Howard J. Thill - Senior VP-Communications & Investor Relations David A. Hager - President and Chief Executive Officer Tony D. Vaughn - Executive Vice President-Exploration & Production Thomas L. Mitchell - Chief Financial Officer & Executive Vice President Darryl G. Smette - Executive Vice President, Marketing, Facilities, Pipeline and Supply Chain.

Evan Calio - Morgan Stanley & Co. LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) David R. Tameron - Wells Fargo Securities LLC Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc. Subash Chandra - Guggenheim Securities LLC Ryan Todd - Deutsche Bank Securities, Inc.

Sameer Uplenchwar - GMP Securities LP Scott Hanold - RBC Capital Markets LLC Doug Leggate - Bank of America Merrill Lynch John P. Herrlin - SG Americas Securities LLC David Martin Heikkinen - Heikkinen Energy Advisors Megan E. Repine - FBR Capital Markets & Co. Brian A. Singer - Goldman Sachs & Co. Phillip J.

Jungwirth - BMO Capital Markets (United States) James Sullivan - Alembic Global Advisors LLC.

Welcome to Devon Energy's second quarter 2015 earnings conference call. At this time, all participants are in a listen-only mode. This call is being recorded. At this time, I would like to turn the call over to Mr. Howard Thill, Senior Vice President of Communications and Investor Relations. Sir, you may begin..

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 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 additional questions from the participants. So, Michelle, with that we're ready to take the first question..

Your first question comes from Evan Calio from Morgan Stanley. Your line is open..

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'll remember back at the end of 2014, we had temporarily increased from five to nine completion crews and we jointly agreed with BHP that that was a temporary measure to draw down the inventory and then after that point, we would reduce the completion crews.

And certainly in the current commodity price environment, and with some draw down 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 the way our agreements are written that they might have reduced the completion crews a little bit further than we have, taking it down to one crew.

Directionally, 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 little bit of a call, I believe, on commodity prices. And so 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. And 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. In fact, 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 pace of activity, and Dave summarized pretty well that we just dropped that pace down. And we'll continue to hover at the five or six drilling rigs for this point and 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 2016, what benefit that's going to provide to us. And so you look at that and the CapEx savings we're going to have from the cost reductions.

Then there are some other factors also that if you look at our, we can take the spending down in Canada probably by around $500 million or so. We will not have any activity essentially probably next year in the Mississippian or the Southern Mississippian, Midland Basin, Wolfcamp, some other plays.

We had great economics because we're essentially being carried on a large amount of the well cost. But once we're beyond the carry, we won't have any money we'll be spending there.

So you put all that together and where we have an E&P capital spend this year of $4 billion or a little bit over, I tried to make the comment there in my opening remarks that you could see that with the current strip that we – the cash flow that will be 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.

And that's obviously the vast majority of the margin that we generate as a company. So there are a lot of positive factors working that we're going to be able to significantly reduce the capital requirements. I know there's some concern out there that when our hedges roll off, what impact is that going to have on the company.

And we're trying to address that with you and give you some directional things to think about there that we have confidence we can continue to grow our oil production, even when these hedges roll off, because of the factors I mentioned..

That's real helpful, guys. Thank you..

Your next question comes from Ed Westlake from Credit Suisse. Your line is open..

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 which we're currently seeing on the strip.

I think 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.

And I think when you look at the combination that Devon provides of tremendous capital flexibility, some of the premier assets in North America, strong balance sheet, and the strong execution that we're consistently demonstrating 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. And 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 really outperform on those type wells that we deliver.

So we really have got 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.

And that's really why we are moving our completion designs back to about the 1,500 to 2,000 pound per foot range because it affords us the most improved rate of returns. Also, our work in the northern portion of Lea and Eddy County, we're derisking and really trying to set up some 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. So I think what the group is doing right now is we have a pretty good understanding about 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 and the clusters and all the various things that go into a frac design. So we'll continue to see I think EURs improve and returns improve..

Thanks very much..

Your next question comes from David Tameron from Wells Fargo. Your line is open..

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 it was important to have a strong balance sheet. And we're going to continue to believe that that is important and certainly in these times of uncertain commodity prices. So directionally, we tend to think of our capital spending has to be within the total cash inflows that we anticipate for the company.

So 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 new, the other new, the NGPL line that we highlighted in the operations report. So that's directionally where we start off the discussion.

