德文能源 (DVN) 2016 Q3 法說會逐字稿

Welcome to the Devon Energy third-quarter 2016 earnings conference call.

(Operator Instruction)

This call is being recorded.

I would now like to turn the call over Mr. Scott Coody, Vice President, Investor Relations. Sir, you may begin.

Thank you, and good morning, everyone. I hope everyone has had the chance to review our third-quarter financial and operational disclosures that were released last night. This data package includes our earnings release, which includes forward-looking guidance and our detailed operations report.

Also on the call today are Dave Hager, President and CEO; Tony Vaughn, Chief Operating Officer; Tom Mitchell, Chief Financial Officer; and a few other members of our senior management team.

Also, I would like to remind you that comments and answers to questions on this call today will contain plans, forecasts, expectations, and estimates that 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 and actual results may differ materially. For a review of risk factors relating to these statements, please see our Form 10-K and subsequent 10-Q filings.

With that, I will turn the call over to Dave.

Thank you, Scott, and welcome, everyone.

Devon delivered another outstanding performance in the third quarter, both operationally and financially. Our development programs delivered the best quarterly drill bit results in Devon's 45-year history, with new wells reaching peak 30-day rates of nearly 2,000 BOE per day. These prolific drilling results were centered in our world class STACK play where production increase by nearly 40% year over year.

Furthermore, the value of Devon's production continued to be enhanced by substantial cost savings achieved during the quarter. We are now on pace to reduce operating and G&A costs by $1 billion for the full year, which provides an uplift to our margins of nearly $5.00 per BOE produced.

In addition to our strong operating performance, another important accomplishment for Devon was a recent completion of our $3.2 billion asset divestiture program. These accretive transactions significantly strengthened our investment-grade position, and, as a result, our net debt has now declined by 45% since the beginning of the year. To further enhance our financial position going forward, we've also been much more active building out our hedging position with the recent increase in commodity prices.

With a more focused asset base and improved balance sheet, the next step in our strategic plan is to accelerate investment in our world class onshore resource plays. By the end of next month, we plan to have 10 operated rigs running focused within our top-two franchise assets, the STACK and Delaware Basin.

Looking ahead to 2017, we are still working toward finalizing the details of our operating and capital plans. However, I can tell you that at $55 WTI pricing; our upstream cash flow in 2017, including EnLink distributions; is projected to expand by more than 100% year over year to around $2.5 billion.

Under this scenario, we would steadily ramp up drilling activity over the next several quarters to as many as 15 to 20 operated rigs in the US by year-end 2017. This program would represent upstream capital spending of around $2 billion, allowing us to invest within available cash flow.

On a retained asset base is, this focused investment in higher-margin projects is expected to drive double-digit oil growth in the US in 2017 compared to the fourth quarter of 2016, which marks the low point in Devon's production profile. As a result of this growth in oil volumes, top-line production in 2017 will range from low- to mid-single-digit growth compared to Q4 2016. This range is dependent upon the level of ethane rejection during the year.

Importantly, this capital plan is designed to create operational momentum and much stronger growth rates heading into 2018. At a $60 WTI price-point in 2018, our upstream crash flow has the potential to reach $3.5 billion, a greater than 200% increase from today's levels.

Under this scenario in 2018, we would continue to aggressively ramp up our drilling programs within the US with a majority of this capital directed to the STACK and Delaware Basin. This low-risk drilling activity is expected to drive production growth of greater than 30% from our STACK and Delaware Basin assets and 2018. This strong growth would further transition Devon's product mix toward higher margin, light oil production in the US.

Now, I want to be very clear. While we are excited about outstanding growth prospects that reside within our portfolio, our capital allocation will be focused on value and rates of return, not the pursuit of top-line production growth. And, if commodity price volatility continues, our capital programs have significant flexibility with no long-cycle project commitments and negligible leasehold expiration issues. This flexibility allows us to be nimble and tailor activity to invest directionally within cash flow.

Another strategic imperative for Devon in the upcoming year is to further delineate and better characterize the growing resource base associated with our US resource plays. Between the STACK and Delaware Basin alone, we have exposure to more than 1 million net acres and thousands of development-ready drilling locations that are highly economic at today's prices. To advance our understanding of the ultimate recovery and resource potential within these two world-class plays, we have important appraisal work underway.

In the STACK, this catalyst-rich activity is concentrated on the Meramec infill spacing pilots and further derisking of the Woodford oil window. In the Delaware Basin, the Leonard Shale opportunity set continues to expand, and we are now flowing back on our first stacked lateral test that will help shape our view on how to best develop the three prospective landing zones in this oil-rich shale.

2017 will also be a breakout year for our Delaware Basin Wolfcamp program, as we begin to actively develop this emerging play. The Wolfcamp will have a material impact to Devon's resource potential in the Delaware, and we are excited about progressing our understanding of the 9,000 plus potential locations we have identified in this play.

The bottom line is that Devon's asset portfolio has never been in better shape than it is today, and I believe that the quality and depth of our opportunity set is unmatched in the industry. We possess thousands of undrilled locations that are extremely well positioned on the North American cost curve.

