德文能源 (DVN) 2015 Q3 法說會逐字稿

Welcome to Devon Energy Q3 2015, earnings conference call.

(Operator Instructions)

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, Tiffany, and I'd like to wish everyone a good morning as well and welcome to our quarterly conference call. As has become our custom, today's call will largely consist of Q&A. So I hope you had a chance to look through the third quarter earnings release including the forward-looking guidance as well as our detailed ops report. 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'll remind you that comments and answers to questions on this call will contain plans, forecasts, expectations and estimates which are forward-looking statements and under US Securities law. Those 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 and actual results might differ materially. For a review of risk factors relating to these statements, please see our 2014 Form 10-K and subsequent 10-Q filings. With that, I will turn the call over to Dave Hager.

Thank you, Howard, and welcome, everyone. In the third quarter, Devon continued its trend of outperforming expectations and delivered another excellent performance. Our strategy of operating in North America's best resource plays coupled with a focus on best-in-class execution is generating top-tier results in each of those basins.

In our US resource plays where the majority of capital is being deployed, well performance has consistently exceeded type curve expectations and peer results through higher production rates, lower capital costs and reduced operating expenses. This operational momentum combined with a strong balance sheet and excellent liquidity, positions us as well as anyone to manage through the current industry conditions.

These strong operating results translated into several noteworthy highlights for the quarter, including record oil production. We raised our 2015 oil growth outlook for the second time this year. We controlled costs with operating expenses coming in significantly below guidance. And we're now on pace to save $1 billion of operating and capital costs in 2015, versus our original guidance expectations. We expect this outstanding operational performance to continue as we head into 2016.

To deliver maximum capital efficiency with today's market conditions, we plan to preserve operational momentum by dynamically allocating capital to the highest returning, lowest risk development opportunities in each of our of core resource plays. Although we are still working through the details of our 2016 capital program, directionally, we expect our E&P capital spend to range from $2 billion to $2.5 billion. Other non-E&P capital requirements and dividends are expected to total around $1 billion next year.

Importantly, we are focused on balancing capital investment with available cash flows. Our capital programs have tremendous flexibility and we can rapidly respond to market conditions. We have minimal exposure to long-term service contracts. We have no long cycle project commitments and negligible leasehold expiration issues. In 2016, the majority of E&P capital will once again be focused in the Delaware Basin, Eagle Ford, Anadarko and Rockies; the plays with the best economics in our portfolio.

With a significant improvements we have seen with well productivity and cost efficiencies, we expect this disciplined oil focused capital program to generate low single-digit oil growth in 2016. We will finalize our budget in the coming months and provide detailed guidance with our fourth quarter Earnings Release. Our strong balance sheet, ample liquidity and investment grade credit ratings are key factors during this period of depressed commodity prices.

Additionally, we expect distributions from our investment in EnLink to approach $300 million next year and we have a high degree of confidence in our ability to transact on these sale of access pipeline in the first half of 2016. Combined with cash flow from our top-tier upstream assets, we have reliable sources of funding for Devon's 2016 capital program without taking on incremental debt.

So in summary, I am quite pleased with the outstanding results Devon has delivered and I fully expect this trend of outperformance to continue going forward. We have a great collection of world class assets and we will continue to get the most out of these assets with superior execution and we have one of the more advantaged capital structures in the E&P space. As we continue to execute on our disciplined business plan, we are well-positioned to generate outsize returns for our shareholders for many years to come. With that, I will turn the call back to Howard for Q&A.

Thanks, Dave. To ensure we get as many people on the call as possible, we ask that you please limit yourself to one question plus a follow-up and reprompt as time permits. And with that, Tiffany, we'll take the first question.

(Operator Instructions)

Your first question comes from the line of Doug Leggate with Bank of America. Your line is open.

Thanks. Good morning, everybody.

Good morning, Doug.

Dave, I wonder if I could pick up on your capital question first of all. So low single-digit oil growth. You obviously have a tailwind from the momentum you've got in the oil sands. So I'm just trying to understand, does that low single-digit mean that the lower 48 grows as well or is the growth predominantly from the oil sands? And I've got a follow-up, please.

