Devon Energy Corp (DVN) — Q2 2015 Earnings Call Transcript

Thank you, Michelle, and good morning everyone. I hope you've all had a chance to review our operations report and management commentary at devonenergy.com, as today's call will largely consist of questions and answers. Also on the call today are Dave Hager, President and CEO; Tony Vaughn, Executive Vice President of E&P; Tom Mitchell, Executive Vice President and Chief Financial Officer, and a few other members of our senior management team. Finally, I'd remind you that comments and answers to questions on this call will contain plans, forecasts, expectations, and estimates which are forward-looking statements under US securities law. These comments and answers are subject to a number of assumptions, risks, and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance. For a review of risk factors relating to these estimates, see our 2014 Form 10-K and subsequent 10-Q filings. With that, I'll turn the call over to Dave Hager.

Thank you, Howard, and welcome, everyone. The second quarter saw Devon deliver another high-quality performance, continuing a trend that has generated top quartile results for our shareholders for the past several quarters. Before we jump into the Q&A, I would like to highlight a few key messages I would hope you would take away from our earnings materials. First, as many of you know, I assumed the role of President and CEO on August 1, and I want to be clear, the overall strategy that has led to Devon's recent outperformance remains unchanged. We will continue to operate in North America's best resource plays, deliver superior execution, and maintain a high degree of financial strength. As you can see from our second quarter results, Devon's premier asset portfolio continues to achieve significant operational improvements. Our three most active plays, the Delaware Basin, Eagle Ford, and the Anadarko Basin, all delivered outstanding well performance that exceeded type curve expectations with substantially lower well costs and reduced operating expenses. We expect this outstanding operational performance to continue. Our technical teams are laser-focused on getting the most out of our advantaged asset base with superior execution. This unwavering pursuit of excellence means we will continue to improve drilling times, maximize value per well with industry-leading completion designs, and optimize base production with best-in-class field operations. Importantly, we are keenly focused on maintaining our strong balance sheet, and we have the flexibility in our capital programs through scalable operations, minimal exposure to long-term service contracts, no long-term project commitments, and negligible leasehold expiration issues to do just that. Additionally, our advantaged capital structure is enhanced with the unique optionality EnLink provides with distributions approaching $300 million annually and the potential for dropdown proceeds. Given these benefits, we believe that in the current commodity price and service cost environment, we can deliver growing oil production in 2016 compared to 2015 exit rates, while spending within total cash inflows. So in summary, we are pleased with the way Devon is positioned to successfully weather the current environment and prosper in the future. Undoubtedly in the E&P business, you need great assets, outstanding operations, and a strong balance sheet to deliver sustainable long-term growth and differentiating returns for investors. With Devon, you have all three of these winning qualities. With that, I will turn the call back to Howard for Q&A.

Thanks, Dave. To ensure that we get as many people on the call as possible, we'd ask that you please limit yourself to one question with an associated follow-up, and with enough time at the end, you can reprompt, and we'll take additional questions from the participants. So, Michelle, with that we’re ready to take the first question.

Hey, good morning, guys. Another strong operations update today.

Thanks, Evan.

First, you've reiterated your full-year crude production outlook, but there are a few moving pieces. And I guess first, what drove the decision to dial back the Eagle Ford, given what must be strong economics at the strip, and what would you and your partner need to see to either complete some of those DUCs you're building or kind of add rigs there? I have a follow-up, please.

Hey, Evan, this is Dave. I'll take a stab at that. Tony may want to add some things to it. Directionally, well first off, our well performance is just outstanding. We continue to see outstanding well performance on the capital program and outstanding economics on that program. If you recall back at the end of 2014, we had temporarily increased from five to nine completion crews, and we jointly agreed with BHP that was a temporary measure to draw down the inventory, and afterward we would reduce the completion crews. In the current commodity price environment, with some drawdown in inventory, we felt that was appropriate. So directionally, we have a great partnership with BHP. We discuss a lot of things technically. They might have reduced the completion crews and they have the ability to do that in the way our agreements are written that they might have reduced the completion crews a little more than we have, finishing down to one crew. We agreed with the reduction, but they were trying to manage their total cash flows as a company when making that along with making a bit of a call I believe on commodity prices, and that was really the decision that was made. It had nothing to do with the quality of the opportunity. The well results are absolutely outstanding. I think we'll continue to see adjustments in rig activity and the completion crews in the future. So, Tony, do you want to add anything to that?