This high rate of returned inventory will continue to expand as we derisk the tremendous resource upside associated with our STACK and Delaware Basin assets. With this resource expansion, it could necessitate additional high grading of our portfolio, monetizing less competitive assets and accelerating development of our highest rate of return inventory.

In summary, before we move to Q&A, I want to leave you with a few key messages from today's call. First, our improved financial positioning now allows us to aggressively accelerate drilling activity across our best-in-class resource plays, while continuing to focus on the value and rate of return of each investment. These accelerated drilling plans will drive attractive cash flow growth in 2017 and 2018, compared to today's level and continue to transition Devon's product mix toward higher margin, light oil production in the US.

In conjunction with our shift to higher margin production, do not lose sight of our peer-group leading leverage to rising commodity prices. For everyone $1.00 increase in realized price on a per BOE basis, Devon generates more than $200 million of incremental cash flow annually.

Looking beyond prices, Devon is also catalyst rich over the next several quarters, as we further delineate the massive resource upside associated with the STACK and Delaware Basin positions.

Finally, with the continued growth and the quality and depth of our resource base, we expect to have an overabundance of opportunities. If this is the case, we are very willing to further high-grade our portfolio and deploy additional investment toward the best projects in our portfolio.

With that, I'll turn the call back to Scott.

Thanks, Dave. We will now open the call to Q&A. Please limit yourself to one question and a follow-up question. If you have further questions, you can re-prompt as time permits. With that, operator, we will take our first question.

(Operator Instructions) Evan Calio with Morgan Stanley.

Good Morning, guys. Dave, you mentioned you are evaluating the total inventory issue as you prepare two core basins to move into development mode in 2017. That is something supporting a newer 2018 guide, here.

A high-level question, though, is what you believe the optimal inventory depth should be, maybe on a years-of-activity basis? It sounds like we should expect a continued rationalization program if locations grow well beyond those optimal levels. Any thoughts, there?

Evan, that's always a very difficult question to answer exactly what is the right inventory level. It's somewhat akin to the old R-over-P ratio we used to talk about for many years. Obviously, directionally, you can have so much inventory that you are not maximizing the inventory value or you could have too short of an inventory that there's questions about the long-term growth of the Company. There is certainly a balance point in there.

To name an exact amount of years of inventory is somewhat difficult. I tend to think probably around the order of 20 or so seems about appropriate. It's certainly a subject -- I often turn the question back over to some of you guys to give your feeling.

I can tell you, I'm somewhere in that range, 20, 25, something like that.

Yes, maybe 15, 20, from our view.

A different question. You provide the year-end 2016 and 2017 rig unit levels. I know the Board hasn't approved the budget yet, but can you talk about the ramp, correlated to the move? Is it back-end loaded as you move into development mode, or what's the ramp pace to the 15 units? Is the five delta, something commodity related or maybe asset supported, asset sales related? Any color, there?

Let me kind of walk you through that. The 10 at the year-end 2016, it's essentially set, and we are executing that.

It's important to understand it's really 10 rigs plus the completion activities we are conducting, that is really driving our 2017 volumes.

So, that's why we're very excited and confident on the volumes that we talked about in the operations report. The ramp up to the 15 to 20 rigs, really won't add production in 2017. That's why we are so excited about 2018, as we do ramp up to that level. That's what's going to provide even higher growth levels as we move into 2018 led by more than 30% growth in the STACK in the Delaware.

The variability around that, it's more at this point, more commodity-price driven although, frankly, we do have -- we are committed roughly to live within cash flow. If there's a little bit of variability around that, we are willing to exceed cash flow by a minor amount, perhaps, if necessary, supplement with incremental small-scale asset sales.

We also, as you know, we've been hedging our -- significantly more; so that's help underpin and provide more comfort to the cash flows that we'll have in 2017, but the opportunities are there. We are confident we have the opportunities there, so I'd say the delta is really more commodity price driven then opportunity driven. (multiple speakers)

Evan, This is John. One thing I'd like to add, too, I would say it's about productivity as well. If you look at where that capital is going, it will be focused in the STACK in the Delaware Basin, two of the highest rate-of-change plays that you are seeing as far as drilling days and proof completion designs right, so I would say we're getting better and better at that and that would have an impact with regards to what that rig ramp would be needed to deliver the production we talked about.

Particularly (inaudible)

Doug Leggate with BofA Merrill Lynch.

Good morning, everybody. So, Dave, you've raised the tide curves obviously in the STACK, but you have not addressed the issue of the inventory. My recollection you are using four wells per section, three upper and one lower, if I recollect.

What you need to see in terms of your density spacing, in order to update that backlog again? What's your thoughts on it, if you can.

Doug, to be clear, the inventory is going up. There's no question about that. We've had about three successful pilots, so far and I think we've tested, one zone up to seven wells per section and that's worked out very well.

We have another 10 pilots or so that are detailed in the operations report, the locations of those pilots. Really, it's just a matter of timing when we feel like we have enough information from each of those pilots to increase the number. There's no question it's going up.

Tony, you want to add any details to that?

Doug, I think Dave summed it up perfectly. We are working on coming out of 2017 with development in two of our areas central to the work that we've been doing with the pilots and, as we've got the detailed data already in house on the three operated pilots, we are starting to get data in right now on three non operated pilots and as Dave mentioned, we've got another six or seven pilots that we are engaged in, now.

