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Devon Energy Corp
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Welcome to Devon Energy's Fourth Quarter and Full Year 2019 Conference Call. At this time, all participants are in a listen-only mode. This call is being recorded.
I would now like to turn the call over to Scott Coody, Vice President of Investor Relations. Sir, you may begin.
Good morning and thank you to everyone for joining us on the call today. Last night, we issued an earnings release and operations report that cover our results for the year and our forward-looking outlook. We will make references to our operations report during the call today to aid the conversation and these slides can be found on our website at devonenergy.com.
Also joining me on the call today are, Dave Hager, our President and CEO; Jeff Ritenour, our Chief Financial Officer; David Harris, our Executive Vice President of Exploration and Production; and a few other members of our senior management team.
Comments on the call today will contain plans, forecasts and estimates that are forward-looking statements under U.S. securities law. These comments are subject to assumptions, risks and uncertainties that could cause actual results to differ from our forward-looking statements. Please take note of the cautionary language and risk factors provided in our SEC filings and earnings materials.
With that, I'll turn the call over to Dave.
Thanks, Scott and good morning everyone. For Devon, 2019 can best be defined as a year of exceptional execution and differentiating performance across every aspect of our business. As you can see on slide 5 of our operations report, a critical accomplishment during the year was our timely and tax-efficient transformation to a U.S. oil business. Even with the challenging market conditions, we successfully completed our portfolio simplification objectives in only 10 months and we're able to exit noncore assets at highly accretive valuations.
Furthermore, by sharpening our focus on Devon's world-class U.S. oil assets, we delivered a step change improvement in corporate level rates of return, achieved enhanced capital efficiencies, expanded our margins, reduced leverage and returned industry-leading amounts of capital to shareholders. All in all, it was a great year. But let me be clear, we are just getting started and the investment case for Devon has never been stronger.
Looking ahead to 2020, our strategic framework for success and disciplined capital priorities remain unchanged. These priorities are outlined on slide 10 of our operations report. As always, Devon's top priorities will be to fund the maintenance capital requirements of our business and the quarterly dividend. Once these objectives are met, next step in our capital allocation process is to selectively deploy capital to high-return projects that will efficiently expand the cash flow of our business.
Importantly, our 2020 plan meets all of these capital allocation priorities at low breakeven funding levels, even after accounting for the recent weaknesses in gas and NGL strip pricing. Should this volatility drive prices higher, we will remain disciplined and the benefits of any pricing windfall above our conservative base planning scenario will manifest itself in higher levels of free cash flow for shareholders, not higher capital spending. Conversely, should we see price volatility to the downside, we've designed our operating plan to have the flexibility and agility to reassess the capital program and react to any structural changes in the macro environment.
Now, let's run through some of the specifics of our 2020 operating plan, which you can see on slide 11. The key takeaway from this slide is that, due to capital efficiencies, we are lowering the top end of our upstream capital guidance in 2020 by $50 million to a range of $1.7 billion to $1.85 billion. Furthermore, the impact of this investment program in 2020 is expected to be enhanced by a reallocation of capital from the STACK, a liquids-rich combo play to the Delaware, the top oil play in all of North America. This shift in capital allocation will increase spending in the Delaware Basin by approximately 15% year-over-year and Delaware will now account for approximately 60% of total capital investment for the year.
Another important distinction of our 2020 program is that, the reallocation of capital to the Delaware Basin will be deployed exclusively towards accelerating Wolfcamp development activity. This is significant because, our Wolfcamp activity exhibited the most substantial capital efficiency improvement of any opportunity in our portfolio in the back half of 2019.
With this increased capital allocation, the Wolfcamp will now account for two-thirds of our Delaware activity, providing a visible capital efficiency tailwind that will accrue to our benefit throughout 2020 and carry forward into 2021 as well.
While the 2020 capital program is concentrated in the Delaware Basin, I would be remiss not to mention the exciting catalyst-rich program we have planned for the Powder River Basin. With the appraisal success we achieved in the Niobrara in 2019, we plan to double our activity levels in this emerging resource play over the upcoming year.
A key objective of the Niobrara program in 2020 is to derisk and to prepare a portion of our 200,000 net acres for full development by early next year. And lastly, with our Eagle Ford and STACK assets, it will be business as usual, with the operating team laser-focused on executing on their capital programs efficiently, managing base production and maximizing free cash flow for the company.
