Welcome to Devon Energy's fourth quarter and full year 2018 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 Petty, Vice President of Investor Relations. Sir, you may begin.
Thank you, and good morning. For the call today, we have slides to supplement our prepared remarks. Our slides for the call, along with our press release and detailed operations report are available on our website. Some of our 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. With that, I'll turn the call over to Dave Hager, our President and CEO.
Thank you, and good morning, everyone. I am very excited to talk to you today about our announcement last night to complete Devon's transformation to a high-return U.S. oil growth company. Before we get started, I want to take a few minutes to set the stage for today's discussion. Today, we are unveiling a new Devon. We've been signaling strongly to the market for some time that when our U.S. oil assets achieve operating scale, exiting Canada and the Barnett is our path forward. What we present to you today is a culmination of an exhaustive strategic and operational review. The results, we believe, will put Devon in a position to become a consistent upper-echelon performer, driving durable improvements in shareholder value. We have the assets, and we have the team to do this. In short, we are aggressively reshaping Devon to win, and we will win.
Turning to Slide 2, this transformational move is consistent with our long-term strategic plan and will allow the company to focus on its world-class oil assets in the Delaware Basin, STACK, Eagle Ford, and Powder River Basin. To accomplish this portfolio simplification, our board of directors has authorized us to pursue strategic alternatives to separate the Canadian and Barnett Shale assets from our retained U.S. oil business. We have hired advisors and are evaluating multiple methods of separation for these assets, including a potential sale or spin-off, and we expect to complete this separation process by the end of 2019. Additionally, with Devon's narrowed focus on the U.S. oil business, we are committed to transforming our culture and cost structure to compete head-to-head with the best in the business.
We are acting with a sense of urgency to materially improve our entire cost structure by delivering at least $780 million in sustainable annual cost savings. With our go-forward business in position to generate substantial amounts of free cash flow at today's pricing, I am also excited to announce that we are advancing our shareholder return initiatives by upsizing our industry-leading share repurchase program to $5 billion and increasing our quarterly dividend payment by 13%. Turning to Slide 3, this exhibit showcases our transformation from a diversified worldwide company to a highly focused U.S. oil producer today. The key takeaway here is that we have an extensive track record of successfully executing on our portfolio simplification initiatives with more than $30 billion of asset sales over the last decade. The strategic rationale for taking this final step in our transformation and our announcement today is quite simple.
With our U.S. oil business reaching sufficient operating scale to deliver advantaged returns, sustainable long-term growth, and the generation of free cash flow, the timing is now appropriate to accelerate value creation for our shareholders by exiting our Canadian and Barnett Shale positions. As you can see on Slide 4, the simplification of our portfolio unleashed the potential of our U.S. oil assets, which possess scale and reside in the very best plays and the best parts of the best plays in the U.S. To be clear, the information laid out here is for our go-forward business and represents the results of our four retained oil basins. The charts exclude results from Canada and the Barnett, along with minor non-core assets for sale in the U.S., but exclude the benefits of cost-saving targets.
It is these world-class oil positions with low breakevens, which provide new Devon the flexibility to generate free cash flow and deliver sustainable long-term growth. This is evidenced by the chart at the top of the slide that showcases our top-tier well productivity. On initial 90-day production rates, our average well has exceeded virtually every top competitor in the U.S. Everyone likes to highlight their best wells, and we do it too. However, this slide captures every well for Devon and peers. This is true transparency. Devon is right at the top, even including a year when we faced challenges optimizing spacing in our STACK play. Just think about it. If we're the top even with the STACK challenges we faced in 2018, I wonder what happened to everyone below us. This good news story does not end with well productivity.
As you can see on the bottom of the slide, new Devon's streamlined U.S. oil portfolio will also deliver substantially improved oil rates, a lower per-unit cost structure, and higher operating margins that will translate into superior returns on capital employed. Moving to slide five. While our U.S. oil assets have many advantage characteristics, we are not finished improving our business. We are aggressively reshaping our organization with a singular focus on our simplified U.S. oil portfolio to unlock the potential of new Devon. As you can see on the top left chart, we expect our U.S. oil business to achieve at least $780 million in sustainable annual cost savings by 2021 versus our 2018 baseline. Our cost reduction plan includes a range of actions to achieve more efficient field level operations, lower drilling and completion costs, and better alignment of personnel with the go-forward business.
To be clear, these are lower drilling and completion costs are structural, the 2019 plan assumes flat year-over-year service and supply costs. To the extent we see deflation in service and supply costs, that would be additive to the plan. Importantly, we are acting with a sense of urgency on these initiatives, we are already executing on plans to achieve at least 70% of these cost reductions this year. Our efforts to reduce costs go beyond just dollars and cents and represent a meaningful shift in our culture to more streamlined leadership, more reliance on technical expertise, and an intense focus on delivering top-tier returns on our investment. The value creation of these changes are material and impactful for our shareholders, equating to a PV-10 over the next 10 years of approximately $4.5 billion or more than $10 per share. Turning to slide six.