No, I think you summed it up very well, Dave. I think the one thing I would add is just the more our technical team has an opportunity to look at additional data through the work that we're doing in both Lavaca County and DeWitt County, both in the upper and the lower Eagle Ford, we continue to grow the resource base. So our expectations of the property are essentially growing. The wells, as you can see from our quarter-to-quarter reports, are just as prolific. If you look at all the public data, you're going to find that the BHP/Devon combination is really delivering the best-in-class well results that we have in the industry right now. So I think it's all about the pace of activity, and Dave summarized pretty well that we just dropped that pace down. We'll continue to hover at the five or six drilling rigs for this point, probably running from about one to three frac crews as we go forward. That's just the overall plan that we'll have for the second half of the year.

Great, thanks. And if I could, on a second question, you guys have reported another round of efficiencies achieved in the second quarter, 10% to 20% compared to the first quarter. Oilfield service prices appear to be coming down faster than you planned at the start of the year. So can you just talk about what's happening to the resulting savings? Does your reiteration of upstream CapEx and increased EUCs tell us there might be downside to that full-year CapEx, or how are you thinking about that relationship? Thanks.

I'd say the bigger impact, Evan, we don't see a lot of variation in what the CapEx will be for the remainder of this year. I think the bigger impact will be as we have a full year of those cost savings and then in 2016, what benefit that's going to provide to us. If you look at that and the CapEx savings we're going to have from the cost reductions, there are some other factors too that if you consider we can take the spending down in Canada probably by around $500 million or so. We will not have any activity essentially next year in the Mississippian or the Southern Mississippian, Midland Basin, Wolfcamp, some other plays. We had great economics, essentially being carried on a large amount of the well cost. But once we're beyond the carry, we won't be spending there. So you put all that together, and with an E&P capital spend this year of $4 billion or a little bit over, I tried to make the comment in my opening remarks that you could see that with the current strip that we have, the cash flow generated by that, plus the anticipated cash flow from any EnLink dropdowns, we are confident we'll be able to grow our oil production in 2016. Obviously, that's the vast majority of the margin we generate as a company. So there are a lot of positive factors indicating we can significantly reduce the capital requirements. I know there's some concern about when our hedges roll off, but we can continue to grow our oil production even when those hedges roll off due to the factors I mentioned.

That's real helpful, guys. Thank you.

I guess just following on from Evan's question, some growth at the strip, but if you truly went to, if commodity prices were awful, to maintenance levels, can you give us a sense next year of what that would be? Have you done that calculation?

We have all the flexibility. It depends on the definition of awful, I guess you'd say. Because we obviously calculate our cash flows at all sorts of various commodity prices, including those below what we're currently seeing on the strip. The key thing is we have all the flexibility in the world to adjust our capital however we want because essentially all of our acreage is held by production. We have no long-term projects we're committed to, no deepwater, no international, no heavy oil projects we're further committed at this point. We’re just wrapping up Jackfish 3 and we don’t have very many long-term rig commitments. So we can adjust our capital spending. I think when you look at the combination Devon provides of tremendous capital flexibility, some of the premier assets in North America, a strong balance sheet, and the strong execution we demonstrate every quarter, I think it's a unique combination in the industry.

Totally separate question then. Just on the Delaware obviously you're with the new completions and the higher proppant loads, you're increasing the IPs very strongly. You've also got a whole lot of downspacing that you have to do, testing different layers within each of the different zones. So I appreciate it's a little bit early, but the EUR feels like it should be rising. Is that an expectation that we should have given the performance that you have across the basin thus far, particularly in the basin?

Ed, I think the EURs are increasing as we continue to develop. We're doing a lot of work in the southern portion of Lea and Eddy County, which is really I think some of the best inventory we have in our portfolio. You're starting to see those characterized on the IPs, and we continue to outperform on those type wells that we deliver. We really have a great understanding now, I believe, of the relationship between frac design and size. Not that we're done with improving the recipe, but we've got a great relationship between the frac design, the resulting IPs, EURs, and most importantly the returns. That's why we are moving our completion designs back to about the 1,500 to 2,000 pounds per foot range because it affords us the most improved rate of returns. Our work in the northern portion of Lea and Eddy County, we're derisking and setting up development work that will be ready for us in 2016. We're starting to improve that design for those fracs. And on a well-by-well basis, that's continuing to improve as well. I think what the group is doing right now is we have a pretty good understanding of proppant loads and what that does to our completions. But we're not done. We’re still trying to improve upon our frac fluids, the spacing links, the clusters, and all the various things that go into a frac design. We'll continue to see improvements in EURs and returns.