Turning your attention to Slide 12. Based on the strong operational momentum of our business, we are raising Devon's per share growth outlook for 2020. Not surprisingly, this improved outlook is underpinned by the outstanding well performance we are experiencing in the Delaware Basin. As a result, we are now increasing the lower end of our oil growth outlook by 50 basis points to a range of 7.5% to 9% compared to 2019.
And to reiterate, this higher growth rate is matched with lower capital spending expectations as well. To maximize the value of this production, we have aggressively acted over the past year to materially improve our corporate cost structure. The success of this ongoing initiative is evidenced by Devon's G&A costs projected to be reduced by 25% year-over-year.
And lastly, while Jeff will speak to this later in the call, the per share impact of this improved 2020 outlook will be further magnified by our new $1 billion share repurchase program and yesterday's announcement to increase the quarterly dividend by 22%.
Moving to Slide 13. While 2020 is setting out to be a great year for Devon, another critical message I want to convey is that the differentiated operating performance achieved in 2019 is sustainable longer term. At Devon, we absolutely have the right personnel, financial strength and inventory depth to deliver both attractive growth rates and increased amounts of free cash flow in 2021 and beyond.
While it is too early to provide official guidance for 2021, our thoughtful and pragmatic approach to the business will remain the same. Our Delaware-centric capital program will remain focused on steady activity levels that deliver the right balance between returns, capital efficiencies, growth rates and free cash flow.
With this disciplined financial framework, we believe investors can directionally expect a mid- to high single-digit oil growth rate in 2021 for a relatively stable amount of capital investment. A noteworthy driver of this preliminary outlook is the positive rate of change we expect to realize from our transition to higher Wolfcamp development activity.
Looking beyond the next few years given the quality of our inventory, I believe a sustainable long-term oil growth rate in the mid-single-digit range feels an appropriate rate to expand our business while generating increasing amounts of free cash flow that can effectively compete with any sector in the market.
Slide 14 showcases the free cash flow our business can deliver through 2021. As you can see in the gray box at the top of the slide, Devon's improved operating outlook lowers a breakeven funding level of our operating plan in 2020 and 2021 from our previous disclosure last November. The combination of higher oil growth rate and improved cost structure and a stronger hedge book, now allow us to fully fund our capital program at $46.50 WTI and $2 Henry Hub pricing and Mont Belvieu realizations of less than 30% of WTI.
While we are pleased with these improvements in breakeven funding, which meaningfully improves our position on the U.S. cost curve, we are not stopping here. To be successful in this unforgiving environment, you must roll up your sleeves, get your hands dirty and on a daily basis look for ways to reduce costs by controlling the controllables. And at Devon, that is exactly what we're focused on.
So, in summary, Devon's multi-basin oil business is built to last. And our disciplined capital plans are designed to deliver compelling amounts of free cash flow and an attractive growth in our per share metrics for the foreseeable future.
And with that, I'll turn the call over to Jeff to review our financial strategy. And detail how we plan to allocate the excess cash flow, from our business.
Thanks, Dave. At Devon, we believe our financial strategy and underlying balance sheet strength are significant competitive advantages.
The extreme commodity price volatility, we've experienced over the last year, is a constant reminder that the strong balance sheet. And effective risk management programs are critical to the long-term success, of an E&P company.
Core to our financial strategy, is the emphasis on building a high-margin asset base. Devon's advantaged asset base is very well positioned, on North America's marginal cost curve.
The high-grading of our asset portfolio over the last several years, and the disciplined allocation of capital to our highest return opportunities, is working to lower the breakeven pricing for the company.
As Dave mentioned in his opening remarks, and as outlined on slide 14, our improved operating outlook, has lowered the breakeven funding level of our operating plan in 2020 and 2021, from our previous disclosure last November.
This allows us to provide shareholders with free cash flow, even in, challenged commodity price environments. To further expand our margin of safety, we are actively deploying proven and progressive risk management. And supply chain practices to optimize our financial results.
The example of this includes our disciplined hedging program, which uses a combination of systematic and discretionary hedges, to effectively mitigate pricing volatility. We have over 40% of our 2020 projected oil production, hedged at an average floor of $53 per barrel, well over our funding breakeven pricing of $46.50 per barrel.