In addition to higher asset quality and an improved cost structure, Devon's unwavering commitment to a disciplined returns-oriented growth strategy will drive additional value creation for our shareholders. As we have highlighted in the past, the leadership team at Devon fundamentally believes that a steadier and more measured investment program through all cycles is the best path to optimize corporate-level returns, sustainably grow our business, and generate free cash flow and reward our shareholders with increased amounts of cash returns. Importantly, this disciplined approach to the business will allow Devon to achieve all our capital allocation priorities at a flat $46 WTI price deck while delivering a mid-teens growth rate in light oil production. To be clear, this includes all of our capital expenditures, not just some of our capital, as suggested by others in the industry in their definition of free cash flow within recent presentations.
Inclusive of all capital and recurring expenses, Devon is poised to grow oil at a mid-teens rate within cash flow at $46 WTI. The benefits of higher commodity prices above $46 oil will drive higher levels of free cash flow for Devon shareholders, not higher capital activity. Let's run through some of the operational highlights and specifics of the 2019 program. As we look ahead to 2019, on slide seven, we expect our disciplined growth strategy to deliver strong results. For new Devon, we plan to invest approximately $1.9 billion of E&P capital, with half of this capital concentrated on low-risk developments in the economic core of our world-class Delaware Basin assets. The other half of our capital will be evenly split between high return, low risk oil projects in the STACK, Eagle Ford, and Powder River Basin.
Well over 90% of our capital is focused on low-risk development, we will strategically allocate capital to mature our upside opportunities in the Niobrara, Austin Chalk, and other key plays. The capital efficiency associated with this plan is fantastic, allowing us to drill 15% more wells compared to 2018 for roughly 10% less capital investment. Key drivers of this improved capital efficiency are substantially lower facility costs across our retained U.S. asset portfolio, improved cycle times associated with our Wolfcamp program in the Delaware, an optimized upspace development program in the STACK, a dedicated frack crew in the Powder River Basin. To reemphasize what I noted on the previous slide, all of new Devon's capital requirements in 2019 are funded within operating cash flow at $46 WTI pricing, assuming flat service and supply costs versus 2018. Turning to slide eight.
This level of capital investment is expected to drive light oil production growth for New Devon of 13%-18% in 2019. The trajectory of New Devon's oil production profile is expected to steadily advance throughout the year and exit 2019 at rates more than 20% higher than the 2018 average. Coupled with our share repurchase program that is on pace to reduce our share count by nearly 30%, Devon is positioned to deliver some of the most advantaged per share growth rates in the industry. Our 2019 business outlook is very strong, we will build upon that success in the future by expanding profitability and improving the return that Devon is capable of delivering on a multi-year basis. On Slide nine, we lay out multi-year targets, which highlight the peer-leading capital efficiency of the company. It really highlights what New Devon can deliver.
We expect capital requirements for the next three years to be fully funded with an operating cash flow at a $46 WTI price point, while growing our light oil production by around 12%-17% per year over the same time period. A direct result of our disciplined returns-based growth strategy at $55 WTI, which is near the current strip pricing, New Devon will generate a cumulative free cash flow of $1.6 billion through 2021. The profitability of our barrels will be enhanced through the aggressive improvement of our cost structure, which is expected to yield at least $780 million of annualized savings. From a balance sheet perspective, New Devon will maintain a low leverage profile by targeting a debt-to-EBITDA ratio of 1.0-1.5 times. Slide 10 outlines the free cash flow our business is capable of delivering at various pricing points.
I've already emphasized, this plan is designed to completely fund our three-year capital requirements at an ultra-low WTI breakeven price of $46, while providing an attractive mid-teens growth rate. As I touched on the previous slide, at today's 36-month strip pricing around $55 WTI pricing, the New Devon is capable of delivering a three-year cumulative free cash flow of $1.6 billion. This is equivalent to nearly 15% of our market capitalization at today's share price, represents a very competitive free cash flow yield to investors, while still providing an attractive oil production growth rate. This measure of free cash flow yield includes the cash flow from New Devon only and isn't adjusted for the cash flow or value of Canada, the Barnett, or other minor U.S. non-core assets for sale. I will quickly cover a few operating highlights from the fourth quarter.
Slide 11 highlights the impressive momentum in the Delaware. Oil production is up 49% year-over-year and has already advanced another 14% in January compared to the fourth quarter. Our well results continue to improve sequentially, reflecting the quality and depth of inventory across our large acreage position in the economic heart of the basin. This will continue into 2019 with our focused Wolfcamp program and an additional development into Bone Spring, near our basin-leading Boundary Raider wells. Slide 12 outlines the substantial progress we have made optimizing infill spacing developments in the STACK. The success of our outspace development drove oil production 9% higher in the quarter versus the third quarter. Important as the strong rates are the significant capital efficiencies in these infill developments.
