Devon Energy Corp

NYSE:DVN

Earnings Call Transcript 2018-Q4

[Operator]

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 Coody, Vice President of Investor Relations. Sir, you may begin.

[Scott Coody, Vice President-Investor Relations]

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.

And with that, I'll turn the call over to Dave Hager, our President and CEO.

[Dave Hager, Chief Executive Officer]

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 as 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 be upper-echelon performer, driving durable improvements and 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 in evaluating multiple methods of separation for these assets including a potential sale or spinoff, and we expect to complete this separation process by the end of 2019.

Additionally, with Devon's narrowed focus as a 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 and position to generate substantial amounts of free cash flow at today's pricing, I am also excited to announce that we're 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 a 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 plays in the U.S. – in 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 break-evens, 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 the year when we faced challenges optimizing spacing in our STACK play. Just think about it. If we were at the top even with the STACK challenge 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 streamed on 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 5, while our U.S. oil assets have many advantaged 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 lower drilling completion costs are structural and the 2019 plan assumes flat year-over-year service and supply costs. To the extent, we see deflation in service on supply costs that would be additive to the plan.

Importantly, we are acting with a sense of urgency on these initiatives and we are already executing on plans to achieve at least 70% of these cost reductions this year. Our efforts to reduce cost 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 PV10 over the next 10 years of approximately $4.5 billion or more than $10 per share.

Turning to Slide 6, 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.

Now, let's run through some of the operational highlights and specifics of the 2019 program. As we look ahead to 2019, on Slide 7, 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. Although 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, the 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 and optimized up-space development program in the STACK and a dedicated frac crew in the Powder River Basin.

To reemphasize what I noted on a previous side, 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 8, this level of capital investment is expected to drive light-oil production growth for New Devon of 13% to 18% in 2019. Importantly, 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. While our 2019 business outlook is very strong, we will build upon that success in the future by expanding profitability and improving the returns Devon is capable delivering on a multiyear basis.

On Slide 9, we lay out multiyear targets, which highlight the peer-leading capital efficiency of the company. It really highlights what New Devon can deliver. First, we expect capital requirements over 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% to 17% per year over the same time period.

As 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 times to 1.5 times.

Slide 10 outlines the free cash flow our business is capable of delivering at various pricing points. As I've already emphasized, this plan is designed to completely fund our three-year capital requirements at an ultra-low WTI break-even price of $46 while providing an attractive mid-teens growth rate.

And as I touched on a previous slide, at today's 36 months strip price of 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 and represents a very competitive free cash flow yield to investors while still providing an attractive oil production growth rate.

Importantly, this measure 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.

Now, I'll 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 in the 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 up-space development drove oil production 9% higher in the quarter versus the third quarter.

As 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, well STACK generate free cash flow of around $300 million in 2019 at today's prices.

Slide 13 covers Eagle Ford, where we expect to add a third rig in 2019. Beyond the prolific lower Eagle Ford wells 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 derisk more than 200 locations. With regard to 2018 results, this asset continue to perform at a very high level contributing more than $515 million of free cash flow. For the quarter, 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 entered 2019 with significant momentum. January oil production rates were 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 frac crew.

The expected 2019 exit-to-exit oil growth rate for these emerging opportunities is greater than 50%. The program will prioritize the Turner. It 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 creates a very attractive valuation and suggests that 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 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.

So, 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. And finally with new Devon, you have a unique opportunity to own a top-tier E&P at an incredibly attractive valuation.

[Scott Coody, Vice President-Investor Relations]

Thanks Dave. We will now open the call to Q&A. [Operator Instructions] With that, operator, we'll take our first question.

[Operator]

[Operator Instructions] Your first question comes from Arun Jayaram from JPMorgan. Your line is open.

[Arun Jayaram, JPMorgan]

Yes. 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. And I'm also hoping that you can kind of address on Slide 9 the free cash flow targets that you achieve because in the footnotes, you're saying that the cost savings are fully realized at the beginning of 2019. So just wondering if you could help reconcile that slide as well.