We obviously will then look at the programs and see if there is any reason to deviate in a positive or a negative way from that. And we have the flexibility to do that given our strong balance sheet. But that's the starting point of the discussion.

And I think it's important to remember that we did, our growth rate may not be quite as high next year, but remember we did, enjoyed great benefits of this in 2015 that others didn't, so we're starting from a much larger base. Don't forget that..

Yes..

The absolute base is higher because we have had such tremendous growth in 2015. So when you look 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 debt-to-cap, self-imposed debt-to-cap? I know in the past you've gotten, I think the word Howard used is antsy when you start to get into the high 30%, 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 to about this.

Tom?.

Okay..

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. So 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..

Your next question comes from Michael Rowe from Tudor, Pickering, Holt. Your line is open..

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 that 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 much as 15 rigs and nine frac crews in DeWitt County. And we also can show that the well performance has improved over time and the resource base is growing. So the development plans are poised for acceleration when the business environment is ready for that to occur.

So 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 just 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.

So we think there are some growing resources with commercial returns available to us. We also think the staggering our wells in the lower Eagle Ford will both improve recoveries and provide additional resources. So 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, I think we are also asking that question. Just to be clear, 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.

So that if you look fundamentally, the two things that we look at when we decide how much to invest is, first, what are the returns on these opportunities. And make sure 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. And so we have tremendous flexibility.

If there's a little bit less program, and I'm not saying it's going to be, but there's a little bit less program in the Eagle Ford, we can easily ramp up activities in other parts of our portfolio. So we have tremendous flexibility about how we spend and where we spend our capital..

Very helpful, thanks on that. I guess last question just 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..

Well we're always looking and we've highlighted how we're continuing to reduce well costs. And so we've given what we think is our most accurate guidance given the information that we have right now. But there's always opportunities to do better, so..

Okay. Great, thanks..

Your next question comes from Subash Chandra from Guggenheim Securities. Your line is open..

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 across our portfolio routinely. And when we compare those, probably the top areas that are performing are DeWitt County and the basin portion of the second Bone Springs. Those are probably the best returns that are equivalent to each other.

Those are the best returns that we have in our inventory. We have additional high returns that we're seeing in the Powder River Basin and the Cosner-Parkman. And we're still having positive returns, very competitive returns in our Anadarko business unit in both the Woodford and the growing Meramec play.

So I would probably characterize the basin portion of the Delaware Basin and DeWitt County 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 (25:58) at some point in the future from that. Now 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 to that. It would impact it near term from a cash perspective, but that's the only way out of there. And the way this works, you're going to come up with some a rate, a fee rate, that your 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. So the value is still there and it would be agreed to in any transaction that we did..

Okay, thank you..

Your next question comes from Ryan Todd from Deutsche Bank. Your line is open..

Great, thanks. Good morning, gentlemen. Maybe a follow-up on the Bone Spring wells. The latest batch in the second quarter, very impressive results.

Can you talk a little bit about maybe potential drivers of the results? Was there any change to completion or 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. So we're drilling the next best well. Not doing much appraisal work. We're trying to stay focused and drive margins and oil growth.

So we have modified the completion designs as we've discussed and that has been really highly centered on proppant loads. But we're also, we probably have about 7 or 8 different designs across the Delaware Basin and those are all customized based on the portion of the basin that we had, the type of rocks that we have.

And so 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 commented on our well comm center here, which is our 24x7 operating center. That largely started out being dedicated to our drilling rigs and tremendous efficiencies on our drilling rigs.

And some of that is really highlighted here in the operating report. But we've moved that into the completion space now. So we've got full coverage of our well center 24 hours a day on all of our frac crews that we're working right now. So there's a lot of attention to detail there. The non-productive time is grossly being 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 both into the Woodford and now into the Delaware Basin.

So 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 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 millions 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 that we brought on historically in Cana was this quarter in our Haley pad. So the Cana-Woodford project continues to outperform and continues to improve quarter by quarter.

So 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. So really the way we describe the Meramec play in this particular report, we're finding that all the IPs and the well costs are very similar to what we have in the Woodford.

It's got a slightly improved oil content so the margins are a little bit better than in Cana. As you know, it's a less mature asset than the Woodford is. So we're really not trying to divert or reallocate capital away from the Woodford.

