Welcome to Devon Energy's Third Quarter 2019 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. Last night, we issued our earnings release, operations report and forward-looking guidance. Those documents can be found on our website at devonenergy.com. Joining me today on the call are Dave Hager, our President and CEO, David Harris, our Executive Vice President of Exploration and Production; and Jeff Ritenour, our Chief Financial Officer. Comments on the call today will contain plans, forecasts and estimates that are forward-looking statements under U.S. securities law. These comments are subject to assumptions, risks, uncertainties that could cause actual results to differ from our forward-looking statements. Please take note of the cautionary language and risk factors provided in our SEC filings and earnings materials. With that, I will turn the call over to Dave.

Thanks, Scott, and good morning, everyone. The third quarter is another one of exceptional execution for Devon across all aspects of our business. The bull strategy we announced earlier this year to transform to a high-quality, multi-basin U.S. oil company is working and it's working quite well. By sharpening our focus on our very best U.S. oil assets, the operating teams at Devon are delivering results that are exceeding expectations. Capital efficient and cost -- capital efficiency and cost reduction targets by a wide margin. This trend of excellence is now well established over multiple quarters and evidenced by several noteworthy accomplishments year-to-date. First, our returns-oriented focus and strong operational execution is translating into attractive rates of return. Year-to-date, the fully burdened rate of return on our capital program has exceeded 25%, and the cash return on total capital employed is also strong, trending well above 20%. The attractive returns we have delivered year-to-date are a function of the learnings we attained from appraisal work in prior years. By deploying these learnings to our highly focused development program in 2019, we have made substantial improvements in drilling and completion designs, reduced cycle times and increased well productivity through enhanced subsurface target selection. This step change improvement in execution has allowed us to raise our oil growth outlook 3 times this year while lowering our capital spending guidance. We have also acted with a sense of urgency to materially improve our cost structure. Our multiyear cost savings initiatives are now on pace to achieve more than 80% of our targeted $780 million in annual cost reductions by year-end. Importantly, our operational performance and cost reduction success have allowed us to generate free cash flow at levels that are ahead of plan. Coupled with asset sales, we are now on track to…

Thank you for the introduction, Dave. Together with our talented operating teams here at Devon, I look forward to continuing to execute on the operating strategy that will drive the next financial growth and strong returns for the company. And given our third quarter results and outlook, we continue to hit on all cylinders. For my prepared remarks today, I will cover the asset-specific highlights that are driving this enterprise-level success. Beginning with our [indiscernible] asset in the Delaware, production continued to rapidly increase in the third quarter, growing 59% on a year-over-year basis. This strong production result was driven by a Leonard Shale oriented program in the quarter, which accounted for roughly half of the 34 new wells that commenced production. Based on learnings from prior projects, our operating teams have refined Leonard development spacing at around 6 wells per drilling unit primarily targeting the Leonard B interval. The execution of these Leonard developments was excellent. Results have exceeded type curve expectations with 30-day rates averaging 2,200 BOEs per day, of which 70% was oil. At an average cost of $7.5 million a well, the returns from this Leonard activity rank among the very best projects we have executed this year. Looking ahead, the setup for the Delaware Basin in the fourth quarter is very strong. Our diversified development activity across all 5 of our core areas in the state line area continues to progress right on plan, positioning the Delaware for another quarter of strong oil growth. In the aggregate, we expect to bring online more than 30 wells in the fourth quarter with the top catalyst being our 10-well Cat Scratch Fever 2.0 project. Cat Scratch 2.0 directly offsets the record-setting Phase 1 project immediately to the southeast in our world-class Todd area. While geologic mapping indicates…