The drilling and completion costs of our infill wells are coming in at approximately 30% lower than the parent wells, a positive step change in capital efficiency. The improved capital efficiency will help STACK generate free cash flow of around $300 million in 2019 at today's prices. Slide 13 covers the Eagle Ford, where we expect to add a third rig in 2019. Beyond the prolific Lower Eagle Ford wells that have driven our development program in previous years, an important program for us this year is our Austin Chalk appraisal. Our five-well program, along with industry-leading offset activity, could de-risk more than 200 locations. With regard to 2018 results, this asset continued to perform at a very high level, contributing more than $515 million of free cash flow.
For the quarter, our positive results were driven by 15 Lower Eagle Ford wells, averaging 30-day IPs of 3,700 BOE per day, highlighting the quality of the position. Slide 14 provides an update on the Powder River Basin, where we enter 2019 with significant momentum. January oil production rates are up 25% versus the fourth quarter. Importantly, we expect this momentum to continue as we double our activity levels in 2019 to four rigs and have a dedicated frack crew. The expected 2019 exit-to-exit oil growth rate for this emerging opportunities is greater than 50%. The program will prioritize the Turner. We will also advance the Niobrara program, building on the early success seen in 2018. Turning to Slide 15, Devon's differentiated investment story only gets better. We believe our top-tier U.S. oil business trades at a substantial discount to comparable high-quality peers on a number of metrics.
We have included a simple comparison on an enterprise value to EBITDA basis to demonstrate this point. As you can see, the analysis implies New Devon trades at a very attractive valuation and suggests investors have further upside with the separation of our Canadian, Barnett, and other marketed assets. Bottom line is that we see a tremendous investment opportunity in Devon, and we have put our money where our mouth is by aggressively buying back our stock over the past year.Devon represents a unique value proposition in the E&P sector that is recognized by the company, and our board has authorized another increase to our share repurchase authorization to $5 billion. We will be actively buying back shares at this attractive valuation. In summary, why should you own Devon? First, core-of-the-core positions in the best U.S. oil plays. Low breakevens of $46 WTI with a mid-teens oil growth rate.
We are committed to capital-efficient growth and returning capital to shareholders. Finally, with new Devon, you have a unique opportunity to own a top-tier E&P at an incredibly attractive valuation.
Thanks, Dave. 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 will take our first question.
Thank you. At this time, I would like to remind everyone, in order to ask a question, press star, pound, number 1 on your telephone keypad. Your first question comes from Arun Jayaram with JPMorgan. Your line is open.
Yeah, good morning. I was wondering if you could maybe outline confidence in achieving the $780 million of cost savings with 70% by year-end, particularly on the G&A line item. I am also hoping that you can kind of address on slide nine, the free cash flow targets that you achieve. In the footnotes, you are saying that the cost savings are fully realized at the beginning of 2019. Just wondering if you could help reconcile that slide as well.
Yeah, Arun, good morning. We are extremely confident on achieving at least $780 million of annualized cost savings. We have activities ongoing right now that are moving us towards achieving those results. We have things that we are doing on the drilling and completion side. We outlined some of the key items there. I think if you look at the deck back on slide 17, it highlights some of the increased capital efficiency around facility costs. I mentioned Wolfcamp drilling costs, stack infill design, the dedicated frack crew in the Powder River Basin, et cetera. We are working on the LOE side right now. The interest expense is obviously contingent upon the asset sale. I am more confident that we are going to do that.
I think very importantly on the G&A side, that we have said that we will achieve approximately 70% of those savings by the end of this year. I can tell you that we have already started our activity on that front, and there's going to be additional activity in the very near future. We have a plan. We've started the execution of that plan, and we're very confident that we're going to get those results. Jeff, do you want to-
Yeah. Just on that slide nine or 10, you go through the cumulative free cash flow of $1.6 billion, trying to understand what you're assuming for cost savings for that target.
Jeff is going to answer that for us.
Yeah, Arun, this is Jeff. As we outlined on the slide with the cost savings, about 70% of that's going to come in the first year. Keep in mind, we've tried to build a 2019 that's clean. We've assumed that we're starting to get the impact of those cost savings in the 2019 timeframe. As you know, that's going to be dependent on, as Dave highlighted, interest costs, for example, is going to be a function of the asset sale proceeds. Until we actually get the assets sold, you're obviously not going to be able to pay down the debt and recognize some of those interest costs. We tried to show you a clean 2019 look.
Just my follow-up, Jeff, can you walk us through potential proceeds, the tax efficiency of the sales of the Barnett and Canada, and perhaps the PV-10 value of both of those assets for the 10-K?
Sure, Arun. Well, as you might guess, we're not going to prejudge our processes that we have ongoing in each of those assets. As you're well aware, there have been multiple transactions in Canada, in the SAGD space over the last couple of years. Certainly, there are several publicly traded companies with quality SAGD assets in that space that I think folks can look to get a sense of the value proposition. On the Barnett side, again, have been fewer transactions, obviously, here of recent. We did obviously sell our Johnson County package last year. I would point out to you, however, that this package is much larger and has a larger weighting towards liquids. Those are things to keep in mind as you think about the value proposition.