Thanks very much.

Thank you, good morning and congrats on another good quarter. So thinking about 2016, I'm going to go back to that. Obviously, this isn't a revelation that the Street bear cases, you guys aren't going to be able to grow as fast in 2016 as some of your peers. One, I guess how would you address that? And two, you talked about being able to grow within cash flow. What type of limits or maybe a better way, what type of goalposts or framework are you thinking about yourselves and at the board level as far as how you want to look at 2016, given where the strip is at right now?

We have always thought that having a strong balance sheet is important, and we're going to continue to believe that is important, especially in these times of uncertain commodity prices. So directionally, we tend to think of our capital spending as having to be within the total cash inflows that we anticipate for the company. That would be both our operational cash flow plus any EnLink distributions and any dropdown proceeds from EnLink, such as the access pipeline or the other NGPL line highlighted in the operations report. So that's directionally where we start off the discussion. We will also look at the programs and see if there's any reason to deviate in a positive or negative way from that. We have the flexibility to do that given our strong balance sheet. But that's the starting point of the discussion. It's important to remember that our growth rate may not be quite as high next year, but remember we enjoyed great benefits in 2015 that others didn't, so we're starting from a much larger base.

Yes.

The absolute base is higher because we have had such tremendous growth in 2015. So when looking at it at a two-year rate, you may get a little different answer.

No, no, and I'm with you on that. And as far as balance sheet metrics, and I talked a little bit with Howard about this last night, but are you guys thinking, is there a debt-to-cap, self-imposed debt-to-cap? I know in the past you've gotten antsy when you start to get into the high 30s, low 40s. Is that still the game plan? I know you said within cash flow, but I'm just trying to think of different scenarios under different pricing scenarios.

I think Tom Mitchell, our CFO, would probably be the best person to talk about this. Tom?

David, there is a perception that our debt level would stay the same but the metrics would blow out next year and that's just not really happening with what we're seeing in the cash flows and in our ability to manage it. There's no question that it moves up, but we're not alone in that, and we don't disproportionately move up within the peer group as you go into next year on that metric. To some degree, there is some misperception and I would just highlight what Dave mentioned. There is incredible flexibility with our EnLink investment that many don't enjoy right now. So I guess I would leave it at that.

Okay, I appreciate the commentary. Thanks.

Thanks, good morning. I just wanted to get a sense for when you all think that you and BHP will decide on the right level of activity to pursue in 2016 in the Eagle Ford? And I guess I just want to understand your level of certainty there, and if those lower activity levels do sustain into 2016, what could that mean for your views on the operated level of activity in the Delaware Basin?

This is Tony. I'll just reiterate some of the points that Dave made early on with our relationship with BHP. BHP is in the same boat that all of us are in, so they're trying to manage their cash flow as a company. It's difficult for me to project what will happen in 2016, but I think we've got a lot of flexibility there. We've proven that we can operate as many as 15 rigs and nine frac crews in DeWitt County. We can show that the well performance has improved over time and the resource base is growing. The development plans are poised for acceleration when the business environment is ready for that to occur. We’ll just have to get through the third and fourth quarter and see where we're at, but the asset base is still top-tier in North America.

Yes.

I'd also point, I'd like to remind you that we've quantified the upper Eagle Ford Marl. We've characterized that with our delineation work in Lavaca County, which is really not even the sweet spot of the upper Eagle Ford Marl. That thickens as we go into DeWitt County. We think there are some growing resources with commercial returns available to us. We also think staggering our wells in the lower Eagle Ford will both improve recoveries and provide additional resources. We're continuing to work on that and that will be incorporated into our plans as soon as the business climate improves.

Michael, just to clarify, we do not have a shortage of opportunities. We have a wealth of opportunities given where that are still economic in the current price environment. The two things we look at when deciding how much to invest are, first, what are the returns on these opportunities, ensuring that we can generate returns well in excess of the cost of capital, and then second, how much do we want to spend given what our cash flow is. So we have tremendous flexibility. If there's a little bit less program, and I'm not saying it's going to be, but if there is, we can easily ramp up activities in other parts of our portfolio. We have tremendous flexibility about how we spend and where we spend our capital.

Very helpful, thanks on that. I guess the last question relates to your revised 2015 capital guidance. This time you cut corporate and midstream capital. I guess my question is, are there more opportunities to cut costs like this heading into 2016 to limit some of those fixed cost obligations, or maybe non-productive capital that could be deferred to the future time periods? Thanks.

