德文能源 (DVN) 2017 Q3 法說會逐字稿

Good morning, and welcome to Devon Energy's Third Quarter Earnings Conference Call. (Operator Instructions) This call is being recorded.

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

Thank you, and good morning. 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, forward-looking guidance and detailed operations report. With today's call, we're going to slightly modify the format of our prepared remarks. As always, I will cover a few preliminary items. Then our President and CEO, Dave Hager, will provide his thoughts on the strategic direction of Devon. Following Dave, Tony Vaughn, our Chief Operating Officer, is going to cover the key operational highlights for the quarter. And then we'll wrap up our prepared remarks with a brief review by Jeff Ritenour, our Chief Financial Officer. Overall, this commentary should last around 15 minutes, and then we'll open the call to Q&A.

Before moving on, I'd like to remind you that comments and answers to questions on the call today will contain plans, forecasts, expectations and estimates that are forward-looking statements under U.S. 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 related to these statements, please see our Form 10-K.

And with that, I'll turn the call over to our President and CEO, Dave Hager.

Thank you, and good morning, everyone. As Scott mentioned, we're making some minor modifications to the format of the call today to provide Tony and Jeff the opportunity to convey key messages and technical insight about their respective areas of business. My comments today will focus on the strategic direction of Devon over the next several years, which we have recently branded as our 2020 Vision. The intent of this strategic plan is to accelerate value creation from our advantaged asset base by continuing to deliver industry-leading drill-bit results while improving our financial strengths. With the 2020 Vision, our top objective is to deliver attractive, peer-leading returns on invested capital for our shareholders. While the disciplined pursuit of returns is not new at Devon, our 2020 Vision will refine -- further refine our focus on maximizing full cycle returns at the corporate level. In fact, at our November Board meeting, we will discuss incorporating return-oriented measures into our compensation metrics for the upcoming 2018 budgeting cycle. Our refinement and capital allocation will result in more measured and consistent investment through all cycles, positioning us to more efficiently expand our business over time while optimizing returns.

This balanced operating model is in contrast to the industry's historical behavior of aggressively chasing top line growth at the ultimate expense of shareholders. This is not a populist philosophy that we are paying lip service to. We are absolutely committed to doing business differently in the E&P space, and we are taking the appropriate steps to become an industry leader with our disciplined approach to capital allocation.

In short, we can lead and we will lead. While having the right capital allocation is critical to achieving our 2020 Vision, it is equally important to possess the right asset portfolio and get the most out of these assets with superior execution. And at Devon, we are truly advantaged with our world-class acreage positions in the STACK and Delaware Basin. The quality and size of these 2 franchise assets are unmatched in the industry, with exposure to more than 30,000 potential drilling locations, concentrated in the economic core of these plays. Not only are the STACK and Delaware Basin assets 2 of the very best positioned plays on a North American cost curve, but Devon's large, contiguous STACK pay acreage position in these basins provide us a multi-decade growth opportunity. And with this long runway of highly economic opportunities, we are executing at a very high level. Over the past few years, Devon has the top well productivity of any U.S. operator, which is quite an accomplishment in this competitive space. And importantly, with these prolific wells, we are significantly enhancing returns by embracing leading technologies to improve drilling times, optimize completion designs and to increase our base production.

As we continue to advance our development programs and build additional operating scale in the STACK and Delaware Basin, the next phase of our 2020 Vision is to further high-grade our resource-rich portfolio. Given the massive opportunity we have in the STACK and Delaware plays, we see the potential to monetize several billion dollars of less competitive assets within our portfolio in a very thoughtful and measured fashion over the next few years. Potential proceeds from these portfolio rationalization efforts would be balanced between further debt reduction, reinvestment in the core business and returning cash to our shareholders. We expect to emerge with a highly focused asset portfolio and enhanced profitability as we transition to a much higher-margin barrel.

With our 2020 Vision, we also plan to have a fortress balance sheet, with a net debt-to-EBITDA target of 1.0 to 1.5x by the end of the decade. Overall, these winning characteristics will allow Devon to deliver consistent, competitive and measured growth rates, along with top-tier returns on capital employed.

And lastly, I will finish my remarks with a few preliminary thoughts on our outlook for 2018. First and foremost, our capital program in the upcoming year is being designed to optimize returns, not production growth. And while we do expect robust growth from our STACK and Delaware assets, this high return in production growth will simply be an output of our outstanding asset base and strong execution. While we are still working through the details of our budget, we are directionally planning on an upstream budget somewhere in the range of $2 billion to $2.5 billion in 2018. To be absolutely clear, we expect to deliver this capital spend within operating cash flow at $50 WTI and $3 Henry Hub. With current strip pricing above this base planning scenario, we have no plans to modify our capital range, and we would expect to generate free cash flow.

And I cannot emphasize this enough. This disciplined plan will represent a major inflection point for Devon due to a step-change in improved capital efficiency as we shift to full-field development in the STACK and Delaware Basin and we leverage technology to lower our cost structure. With this highly efficient capital program, we expect to bring online more than 25% more development wells in 2018 as compared to the 2017 program. This means both more wells online and a focus on our highest-return plays. This high returning capital program is expected to increase oil production in the STACK and Delaware Basin by more than 30% in 2018. We will provide more detailed production guidance on other components of our product mix in the coming months once we have better insight into planned activity levels for our nonoperated Eagle Ford asset.