From a tax standpoint, as I think you probably have talked to Scott a little bit last night, and he's probably shared some of this with you already, our expectation is we will not have any cash taxes in 2019 related to the divestiture of either of these assets. That's a function of the basis that we have in both of those assets. Structure of the ultimate transaction is ultimately going to determine the tax implications. Under any scenario, we really don't believe there's going to be a significant tax impact. Again, that's a function of the basis that we have in the assets, as well as the tax attributes that we have in hand today. For example, at year-end, we had just under $400 million of NOLs in the U.S.
You put all that together, and we think we're going to have a pretty tax-efficient separation of both these assets.
Arun, I may just add a little detail around the G&A, because I suspect others are going to have the same question about it. If you start with a 2018 G&A of $650 million, we're saying we're going to achieve $300 million of G&A savings. Let me kind of break that down for you so you get an idea in the different categories. We have already identified and already have completed about $35 million of efficiency gains versus the 2018 annual number. Our run rate currently is around $615 million. We expect another $100 million associated with the divestiture related exits, and specifically the G&A associated with Canada and the Barnett directly related to that. We're targeting additionally about $75 million of non-workforce related reductions in G&A, and there are a number of areas that is going to come from.
We've identified specific areas where we think that we can target savings. We're spending more than we want, and there are certainly some areas of even in like the technology area, we think our costs are high, and we're working to reduce those, optimizing our third-party labor. A number of areas that are not workforce related. We do target about $90 million for our workforce reductions. The bulk of that will be done in 2019 as well. That gives you a little more detail hopefully to see how we get there.
Thank you.
Your next question is from Doug Leggate with Bank of America Merrill Lynch. Your line is open.
Thank you. Excuse me. Good morning, everybody. Dave, I wonder if or maybe Jeff, I'm not sure who wants to take this, but could you give us an idea what you think the run rate cash flow is associated with the oil sands business and the Barnett business? Obviously, as you pointed out in your slide deck, the oil business now, the main core business is of a scale now that it can self-fund its growth. Previously, I think one of the issues that prevented an exit from these was that they generated substantial free cash. What should we be thinking as a kind of run rate cash flow that is associated with these two?
I think Jeff can handle it. Obviously in Canada, it's been quite variable, the cash flow that's been generated from that given the differentials. Jeff can give you more specific numbers.
Yeah. Doug, as Dave pointed out, it's a little bit challenging at the moment just given the volatility that we saw in the fourth quarter. We're certainly, on a go-forward basis, thinking about more normalized differentials from a WCS standpoint. There's obviously other complexity given the curtailments and everything else that's going on in the space. If you think about our base business and steady state production, you're probably in that $400 million-$500 million range from an EBITDA standpoint for the asset.
Barnett.
Yeah, on the Barnett.
Thank you.
On the Barnett, I believe in 2018, that asset did around $200 million-$250 million of cash flow. It should be in that same ballpark going forward.
All right. We're not a million miles away. Thank you for that. My follow-up is really more on the go forward plan. Dave, the performance in the Danbury area and the Delaware obviously has been quite impressive. I think you still hold the record wells up there. As I look across down into Cotton Draw and some of the other areas that you tested or initial wells in the fourth quarter, the whole area looks like it has stepped up in terms of productivity. I guess I'm curious, what should we be thinking now in terms of the standard well design that's behind your go forward program, given that the Delaware is dominating the drilling plan? I'm really thinking more about the quality of that 2,000 location inventory. How variable is that relative to what the 2019 fund will look like? I'll leave it there. Thanks.
Well, we've obviously had a significant step change in productivity with the Delaware Basin as we've moved out of the appraisal activity, now we're more into the full development activity in the Delaware Basin. We're being able to target the right zones in the right areas, that has led to this productivity improvement. That's going to continue, Doug. I think the other thing you're going to see is, as I alluded to, you're going to start seeing the cost come down significantly on the Wolfcamp program. Tony, you can go through a little more specifics on the well expectations by formation.
Yeah. Doug, in the Wolfcamp, we're going to drill about 45% of our activity will be in the Wolfcamp in 2019. As Dave mentioned, having great success there on the well performance side, but also on the cost efficiency side of our business. Some of the good well performance is also translating up into our Todd area, which is pretty far north for Wolfcamp activity, and seeing some really outstanding results there. If we look at the typical 8,500 foot Wolfcamp well, our D&C costs right now are estimated someplace between $9 million and $11 million per well. You got to recognize that we're in a transition state right now where the more repetitions we have, that's coming down, and the learnings are accelerating quite rapidly.
The 30-day IPs we're estimating to be about 2,500 BOEs per day, and the ultimate recoveries we're estimating to be upwards of about 1.4 million barrels per well. We also have followed our activity in the Bone Spring, and we continue to do very good thoughtful work there with outstanding results, high returns. There we're spending about $6 million to $7 million per well. IP is a little bit less than the Wolfcamp, a little bit less than 2,000 BOEs per day, and ultimate recovery is about 1 million barrels per well. The Leonard is also a great storyline there as well. Costs are in that same range as the Bone Spring well. The 30-day IPs are about 1,500 BOEs per day, and the ultimate recoveries are also about 1 million barrels per well. We're quite pleased with all the activity that we have in the Delaware.