We’re always looking, and we’ve highlighted how we continue to reduce well costs. We’ve given what we think is our most accurate guidance given the information that we have right now. But there are always opportunities to do better, so.

Good morning. BHP's decision aside, how would you compare the relative economics of DeWitt County and say in the Bone Springs Basin or maybe some emerging opportunities in the Delaware Sands? And then I have a follow-up, thanks.

When I look across our portfolio, we update our well economics routinely. When we compare those, probably the top areas performing are DeWitt County and the basin portion of the second Bone Springs. Those are probably the best returns we have in our inventory. We have additional high returns in the Powder River Basin and the Cosner-Parkman. We’re still having positive returns and very competitive returns in our Anadarko business unit in both the Woodford and the growing Meramec play. So I would characterize the basin portion of the Delaware Basin and DeWitt County as very similar.

Okay, thanks for that. And my follow-up is, the Access Pipeline is a go-forward plan on Pike. Does that influence the valuation of Access in any way?

It would influence the valuation of Access, as you might imagine, to some degree because it would be the anticipation of it at some point in the future from that. There are ways you may be able to address that and how we actually do the dropdown, but it could have some impact. Tom, do you want to add something to that?

I do want to add. It would impact it near term from a cash perspective, but that's the only way out of there. The way this works, you're going to come up with some a rate, a fee rate that you are present valuing to come up with your sales value. So it would be considered; it just wouldn't necessarily come next year or it would be a contingency that would be out there. The value is still there, and it would be agreed to in any transaction that we did.

Great, thanks. Good morning, gentlemen. Maybe a follow-up on the Bone Spring wells. The latest batch in the second quarter had very impressive results. Can you talk a little about potential drivers of the results? Was there any change to completion, is it the type well, the specific location of the geography, landing zone improvement, and any reason why this type of performance wouldn't be sustainable going forward?

If you're asking about the second Bone Springs, I think we just continued to optimize and we're really trying to core up and offset some of our best wells. We're drilling the next best well, not doing much appraisal work. We're staying focused on driving margins and oil growth. We have modified the completion designs, which has been highly centered on proppant loads. We probably have about seven or eight different designs across the Delaware Basin and those are all customized based on the portion of the basin we've had and the type of rocks that we have. I think we just continue to refine that in a very granular fashion. I'd also like to comment about thinking in the last quarter; we talked about our well command center, which is our 24x7 operating center. That largely started out being dedicated to our drilling rigs and tremendous efficiencies on our drilling rigs. Some of that is really highlighted in the operating report. We've moved that into the completion space now, so we have full coverage of our well center 24 hours a day on all our frac crews that we're working now. There’s a lot of attention to detail there. The non-productive time is grossly diminished. A lot of the emphasis around the way we flow wells back, that's a science in itself, and we’ve had a lot of learnings from some of our older plays like Cana-Woodford, that we've incorporated into the Woodford and now into the Delaware Basin. We feel like we're driving top-tier execution just through a more focused granular approach to our business.

Great, thanks. And then maybe a follow-up in the Anadarko Basin. I guess a couple of parts. Meramec versus Cana, looks like you're allocating more in the near term to the Meramec. Is this reflective of rates of return or just reflection of controlling CapEx as Cana drilling is ahead of schedule? And then maybe broadly in the Anadarko, should we expect to continue the acceleration? Have the rates of return improved enough that we should expect additional acceleration into 2016? It looks like one of your partners is talking about doubling a rig count. So how should we think about capital trends there in that basin?

I think the returns are very competitive in the basin in general. We've got a lot of repeatability in Cana. You've seen us decrease our well cost from $8.5 million, probably about a year ago, to the low $8 million in the last call, and now those are being driven down towards $7 million per well. The IP and EUR performance in the Cana-Woodford are continuing to grow. Probably the best pad we brought on historically in Cana was this quarter in our Haley pad. The Cana-Woodford project continues to outperform and improves quarter by quarter. We're extremely pleased with that, and if you recall, we’ve got a long list of opportunities there that we'll continue to prosecute on. The returns are good in the Meramec; they're not measurably higher, but they are a little bit better. We’re going to approach 2016 with a combined development plan for both horizons, which is what you’re probably hearing our partner talk about as well as us.

Great, thank you.

