Welcome to Devon Energy's second quarter earnings conference call. At this time, all participants are in a listen-only mode. This call is being recorded. I'd now like to turn the call over to Mr. Scott Coody, Vice President of Investor Relations. Sir, you may begin.
Thank you. Good morning. On today's call, I will cover a few preliminary items and then turn the call over to our President and CEO, Dave Hager. Dave will provide his thoughts on the recent performance and strategic direction of New Devon. Following Dave, Tony Vaughn, our Chief Operating Officer, will cover a few operating highlights from the quarter, and then we'll wrap up our prepared remarks with Jeff Ritenour, our Chief Financial Officer. Jeff will cover our financial highlights and outlook for the remainder of 2019. Comments on the call today will contain plans, forecasts, and estimates that are forward-looking statements under U.S. securities law. These comments and answers are subject to a number of assumptions, risks, and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance, and actual results may differ materially.
Following our prepared remarks, we will take your questions, and with that, I'll turn the call over to Dave Hager, our President and CEO.
Thank you, Scott, and good morning, everyone. The second quarter is another outstanding one for the New Devon. Across the portfolio, our teams are delivering results that continue to exceed the production and capital efficiency targets, while successfully driving down per unit costs and maximizing margins. Before we get into details of the quarter, let's begin with a brief overview of what defines New Devon. For those of you that are new to the story, Devon is nearing the completion of its transformation to a U.S. oil growth company, allowing us to focus entirely on our world-class oil assets in the Delaware Basin, Powder River, Eagle Ford, and STACK. The simplification of our portfolio unleashes the potential of our U.S. oil assets, which reside in the very best parts of the best oil plays in all of North America, where we possess a multi-decade inventory of high-return growth opportunities.
With these advantaged attributes, New Devon is positioned to deliver sustainable growth and thrive in today's commodity price environment. This is evidenced by several value-enhancing accomplishments year to date. First, oil growth continues to exceed our plan, and we are now raising our full-year production outlook for the second time this year to a 19% growth rate. This represents a 400-basis point improvement compared to our original budget expectations heading into the year. Importantly, the strong well productivity driving oil growth higher is complemented with a step change in capital efficiency, resulting in a $50 million reduction in our 2019 capital outlook. Keep in mind our 2019 capital budget already had $200 million in efficiencies built in it to it compared to 2018. So far this year, we have brought online 20% more wells for 10% less capital compared to 2018. Any way you slice it, these are outstanding results.
We have also taken action to materially improve our corporate cost structure. Our operating G&A cost savings initiatives are exceeding the plan by a wide margin, and now we're on pace to achieve more than 70% of the $780 million annual savings target by year-end. The impact of this savings plan is massive, with a PV10 benefit over the next decade of more than $4 billion. This is equivalent to roughly 25% of our current enterprise valuation. Coupled with our accretive sale of Canada, we have achieved nearly $3 billion of excess cash inflows this year. With these inflows, we are delivering on our promise to reduce leverage and return capital to shareholders.
In fact, our leverage has now declined by 80% from peak levels, and we have returned more than $4 billion of cash to our shareholders through dividends and buybacks. All in all, it has been a fantastic start to the year as we have executed at a very high level on every single strategic objective underpinning the New Devon. Given the commodity price variability we must navigate through in this space, I firmly believe the investment of appeal of New Devon is further distinguished by our strategic approach to the business. We all know there's been some messy and surprising results in the industry of late, but I want to be clear about our unyielding commitment to excellence, discipline, and consistency of results.
New Devon's financial-driven model is designed to deliver peer-leading returns on invested capital, to generate sustainable cash flow growth and growth rates in cash flow, and to return increasing amounts of cash to shareholders. As you can see from our recent results, this model is working. The key to this progressive and balanced operating model is the quality and multi-basin diversity of New Devon's asset portfolio, which has some of the lowest break-even points in the E&P space. This asset quality and low-cost advantage allows us to build a margin of safety into our operating plans, which is demonstrated by our ability to fully fund our capital program at less than $50 WTI pricing, even after accounting for the recent weakness in gas and NGL strip pricing. With our multi-basin diversity, we have the capability to dynamically allocate capital between opportunities to optimize our rate of return.
This flexibility is evident with our recent redeployment of capital from the STACK to higher return on opportunities in the Delaware and Powder River. Lastly, to provide an additional level of certainty to our operational execution, we are proactively managing commodity risk through an active hedging program and have taken steps to further fortify our balance sheet by aggressively reducing leverage ratios to less than one times net debt to EBITDA. Put another way, our operations are now backstopped by a fortress balance sheet. I want to end my prepared remarks today with a few preliminary thoughts on our outlook for next year. As I mentioned earlier, Devon is trending ahead of plan on all the operational objectives supporting our three-year outlook, and we have significant operating momentum heading into next year.