And with that, I will turn the call over to Tony Vaughn for additional commentary on our operations.

Thanks, Dave, and good morning, everyone. My remarks for today will be focused on a few key operating themes that are integral to the success of Devon's 2020 Vision. First, the prolific wells we are bringing online lead the industry in well productivity and reflect the quality of our underlying asset base, our staff's operating capabilities and our willingness to deploy cutting-edge technologies across our asset base.

In the third quarter, the well productivity from our U.S. resource plays was nothing short of outstanding. We commenced production on 50 new wells that achieved 30-day rates of greater than 2,100 BOEs per day. Importantly, we delivered these high-return wells with a capital investment that was below the low end of our guidance range for the third consecutive quarter.

The second key message I want to leave you with today is our capital efficiency will dramatically improve as we transition to full-field development as we further leverage technology to maximize performance. With the size and the scale of our STACK and Delaware positions, a top priority is to efficiently convert the resource associated with these world-class assets into production and cash flow. To maximize the value of these STACK pay reservoirs, our capital activity is shifting towards low-risk, multi-zone developments to increase capital efficiencies and recoveries on a per-section basis. Early results from this thoughtful, leading-edge development concept are quite positive. At the Anaconda project in the Delaware Basin, which is Devon's first multi-zone development, drilling times improved 55% compared to historical results in this area. We also attained significant efficiencies due to less move times, more repetitive operations, improved productivity from zipper fracs, and we achieved supply chain savings by debundling our completion work.

Overall, these improvements resulted in capital savings of approximately $1 million per well compared to traditional pad developments. Also of note, we were able to compress the spud to first production cycle time at Anaconda to only 5.8 months. We will continue to leverage this advantaged development scheme with the majority of our capital activity going forward. In fact, we will have several multi-zone projects under development across STACK and Delaware by year-end, and I fully expect to report more positive results on this topic next quarter.

And finally, I am excited about our supply chain efforts underway that will help ensure the certainty of execution with our future multi-zone projects. As we have discussed at length today, Devon is uniquely positioned to maintain and build operating momentum for the foreseeable future with our STACK and Delaware Basin assets. To properly execute on this massive opportunity, we have integrated teams across Devon proactively securing equipment, crews, materials and takeaway capacity at competitive prices and flexible terms to ensure the resources and capabilities to execute on our capital plans. A recent example of this integrated planning effort was our ability to lock in essentially all sand requirements for our capital programs through 2018 at rates significantly below market. This accomplishment was achieved in a tight market, and the advantaged rates were secured by sourcing all finer mesh sand requirements from regional sand mines in the southern U.S. Due to substantially lower transportation cost, we expect total delivered cost from our regional sourced sand to be around 30% less than the equivalent grades of northern white sand without any degradation in performance. To provide additional flexibility with our operations, we have also secured appropriate amounts of local transload capacity in both STACK and Delaware to further improved final-mile logistics. These are just a few of the many initiatives underway across Devon that will help enhance returns on a capital investment and the certainty of our ability to execute on these development projects.

So to summarize, we are building a very progressive culture that emphasizes data-driven decision-making and innovation across multi-discipline teams. This effort is consistently delivering best-in-class drill-bit results, improvements in capital efficiency as we shift to multi-zone developments, and we have planning efforts underway to ensure certainty of execution with our future activity.

And now I will turn the call over to Jeff for a financial overview.

Thanks, Tony. I'd like to spend a few minutes today discussing Devon's financial strategy within the context of our 2020 Vision and build upon the points made by Dave in his opening comments. A great place to start is with a review of our current financial position. Our upstream business currently has $6.9 billion of outstanding debt with no significant maturities prior to 2021. Devon also has excellent liquidity with $2.8 billion of cash on hand and an undrawn credit facility of $3 billion. In the coming months, we expect our financial strength to be further enhanced with the completion of our ongoing divestiture program.

This solid financial position provides us significant optionality as we move forward in pursuit of Devon's 2020 Vision. Our top near-term objective is to fund our operational plans in the STACK and Delaware Basin as these early-stage assets transition to full-field development. Growth in these assets will drive additional operating and capital cost efficiencies, along with higher overall margins for the company. This disciplined capital program will be funded directionally with an operating cash flow. In conjunction with funding our capital programs, we are also intent on reducing outstanding debt. As Dave mentioned earlier, a critical component of Devon's 2020 Vision is the commitment to further improve our investment-grade financial strength. By the end of the decade, we expect to improve Devon's leverage metrics from 1.0 to 1.5x net debt-to-EBITDA as compared to our current level of just below 2x. To be clear, we expect to achieve this goal with the reduction of absolute debt. We are not planning on higher commodity prices to deleverage our business.

Given our strong liquidity, the first step in our debt reduction plan will be to utilize a portion of cash on hand to tender for outstanding debt. We will finalize size and timing of our tender after we complete our 2018 capital budgeting process, but we expect to further reduce debt by at least $1 billion over the next year.