[Dave Hager, Chief Executive Officer]

Yes, 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 toward achieving those results. We have results or things that we're 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 and I mentioned Wolfcamp drilling cost, and STACK infill design, dedicated frac 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. And we're confident that we're going to do that. But I think very importantly on the G&A side and 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 is going to be additional activity in the very near future. And 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 you want to...

[Arun Jayaram, JPMorgan]

Just on that Slide 9 or 10, you go through the cumulative free cash flow of $1.6 billion. But just trying to understand when you're assuming – what you're assuming for cost savings for that target.

[Dave Hager, Chief Executive Officer]

Jeff is going to answer for us Arun.

[JeffRitenour]

Yes, 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. But keep in mind we've tried to build a 2019 that's clean. So we've assumed that we're starting to get the impact of those cost savings in the 2019 time frame.

As you know, that's going to be dependent on, as Dave highlighted, interest cost, for example, is going to be a function of the asset sale proceeds. So, until we actually get the asset sold, you're obviously not going to be able to pay down the debt and recognize some of those interest costs. But we tried to show you a clean 2019 look.

[Arun Jayaram, JPMorgan]

Great. And 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 PV10 value of both of those assets for the 10-K?

[JeffRitenour]

Sure, Arun. Well, as you might guess, we're not going to prejudge our processes that we have ongoing in each of those assets. But as you're well aware, there have been multiple transactions in Canada, in the SAGD space over the last couple of years.

Certainly, there's several publicly traded companies with quality SAGD assets in that space but 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 toward liquid. So those are things to keep in mind as you think about the value proposition.

From a tax standpoint, as I think you probably had talked to Scott a little bit last night and he's probably shared some of this with you already, but 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 bases that we have in both of those assets.

Structure of the ultimate transaction is ultimately going to determine the tax implications. But under any scenario, we really don't believe there's going to be significant tax impact. Again, that's a function of the bases that we have in the assets, as well as the tax attributes that we have in hand today. So for example, at year-end, we had just under $400 million of NOLs in the U.S. So, you put all that together and we think we're going to have a pretty tax-efficient separation of both of these assets.

[Dave Hager, Chief Executive Officer]

I may just add a little detail around the G&A, because I suspect others are going to have this same question about it. So if you start with a run or a 2018 G&A of $650 million, we're saying we're going to achieve $300 million of G&A savings. And 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 numbers. So our run rate currently is around 615. 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 that's going to come from. But we've identified specific areas where we think that we can target savings. We're spending more than we want. But there are certainly some areas even 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 are non-specific to, that are not workforce-related, and we do target about $90 million of workforce reductions.

So and the bulk of that will be done in 2019 as well. So that gives you a little more detail hopefully to see how we get there.

[Arun Jayaram, JPMorgan]

Thanks, Dave.

[Operator]

Your next question is from Doug Leggate with Bank of America Merrill Lynch. Your line is open.

[Doug Leggate, Bank-America Merrill Lynch]

Thank you. Good morning, everybody. Dave, I wonder if or maybe Jeff, I'm not sure who wants to take this, but can you give us an idea what you think the run rate cash flow is associated with the oil sands business and the Barnett business? Because, obviously, as you pointed out in your slide deck, the oil business, the main core business is of a scale now that it can self-fund its growth, but previously I think one of the issues that prevented an exit from these was that they generated substantial free cash. So what should we be thinking as kind of run rate cash flow that is associated to these two?

[Dave Hager, Chief Executive Officer]

I think Jeff can handle it, but obviously in Canada, it's been quite variable. The cash flow that's been generated from that given the differentials. But Jeff can give you more specific numbers.

[JeffRitenour]

Yes. Doug, as just Dave pointed out, it's a little bit challenging at the moment just given the volatility that we saw in the differentials in the fourth quarter. But 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.