While it is still a bit too early to provide any detailed targets for 2020, I can tell you based off the trajectory of our business, I expect efficiencies to continue to lower our break-even capital funding levels and to further improve our corporate level returns. Given our low maintenance capital, we have the substantial flexibility to deliver a desirable combination of both free cash flow and highly competitive oil growth rates at today's strip pricing. More specifically at the asset level, we plan to allocate more capital to the Delaware to better leverage the well productivity and capital efficiencies this franchise asset is delivering. We will continue to tailor stack activity to the current commodity price environment. As our planning process firms up, we will provide more specific details on our 2020 outlook this fall.
With that, I will turn the call over to Tony Vaughn, our Chief Operating Officer.
Thank you, and good morning. As Dave touched on, New Devon's operations are hitting on all cylinders, and I am quite pleased with the positive business momentum we continue to demonstrate in the second quarter. Each asset in our portfolio is executing at a very high level, fulfilling its respective role in our portfolio. I am quite proud of the results the organization has generated, and this strong performance is a result of the quality of our people, and they're delivering results. For today, I will focus my comments on our Delaware Basin operations, which are the driving force behind New Devon's growth year to date. Our high margin production in the Delaware continued to rapidly advance in the second quarter, growing 58% on a year-over-year basis.
The key driver of this robust growth is the high impact wells we have consistently brought online that rank among the very best in all of industry. In the first half of the year, we commenced production on more than 50 new wells, diversified among the Leonard, Bone Spring, and Wolfcamp formations that achieved average 30-day rates of around 2,500 BOEs per day. These high impact wells reflect the quality of our underlying asset base, our staff's top-tier planning and operating capabilities, and our willingness to deploy cutting-edge technologies to improve well productivity and capital efficiency in the economic core of this world-class play.
Looking ahead, as we transition more activity to the Wolfcamp, which will account for as much as 65% of our program in coming years, I am confident in making the prediction that our Wolfcamp well productivity and capital efficiency will improve from the impressive baseline we have established this past year. Furthermore, with the substantial amount of acreage trades we have completed in the state line area, our future results will benefit from higher working interest in these high impact operated areas and from less exposure to certain lower returning non-operated activity scattered across the basin. With this world-class leasehold position in the Delaware, our team has successfully transitioned to fulfilled development across a significant portion of our core areas. Our outstanding results year to date are benefiting from the learnings obtained from the appraisal work we performed in prior years.
Through this appraisal activity and our work in other plays across the company, we have a strong understanding of the subsurface that allows us to identify the best landing zones, understand parent-child dynamics, along with the appropriate well density per section, and deploy optimized completion designs to capitalize on that knowledge. Importantly, through this process, we have learned how to better size and scale these projects to optimize capital efficiency and returns. Our go-forward development projects are striking a healthy balance between present value and rate of return, delivering an optimal outcome for shareholders. Overall, as our results indicate, we are well up on the learning curve and are very confident in our Delaware asset. Specifically, in the Wolfcamp formation, which will be our most active target going forward, we have a very good understanding of lateral and vertical connectivity.
We have settled on a development spacing of about four to eight wells per landing zone, depending on the oil column pressure connectivity and the subsurface variability in southeast New Mexico. Our recent success with our Fighting Ochre and Flagler projects are examples of this pragmatic spacing approach and strong returns. Importantly, with our significant acreage position, we have the depth of inventory to deliver top-tier results in the Delaware Basin for many years to come. At today's drilling pace, the currently identified 2,000 higher return risk locations we have identified equate to 16 years of operated inventory. This inventory is a result of a detailed subsurface evaluation across our entire position rather than generalized acreage math.
With a depth of stack pay resource across the Delaware, we expect our high return inventory to continue to expand as we capture additional efficiencies and further delineate the rich geologic column across our entire acreage footprint. I'd like to transition to a storyline that's often overlooked, but critical to our recent success in the Delaware, and that is the work we have performed in the field to improve the profile of our base production decline. So far, year to date, our gross operated base production has outperformed our budgeted expectations by approximately 10%. This dramatic outperformance was accomplished through the use of leading-edge data analytics that has helped minimize downtime in the field. We have also successfully boosted existing well productivity through proactive gas lift and rod pump optimization while reducing maintenance costs.
This thoughtful and innovative work is delivering some of the best returns and value uplift in the portfolio with minimal cost. Lastly, I want to conclude my remarks in the Delaware by highlighting the good work that we have performed to maximize the value of our barrels produced. Beginning with our oil realizations, a major victory for us has been the avoidance of price deducts associated with the new West Texas Light index. We have leveraged our operating scale and acreage dedications in the area to attain multi-year contractual guarantees that ensure we receive Midland WTI pricing with gravity protection up to 60 degree API.