Sure, Doug. Well, we obviously do have tailwinds as we move forward into 2016 in the oil sands in Canada. But we also have good growth opportunities in the Delaware Basin. We're confident we're going to be growing volumes there in Q4 of 2015, and we see that momentum continuing on into 2016. We're still finalizing our capital allocation, so we're not going to break out the exact numbers at this point. But we still see a lot of great growth opportunities in the US. It's really just a matter of how much capital, exactly how much capital we put to those programs to see what the growth percentage will be in both areas.

Just to be clear though, when you talk about low single-digit, are you trying to signal to us that the lower 48 will see oil growth as well as the oil sands?

All I'm signaling is that overall as a Company, we're going to have low single-digit oil growth and we'll break that out for you, Doug, on the Q4 earnings call.

Okay. Thanks. My follow-up is there's obviously a lot of resource detail, type curves and so on this quarter. I'd like to hone in on one issue if I may, which is the increase in the unrisked locations, particularly in the Wolfcamp. Given that you still haven't provided any risked locations there but you have increased the unrisked locations. It's now the biggest backlog I guess, unrisked backlog in your portfolio. I'm just trying to understand what is it going to take for you to start more aggressively allocating capital to that area? And how do the economics stack up, for example, relative to the Delaware and the Bone Springs? And I'll leave it there. Thanks.

Good morning, Doug. This is Tony Vaughn, here. I'll take a stab at this. Doug, as we've approached our work in the Delaware Basin, we've really highlighted the second Bone Springs and the Delaware sands as probably being the two most prolific from a rate of return perspective. That's where a lot of our focus has been through 2015. We have done enough appraisal work to start building our 2016 program going forward, which will still have a nice component of the second Bone Springs with very high returns.

You'll probably see us have a little bit more influence from the Leonard interval in 2016. We've got that appraised. You can see in the operating report, we've had some good Leonard wells that are coming on. So we'll have a couple of, what I would anticipate anyway, a couple of rig lines dedicated to the Leonard. We're also contemplating really how to appropriately develop the stack pay sands. The Wolfcamp's got up to four different intervals. We have assessed that. We're getting a lot of industry activity on the Texas side of the basin moving right up to our play. Now we're starting to see industry and Devon has drilled about four or five Wolfcamp wells this year. So we're understanding the play.

We still find that the economics for the Wolfcamp are slightly disadvantaged in comparison to the second Bone Springs, the Delaware and the Leonard sands, just because the cost of the drilling complete costs. So we're incorporating that. I still don't think it will have a large influence in our 2016 activity with the one exception, when we get towards the latter parts of 2016, we will have -- we will be incorporating, lack of a better way to put it, more of the super pad type concept, which will be incorporating Wolfcamp all the way up through the Delaware sands and really trying to take a holistic development concept into our business.

Doug, I'd just add, we have such strong results in what we think is a little bit better economics in the Bone Spring and now the Leonard and to some degree the Delaware sands that we haven't been as actively developing the Wolfcamp. We know it's there. I look at it as just having a lot of option value out there for us right now. The resource is there. There's no question. We're just focused our dollars on the highest return.

Thanks very much, indeed.

Thanks, Doug.

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

Thanks. Good morning, guys. I was wondering maybe if we could stay on the Delaware for a minute and can you update us on progress with infrastructure out there and what you all think needs to be done as you go forward in growth? Obviously, the growth that you guys are projecting for Q4 in the Delaware is pretty substantial, and can you just talk about what EnLink's doing there for you guys and what you plan here over the next 12 to 18 months?

Yes, I think we'll let Tony answer that and I may add on if there's anything additional.

Okay. I'll be happy to, Dave. Scott, I think it's a great question. As we've talked about in the past, infrastructure in the Delaware Basin has been a challenge, as specific or more localized in different areas. We've had some substantial relief in that as we've tied in a large portion of our what we call our Cotton Draw area and to a DCP plant called Zia II. That has allowed us to move a lot more volumes. We're also starting to see a few more right of way permit approvals come forward which is going to allow us to continue to bring wells on.