But if you think about our base business and steady-state production, you're probably in that $400 million to $500 million range from an EBITDA standpoint for the asset. On the Barnett, I believe in 2018 that asset did around $200 million and $250 million of cash flow, and so it should be in that same ballpark going forward.

[Doug Leggate, Bank-America Merrill Lynch]

All right. And we are not many miles away. Thank you for that. My follow-up is really more on the go-forward plan. Dave, the performance in the Boundary area and the Delaware obviously has been quite impressive. I think you still hold the record wells up there. But as I look across the going into Cotton Draw and some of the other areas that you tested initial wells in the fourth quarter, the whole area looks like it has stepped up in terms of productivity. So 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 2000 location inventory; how variable is that relative to 2019 fund would look like and I'll leave it there? Thanks.

[Dave Hager, Chief Executive Officer]

Well, we've obviously had a significant step change in productivity with the Delaware Basin. As we've moved out of the appraisal activity and now we're more into the full development activity in the Delaware Basin. So we're being able to target the right zones and the right areas and that has led to this productivity improvement. That's going to continue some. I think the other thing you're going to see, as I alluded to, you're going to start to see the costs come down significantly on the Wolfcamp program. So, Tony, I don't know you if you want to go – you can go through a little more specifics on the well expectations by formation?

[Tony Vaughn, Chief Operating Officer]

Doug, in the Wolfcamp, you know, we're going to spend about – we're going to drill about 45% of our activity will be in the Wolfcamp in 2019. And 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.

But 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; recognize that we're in a transition state right now where the more repetitions we have that's coming down the learnings are accelerating quite rapidly.

The 30-day IPs we're estimating to be about 2,500 BOEs per day and ultimate recoveries are we're estimating to be upwards of about 1.4 million barrels per well. You also have followed our activity in the Bone Springs and we continue to do very good thoughtful work there with outstanding results, high returns.

And there we're spending about $6 million to $7 million per well. IP is a little bit less in the Wolfcamp, a little bit less than 2,000 BOEs per day and ultimate recoveries is about 1 million barrels per well. And Leonard is also a great story line there as well. Costs are in that same range as the Bone Spring's well. The 30-day IPs are about 1,500 BOEs per day and the ultimate recoveries are also about 1 million barrels per well.

So 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 talking the past about the magnitude of water that we move through our existing infrastructure, which is about 90% to 95%.

So the guys are doing just really quality work and I think this is all predicated, not really initialized from the initial work where we locked up our acreage in the areas that we knew we wanted to focus. And that has proven out to be extremely valuable decision from three years ago.

[Doug Leggate, Bank-America Merrill Lynch]

Tony, just to be clear before I jump off, so the chart showing the 2018 program, on the 2018 Boundary Raider program, is the implication that your 2000 locations, do you expect to be able to continue to follow that kind of profile?

[Dave Hager, Chief Executive Officer]

We're going to put John. John is Head of our Delaware Business Unit and John has been a part of all the transformation work that we're doing in the Delaware.

[John Raines]

Yes. Doug, what I would say is, when you look at our 2019 program, the activity is pretty evenly split over what I'd call our big four core areas. With the Potato Basin, with our Spud Muffin project, we're adding a fifth core area this year. And these four or five core areas I guess now would be what I would characterize as geographically and geologically diverse.

So 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, and we have a bit higher expectations for those wells; it's called our cat scratch fever development program. So as compared to the blended average, we have higher expectations for these wells.

What I would caution you is that the Boundary Raider wells are the biggest wells in the history of the Delaware Basin, so we're not going to build a type curve off those two wells, but we do have extremely high expectations for this program.

[Doug Leggate, Bank-America Merrill Lynch]

Appreciate for the answer, guys. I have to meet a guy that named Spud Muffin, but we will leave out for another day. Thanks a lot guys. Appreciate the time.

[Operator]

Your next question is from Phillip Jungwirth with the BMO. Your line is open.

[Phillip Jungwirth, BMO]

Thanks. Good morning.

[Dave Hager, Chief Executive Officer]

Good morning.