In addition, our supply chain team has shifted the majority of our contracted services to shorter-term, over the last year, allowing us to take advantage of the deflationary environment. And providing flexibility should market conditions change. Demand changes and activity to preserve free cash flow.
In combination with our high liquidity and low leverage, these prudent risk management and supply chain practices, allow us to optimize planning efforts and enhance our capital allocation decisions, in periods of uncertainty.
Now turning your attention to slide 8 of our operations report, I plan to briefly cover the details of our financial position, where we have built a tremendous amount of flexibility.
An important strategic priority over the last year has been the repayment of debt, to further strengthen our investment-grade financial position. We made significant progress towards this initiative in 2019, as we retired $1.7 billion of senior notes, which reduced our debt ratio to around 1 times, net debt-to-EBITDA on a trailing 12-month basis.
Importantly, this deleveraging activity, completely cleared Devon's outstanding debt maturity runway, until late 2025 extending the weighted average maturity of our debt portfolio to more than 18 years.
While our balance sheet is in great shape, and we have tremendous flexibility, we're not done making improvements. In the fourth quarter, Devon generated $171 million of free cash flow. And we exited the year with $1.8 billion of cash on hand.
Furthermore, Devon's cash balances will increase, upon close in mid-April, with our $770 million, Barnett Shale divestiture. We are keeping a close watch on, interest rates and credit spreads, as we evaluate the next potential steps in our debt repurchase plan.
Current market dynamics have driven redemption premiums substantially higher. But we are prepared to be patient and opportunistic to repurchase additional debt should the market move to our benefit.
Pivoting your attention to the left hand of slide 9, another top financial priority for Devon is returning capital to shareholders in the form of an increasing dividend. Overall, from a dividend policy perspective, we are targeting a payout ratio of 5% to 10% of operating cash flow, at our base planning scenario of $50 WTI pricing.
Additionally, we believe consistent and sustainable growth in our dividend, provides for a very attractive and competitive result, when compared to our E&P peers and other large-cap companies, across the broader S&P 500.
Our $46.50 per barrel breakeven underpins this policy, and supports growth in the dividend over time. Given the strength of our projected 2020 financial outlook and reduced breakeven, we were pleased to announce last night, that our Board has approved a 22% increase in Devon's quarterly dividend.
This shareholder-friendly action is consistent with our target payout ratios, and is aligned with our commitment to steadily grow the dividend over time to a level that is highly competitive with other sectors in the market.
As you can see on the right-hand side of slide 9 in addition to our dividend, we are also returning cash to shareholders through Devon's industry-leading share repurchase program. Since our program began in 2018, we've repurchased 147 million shares at a total cost of $4.8 billion. Our Board of Directors authorized a new $1 billion program last December paving the way for additional repurchases in 2020 and total -- and a total reduction in Devon's outstanding share count of approximately 35% by year-end.
This is not only the most active program in the E&P space, but it also outpaces the activity of any company regardless of sector in the S&P 500. We have been aggressively buying our shares over the last year at levels ranging from $20 to $25 per share. Given our view of the attractive valuation of our shares compared to the intrinsic value of the company, you can expect more of the same from us in 2020.
In summary, the disciplined financial model we are using to operate the company is working and checks all the boxes necessary for long-term success. We have a strong financial position with a low breakeven funding level and our business can generate excess cash flow in any commodity price environment. We have excellent liquidity and strong balance sheet with very low leverage ratios and we're rewarding our shareholders with a return of cash through our dividend and share repurchase program.
With that, I'll turn the call over to David Harris to cover our operating performance and outlook.
Thanks, Jeff. The fourth quarter was another strong one operationally for Devon that can best be described by oil production once again exceeding guidance and capital spending coming in 6% below forecast. This trend of operational excellence has now been established over multiple quarters and is a testament to the high level of performance each of our asset teams in effectively fulfilling their respective roles in our business. For my prepared comments today, I plan to cover the asset-specific highlights that are driving this positive business momentum and provide some insights and observations regarding our outlook for 2020.