All that information is helping us inform our 2017 development plans and I think, as we get more data under our belt, we will come out and see a material increase to that inventory.

Okay. I guess I have to be a little more patient. My follow-up, if I may, I realized oil is heading in the wrong direction again this morning. It's -- who knows what 2017 is going to look like.

Do you believe the trajectory that has got you tripling cash flow, basically, by 2018 at $60 oil? I'm just curious as to what should we infer by way of your activity level with that level of cash flow and, perhaps, even a higher oil-price environment Where does Devon go in terms of activity? Or do we flatten out the targeted growth level at a particular rig level? Or maybe returning cash to shareholders, at some point.

Doug, as you well know, we have a very deep inventory of opportunities. Certainly, the two franchise assets that we have are the STACK play and the Delaware Basin play.

We could even -- if prices go even higher than that, we certainly can ramp-up activity even further there. We are always going to be mindful, I want to emphasize, we will be mindful of the returns. So, we're not driven by top-line production growth. We are driven by getting good return for every dollar in our capital program.

We feel we have the opportunities we could further drive up activity in both of those areas. Plus, we have other areas that we are not funding right now, as much as could be, if we had higher cash flow levels. They are already have returns well above the cost of capital. They just don't compete as well to Delaware Basin and the STACK.

The Rockies, we are starting to fund now with one rig. We could add activity there with strong returns and even the Barnett. We laid out some numbers in and operations report how we are driving down the cost there and we think we have program that we do both from a horizontal refracs and from additional drilling locations, that right now are well above the cost of capital. They're just not as good as the Delaware Basin and STACKs.

We are focusing our capital there because they are the highest returns. So, we do not have a shortage of opportunities. So, I think we would, if prices are even higher, we would look at funding some of those opportunities, as well.

David, I don't want to labor and take up too much time. I want to be clear what I'm asking which is one of your competitors is talking about mid cycles of $55 level and I realize that's totally subjective.

Their point is, in the higher oil-price environment, the industry got itself into a bit of a mess by growing too quickly and they look upon that as a windfall and would not jerk around their rig count with a view to longer term sustainable growth.

What I keep on hearing from you, is that you would respond to higher oil price with higher activity levels.

I guess my question is, is that what the industry wants to see is high growth that's going to keep this oil price up and the problem we've got right now, or is it an argument that says work towards a growth level and return any perceived quote-unquote windfalls to shareholders? I guess that is really what I am asking

Doug, it's my view that what got the industry in trouble at the higher commodity prices, is that there are a lot of projects that were funded out there that were really -- didn't -- they were very marginal projects, and we didn't pay enough attention to the reservoir. We didn't pay enough attention to the fundamental economics. So, I don't think it's so much the activity level, in and of itself, is the fact that this activity level was really going toward projects that didn't provide the returns that they should.

So, I can tell you here at Devon, we are very, very focused on returns and we're very, very focused on the reservoir. Making sure that each project that we do is going to provide good returns. I don't think it's necessarily a problem as long as you can, on an individual Company level, as long as you can be confident you can provide good returns.

I think what really happens at $90 oil, a lot of these projects being funded were not providing good returns. We are over capitalizing some of these fields, frankly, and that is what the big issue was.

Appreciate your honesty, Dave. Thank you.

Ryan Todd with Deutsche Bank.

Maybe, if I could follow-up on STACK activity. Can you talk about how you view the mix of Meramec versus Woodford activity as we look at 2017?

Any thoughts on what the potential swing in non-op CapEx might look like there?

Ryan, Tony Vaughn, here. Our plans are to, as Dave mentioned, we are at six rigs coming into this year end and we've got the capacity to build up that to roughly about, about 12 rigs.

We have plans in the second half of 2017 to engage back into a drilling campaign on another row called the Jacobs Row, and you see that on page 10 of our operating report.

We haven't gone through the budgeting process, yet. I can't say specifically how this will happen. For the most part, our drilling activity up until about mid-year of 2017 will be concentrated in the Meramec and then, in the second half of 2017, we'll take, probably, roughly about four of those rigs and move them into our Woodford campaign.

If you look at the magnitude of our OBO spending in the STACK play it's quite substantial. I think we talked to you guys before about the level of participation that we have, not just in operated wells, but we have a 430,000 acres in the play. So, we have access to a lot of data, a lot of information and that drives a spend of about $300 million per year from our non-operated exposure.

Okay. Thanks. That's helpful. I know this is always a hard thing to quantify, but, any thoughts on what any year-end for LOE and G&A cost reductions?

The cost reductions over the past 18 months have been extremely impressive. Should we expect to continue to see downward pressure on those?

Is there any risk to inflation in either one of those as we see rigs ramp over the next 12 months?

I will take the G&A part. I will let Tony talk about the LOE side.

We, obviously, did a significant reduction in employees earlier in the year, on the order of 25%. It was a big move for us, as a Company and obviously involved some pain losing some good friends.

We did maintain the key operational capability and the key value drivers that can allow us to execute, we feel, comfortably, a $3 billion capital program, or about 20 operated rigs.