[Phillip Jungwirth, BMO]

In the past, you've always talked about wanting a mid-cycle price for Canada. And now with a more definitive time line around separation, how much will market condition continue to play a role here? And what gives you confidence that the assets can transact at an attractive price?

[Dave Hager, Chief Executive Officer]

Well, we're not going to give these assets – this asset away. This is a high-quality asset. There is in top 10% of all SAGD assets out there. Assets like this don't come to market every day and we think that that's going to be recognized by the potential purchasers that will – how high-quality asset this is. And 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 out there and we'll be able to price it appropriately. So you're not going to see – we're not going to give it away. But I think the other thing that I would remind you and that's important I remind you to go back and look once again at – 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.

So in a way, you're getting free option on this. Now that doesn't mean we're going to give it away for free because we think it is a valuable asset. But when you look at the share price I think that's important thing to keep in mind.

[Phillip Jungwirth, BMO]

Great. And then on the option for 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.

[Jeff Ritenour, Chief Financial Officer]

This is Jeff. We're in early days of just working through all that with our advisors, so I don't have definitive answers for you on each of those points but our current expectation is a complete exit. So not to say that we won't consider structures where Devon does keep some sort of equity ownership but our current thought is a complete spin to shareholders.

[Phillip Jungwirth, BMO]

Right. Thanks.

[Operator]

Your next question is from Robert Morris with Citigroup. Your line is open.

[Robert Morris, Citigroup]

Thank you and Dave congratulations on pending transformation.

[Dave Hager, Chief Executive Officer]

Thanks Rob.

[Robert Morris, Citigroup]

Question on the STACK here I know versus what that 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?

[Dave Hager, Chief Executive Officer]

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 in the volatile oil window and we feel good about that. But I think with the – 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.

But 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. And so we have a relationship there, so we feel that's appropriate. So that really makes it come back to the STACK and STACK is really the one that has the most flexibility for the pace of the program. And so 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.

[Robert Morris, Citigroup]

Okay that's good answer. Appreciate that. With regard to capital allocation, I see that you're targeting 25 horizontal refresh in the Eagle Ford this year. Can you give us a sense of sort of the costs of those, what the economics are in doing those and the uplift in the EUR of production trend in those refracs?

[Tony Vaughn, Chief Operating Officer]

Bob, this is Tony again. We are – 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. And there we're spending about $4 million per well. When we tried to go without liner and without trying to add new perfs and direct our injection with a plug-and-perf system we can save about $1.5 million and get back to something closer to about $2.5 million.

Order of magnitude, we're seeing on uplift. 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 fracked – refracked 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 risk.

And if you look at the cheaper refracs that we've done just bull heading the fluid and prop it down; gets similar-type response and economics there at lesser cost, but the IPs are a little bit less at about 700 initially. And again a little bit more volatility in some of the results we've had to date. But for the most part we're excited about this and find it to be one of the higher-end components of our portfolio.

[Robert Morris, Citigroup]

That's great. And just lastly, what would you estimate the inventory you have of refrac candidates now?

[Tony Vaughn, Chief Operating Officer]

We've got about 700 refrac opportunities in the field on an unrisked basis. So as we continue to prosecute this and get more data, we'll just keep marking through that list.

[Robert Morris, Citigroup]

Great. Thank you.

[Operator]

Your next question is from Ryan Todd with Simmons Energy. Your line is open.

[Ryan Todd, Simmons Energy]

Thanks. Maybe a follow-up, first of all, I mean, if you're able to execute on planned monetization efforts, your potential and your commitment to shareholder cash returns are 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 of the goal, 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?

[Jeff Ritenour, Chief Financial Officer]

Hi, Ryan, this is Jeff. I think as I started out I would point you to one of the things that we're really focused on is just maintaining steady state of activity in our base operations. And as we've talked about today, we feel really comfortable that we can do that at $46 kind of break-even price that we've laid out. We aren't specifically targeting a specific yield or an absolute dollar number, but really more focused on maintaining that momentum in our operational programs and then focused on the cost control that we've outlined today. And then beyond that the free cash flow frankly is just going to fall out of that game plan.