So it's getting better. I think in 2016 the outlook is much better. We are doing a really good job of planning our business I think to take advantage of the infrastructure and the permits that we have in place right now. If you go back and take a look at our Delaware performance on a standalone basis, it's been a little bit lumpy and in Q1, our volume growth from Q1 into Q2 was -- it was exceptional. If I remember right, it was over 20% growth just on a quarter-to-quarter basis.

Q3, we had less development wells that we brought on. The timing of those wells wasn't positive. And again, the tie-in to the Zia plant caused a lot of starts and stops to our business. So we had a lot of down time. So really our oil volume growth, we actually saw a little bit of a downturn in Q3 on oil volume growth.

I'll have to remind you though, that the wells that we continue to bring on are every bit as good as they've been in the past. If we look forward into Q4, we'll have more of an influence from the low risk development type work that we do in Southern Lee and Eddy Counties. We've got less impact of infrastructure that's coming to us by the end of the year and we're working with a BLM.

The BLM's still going to be a little bit of a challenge there for permit approvals. Really just look at the Delaware over the course of the year and I think we saw something like 30% volume growth from year-over-year and I think about 50% oil growth. So it's still our most active area and one that we have a lot of emphasis on.

I appreciate that color. Thanks. And my follow-up is on the Merrimack play. Seems like you guys and the industry as well in general have seen better results and you all pointed out too, I guess lower well cost on top of that. Can you just talk about how that fits into the portfolio on a rate of return basis and where that inventory could go? Right now, I think you've talked about 500 risked locations but ultimately with some your down-spacing potential, where do you think that could go?

Scott, we're real pleased with the Merrimack, as is the industry right now, and we participated in I believe about 20 wells to date. Industry's got about 100 wells down in the Merrimack. I think in a lot of ways you could kind of look at the Merrimack play as already moved through the appraisal process and really is getting into more the development phase. When we look at the commercial expectation for the Merrimack, it really competes in our mind with our top-tier returns from DeWitt County, the Powder department in the Powder River Basin and also, the southern portions of Lee and Eddy County in the heart of the Delaware Basin.

We think the Merrimack is going to be another top-tier asset for us. We've characterized about 500 locations there. My own mind that's conservative and that will as we drill that out, will have the potential to greatly improve. So it's going to be one of our go-to areas as we go forward. It's slightly more commercial than say, the work that we -- the good work that we do in the Woodford right now and the Cana area.

Will you be willing to provide a multiple on where that 500 locations could go? Are we talking double? Triple? What do you think the upside range on that could be?

I'd probably be hesitant to quantify that right now. I think it's still early in the play for us to do that. We'll keep some meat on the bone there and communicate as we go forward but we'll continue to keep you abreast of that. In my own mind from a technical perspective, I'm highly encouraged that that play will continue to develop for Devon.

Appreciate it. Thank you.

Your next question comes from the line of Jeffrey Campbell with Tuohy Brothers. Your line is open.

Good morning and congratulations on the strong performance. My first question was your continued LOE cost reduction is quite impressive. Can you rank order what can continue to drive costs down going forward?

This is Tony again. I'll talk a little bit about that. One of the things, Jeff, that we knew going into the downturn here that LOE would be a little bit sticky and would not drop as rapid as say, our capital efficiencies could bring. As you can see from our operating report, this particular quarter, we've had outstanding results on LOE in terms of both dollars and LOE per BOE. So I think we're really moving right into the portion of the work that we're doing that's offering the most drop in cost right now. We're optimistic that this will be sustainable and we'll move into 2016.

So specific to your question, I think a lot of the work that we are doing building out infrastructure in the Delaware Basin, Anadarko Basin, some of the heavy, more intensely capital areas right now is really providing a benefit in our ability to handle water both more efficiently and more cost effectively. So we're handling a lot more of fluid these days and so I'd say water is the big component of that. I'll also say our focus on artificial lift is really having the opportunity to drive costs down now.

We're putting a lot more attention to our chemical programs, which is reducing our intervention rate, reducing work over cost going forward. We're optimistic that -- we're not done with our LOE work. We've got a lot of joint efforts between our supply chain group and our technical teams, looking for not only efficiencies but also taking advantage of the market conditions. I think I'd look for an improvement as we go into 2016.