Good morning, guys, and congrats on a good quarter, a couple of questions. The first one is on the Permian, basically the Delaware. I'm trying to understand how further along you are on announcing the grand plan for the Permian. When you got into the Eagle Ford, you said you were going to be at 140,000 BOEs per day. We can see a path to getting to 140,000 BOEs per day, in fact even higher than that with 5,000 locations, multiple stacked pays. How much further do we have to go before we get an idea regarding how big this play could be as it relates to Devon, and how quickly can you get there? I'm just trying to get some color around that.

I think that's a good question, Sameer. We’ve been focused on generating high returns. The highest return in our stacked opportunities is the second Bone Springs. It’s very repeatable, and we're growing a little. You can see we had outstanding Q1 and Q2 in the second Bone Springs that drove that oil growth. We are continuing to watch industry delineate the Wolfcamp. All that activity in Loving County is moving right into our acreage position, and we're growing more comfortable with that. We've talked about that being a little bit more costly and a little bit more gassy, slightly less returns, but we’re getting a good understanding of the Wolfcamp. We're also monitoring the Leonard, watching our industry competitors derisk around us. We're feeling pretty good about that, but we don’t feel like it offers the same returns per well that we're seeing in the Bone Springs. In this call, we highlighted several wells that we drilled and completed in the Delaware Sands. Our appraisal work in the last couple of quarters has found a new landing zone in the Delaware Sands that is much more prolific than it was before. We’re talking about this D-Sand, we were able to put on nine wells, all repeatable, averaging over 1,000 BOEs per day from that particular horizon. What that means to us is that coupled with the different pilot tests we have ongoing will move into a full development concept. We’re coupling the optimum surface design for a multi-stacked area like this with the optimum subsurface design. In 2016, we’ll come out with a full development plan for all horizons that we think will increase the returns of these projects even greater than with our pad work, mostly centered in the second Bone Springs.

Got it, thank you. Thanks for the color. On the maintenance CapEx for 2016, I know this has been discussed a lot on the call. But I'm trying to figure out from a numbers perspective. We can see like $1 billion saving year over year just by getting like the Pike strat wells and the JV capital. If you remove all that, we can get about $1 billion less. So, if I'm thinking about flat year-over-year numbers, is $3.5 billion the right number? Is it $2.5 billion? I'm just trying to understand from a spending perspective. Where do you see from a Q4 2015 to Q4 2016 exit-to-exit flat level?

Okay, Sameer, let me try to clarify that. We are very confident that we can grow our oil production with a capital spend of between $2 billion and $2.5 billion. Now, we are not as focused on the natural gas side, so there would be some decline on the natural gas side. But on the oil, which generates the vast majority of our revenue and margins, we are confident we can grow our oil volumes at a spend between $2 billion and $2.5 billion. The other thing that's continuing to go on too that I didn't mention is just the efficiencies we’re getting that Tony has been alluding to in his answers to various calls here, which is driving higher productivity in each of our plays. That’s the other important factor driving that conclusion.

Perfect, thank you.

Thanks for taking my questions. Just some more follow-ups in the Permian. Certainly the performance was outstanding this quarter. It sounds like you're obviously evaluating development plans in the future for this. My two questions would be, first, a little bit more on how fast you can grow in the Permian. Can you discuss? What are the key bottlenecks that you're looking at on the infrastructure side? The second question is, when you look at the various formations you have opportunities on in the Permian, how does that development happen? Is this amenable to big well pads with multiple horizons and wells on it?

I think the second part of your question, we’ve historically and the industry has historically talked about pads big enough for two to three wells, and I think what we would contemplate is probably eight to nine wells per pad. We would contemplate simultaneous operations much like you see in offshore international environments, perhaps having frac centers off the pad. It’s a slightly different concept than what North American onshore players historically developed or prosecuted their inventory with. The basin is just loaded with opportunities. The resource size is tremendous. You've seen some of the unrisked locations we had. The last time we commented it was about 11,000. So really, we’ve got to come out with a design for all of these horizons that will be complementary to each other and fully utilize the surface facilities in a different way than the industry has historically done. If I go back to the first part of your question, there are challenges in the Delaware Basin. Permitting on federal acreage continues to be a real challenge; it typically centers around seven to eight months to get some of those APDs approved. We work well with BLM's field offices; we have a great relationship. But they're limited on resource as well. There are localized infrastructure issues that cause us to be thoughtful about what we drill. In fact, some of these other horizons we talked about being more gassy, some have CO2 issues associated with them, so we avoid that for now. Understanding power, water management, and results from pilot tests will impact the development plan for 2016 and beyond.