[Dave Hager, Chief Executive Officer]

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. And so you can look for us and that's one of the strengths obviously advantages of having a strong balance sheet also allows you to weather fluctuations in commodity prices.

And so we – 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. So you can look for us to stay measured in our approach on capital investment. And as Jeff said as free cash flow is generated above that approach, we see that available to return to shareholders.

[Ryan Todd, Simmons Energy]

I appreciate that color. And maybe a question on the PRB unit, 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 toward more of a development program there how you feel about in terms of how much you've been able to derisk and how you think that activity level may evolve in the next few years?

[Dave Hager, Chief Executive Officer]

I would say – Tony is going to give you the detail but the big picture is the Turner is moving into full development and we are appraising the Niobrara for potential full development in 2020. But Tony can lay more details on that.

[Tony Vaughn, Chief Operating Officer]

And 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 derisking the Turner.

We've continued to manage our Turner appraisal process understanding spacing as Dave mentioned are now moving into the development phase of that. So very high confidence on the results that we've seen in the Turner, we also continue to run about a rig line associated with the shallower zones in department and the Teapot in there is a great filler for some of the Turner activity.

Those type of results have been outstanding. And I think if you looked at the operating reports on the detailed information there, we brought on about nine wells at the second half of December; came on a little bit late because we don't operating two rigs there. We did not have the ability to handle a dedicated frac fleet.

So it was deferred just a little bit, moved most of our new performance from those nine wells into January. But 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.

And what that 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 costs simply by having enough of a relationship between the four rigs to keep the one frac fleet busy. So 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've 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. And in fact, on our Atlas East program, we'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 development mode around the Atlas East portion of our base in there and have the capabilities to even increase rig count past that for Niobrara development.

And if you remember, the Niobrara is a source rock for the upper portion of the column there in the Powder River Basin. There were certainly behave more like a ubiquitous unconventional formation like we're used to prosecuting. So a lot of upside coming our way in the Powder River Basin.

[Dave Hager, Chief Executive Officer]

Ryan, I can tell you just a second just to highlight – step back and highlight. What I think is a very important point about the New Devon. And it's really showing in a series of three slides there in the operations report, not the one accompanying the – my comments, not the management commentary, but the operational report and Slides 4, 5, and 6. And Slide 4 shows that we have assets in four of the best U.S. onshore basins.

And we don't just have assets in four of the best U.S. onshore basins, we have – when you look at the acreage position, our acreage is truly located in the best parts of each of those four basins. And that manifests itself directly on Slide 5 with those well productivity results. And a little provocative in my comments there, but it is amazing to me that we're so transparent with everything.

We talk about base missteps we have at Showboat and the STACK and all that, but it just makes you wonder. I mean, we talked 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. So that is that's transparency and that's also showing that we're in the best parts of those basins. And then when you continue on Page 6, we have depth.

So we've got acreage in the best part of it and we also have depth in the best part of it. And 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.

[Tony Vaughn, Chief Operating Officer]

Ryan, 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.

[Ryan Todd, Simmons Energy]

Okay. Thanks. I appreciate all that color.

[Operator]

Your next question is from Bob Brackett with Bernstein Research. Your line is open.

[Bob Brackett, Bernstein Research]

A question on the sale potentially of Barnett and Canada, Do you have any – 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?

[Dave Hager, Chief Executive Officer]

Those will come out of a data room process. We just hope to have the data room completed by – on Canada by the end of the first quarter; Barnett second quarter. And so that we'll get bids in.

[Bob Brackett, Bernstein Research]

Okay. And then a follow-up on the refrac question earlier for the Eagle Ford. Do you have a notion of the EURs of those refracs? And are those refracs included in your inventory of high-return locations?

[Tony Vaughn, Chief Operating Officer]

Bob, I'm just looking at some of the notes here. This would be about 150 MBOE to 200 MBOE per refrac.