As we focus our dollars really into just more pure development and so we're concentrating our drilling in specific areas, that's what really allows you in many cases to lower the LOE where you don't have scattered drilling across a larger area. Instead, you're in a very concentrated geographic location where there's synergies in the infrastructure you have to put it from well to well. And that's what we're doing largely in 2016 and one of the reason we're optimistically can continue to attack the LOE.

Thank you for that thorough answer. My other question is this quarter's operation report on the Leonard Shale expanded on its three zone potential. Can you give us some idea of what percentage of your 60-acre position has three zone potential? Does most of it have two zone potential? And is there any meaningful mix differences between these zones?

I can't give you a specific answer for that. I would think in our Leonard, when we look at it, I know where a good portion of it has got the two zone potential and I think there's some general localized area that have the three zone potential as well. When we characterize the opportunity going forward in our unrisked locations, we're thinking we could see up to 20 wells per section in three different zones. So high confidence in two intervals and with some localized areas of three different intervals in the Leonard.

And do they all pretty much behave the same way in terms of OM mix, NGL, that sort of thing?

Yes, I think it's probably a little early to comment on that. We don't have just a lot of specific data to give you more of a fact based answer. So it's probably a little bit early to define that.

You would think intuitively they probably would because they're very similar depths but we do need to do some more appraisal to know the answer for sure.

That's fair. We'll look forward to that. Thanks very much.

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

Good morning and congratulations on all the good stuff that's happening across the Company. I just had a question around CapEx if I may? Your guidance for Q4 E&P is $800 million to $900 million and you've got $2 billion to $2.5 billion E&P for next year which is sort of another 30% reduction. I just wanted to get a sense, obviously industry deflation has already happened a lot this year. How do you get those costs down further and maybe give us some sense of how much is deflation and how much is activity from here? Thanks.

This is Tony. Let me describe I think what you're probably seeing in there. So in Q4, we have what I would classify or call non-repeatable type investments and we have a fair amount of exploration activity and appraisal activity that have really were initiated in the beginning of the quarter and will be essentially closed out by the time we get into 2016. You know we're doing some appraisal work on the north Texas horizontal refracs. We've got the ability to control that.

We also have some nonrecurring capital items in Jackfish associated with three new pads, one at J1 and two at J2. There's a fair amount of spend in Q4 that won't be repeated in 2016. I would also have to tell you that when you look at the operations report, we commented generally on how many rigs we had running at the close of the quarter. But since then, we've dropped rigs in the Rockies and the Powder down to one. We've dropped down from 10 in the Delaware down to eight and may go to seven.

We're still trying to contemplate what our 2016 spend is. We know the capital spend in 2016 is going to be dramatically different than it is in 2015. We're very aware of that. We've got good history of performing to our capital forecasts. So we're on top of it, Ed, and we're working it down to be consistent with the business environment that we'll talk more about in the next call.

Okay. And then coming back to the Delaware, these super pads are going to be presumably very efficient. I don't know if you've got a sense of other than the deflation in the industry what cost reduction you could get as you go to full development mode of three zones in the Leonard and Bone Springs and other zones.

Ed, we've got a project team that was stood up probably I think, probably a quarter ago and they're really trying to understand and explore the opportunity there. It's really a lot of different scenarios and variations that they're contemplating. It's probably early to comment on specifically what our expectation would be. But I think just to describe that, we're getting ready to pilot in the fourth quarter of 2016. We'll be active on a first super pad where we'll have up to 12 wells and a quarter section. And as Dave mentioned just a moment ago, the efficiencies gained on that kind of a development are substantially below.

We would start turning our operations to having less permitting obligations or challenges, just because of surface disturbance would be much less. We could see the opportunity for batch drilling going forward, not really having to have time associated with substantial rig moves since everything would be on a pad. We would have the ability to do simultaneous operations and have some fracking work going on while we could be producing. So we're trying to understand and define that and we'll have a keen eye on maximizing present value or returns as we think through that. So it will be a balance between size and scale and efficiency and keeping some predictability in our rate growth and cash flow growth that we'll be focused on.

Just to be clear, the rigs you're dropping in the Delaware, that's really because of efficiency gains or are you lowering the number of completions?