So, we see, really, that given what we've laid out here as potential for 2017 and 2018, that we're comfortable with the level of G&A in the Company and I wouldn't expect a significant change on that, one way or the other.

Tony may want to talk a little bit about the LOE side of the equation. And I think, probably, we found most of the big gains, but I think we are always continuing to look more as the infrastructure increases in some of these fields. There may be some more things that we can do. Tony?

Ryan, I tell you, I've got to hand it to our operating team both in the field and here in the office. They've taken a very passionate approach to driving cost out of the business and you can see the improvements that we've made over the last two years.

I think, if you were to look at the cost for the price of materials and services, it is starting to level out, starting to flatten out in most of those areas.

That doesn't mean we are still looking for opportunities to continually improve our business and some of those areas, we've unbundled or decoupled different components of our operations, as an example, separating the saltwater disposal from the water hauling vendors, that has offered improvements there.

We've continued to build out our infrastructure and have more water in pipe now. We have a better power grid system, especially in the Delaware Basin. All that is tending to drive cost down.

Probably, the tension that was seen in the business is coming. We also have, by virtue of our sale of the access pipeline, an increased transportation fee that would be coupled into our LOE cost.

For the most part, our guys are continuing to work LOE in a very passionate approach.

Thank you.

Arun Jayaram from JPMorgan.

I wanted to see if I could discuss a little bit about your thoughts on guidance. You gave us a lot of clues how we should be thinking about 2017 and 2018 in terms of the ops report. Tell me if this is what you are trying to convey.

You guided to at least double digit US oil production growth in 2017 versus the Q4 guidance. I think the guide was 105.5 MBOE at the midpoint and then if we assume Canada is relatively flat from Q4 levels including maybe a turnaround in Q2. That to me suggests your overall guidance, soft guide, however you want to call it, a bit north of 250 MBOE per day versus the street at 243 MBOE. Am I thinking about that right?

Also, can you give us some sense of what capital it would take to achieve that in 2017?

Let me address, first, the cap. I will have Scott address the detailed question on the volumes.

I did say in my opening remarks, there, that the capital in 2017 we anticipate being around $2 billion of E&P spend. But, it is also important to understand that really, the volumes in 2017 are being primarily driven by the completion work that we currently have ongoing, specifically the Eagle Ford. Also, other areas.

Then, in addition to that, the 10 rigs that we are to have working by the end of this year. The incremental capital going to 15 to 20 rigs, which really, rough numbers, increases the capital budget that would be at 10 rigs if we stayed flat there for the year, probably around $1.6 billion dollars versus going to 20, would be around $2 billion. That incremental dollar is really driving 2018 volumes, which is why we are really excited.

Just because of the timing of how long it takes to bring these wells on production. Is not really a matter of $2 billion that is needed to drive those 2017 volumes.

We could do that at a lower level. It would just impact 2018 and that is again why we are more excited about the growth potential in 2018. Scott?

With regards to the production, everyone, I think directionally you're thinking about that correct. We would expect it to be, when you combine the US and Canada from an oil production perspective, we would expect to be north of 250,000 barrels.

We will firm up that guidance as we get with our fourth quarter call and we are still working through the detailed operating and capital budgets. But, directionally, you are absolutely thinking about that correctly.

Once again, I do want to emphasize, though, it is absolutely being driven by light oil growth in the US. You are seeing a real time shift to high margin production for Devon which is going to significantly enhance our profitability.

That's great. Thank you, Scott and just a follow up. Dave, you commented in your prepared remarks about potentially looking at opportunities, given the inventory depth of high grade, the overall portfolio.

Can you give us a sense of timing and magnitude and what you guys are thinking about, in terms of potentially monetizing more assets?

Yes. There are a lot of variables that go into this equation.

I can tell you, we want to get a greater sense of the inventory, particularly in the STACK and the Delaware Basin, where we are doing these spacing tests in the STACK play, both between the Meramec. You can see also there is now some Woodford oil potential that's developing underneath the STACK, and we want to get a sense for that and how many zones in the Meramec are going to work. We've laid out that we are testing up to eight wells and six in the secondary in the Meramec and we're talking about a Woodford zone, there.

And Wolfcamp, we talk about the Leonard and testing how many zones in the Leonard may work, as well as the fact that in the Wolfcamp, we have 9,000 unrisked locations, there and we've moved about 500 or so into the risked locations and that's got to continue to grow.

That's going to take until -- we will start getting a better field for that probably mid next year. So, that's one factor in it.

The other big factor, really, is long-term commodity prices. Because, you can see the leverage to the cash flow that we have from the operations report. The leverage that we have to higher cash flow at higher commodity prices, which is the highest leverage in the industry. Where do we think long-term commodity prices are going to level out, has a big impact on what cash flow we will have, which has a big impact on how many other opportunities that we can fund in other areas that already have potential returns well above the cost of capital. They're just not as big as the Delaware and the STACK.

We want to get a better handle for both of those variables, probably mid-2017 at the earliest, before we make any strategic calls.

Great. Thank you for that.

Edward Westlake with Credit Suisse.

Good morning and congrats on the risk location update and the cash flow guidance.