We're really trying to grow understanding of the Meramec so in 2016 we can come back with a very thoughtful development plan that will effectively prosecute both the Meramec and the Woodford combined. So the returns are good in the Meramec. They're not measurably higher, but they are a little bit better.

But we're going to approach 2016 with a combined development plan for both horizons. And that's really what you're probably hearing our partner talk about as well as us..

Great, thank you..

Your next question comes from Sameer Uplenchwar from GMP Securities. Your line is open..

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 just trying to understand how further along are you 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 stack 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, and I'll tell you what we've been focused on, as we've talked about in previous calls, is really trying to generate high returns. And the highest return in our stacked opportunity of horizons we feel like is a second Bone Springs. It's very repeatable. We're growing a little there.

You can see we had an 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 getting 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 understand of the Wolfcamp. Same thing for the Leonard, we're watching our industry competitors derisk around us.

We're feeling pretty good about that, but again, we don't feel like that offers the same returns per well that we're seeing in the Bone Springs.

And I think in this call we highlighted several wells that we just drilled and completed in the Delaware Sands, and some of that appraisal work that we've done in the last couple of quarters we found a new landing zone in the Delaware Sands that is much more prolific than it was before. So we've talked about this D-Sand.

We were able to put on nine wells, all very repeatable, and averaged over 1,000 BOEs per day from that particular horizon. So what that all means to us is that coupled with the different pilot tests that we've described in the Delaware Basin, all that information is being moved into a full development concept.

And so we're coupling the optimum surface design for a multi-stacked area like this with the optimum subsurface design.

In 2016, we're going to come out and have a full development plan for all horizons that we think will increase the returns of these projects even greater than what we have done just 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 a 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 the vast majority of our margin, 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 even mention is just the efficiencies we're getting that Tony has been alluding to in his answers to the various calls here, which is driving higher productivity in each of our plays. And so that's the other thing that's an important factor in here and is driving that conclusion..

Perfect, thank you..

Your next question comes from Scott Hanold from RBC Capital Markets. Your line is open..

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. And I guess my two questions would be I guess 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, at this point in time on the infrastructure side? And then the second question is, when you look at all those various formations that you have opportunities on in the Permian, how does that development do you think happen? Is this amenable to big well pads with multiple horizons and wells on it?.

I think the second part of your question, we historically and the industry has historically talked about pads enough size 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 type environments, perhaps having frac centers off the pad. So it's a slightly different concept to what North American onshore players have historically developed or prosecuted their inventory with. But the basin is just loaded with opportunities.

The resource size is tremendous. You've seen some of the unrisked locations that we had. I think 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 of each other and fully utilize the surface facilities in a different way than the industry has historically done. So I think if I go back to the first portion of your question, there are challenges in the Delaware Basin.

Permitting on federal acreage continues to be a real challenge. That has typically centered around seven to eight months to get some of those APDs approved through the system. We work really well with the field offices of the BLM, have a great relationship. We're working together. But they're limited on resource as well.

There is infrastructure, there is localized infrastructure issues and takeaway that cause us to be a little bit more thoughtful about what we go drill. In fact, some of these other horizons we talked about being more gassy, some of those horizons has had CO2 issues associated with them, so we avoid that for now.

And that's incorporated in our more thoughtful plans. And then finally, I think understanding all of those challenges with having a more thoughtful approach to power, water management, understanding all of the results from the pilots that we have ongoing will certainly impact the development plan going forward for 2016 and beyond..

Okay, I appreciate that context. So it sounds like certainly that the fact that the northern Delaware is I guess in general more fragmented than say 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 both of those counties two years ago. Had outstanding results and then we moved out and tested the southern portion of those two counties I believe in the fall about, or mid 2014 if I recall.

And so really, if you think about the timeline that we've had to build our position and our oil growth here in the southern portion of the two counties, it's been quite rapid. And so now we're going back, I think we talked about the 13 rigs we're using today. Three of those had been centered on the slope.

So we're going back to build, get an updated to build our develop plane going into 2016 that will incorporate activity there. You got to chase slopes and it's a little bit more of a different depositional environment than it is in the southern portion of the two counties.

So you've got to go at a pace and stay behind the data so you can do good quality work and maximize returns and that's what we're trying to do..

Thank you for that..

Your next question comes from Doug Leggate from Bank of America Merrill Lynch. Your line is open..

