Welcome to Devon Energy's third quarter 2019 earnings conference call. At this time, all participants are in a listen-only mode. 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, and 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 Energy across all aspects of our business. The bold strategy we announced earlier this year to transform to a high-quality, multi-basin U.S. oil company is working, and is working quite well. By sharpening our focus on our very best U.S. oil assets, the operating teams at Devon Energy are delivering results that are exceeding expectations. Capital efficiency and cost reduction targets. 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've 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 three 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 multi-year 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 generate more than $3 billion of excess cash this year. With this abundant cash flow, we are delivering on our promise to reduce leverage and return capital to shareholders. Our balance sheet is exceptionally strong. At 1 times net debt to EBITDA, we have increased our dividend by 13% and are on track to reduce our share count approximately 30% by year-end. As you can see from these highlights, Devon is executing at a very high level on every strategic objective underpinning our strategy. Our unwavering focus on what we can control is delivering compelling financial and operational results that are demonstrating a positive rate of change unique among our competitors.
Clearly, we have accomplished quite a bit this year to date, and there is plenty of excitement left in 2019 as our upcoming fourth quarter is full of catalyst-rich events. The Delaware is set to attain another meaningful step up in oil production due to several high-impact projects coming online in Q4, headlined by our Cat Scratch Fever 2.0 project. There are also several good things happening in the Powder River Basin. We are raising our oil exit rate target, and our Niobrara appraisal work is unlocking a new resource play for us. The Eagle Ford will also be worth watching as we've officially re-established operational momentum with our new partner and expect to bring online more than 25 high-rate wells in the fourth quarter. Lastly, with regard to our Barnett sale process, the bids are in, and we continue to advance the process with interested parties.
We expect to exit the Barnett by year-end at a price that is consistent with our view of the intrinsic value of the asset. Looking ahead to 2020, we have conviction in our multi-year plan and expect to progress the operational scale of our business in the highest return areas of our portfolio, while delivering growth and free cash flow. With the significant improvements in capital efficiency we have experienced across our asset portfolio, we believe we can achieve the strategic objectives of our multi-year plan with substantially lower capital requirements compared to the original projection we laid out in February of this year. Before I get into the details of our 2020 outlook, I want to share with investors our capital allocation priorities for the upcoming year.
As always, Devon's top priority will be to fund maintenance capital requirements and the quarterly dividend. Once this objective is met, the next step in our capital allocation process is to selectively deploy capital to high return projects that will efficiently expand the cash flow of the business. Importantly, our plan meets all these capital allocation priorities at a low break-even funding price of $48 WTI and $2.50 Henry Hub pricing. This ultra-low break-even pricing point provides us with a substantial margin of safety to execute on our capital program on navigating through the inevitable commodity price volatility we will encounter. Should this volatility drive prices higher, we will remain disciplined, and the benefits of any pricing windfall above our conservative base planning scenario will manifest itself in higher levels of free cash flow for shareholders, not higher capital spending.
Conversely, should we see price volatility to the downside, we have designed our operating plan to have the flexibility and agility to appropriately react to changes in the macro environment. Although we are still finalizing the details of our 2020 operating plan, I can tell you we are directionally planning on a capital program in the range of $1.7 billion-$1.9 billion. This level of activity is expected to generate oil growth of 7%-9% compared to 2019 on a retained asset basis. When you account for the benefits of our ongoing share repurchase program, oil growth rates jump into the mid to high teens on a per share basis. As I've already emphasized, our 2020 plan is designed to completely fund our capital requirements at an ultra-low WTI break-even price of $48.
This conservative plan provides significant torque to the upside as we can generate free cash flow of $400 million at $55 WTI pricing. With our updated outlook, I hope this one key message resonates, that Devon's capital efficiency continues to trend meaningfully ahead of our multi-year plan. This is evidenced by our cumulative capital spending in 2019 and 2020, which is projected to decline by approximately $400 million or 10% less than the original plan we outlined this February. Importantly, our oil growth outlook over this same two-year timeframe remains on track with the original plan. This is a great result, we are not content with the substantial progress we have made. The management team at Devon is laser focused on optimizing returns and driving capital efficiency for our shareholders. I expect to have more positive updates on this topic in the near future.