Thanks, David. I'll spend my time today discussing the progress we've made advancing our financial strategy and detailing the future benefits of our plan. A good place to start is by highlighting our financial performance in the quarter, where Devon's earnings from continuing operations totaled $0.35 per share, exceeding consensus estimates. Operating cash flow for the quarter was $597 million, a 22% increase compared to the year ago period despite lower benchmark pricing. This level of cash flow exceeded capital spending, resulting in free cash flow of $56 million for the quarter. This strong financial performance was underpinned by oil production that exceeded the top end of our guidance, per unit LOE cost improving by 19% year-over-year, G&A and financing costs that were reduced by more than 25% versus the previous year and capital efficiencies that are trending well ahead of our plan. Turning to the balance sheet. Over the past 3 months, we've made significant progress strengthening our investment-grade financial position. In the quarter, we retired $1.5 billion of senior notes reducing our total debt to $4.3 billion and net financing costs by 25% year-over-year. Strategically, this debt reduction activity focused on near-term maturities to completely clear Devon's debt maturity runway until late 2025. We are carefully evaluating the next steps in our debt reduction program as we keep a close watch on interest rates and credit spreads. Overall, we are well on our way to achieving the $3 billion debt reduction target. With strip prices where they are today, we expect our net debt to EBITDA ratio to trend towards the low end of our 1 to 1.5x targeted range as we execute on our multiyear plan. In the third quarter, we were also very active with our share repurchase program completing $550 million of share repurchases in…

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

[Operator Instructions]. And your first question comes from the line of Arun Jayaram from JPMorgan.

I was wondering if you could discuss your plans in the Delaware Basin for 2020. I think this year, you're going to be placing under production about 117 wells. I wanted to see if you can give some thoughts on the program next year, lateral lengths and number of wells. And where do you see well cost on per lateral foot basis in the Delaware?

I'll start this off, Arun. It's a bit premature for us to provide any specific guidance as far as the amount of wells or even the cadence of the wells for 2020. We'll keep it to the preliminary guide that we provided at a high level in our earnings materials. But that being said, with regards to our allocation at the Delaware, it's certainly going to be our top funded asset by a wide margin. Proportionately, you would probably directionally expect that level of funding to be similar to what you're seeing this year. And obviously, the PRB and the Eagle Ford would be top funded assets as well within our portfolio. And as always, with the extended reach laterals, we continue to push towards having longer laterals every year. And if you saw our recent operations report, we're pushing towards 10,000 in virtually every area that we operate. So that's a good news story where the capital efficiency continues to improve.

Arun, this is Dave. I may just make one more comment on just the capital efficiency or the cost reduction side. If you go to, obviously, Slide 16 in the operations reported, it really shows how we're continuing to get drilling and completion efficiencies. So we think they are leading the industry in cost per foot -- drilling completion cost per foot, but we're not done. And I can tell you, the way we've guided and built into our 2020 guidance, we are still seeing that we think there's opportunity to do even better, and we're working on some things and having early results that back that up.

Great. And just my follow-up. On Slide 5, you guys present your updated guidance on the cost structure. Maybe for you, Jeff. I was wondering if you could give us a sense of how you expect the cost structure to trend for the new Devon in 2020. And maybe also provide some thoughts on how do you think realizations or differentials will trend for the three main product groups for the new Devon.

Yes. Arun, you bet. Yes, I would say, generally speaking, we continue to expect per unit cost to trend lower as we move into 2020 really across the board from an LOE and a G&A standpoint. Obviously, the financing cost piece is going to be dependent on the timing of our debt repurchase. But again, that's another area where we would see a continued reduction in our cost structure as we move into 2020. As it relates to the realizations, I would -- as a general statement, I would say, I would expect it to look a little bit like this year. There's obviously -- it looks like there's going to be continued pressure on WAHA pricing coming out of the Delaware. But with the hedges that we have in place as well as some of the takeaway options we have there, we think we're going to mitigate that to some degree. Oil pricing coming out of the Delaware, we feel really good about. There's obviously plenty of pipeline capacity there to move the product. And we generally have a pretty balanced approach there, getting about -- 50% of our production is exposed to Gulf Coast pricing and the remainder would get exposed to that Midland area pricing, which right now looks pretty positive. It's actually trading at a premium relative to WTI.

Your next question comes from the line of Jeanine Wai from Barclays.