Thanks. Good morning everybody. I 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? And 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 very, very bright future. And so we like it longer term. We do recognize the optionality that EnLink brings to Devon. It's probably somewhat unique within the industry to have that optionality.

And so we, like we do with all of our asset base, we believe active portfolio management is the right way to look at things. So we look at that with regard to every asset we own including EnLink on a continuous basis. And I think 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's been a lot of questions on maintenance capital and definitions of growth, and I think you've been quite clear about that, but if I could just try one more go at it to just to really annoy you I guess.

It seems at least for the first half production numbers that the 2015 production guidance probably has some upside risk to it. So I'd first of all appreciate your comment on that.

And if so, when you talk about growth in oil production, are you talking about average 2016 over 2015 or are you talking more of a sustainable go forward basis? Or to be very clear about it, are you talking exit to exit? In other words, can you actually still add new volume at that spending level as opposed to maintaining the exit rate in 2015 at that spending level, if you see what I mean?.

Yes, to answer your second question there, Doug. First, you could never aggravate me, by the way. But we are talking about average of 2016 over the exit of 2015. And essentially we're flat for the entire year. So you can look at it as average of 2016 over average of 2015. It's really the same answer.

So, we're talking about on average that we would be above 2015 levels, not just the exit of 2016. So I think that's a stronger statement, obviously. As far as our second half of 2015 guidance, I think our guidance is our guidance since we give it that way for a reason now. And I think Tony could comment on this.

But there probably is some variability in there based I'd say particularly on the completion timing in the Eagle Ford to a larger degree, and to a lesser degree some timing of completion and completion of facilities in the Delaware Basin. And so we've given you the best guidance we have.

But there is some variability based on exactly how that works out..

Okay, maybe at the risk of aggravating Howard, maybe I could squeeze a third one in very quickly. And it really just goes back to the Bone Spring production numbers. I mean, they're quite stunning compared to the type curve that you just raised on the last call.

So I guess my hopefully quick question would be, 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? And I'll leave it there. Thank you..

Doug, I think it's a good point. If you go back probably two or three 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. We increased that this past quarter up to 900 and you're seeing IPs in Q2 of 1,400.

So if we wanted to give you a more granular type curve based on the activity quarter to quarter, I think we could increase that. So the guys are confident that we're seeing a lot of consistency there in the southern portion of the basin.

So I would think with continued well performance here and watching the data for a few months to make sure the EURs hold up as expected, the type curve could improve on the basin portion of that.

And going back to a couple of calls ago, the slope work is really about the same type curve that we had a year ago and we're seeing a little bit of variability there. The returns are not as good on the slope as they are on the basin. They're not as repeatable.

So certainly wouldn't want to go out on a limb and talk about a changing type curve on the slope at this point. But the southern portion of the two counties is performing extremely well as you note..

I appreciate the answers, Dave. Thanks a lot..

Your next question comes from John Herrlin from Société Générale. Your line is open..

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?.

Well, there's 50 or 60 data points out there with the industry right now and all of it is looking pretty consistent. So, I think it's a bit early to tell but the encouraging, I think the encouraging thing right now is everything at this stage of that part of the play is nothing but positive.

I think with continued development there, we'll start seeing some sweet spots in some less attractive areas. But for now, industry and Devon and our partner Cimarex is drilling a lot of really positive wells. I think we only have a couple of data points on the gassy side of that fluid column. So there will be further refinement behind that.

So I'd say yes, it could grow..

Another thing, John, is obviously it's gradational. So even though we may talk about a specific oil window, as you get shallower, it tends to be more. And as you get deeper it tends to get a little more liquids-rich. But it's gradational, that boundary is..

Okay, thanks, Dave. One for Tom regarding dropdowns.

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

I don't know, we really, John, we haven't worked through the specific timing, but it's likely that NGPL would be later than that given the state of development and Darryl may want to give you some color around that. But likely the first dropdown would be Access to the degree we decide to do that..

Okay, thanks..

Darryl, I might suggest, we haven't talked much about NGPL. And why don't we give Darryl just a minute here to describe the NGPL asset so everybody understands it a little bit better and the optionality that this asset provides us..

Okay, the NGPL line that we've talked about in our disclosures is a 20 inch line that we have purchased, has not really finalized yet. We expect it will finalize end of the first quarter, early second quarter. It's subject to a couple of conditions that we feel very comfortable will be met.