[Bob Brackett, Bernstein Research]

And are those counted as inventory locations?

[Tony Vaughn, Chief Operating Officer]

No, they are not.

[Bob Brackett, Bernstein Research]

Yes. Thank you.

[Operator]

Your next question is from Brian Singer with Goldman Sachs. Your line is open.

[Brian Singer, Goldman Sachs]

Thank you. Good morning. Sticking with the Eagle Ford, you talked about the refrac program and 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 refracs? Are there other measures that are contributing to that stabilization and potential growth?

[Dave Hager, Chief Executive Officer]

I think it would be primarily due – three rigs basically production plan in the Eagle Ford. And so the anticipation that we may have a fourth rig in the Eagle Ford which should be somewhat predicated on the success of the appraisal work in the Austin Chalk.

[Brian Singer, Goldman Sachs]

The fourth rig would basically only come in if the Austin Chalk were successful in other words?

[Dave Hager, Chief Executive Officer]

Yes.

[Brian Singer, Goldman Sachs]

Got you. Great. And one quick question with regards to the Barnett Shale. 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?

[Jeff Ritenour, Chief Financial Officer]

Yes, Brian, this is Jeff. That's still to be determined. We have worked through that with the potential buyer. I will point out to you though the MVC is obviously that we've lived with in the Barnett dropped off here at 2018. So you've seen a big step-up in the resulting cash flows as a result of that.

[Brian Singer, Goldman Sachs]

Great. Thank you.

[Operator]

Your next question is from Charles Meade from Johnson Rice. Your line is open.

[Charles Meade, Johnson Rice]

Good morning, Dave and whole team there.

[Dave Hager, Chief Executive Officer]

Good morning, Charles.

[Charles Meade, Johnson Rice]

I appreciate the, I guess, your posture in all your comments today. You've got a good and a new story to tell. But I wanted to go back to a couple of your earlier responses in Q&A about the Canadian assets. And I recognize that you guys are going to be circumspect as you're in the sales process.

But I just want to make sure I understand what you do want to tell us. So you've said in your slides in and operations report, you say it's free cash flow above $50 WTI. But did I hear right that you expect the annual EBITDA in the range of $400 million to $500 million for Canada? And if so what is the implied WTI price in that assumption?

[Jeff Ritenour, Chief Financial Officer]

Charles, this is Jeff. Yes, the WTI price that we assumed in that is kind of a $55 oil.

[Charles Meade, Johnson Rice]

Got it, got it. Okay. That's helpful. And then if I could go back and ask a question about those boundary Raider wells. And I recognize it's just two wells and you can't move a type curve based on it. But I'd go back to a few quarters ago when you said that's pretty outstanding wells in the STACK area.

And the story was there that you predicted that the wells will be more productive because there was – you anticipated a change in lithology. And I'm wondering if that was the case also with these Boundary Raider wells that you expected different lithology that would be more productive going in and how these wells, which are really outstanding wells – how they fit with your previous expectations?

[Dave Hager, Chief Executive Officer]

Yes. Well, maybe we have John Raines discuss it here a little bit more detail. I think we all anticipated to be good wells based on our understanding of the lithology and the thickness of the particular zones. We're targeting that we all think they're going to be as good as they were. I think they may have been a little bit of a surprise they were that good. But I think we do have a good handle for what's going on lithologically there.

And that's why we expect this next batch oil to be really strong. Now are they going to be as strong as those two wells or maybe not that quite strong but they'll be strong wells. So John you want to add to that?

[John Raines]

Yes. 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 marched east with our cat scratch fever program we don't have us much well control in the Second Bone Spring.

So for us to predict Boundary Raider like results would probably be a bit foolish, but like everybody said we expect big things from the cat scratch program and look forward to bringing those wells on.

[Charles Meade, Johnson Rice]

Thanks for that detail, John. And thanks, Dave.

[Dave Hager, Chief Executive Officer]

Yes.