Okay, I appreciate that context. So it sounds like certainly that the fact that the northern Delaware is generally more fragmented than what you have in the Eagle Ford. You still can build that scale and efficiencies in a similar fashion.

I think we can. If you recall, we started our development in the northern portion of those counties about two years ago; had outstanding results, and then moved out and tested the southern portion of those two counties around mid-2014. Really, if you think about the timeline we’ve had to build our position and our oil growth here in the southern portion of the two counties, it’s been rapid. We’ve talked about the 13 rigs we’re using today. Three of those had been centered on the slope. We're building a plan going into 2016 that will incorporate activity there. You’ve got to chase slopes and it's a deposititional environment. You’ve got to go at a pace and stay behind data to maximize returns, and that’s what we’re trying to do.

Thanks. Good morning, everybody. I've got a couple of questions, Dave, if I may. I guess just changing tack a little bit on EnLink. What is the latest thinking after the sell-down you guys did? What is your latest thinking on the pace at which you want to bring forward that value? I’ve got a follow-up, please.

Thanks, Doug. We recognize the strategic value in EnLink, and we believe in the long term of that business. We think it’s a well-run company with a bright future. We like it long term. We do recognize the optionality that EnLink brings to Devon. It’s somewhat unique within the industry to have that optionality. We believe active portfolio management is the right approach, so we look at that with regard to every asset we own, including EnLink on a continuous basis. I’d just stop there.

Okay. I realize it could be somewhat sensitive in terms of timing. But my follow-up, Dave, and I know there have been many questions on maintenance capital and definitions of growth, and I think you've been clear about that, but if I could just try one more go at it to just to really annoy you I guess. For the first half production numbers, the 2015 production guidance probably has some upside risk to it. So, I’d appreciate your comment on that. If so, when you talk about growth in oil production, are you talking about average 2016 over 2015 or a sustainable forward? Or are you talking more exit to exit? In other words, can you add new volume at that spending level as opposed to maintaining the exit rate in 2015 at that spending level?

Yes, to answer your second question, Doug. First, you could never aggravate me, by the way. We’re talking about average of 2016 over 2015 exit rates. It’s really the same answer. We’re talking about it on average; we’d be above the 2015 levels, not just the exit of 2016. I think that's a stronger statement. Our guidance is our guidance for a reason. There’s some variability regarding completion timing in the Eagle Ford to a larger degree, and to a lesser extent some timing of completion and completion facilities in the Delaware Basin. We’ve provided the best guidance we have, but there’s some variability depending on how that works out.

Okay. Maybe at the risk of aggravating Howard, could I squeeze a third question in very quickly? It goes back to Bone Spring production numbers. They are stunning compared to the type curve that you’ve just raised on the last call. What do you need to see by way of well count or consistency in order to revisit that type curve, which was only just upgraded a quarter ago? I’ll leave it there. Thank you.

Doug, I think it's a good point. If you go back a couple of quarters ago, our type curve was a general type curve for the entire Delaware basin, and we're talking about IPs of about 750 BOEs per day and EURs of about 450,000 BOEs per day. This past quarter, we increased that to 900, and you're seeing IPs in Q2 of 1,400. We might think about giving a more granular type curve based on activity quarter to quarter. The guys are confident we’re seeing a lot of consistency in the southern portion of the basin. With continued well performance here and watching the data for a few months to ensure the EURs hold up as expected, the type curve could improve in the basin portion. The slope work is about the same type curve we had a year ago, but the returns are not as good. So, we wouldn’t want to change the type curve on the slope at this point. But the southern portion of the two counties is performing extremely well, as you've noted.

I appreciate the answers, Dave. Thanks a lot.

Yeah, thank you. With the Meramec, Dave, it's early days I know, but do you think you're going to have a larger oil and liquids window than you're currently indicating in today's ops report?

I'll let Tony answer that. Tony, do you think the oil window is going to grow, continue to grow?

There are 50 or 60 data points out there with the industry right now, and all of it looks consistent. It’s a bit early to tell, but the encouraging thing right now is everything at this stage of the play is nothing but positive. I think with continued development, we'll start seeing some sweet spots in some less attractive areas. For now, industry and Devon and our partner Cimarex is drilling a lot of really positive wells. We only have a couple data points on the gassy side of that fluid column, but there will be further refinement.