As you can see on slide 16 of the operations report, our world-class Delaware Basin asset is the capital-efficient growth engine driving Devon's operational outperformance. In the fourth quarter, net production from the Delaware continued to increase rapidly growing 82% on a year-over-year basis. This strong growth was driven by 36 high-impact wells brought online in the quarter that were diversified across all five core areas in the Wolfcamp, Bone Spring and Leonard formations. These strong wells achieved average 30-day rates of 2,800 BOEs per day of which 70% was oil at an average cost of around 75 million -- $7.5 million per well. The overall returns from our fourth quarter program in the Delaware Basin were simply outstanding.
Looking specifically at the project level detail for the quarter. Our much anticipated Cat Scratch 2.0 project did not disappoint. This 10-well project which developed a second Bone Spring sweet spot exceeded our pre-drill expectations by reaching average 30-day rates of 3,000 BOEs per well or 425 BOEs per 1,000 feet of lateral. While the Cat Scratch results were certainly impressive, I believe the top thematic takeaway for the fourth quarter activity is the operational momentum we are establishing with our Wolfcamp program.
As you can see on the map at the right side of slide 16, we brought online three impactful Wolfcamp projects during the quarter to help further validate the commerciality of multiple Wolfcamp landing zones across the basin of Southeast New Mexico. Of particular note was our highly successful seven-well Spud Muffin project in the Potato Basin area in Eddy County in which we co-developed the third Bone Spring and Upper Wolfcamp intervals.
While industry has been active for some time in the Potato Basin area, the Spud Muffin project was our initial operated test in this area. And given the well productivity we experienced, this will be an area that definitely works its way into the Delaware Basin capital allocation mix going forward, which further deepens our resource-rich opportunity set in this franchise asset.
As Dave touched on in his opening remarks, the setup of the Delaware Basin in 2020 is exciting. Our diversified development programs across our five core areas position us for another year of exceptionally strong oil growth. In total, we expect to invest around $1 billion of capital in the Delaware that will result in approximately 130 operated spuds. Of this activity, we are allocating nearly 65% to the Wolfcamp formation, which essentially represents a doubling of Wolfcamp activity year-over-year.
To reiterate comments from earlier in the call, this shift in Delaware capital allocation to the Wolfcamp is impactful given the substantial capital efficiency improvements we've achieved in the second half of 2019. In fact in the most recent quarter, our drilled and completed feet-per-day metrics in the Wolfcamp improved 48% and 62% year-over-year, respectively. These steadily improving cycle times and costs provide a capital efficiency tailwind heading into 2020.
The next asset I would like to discuss is the Powder River Basin, an important emerging oil growth opportunity in our portfolio. In the fourth quarter our development-focused program commenced production on 19 new wells that drove net production more than 50% higher year-over-year. Importantly, this oil-weighted production growth was accompanied by a step change improvement in capital efficiency.
Specifically looking at the Turner formation, which was our top development target in 2019 the team did a fantastic job of substantially reducing cycle times and recognizing savings of more than $1 million per well as well cost pushed towards $6 million per well by year end.
As I look ahead to the upcoming year, our highest priority in the Powder River Basin is the delineation of our Niobrara potential. Our Niobrara position consisting of 200,000 net acres in the core of the play's chalk window has repeatable resource play characteristics and the potential to be an important growth driver for Devon longer term. Over the past two years, results from our Niobrara appraisal work have confirmed this potential with 11 operated wells now online and the average 30-day rates from these oil-prone wells reaching as high as 1,500 BOEs per day.
Further progressing the team's confidence, our initial spacing test brought online in the second half of 2019 would suggest the commercial potential for at least three to four wells per section. These tests have also confirmed our ability to develop the Niobrara independent of the deeper Turner interval.
Based on positive operating results obtained to-date, we are doubling our Niobrara activity in 2020 to approximately 15 wells. With this increased capital allocation, we are methodically focusing our delineation efforts in the Southwest quadrant of our acreage, which we call Atlas West and has delivered some of the highest oil rates in the basin. With additional success, we believe it's possible to ready a portion of our Atlas West acreage for full field development in 2021.
And finally, our Eagle Ford and STACK assets are successfully fulfilling their strategically important roles in our portfolio providing nearly $600 million of free cash flow over the past year. Specifically in the Eagle Ford, the key message I want to convey is that we have reestablished operational momentum in the play with our new partner, exiting the year producing around 53,000 BOEs per day.