It is associated with efficiency gains and Ed, you know that's really our growth area and high focused area. We'll keep all the rigs running in the low risk development areas that are offering the greatest returns. So we're starting to get so much efficiencies out of the rigs that we've got now just from continuous improvement. I guess I'd also say both on the -- not only just on the rig activity but also on our frac crews as well. So we're just -- the pace of our business is ever increasing like it always has.

Hey, Ed. That type discussion holds true not only in the Delaware but also holds true in many of our areas where you've seen throughout our operations report where we have been improving the drilling efficiency significantly. We've done it in the Eagle Ford, we're doing it in the Anadarko Basin, in the Cana and the Merrimack. So we are getting a lot more productivity per rig.

Frankly, we probably need to get away from talking about number of rigs at some point and talk about number of wells that we drill because that's a much better indicator of our activity levels. We're just getting a lot more productivity than previously. You just don't need as many rigs to accomplish a program.

Thank you.

Your next question comes from the line of Peter Kissel with Howard Weil. Your line is open.

Hi, guys. How are you? Thanks for taking my questions. Just to start off with, maybe Tony, following on the prior question that you alluded to the answer here. But with regards to Jackfish, what's the total spend level in 2015 now that you're coming close to the end of the year? And looking at 2016, is that $150 million to $200 million still a base case spend level we should be expecting?

I think Peter, if I recall right, we're going to spend roughly about $600 million, $650 million in 2015. We're still putting our thoughts together for 2016, but that number will go materially down, probably in the range of something approaching $300 million, maybe a little less than $300 million, if I recall.

Got you. Okay. Thanks, Tony. And then maybe more of a broad based question. Portfolio optimization rationalization has been very successful for you guys over the last two years. Can you please just update us on where you stand with the upstream assets? In particular, any sales you're looking at, any acquisitions? I know that's a little tricky given your focus on preserving capital at this time. And then maybe you how does your ownership of EnLink units factor in here as a source of capital?

Hi, Peter. This is Dave. Well, first off, we're very happy with our portfolio. We think that we have really significantly transformed the portfolio through over the past few years divesting the Gulf of Mexico and international, the Canadian conventional, the non-core US. So now, we really try to focus our assets into top -- in the best portion of the best plays in onshore North America and we think now we have that kind of portfolio. So we're first off very, very satisfied with where we stand.

If we were to look to add anything, and we always are out there evaluating if there's anything worthwhile to consider, if we were to add anything, it would have to be something that would compete for capital internally with our own opportunities, which again are located in the best parts of some of the best plays. And so, we have to be very high quality before we would consider adding anything. There are always some things that I think -- especially right now, there are not attracting capital in our portfolio, significant amounts of capital.

And if that condition persists over a number of years, then we will consider moving those assets out of the portfolio. We think we generate the most value when we are investing funds or getting a return significantly above the cost of capital. And so if we're not in a position where we think we'll be investing in an area for the foreseeable future, then that over time you could see that as a candidate for divestment. That's the philosophy we've always taken and that's the philosophy we'll continue to take.

As far as EnLink as a source of funds, we really like our position in EnLink a lot. We think it's a strong Company. We think the Company is poised to grow. We have no plans for any current unit sales in EnLink. We look at that asset just as we look at all the others assets in our portfolio.

Thanks, Dave and congrats on a great update.

Thank you, Peter.

Your next question comes from the line of John Herrlin with Societe Generale. Your line is open.

Yes, hi. I was wondering if you could give more detail on the enhanced completions in the Bone Spring? What you did different?

Well, I think, John, this is Dave. I'll kick it off to start with. I think the main thing that we have been doing over the past few quarters, you've seen the results, is to really increase the sand concentrations significantly. We went from around 600 pounds of sand per foot a few quarters ago, up to and we experimented up to as high as 3,000 pounds of sand per lateral foot.

I think we backed off now to what we think is the optimum amount sand which in most cases in the basin part of the play for the Bone Springs is probably somewhere between 1,500 and 2,000 pounds of sand per lateral foot. But I think Tony, you might have a little bit more detail on that. The main thing is, we are really just concentrating on the highest areas and just getting great returns in those areas by concentrating on some of the most productive areas for the Bone Spring.