Another thing to note is it's gradational. We may talk about a specific oil window, but as you get shallower, it tends to be more oily, and as you get deeper, it tends to get a little more liquids-rich.

In all likelihood, NGPL to go before Access as a dropdown?

I don't know; we haven’t worked through the specific timing. It’s likely that NGPL would be later than that given the state of development, but likely the first dropdown would be Access to the degree we decide to do that.

The NGPL line we’ve talked about in our disclosures is a 20-inch line that we've purchased; it’s not finalized yet. We expect it will finalize end of Q1 or early Q2. It's subject to a couple of conditions, but it runs from North Texas to the very south of what the industry now calls the SCOOP area. It is very strategic in where it goes. There are a few things that could happen. First, the pipeline could be extended so it moves all the way through SCOOP up to the Cana area and Stack area. That's important because we think as these plays develop, we’ll see the need for additional NGL takeaway capacity out of Oklahoma, as well as residue capacity. Another positive is that the right-of-way that comes with this acquisition is perpetual; it allows us to put as many lines in that right-of-way, and it doesn't expire, it doesn’t specify for which product. So this gives us tremendous optionality for the asset, and we think we can add on to that to create value for Devon and EnLink. We view this as very positive for us and quite frankly, positive for the industry.

Good morning. I guess a question on the Meramec map that you have on slide 14 defining the geologic boundaries to the north and south in the zone. I understood that to the north it becomes more carbonate-rich, and then to the south it gets a little more clay-rich. It looks like your blob corresponds to how I would have drawn it. Is that a fair geologic characterization of why that blob is where it is?

I think you're on to it, David. At least in our portion, it's more of a silty mudstone which provides a lot of the productivity of the interval. You're describing that general trend just fine.

Okay, that's helpful. And then thinking about your Eagle Ford production profile and knowing BHP is the operator, you also had some facility constraints that you were working on debottlenecking. How does that production profile, surface capacity and BHP relationship impact your 140,000 barrel a day targets that you originally had? How do you think about that growth profile heading into next year or lack thereof?

As it relates to takeaway capacity, over the past four, five, six months, our midstream providers have continued to work on that, and we’ve increased our stabilization capacity from about 140,000 barrels a day to between 160,000 to 170,000. On any given day, it can be 170,000 barrels a day and some days 160,000. That’s a significant increase in capacity, and that’s gross obviously. The other area where we’ve increased capacity is we’ve put in a truck station that will be finalized this month of October. We have the capacity to truck barrels out of that area, and that truck station is much closer to our production area, keeping the barrels flowing better. So from an infrastructure standpoint, we think we’re in good shape considering the current spend profile for the rest of the year and as we start working with BHP on 2016.

David, you're aware of this, but the productivity index on those wells is extremely rich. When we do our modeling work, pace of activity is dramatic on what that forecast looks like going forward. So we continue to be optimistic about the play and our ability to grow volumes.

So in other words, we have the capability to go to 140,000 barrels a day from an operational perspective. It’s just a question of how much capital we put into the program. We’ll be discussing that with BHP as we continue throughout the year and seeing what the commodity price environment looks like and how much we both mutually want to spend.

Hi, good morning, guys. I wanted to drill down on the Powder River results. How much of the 225,000 acres in the oil fairway would you say are derisked at this point? In this commodity environment, how should we think about the pace of further derisking? And then just looking at the returns there, is there anything that keeps you from accelerating activity more there?

Okay, Megan, without having my map in front of me, it’s difficult to estimate that. But I would just estimate roughly about a quarter of our position has been derisked. The way our technical teams categorize our opportunities is into different tier levels. Our top tier asset base has several years of running room. We need to move up-dip and to the north to continue derisking a larger area. We feel very confident. We’re starting to move toward long-lateral drilling, and that has achieved everything we expected in our modeling work, so that is moving forward. The portion of our position not derisked was dependent on the long-lateral results. We’re extremely encouraged, and again, we’re focused on drilling the next best well and benchmarking repeatable results. Very commercial, in fact probably the top three returns we have in our portfolio right now.

That's helpful, thanks. My next question is just on refracs. Can you discuss the major challenges you're still trying to get answered for horizontal refracs, and any thoughts around refracs on some oil assets anytime soon?