So my question is on 2020 capital efficiency in the corporate breakeven. You've reported a pretty low 2020 corporate breakeven of $48 WTI. And I believe the original 2019 breakeven was around $46 WTI, but that was at higher gas and NGL prices. So I'm just trying to get a sense of the year-over-year change in capital efficiency on an apples-to-apples basis. So if you were to normalize for pricing, what's the change in the corporate breakeven in 2020 relative to this year?

Well, I don't know if I have an absolute number normalized for pricing. I think the easiest way to think about it is look at Slide 9 in the deck where we're saying we're delivering all of the oil growth that we had originally planned over the 2-year time frame. But yet, we're doing it for $400 million less capital versus our original plan. And so obviously, on a normalized basis, if we went back to the original pricing, it would be below $46. I don't know if we have an exact number of what that may be.

Yes. Jeanine, this is Jeff. I actually don't have the absolute number, but Dave described it well. And obviously, the biggest driver of that is the capital efficiency that we're seeing in the Delaware and really across the board in each of our different areas. But the Delaware, obviously, is the biggest component of our capital spend, and that's the biggest driver of that capital efficiency that we're seeing on a multiyear basis.

Okay. And then my follow-up, if I could just dig in to your last comment about the improvement. You mentioned that it's mostly getting driven by the Delaware. But how much of it is also for 2020 driven by just taking capital out of the STACK versus any well cost reductions or any cyclical factors? And I'm not sure -- I think your corporate breakeven is on a hedge basis as well.

Yes.

Yes. Jeanine, that's correct. It does include the benefit of hedges, which, for 2020, is relatively minor at this point.

David Harris, I think you can answer that.

Yes. Jeanine, in terms of capital efficiency, to Jeff's point, we're seeing a lot of progress across the board in the Delaware specifically. On the drilling side, we've changed our wellbore design. We've gone to a slim hole design that we've modified to a slightly larger hole that's allowing much faster drilling times. On the completion side, we continue to relentlessly attack nonproductive time and flat time, moving equipment around and when we're doing zipper fracs. And as we talked to you about before on the facility side, the move from more complex and customized facilities to more standardized and modular designs has driven a real step change in our performance there. These improvements really aren't just limited to the Delaware though. In the Rockies, we continue to see cost reductions and expected to see material further cost reductions. As we've highlighted in the Turner, we've had a 20% improvement year-over-year and continue to believe that we're going to see similar rate of change in the Niobrara as we continue to derisk that position and move more into development mode. In the STACK, we're seeing capital efficiency improvements from more efficient infill spacing results and improved stimulation designs. Just on the completion side alone, we've seen a 15% decrease in our costs since the beginning of the year, so we're really encouraged by that. And then obviously, working with a new partner in the Eagle Ford. As you saw in the ops report, we've driven somewhere around $1 million per well out as we've debundled services and worked with more efficient vendors and applied best practices from other parts of our asset base to that asset go forward. So we feel good about the capital efficiencies we're seeing across the entire portfolio and really want to make sure you appreciate it's not just limited to what we're doing in the Delaware.

The only thing I'd add, Jeanine, is we are allocating a significant amount of capital to the Delaware and last to the STACK, but don't count the STACK out. I see some work that we're doing internally in the STACK. We're driving down the well cost. We are doing some outstanding technical work in there. And it's just because of the high-quality of our portfolio that we are allocating more to the Delaware. But the STACK is still there. It's not far away from getting funding and it's going to be a significant part of our portfolio for a long time to go, and you're going to see capital allocated to STACK in future years. And it's going to be good, strong returns.

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

Philosophically, when you think about production growth, is 7% to 9% what you would see as the more normal oil growth rate if current commodity prices hold? Or do you see acceleration be backing up some of your comments on further cost reductions, reallocation to STACK or other areas?