I got to compliment our technical staff at this point, Doug, since we're talking about the Delaware. They've done a very nice job building out the infrastructure for that entire area. I think you've heard us talk in the past about the magnitude of water that we move through our existing infrastructure, which is about 90%-95%. The guys are doing just really quality work, and I think this was all predicated and all really initialized from the initial work where we locked up our acreage and the areas that we knew we wanted to focus. That has proven out to be extremely valuable decision from a few years ago.
Tony, just to be clear before I jump off. The chart showing the 2018 program and the 2018 Boundary Raider program, is the implication that your 2,000 locations, do you expect to be able to continue to follow that kind of profile?
Doug, we're going to put John Raines on. John is head of our Delaware Business Unit. John has been a part of all the transformation work that we're doing in the Delaware.
Yeah, Doug, what I would say is, when you look at our 2019 program, the activity's pretty evenly split over what I'd call our big four core areas. With the Powder River Basin, with our Spud Muffin project, we're adding a fifth core area this year. These four or five core areas, I guess now would be what I would characterize as geographically and geologically diverse. What Tony just walked through was essentially a blended average of our production profile. When you look at the Boundary Raider area in particular, in 2019, we're offsetting the Boundary Raiders with about 20 wells. We have a bit higher expectations for those wells. It's called our Cat Scratch Fever development program. As compared to the blended average, we have higher expectations for these wells.
What I would caution you is that the Boundary Raider wells were the biggest wells in the history of the Delaware Basin. We're not going to build a type curve off those two wells. We do have extremely high expectations for this program.
I appreciate the full answer, guys. I can't wait to meet the guy the name Spud Muffin. We'll leave that for another day. Thanks a lot, guys. Appreciate the time.
Your next question is from Phillip Jungwirth with BMO. Your line is open.
Thanks. Good morning.
Good morning.
In the past, you'd always talked about wanting a mid-cycle price for Canada. Now, with the more definitive timeline around the separation, how much will market conditions continue to play a role here, and what gives you confidence that the assets can transact at an attractive price?
Well, we're not going to give this asset away. This is a high-quality asset. It's in the top 10% of all SAGD assets out there. Assets like this don't come to market every day. We think that that's going to be recognized by the potential purchasers, what a high-quality asset this is. I think frankly, there are a number of people who are looking at this business for the long term and understand that, and will understand that the differentials can swing widely, but they do have some confidence that eventually we are going to have more pipeline infrastructure up there, and we'll be able to price it appropriately.
We're not going to give it away, I think the other thing that I would remind you to, that's an important point, remind you to go back and look once again on the operations report at slide 11, where it shows that even with no value ascribed to the Barnett and Canada, we're still trading at a discount. In a way, you're getting a free option on this. Now, that doesn't mean we're going to give it away for free because we think that it is a valuable asset. When you look at the share price, I think that's an important thing to keep in mind.
Great. Then on the option for a spin, curious if you had any initial thoughts on pro forma leverage, G&A allocation, and whether you would expect Devon to retain any equity ownership in the new company.
Yeah. Phil, this is Jeff. We're in the early days of just working through all that with our advisors, I don't have definitive answers for you on each of those points. Our current expectation is a complete exit. Not to say that we won't consider structures where Devon does keep some sort of equity ownership, our current thought is a complete spin to shareholders.
Great. Thanks.
Your next question is from Bob Morris with Citigroup. Your line is open.
Thank you. Dave, congratulations on the pending transformation. Certainly. Question on the STACK here. I know versus what the budget was you laid out in November, it appears you're cutting some capital out of the STACK, and that results in a pretty sharp downtick in activity there this year versus last year. Can you give us a little bit of color or thought around why you're cutting capital out of that area versus the other core areas now?
Well, I'd say that overall, we obviously allocate the capital to where we see the highest returns. Now, we do have some very high-quality program that we're going to be executing in the STACK and the Volatile Oil Window, and we feel good about that. I think you start with the overall desire to certainly live within cash flow and to generate some level of free cash flow. With the breakevens of 46, you can see that we're poised to do that. Given that, and given where we want the overall capital budget to be, you start ticking through the areas, and the Delaware is performing just outstanding. We want to keep our momentum going there. The Powder River Basin, we think it's important to expand from two to four rigs to be able to go into development on the Turner and fully appraise the Niobrara activity.
The Eagle Ford, we've gone to three rigs in partnership with our new partner, BP, and potentially adding a fourth rig later this year. We have a relationship there, so we feel that's appropriate. That really makes it come back to the STACK, and the STACK is really the one that has the most flexibility for the pace of the program. Given the learnings we have, and we want to concentrate on the core of the Volatile Oil Window, that's the one that we feel that we should adjust capital.