A final item I'd like to address is the recent political rhetoric regarding drilling and fracking moratoriums on federal lands. Although we believe substantial obstacles exist for such an idea to be enacted into law, I do want to highlight that only 20% of our total company-wide leasehold resides on federal land. Within our core focus areas, our largest federal acreage holding resides in the Powder River Basin, which accounts for nearly 60% of our leasehold in that operating area. In the Delaware Basin, roughly half of our acreage is federal, and our Eagle Ford and STACK assets reside almost entirely on private lands. Regardless of how the politics of this issue will ultimately be resolved, I do want to emphasize that we have been building a deep inventory of federal drilling permits in our highest confidence development areas within the Delaware and Powder River Basin.
Furthermore, our diversified multi-basin portfolio provides the flexibility and the depth of inventory within each of our core basins to be nimble and quickly pivot drilling activity to private leasehold that is highly economic and well-positioned on the cost curve. While our diversified portfolio positions us well to adapt to a scenario such as this, we fundamentally believe that the basic notion of such campaign rhetoric is fraught with serious economic ramifications. This proposal would unfairly harm the communities that financially benefit from our business activity, as well as impact the broader U.S. economy from an inevitable spike in energy costs that would unnecessarily limit GDP growth. That concludes my prepared remarks. I'd now like to introduce and turn the call over to David Harris.
David was recently appointed Executive Vice President of Exploration and Production, replacing my good friend Tony Vaughn, who is retiring from Devon after 20 years of service. Many of you know David, but for those of you who do not, David has been at Devon for more than a decade and is a seasoned and trusted leader who has been instrumental in strengthening Devon into the world-class U.S. oil company it is today. David?
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. 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 France 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 six 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 five of our core areas in the Stateline 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 one project immediately to the southeast in our world-class Todd area. While geologic mapping indicates that this thin spot thins a bit to the east, we do expect Cat Scratch 2.0 to be special and more prolific than the typical Second Bone Spring project. Lastly, in the Delaware, another noteworthy trend I would like to highlight is our improving capital efficiency. In the most recent quarter, our drilled and completed feet per day metrics in the Wolfcamp improved 45% and 65% year-over-year, respectively. This positive trend is very important as we expect the majority of our drilling activity to target the Wolfcamp formation next year.
These steadily improving cycle times and costs will provide capital efficiency momentum heading into 2020. The next asset I would like to discuss is the Powder River Basin, one of the top emerging oil growth opportunities in North America. In the third quarter, our full field development activity, targeting the Turner, Parkman, and Teapot formations in our Super Mario area, drove oil production 25% higher year-over-year. With this drill bit success, we are raising our 2019 oil exit rate growth target in the Powder River to more than 70% compared to 2018, up from our previous target of greater than 50%. This strong growth is accompanied by structural improvements to our capital efficiency as we attain operating scale in the play.
Specifically, with the Turner formation, our top development target in 2019, we have achieved capital savings of greater than $1 million per well or nearly 20% compared to last year. Another critically important initiative underway in the Powder River is the delineation of our Niobrara Shale potential in the basin. Our 200,000 net acre Niobrara position in the core of the oil fairway possesses repeatable resource play characteristics with the potential to be an important growth platform for Devon in 2020 and beyond. Over the past year, industry permitting has accelerated. More than 30 new Niobrara wells have been brought online around our acreage position in Converse and Campbell Counties. Specifically for Devon, we are methodically focusing our delineation efforts in the southwest quadrant of our acreage, called Atlas West, which has delivered the top oil rates in the basin.