Looking beyond 2018, the second phase of our debt reduction plan is tied to the progression of our STACK and Delaware development programs. As these world-class assets build scale and become self-sufficient, we expect to take additional steps to high-grade our resource-rich portfolio with the monetization of less competitive assets. Use of proceeds will include additional debt reduction, reinvestment in the core business and the return of cash to our shareholders.

So in summary, achievement of Devon's 2020 Vision positions the company with a top-tier balance sheet in the E&P space, facilitating consistent investment in our assets and optimal returns through all cycles.

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

Thanks, Jeff. We will now open the call for Q&A. (Operator Instructions). With that, operator, we'll take our first question.

(Operator Instructions) First question comes from Evan Calio from Morgan Stanley.

My first question, Dave, I know in your opening comments you talked about prioritizing, improving the balance sheet near term to ensure execution under a range of commodity prices and have an active asset program. How do you think about the potential return for cash to shareholders longer term on the back end of your Vision 2020 strategy? And I'm presuming that your capital efficiency will be higher in '18 with all bases in development mode, and you'll have proceeds of several years' worth of noncore asset sales on the books. Can you give us kind of color on that, the distribution strategy in that maybe longer- or medium-term period?

Yes. That's absolutely something we are considering in the medium and longer term. Our short-term priority is to continue to build scale in the STACK and the Delaware Basin, and we have really optimized our capital program in 2018 to deliver what we consider the sweet spot of capital spend to deliver the highest return. As we focus our activities, one, on development activities with increased efficiencies with having higher -- significantly higher number of spuds and completions. As I said in the opening remarks, 25% or more than we had in 2017, as well as focusing those in the highest-return areas in our portfolio. As we build that scale, as we execute on the 2020 Vision with further several billion dollars of divestments, we do see that we will be paying down some debt to build this fortress balance sheet, to allow us to certainly withstand any sort of weaker commodity price environment in any reasonable price range. Beyond that, we do see in the medium to longer term that we will be in a free cash flow generation, plus potentially have proceeds from the asset divestitures as those take place, and we will be looking at returning value to the shareholders in one way or the other.

Great. I appreciate that. And second, I know you've introduced a preliminary CapEx guidance range of $2 billion, $2.5 billion. It's lower than expectations. Assume to be -- it looked -- appeared to assume a 4Q run rate or annualized run rate. On the other half of the picture, I believe you mentioned 25% more wells on a similar drilling dollar assumption. I mean, can you give us kind of a baseline of what that's assuming in 2017? I know there was some...

Yes, that's going to be somewhere around 240 or so approximately, wells drilled and completed in 2017. And put simply Evan, it would be inaccurate to take our Q4 capital run rate and extrapolate that forward to all of 2018. We have a handful of rigs that are working in Q4, one in the Rockies, one in the Barnett and a few others test, a few of one-off exploration ideas that will not be active in 2018. And so we will have a higher capital spend rate in Q4 2017 than we do -- than we'll average for each quarter in 2018. And then our efficiency is really just what Tony went through in many ways that we're getting into development drilling. We are realizing efficiencies from that, and we are concentrating more of our total E&P capital spend on development drilling. So we're getting more efficient. We're putting more dollars into development drilling, and we're drilling the best-return wells. So if you put all 3 of those factors together, that's why we feel really good about the program not just in 2018, but well beyond 2018. We're getting in development mode, quite simply, and that's going to continue for a long time.

That's great. Maybe just a follow-up to that, to your comments. What percentage of that -- of the '18 wells will be drilled in multiwell pads versus 2017? I think I missed that.

Evan, it's going to be -- about 2/3 of our program in '18 will be on these multi-zone projects. And I think a good readout on what David's talking about is really to go back and dissect the results that we had on really, our serial number one, which was our Anaconda project in the Delaware Basin. And there, we were able to reduce costs some 20% on a per-well basis, just through the efficiency gains from this multi-zone concept.

Your next question comes from the line of Bob Morris from Citi.

You mentioned focusing on the STACK and the Delaware, but perhaps the best returns on unlimited program today would have been in the Powder River Basin in the Rockies. How does that fit into your program next year? And do you have the scale there or the runway to be able to accelerate that or do more there? Or how do you think about that looking at your portfolio?

Well, you're right, Bob. We've drilled some really nice wells. It's still early on in the Powder River Basin, but that certainly provides additional strength and optionality to the overall portfolio. I'll let Tony detail out the potential 2018 plans, but we're proud of what we've done so far, and we have a lot of acreages that we have yet to evaluate there. It looks like we'll be focused primarily in the shorter term on the Turner, as we described in the operations report. But Tony, you want to detail it out a little further?

Just to add on to what Dave said, Bob, we're doing some really outstanding work. You're seeing the returns on that. We've historically been focused on some of the shallow conventional horizons from the Teapot and Parkman, and those offer some of the best returns we've seen, essentially, 90%, 95% oil stream. Now we are bringing on some of our Turner wells. We think this is a more unconventional-type play in the basin, perhaps a little bit more ubiquitous across our position. We've got a substantial permit there. In fact, we've picked up about 100-plus permits from the Casper BLM office, which is quite unusual in terms of the pace of permits being approved. So we've got the capacity to stand up additional rigs and repeat high-quality results. It's going to be a matter of going through the budgeting process this year and allocating capital to the best opportunities we have.

