. Okay. Thanks a lot. Congrats on the quarter.

Thank you, Mike.

And our next question comes from the line of Chris Stevens from Keybanc. Please proceed.

Hey. Good morning, guys. I was hoping you could maybe break down a little bit the components of the inventory expansion opportunities out in the Eagle Ford. You mentioned 25% you could add by the down-spacing. 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 for the Upper Eagle Ford?

Well, now, if you really add all these up and you look at, okay, what could it all be, you're 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. And the current number of wells we have already drilled, let's say, 900-foot spacing is in the 150 kind of range, I think. So, there's 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's just easy math. And in fact, what we're testing is orders of - really, in order of magnitude, different from that. And so, we haven't laid out - even for ourselves, really, we haven't laid out a completely [ph] un-risked stacked four wells in every - 12 wells in every section kind of thing because it again is at 2D versus 3D problem. But the numbers are big. What we're hoping people will get out of this is that when we say double, that's not an unreasonable expectation. Because the problem is, we thrown out some really big numbers and 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've shown on Upper Eagle Ford productivity, what we're 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, right now, that's fine.

Okay. And just looking at the Upper Eagle Ford, how many wells 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?

Well, if you look at standalone, completely landed in the Upper Eagle Ford only wells, I think we've 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 one, a lot of those wells, about half the laterals 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 drilled those standalone wells to prove it to people. But we know the upper can make wells. We're confident that we have some of the very thickest, energetic Eagle Ford bay 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'll 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 [indiscernible] over at Spraberry at this point?

We think we can drill a 7,600-foot well out there right now for around $7 million. And, frankly, you know, we don't compete in the EUR contest with people. But if you look at our wells, and I'd encourage you to look at the public data on our wells, and plot them over anybody else's curves, publically-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 usually kind of tell the clients what 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're 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're doing a lot of simulation right now as we're kind of in this downtime period to tune up our plans. 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 state and 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 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.

And our next question comes from the line of Brian Velie from Capital One. Please proceed with your question.

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

Yeah. We're running the script [indiscernible].

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

Okay.

I apologize but [indiscernible] we need to limit everybody to one question because we're running out of time. So, I'll give you another one though.

Okay. [Indiscernible]. The new sliding - I'm sorry. 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 - can you quantify what the green line represents?

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

All right. That's great. Thanks for taking my question.

You bet.

And our next question comes from the line of Paul Grigel from Macquarie. Please proceed.

Hi. Good morning, Jay. Just...

Hey, Paul.

...a quick one on the ducks 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 via geologic, operational or regulatory on when you complete those wells or how long they can remain uncompleted?

There are some constraints. We're 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 capital - 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's a year - you have a year, if I remember right, to kind of a running basis to get your wells completed. So, we would have to get it faster at some point. But we're not in any jeopardy at this point.

Okay. Perfect. Thanks for the time.

And our next question comes from Andrew Coleman from Raymond James. Please proceed with your question.

Great. Thanks a lot guys. The question I had was looking at the CapEx numbers for Eagle Ford and Bakken, given the soft guidance there of 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 both. I'm just kind of curious like kind of 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 and stuff. So, there will be no incremental capital to us. We are continuously in a process of working with our provider there to get ahead us as we look at this. And certainly, we're 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 [indiscernible] really been good to work with, and we're doing great there. On the Bakken side, I don't really see incremental cost. Every well we drill has a certain amount of facility costs with it. It's pretty much a stand-alone 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 of years off at this point.

Okay.

In non-op Eagle Ford, they haven't spent some money and, certainly, will spend a little bit. But obviously, our working interest there is fairly low.

Good. Thank you very much.

You bet.

Hey. I think that's the last question we had [indiscernible]. I just want to thank everybody again for the time you spent this morning. And I know you're busy, and I 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.