Coupled with the good work of our marketing teams have done in the hedging and firm transport front, our light oil realizations are near WTI pricing levels, and importantly, the regional gas price weakness experienced by the market has been mitigated by our attractive basis swap position. On the cost side of the equation in the Delaware, we have also been able to lower expenses and enhance our margins through the scalable field-level infrastructure our teams have built out over the past several years. This foresight has helped us reduce per-unit LOE cost by more than 60% from peak levels. One of the most meaningful sources of LOE savings is the extensive water infrastructure we have proactively built out. We now have nearly all of our produced water connected to pipes. The infrastructure is fully integrated with eight recycling facilities, 40 operated saltwater disposal wells, and several third-party water systems.
With this infrastructure, we avoid the extremely high expense of trucking in the remote desert of southeast New Mexico that can easily exceed a couple of dollars per barrel and are able to source over 80% of our operational water needs from produced water at very low cost. The bottom line is that the hard work and thoughtful planning from our operations is paying off and our positions allow us to capture additional value per barrel that many of our competitors cannot. With that, I will now turn the call over to Jeff Ritenour.
Thanks, Tony. I'd like to spend a few minutes today discussing the progress we've made advancing our financial strategy and briefly provide context on several key metrics that are improving within the updated 2019 outlook we issued last night. A good place to start today is with our improving financial performance for the quarter. Our operating cash flow increased 23% year-over-year to $623 million. This level of cash flow fully funded our capital requirements and generated nearly $60 million of free cash flow for the quarter. With the free cash flow our business generated, coupled with the proceeds from the sale of Canada, Devon's cash on hand increased to $3.8 billion at the end of June. Subsequent to quarter end, we utilized a portion of this cash on hand to redeem $1.5 billion of low-premium senior notes that were due in 2021 and 2022.
With this redemption activity, Devon has now completely cleared its debt maturity runway until late 2025. Given our strong liquidity, we expect to reduce additional debt in the second half of 2019. We will finalize the size and timing of our debt reduction activity in the near future, but we are well on our way to achieving our debt reduction goal. In addition to debt reduction, another key financial priority is our ongoing share repurchase program, which is the largest program by a wide margin in the E&P space. Since the program began in 2018, we have repurchased 125 million shares at a total cost of $4.4 billion, and we are on pace to reduce our outstanding share count by nearly 30% by year end.
To advance our share repurchase activity in the second half of 2019, we expect to utilize cash on hand to reach our goal of $5 billion by year end. Any upside from higher commodity prices or asset sales would be earmarked for additional return of capital to shareholders. I'll wrap up my comments today by covering a few key guidance items from our updated 2019 outlook. This updated outlook reflects the improvements of our retained businesses achieved year to date and incorporates the impact of Canada's restatement to discontinued operations. On the production front, as Dave touched on earlier, our light oil growth is running at least 400 basis points ahead of our original budgeted expectations. For the second half of the year, we expect the strongest oil growth to occur in the fourth quarter, driven by the timing of activity in the Delaware.
This production profile positions us with strong volume momentum heading into 2020. Importantly, we're delivering this incremental oil growth with better than expected well productivity and capital efficiency. Because of this positive trend, we are lowering the midpoint of our capital spending outlook in 2019 by $50 million to a range of $1.8 billion-$1.9 billion. We also continue to make substantial progress on the cost reduction front. With the scalable growth we are achieving in the Delaware and the Powder River, coupled with the benefits of Canada exiting the portfolio, we project total company per unit LOE cost to improve 15% versus our original budget. Our G&A initiatives have also delivered a steady cadence of successful cost reductions year to date.
We estimate that we have captured approximately $190 million of overhead savings to date on a run rate basis, and this momentum is projected to reduce G&A by more than 15% versus our original budget. With the progress we've made year-to-date, we are well on our way to attaining more than 70% of our $300 million three-year savings goal by the end of 2019. Shifting to interest expense, with the $1.5 billion debt redemption we completed at the end of July, we are lowering our net financing cost forecast by approximately $50 million to a range of $250 million-$270 million. All in all, we are executing at a very high level on the key financial objectives underpinning our three-year plan. We have significant operational momentum heading into 2020, and we are positioned to deliver free cash flow and attractive growth.
With that, I'll turn the call back over to Scott for Q&A.
Thanks. Thanks, Jeff. We will now open the call to Q&A. Please limit yourself to one question and a follow-up. If you have further questions, you can re-prompt as time permits. With that, operator, we'll take our first question.