And how do you think about your footprint there? Is it somewhere -- do you think you could expand your footprint if all these tests work in the different formations? Or is there enough running room there to really make this a core part of your portfolio?

Bob, we've got 400-plus thousand acres in the Powder, so we think we've got the position that we want. If you just really map out what we would classify as Tier 1, it's something less than the 400,000 acres. But we've got a substantial portion of that locked up in between our position, our legacy position that we had on the north end of our play in Campbell County to the south end of our newly acquired position in Converse County. There's some good work going on by EOG. And then to the South of us there's some other good work going on by Chesapeake and a few others. So we're really in the heart of the play and have the position that we like there.

Your next question comes from the line of Ryan Todd from Deutsche Bank.

Maybe if I could ask one on each of your key core plays. In the Permian, it was a, I guess, started out -- what's the early impression? You mentioned that you drilled a 3-mile lateral. Any comments on what you saw there, the 3-mile lateral potential for that to become a larger part of the program going forward, within the multi-zone development plans?

You bet, Ryan. We are flowing that well backward. We don't have the 30 days behind us to report on that. You'll hear from us on our next quarter, but we're quite pleased with the results that we have to date. So really, on an opportunity going-forward basis, we've got a 3-mile lateral in the Delaware. We've also -- are in the process of preparing to flow back a 3 mile in the STACK play as well. I don't know that this will displace all the 2-mile laterals that we're working on and established. There's going to be some unique footprint opportunities that will allow us to go to 3 miles. And I think these first 2 wells are proving and giving us confidence that from an operational perspective, we can drill and flow back -- we can drill, complete and flow back a high-quality well at 3 miles.

That's great. And any ideas on extending the 3-mile lateral in the STACK as well? Or are you keeping it in the Permian for now?

No, we've got a -- we are flowing back -- preparing to flow back our first 3-mile lateral in the STACK play right now. It's early, so I can't report on that. But mechanically, the drilling operation went extremely well, very cost efficient to do this. We treated all the way to the toe of the well and are preparing to flow that well back. So there's going to be some opportunities to fill in on our footprint, the 3-mile concept, but a lot of our position is going to be relegated to the 2-mile laterals.

Okay. And then, maybe another follow-up on the STACK. A couple -- and the Fleenor pilot was clearly the strong results, can you maybe talk a little bit more about what you learned on spacing there, in the upper Meramec? And then you also stepped out with the Sidewinder and then Ollie wells, you're moving a little further, kind of pushing the boundaries up further to the north and even to the east. Can you talk about maybe what you've seen in terms of the extent of the core of the play, as you've tested the boundaries a little bit?

Ryan, I think we're -- Ryan, we're pleased with the work that we're doing. I think you saw the report out on the Fleenor work there, and we're quite pleased with that. I think what we were trying to highlight there is, while we got exceptional flow back results on the Fleenor wells, we did this with a different cost structure than what we had historically done. It wasn't just simply the cost going from a 3 string to the C string, we didn't think about that, but it was really associated with a modified completion design. So we're pleased with the work that we're doing on the east side of the play. I think if you look at our '18 work, we're going to start moving that to the north and west portion of the play. We're going to -- in fact, we've already spud our second multi-zone project that we call the Coyote on the northwest side of the play. And we've piloted some wells around there that we're quite pleased with and probably we'll be reporting on that sometime soon, as well.

And Ryan, just to add a few more details there to Tony's comments, that was -- the Fleenor pilot was a staggered test within the Meramec 200. So in that area, that's the thickest zone. And so ultimately, we're just trying to maximize recoveries in that very prosperous area. So it's once again very successful and we'll deploy those learnings to just the next multi-zone projects that we have. So it's just once again, you're constantly retooling what you do, and that's just going to be an input for, as we head towards Showboat and other projects, so.

Your next question comes from the line of Doug Leggate from Bank of America.

So Dave, obviously, this is a little bit of a change from the cash inflow versus operating cash flow. I guess that's the subtlety of your Vision 2020. So I guess, my question is, as you focus on the 2 core areas, given I guess, the increase in inventory, what does it say about the asset sales definition in terms of what becomes noncore? And I'm specifically thinking about Tony's comment around the Powder. Because obviously, while the returns are great, the scale is not relative to the other areas. So does that become a for-sale asset? And just maybe some color on your thinking around scale and timing of executing that program.

Yes. Well first off, you're right, we have made a subtle change where we say we're going to live within our cash flow from operations. And the reason for that is simply the strength that we're seeing, both in terms of the capital efficiency that we're able to achieve, as well as the returns we're able to achieve when we're focusing even more dollars on the development side and in our highest-return areas. So it's really a very good news story that we are -- been able to spend lower capital dollars, live within operating cash flow and deliver the kind of returns that we are, which again, we're focused more on returns than on production growth, but we will see strong production growth as a result. Now more specifically to the Powder River Basin, it's still early days in the Powder River Basin. We like the optionality that the Powder River Basin provides. We see that on a go-forward basis, as Tony said, we'll be focusing more of our activity on the Turner. And we really need to see more results from the Turner to really understand, with some certainty how does it compete for capital versus the STACK and the Delaware plays. So we have a lot of optionality around, and we have said, we'll be divesting several billion dollars of additional assets. But it's because of the incredible strength of our portfolio that we have a lot of optionality of where that may come from. We certainly are going to have areas throughout our portfolio that somewhat could come in and drill development wells that will achieve returns well above the cost of capital, but not as good as we're going to get in our core plays. So that gives us a lot of optionality around where we decide to do those divestments for -- from, and we haven't made a final decision on that. It may be one area or maybe a combination of acreage from a number of areas. But we are absolutely committed, though, to the vision that we have. It's just that the -- how we execute that vision, we're still talking about.