To date, we have brought online eight operated wells that have averaged 30-day rates as high as 1,500 BOE per day with a 90% oil mix. Further progressing our confidence in this play are two spacing tests we commenced production on during the quarter in Atlas West. These spacing tests have shown positive results for the commercial potential of three Niobrara wells per section and the ability to develop the Niobrara independently of the deeper Turner interval. By the time of our next call of February, we expect to have several more appraisal wells online, further delineating our Atlas West acreage position. With positive operating results we've attained to date, coupled with several encouraging industry data points, it is likely that the Niobrara will compete for increased capital allocation in 2020, with potential for us to double our drilling activity.
Finally, our Eagle Ford and STACK assets are successfully fulfilling their respective roles in our portfolio, providing more than $600 million of free cash flow over the past year. In the Eagle Ford play, the key message I want to convey is that we have officially reestablished operational momentum with our new partner in the play. With peak completion activity for the year occurring in the third quarter, we expect a strong production response in Q4, with more than 25 Eagle Ford wells scheduled to come online. The impact from these high-quality wells is projected to increase our Eagle Ford net production to between 50,000 and 55,000 BOEs per day in the fourth quarter. We're still working on details for the 2020 plan with our partner, our intent is to target an average of three to four rig lines.
This level of activity would maintain our base production profile and advance our infill and redevelopment work in the Lower Eagle Ford and Upper Eagle Ford while generating meaningful levels of free cash flow for the company. Lastly, in the STACK, our infill development program continues to deliver strong operational results. Our recent Meramec development spaced at 4 to 6 wells per unit are exceeding type curve expectations. We have lowered well costs by as much as 30%. We still have a deep drilling inventory in the overpressured oil window of the play. Given recent weakness in gas and NGL prices, we continue to reduce activity in the STACK. In fact, we recently dropped to zero rigs in the play as higher returns currently exist within other oilier projects in our portfolio. While STACK activity may be down, it is not indefinitely out.
We are actively working to rejuvenate returns in the play to more competitive levels within our portfolio by lowering our D&C costs and through evaluation of partnership and DrillCo structures.
While I have nothing specific to announce today, I can confirm that we're encouraged by ongoing discussions that are taking place with well-capitalized counterparties. With that, I will now turn the call over to Jeff.
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 three 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 one to one and a half times targeted range as we execute on our multi-year plan.
In the third quarter, we were also very active with our share repurchase program, completing $550 million of share repurchases in the period. Since the program began in 2018, we've repurchased 147 million shares at a total cost of $4.8 billion. We are on pace to reduce our outstanding share count 30% by year-end. In addition to our share repurchase activity, we are also returning cash directly to our shareholders through our quarterly dividend, which we've increased by 50% since 2018. Year to date, share repurchases and dividends total over $1.7 billion, representing a cash yield to shareholders of 20% when compared to our current market capitalization. This follows repurchases and dividends in 2018 totaling $3.2 billion, or a 35% yield to shareholders. Moving forward, we expect additional cash returns for our shareholders as our multi-year plan builds momentum.
We will continue the use of the dividend and share repurchases to deliver free cash flow to our investors. As Dave touched on in his opening remarks, our 2020 plan is set up for attractive per-share growth and free cash flow generation of $400 million at a $55 WTI price deck. To put this into context, the free cash flow we expect to generate in 2020 is equivalent to 5% of our current market capitalization. We believe this free cash flow yield is very competitive with other sectors in the broader S&P 500 index that possess valuation multiples far in excess of Devon's, supporting the continuation of our share repurchases into the future. With that, I'll turn the call back over to Scott.
Thanks, Jeff. We'll now open the call to Q&A. Please limit yourself to one question and a follow-up. This allows us to get to more of your questions on the call today. With that, operator, we'll take our first question.
As a reminder, to ask a question, you will need to press star one on your telephone. Your first question comes from the line of Arun Jayaram from J.P. Morgan. Your line is open.
