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Devon Energy Corp (DVN 0.42%)
Q3 2019 Earnings Call
Nov 6, 2019, 11:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Welcome to Devon Energy's Third Quarter 2019 Earnings Conference Call. [Operator Instructions]. I'd now like to turn the call over to Mr. Scott Coody, Vice President of Investor Relations. Sir, you may begin.
Scott Coody -- Vice President, Investor Relations
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 US 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.
David A. Hager -- President and Chief Executive Officer
Thanks Scott and good morning everyone. The third quarter is another one of exceptional execution for Devon across all aspects of our business. The [Indecipherable] strategy we announced earlier this year to transform to a high quality multi-basin US oil company is working and is working quite well. By sharpening our focus on our very best US oil assets, the operating teams at Devon are delivering results that are exceeding expectations.
Capital efficiency and cost -- capital efficiency and cost reduction targets by a wide [Technical Issues]. 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 is exceeded 25% and a 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 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, reduce 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 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 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 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 have officially reestablished operational momentum with our new partner and expect to bring online more than 25 high-rate wells in the fourth quarter. And lastly, with regard to our Barnett Shale process, the bids are in and we continue to advance to 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 and the highest return areas of our portfolio, while delivering growth and 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 were substantially lower capital requirements compared to the original projection we laid out in February of this year. However, 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 in the quarterly dividend. Once this objective is met, the next step in our capital allocation process is to selectively deploy capital at a high return projects, and will patiently expand a cash flow of the business. Importantly, our plan meets all of these capital allocation priorities at a low breakeven funding price of $48 WTI and 250 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 we are directionally planning on a capital program in a range of $1.7 billion to $1.9 billion. This level of activity is expected to generate oil growth of 7% to 9% compared to 2019 on a retained asset basis. We 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 talk to the upside as we can generate free cash flow of $400 million, a $55 WTI pricing. With our updated outlook, I hope there is 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 the same two-year timeframe remains on track with the original plan. While this is a great result, we are not content with a substantial progress we have made. The management team at Devon is a 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 a part of our item, I'd like to address is a recent political letter 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 companywide leasehold resigns 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 lease hold, a net 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 a flexibility and a depth of inventory within each of our core basins to be nimble and quickly pivot drilling activity to private leasehold, this 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 a 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 US economy from an inevitable spike in energy cost, it 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 US oil company it is today. David?
David Harris -- Executive Vice President, Exploration and Production
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 net financial growth and strong returns for the company. And given our third quarter results and outlook, we continue to hit on all cylinders. From my prepared remarks today, I will cover the asset specific highlights that are driving this enterprise level success. Beginning with our [Indecipherable] 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 2200 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 state-line area continues to progress right on plan positioning the Delaware for another quarter of strong oil growth.
In the aggregate, we expect to bring online more than 30 wells in the fourth quarter with the top catalyst being our 10 well Cat Scratch Fever 2.0 project. Cat Scratch 2.0 directly offsets the record setting Phase one project immediately to the Southeast in our world-class Todd area. While geologic mapping indicates that this 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 a $1 million per well or nearly 20% compared to last year. Another critically important initiative under way 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 1500 BOE per day with a 90% oil mix.
Further progressing, our confidence in this play, our two spacing test, we commenced production on during the quarter in Atlas West. These spacing test 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 obtained 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 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, but 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 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 spaced at four to six 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, 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 exists within other oilier projects in our portfolio.
So 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 drill cost structures. Though 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. And with that I will now turn the call over to Jeff.
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
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 resulted 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. We strip prices where they are today, we expect our net debt to EBITDA ratio to trend toward the low end of our 1 to 1.5 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 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 $1.7 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 35% yield to shareholders.
Moving forward, we expect additional cash returns for our shareholders as our multi-year plan builds momentum. We will continue to 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 in the 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.
And with that, I'll turn the call back over to Scott.
Scott Coody -- Vice President, Investor Relations
Thanks, Jeff. We will 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.
Questions and Answers:
Operator
[Operator Instructions]. And your first question comes from the line of Arun Jayaram from JP Morgan. Your line is open.
Arun Jayaram -- JP Morgan -- Analyst
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 give us 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?
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
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 this year and obviously the PRB and the Eagle Ford to be top funded assets as well as in our portfolio and as always with the extended reach laterals, we continue to push toward having longer laterals over year. And if you saw for recent operations report, we're pushing toward 10,000 virtually every area that we operate. So that's a good new story where the capital efficiency continues to improve.