My follow-up, Dave, it may be for you or it may be for Jeff, but it really goes to the net debt EBITDA target and the relationship with EnLink, I guess, is a broader question. In years gone by, you did sell down a little bit of EnLink. That stopped, obviously. But when you look at net debt, obviously, you're consolidating EnLink debt. But on a -- if you're going to be strictly intellectual about it, deconsolidating EnLink would that also add the marketable securities in your definition of corporate net debt, the recourse, the Devon levels? Sorry for the lengthy question, I guess, but what I'm trying to understand is, what does your future relationship with EnLink look like? How does it factor into that net debt target? And do you look at it on a just Devon basis as opposed to the consolidated EnLink business and how we did there?

Hey Doug, this is Jeff. Yes, we think about on a -- in the targets that we've outlined are based on a Devon stand-alone basis. So we are not including the EnLink debt or the EnLink EBITDA in that calculation.

What about the EnLink equity, as marketable securities?

That is not included in the calculation, either. Yes, so we are -- if you're asking if we reduced the debt for the value of the EnLink securities, we are not.

Okay, that's very clear. As far as the relationship with EnLink goes going forward, any additional sell downs planned?

Well, I can add from a strategic level, first off, we like the relationship very much. And we think they're doing an outstanding job and particularly in supporting us in one of our key development areas in the STACK, but also every area where we have common operations. So we like the relationship strategically. Now whether we would ever consider any sell downs or not, that's certainly not on the table at this point. I would never rule it out. That's always an option that we have out there but we certainly have no current plans around that.

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

Dave, focusing on your comments around changes to management incentives. What should we expect on those changes? You mentioned the drilling rate of return as a potential metric. Has there been a consideration for a corporate returns level metric like an ROCE? And then for any growth metrics, will they be measured on a debt adjusted per-share basis?

Yes. And let me start this answer off, and then I'll ask Jeff to fill in on the details. He can give -- again, we have not made a decision on this. We need to discuss this with our Board to make a final decision. But this -- I'll give you our preliminary thoughts that we'll be taking to our Board. The first comment I just want to make is, we fully acknowledge that our industry in general, has not delivered acceptable returns, and that we are absolutely -- and I would include Devon in it, and we are absolutely committed on a go-forward basis to deliver acceptable returns at the corporate level to our shareholders. And that's what this effort is all about, is to make sure that we are delivering on that. We are focusing our capital program in order to be able to accomplish it. We have the asset base, and we have the execution to do it, but we are fully committed to provide, one, the right incentives internally to make sure that we deliver on that; and second, the transparency as best we can to the shareholders so that they can measure our effectiveness of doing this. And as I said in the opening comments, we have the ability to lead in this area, and we intend to lead. And so Jeff, you can maybe talk in a little bit more detail about a couple of the metrics that we're considering at this point. And again, there's no final decision. We'll give you our thought process.

Yes, that's right. As Dave said, it's certainly something that we're still in discussion with our Board about. Paul, we're going to lay out the spectrum of all the usual suspects that you would expect as it relates to these metrics. If I had to put them into 2 buckets, I would say one bucket is probably closer to a GAAP metric, so things like ROTCE or a cash return on capital employed. The benefit there, obviously, is the transparency and the ease of calculation of those metrics directly off the financial statements. And then maybe a second bucket, which is, frankly, what we think is probably closer to the reality of our returns on our capital program each year, which is more of an all-in -- again, a corporate return. So all-in capital, not just drilling capital, but all capital spent by the company in any given year. And then the future cash flows obviously, that's going to be generated from that capital spend. That one, again, as I said is, we think is probably the better metric. However, it's a little bit more difficult to provide the level of transparency, I think, that you and the investor universe would like to see. So we're weighing and balancing each of those different options. We'll discuss that with the Board, as Dave said, later this month and, hopefully, land on a conclusion. I will add, as you mentioned Paul, our analysis and our historical look at all these different metrics continues to suggest that a debt adjusted per share metric is the most highly correlated with equity returns in this space. So I certainly think that whatever we land on will have a flavor of that.

And again, just to be clear, on that second measure that Jeff talked about, which is a rate of return metric, we were thinking in terms of burdening that as much as we can with all other costs that we incur within the corporation. So you're getting that, even though it's based on wells, it is really burdened with all the costs of the corporation. So you're looking at more of a total corporate return on a -- from our capital program.