Well, I think the main thing to understand is that we have the capability and the resource that we can deploy capital and generate strong returns at various growth rates. So we aren't really limited by the amount of resource and amount of opportunities with the amount of growth. It is really trying to maximize the capital efficiency of our program as well as to generate competitive growth, along with competitive free cash flow yield. And so we're trying to balance all of those variables. Given that, we think, as a company, that's appropriate for us to target high single-digit growth rates and mid-single-digit free cash flow yields. And that allows us to invest in very high-return opportunities. So we think, at this point, that's the right decision. Obviously, we're open to feedback from our shareholders on whether they think that's appropriate as well. But we think it's a strong program that's underpinned by very high-return projects. And we do, again, have the flexibility to grow at higher or lower rates, but we have no shortage of opportunities to do that for a long time.

Great. And then my follow-up is on your ops report, the Slide #18. You talked about the visibility of several hundred inventory locations in the Todd area. You talked to Cat Scratch Fever 2.0 in the prepared remarks. Can you talk to the characteristics of how the costs and the oil EURs from that broader inventory compare versus what you drilled in 2019 and what you expect to drill in 2020?

Brian, this is David. I think we expect it to continue to be an important growth driver for the foreseeable future. You've obviously got a highly charged reservoir there with stacked pay. As we've highlighted on Cat Scratch 2.0, we do see the pace in a bit to the east. And so we wouldn't expect copycat results all the way across it, but we think these are going to be some of the most compelling projects in the Lower 48 for the foreseeable future.

And can you remind us of the spacing assumptions that you have built in, in that area?

Brian, we're going to hand this over to John Raines, who heads up our Delaware Basin business unit.

Yes. Brian, for the Todd Area, we'll start in the Leonard. So we're just delineating the Leonard at this point, moving from appraisal into development. In other parts of the basin, we've seen six wells per section, and that's what we started with here, but we've got line of sight to upside to potentially 8 wells per section in the Leonard. Moving to the Second Bone. Historically, we've developed this on 4 wells per section, and that's what we've done from Central Todd going east. This is a bit of a geologically complex area as we move west and southwest in Todd. We're exploring six wells per section. Oxy actually offsets us to the west and they've been successful at six wells per section. And we've only just begun appraisal in the Wolfcamp here. We're testing multiple landing zones. We've actually tested three different landing zones in the Upper Wolfcamp. I think it's safe to assume that we'd feel good about two landing zones at four wells per section with a strong chance of upside to three landing zones at 12.

Your next question comes from the line of Subhash Chandra from Guggenheim Partners.

I just want to clarify the return of capital commentary, make sure I understood it correctly. Want to understand sort of how you split the buckets, debt, share buybacks and dividend growth with and without the Barnett sale. In particular, I think the presentation alludes to more debt reduction by year-end. Is that presuming the Barnett sale? And then how do we split the return of capital to share buybacks beyond that point?

Yes. This is Jeff. Yes. So no, it does not include the Barnett proceeds. So we are -- we've already obviously executed on $1.7 billion of the $3 billion debt target that we set earlier this year. We've got the cash and the balance sheet today to go ahead and execute the remainder of our $3 billion target. However, what we've seen happen over the last several months is interest rates go lower and the cost of debt go higher. And so we're going to be mindful of that and be opportunistic as we look to repurchase debt in the market. So we don't need those Barnett proceeds obviously to accomplish our debt targets going forward. Beyond that, that will allow us to utilize the proceeds in the Barnett for additional share repurchases, along with, obviously, the dividend that you highlighted. And certainly, the free cash flow that we expect to generate next year, that will have the potential to be devoted to further share repurchase programs.

Got you. Okay. And a question -- I think operators are seeking to monetize water assets, seems to be the thing to do. You've highlighted 40 saltwater disposal wells, et cetera. I'm just curious if that is something you might do and what capacity and capacity utilization might be at the moment?

Yes. This is Jeff. That's absolutely something we've looked at and we'll continue to monitor. We feel pretty good with our setup in the Delaware today. We like having control of those assets and the low cost that it brings to our cost structure going forward. But it's certainly something we've been monitoring and watching. And should the right opportunity arise, it's something we would consider. But frankly, where we sit today, we feel pretty good about our setup and certainly the cost structure that we've got.

Could you share, by any chance, the sort of the disposal capacity and the utilization levels you might be running?