But it's a 20 inch line that runs from North Texas to the very south end of what industry now calls the SCOOP area. And so, it is very strategic in where it goes. Now there is a couple of different things that could happen there.

First of all, that pipeline could be extended so it moves all the way through SCOOP up to the Cana area and Stack area and that's very important when we look at it, because we think as all of these plays continue to develop, that we're going to see a need for additional NGL takeaway capacity out of Oklahoma as well as residue capacity out of Oklahoma.

That's a positive. The other positive is that the right-of-way that comes with this acquisition is a perpetual right-of-way. It doesn't expire and it allows us to put as many lines in that right-of-way as we can get in there and it doesn't specify for which product.

So this gives us so much optionality in terms of whether it's a rich line that could move NGL and gas down to the Bridgeport plant for EnLink, whether it could be a residue gas that takes gas out of the State of Oklahoma. It could be used as an oil line. It could be used in a number of different ways. So we are very pleased that we have that asset.

We think we can add on to that asset to create value either for Devon or for EnLink. So it's something we view as very positive for us, and quite frankly, positive for the industry..

Thanks, Darryl..

And your next question comes from David Heikkinen from Heikkinen Energy Advisory. Your line is open..

Good morning. I guess question on the Meramec map that you have on slide 14 defining the geologic boundaries to the north and to the south in the zone. I'd understood that to the north it becomes more carbonate rich and then to the south it gets a little more clay rich. And 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. I think it's really, at least in our portion of it, it's more of a silty mudstone which provides a lot of the productivity of the interval. But I think you're describing the general trend just fine..

Okay, that's helpful. And then thinking about your Eagle Ford production profile and knowing BHP as 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, I guess?.

This is Darryl. As it relates to takeaway capacity, over the past four, five, six months, our midstream providers continued to work on that, and we have increased our stabilization capacity from about 140,000 barrels a day up to somewhere between 160,000 to 170,000. On any given day it can be 170,000 barrels a day and some days 160,000.

So that's a significant increase in capacity, and that's gross obviously. The other area where we have increased capacity is we have put in a different truck station that will be finalized this month of October where we have the capacity to truck barrels out of that area.

And that truck station is so much closer to our production area that it just keeps the barrels flowing a lot better. So from an infrastructure standpoint, we think that we are in pretty good shape when we look at the current spend profile for the rest of this year and as we start working with BHP on 2016..

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

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. And we'll be discussing that with BHP as we continue on throughout the year and seeing what the commodity price environment looks like and how much we both mutually want to spend..

That's helpful. Thanks, guys..

Your next question comes from Megan Repine from FBR Capital Markets. Your line is open..

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? And 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 would keep you at this point from accelerating activity more there?.

Okay, Megan, without having my map in front of me, it's difficult for me to estimate that. But I would just estimate roughly about a quarter of our position has been derisked. The way our technical teams really try to think about this is we categorize our opportunities into different tier levels.

So our top tier asset base, we've got several years of running room there. We do need to move up-dip and to the north to continue to derisk a larger area. We feel very confident. As you know, we are starting to move towards long-lateral drilling, and that has achieved everything that we had expected in our modeling work, so that is moving forward.

And really, the portion of our position that has not been derisked was dependent on the long-lateral results. So right now we are extremely encouraged, and again we're focused on drilling the next best well and seeing repeatable results. Very commercial, in fact, it's probably the top three returns we have in our portfolio right now..

That's helpful, thanks. And then my next question is just on refracs.

Can you just discuss the major challenges that you're still trying to get answered for horizontal refracs, and then any thoughts around refracs on some oil assets anytime soon?.

Sure, Megan. We've got I think a working laboratory in the Barnett. And if you look what we have refrac'd over the years, it's over 1,000 vertical wells that we have refrac'd. We've refrac'd refracs now in the Barnett about 50 times. And now we're working on horizontal refracs that we talked about.

And we probably had more of those done over time than you would expect. But we're using the more recent technology of finer grade sand and more diversion, more capable diversion techniques. That's really what we're exploring right now. And so we tried chemical diversion. We tried mechanical diversion.

At least in the Barnett right now, mechanical diversion techniques are working better. We're expecting quality returns in that. And so really when I look at the Barnett, it's an exciting resource base that we really haven't even talked about or tried to quantify right now, but very material to the company.