No, that's great. Sounds like there's a tremendous amount of thought that you guys have put into it. It's great to hear. And I guess, as a follow-up to that, how do you guys consider the role of hedging, as well as exploration within the 2020 Vision and balancing against both an annual corporate return as well as a longer-run ROC or corporate return metric?

Well, I'd say, first, in regard to exploration, we're certainly in a great position where we have such a strong development inventory as we have right now. So there's not the need in the short term for exploration in order to accomplish, certainly the 2020 Vision. Now if you look out longer term for the company, I think that you always have to be mindful that a -- some level of exploration should be thought about in order to have a long-term sustainable company. But certainly, in the next few years, the amount of capital that will be dedicated to exploration is going to be less than you might normally think for a company our size. With regards to hedging, we think that hedging is an important part of the overall company business in order to make sure that we are delivering consistent results. We also think it's important to give us confidence around the cash flow that we're going to have in a given year in order to execute our capital program. We have designed our hedging program for hedging out approximately 1/3 of our volumes in any given year on just what we would call a systematic basis, where we just take the existing prices in the market and hedge forward for a number of quarters on that basis. And then we intend to roughly get to around 50% overall hedged with the other 16%, 17% or whatever, it could vary a little bit from that, but somewhere around that on more an opportunistic basis. And we certainly, with the strength that we've seen in the market recently here, that we are opportunistically hedging as we speak.

And your next question comes from the line of Scott Hanold from RBC Capital Markets.

One follow-up question on the EnLink response you provided. Can you tell us incrementally what the other strategic benefits are there to be joined up with EnLink? Do you have most of the developments, midstream developments done that you need in the STACK? Or is there still a lot of wood to chop out there?

There is still midstream development. It's ongoing as we speak. We're certainly getting into the development program, but there's certainly is a build out of quite a bit of the midstream infrastructure that's still in front of us. And obviously, the hooking up of a very large number of wells on a timely basis is important to delivering our returns.

Okay. Okay. So certainly, through '18 and maybe into '19 strategically, there's a reason to be joined at the hip. Is that fair?

Well I think that's certainly true. Yes, there's a benefit there.

And my follow-up question would be related to, again this thought on looking at being a little bit more balanced and potentially free cash flow positive in the future. And I think you guys made a point this year of really ramping up activity, especially in the STACK, in Delaware for efficiency purposes. And so those -- obviously, those areas are at cash flow deficits. I would imagine that at the field level. Can you just generally discuss, when you look at the future monetization strategy, would you look to really do that once those assets can support themselves? Because I think right now, some of your other mature assets that don't get capital are actually free cash flow generators for those areas.

Yes, Scott. This is Jeff. That's exactly right. I mean, I think the way we're thinking about it internally is, we'd like to see those STACK and Delaware assets get to a more mature level. They're relatively immature today in our portfolio, just by the nature of the assets. But as Tony described with the multi-zone development that we're going to head into in a much bigger way here in 2018, the capital efficiency and the cost efficiency that we're going to see in those assets, we expect them to reach that kind of self-sufficiency point in the not-too-distant future. And that will give us the confidence to then embark upon a broader divestiture program that Dave described in his opening comments.

Okay. So that self-sufficiency point is probably in line with what you talked about in the 2020 Vision of monetization? Is that right?

Yes, that's right. I mean, we certainly would expect to reach that point, again, assuming a commodity price environment of, kind of the 50 and 3 environment within our 2020 timeframe.

Your next question comes from the line of Arun Jayaram from JPMorgan.

Just perhaps a follow-up on that question. Are there assets today outside of the Delaware and STACK that you consider as core? Or perhaps you could describe the attributes of the assets that you think will remain in the portfolio on a longer-term basis.

Well, the key attribute that we would look at is, do they compete for capital in our portfolio? And is there additional value that we can create by -- if there are development opportunities that may not compete in our portfolio, but that we could be paid for some of that upside from that development opportunity by someone else. And so we'll be looking at areas that -- and certainly all of our areas, we feel, whether you're talking about the Eagle Ford, you're talking about the Barnett, the Powder, they have some element and there may even be areas within the STACK and Delaware on a much smaller-scale basis that we may not get to. They're not absolutely core to us, but that we could look at divestment. Now these are not going to be large-scale numbers, but there are probably some areas within those spaces as well that aren't going to necessarily meet our return requirement. This causes a very high-return capability of so many of our development opportunities. So that's the key thing that we'd be looking at is, we think the bulk of the value creation that we do in the company is when we can deploy capital at returns very far above the cost of capital. And that's what we'll do in our key development areas. And if we aren't doing that, and we aren't going to fund it, perhaps someone else will see an opportunity there and pay us for part of that opportunity.

That's great. And my follow-up, I just wanted to check or had perhaps a housekeeping question on Jackfish. Just given the improvement in oil prices, do you expect any of those projects to reach a threshold where the royalties would increase in 2018? And also wanted to see if there's any turnaround scheduled at any of the 3 Jackfish projects in 2018.

Arun, this is Tony. We do have -- we're working a turnaround, one per year. So you saw us go through J3 and then previous to that, J2. Did a little bit of maintenance on J2 this year, so we'll be back to a turnaround on J1 in the summer of '18. We don't expect a royalty change in 2018.

No changes at all in any of the 3 projects in '18?