Yes. I think roughly 40 -- we've got 40 saltwater disposal wells out in the space. I think if you look at Slide 15, we kind of highlight some of the detail there, about 8 water reuse facilities. So any -- capacity is 120,000 barrels, is the throughput capacity of those facilities.

Your next question comes from the line of Devin McDermott from Morgan Stanley.

So my first question, Dave, is actually following up on your response to one of the questions earlier around the STACK. You noted that it's close to competing for additional capital and likely receive it in future years. I guess first of all, as we think about 2020 with 0 rigs there, kind of what's envisioned in terms of cap allocation there, if any, in the preliminary 2020 plan that you provided? And then as we think about the outlook for the STACK going forward. Assuming no change in commodity prices, gas or NGLs, I guess, what would you need to see in order to make it competitive within the overall portfolio and start allocating more capital back?

Well, there's very little capital allocated in the current plan and 2020 is really more carry-in capital from 2019. We're working a number of initiatives. It's not just on the price side that we -- certainly a little bit higher gas and NGL prices would help. We're also -- our teams are doing some outstanding work on the cost side, on the drilling and completion costs and driving down those costs. We're also working on potential joint venture type opportunities there that could bring in some capital to drive higher capital efficiency into it. So there are several different angles that we're working this from -- in order to allocate capital in the future years. And obviously, we're being patient because we have such a strong portfolio. When we talk a lot about the Delaware, I think we need to talk about the Powder also and the success we're having in Niobrara and now that's going to drive more capital there and higher returns and very high returns there as well with the success we're having. And I can tell you, in the Eagle Ford also with our new partner, BP, they're very excited about what their -- or BPX, they're are very excited about this asset. I think they see it as one of their key cornerstones of the acquisition they did from BHP into one, they probably want to put a lot of capital too early on. So we just have a lot of high-return opportunities here in front of us. So we're just being patient to work out some of these other issues. And then I'm confident we're going to do it. And then the capital will come to the STACK when the appropriate time comes.

Got it. Makes sense. Can you comment on -- go for it.

Sorry, just a few more follow ups, specific thoughts on that. I would point out, as we've talked about this quarter, our lighter space infill projects are performing really well, exceeding both type curve and cost expectations. We do have a significant amount of inventory remaining in the heart of the play. So we do believe we still have a lot of economic resource there to develop. As Dave said, we've got a very high bar internally with the portfolio we have, but we're going to continue to try to bring those -- bring the value of those opportunities forward.

Got it. Can you comment on the production profile or decline rate you've assumed through the 2020 guidance? Or is it still too early to say given some of the uncertainty there for the Powder specifically -- or sorry, for the STACK specifically?

Yes. Devin, once again, we'll refrain from providing that at this point in time just because we still have some work on that front. But generally speaking, the last disclosure point we've had on the STACK is on the first year PDP decline. It was in the high 20% on a BOE basis. And it was on an oil basis, it was a high 30% range. So we'll recalibrate that number in conjunction with our reserve outlook -- with our; reserve report and our activity outlook for and have a more specific update for you here in February.

Your next question comes from the line of Neal Dingmann from SunTrust.

Great update on the Eagle Ford. My question is around that play. Beyond the 4Q and the 25 wells and obviously the growth you have there, I know you don't have the full 2020 out, but just how are you considering that play, as more of a -- still in the near term than a growth driver? Or is it more stable production with a more of a free cash flow generator?

Neal, this is David. I think the way we think about it within the context of our portfolio is the latter. It is an important free cash flow generator for us, and we believe we can maintain a profile there that's flat to some slight growth probably. We're -- we've regained operational momentum with our partner. We're going to bring on a big package of wells in Q4. And then as we move into 2020, we've talked about stabilizing somewhere around a rig count of 3 to 4 years. But we do still have quite a bit of resource in place and are testing infill and redevelopment concepts as well as things like the Austin Chalk. So we believe there's still a lot of good work to be done in the play.