Good morning. 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 could give some thoughts on the program next year, lateral lengths, and number of wells, and where do you see well costs on a 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. That being said, with regards to our allocation of 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. Obviously, the PRB and the Eagle Ford would be top-funded assets as well within our portfolio. As always, with the extended reach laterals, we continue to push towards having longer laterals every year. If you saw our recent operations report, we're pushing towards 10,000 in virtually every area that we operate.
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 report, it really shows how we're continuing to get drilling and completion efficiencies we think that are leading the industry in cost per foot, drilling and completion cost per foot. We're not done. 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. Just my follow-up. On slide five, 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?
Yeah, Arun, you bet. Yeah, 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. Again, that's another area where we would see continued reduction in our cost structure as we move into 2020. As it relates to the realizations, as a general statement, I would say, I would expect it to look a little bit like this year. It looks like there's going to be continued pressure on Waha pricing coming out of the Delaware. 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. 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.
Great, thanks a lot.
Your next question comes from the line of Jeanine Wai from Barclays. Your line is open.
Hi, good morning, everyone.
Good morning, Jeanine.
My question is on 2020 capital efficiency and 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. I'm just trying to get a sense of the year-over-year change in capital efficiency on an apples-to-apples basis. 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 nine in the deck, where we're saying we're delivering all of the oil growth that we had originally planned over the two-year timeframe. Yet, we're doing it for $400 million less capital versus our original plan. 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.
Yeah, Jeanine, this is Jeff. I actually don't have the absolute number, but Dave described it well. Obviously, the biggest driver of that is the capital efficiency that we're seeing in the Delaware Basin, and really across the board in each of our different areas. The Delaware Basin 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 multi-year basis.
Okay, then my follow-up, if I could just dig into your last comment about the improvement. You mentioned that it's mostly getting driven by the Delaware. 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? I'm not sure, I think your corporate breakeven is on a hedged basis as well?
Yes, Jeannine, that's correct. It does include the benefit of hedges, which for 2020 is relatively minor at this point.
David Harris, I think your answer to that.
Yeah, Jeannine, 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 non-productive time and flat time, mobbing equipment around when we're doing zipper fracs. 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 expect to see material further cost reductions, as we've highlighted in the Turner.
We've had a 20% improvement year-over-year, continue to believe that we're going to see similar rate of change in the Niobrara as we continue to de-risk 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 cost since the beginning of the year. We're really encouraged by that. 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 de-bundled services and worked with more efficient vendors, and applied best practices from other parts of our asset base to that asset go forward.
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, Jeannine, is we are allocating a significant amount of capital to the Delaware, less to the STACK, don't count the STACK out. I see some work that we're doing internally in the STACK. We're driving down the well costs. We are doing some outstanding technical work in there. It's just because of the high quality of our portfolio that we are allocating more to the Delaware. The STACK is still there. It's not far away from getting funding. 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 strong returns.
Interesting. Thank you. Appreciate the detailed response.
Your next question comes from the line of Brian Singer from Goldman Sachs. Your line is open.
Thank you. Good morning.
Morning, Brian.
Philosophically, when you think about production growth, is 7%-9% what you would see as a more normal oil growth rate if current commodity prices hold? Do you see acceleration piggybacking on 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. 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. We're trying to balance all of those variables. Given that, we think as a company, that it's appropriate for us to target high single-digit growth rates and mid-single-digit free cash flow yields. That allows us to invest in very high return opportunities. 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.
We think it's a strong program that's underpinned by very high return projects. We do, again, have the flexibility to grow at higher or lower rates. We have no shortage of opportunities to do that for a long time.
Great. Thanks. My follow-up is on your ops report, the slide number 18, you talk about the visibility of several hundred inventory locations in the Todd area. You talked to Cat Scratch Fever 2.0 in 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 pay thin 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.
Can you remind us of the spacing assumptions that you have built in that area?
Brian, we're going to hand this over to John Raines, who heads up our Delaware Basin business unit.