No.

And Arun, just real quick, just to provide some color there, as obviously, Jackfish 1 is post payout. That's been post payout for quite some time. Jackfish 2 and Jackfish 3 are pre payout. And based off of current strip pricing, we wouldn't expect those to be -- have any meaningful adjustments in royalty factors on that front until next decade.

The next question comes from the line of David Heikkinen from Heikkinen Energy.

The highlight, kind of in the release around a projected NPV uplift of greater than 40% as you look forward for the STACK and Delaware kind of caught our eye, but can you help us understand, kind of define the starting point for where the NPV is in the STACK now, and then how the 40% or more is there and then same thing for the Delaware starting point. So kind of know where you're going on that uplift, for the multi-zone development.

David, this is Tony. The comment about the 40% uplift in PV10 is really in comparison to a typical historic 4- or 6-well pad. That's the -- that's just the delta that we see in front of us by utilizing this multi-zone concept. As we mentioned before, we already saw 20% of the cost come out of the -- our first project in the Delaware Basin. We really haven't even optimized, in my mind, the opportunity in front of us. And you're starting to see the concept of more batch operations utilizing spudder rigs to get the surface hole drilled followed by the conventional drilling rig to drill the production string. And the utilization of these centralized production facilities that will be equipped to handle production from multi-pads, kind of a drill to fill-type concept, is a substantial boost. So if you just look at the typical flow -- or the typical work process in the Gant chart, this is a way that we're leaning out all components of that. And to give you order of magnitude, when you take a rig in typical Delaware Basin well, you take the rig and move it to another pad a couple of miles away. It's an additional 3.5 days of nonproductive time until you're back moving the bit. And simply skidding over for a multiwell pad, you've got about a half a day of downtime. So this is a -- this is the type of work that we think is something we've been planning and talking about for 2 years. We're just now coming into this space. And again, we think it's a game changer for the type of contiguous multi-zone sweet spot type projects that we have.

I guess, I'm going to try a little harder. So if I think about a 4- or 6-well pad, and if we just think about an NPV per well of kind of $15 million to $20 million and you get 40% more than that on each set of 4 to 6 wells, is that how it ends up flowing? I'm trying to get the hard numbers on this, I guess. Like where the 4- to 6-well pad would have been, just on NPV -- incremental NPV beyond invested capital?

Dave, this is Scott. A lot of numbers floating around there. And I think, in all honesty, that's -- I have a spreadsheet that I'd be very happy to walk through with you at my desk after the call. So just maybe keep it a little bit higher strategic question, it's certainly something I can handle later on.

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

We've got a lot of capital allocation questions, so I thought I'd stick to the couple that are more to do with the field. So I'm looking at the operations report, that's what I'm referring to. Slide 16, it shows a number of interesting multi-zone projects, beginning with Anaconda at the top and going down to Medusa. I was just wondering, because -- particularly because there're a number of different zones and multiple intervals involved in these different projects. Are any of these anything that you would still consider to be a delineation project or a testing zone interference or anything in any way, I wouldn't want to call it exploratory, but something of that nature? Are these all just purely development projects at this point aiming for efficiency?

Yes, Jeffrey, these are all development projects. And we've done a lot of pilot work over the last couple of years. We felt like we have a really good understanding of the lateral spacing requirements for the different zones that we work in. We're continuing to gain more insight into the vertical connectivity. What -- when you go into the Delaware Basin, for instance, you've got about a dozen different known commercially productive horizons there. Through the pilot work, we've established what we believe to be zones that are pressure dependent on each other and some that are independent of each other. So we're utilizing that knowledge to really focus here on what we consider to be the high-return, low-risk development projects in front of us. That doesn't mean to say that we're not going to do a little bit of a spacing work or test a zone in a column that we know to be pressuring communication with the rest of the column that we're going to complete. A little bit of that will happen. But for the most part, in the Delaware Basin for 2018, you'll see about 90-plus percent, maybe 95% of our capital spend will be on development.

Okay. That was a very comprehensive answer. And then returning to the PRB, I just, earlier in the discussion, it was mentioned that you guys have a very large acreage position there. But I'm just curious, I think I understood Dave to say that going forward, this is really going to be a concentration of the Turner. And of course, you have the Super Mario project area laid out. So what I'm wondering is, as a really hone in on the Turner going forward, will it still contain enough resource to support a core play if the well results pan out? And what I'm thinking is that the illustration on Page 17 kind of shows that the Parkman, the Teapot, the Turner, they all seem to be sort of discrete in different portions of the acreage.

You're a little bit right. Now there is some vertical opportunities in the Turner. There's a couple of different zones in the Turner that we look at, and there's a portion of the footprint here that will have traditional multi-zone potential. But not like you see in the Delaware Basin. But I would tell you that in addition to the Teapot, Parkman and Turner that we've talked about, there's a lot of activity that's happening in the deeper horizons. The Niobrara is a source rock here, but there's some really good results happening just south of our footprint in the Niobrara. We've got about 8 producing Niobrara wells on our footprint that we acquired a couple of years ago. And on a per-foot basis, even though the wells -- the laterals were very short laterals, and probably not fracked with the knowledge that we have today, they're encouraging. And so if you look at the Niobrara being ubiquitous across the play and the source rock there, moving that into a commercial development over the next few years would be a step-change for the Powder. So there's some other zones that both Devon and other -- some of our peers are pursuing outside of the Turner and the Parkman.

