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 Cootey, 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 Rittenour, 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 Q3 is another one of exceptional execution for Devon 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 are delivering results that are exceeding expectations. Capital efficiency and cost reduction targets by a wide 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 $780,000,000 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 $3,000,000,000 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 one 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 Q4 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 target rate 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 have officially reestablished operational momentum with our new partner and expect to bring online more than 25 higher rate wells in the 4th quarter. And 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 in free cash flow. With a 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. However, before I get into 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 in 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 breakeven funding price of $48 WTI and 2.50 Henry Hub pricing. This ultra low breakeven 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 planning on a capital program in the range of $1,700,000,000 to $1,900,000,000 This level of activity is expected to generate oil growth of 7% to 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 breakeven price of $48 Furthermore, this conservative plan provides significant torque to the upside as we can generate free cash flow of $400,000,000 $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 2020, which is projected to decline by approximately $400,000,000 or 10% less than the original plan we outlined this February.
Importantly, our oil growth outlook over the same 2 year timeframe remains on track with the original plan. While 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. And the final item I'd like to address is a 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 turn 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 drive the next financial growth and strong returns for the company. And given our Q3 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 franchise asset in the Delaware, production continued to rapidly increase in the 3rd 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 $7,500,000 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 4th quarter is very strong. Our diversified development activity across all 5 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 4th 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 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% 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 Q3, 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 $1,000,000 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 8 operated wells that have averaged 30 day rates as high as 1500 BOE per day with a 90% oil mix.
Further progressing our confidence in this play are 2 spacing tests we commenced production on during the quarter in Atlas West. These spacing tests have shown positive results for the commercial potential of 3 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 Acres 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. And finally, our Eagle Ford and STACK assets are successfully fulfilling their respective roles in our portfolio, providing more than $600,000,000 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 Q3, 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 to target an average of 3 to 4 rig lines. This level of activity would maintain our base production profile and advance our infill and redevelopment work in the Lower and Upper Eagle Ford, while generating meaningful levels of free cash flow for the company. And lastly, in the STACK, our infill development program continues to deliver strong operational results.
Our recent Meramec development space at 4 to 6 wells per unit are exceeding type curve expectations and we have lowered well costs by as much as 30%. We still have a deep drilling inventory in the over pressured oil window of the play, but given recent weakness in gas and NGL prices, we continue to reduce activity in the STACK. In fact, we've recently dropped to 0 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 and C costs and through evaluation of partnership and DrillCo structures.
While I have nothing specific to announce today, can confirm that we're encouraged by ongoing discussions that are taking place with well capitalized counterparties. And 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 $597,000,000 a 22% increase compared to the year ago period, despite lower benchmark pricing. This level of cash flow exceeded capital spending resulted in free cash flow of $56,000,000 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 and 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 $1,500,000,000 of senior notes reducing our total debt to $4,300,000,000 and net financing costs by 25 percent 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 $3,000,000,000 debt reduction target. With strip prices where they are today, we expect our net debt to EBITDA ratio trend towards the low end of our 1 to 1.5 times targeted range as we execute on our multiyear plan. In the Q3, we were also very active with our share repurchase program completing $550,000,000 of share repurchases in the period. Since the program began in 2018, we've repurchased 147,000,000 shares at a total cost of $4,800,000,000 and 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 totaled over $1,700,000,000 representing a cash yield to shareholders of 20% when compared to our current market capitalization. This follows repurchases and dividends in 2018 totaling $3,200,000,000 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 $400,000,000 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 and P 500 index that possess valuation multiples far in excess of Devon's, supporting the continuation of our share repurchases into the future. And with that, I'll turn the call back over to Scott.
Thanks, Jeff. We will now open the call to Q and 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.
And your first question comes from the line of Arun Jiram from JPMorgan. 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. But 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 in 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 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 costs 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 is 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 3 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 and 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 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.
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.
So 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. 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 $400,000,000 less capital versus our original plan. And so obviously, on a normalized basis, if we went back to the original price, it would be below $46,000,000 I don't know if we have an exact number of what that may be.
Yes, Jameen, 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 into your last comment about the improvement. You mentioned 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'll answer that.
Yes. Jeneen, 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 mowing 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 expect 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 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. And 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 $1,000,000 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 less 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 costs. 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 strong returns.