Yes, I think that's right, Dave. So John, you know it's really a combination of a lot of things, but we've got some great work that's ongoing with our subsurface teams. We're integrating all of our data much more rapidly and better with a lot more influence from the data. We're taking, I think we've told you in the past, we're taking a lot more full bore cores and pressure and we've got fiber optics and so we're having a much better understanding about the subsurface. We're also incorporating that into our frac design and modeling work.

And then finally, I'll point out that the execution of our work on the completion side of the business is also dramatically improving. We've stood up our 24-hour, seven day a week well con center, probably about 18 months ago and that now has stations involving all of our frac operations and flowback operations. We've got a unique -- what I think is a complete package that's driving the results that we see.

I think what I'm most proud about from our technical teams is over the past two quarters, we really own the top completions per public data in all the basins that we're working. So we're really doing a lot of good technical work with good execution that's driving our results up. And so I think if you go back and look at our first quarter of this year, second quarter, we don't have the third quarter data in, but we probably have at least the top 50% to top 70%, 75% of the top-10 IPs in the basins we work. So doing a lot of good, thoughtful work that's leading to that.

Thanks. Last one for me is on the park when you shot a 3D, when will that actually be useable? First half?

John, we've got the data in house and it's being incorporated into our work right now. We've actually got great 3D coverage across that entire Parkman Turner play. It's influencing what we do. If you go back and look at the work that our technical teams have delivered, we're drilling long laterals there and exceeding our type curve performance. All that data is yielding some outstanding results.

Great. Thank you.

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

Thank you. Good morning.

Good morning, Brian.

In the Anadarko Basin, you talked to the 60 wells coming online from the Gordon Row area. Can you just refresh us on your working interest there and then how you think about the production impact over the next few quarters and what the oil versus gas versus NGLs mix is likely to be?

Brian, this is Tony. You're right, we're working on the Gordon Row right now and doing some really good, thoughtful work. We have a rough working interest of 50%. We're in the AMI with some recs and working that relationship really well. Our percent oil cut is consistent with what we've been seeing. It's starting to get a little bit more rich but we're going to see about -- I think we've actually put on our IP about 80 million plus, 80 million to 90 million cubic feet per day gross already from the wells that we have delivered into production right now. And I think the ratio of the liquids and gas is consistent with what we've been seeing.

We have our type curves out there, Brian. We have about 5% condensate on it. I don't have the type curve in front of me. I know it's in all of our investor presentations. I can't give you the NGL and gas. I think Scott has near 40% NGLs and that means about 55% gas.

Great. Thank you. And then maybe a little bit more off the beaten path. You highlighted in the ops update the horizontal refrac opportunity in the Barnett Shale. Can you talk about how committed you are to spending capital on those in the context of all else that's in your portfolio and whether that lowers the decline rate from the relatively consistent decline that we've been seeing on a sequential basis in the Barnett or whether it just keeps it at that level?

We are committed to understanding the opportunity. So I would say that we're trying to fund enough opportunities or get enough repeatable results in the play to understand what that development opportunity would be. So it's something that we're putting some investment dollars into in the Q4 of this year. That will probably carry into Q1. Really just trying to define and understand what the refrac opportunity would be, not only in North Texas, but it's a great library for us to understand what it could be across the rest of our portfolio.

When you look at it, I think we've commented on that it's got meaningful returns. We probably need at the low gas price that we're seeing now, we'd like to see more gas price to have it compete effectively with some of the other good opportunities that we have. So we're really just trying to understand the opportunity through the appraisal process and then we'll take a pause and see how that competes.

Great. Thank you.

Your next question comes from the line of Evan Calio with Morgan Stanley. Your line is open.

Good morning, guys. And strong results again. My first question on the access dropdown language was modified as to be as early as the first half of 2016. Can you discuss any structuring alternatives and if unavailable to draw for cash, would that alter your 2016 capital spending in any way?

Well, we believe that we can drop it and so we think we can drop it to EnLink. I have also said that we are taking efforts out there to understand what the market is also for that asset outside of that. Our preferred option is to drop that asset to EnLink and we believe that we can drop it. Now, if their situation had changed dramatically, it would really have to change dramatically for this to take place.