David A. Hager -- President and Chief Executive Officer
Arun, It's Dave, I may just make it one more comment on just the -- what the capital efficiency or the cost reduction side, if you go to obviously slide 16 in operations reported, it really shows how we're continuing to get drilling and completion efficiencies. So, we think that are leading the industry and cost per foot, drilling and completion cost per foot. But we're not done, and I can tell you the way we've guided and built into our 2020 guidance, we are still seeing that we think there is opportunity to do even better. And we're working on some things and have an early results that back that up.
Arun Jayaram -- JP Morgan -- Analyst
Great and just my follow-up. On Slide 5, you guys present your updated guidance on the cost structure, maybe for you, Jeff. I was wondering if you could give us a sense of how you expect the cost structure to trend for the New Devon in 2020 and maybe also provide some thoughts on how do you think realizations or differentials will trend for the three main product groups for the New Devon?
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
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 on from an LOE and a G&A standpoint, obviously the financing cost piece is going to be dependent on the timing of our debt repurchase. But again, that's another area where we would see 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 it 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 was a really good about. There's obviously plenty of pipeline capacity there to move the product and we generally have a pretty balanced approach they're 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.
Arun Jayaram -- JP Morgan -- Analyst
Great, thanks a lot.
Operator
Your next question comes from the line of Jeanine Wai from Barclays. Your line is open.
Jeanine Wai -- Barclays -- Analyst
Hi, good morning everyone.
David A. Hager -- President and Chief Executive Officer
Good morning, Jeanine.
Jeanine Wai -- Barclays -- Analyst
So my question is on 2020 capital efficiency in the Corporate breakeven. You've reported 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?
David A. Hager -- President and Chief Executive Officer
I don't know if I have an absolute number normalized for pricing, and I think the easiest way to think about it is to look at Slide 9 and the deck, where we're saying we're delivering all of the oil growth that we had originally planned over the two-year timeframe. But yet, we're doing it for $400 million less capital versus our original plan. And so obviously on a normalized basis if we went back to the original pricing, it would be below $46. I don't know if we have an exact number of what that may be.
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
Yeah Jeanine, this is Jeff. I actually don't have the absolute number, but Dave described it well and obviously the biggest driver of that is the capital efficiency that we're seeing in the Delaware and really across the board in each of our different areas. But the Delaware obviously is the biggest component of our capital spend and that's the biggest driver of that capital efficiencies that we're seeing on a multi-year basis.
Jeanine Wai -- Barclays -- Analyst
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?
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
Yes, Jeanine. That's correct. It does include the benefit of hedges, which for 2020 is relatively minor at this point.
David A. Hager -- President and Chief Executive Officer
David Harris, I think, you answer that.
David Harris -- Executive Vice President, Exploration and Production
Yeah, Jeanine in terms of capital efficiency to Jeff's point, we're seeing a lot of progress across the board in the Delaware specifically on the drilling side where 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, moving equipment around when we're doing zipper fracs.
And as we talk to you about before on the facility side, the move from more complex and customized facilities to more standardized and modular designs has driving a real -- 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 derisk that position to move more into development mode.
In the STACK, we're seeing capital efficiency improvements from more efficient infill spacing results and improved stimulation designs. Just on the completion side alone, we've seen a 15% decrease in our costs since the beginning of the year. So we're really encouraged by that and then obviously working with a new partner in the Eagle Ford as you saw in the ops report we've driven somewhere around $1 million per well out as we've debundled services and worked with more efficient vendors and apply 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.
David A. Hager -- President and Chief Executive Officer
The only thing I'd add Jeanine, is we are allocating a significant amount of capital to the Delaware and last to the STACK, but don't count to STACK out. I see some work that we're doing internally in the STACK. We are driving down to 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 ago. And you're going to see capital allocated to STACK in future years and is going to be good strong returns.
Jeanine Wai -- Barclays -- Analyst
Interesting. Thank you. I appreciate the detailed response.
Operator
Your next question comes from the line of Brian Singer from Goldman Sachs. Your line is open.
Brian Singer -- Goldman Sachs -- Analyst
Thank you. Good morning.
David A. Hager -- President and Chief Executive Officer
Good morning, Brian.
Brian Singer -- Goldman Sachs -- Analyst
Philosophically, when you think about production growth of 7% to 9%, what you would see is a more normal oil growth rate of current commodity prices hold or do you see acceleration piggybacking on some of your comments on further cost reduction to allocation to STACK or other areas?