Thank you. At this time, I would like to remind everyone, in order to ask a question, press star, then the number one on your telephone keypad. We'll pause for just a moment to compile a Q&A roster. Our first question comes from the line of Arun Jayaram from J.P. Morgan. Your line is open.
Yeah. Good morning. You mentioned that you're now in, call it pure development mode in the Delaware Basin. I just wonder if you could talk about some of the implications for capital efficiency. I perceive that your capital efficiency is improving, but maybe give us some more details on what's going on there. Also maybe you could shed some light on the acreage. Ted's surprised that you could get some acreage in that neck of the woods in Todd, which has been really a productive rock.
Morning, Arun. This is Dave. I'm going to start off with just a summary comment here, and then we'll turn it over to John Raines, who is our Delaware Basin Vice President of that business unit, to give some detailed comments about what you asked. I think that you hit on one of the key elements about New Devon that we have to continue to emphasize, is that in the Delaware Basin, and in most of our plays, we have moved out of an era where we're doing quite a bit of appraisal work and moving into a much higher percentage that's pure development work. That leads to increased capital efficiency, a lowering of the well cost, drilling the best wells in the best zones, higher rates. It also obviously allows us to lower the well cost as we have consistent capital or consistent rigs in the same area.
You see higher quality results, and you see very consistent results. We've demonstrated that clearly with the first two quarters of results in 2019, and we will continue to deliver on that in the future. With that, I'll turn it over to John to answer more details about what that means.
Yeah, this is John. Thanks, Arun, for the question. It's a good one. It's a story I'm pretty excited to tell. I think to properly tell the story, I'll take you a little bit back to 2018. If you go back to 2018, specifically with respect to our Wolfcamp, we really leaned in on developing two-mile laterals. When we did that, we had a lot of learnings from these two-mile laterals. I'll talk about some of those specifically. On drilling, and as you noted in the ops report, we've improved our performance by 20% on drilled feet per day. These improvements are largely driven by moving away from a pure slim hole design to a slightly larger hole in casing sizes. The result has seen better tool reliability, better ROP or rate of penetration, and significantly reduced NPT.
On completions, as noted, we've seen about a 40% improvement in feet per day. The real driver here is much more consistent work with our dedicated frack crews, and we've also engineered certain more prevalent problems out of the system. To date, we've seen fewer horsepower, wire line, toe sleeve issues that again, were much more prevalent in the past, and this has significantly reduced our NPT. I'd also note on completions that we've reduced our flat time. Our flat time is essentially the time it takes to swap wells on a zipper job or to rig up and rig down. To say that differently, we've basically substantially improved our on-site logistics. Finally, for facilities, we've successfully deployed our first standardized train design on our Flagler project. Versus our 2018 baseline, this project delivered facilities at a per well cost of roughly 50% versus our baseline.
This new design's really brought some much needed standardization to our facilities. The simpler design has resulted in less equipment and associated costs, much lower construction costs, and other supply chain savings. I'd say if you had to look at our total costs, in addition to just the cycle times we've mentioned in our operations report. By year-end, we feel pretty good that we're going to be able to reduce our non-Wolfcamp wells 10%-15% total, and that does include some larger completion designs on some of those wells. If we look at Wolfcamp, we're really striving towards a 15%-20% type of reduction. Very proud of the work that the team's done there.
Acreage trades?
Yeah, Arun, I think your second question was around acreage trades, and I bet you're more specifically referring to the 5,500 acres at Todd. This is also a pretty fun story to tell, and I think it shows how much success you can create by having a really intentional effort. The 5,500 acres, again, to go back in time, has to be considered as a multi-year effort.
If you really go back to the Todd area, this was an area that the team identified early on as being a good ZIP code. I think I've referred to the parent boundary Rader well being drilled several years ago, even on a previous call. It was really at that point that the team got pretty creative about consolidating our position here and upping our working interest. As for the 5,500 acres itself, this is really a product of the team being creative and the land team in particular, being able to execute on our consolidation strategy. This acreage did not come to Devon via one or two large deals. Rather, this acreage came to Devon over the course of three years and over the course of more than a dozen trades. These trades ranged in size from as small as 40 acres to as large as 2,000 acres.
You can see that the team's really been effective in the hand-to-hand combat out here.
Great. Just my follow-up is, you guys had put out previously, called it a 12%-17%, I believe, oil growth target from the New Devon properties. This morning or last night, you highlighted more capital going to the Delaware from the STACK. I was just wondering if you could maybe give us a little bit more thoughts on initially how you're thinking about how much capital would shift from the Delaware. Is it a rig line or two, or just maybe some broad thoughts on that?