But if it were to change dramatically, we would obviously since we're including that in our anticipated cash flow for 2016, and we look at adjusting if that situation were to occur. But we think that's a very unlikely outcome. We're very confident that we are going to be able to transact on access in the first half of 2016.

Great. I appreciate that. My second question, it looks like you're taking your Hailey pad completion design and applying it across your Cana-Woodford. I know it's a harder question, but how much of the Hailey 50% initial performance of the Cana-Woodford, above the Cana-Woodford type curve can be attributed to better rock quality and how much to completion design? I know it's a hard question. I'm trying to get a sense of how much this performance could transfer to other areas of the basin, like Gordon Row, where you'll be active upcoming here.

Evan, this is Tony. I really think it's got a lot to do with the good subsurface work that the guys are doing, the completion design work that we're doing. We've got enough data points out there. I think we understand the rock really well. We've got a good -- we've got it mapped. We're got our model over that. So I think the variation and the improvement that we continue to see is really associated with the technical work that both the Dev and Cimarex team jointly have put into our designs.

So primarily completion design we think.

Great. Look forward to seeing those results upcoming.

Your next question comes from the line of Charles Meade with Johnson Rice. Your line is open.

Good morning, Dave and Tony. If I could go back to a little bit more of the bigger picture here with your comments, Dave, about 2016. I believe you've laid out a similar scenario, at least as far back as September, about E&P CapEx of $2 billion to $2.5 billion and getting you flat to up slightly. Can you talk about how that has changed maybe or evolved over the last few months, if at all, and should we be reading any directionality into your comments this morning about prospects for 2016?

It should be identical to what I said and have been saying, I said in the second quarter call and I've been saying when meeting with investors on the road. So don't imply any difference at all. We are exactly where we were. The only exception I'd say is we keep raising the bar, darn it. We keep moving production into 2015. We keep outperforming here in 2015. So that makes -- it means we're going to be delivering this on a higher 2015 volume. So that's the only difference that I would say. But we're going to keep outperforming and we plan to keep doing that for a long time.

Got it. So I think I get your point. The growth number may be the same but the absolute level that you're going to achieve with that $2 billion to $2.5 billion keeps moving up.

Yes.

Got it. And then another question. You guys, and it's been a theme in the Q&A here that you've had a lot of positive things go -- a lot of positive elements all across your US unconventional portfolio. But can you give us a little context or perhaps some insight into how you're thinking about which of these plays or opportunities, which of them rank most high on attractiveness or kind of rate of change in attractiveness and also on materiality to Devon in 2016?

I'll have Tony go through that with you. I'd like to take this chance just to make a comment too. You have seen obviously tremendous improvements and we talk a lot about improved -- the higher sand concentrations and lower drilling costs and all of that. But I think I want each of you out there to understand. The reason we're doing this is we have the absolute desire to be the best operator in each of our core areas. We talk a lot around here about not being one of the best. We talk about being the best and an intolerance of mediocrity. Those are the words I say to you guys. It's the words I say internally. And I can tell you, there's a lot of energy in the Company around that entire notion.

When you have that kind of attitude I think in a Company, that's when you really start delivering the kind of results you've been seeing out of the last few quarters. That's why we have confidence that we're going to continue to do this. We're not sure exactly what's going to be the next thing that comes down the line to improve our results, but I can tell you, we're absolutely focused on being the best supplier of whatever it be. With that, I'll turn it over to Tony to talk more specific on returns for each of the areas.

Charles, if I just had to categorize generally, I would say our DeWitt County returns in the Eagle Ford are consistently high, as well as the Southern portion of our Delaware Basin work, as well as the Parkman in the Rockies. Those have been really what I would call our Tier 1 returns and that's really where the capital is moving towards.

Just slightly behind those returns would be our Cana-Woodford. Again, the Woodford project continues to improve. Our well costs have dropped from $8 million down to about $7 million. As we talked earlier, the IPs and the EURs continue to improve. The Cana-Woodford project is competing in the portfolio right now. I think what will emerge with additional data will be this Merrimack play. I think its will move into the top tier, it will elbow its way in. So we'll have what I think are four very high returns that are top-tier in the US. And behind that, we'll have the Cana-Woodford which has got great repeatability, predictability.