Just on the Delaware Wolfcamp, you've put in 500 risked locations, it looks like a large majority in Rattlesnake and the Nabeda. The 9,000 number, maybe just talk through the work that has to be done to sort of unrisk those, and what sort of EURs you'd expect on the core 500.

Okay. Ed, we just talked about in the operations report the Rattlesnake and Nabeda area where we mentioned about 500 risk locations there.

But, we have a total of about 9,000 unrisked locations across our position in the Delaware Basin and I'd have to say that the industry has done an outstanding job of derisking the play. It's moved from the Texas side of the basin up to the state line and now, north of that state line. So, we are utilizing a lot of that information.

We did participate in some non-operated activity in there. So, we are getting a good feel of the potential in the Wolfcamp.

I think some of the things that we're still anxious to understand through some of our pilot work that we'll engage in will be the vertical connectivity between that very thick Wolfcamp column.

We know that of the 2,000 wells drilled, and we drilled some on the New Mexico side, as well, we just really haven't prosecuted that in our development plan. We know from the X Y through the upper, through the lower, portion of the Wolfcamp, it's all productive. So, it would really be a matter of the development style that we choose to engage in.

I think one of the elements that we are incorporating into our thoughts as we go into 2017, is bringing in an aggressive approach from the Leonard A, B, and C intervals.

We've got a stacked piloting engaged right now to help us understand the vertical connectivity. We spent most of our time in the B zone, the industry spent most of their activity in the C. We know each of the three intervals are productive.

We've seen some encouraging results. Were not commenting on that because the data is pretty young right now. We will come back and clear up the results of that, soon.

We'll incorporate the three intervals in the Leonard with the typical work that we do in the Bone Spring and the two in the southern portion of the two New Mexico counties and have a pretty aggressive approach into the Wolfcamp in both the Rattlesnake and Nabeda areas. They will be the first two areas that we engage the Wolfcamp.

Thanks, very useful answer.

Just on the east and Woodford. Your well cost is 6 to 6.5 and the EUR is 1,600 and it is 25% oil and at old Ricky's Ridge well is 60% oil. It almost feels like it'll be better than the stuff over in Blaine, as Blaine gets deeper, the costs go up.

You are getting similar types of EURs, maybe just a little bit of elaboration in terms of why those well results, A, they're cheaper and, B, EURs are so strong. Is it the thickness of the reservoir in that particular location?

Thank you for picking up on that, a lot of variability in the subsurface portions of the Meramec and the Woodford.

The depth does run from the shallow being in the east to the Northeast to the southwest, as you described. Also, about midway between the Northeast of our position and the far Southwest, there's some subsurface intricacies that make us run a third casing stream.

So, as you move up into the old Ricky Ridge area, it's a very important data point there. We wanted to highlight, simply because the oil cut is 60% and we really hadn't valued that in our thoughts about the Meramec. As you can see up there, we think there could be substantial NAV add. If you move the high oil cut across the upper portion of our Meramec play. This really sets us up for that stacked development from the five intervals in the Meramec and the Woodford.

Also, unique about Ricky's Ridge, is was a 10,000-foot Woodford test and we incorporated 70 stages in that frac design and pumped about 2,600 pounds per foot of sand. So, it was a pretty aggressive attempt to see what we could do there. We're very happy with the results. You can see some of the 90 day IP is solid. But, the more important thing is the production profile, it's flat. Much more optimistic than our initial expectation. So, I think Ricky's Ridge is an important data point for us to keep our eye on.

It's a little bit cheaper over there, too. You are shallower to the northeast as you get deeper to the southwest. That's true both where you're drilling Meramec or Woodford wells.

Thanks very much.

Scott Hanold with RBC Capital Market.

I have a question on the STACK. It looks like you're going to be increasing activity to these longer 10,000-foot laterals.

Can you give us a sense of how much of your acreage ultimately do think is a minimal to that? What efforts are ongoing to help block up acreage more so it can become part of the long-term development plan?

Scott, do you know what, that is a good piece of the business that our business unit is engaged in every day. So, we are working with other operators there to block up and try to provide the most opportunities to drill long laterals. We find that to be the right answer, especially in this particular play.

Data is fairly early on that but all the long laterals that we have drilled are outperforming initial expectations. We've got a very aggressive type curve that you can see there. Very excited about that ability to drill those long laterals.

We think about two-thirds of our position is currently available to drill the 10,000 footers. So, the majority of our work going into 2017, or at least two-thirds of that work will be directed toward the long lateral type work.

Yes. Specifically, do you find right now other operators are fairly willing or are we at the right stage in the STACK for other operations to be willing to help do this and block up their acreage as well as yours?

Well, I think there's a good dialogue that's just now happening. There's a part of an industry group that we participate in with most of our larger operators in the field working very well together. I think everybody is looking at operatorship. Everybody is looking at their position trying to make sure that we take a very efficient approach.

Some of the work that you've seen us and heard us talk about with our Cimarex partner in the Woodford, has been very accommodating to both the work that Cimarex does and Devon has done, bringing out the most efficient results and I think we are just now starting to see some of those type of conversations happen with most of the operators there in the Meramec play.