Interesting. Thank you. I 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. Good morning, Brian. Philosophically, when you think about production growth, is 7 percent to 9% what you would see as a more normal oil growth rate if current commodity prices hold? Or do you see acceleration piggybacking on some of your comments on further cost reduction, 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 continent, it is 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 opportunity to do that for a long time.
Great. And then my follow-up is on your ops report, the Slide number 18, you talked about the visibility of several 100 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 EORs 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 forty eight 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 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 2nd 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. And then we've only just begun appraisal in the Wolfcamp here. We're testing multiple landing zones. We've actually tested 3 different landing zones in the Upper Wolfcamp.
I think it's safe to assume that we feel good about 2 landing zones at 4 wells per section with a strong chance of upside to 3 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. I 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 $1,700,000,000 of the $3,000,000,000 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 $3,000,000,000 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 water disposal wells, etcetera. 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 and about 8 water reuse facilities. So 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.
Good morning, Devin.
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 will 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 capital 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 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 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's 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. 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. So and I can tell you in the Eagle Ford also with our new partner BP, they're very excited about what their 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 1 they probably want to put a lot of capital to 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 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-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. 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. And 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 sorry for the STACK specifically?
Yes, Devin. And 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. But generally speaking, the last disclosure point we've had on the stack is on the 1st year PDP decline. It was in the high twenty percent 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.
Got it. Thank you very much.
Your next question comes from the line of Neal Dingmann from SunTrust. Your line is open.
Good morning, Neal. Thanks for taking my call. 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 it being 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.
Just to reinforce that, what we're finding, there's still a lot of hydrocarbon in place and a lot of reservoir pressure thereafter. 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. And there's it's just a great resource with a lot of pressure and a lot of opportunities that look like is remaining.
And then the Austin Chalk on top of it, 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.
Well, certainly, it sounds like a lot of running room. And then moving over equally as positive, it sounds like to me I'm looking at slide particularly on slide 20. In the now you've had some really interesting spacing tests there. I'm wondering after specifically the 2 successful wells you've had there. Maybe could you just talk about has your thoughts just on overall spacing or at least in that area how that's changed now after this 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've talked about the spacing test at 3 wells per section. We have plans to test 4 well per section spacing.
We've seen offset industry participants testing up to 6 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 Your next question comes from the line of
Charles Meade for
Your next question comes from the line of Charles Meade from Johnson Rice. Your line is open.
Good morning, Dave, to you and your whole team there. Actually, I have a question for Dave, but I'm going to pick up on Neil's point with that Niobrara first. Is you've given us a kind of this cartoon log on 2020 and it looks like the that 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 event just being 3 or 4 across the 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 the north with some other operators, you're more in a gassy window into 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. And that interval is developed around our acreage position and around some other acreage immediately around us, but it's 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 doesn't frac as well. Other places, it really fracs well on our acreage.
So we think and 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 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 to you 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 your frac ban or a cessation of permits? And what timeframe 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. But 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. And 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.
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.
All right. Well, thanks for that. As far
as 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.
And 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 multiyear capital shift to the Wolfcamp since your Leonard and Bone Spring results have consistently been so slow?
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 three 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 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. And just I just was wondering if you could quickly give some of the technical differences between an Eagle Ford refrac versus a redevelopment well?
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 re stimulate 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've 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.
Okay, great. Thanks for the clarity. I appreciate it.
And 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 and it seems like given your higher 2019 Powder River Basin exit rate and you're shifting more capital to your oily powder, but definitely shifting less capital to your less oily stack that 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 is a bit of a layup.
I don't know.
I don't know.
I'm about to throw a sports analogy at you, but I'm not sure of the right one, David. It's a layup, maybe a 15 foot jump shot. It's not a long 3 pointer.
Unless you're James Harden.
There you go. But 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 feel really good about the ability to execute on that.
And then just in the stacker, can you remind us how much of your capital was outside operated? And are you non consenting your current plan or thinking about non consenting in 2020?
Well, there is a I don't have the exact number, the guys will have it for a year, but it's typically run higher than it has in any other business units. But the amount of outside capital has actually or OBO Capital has been declining this year significantly as other people move activity outside of the basin 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 non consent. And so we're trying to get some return on that as well.
Yes. And David, just specifically, we had about $8,000,000 of non op capital in the 3rd quarter in the STACK. And from a year to date perspective, it's been about $30,000,000 or so, although we have seen downward pressure on that as Dave highlighted throughout the year.
Really not that much.
Okay.
And there are no further questions at this time. Mr. Scott Cootey, 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.