Now just to reinforce that, what we're finding is there's still a lot of hydrocarbon in place and a lot of reservoir pressure there after our initial development activities take place. And so we're finding success with staggered wells within the Lower Eagle Ford as well as staggering them up in the Upper Eagle Ford between the Lower Eagle Ford completions. And so it's exciting how it's -- and there's -- it's just a great resource with a lot of pressure and a lot of opportunities that look [indiscernible] remaining. And then the Austin Chalk on top of it is probably a little less certainty as to how big that's going to be at this point. We're changing more to a linear gel type design on our completions there from slick water, and we're optimistic that, that can compete also.

Well, it certainly sounds like a lot of running room. And then moving over equally is positive. It sounds like, to me, I'm looking at Slide -- particularly on Slide 20. In the Nio, you've had some really interesting spacing tests there. I'm just wondering after -- specifically the two successful wells you've had there. Maybe could you just talk about just your thoughts just on overall spacing or at least in that area, how that's changed now after the success?

You bet. Yes, one of the things that we're excited about in the Niobrara is that we're seeing consistent results across a really large area, both from our results as well as from offset operators. And if you think about the 200,000 acres that we talk about in our Atlas West and East area, we have currently -- we talked about the spacing test at three wells per section. We have plans to test four well per section spacing. We've seen offset industry participants testing up to 6 and 7 wells per section. And so we're going to learn more here throughout 2020 that's going to inform with success, what we believe, will be development mode beginning in 2021 for the Niobrara for us.

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

Actually, I have a question for Dave, but I'm going to pick up on Neal's point with that Niobrara first. As -- you've given us kind of this cartoon log on '20. And it looks like the B section is more of a classic or carbonate versus the, I guess, the overall shale package. Is that the case? And does that tie into your spacing of it just being 3 or 4 across a unit?

Well, there's a couple of what we think are really great advantages that we have in and around our acreage position relative to other areas in the Powder River Basin. The first is from a thermal maturity standpoint, we are clearly in the oil window throughout the geologic column here and that varies. We've done a thermal maturity mapping throughout the basin and that varies. And as you go further to north with some other operators, you're more in a gassy window in the Niobrara. The other thing that you're pointing out, Charles, is, yes, you do have more of a chalky interval in the particular part of the basin within the Niobrara. And the chalky interval is what gives some brittleness. And that interval is developed around our acreage position and around some other acreage immediately around us but is not developed everywhere in the Powder. And so we think that brittleness, where it doesn't exist in other areas, it's a little more ductile and done frac as well. Other places, it really fracks well on our acreage. So we think -- and that's one caution I'd give everyone about comparing our Niobrara results, everybody else's Niobrara results too because we do have these unique advantages of being in the oil window and have this chalky interval in there that frankly, we think ours is going to be better because of these geological characteristics. And so far, it's turned out to be true.

That's great detail, Dave. And then if I could go back to your prepared comments about this unfortunate topic, the jury about federal acreage. And I know you talked a little bit about some of your contingency about being able to go on to private lands. But you might not be surprised to know, I agree with you, it's a bad idea. But national politics are more and more like a demolition derby where wild things happen. And so I wondered if you could talk more about what are the obstacles to implementing a frac ban or a cessation of permits. And what time frame that would play out over in your contingency planning?

Well, you can rest assure that we've done a lot of background legal work around this issue. And I don't think it's probably appropriate to go into the details around that work on this call. But I think that at a high level, we would say that we think it is really fraught with serious legal ramifications, the ability to enact that in a short-term basis. And I think even more importantly though, obviously, is we just think it's going to unfairly harm the communities where we work, the states where we work. We work in an incredibly environmentally responsible manner, our own company does and our industry does. And all this is going to do is to shift -- the demand for the oil is not going to change. It's there on a worldwide basis. And all this would do is to shift the production to areas of the world that -- where there are not as high environmental standards followed. And so we just think that it is obviously going to be impactful, very impactful to the U.S. economy and as well as our national defense. So we think it's just obviously a bad idea from a number of fronts and it's not good for the U.S., it's not good for the world. And again, I'm not going to go through the details of the legal issues. But we've studied it pretty deeply, and we think there's a significant time frame to do anything from a purely legal standpoint. Obviously, from a regulatory standpoint, there's a possibility to slow things down. But we've obviously been thinking through that and we have a deep inventory permit to help mitigate that. The targets on -- I think the key point of all this is we have a clear path forward if this were to take place and we've been thinking about it.