Okay. Thanks. The follow up on the Nabeda area again. Can you give us a sense of why this has popped under your focus? Is it some work theologically you have done or is it more of what you are seeing from industry end? Maybe this is looking at it a little bit too closely.

If I look at this map, you have some acreage outside that little box that you drew down there. Is there any particular reason that is not included?

Well, I think the one thing unique about the Nabeda area, we have about 5,500 to 6,000 net acres there, 8,000 gross, roughly. We've got a nice contiguous position in that portion of the Wolfcamp on the border of Reeves and Ward County. It really sets us up for a more efficient development going forward.

That's really caused us to put that on our radar screen and we are getting a lot of good competitive data around this. There's some good wells that are being drilled there. Again, we are trying to see and understand the vertical connectivity between that column to best understand best how to develop that.

Thanks.

Peter Kissel with Scotia Howard Weil.

May be just another on the cost side, but more on the CapEx side than the OpEx side. In your supplemental presentation you mention you are proactively securing services to mitigate inflationary pressure in 2017.

I was just curious if you could elaborate on that a little bit more. Maybe, where you see inflationary pressures and how you are mitigating that?

Pete, I'm going to introduce Sue Alberti, our Senior Vice President here that manages our marketing and supply chain group. She is very well-connected and her group's with our operating team.

I will let Sue kind of describe some of the work that we are doing on the price of our goods and services.

Thank you. I'd like to say that we do think that as commodity prices improve and activity increases, we are looking that we will get that inflationary pressure next year. We think that that could be mid to high single digits, especially in the stimulation area.

I'll tell you a few of the things we're doing to mitigate those cost increases on the capital side. We did, as you said, we talked about proactively securing equipment and crews at competitive prices, and we are locking in rates and terms, where it makes sense, given our outlook, right now. For example, on the rig side we've locked in two long-term agreements for these rigs at current market rates.

Then, Tony talking about the LOE, said that we were unbundling the water transport and water disposal. We are doing unbundling on the capital side, too, in the stimulation area, and we've recently started this where we contract separately for pressure pumping, sand, chemicals and diesel, taking out the markup of the bundling. And while it's new and we don't have a lot of data, yet, what we realize that what we see now is about a 10% savings from the unbundling.

So, we will look to do may be more of that. We are very encouraged with those results.

(multiple speakers)

One thing I would add. Sue talked about probably the high single digit type service cost increase, again, we think we can offset that with these internal efficiencies that we are doing.

She mentioned some of the efforts. There is a lot more than that going on, just continuing design of the wells, I think Tony may even like to brag on a few wells we've drilled recently in the Delaware. Not sure if you are going there Tony, but I see you are holding a piece of paper I think you are proud of.

And I am trying to let you say your few words and then let me get in here. I tell you, I'm really excited about the work that we do, and we talked a little bit about the passion for the technical work that our operating teams do.

On the drilling side of the business, we just stood up a Delaware rig and have now drilled three wells from spud to TD. Those used to take 17 days to complete. All three of these are averaging about 10 days and that's really an approach to an optimized design that we've had the luxury of tying to a lot more sub surface data that we've had in the past. It's also reflective of, really, the granular detail toward the execution of our business.

Pete, I think we've talked to you about the Welcon center there, so, we're getting a lot of efficiencies both on the drill side of the business and also on the completion side of the business.

All that passion for data acquisition and integrating that into three-dimensional earth models and picking the right landing zone and designing more optimized or better frac designs, all that is paying off and we're also putting a lot of attention into the execution portion of that completion space. We monitor all of the operations on the frac. We monitor all of the data on the flow back of the wells in great detail.

We have also recently incorporated the drill out, the coil tubing drill out data in our Welcon center and we think that's another potential savings, there.

While Sue has mentioned that the industry is going to have some tension on cost, we think, from the technical work we are doing, we've got the ability to offset that in 2017 and very excited about additional enhancements that will be available to us for more of that type of work in the second half of 2017 and 2018.

Great, Tony. Thank you. That's a great answer. One quick follow up, more on efficiency side.

In the STACK, in particular, as activity levels increase, what do you see is the biggest gaining factors there for the play in general but also Devon, in particular? Is it midstream, is it water availability? I know the play doesn't produce much water, but is there any concerns you have looking forward for any of those items?

You know, Pete's, it's not on the takeaway out of the basin. I think Sue could talk to us a little bit of detail but we are not worried about that through 2017 and into 2018. A lot of the pace of activity, right now, is more associated with just doing good, quality work and getting all of the pilot work under our belt before we finalize our development plans going forward.

Just like we do in all of our areas, we'll have a good build out of infrastructure there, so we know that, say on the water handling side of the business, there could be a time when we have 20 rigs running just in STACK. There is a heavy demand on water, water handling. We will be mimicking some of the work that we've done in the Cana Woodford project also in the Delaware Basin to make sure that that's very efficient and our operating cost, going forward, are low and well thought through and Sue, I don't know if you want to add any comments to that?

Let me add a little bit. What Tony was saying about takeaway. We don't have any short-term concerns regarding for Devon processing or takeaway constraints in the STACK. We have been working with EnLink to ensure that they will have adequate processing capacity for us on our forecasted production.