Behind that are really the projects that are not garnering any funding right now and that would be the Southern Midland Basin, it would be the Mississippian play, Barnett, outside of the appraisal work that we're doing on the refracs. So that's kind of how we look at the projects from a return and how really generally how we allocate capital.

Got it. So Tony, on the question of scale or materiality, it sounds like you roughly went in order there or the order I would have guessed, that really Eagle Ford and Permian are the biggest kind of scale of those high quality ones and that the Merrimack is -- that's where the arrow is pointing up the most. Is that the right read?

I think that's it, Charles. Really, our most intense focus area for 2016 will definitely be the Permian Basin and our work in the Delaware and of course, the Eagle Ford is going to continue with the work that we've been doing there. What we'd like to see happen is really increasing the materiality in both the Merrimack and the Parkman in the Rockies. Those are two good plays that have great returns, just not, as you mentioned, just not quite as material to us today.

That is great color, Tony. Thanks a lot.

Your next question comes from the line of Paul Grigel with Macquarie. Your line is open.

Hi. Good morning. Just a quick follow-up on 2016, realizing there's not full guidance out. But could you guys provide any color on the trajectory throughout the year as it kind of stands now on both oil and gas? And then, also if the low single-digit growth, is that exit rate to exit rate or complete year-over-year full-year over full-year?

That's full-year 2016 compared to full-year 2015. And we're not to the point yet on this where we're going to be giving quarterly guidance on it. We're going to cover all that kind of thing in more detail on the Q4 call.

Okay. Thought I would try. Turning on the operation front to the Eagle Ford, you guys have talked about the staggered development concept as well as the upper Eagle Ford. Could you provide a little bit more color on what you're seeing there but also what you would need to see to step up activity in that area from those tests?

Paul, I'm glad you mentioned that. That's an exciting project that we have working right now and our technical team has done some outstanding subsurface work to recognize the opportunity. We've done -- put a lot of data and reservoir characterization work together, built our models. We believe that the staggered opportunity just inside the lower Eagle Ford offers upside to the resource base that we've talked about. That's in addition to the lower Eagle Ford that we described in our past couple of calls.

So we think the resource base has got the opportunity to grow. We've kind of highlighted that in our operating report now. I'm pleased to report, while it's early, our first staggered lateral result in our central core area in the DeWitt County solve with a slight offset to an existing producing well near original reservoir pressure.

So I think what we're going to see is the ability to come back and take all of our undrilled areas, go to a staggered approach, increase the ultimate recovery and the total value of the field. I think we'll also have an opportunity to come back into areas that have already been drilled and lay in some staggered laterals in addition to that. And couple that with the opportunity to put a stacked lateral in the upper Eagle Ford on top of that, I think there's still a lot of resource work that our technical team is excited about right now.

Great. Thank you.

Your last question comes from the line of Jeffrey Campbell with Tuohy Brothers. Your line is open.

Thanks for letting me get back in for one more. I just wanted to clear up one thing real quickly and that's with regard to the infrastructure expansion in the Eagle Ford. Is that essentially an aspirational number for Devon's future production or do you see any third party volumes getting into there?

Well, the infrastructure volumes we have available, those are the numbers that are actually available. Now, whether we realize that volume or not depends on the amount of capital that we put against the program. So we're just showing what the system capacity is in the Eagle Ford for our production and at this point, we don't have any current plans I don't think to put any third party volumes in that. That's just our -- within the Eagle Ford, our capacity within the DeWitt County, what our capacity is.

Okay. Thanks for clearing that up.

Jeff, we've had a lot of questions on the capacity, the reason we put that in there, not to signal anything else. Just a matter of what Dave said around commodity price and whether we add additional capital in there, that there is no bottleneck other than commodity price and our activity levels.

Thanks for clearing that up.

There are no further questions in queue. I turn the conference back over to our presenters.

Thank you, Tiffany and we appreciate everyone's attention and investment in Devon Energy. We hope you have a wonderful day and we'll see you on the road soon. Thanks so much.

This concludes today's conference call. You may now disconnect.