Well, we're still working through the details of that, Arun, we're doing a lot of modeling work on our 2020 capital program to determine what provides the optimum efficiencies. In my comments, I did directionally guide that Delaware capital will continue to increase in 2020, obviously rightfully so, when you see the outstanding results that we're delivering there. We're delivering good results, by the way, in other parts of our portfolios. Not that others are failing, it's just that this is succeeding so well, and that's why we're able to increase our production guidance and lower our capital guidance. I can't give you specifics at this point. We're continuing to look at various scenarios, obviously, it's a great place to be.
We're getting even more capital efficiencies than you originally estimated to think about what the options you have when it comes to our 2020 capital program.
Great. Thanks a lot, Dave.
Our next question comes from the line of Doug Leggate from Bank of America. Your line is open.
Thank you. Good morning, everybody. Dave, I'm not sure who wants to take this one, but just looking at the cash margin disclosure that you've given us, which is obviously very helpful. The highest margin in the portfolio right now is in the Powder River. I'm wondering if you can just give us an update there as to how that translates to returns at the well level, because obviously embryonic play, one assumes the well costs are still being optimized. Just discuss how you see the evolution of that play as it relates to the risked inventory and just how relative incremental capital allocation might evolve towards the Powder over time.
Yeah, you're right, Doug, good morning. The Powder has the highest oil % of any of the plays that we're involved in, that play does have very high margins associated with it. Obviously, it's very sensitive then to oil prices, the returns that you generate on that play. We're extremely pleased with the results that we're getting so far in the Powder. We've now entered into the full development mode on the low-risk Turner play. That will constitute the bulk of the growth that we're going to realize over the next three years. We're excited as well about the Niobrara. We have not said too much about our first Niobrara well. We're just flowing that well back at this point, but so far so good, I would say.
One thing to be cautious about, by the way, on the Niobrara is, what you really can't compare our Niobrara to other industry players' Niobrara out there. From a thermal maturity standpoint, we are in the heart of the oil window throughout the geologic column, including the Niobrara on our acreage, and that is not the case for some of the other industry players that have a much more gassy content to the Niobrara. We're excited, although again, that's the smaller part of our overall growth story over the next three years. The returns are very competitive with those in the rest of the portfolio, and that's why we have four rigs working out there right now.
Just on the risked inventory, Dave, what would you say is the current gross inventory, if you like, versus the, I guess, eight or 900 locations that you've identified to date?
I'm going to turn that over to Wade Hutchins to give you the inventory number.
Good morning, Doug. As you see in our main inventory disclosure slide, the high-quality risked inventory for the Rockies is sitting at about 650 gross operated wells. Again, I'd just remind you, on all of that inventory, we've stripped out any non-operated locations, and we've also stripped out any unrisked locations, and we've just focused in on those locations that we think we can drive high-quality returns on. The inventory is a balance between all of those targets that Dave noted a moment ago, including some very high return Parkman and Teapot locations. When you look at it from an unrisked basis, the numbers obviously get a lot bigger. Those are very preliminary risked high-quality locations. When we look at it from a total unrisked basis, we see several thousand Rockies-operated locations as potential.
Again, we're in the middle of trying to unlock that today with some of the appraisal work we're doing in the Niobrara. We would note also there's several other prospective targets that other companies are testing. We're watching that very closely as well.
I appreciate the answers, guys. My follow-up hopefully is a quick one, Dave. Just the reallocation of capital from the STACK, and I guess the Eagle Ford is back to seeing some activity, it seems. Can you just clarify, should we think about these assets just as ex-growth or absolute decline, particularly in the STACK? On a similar context, just what are the triggers that might cause you to change activity levels if oil stays under pressure?
Doug, and for everyone, I think it's important to understand that we really have a dynamic capital allocation model, and what that means is that we really look at what are generating the highest returns throughout our portfolio, and we obviously take into account commodity prices when we make that decision. We have the ability, with the inventory levels that we have, to grow any of the assets if we so choose. But we don't think about it so much about whether or not we are growing an individual asset or not. We allocate our capital to what we consider to be the highest return opportunities, and then the growth is an output of that, given where we think we're getting the highest returns.
If we were less dynamic, frankly, with our capital, we could allocate it more proportionate to all of our plays so that they all grow, because we have the inventory to do that. We don't think that's the way to optimize the value of the company. With this, obviously, we've had some weakness in natural gas and NGL prices here. With that, we've made the decision to reduce the activity somewhat in the STACK and to reallocate that capital out to the Delaware and the Rockies, given the higher returns at this point.
Appreciate the answers, Dave. Thanks a lot for your time.
Thank you.
Our next question comes from the line of Jeanine Wai from Barclays. Your line is open.
Hi, good morning, everyone.
Good morning, Jeanine.