In addition, we've got firm takeaway for our oil and our NGL and actually until 2019, at this point, I would say, though, that longer term, when you think about the growth in this area, we think that there needs to be an industry solution for residue gas takeaway, and we are actively working solutions with multiple midstream companies to address this. Given the timeframe when we think that will be needed, we believe that there is enough time, in order to get that in place, when the growth is met.

Great. Thanks again, guys.

David Heikkinen and with Heikkinen Energy Advisors.

One thing that we've been thinking about, is the industry ride ramp in the Permian and just thinking about Devon's advantages around securing oil, gas, NGL and water takeaway capacity with the EnLink relationship. Can you talk some about that over the long term with the 30% ramp in production in 2018 and beyond?

I think it absolutely is an advantage and when we are in growth plays we have a very close relationship with EnLink. They are our midstream provider in the STACK play and it gives us great comfort that they are -- that they have that -- we have that relationship so we can have teams working essentially on a daily basis on looking at what the long-term needs are and making sure that they have the right gathering processing and takeaway capacity at the right time, to ensure that we can execute our capital plan and get our wells hooked up on a timely basis and get that value.

Certainly, when you are in a growth mode in a basin, I think a tight relationship with your midstream provider is very important and we have that with EnLink.

Secondary thought and question, with your well level return focus, how do you think about the shift in Devon's corporate returns as you become more light oil, the return on capital employed, or what metrics should be included and have you done any thoughts of what level economics translating to corporate economics?

Well, we tend to talk about the incremental well level economics in these calls. I can tell you, that we actively look, also, at what we consider full-cycle returns on each of our key project areas. Just trying to look at return on capital employed, when you have all these write offs, if you are just looking at that, it's kind of hard to get good calculation off the financials.

But, we look at it just from a pure rate of return, all-cash spent, all-cash we are getting back, at each of our key plays, to make sure that were not only delivering on good incremental well level economics, but from a total investment level, that we are generating good returns on each area that we work.

This is Scott, real quick, to further address the question, you absolutely start seeing these high rate of return wells in the future years impact our ROCHE calculations in a very positive manner, and also another proxy for that would be on a cash flow per data adjusted share adjusted basis. It's certainly something that we view will be a very differentiated metric for Devon going forward.

What do you think the full cycle returns are in your STACK and Delaware?

It's hard to give you that number right now. The play is still changing so much and how much incremental resource are we going to have over our original assumptions? Because, the economics of each individual well is improving and we have a lot more wells than our original acquisition assumption. So, it's certainly improving. But, to give an absolute number, at this point, it would be very difficult.

Dave, I would just add a little bit of a description of what we do on the operating side of the business. On a quarterly basis, we get the senior leaders from across the Company together on a by-business-unit basis and we do a look back at the work that we just finished for the quarter and how that infers the forward look.

We also have, I think, a very detailed look back project from a project basis. Also, from an annual-investment basis.

So, I think we do a really good job of ensuring that we have an accountable approach to the work that we do. It's all based on historical results shaped with a forward continuous improvement look. So, it's a pretty detailed process here on the operating teams.

Thanks, guys.

Matt Portillo with TH.

Just going back to the Woodford, I wanted to see if we could get some color or context around your development plans on the Jacobs Row. Quite interesting that you plan to utilize 10,000-foot laterals. Just trying to get a better sense of the size and scale from a section or well-count perspective that you might have on the development. It seems like it could be a pretty material growth plan going up to 2018.

Matt, I think we're getting information in on the Hobson Row the that will help us understand and infer the magnitude of a performance improvement by going from the normal laterals to the 10,000-foot laterals.

We're going to utilize that to our advantage, where we can, as we go into the Jacob's Row. I think, over 800 wells, now, have been drilled and completed and are producing. Each of the new vintage completions that we see, we tend to outperform the past or previous type curves. Costs are continuing to come down.

Another step change here in addition to the Ricky Ridge and the increased oil content of our fluid going forward, is really just incorporating that 10,000-foot concept into the work.

So, I think the returns on the Woodford play are beginning to shape up as being dramatically better than they had been in the past and it really has been in the core portion of our field.

Don't hold me to an exact number but there are roughly 60 wells in the Jacobs development.

Great. Just a follow-up question. We talked a lot today about the Delaware and the STACK as kind of the core oil developments. Just curious, your thoughts on the Eagle Ford as you potentially return to activity in the play?

Any opportunity to continue to optimize completion design as the basin has been in a frozen moment here for the last year or so?

Are you changing any of your views on the spacing? I know that you have a new spacing design that you may be testing here with the diamond formation.

Yes. Matt, I tell you, we are real pleased with where we are in the Eagle Ford. If you go back and look at the pace of our activity, it's greatly slowed down in 2016 versus 2014 and early 2015. In fact, we're bringing on 70 to 75 wells per quarter, in that timeframe.

In Q1 of this year we were down to 22 wells brought on in the quarter. Second quarter is only five and third quarter is only five and we've seen the rate drop off but it has now stabilized; and we have four frac crews in the fields that are lowering our DUC inventory down. That's being done for a couple of purposes.