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

Congratulations on the quarter. Dave, I was just wondering, on Slide 17, can you add some color on the drivers of the multiyear capital shift to the Wolfcamp since your Leonard and Bone Spring results have consistently been so...

I didn't quite catch that. Could you repeat that, Jeffrey? I'm sorry.

Sure. On Slide '17, can you add some color on the drivers of the multiyear capital shift to the Wolfcamp since your Leonard and Bone Spring results have consistently been so successful?

This is David. I think we're seeing great results from all 3 of those main intervals. But I think the simple answer is really the capital efficiency. We see -- from development of the Wolfcamp formation, relative to that, the depth of resource and inventory. We have the various landing zones of the Wolfcamp. Those 2 things combined, I think, are really the main drivers of what you're seeing from some of that internal shift of where you'll see that capital deployed within the Delaware.

Okay. Great, that's helpful. And just -- I just was wondering if you could quickly give some of the technical differences between an Eagle Ford refrac versus a redevelopment oil.

Yes. It's a great question. I've actually asked the team that. The lingo is a little bit hard to follow. If you think about a refrac, it's just a traditional refrac where you're accessing stranded reserves there. Typically, what we do, the preferred approach -- we've tried a few different approaches, but we pump a liner refrac there to go in and restimulate near wellbore to access those stranded reserves. When we talk about redevelopment, those are new wells that would be drilled in the Upper Eagle Ford. So if you think about what we're doing today in our primary development sections, we're co-developing the Upper Eagle Ford with the Lower Eagle Ford. In units that were delivered prior to that shift, we got undeveloped Upper Eagle Ford. And so we're going back in and essentially, in some sense, kind of infilling Upper Eagle Ford wells, and those are the wells that we talk about as redevelopment.

And your next question comes from the line of David Heikkinen from Heikkinen Energy.

Kind of thinking through, and it seems like given your higher '19 Powder River basin exit rate and you're shifting more capital to your oilier Powder but definitely shifting less capital to your less oily STACK. But you've really got some increase to your 2020 oil CAGR in your hip pocket as it kind of flowed that through the model. I'm trying to lead the witness to 7% to 9% or higher, but it seems like that's a bit of a layup.

I don't know. I don't know. I'm trying -- I'm not sure with the sports analogy. You better -- not sure it's the right one, David. It's a layup, maybe a 15-foot jump shot. It's not a long 3 pointer.

Okay, fair enough. Unless you're James Harden.

There you go. Well, then that's like a layup, yes. but I mean obviously, we feel confident. We've exceeded our expectations the last few quarters. So we're -- we feel really good about the ability to execute on that.

And then just on the STACK, can you remind us how much of your capital is outside operated? And are you not consenting your current plan or thinking about not consenting in 2020?

Well, there's a -- the out -- and I don't have the exact number. The guys will have it for you here. But it's typically run higher than it has in any of the other business units. But the amount of the outside capital has actually -- our OBO capital has been declining this year significantly as other people move activity outside of the base as well. And typically, we try to find companies that are willing to participate in those projects. So we sell down our interest in those versus nonconsent. So we're trying to get some return on that as well.

Yes. And David, just specifically, we had about $8 million of non-op capital in the third quarter in the STACK. And from a year-to-date perspective, it's been about $30 million or so, although we have seen downward pressure on that, as Dave highlighted, throughout the year.

And there are no further questions at this time. Mr. Scott Coody, I turn the call back over to you for some closing remarks.

Well, I appreciate everyone's interest in Devon today. And if you have any further questions, please don't hesitate to reach out to the Investor Relations team, which consists of myself and Chris Carr. Thank you, and have a good day.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.