[Operator]

Your next question is from Paul Grigel with Macquarie. Your line is open.

[Paul Grigel, Macquarie]

Hi, good morning. What's the underlying PDP decline rate of the New Devon U.S. onshore business moving forward?

[Jeff Ritenour, Chief Financial Officer]

Hi, 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 is going to be a little bit higher than that. So that's going to be for the New Devon. So that would exclude the Barnett and Canada.

[Paul Grigel, Macquarie]

Okay perfect. Thank you. And then I guess following up on the Powder River, you mentioned 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 and later into 2019 or into 2020, should the Niobrara go into development mode as well?

[Jeff Ritenour, Chief Financial Officer]

Yes. This is Jeff, Paul. We don't expect to see any issues in the near term – excuse me, 2019, 2020 or 2021 from a transportation standpoint or takeaway standpoint.

[Paul Grigel, Macquarie]

Great. Thank you so much.

[Operator]

Your next question is from John Aschenbeck with Seaport Global. Your line is open.

[John Aschenbeck, Seaport Global]

Good morning and thank you for taking my questions. Wanted to follow up on your three-year plan and I apologize if I missed this, but I 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. And then also 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.

[Jeff Ritenour, Chief Financial Officer]

This is Jeff. Yes, 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 and you'll see additional free cash flow as the cost savings really start to compound over that multiyear 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 and then from 2020 to 2021; 10% overall.

[John Aschenbeck, Seaport Global]

Got it, got it. Really helpful. Appreciate that. Last one is a 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 of time?

[Jeff Ritenour, Chief Financial Officer]

We will probably consider that a snapshot in time. That's just trying to give you indicator of just the production momentum we expect heading into 2020. So not trying to imply Q4 there but clearly you'll see a pretty strong growth rate year-over-year, but probably not greater than 20%.

[John Aschenbeck, Seaport Global]

Okay. Perfect. That's it for me. Thank you.

[Operator]

Your next question comes from Subash Chandra with Guggenheim Securities. Your line is open.

[Subash Chandra, Guggenheim Securities]

Yes, hi. First question on Canada, how are you thinking about Pike in the asset sale? I guess as a full exit, so is the intention sort of recover the billion-ish invested in Pike to-date?

[Dave Hager, Chief Executive Officer]

Well, its full axis of Canada. So Pike would be included in that in whatever sales price we get.

[Subash Chandra, Guggenheim Securities]

Okay. And the capital allocation in the U.S., just a follow-up on the Eagle Ford and STACK, the completion phase in 2019 for STACK in the 80 90 wells, should we think of that sort of as a run rate going forward? And in the Eagle Ford, the refracs, do they stand on their own or are they part of a mitigation strategy against frac heads?

[Tony Vaughn, Chief Operating Officer]

Subash on the Eagle Ford question, a portion of these are stand-alone refracs but the portion of those part of the completion of a pad. So it'd be a pressure mitigation process.

[Scott Coody, Vice President-Investor Relations]

And 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 drill about 90 wells, and from a spudding perspective, order of magnitude maybe 10 less somewhere in that neighborhood. So I think that's the best way to think about the cadence of activity in the STACK in 2019.

[Subash Chandra, Guggenheim Securities]

Okay. And so no comment on 2020 and beyond? Or should we think about that program as being a run rate program beyond 2019?

[Dave Hager, Chief Executive Officer]

Subash, I think it's a little bit early to be looking at that. But right now we have thoughts that that would just be a good cash flow-generating asset and that 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 fuller modeling thought process, but for the most part be fairly consistent activity to 2019.

[Subash Chandra, Guggenheim Securities]

Right. Thank you for all the answers.

[Scott Coody, Vice President-Investor Relations]

I show that we're now at the top of the hour. We appreciate everyone's interest in Devon today. And if we didn't get your question, please not hesitate to reach out the Investor Relations team today, which consists of myself and Chris Carr. Once again, thank you for your time.

[Operator]

This concludes today's conference call. You may now disconnect.