Okay, that's a good answer. I appreciate that. With regard to capital allocation, I see that you're targeting 25 horizontal refracs in the Eagle Ford this year. Can you give us a sense of sort of the cost of those, what the economics are in doing those, and the uplift in the EUR production from those refracs?
Bob, this is Tony again. We've got about 19 planned for 2019. We're having great success with our refrac program, especially high-end success with our liner refracs. In there, we're spending about $4 million per well. When we try to go without liner and without trying to add new purse and direct our injection with a plug and perf system, we can save about a million and a half dollars and get back to something closer to about $2.5 million. Order of magnitude, we're seeing an uplift, and it depends on well to well, but we're seeing an uplift of about 1,000 barrels of oil per day uplift from the wells that have been refrac'd with the liner system. The total capital, again, is about $4 million, and the expected rate of return is really at the high end of our portfolio list.
If you look at the cheaper refracs that we've done, just bullheading the fluid and proppant down to get similar type response and economics there at the lesser cost. The IPs are a little bit less at about 700 initially. Again, a little bit more volatility in some of the results we've had to date. For the most part, we're excited about this and find it to be one of the higher-end components of our portfolio.
Just lastly, what would you estimate the inventory is that you have of refrac candidates now?
We've got about 700 refrac opportunities in the field on an unrisked basis. As we continue to prosecute this and get more data, we'll just keep marching through that list.
Great. Thank you.
Your next question is from Ryan Todd with Simmons Energy. Your line is open.
Great. Thanks. Maybe a follow-up first of all. If you're able to execute on planned monetization efforts, your potential and your commitment to shareholder cash returns would clearly set you apart from your U.S. onshore pure-play peers while still growing double-digit oil volumes. Can you talk about how you think about free cash flow generation as a goal, and whether you have specific targets relative to peers or relative to the broader market, or how you look to manage free cash flow generation relative to organic growth over the longer term?
Hey, Ryan, this is Jeff. I think as a starter, I would point you to one of the things that we're really focused on is just maintaining the steady state of activity in our base operations. As we've talked about today, we feel really comfortable that we can do that at that $46 kind of breakeven price that we've laid out. We aren't specifically targeting a specific yield or an absolute dollar number. Really more focused on maintaining that momentum in our operational programs, then focused on the cost control that we've outlined today. Then beyond that, the free cash flow, frankly, is just going to fall out of that game plan.
I think, Ryan, our basic philosophy is to have a consistent, measured approach to capital investment. We find that we generate the highest returns when we do not dramatically increase or decrease our capital spending. That's one of the strengths, obviously, advantages of having a strong balance sheet also allows you to weather fluctuations in commodity prices. You can see us, we may flex it up and down slightly, but we try not to do it too much because if you do, you start losing returns. You become much less efficient. You can look for us to stay measured in our approach on capital investment. Then, as Jeff said, as free cash flow is generated above that approach, we see that available to return to the shareholders.
Thanks. I appreciate that color. Maybe a question on the PRB. You had a pretty significant increase year-on-year in activity. Can you talk about where you see those assets in terms of confidence level on development maturity as you move towards more of a development program there? How do you feel about in terms of how much you've been able to de-risk, and how you think that activity level may evolve in the next few years?
I'd say, and Tony can give you the details, but the big picture is the Turner is moving into full development, and we are appraising the Niobrara for potential full development in 2020. Tony can lay more details on than that.
Yep. That's right, Dave. Ryan, we're quite excited about the Powder River Basin position. We've been operating in the basin for quite some time and fully understand the subsurface of the basin. You recall that we expanded our position a couple of years ago, and the team has done a really thoughtful job of de-risking the Turner. We've continued to manage our Turner appraisal process, understanding spacing. As Dave mentioned, they're now moving into the development phase of that. Very high confidence in the results that we've seen in the Turner. We also continue to run about a rig line associated with the shallower zones in the Parkman and the Teapot. There, it's great filler for some of the Turner activity.
Those type of results have been outstanding, and I think if you looked at the operating report and some of the detailed information there, we brought on about nine wells at the second half of December. Came on a little bit late because operating two rigs there, we did not have the ability to handle a dedicated frac fleet. It was deferred just a little bit, moved most of our new performance from those nine wells into January. The well results were outstanding, fit right nicely into our expectations. As Dave mentioned, we're increasing our activity. We're at three rigs right now, and by April, we'll have the fourth rig running, and we'll also have our dedicated frac fleet there.
What the significance of that means in terms of the cost savings there, our technical team has done a really good job, and they believe they can work about $1 million per well out of our cost simply by having enough of a relationship between the four rigs to keep the one frac fleet busy. We're very optimistic about the development work we're doing there. What's also very intriguing to us right now is the work that we're doing in the Niobrara, and we reported on three outstanding wells in the Niobrara. Those are holding up really nicely, fit well into our subsurface model. We're continuing to appraise that in 2019.