Morning. My first question is on capital allocation. Can you just discuss how you weighed whether to reallocate that $50 million in STACK CapEx versus just taking it out of the schedule and reducing the 2019 budget by $100 million instead of $50 million? I know it's a pretty small amount, but there's a lot of good things going on. You're on track to meet or exceed your oil production targets. You raised oil guide already twice this year. You've got the three-year plan that already has a competitive growth rate. I guess one can argue that the market's not paying for growth, but for discipline. I just wanted to understand how you're thinking about this, because I know spreadsheet math is different from how things work operationally.
Well, I'm glad you appreciate that. Yeah, I think you could make the argument, frankly, not just about that $50 million, but you can make the argument about capital in general. As to what the right levels of capital are in the program. We did it to optimize the capital efficiencies that we have in both the Delaware and the Powder River Basin to optimize returns. It's to optimize the interplay between drilling rigs and completion crews, and to maximize the efficiency between those. We felt that that was going to maximize the returns and the right decision to do. I think it's a totally separate discussion that you could ask of us or everyone else, every other E&P company, is what the right level of capital allocation is, and what's the right mix of competitive free cash flow yield and growth.
Certainly, we think we're in a position to deliver on both of those, and that's certainly what we're looking at going forward into 2020.
Okay, great. That's very helpful. Thank you. My second question, in terms of next year, I know you're not giving any detailed guidance or anything right now, but can you talk about generally what your appetite is for activity in the STACK if strip pricing holds? I'm pretty sure this isn't a target, but how much activity is required just to hold that asset flat these days? Are there any overriding considerations in terms of having to maintain a specific minimal amount of activity in the play? It's pretty mature, so I'm guessing there's no real HBP requirements or anything, but you might have some other transport agreements or something.
No. There's no firm transportation that drives that capital allocation. There's no held by production issues at all. It is simply optimizing returns. Again, it's optimizing returns across the entire portfolio. We are currently having the bulk of our activity in what we call the volatile oil portion of the play. Those returns, and on our revised type curve that we put out previously, we're meeting or exceeding those, and we're driving down the cost of those wells extremely efficiently. Those returns compete for capital with everything else in the portfolio. Obviously, as we move outside of that in future years, more into what would be considered the gas condensate window and even perhaps the dry gas window, the resource is there. The resource is very strong and the opportunities are there.
With the recent weakness in natural gas liquids and natural gas prices, that's why we reallocated the $50 million out, and we're looking very closely at any activity outside of that, and considering whether we want to bring in joint venture partners on a small or a larger scale to help us with any activity there to really dramatically increase our capital efficiency and make those opportunities compete for capital.
Okay, great. That's very helpful. Thank you very much.
Thank you.
Our next question comes from the line of Paul Grigel from Macquarie. Your line is open.
Hi, good morning. Going back to the commentary on the base decline mitigation was interesting. I was wondering if you could talk about further upside that might be seen through that, if that's being applied to other plays within the portfolio, and then maybe the overall impact to the corporate decline rates that could have, either initially or over time.
Yeah, Paul, that's an area of focus that we've put in the company probably about four or five years ago. I think over time, we've described our commitment to being data-driven. During that process, we've installed automation in virtually all of our producing assets across the portfolio. We have what we call decision support centers in each of our producing areas. They're manned 24/7, generally. They're the source of all this data-driven work. We're actually now having the ability to look at information on all of our artificial lift equipment, and we can spot pending trouble on some of our artificial lift pumps and gas lift operations. We have the ability to predict failure as opposed to just running towards failure. We have the ability to bring the replacement pumps to location, have the crews available and ready to go before wells actually go offline.
The guys have done a really good job of incorporating this thought process across the organization. You heard us talk a little bit or describe what is going on and the good work that the Delaware Basin team is doing. A lot of that same work is happening across the other areas as well. We think it's material to the business. As John described, having 10% uplift in our base operations with virtually very little cost associated with that is an increment I'm not sure all companies appreciate and then focus on. Appreciate your interest in that as well. It's good quality work by our operating people.
Definitely an interesting topic. Then I guess maybe changing a little bit to 2020 and just the capital efficiency that Dave, you mentioned earlier. As you guys look going forward, on 1Q, you were very clear that you would not outspend capital this year, and that's clear in the reduction. As we move to 2020 with ongoing capital efficiencies, what are some of the sources that you guys see for additional upside that you can drive either on the capital side or on the operating cost side into 2020?
Well, obviously, as we move into full development mode, we are going to continue to drive down the costs on the capital side. I think John Raines already outlined of how he sees additional cost improvement in the Wolfcamp. I would anticipate that we are going to see drilling and completion cost improvement throughout the portfolio, because when you're in full development mode, it's just by nature that you get better and better as you do more repetitive type activities. I would anticipate that you would see that even more.