We’ve got a working laboratory in the Barnett. If you look at our refracs, it's over 1,000 vertical wells that we have refrac'd. We’ve refrac'd about 50 times in the Barnett. We’re working on horizontal refracs, and we probably had more of those done over time than you would expect. We’re using more recent technology with finer grade sand and diversion techniques. That’s what we’re exploring now. We've tried chemical diversion, and at least in the Barnett, mechanical diversion techniques are working better. We expect quality returns from that. In the Barnett, it’s an exciting resource base that we haven’t even talked about or quantified right now but it’s very material to the company. We’re also using that knowledge for some of our other plays. We’ve refrac'd about 15 or 20 wells in the vertical Wolfberry in the Permian and have seen reasonable results. We’ve refrac'd a couple of wells in the Eagle Ford and also in the Haynesville. We’re using that knowledge to look for good quality candidates. There’s tremendous upside with the refracs in our inventory.

Great, thanks for taking my questions.

Thank you, good morning.

Good morning, Brian.

Most of my questions have been answered, but I wanted to follow up as you think about your cadence of well completions on the oil side going into next year. To meet your goal of growing production and doing that within cash inflows, do you expect that you would need a greater cadence of completed wells, or is well productivity really the major driver looking into 2016?

Well, productivity is the major driver. We haven’t assumed any tricky maneuvers regarding drawing down the inventory of wells. It’s really just the improved productivity along with lower costs and other factors I talked about.

Got it. Just to make sure we're defining inflows correctly. That does include the potential for dropdowns from EnLink. Would you be able to hit that objective without a dropdown from EnLink?

What I tried to clarify is that we can grow oil production at between $2 billion and $2.5 billion capital program next year. You can then plug in whatever oil price you want for your cash flow models and assumptions on dropdowns, etc., and see how that works out relative to cash flow, I think.

Okay, thanks. In the Wolfcamp, you talked about increasing your prospectivity by 40% to 140,000 net acres. Can you talk about geographically where you saw that and where you're heading? What type of potential do you see for further improvements in prospective acres?

We expanded our Wolfcamp footprint across our position because we saw a couple of industry wells that were more oily than we previously expected. If you look at our map, you’ll see that in southeast of Mexico, we expanded to the west. There are a few industry data points showing strong quality work. We’re seeing a lot more activity just south of the New Mexico border that’s encouraging to us. We’re going to drill about six Wolfcamp wells this year, about the same for the Leonard. We think that’s a great resource opportunity and will be incorporated into our 2016 development plans.

Hey, good morning. In the release, you highlighted margin improvement from reduced operating costs and higher value oil growth, but also noted that Eagle Ford is the highest margin asset in the portfolio. With reduced activity here, how should we think about continued margin expansion to the corporation at a static commodity price? It might also make sense to expand upon the strong sequential decline in Permian LOE as this becomes a bigger contributor to overall volumes.

We’re always driving to find ways to drive down LOE. That’s part of the goal we have to increase margin, so there’s opportunity there. This organization is highly focused on being the best operator in each of our core areas. So there’s potential for expansion at static prices. We don’t see any big shifts in the mix taking place in the volumes, but we’re always looking to drive down costs associated with operations. I would not expect the GOR to magically increase with time. If you look at our activity, we’ve drilled a lot of the Cana core inventory, so we're moving to the north and to the east. We’re expecting a more liquid-rich fluid content as we go into the second half of the year and into 2016. We’ve had about four or five wells in those areas that have been encouraging and have been more oily. Great returns. The performance will be moving in that direction.

Michelle, we're past the top of the hour, so we're going to take one more call and then call it a day.

Hey, guys, thanks for squeezing me in. Obviously, we've covered a lot of ground here. I just want to go back to one quick thing on the refracs. Do you guys have commentary on alternative financing programs that are out there via service companies to do refracs? Have you looked at that or talked to people about that? I think Halliburton was talking about doing one just as a way of making the base maintenance cheaper for you guys or more capital efficient for you.

We’re seeing some of the larger service providers that want to have more skin in the game for these new ideas. We’re utilizing a concept and won’t talk about the individual provider in southeast New Mexico on some newer technology for our new completions. We know that opportunity exists for refracs. I tell you right now, I think with the 1,000 wells we’ve refrac'd in North Texas and the growing list of horizontals we have refrac'd, I think we likely have the greatest library available in the industry right now. We’ve got a great opportunity there and we’re continuing to prosecute that on our own.

Okay. Sounds great. All right, thanks. I’ll let you guys jump off now.

Thank you all for joining our conference call today. We appreciate the interest. If you have additional follow-ups, please don't hesitate to contact any of us in Investor Relations. We look forward to seeing you on the road soon. Thanks and have a great day.