Yeah, Brian, for the Todd area, we'll start in the Leonard. We're just delineating the Leonard at this point, moving from appraisal into development. In other parts of the basin, we've seen 6 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 6 wells per section. Oxy actually offsets us to the west, and they've been successful at 6 wells per section. 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.
Great. Thank you so much.
Your next question comes from the line of Subash Chandra from Guggenheim Partners. Your line is open.
Thank you. Good morning, everyone. 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? How do we split the return of capital to share buybacks beyond that point?
Yeah, this is Jeff. Yeah. No, it does not include the Barnett proceeds. 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 on 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. We're going to be mindful of that and be opportunistic as we look to repurchase debt in the market. We don't need those Barnett proceeds, obviously, to accomplish our debt targets going forward. Beyond that'll 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. 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.
Yeah, 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. It's certainly something we've been monitoring and watching, and should the right opportunity arise, it's something we would consider. 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?
Yeah, I think 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 and about eight water reuse facilities. Capacity is 120,000 barrels, is the throughput capacity of those facilities.
Okay, terrific. Thank you.
Your next question comes from the line of Devin McDermott from Morgan Stanley. Your line is open.
Good morning.
Morning, Devon.
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 will likely receive it in future years. I guess, first of all, as we think about 2020 with zero rigs there, what's envisioned in terms of cap allocation there, if any, in the preliminary 2020 plan that you provided? 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 in 2020. It's really more carry-in capital from 2019. We're working a number of initiatives. It's not just on the price side certainly a little bit higher gas and NGL prices would help. 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. There's several different angles that we're working this from in order to allocate capital in the future years. Obviously, we're being patient because we have such a strong portfolio.
We talk a lot about the Delaware, but I think we need to talk about the Powder also, and the success that we're having in Niobrara, and how that's going to drive more capital there and higher returns and very high returns there as well with the success we're having. I can tell you in the Eagle Ford also with our new partner, BP, they're very excited about what their or BPX, 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 to early on. We just have a lot of high return opportunities here in front of us. We're just being patient to work out some of these other issues.
I'm confident we're going to do it, and then capital will come to the STACK when the appropriate time comes.
Dave, can you comment on?
Got it. Makes sense.
Go for it.
Sorry, just a few more follow-up 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. 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 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? Is it still too early to say, given some of the uncertainty there for the Powder or sorry, for the STACK specifically?
Yeah, Devon, once again, we'll refrain from providing that at this point in time just because we still have some work to do on that front. 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. We'll recalibrate that number in conjunction with our reserve report and our activity outlook and have a more specific update for you here in February.
Got it. Thank you very much.
Your next question comes from the line of Neal Dingmann from SunTrust. Your line is open.
Well, Neal, thanks for taking my call. Great update on the Eagle Ford. My question is around that play. Beyond the four Q and the 25 wells, and obviously the growth you have there, I know you don't have the full 2020 out, just how are you considering that play as more of a still in the nearer term than a growth driver? Is it more stable production with 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've regained operational momentum with our partner. We're going to bring on a big package of wells in Q4. As we move into 2020, we've talked about stabilizing somewhere around a rig count of 3 to 4 years. 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. We believe there's still a lot of good work to be done in the play.
Yeah, 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. 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. It's exciting. It's just a great resource with a lot of pressure and a lot of opportunities that look like it's remaining, and then the Austin Chalk on top of it. It's 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 slickwater, and we're optimistic that that can compete also.
Certainly sounds like a lot of running room. Moving over equally as positive sounds like to me, I'm looking at slide, particularly on slide 20. In the Niobrara, 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, as your thoughts just on overall spacing or at least in that area, how that's changed now after this success?
You bet. Yeah. 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. If you think about the 200,000 acres that we talk about in our Atlas West and East area, we've 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 six and seven wells per section. 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.
Very good. Thanks for the details, guys.
Your next question comes from the line of Charles Meade from Johnson Rice. Your line is open.