And we're also using that knowledge to actually go into some of our other plays. We've refrac'd I believe about 15 or 20 wells in the vertical Wolfberry in the Permian and have seen reasonable results. Not outstanding, but we're continuing to refine that.

We've refrac'd a couple of wells in the Eagle Ford and also have refrac'd a well in the Haynesville. So we're using that knowledge to go into some of our wells that were frac'd before the recent drive-in technology changed about 18 months ago and looked for good quality candidates. But there is tremendous upside with the refracs on our inventory..

Great, thanks for taking my questions..

Your next question comes from Brian Singer from Goldman Sachs. Your line is open..

Thank you, good morning.

Good morning, Brian..

Most of my questions have been answered, but I wanted to just 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 then 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 as you look into 2016?.

Well productivity is the major driver. We haven't assumed anything like, well we can do this if we really draw down the inventory of wells or anything tricky like that. That's not been in our thinking at all. It's really just the improved productivity along with the lower costs and the other factors I talked about..

Got it. And along those lines, then also just to make sure we're just defining inflows correctly. That does include, I think you said this before, the potential for dropdowns from EnLink.

Would you be able to hit that objective without a dropdown from EnLink?.

Well, what I tried to clarify and you can run your own cash flow models. But I tried to clarify that we can grow oil production at between $2 billion and $2.5 billion capital program next year.

And so, you can then plug in whatever oil price you want to and assumptions on drop downs, etcetera, and see how that would work out relative to cash flow I think..

Okay, thanks. And then in the Wolfcamp, you talked about increasing your prospectivity by 40% to the 140,000 net acres.

Can you just talk about geographically where you saw that and then where you're heading and whether you see – what type of potential you could see for even further improvements in prospective acres?.

We expanded our Wolfcamp footprint across our position really because we saw a couple industry wells that were more oily than what we had previously expected. So if you look back at our map, you'll see that in southeast of Mexico, we expanded that to the west.

And there's a few industry data points that you could go out and dig out that would show some really good quality work. We're still seeing a lot more activity just south of the New Mexico border that's very encouraging to us. We're going to drill about six Wolfcamp wells ourselves this year, about the same for the Leonard.

So again, we think that's a great resource opportunity for us and will be incorporated into our 2016 development plans..

Great, thank you..

Your next question comes from Phillip Jungwirth from BMO. Your line is open..

Hey, good morning. In the release, you highlighted margin improvement from reduced operating costs and the higher value oil growth, but also note the Eagle Ford is the highest margin asset in the portfolio.

So with reduced activity here, how should we think about continued margin expansion to the corporation at a static commodity price? And 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, looking at ways we can drive down the LOE. And so that's part of the goal that we have to increase the margin. So there's the opportunity there. I think that you can see that this organization is highly focused on being the best operator in each of our core areas. So there is a potential there for expansion at static prices.

We don't see a big shift in the mix taking place in the volumes, but that's part of what we do is always try to drive down the cost associated with our operations..

Okay, and then on the Haley pad, the 15% oil mix, the well exceeded the type curve of 5% oil.

How sustainable is the lower GOR over the life of the well and does the increased oil mix have more to do with the new completion design or the well is being drilled towards the eastern side of the Cana development?.

I would not expect the GOR to magically increase with time. I think if you look at our activity, we have drilled a lot of the Cana core inventory, so we're starting to move up dip to the north and to the east. So we're expecting a more liquid-rich fluid content as we go into the second half of the year and into 2016.

So we'll still have, we've had I think about four or five wells in those areas that have been very encouraging and have been more oily. Great returns. So the performance will be moving 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..

Okay, so your final question will come from James Sullivan from Alembic Global Advisory. Your line is open..

Hey, guys, thanks for squeezing me in and obviously we covered a lot of ground here. I just want to go back to one quick thing on the refracs.

Do you guys have any commentary on say alternative financing programs that are out there via service companies to do refracs? Have you guys 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..

I think that's a good question. We're seeing some of the larger service providers that want to have a little bit more skin in the game for some of these new ideas. We're utilizing a concept and won't talk about the individual provider in Southeast New Mexico on some of the newer technology there for our new completions.

We also know that that opportunity is available for the refracs. I tell you right now, I think with the 1,000 wells that we have refrac'd in North Texas and the growing list of horizontals that we have refrac'd, I think we probably had the greatest library available in the industry right now.

So 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..

Thank you, everyone. This concludes today's conference call. You may now disconnect..