David A. Hager -- President and Chief Executive Officer
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 at 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 now we think it's a 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 just underpinned by very high return projects and we do again have the flexibility to grow at higher or lower rates. But we have no shortage of opportunities to do that for a long time.
Brian Singer -- Goldman Sachs -- Analyst
Great, thanks. And then my follow-up is on your Ops report, the slide number 18. You talked 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 [Indecipherable] from that broader inventory compare versus what you've drilled in 2019 and what you expect to drill in 2020?
David Harris -- Executive Vice President, Exploration and Production
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 tax pay. You know we've highlighted on Cat Scratch 2.0. We do see the pace in a bit to the east. And so we wouldn't expect copycat results all the way across it, but we think these are going to be some of the most compelling projects in the Lower 48 for the foreseeable future.
Brian Singer -- Goldman Sachs -- Analyst
And can you remind us of the spacing assumptions that you have built-in in that area?
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
Brian, we're going to hand this over to John Raines, who heads up our Delaware Basin business unit.
John Raines -- Vice President, Delaware Basin Business Unit
Yeah, Brian. For the Todd area, we'll start in the Leonard. So we're just delineate the Leonard at this point moving from appraisal into development. In other parts of the basin, we've seen six wells per section and that's what we started with here, but we've got a line of sight to upside to potentially eight wells per section in the Leonard. Moving to the second Bone, historically we've developed this on four 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 [Indecipherable]. We're exploring six wells per section. Oxy [Phonetic] actually offsets to the west, and they've been successful at six wells per section and then we've only just begun appraisal in the Wolfcamp here. We are 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 feel good about two landing zones of four wells per section with a strong chance of upside to three landing zones at 12.
Brian Singer -- Goldman Sachs -- Analyst
Great, thank you so much.
Operator
Your next question comes from the line of Subash Chandra from Guggenheim Partners. Your line is open.
Subash Chandra -- Guggenheim Partners -- Analyst
Thank you and good morning everyone. I just wanted 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 within, 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?
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
Yeah, this is Jeff. Yes, I know, it does not include the Barnett proceeds. So we are -- we've already obviously executed on $1.7 billion of the $3 billion debt target that we set earlier this year. We've got the cash on the balance sheet today to go ahead and execute the remainder of our $3 billion target. However, what we've seen happened over the last several months, as interest rates go lower and that 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.
Subash Chandra -- Guggenheim Partners -- Analyst
Got it, OK. And a question I think operators are seeking to monetize, water asset seems to be thing to do? You've highlighted 40 saltwater disposal wells, etc. I'm just curious if that is something you might do and what capacity and capacity utilization might be at the moment?
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
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 in the low cost that it brings to our asset, 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.
Subash Chandra -- Guggenheim Partners -- Analyst
Could you share by any chance the sort of the disposal capacity and the utilization levels you might be trying?
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
Yeah, 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 eight water reuse facility. So capacity is 120,000 barrels, is the throughput capacity of those facilities.
Subash Chandra -- Guggenheim Partners -- Analyst
Okay, terrific. Thank you.
Operator
Your next question comes from the line of Devin McDermott from Morgan Stanley. Your line is open.
Devin McDermott -- Morgan Stanley -- Analyst
Good morning.
David A. Hager -- President and Chief Executive Officer
Morning, Devin.
Devin McDermott -- Morgan Stanley -- Analyst
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, you know at zero rigs there, what's envisioned in terms of cap allocation there if any in the preliminary 2020 plan that you provided? And then as we think about the outlook for the STACK going forward assuming no change in commodity prices gas or NGL, I guess what would you need to see in order to make it competitive within the overall portfolio and start allocating more capital back?
David A. Hager -- President and Chief Executive Officer
Well, there is very little capital allocated in the current plan, and 2020 is really more carry in capital from 2019. We're working on a number of initiatives, it's not just on the price side that we -- certainly a little bit higher gas and NGL prices would help, we're also -- our teams are doing some outstanding work on the cost side, on the drilling and completion costs and driving down those costs. We're also working on potential joint venture type opportunities there that could bring in some capital to drive higher capital efficiency into it. So there are several different angles that we're working this from in order to allocate capital in the future years. And obviously we're being patient because we have such a strong portfolio. We talk a lot about the Delaware, but I think we need to talk about the Powder also in the success, we're having in Niobrara and how that's going to drive more capital there and higher returns and very high returns here as well with the success we're having. And I can tell you in the Eagle Ford also with our new partner, BP, they are very excited about what their -- BPX are very excited about this asset. I think they see it as one of key cornerstones of the acquisition they did from BHP, the one 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 come to the STACK when the appropriate time comes.