In fact, on our Atlas East program, you're going to watch that develop in 2019, and by the end of 2019, if all this drills out as we expect to, we'll be into a development mode around the Atlas East portion of our basin there, and have the capabilities to even increase rig count past that for a Niobrara development. If you remember, the Niobrara is a source rock for the upper portion of the column there in the Powder River Basin, and will certainly behave more like a ubiquitous unconventional formation like we're used to prosecuting. A lot of upside coming our way in the Powder River Basin.
Ryan, I'm going to take just a second just to highlight, step back and highlight what I think is a very important point about the new Devon. That's really shown in a series of three slides there in the Operations Report, not the one that accompanied my comments, not the management commentary, but the Operations Report, slides four, five, and six. Slide four shows that we have assets in four of the best U.S. onshore basins. We don't just have assets in four of the best U.S. onshore basins. When you look at the acreage position, our acreage is truly located in the best parts of each of those four basins. That manifests itself directly on Slide five with those well productivity results. I was a little provocative in my comments there, but it is amazing to me that we're so transparent with everything.
We talk about the missteps we had at Showboat and the STACK and all that. It just makes you wonder. I mean, we talk about that and the negatives there, but look at where we stack up. We are stacked up, even including that, at the top of the 90-day IP charts. That's transparency. That's also showing that we're in the best parts of those basins. When you continue on page six, we have depth. So we've got acreage in the best part of it. We also have depth in the best part of it. That's why we are so excited about this new Devon, because we think this positions us to compete at the top echelon of the U.S. onshore unconventional companies.
Ryan, while you're on the phone, this is Tony. I misspoke. It's not Atlas East, it's our western portion of our development called Atlas West.
Okay. Thanks. I appreciate all that color.
Your next question is from Bob Brackett with Bernstein Research. Your line is open.
Yeah. A question on the sale potentially of Barnett and Canada. Have you been approached by buyers? Do you have any sort of notional bids on those yet, or will those come out of a data room process?
Those will come out of a data room process. We hope to have the data room completed on Canada by the end of the first quarter, Barnett second quarter, that's where we'll get the bids in.
Okay. Then a follow-up on the refrac question earlier for the Eagle Ford. Do you have a notion of the EURs of those refracts, and are those refracts included in your inventory of high return locations?
Bob, I'm just looking through some of the notes here. This would be about 150-200 MBOE per refrac.
Are those counted as inventory locations?
No, they are not.
Yep. Thank you.
Your next question is from Brian Singer with Goldman Sachs. Your line is open.
Thank you. Good morning. Sticking with the Eagle Ford, you talked about the refrac program. Then you also talked about stabilizing volumes by year-end and potentially growing in 2020. Is that mainly just a function of the three-rig program, i.e., greater activity or beyond the refracts? Are there other measures that are contributing to that stabilization and potential growth?
Well, I think it would be primarily. Three rigs basically holds production flat in Eagle Ford. So it's the anticipation that we may have a fourth rig in the Eagle Ford, which would be somewhat predicated on the success of the appraisal work in the Austin Chalk.
The fourth rig would basically only come in if the Austin Chalk were successful, in other words?
Yes.
Got you. Great. Then one quick question with regards to the Barnett sale. Would the transportation piece be a part of the sale, or would you be retaining transportation or paying or having to settle on transportation contracts?
Yeah, Brian, this is Jeff. That's still to be determined. We'll work through that with the potential buyer. I will point out to you, though, the MVCs obviously that we've lived with in the Barnett dropped off here at 2018. You've seen a big step-up in the resulting cash flow as a result of that.
Great. Thank you.
Your next question is from Charles Meade with Johnson Rice. Your line is open.
Morning, Dave, to you and your whole team there.
Morning, Charles.
I appreciate, I guess your posture and all your comments today. You've got a good and a new story to tell. I wanted to go back to a couple of your earlier responses in Q&A about the Canadian asset. I recognize that you guys are going to be circumspect as you're entering your sales process, but I just want to make sure I understand what you do want to tell us. You've said, or in your slides in the operations report, you say it's free cash flow above $50 WTI. Did I hear right that the expected annual EBITDA in the range of $400 million-$500 million for Canada? If so, what is the implied WTI price in that assumption?
Charles, this is Jeff. The WTI price that we assumed in that is at kind of a $55 oil.
Got it. That's helpful. If I could go back and ask a question about those Boundary Raider wells, I recognize it's just two wells, and you can't move a type curve based on it. I go back to a few quarters ago when you guys had some really outstanding wells in the STACK area, and the story was there that you predicted that the wells would be more productive because you anticipated a change in lithology. I'm wondering if that was the case also with these Boundary Raider wells that you expected some different lithology that would be more productive going in, and how these wells, which are really outstanding wells, how they fit with your pre-drill expectations.
Maybe we have John Raines discuss it here a little bit more detail. I think we all anticipated it to be good wells based on our understanding of the lithology and the thickness of the particular zones we were targeting. Did we all think they were going to be as good as they were? I think that may have been a little bit of a surprise they were that good. I think we do have a good handle for what's going on lithologically there, and that's why we expect this next batch of wells to be really strong. Are they going to be as strong as those two wells? Maybe not quite that strong, but they'll be strong wells. John, you want to add to that?