The primary purpose is to get information on the staggered lateral approach to the development, which is incorporating the upper Eagle Ford. That information, we are looking forward to having in 2017, which will shape what I think will be an accelerated pace of activity in the second half of 2017, which will have the potential for material rate impact going into 2018. So, we are looking forward.

We are continuing to improve our completion designs. Historically, we have pumped pretty much roughly a 2,000 pound per lateral foot type of job and we've moved that to a more of a hybrid type fluid, and we're increasing the proppant load up too close to 3,000 pounds per lateral foot, at this point. So, a substantial change to the completions.

The wells are just now starting to flow back on a few of those new completions and we are not ready to talk about that. But, we're highly encouraged that some of the well rates that you've seen us as report in the past, we are going to materially beat as we go forward.

So, that play is setting itself up for, what I think, will be an accelerated ramp-up in the second half of 2017.

Great. Thank you very much.

David Tameron with Wells Fargo.

Everything has been asked. I'm good. Thanks.

Operator, we are ready for the next question.

David Tameron.

Operator, you can move onto the next.

James Sullivan with Alembic Global Advisors.

A lot of stuff asked and answered. I just wanted to quickly ask you guys to touch on if you could, you mentioned in passing, the Powder River, I know you are adding a rig back there. An area that you guys have you spoken positively about on, a number of times, in that acquisition over there, you are adding the rigs. So obviously you still feel good about it.

What gets that area a good percentage of limited capital pie? Is it just that you need a longer runway on infrastructure and permitting? I know you are working on both those things. What is it and what is the state of play right now?

James, thanks for bringing that up. We've been real pleased about the work that we've done in the Powder River basin in the past, and we've been operating in that area for quite some time.

If you recall back before commodity prices dropped, we were drilling at probably the highest return wells in the portfolio were, especially the [partment] in the Powder River basin. We did take a pause in our activity as commodity prices ramped down and our focus has gone back to STACK and in Delaware, and we continue to work the sub surface portion of that. We have an extensive 3D coverage across the entire basin.

We have what I think will be unparalleled knowledge about the sub-surface there after the acquisition, we doubled our position there and it's all Tier 1 opportunity connected. We've got about three rig lines ready to go, and it's a matter of managing the portfolio and staying within our cash flow. So, we think it's a great asset.

You've seen some transactions happen in the Powder which further confirmed what we think the ultimate value in the Powder position will be. While it won't ever have the scale and materiality that we'll see in the STACK or Delaware, it's got outstanding returns and we are looking forward to showing you additional subsurface results.

Okay. Great. Thanks, guys.

Bob Brackett with Bernstein.

Good Afternoon. A question on the track development plan in the Delaware. Can you talk about the trajectory of wells per pad? Last year, this year, going into next year and what that steady-state number looks like?

Bob, historically, and I don't know, it is more than just Devon, but industry has really been prosecuting two and three well pads across the Delaware Basin.

The areas where we have a larger contiguous position, we are going to employ this new design concept. So, they are up to about 14 known productive intervals in that Delaware Basin column, Bob.

When you look at the number of unrisked locations that we've highlighted, or 20,000, there's got to be a more compelling development plan going forward, to accelerate present value. So, that's the concept that we're looking forward to.

The way we're designing the track process, is highly flexible between what we need to get done in the Delaware, which has some additional challenges with the Federal permitting, but the concept of track will be applied in both the Delaware and the STACK on both those stack developments.

It's hard to tell you exactly how many wells per pad but I could see is putting up to maybe 30 wells in a given section. We'll utilize very efficient drilling pads coupled with more of a centralized tank battery. So, we'll see quite a few advantages.

We try to highlight the advantages in our operating reports, so you can take a look at that.

Will you do a pilot track sometime in the next years? Or, how do you get from where you are today to rolling out track?

We are going to push forward in 2017, employing this concept. We think it will be -- you can call it a pilot or really just a go-forward development plan, but we think there's a lot of flexibility in this so we're going to be pushing forward to a more creative solution for our developments, moving forward.

The last follow up, if I look at your 7.5-ish rigs for 4Q, you call for about $400 million in CapEx for the quarter. If I just scale that and say you will run double those rigs next year and there's four quarters next year, I get closer to kind of a $3 billion, $3.2 billion CapEx spend; but you are talking about $2 billion. How should I think about that?

Yes. Included in the $400 million will be, also, a larger component of -- well it will include the OBO component. Plus, we have other leasehold expenditures, things like that, that are not actually Devon-operated drilling-rig components.

Really, when you talk about going to the -- and I've been talking about it on the streets for quite some time that we are going to be at a run rate of about $1.6 billion with the 10 operated rigs. Going from the 10, to 15, to 20, you are not increasing all these other components that are in our capital program. You are just increasing the operated rig component and if you do the math on that, on average, another 7.5, over half a year, more like four rigs and you take four rigs and average working interest you get somewhere around that incremental $400 million to get to around $2 billion.

Got you. Thanks for that math.

There are no further questions at this time and I will turn the call back over to Mr. Coody.

Thank you, and we appreciate everyone's interest in Devon today, and if you have additional questions, feel free to reach out to the IR team at any time, myself or Chris Carr. Once again, thank you for everything.

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