Tony, I don't know if you want to answer a little bit on the LOE side, but I think one of the good news things I can add, steal your thunder a little bit, is a lot of our infrastructure is in place, and so we are able to add barrels with very little incremental cost because of all the vast majority of the infrastructure is already in place for once we increase our production.
Yeah, I think that's right, Dave. I think it even goes back prior to that, is we've been very committed to building contiguous acreage positions in all of our core areas of being in the heart of the play.
While that is just background work, John described a little bit of that in the Delaware Basin, but we've done a really good job of coring up our operations in all the areas that we work. That was purposeful. It allows us to build a more integrated infrastructure system there. We're continuing to optimize our drilling work and showing some great work there. You see hints of that across our operating report that we've published, where the drillers are reducing drill times. They're doing that through new design work that they're doing and less trouble time than we've had in the past. We're also in the process of seeing a lot of technology and innovation on the completion side of the business.
We're tending to stretch out our stages, reduce volumes, increase the number of clusters, and we've even got technical guys that are working on very detailed work on the size and placement of perforations. That is ability for our guys to both manage cost and deliver probably some of the best returns in the industry, as shown in one of our exhibits. There's continuing to be a lot of very thoughtful technical work across the business. We're also doing this on the facility design work. We're standardizing and modularizing all of our equipment there. In almost every component of our operations, we're seeing some really thoughtful, granular work that's delivering the last couple of quarters outperformance that I think you're seeing there.
Coupled with that, we have a supply chain group that is doing some really good quality work. I'm not sure, Jeff, you may want to describe a little bit about the.
Tony, I was going to add some commentary on top of all the great operational things that Tony highlighted that the teams are working and the efficiencies that we're gaining. On top of that, as you look forward to 2020 and 2021, the supply chain group, along with our operations teams, have done a great job of driving down price on the services that we're procuring. In fact, we're working in a deflationary environment at the moment and expect that to continue for the second half of this year. That's going to be a nice tailwind for us potentially as we move into 2020 and 2021 relative to the expectations that we had for our three-year plan initially.
No, that's helpful. I just want to clarify one real fast, excuse me. On development mode, is there any risk to lumpiness on production, or is it sufficiently spread out?
A little bit. It looks like we're going to have a really strong Q4, and that's going to be based on a slightly higher capital spend than we have in Q3. That's going to drive really high production there. The only concern I've seen from a couple reports is, well, does that drive down our 2020? I guess I'd be willing to prepare a little spreadsheet for anybody why bringing on production a month early is a good thing if that's what ends up happening, and I don't get too worried about whether it comes on in December or January, quite frankly. I don't think it's a big value driver. Anyway, we do anticipate a very strong end of the year that's going to give us a lot of operational momentum as we go into 2020.
Fair enough. Thank you very much.
Our next question comes from the line of Bob Brackett from Bernstein Research. Your line is open.
Yeah. At the beginning of your prepared comments, you mentioned a low maintenance capital. Could you talk about what the maintenance CapEx is and what that base decline that it correlates to is?
Yeah. The maintenance capital is about $1.4 billion, and that's a maintenance capital essentially to keep EBITDA flat. The base decline on the assets overall is in about the low 30s, a little bit higher on the oil side of the business that factors into that.
Great. Thanks for that.
Thank you.
Our next question comes from the line of Ryan Todd from Simmons Energy. Your line is open.
Good. Thanks. Maybe one on cash return. You've chopped a lot of wood over the last couple of years on debt reduction and buyback. As you reach the end of the near-term targets you've given on those two programs towards the end of this year, looking forward, how does dividend growth compete going forward? How important of a factor do you view the potential for dividend growth in terms of long-term investability by the market?
Hey, Ryan. This is Jeff. Yeah, I appreciate the question. Absolutely, the dividend's a critical tool that we're utilizing to return cash to shareholders. We've done that for some time. We've had nice growth in the dividend. As you've heard us talk about our kind of dividend policy that we discussed with the board, our thought process really centers around a payout ratio. We've kind of designed the dividend to be a 5%-10% payout ratio relative to our cash flow from operations. We think that that's competitive with our peer group. We want to make sure that, number 1, we can sustain the dividend on a go-forward basis, and then, of course, grow it from there.
As to the extent that we execute as we've talked about on our share repurchase program the remainder of this year, and the debt reduction targets that we've outlined as well, we'll certainly go back and discuss with the board at the end of this year what the opportunity is to do additional share repurchases and think about additional dividend growth and those two concepts together.
Great. Thanks. Maybe just a quick one. I know the data room's open. Any comments you can make on the initial level of interest that you're seeing in the Barnett, and whether it's likely to go as a single package or potentially multiples?
Hey, Ryan, this is Jeff again. I'm just going to introduce David Harris, who leads our business development and A&D group, and he can give you some color on the process there.