This is John. Just a touch of detail on that. We actually drilled the parent well in the Boundary Raider area back a few years ago and discovered the lithology. There's a bit of a structural high there. You've got some exceptionally clean sand in the second Bone Spring, but the reality is, as we march east with our Cat Scratch Fever Program, we don't have as much well control in the second Bone Spring. For us to predict Boundary Raider-like results would probably be a bit foolish. Like everybody said, we expect big things from the Cat Scratch Program, and I look forward to bringing those wells on.
Thanks for that detail, John, and thanks, Dave.
Yep.
Your next question is from Paul Diggle with Macquarie. Your line is open.
Hi, good morning. What's the underlying PDP decline rate of the new Devon U.S. onshore business moving forward?
Hey, Paul, we're pulling this number together right now, but directionally, it looks like to us with regards, it's about 30% year one on a BOE basis, and oil's going to be a little bit higher than that. That's going to be for the new Devon, so that would exclude the Barnett in Canada.
Okay, perfect. Thank you. I guess following up on the Powder River Basin, you make a mention on the infrastructure not being an issue in 2019 as you move to four rigs. How should we think about either oil or gas takeaway or other logistical infrastructure items as you move maybe later into 2019 or into 2020 should the Niobrara go into development mode as well?
Yeah, this is Jeff. Paul, we don't expect to see any issues in the near term, 2019, 2020, or 2021 from a transportation standpoint or takeaway standpoint.
Great. Thank you so much.
Your next question is from John Ashenbeck with Seaport Global. Your line is open.
Good morning, and thank you for taking my questions. Wanted to follow up on your three-year plan. I apologize if I missed this, but was wondering how we should think about the progression of free cash flow specifically as we get into 2020 and 2021. I'm just wondering, is it fairly ratable or if there's perhaps some lumpiness from one year to another? I'm not sure if you have it in front of you, but was curious what the progression of CapEx looks like over that time period as well. Thanks.
This is Jeff. The first two years are pretty comparable as you roll forward. 2021, you do see a move higher with the production growth that we expect. You'll see additional free cash flow as the cost savings really start to compound over that multi-year period. On a capital standpoint, it's relatively flat as well. You'll see some increase on a year-over-year basis from 2019 to 2020, from 2020 to 2021. 10% overall.
Got it. Got it. Really helpful. Appreciate that. Last one is more of a point of clarification on your 2019 oil growth. Looking at your exit rate that's targeting 20% growth versus full year 2018. How should we think of that exit rate? Is it fair to think of that as a proxy for a Q4 average, or is it more so a smaller snapshot in time?
We would probably consider that a snapshot in time. That's just trying to give you an indicator of just the production momentum we expect heading into 2020. Not trying to imply Q4 there, but clearly you'll see a pretty strong growth rate year-over-year in Q4, but probably not greater than 20%.
Got it. Perfect. That's it for me. Thank you.
Your next question comes from Subash Chandra with Guggenheim Securities. Your line is open.
Yeah, hi. First question on Canada. How are you thinking about Pike in the asset sale? I guess it's a full exit. Is the intention to sort of recover the billion-ish invested in Pike to date?
Well, the plan is a full exit of Canada, Pike would be included in that, in whatever sales price we get.
Okay. The capital allocation in the U.S., just a follow-up on the Eagle Ford and STACK. The completion pace in 2019 for STACK, the 80, 90 wells, should we think of that sort of as a run rate going forward? In the Eagle Ford, the refracs, do they stand on their own? Are they part of a mitigation strategy against frac hits?
Subash, on the Eagle Ford question, a portion of these are standalone refracs, but a portion of those are part of the completion of a pad, so it'd be a pressure mitigation process.
Okay.
Then Subash, this is Scott. With regards to the STACK activity levels for 2019, we're going to bring online a few more wells than what we drill. I think we're going to bring online about 90 wells, and from a spudding perspective, order of magnitude, maybe 10 less, somewhere in that neighborhood. I think that's the best way to think about the cadence of activity in the STACK in 2019.
Okay, no comment on 2020 and beyond, or should we think about that program as being a run rate program beyond 2019?
Subash, I think it's a little bit early to be looking at that. Right now we have thoughts that that would just be a good cash flow generating asset and the activity would be somewhat consistent with our plans in 2019. We're quite excited right now. I think we reported in some really good rates on the wells that are associated with the less dense space projects, and that's showing to be really prolific and has not been built into our forward modeling thought process. For the most part, it'd be fairly consistent activity to 2019.
Thank you. Thank you for all the answers.
Well, I see that we're now at the top of the hour. We appreciate everyone's interest in Devon today. If we didn't get to your question, please do not hesitate to reach out to the investor relations team today, which consists of myself and Chris Carr. Once again, thank you for your time.
This concludes today's conference call. You may now disconnect.