Devin McDermott -- Morgan Stanley -- Analyst
This makes sense. Can you comment on so forth.
David Harris -- Executive Vice President, Exploration and Production
Sorry, just a few more follow-up specific thoughts on that. I would point out as we've talked about this quarter. Our lighter spaced infill projects are performing really well exceeding both type curve and 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.
Devin McDermott -- Morgan Stanley -- Analyst
Got it. Can you comment on the production profile or decline rate you've assumed through the 2020 guidance or is it still too early to say given some the uncertainty there for the Powder specifically, I'm sorry, for the STACK specifically?
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
Yeah, definitely. Once again, we will 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 first year PDP decline. It was in the high 20% on a BOE basis and it was on a oil basis, it was high 30% range. So we'll recalibrate that number in conjunction with our reserve outlook -- reserve report, and our activity outlook for and have the more specific update for you here in February.
Devin McDermott -- Morgan Stanley -- Analyst
Got it. Thank you very much.
Operator
Your next question comes from the line of Neal Dingmann from SunTrust. Your line is open.
Neal Dingmann -- SunTrust -- Analyst
Thanks for taking my call, great update on the Eagle Ford. My question is around that play beyond the 4Q when 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 is more of a, still in the near-term, growth driver or is it more stable production with it, more of a free cash flow generator?
David Harris -- Executive Vice President, Exploration and Production
Neil, 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 where we've regained operational momentum with our partner, we're going to bring on a big package wells in Q4 and then as we move into 2020, we've talked about stabilizing somewhere around a rig count of three to four 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 is still a lot of good work to be done in the play.
David A. Hager -- President and Chief Executive Officer
Now just to reinforce that, what we're finding there is 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 is -- it's just a great resource with a lot of pressure and a lot of opportunities to look out for 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 slick water and we're optimistic that that can compete also.
Neal Dingmann -- SunTrust -- Analyst
Well, certainly sounds like a lot of running room and then moving over to equally is positive, it sounds like to me. I'm looking at slide, particularly on slide 20. In that, you've had some -- it's 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 -- how that's changed now after the success?
David Harris -- Executive Vice President, Exploration and Production
You bet. Yeah, one of the things that we're excited about it 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 talked about in our Atlas West and East area, we have currently -- we've talked about the spacing test at three wells per section. We have plans to test four wells per section spacing. We've seen offset industry participants testing up to six and seven wells per section and so we're going to learn more here throughout 2020 that's going to inform with success, what we believe will be development mode, beginning in 2021 for the Niobrara for us.
Neal Dingmann -- SunTrust -- Analyst
Very good. Thanks for the details, guys.
Operator
Your next question comes from the line of Charles Meade from Johnson Rice. Your line is open.
Charles Meade -- Johnson Rice -- Analyst
Good morning Dave, to 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. As you've given us up this fortune log on '20 and it looks like the [Indecipherable] is more of a classic or carbonate versus I guess, the overall Shale package. Is that the case and does that tie into your spacing there if it just being three or four across a unit?
David A. Hager -- President and Chief Executive Officer
Well, there is 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 [Indecipherable] in the oil window throughout the geologic column here and that varies. So we've done a thermal maturity mapping throughout the basin and that varies and as you go further north with some other operators, you are 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 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 and done [Phonetic] exist in other areas is a little more ductile and done [Phonetic] 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 by else's Niobrara results to 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.
Charles Meade -- Johnson Rice -- Analyst
That's great detail, David. And then if I could go back to your prepared comments about this unfortunate topic of your 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 the national politics are more and more like a demolition derby where wild things happen, and so I wonder if you could talk more about what are the obstacles to implementing in your frac banner or associational permits, and what timeframe that will play out over in your contingency planning?
David A. Hager -- President and Chief Executive Officer
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 it is really fraught with serious legal ramifications, the ability to enact at 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 stage where we work, you know we work in an incredibly environmentally responsible manner, our own company does and our industry does, and all of 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 in the world where there are not as high environmental standards followed. And so we just think of it is obviously going to be impactful, very impactful to the US economy 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 US, it's not good for the world and again I'm not going to go through the details of the legal issues, but we have studied it pretty deeply and we think there is the significant timeframe to do anything from a purely legal standpoint, obviously from a regulatory standpoint, there is 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.