Morning, Dave, to you and your whole team there. Actually, I have a question for Dave, but I'm going to pick up on Neal's point with that Niobrara first. You've given us this cartoon log on 20, and it looks like that B section is more of a classic or a carbonate versus, I guess, the overall shale package. Is that the case, and does that tie in to your spacing of it just being three or four 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 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 this particular part of the basin within the Niobrara, and the chalky interval is what gives some brittleness. That interval is developed around our acreage position and around some other acreage immediately around us, but is not developed everywhere in the Powder River.
We think that brittleness where it doesn't exist in other areas, it's a little more ductile and doesn't frack as well other places. It really fracks well on our acreage. That's one caution I'd give everyone about comparing our Niobrara results to 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 turning out to be true.
That's great detail, Dave. If I could go back to your prepared comments about this unfortunate topic du jour about federal acreage. I know you talked a little bit about some of your contingency about being able to go onto 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. I wondered if you could talk more about what are the obstacles to implementing a frack ban or a cessational permits.
What time frame that would play out over in your contingency planning?
Well, you can rest assured 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. I think that, at a high level, we would say that we think that it is really fraught with serious legal ramifications, the ability to enact that in a short-term basis. I think even more importantly, though, obviously, is we just think it is 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. 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.
All this would do is to shift the production to areas of the world that where there are not as high environmental standards followed. We just think that it is obviously going to be very impactful to the U.S. economy, and as well as our national defense. 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. 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. Now, obviously, from a regulatory standpoint, there's a possibility to slow things down. We've obviously been thinking through that, and we have a deep inventory permit to help mitigate that.
All right. Well, thanks for that info.
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.
Got it.
Your next question comes from the line of Jeffrey Campbell from Tuohy Brothers. Your line is open.
Good morning, and congratulations on the quarter. Dave, I was just wondering, slide 17, can you add some color on the drivers of the multi-year capital shift to the Wolfcamp since your Leonard and Bone Spring results have consistently been so successful?
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 multi-year 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 three of those main intervals. 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 in the various landing zones of the Wolfcamp. Those two 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. I just was wondering if you could quickly give some of the technical differences between an Eagle Ford refrac versus a redevelopment well.
Yeah, 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. 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. 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've got undeveloped Upper Eagle Ford. We're going back in. Essentially, in some sense, kind of infilling Upper Eagle Ford wells. Those are the wells that we talk about as redevelopment.
Okay, great. Thanks for the clarity. I appreciate it.
Your next question comes from the line of David Heikkinen from Heikkinen Energy. Your line is open.
Good morning, guys. Thanks for taking the question. Kind of thinking through, it seems like given your higher 2019 Powder River Basin exit rate, you're shifting more capital to your oilier Powder, but definitely shifting less capital to your less oily STACK, that you've really got some increase to your 2020 oil figure in your hip pocket as I kind of flowed that through the model. Not trying to lead the witness to 7%-9% or higher, it seems like that's a bit of a layup.
Oh, I don't know.
I don't know.
I'm about to throw a sports analogy at you, but I'm not sure the right one, David. It's a layup, maybe not. Maybe a 15-foot jump shot.
Okay. Fair enough.
It's not a long three-pointer.
Unless you're James Harden.
There you go. Well, that's like a layup, yes. Obviously, we feel confident. We've exceeded our expectations the last few quarters. We feel really good about the ability to execute on that.
Just in the STACK, can you remind us how much of your capital is outside operated, and are you non-consenting your current plan or thinking about non-consenting in 2020?
Well, 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. The amount of OBO capital has been declining this year significantly as other people move activity outside of the basin as well. Typically, we try to find companies that are willing to participate in those projects, so we sell down our interest in those versus non-consent. We're trying to get some return on that as well.
Yeah, David, just specifically, we had about $8 million of non-op capital in the third quarter in the STACK. 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.
Really not that much. Okay.
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.