Thanks.
Good morning, Ryan. This is David. Thanks for your question. Yeah, the data room process has been really active. I think the one thing I would highlight to you is it is a much deeper and broader mix of participants compared to what we saw recently on our Canadian process. As we've indicated, we expect to get bids by the end of the third quarter. I'll remind you, these are attractive low decline assets with access to premium Gulf Coast pricing. We've really seen a lot of interest from the market participants given those attributes.
Okay. Thank you.
In terms of your second question on is it likely to go as a single package, obviously we're open to whatever maximizes value for our shareholders. Given the operating synergies across the asset base and how blocky it is, I think it's more likely to be attractive to a buyer as a single package.
That's helpful. Thanks.
Our next question comes from the line of Neal Dingmann from SunTrust. Your line is open.
Morning. My question sort of tags on what they were just asking. You all certainly have done a lot for shareholder returns here, not only in the near term, but the last several quarters. My question would be, does this market continue to stay irrational as it is? I'm just wondering how do you balance, do you re-up the shareholder buyback program, or how do you balance that versus the growth program that you're outlining?
Well, we are going to stick to I think the overall message, first and foremost, is that we are executing from an operational perspective at a very high level. We are going to continue to stick to that plan, and we're very confident that that execution is going to continue.
We think that we have the asset base and the cost structure that we can deliver both, that we can deliver free cash flow yield that's competitive, not only within the space but within other industrial companies, while still delivering significant growth. We are planning, and our plans are based on delivering both of those. With that overall thought, that's part of the work that we're doing in regards to 2020 and beyond, is what is the optimum level to ensure that we deliver on those metrics. The good news is, with our low breakevens, the continued increase in capital efficiency, the continued reduction of the cost structure, and the growth in revenue that's going to come as we grow our light oil production, we think we're as well-positioned as just about any company out there in the space to deliver on that.
No, great answer. Just one follow-up. Around the reallocation of your MidCons to Delaware and the PRB, I'm just wondering, are there factors that you foresee in the MidCon that would cause you to bring some capital back to that play? Is it just, you mentioned about just you're certainly return driven. Do you envision that Delaware and PRB just continuing to have higher returns?
Well, I think currently, again, to emphasize that the current activity we have going on in the volatile oil window is competitive right now. It's as we move out of the volatile oil window in the future, are those returns going to compete? Certainly in the weaker natural gas and NGL market on a ground floor basis right now, that they're going to struggle to compete for capital as well as with the other plays. As I also have mentioned, and we're not being too specific here, we just can't, that we see opportunities because of our strong acreage position, that there are opportunities on both a small and perhaps even larger scale to bring in capital to that play to make those economics competitive, that we would have activity outside the volatile oil window that would take advantage of these partner joint venture type opportunities.
That's great details. Thanks so much.
Yep.
Our final question today comes from the line of David Heikkinen from Heikkinen Energy Advisors. Your line is open.
Morning, guys. Congratulations on the process and progress. I've been thinking about clear and simple communications for investors a lot, and I was thinking through, why don't you all just say something simple like, "As we reduce our interest cost, we'll transfer those savings to our shareholders through an increased dividend." Just imagine the immediate capitalization of $60 million of interest from the quarter into your stock through that increase in dividends. As you move forward with your plans on cost reduction, it would just be a very simple method for people to understand where you're going.
Yeah, David, this is Jeff. I guess my commentary would be is that we believe we are delivering a pretty simple message, which we've been pretty clear. We're generating cost savings, whether it's on the interest side or on the operating cost side, and the capital efficiencies that we're delivering on the operational side, that's ultimately generating the free cash flow that we projected in our three-year plan. The mechanism that we're returning that to shareholders is through both the dividend and the share repurchase. We think that's important to have a balance there. Obviously, our first priority has been to get the leverage down to a level that we felt comfortable with. We're going to get that accomplished, obviously, here over the next six to nine months.
Beyond that, to the extent that we're generating the free cash flow that we expect, we'll deliver that in the form of share repurchases and the dividend. Again, I guess I would just say we feel like we have a pretty clear message on that front. We've done over $4.4 billion of share repurchase to date and grown the dividend in the last year. Clearly that cash flow is going back to shareholders.
Yeah, I guess that optionality in the group is one thing that we hear a lot, and optionality leads to some uncertainty, is all I'd close with. I appreciate the understanding in what you all are doing.
We have no further questions in queue. I'll turn the call back to our presenters for closing remarks.
Well, thank you. I appreciate everyone's interest in Devon today. If there's any other questions, obviously the IR team will be around all day long, so feel free to reach out to us, and we'll do what we can to help you out. Thank you once again for your time today.
This concludes today's conference call. You may now disconnect.