Charles Meade -- Johnson Rice -- Analyst
All right. Thanks, it's very helpful.
David A. Hager -- President and Chief Executive Officer
Well, I mean, 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.
Charles Meade -- Johnson Rice -- Analyst
Got it.
Operator
And your next question comes from the line of Jeffrey Campbell from Tuohy Brothers. Your line is open.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
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 you're Leonard Bone Spring results consistently been successful?
David A. Hager -- President and Chief Executive Officer
I didn't quite catch that. Could you repeat that, Jeffrey, I'm sorry?
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Sure. On slide 17, can you add some color on the drivers of the multi-year capital shift to the Wolfcamp since you're Leonard and Bone Spring results have consistently been so successful?
David Harris -- Executive Vice President, Exploration and Production
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 related to that, the depth of resource and inventory we have in the various landing zones of the Wolfcamp. Those two things combined, I think 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.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Okay, great, that's helpful. And just I'm -- just was wondering if you could quickly give some of the technical differences between an Eagle Ford refrac versus a redevelopment oil?
David Harris -- Executive Vice President, Exploration and Production
Yeah, it's a great question. I've actually asked the team that the lingo is a little bit -- 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 try to few different approaches, but we pump a liner refrac there to go in and restimulate near well bore 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 is redevelopment.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Okay, all right, thanks for the clarity, I appreciate it.
Operator
And your next question comes from the line of Davil -- sorry David Heikkinen from Heikkinen Energy. Your line is open.
David Heikkinen -- Heikkinen Energy -- Analyst
Good morning, guys, thanks for taking the question. I'm kind of thinking through and it seems like given your higher '19 Powder River Basin exit rate and you're shifting more capital to your oilier Powder but definitely shifting less capital to your less oily STACK that you've really got some increased your 2020 oil CAGR in your hip pocket as a kind of flow that through the model. I'm trying to leave the witness to 7% to 9% or higher, but it seems like that the bit of a way up?
David A. Hager -- President and Chief Executive Officer
I don't know. I don't know. [Indecipherable] not a sports analogy but I'm not sure the right one day [Phonetic], it's way up, maybe not, maybe a -- maybe a 15 foot jump shot. [Indecipherable] It's not a long 3-pointer.
David Heikkinen -- Heikkinen Energy -- Analyst
Mr. James Harden
David A. Hager -- President and Chief Executive Officer
There you go, whether that's like our way up. Yes. But I mean obviously and we feel confident, we've exceeded our expectations the last few quarters. So we're -- we feel really good about the ability to execute on that.
David Heikkinen -- Heikkinen Energy -- Analyst
And then just in the STACK, 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?
David A. Hager -- President and Chief Executive Officer
Well there -- there is a, -- I mean I don't have the exact number, the guys will have it for you. But it's typically run higher than it has in any other business units, but the amount of the outside capital has actually [Indecipherable] 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 acreages in those versus non-consent. And so we're trying to get get some return on that as well.
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
Yeah. And David just specifically, we had about $8 million of non-op capital in the third quarter in the STACK. And from a year-to-date perspective it's been about $30 million or so, although we have seen downward pressure on that as Dave highlighted throughout the year.
David Heikkinen -- Heikkinen Energy -- Analyst
Sure, thanks very much.
Operator
And there are no further questions at this time. Mr. Scott Coody, I turn the call back over to you for some closing remarks.
Scott Coody -- Vice President, Investor Relations
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.
Operator
[Operator Closing Remarks]
Duration: 56 minutes
Call participants:
Scott Coody -- Vice President, Investor Relations
David A. Hager -- President and Chief Executive Officer
David Harris -- Executive Vice President, Exploration and Production
Jeff Ritenour -- Executive Vice President and Chief Financial Officer
John Raines -- Vice President, Delaware Basin Business Unit
Arun Jayaram -- JP Morgan -- Analyst
Jeanine Wai -- Barclays -- Analyst
Brian Singer -- Goldman Sachs -- Analyst
Subash Chandra -- Guggenheim Partners -- Analyst
Devin McDermott -- Morgan Stanley -- Analyst
Neal Dingmann -- SunTrust -- Analyst
Charles Meade -- Johnson Rice -- Analyst
Jeffrey Campbell -- Tuohy Brothers -- Analyst
David Heikkinen -- Heikkinen Energy -- Analyst