Jeffrey, just another way to describe it too is, if you look at Page 18, you can see clearly the potential that exists there in the Turner, with about 400-or-so high-quality locations. This is very early on in the spacing test, and whether it's going to play out that way. But that area could be significant. The other thing you have to think about, too, and I'm not saying we would or wouldn't consider this for monetization outside of some core area we defined in the Powder, but you also want to know what you're potentially monetizing, and what you're potentially giving up in the what the right value for that is, too. And so even though -- and when you -- and Tony described some potential, for instance, in the Niobrara that still exists up there. And you'd want to have some idea for what that potential truly is, in order to make sure you're getting the proper value for the shareholders before you would consider that.

Yes, well I mean, I think that's a great point. And if I could just follow up because this is the first time I'm aware that you guys have talked about the Niobrara. When we're -- just to have something to visualize. Are we thinking about some areas that might have had the potential to have a DJ Basin-type of setup, where there's an A and a B and a C? Or is it going to essentially be one extra zone that could be added to the Turner or Sussex or whatever else you might mess around with?

I think it's too early to define that. I know the B and the C have been tested in the basin. But I'd say for our particular area, we're going to do some work in 2018 to start understanding that. And we've got a good technical team that's mapped the southern work that has been ongoing. And there's some new work that's just north of us that is also helping us connect the dots in between that activity. So a little bit early to define what this might look like.

And your next question comes from the line of Jamaal Dardar from TPH and Company.

I know it's been touched on a little bit, but just wanted to talk about the spending at operating cash flow again. And if it's to be implied that the EnLink distributions are going to be used to cover the dividend, and also just wanted to think about the delta between the EnLink distributions, which are quite a bit higher than the dividend and how you are all thinking about that, as that continues to tick up.

Jamaal, this is Jeff again. Yes, no, you're exactly right. We -- as Dave mentioned earlier, subtle difference in how we've described our go-forward game plan, which is to spend within operating cash flow. So that would mean the EnLink distributions would be on top of that. But as you point out, we do have a dividend and the EnLink distributions more than offset that. So we still, between the 2, would have some incremental cash available.

All right. That makes sense. And then just quickly wanted to talk on the Jacobs pad. That was -- wasn't mentioned in this release. And just wanted to think of your updated thoughts in terms of development in 2018 for that pad, especially given some of the ongoing spacing tests by your partner.

Yes. I think we're anxious to see some of the spacing tests just south of our Jacobs/Annalou. I think that's going to be informative for us to continue to design work on our particular project. We've actually engineered the Jacobs project. We continue -- we're thinking about deferring that outside of our 2018 capital program. Most of that thought process is really because the Meramec and the STACK work we're doing right now is so commercial and prolific. And so it's -- the Jacobs and the Woodford are now getting displaced by the Meramec type opportunities from a return perspective. And as we mentioned before, we're setting up these multi-zone developments in the -- in both, in the STACK and Delaware. In fact, we have about 29 known projects identified that will get us through the next couple of years in these 2 basins alone. So we've got it engineered and it is there if it competes. But right now, it's -- we're finding that we've got other opportunities that have higher returns that will displace that.

And that's some pretty important data that our partner in this development is going to be obtaining from their spacing test. It's a pretty dramatic downspacing that they're testing there. And if that works, we'd certainly want to know that before we commence on this Jacobs/Annalou development.

Your next question comes from the line of Biju Perincheril from Susquehanna.

Dave, I have a quick follow-up question on the Fleenor pilot. Is that the 2 wells in the 200 zone testing sort of the optimum landing point? Or in that area, do you have sort of enough thickness to have 2 separate wells within the 200 zone?

Biju, these are -- this is really testing the landing zone, is the primary purpose of the test. And again, this is a staggered approach. We've seen some advantages by staggering, even within the same specific interval. That -- just a subtle difference tends to provide a better performance from the offset wells. So it was really a landing zone, staggered -- with a staggered concept. And then again, we slightly modified our completion design there, which really moved about $200,000 held to completion, and still got the results that we posted here.

Great. And those completion improvements if that is replicated throughout the STACK acreage, that is not -- is any of that built into the 2018 sort of preliminary plans you provided?

It will be. It's a data point that we have here, so we're continuing to work that. It happens to be with some of the product that we used during our completion process. So we got a data point now that was positive, and we'll continue to better understand that. But those are the subtle opportunities that we're seeing across the board. We've got a culture of innovation in the company that, frankly, we haven't seen to date, that are exploring every component of our business, and it's a summation of a lot of subtle changes like this that's really adding up into the -- that present value up list of perhaps 40% on these type of projects.

We're now at the top of the hour, and there's admittedly several still in our queue. So if we did not get to your question today, please don't hesitate to reach out to our Investor Relations team at any time today, which obviously consists of myself and Chris Carr. But we appreciate your interest in Devon, and we'll talk to you next time. Thank you.

And this concludes today's conference call. You may now disconnect.