Our fourth quarter operations were impacted by a well control event related to surface equipment. This situation has been resolved but it did result in estimated downtime of 9,000 BOEs per day in the quarter and remediation costs in the quarter of approximately $7 million.
Looking ahead to 2020, we expect to maintain strong operational continuity in the Eagle Ford running an average of three to four rig lines through most of the year. This disciplined and capital-efficient plan is expected to deliver a modest increase in our production volumes on a year-over-year basis while staying true to the role of generating significant amounts of free cash flow.
Lastly in the STACK, we are excited about our recently announced Dow joint venture. With the Dow deal we have monetized half of our working interest in 133 undrilled locations in exchange for a $100 million drilling carry over the next four years. This innovative agreement will help us bring forward value in the STACK, while delivering carry-enhanced returns that compete effectively for capital within our portfolio.
In addition to the benefits of a drilling carry, our returns are also expected to be enhanced by lower well cost from focused infill drilling and from midstream incentive rates that substantially improve per unit operating cost for each new well brought online.
Initial activity from the Dow joint venture will begin in the second quarter of 2020 with a two-rig program developing the 18-well Jacobs Row in Northern Canadian County. First production from the Jacobs Row is forecast to occur in early 2021. While we will continue to look for smart ways to enhance the value of our STACK position, we are quite pleased with the initial step we have taken with Dow.
That concludes my prepared remarks. And I would like to turn the call back over to Scott.
Thanks David. We'll now open the call to Q&A. Please limit yourself to one question and a follow-up. This allows us to get to more of your questions on the call today. With that operator, we'll take our first question.
[Operator Instructions] The first question is from Arun Jayaram of JPMorgan. Please go ahead. Your line is open.
Yeah. Good morning. Dave the 2020 capital allocation obviously 60% going to the Delaware, 20% to Powder, 17% to the Eagle Ford and 3% in the STACK. And the STACK CapEx is down from call it a 16% mix last year. How comfortable are you with the complement -- complementary assets in the portfolio to the Delaware? And how are you thinking about inorganic opportunities as we did see a favorable reaction to the WPX Felix transaction, which was announced a few weeks ago?
Sure Arun. Yeah, first off, we are very comfortable with the capital allocation we have and frankly the shift of capital from the STACK to the Delaware is the primary reason that you're going to see the growth that we have described in 2021 in general terms, why that is sustainable over a longer period of time, because if you think about it conceptually it takes nine to 12 months for first production to come from capital.
And so really for the most part the capital that we're spending in 2020 where we've shifted some of that capital to the Delaware is being reflected in 2021 production results, which is driving that oil growth rate. And that is sustainable for many, many years with the deep inventory of opportunities that we have in the Delaware Basin. So that's fundamentally why we're going to see the kind of growth rates that we're describing here for a long time.
Now given that that we are comfortable and we are driving higher capital efficiencies internally, we're driving higher levels of cash flow and focused on returning that value to shareholders through increased capital efficiencies and the higher cash flow that we're generating, we have no need to do an acquisition.
Now are we looking at opportunities? Absolutely. That -- we are in the deal flow. We're always going to be in a deal flow. We think that's part of our job. But we are going to be incredibly disciplined around any decision regarding that because of the strength of our internal portfolio that we have and the confidence that we have that we're going to be able to continue to drive higher cash flow through the oil growth and increased capital efficiencies.
Great. And I had one operating question. I know there's been a lot of excitement around the Cat Scratch area Todd. We did want to see if you could maybe elaborate on the initial delineation success in the Potato Basin. I think your pad is just south of Oxy's height and length 14-well program. So I was wondering if you could talk about some of the implications of these delineation results and perhaps capital allocation on a go-forward basis in this fifth part of your Delaware Basin portfolio.
Arun, this is David Harris. Thanks for the question. Yeah, we're really excited about the Potato Basin areas. I mentioned in my prepared remarks, this is an area where some other companies including Oxy as you mentioned have been active for a little while.
Spud Muffin is our first operated test. We brought seven wells online there and they far exceeded our expectations for that area. And so we think we're going to see increasing activity out there not just from an industry perspective, but you'll increasingly see it compete for capital within our portfolio.
I think if you look in the operations report at kind of how we've allocated capital throughout the year, it's going to be roughly about 20% of our capital or so going forward. And so it's one of the things that we like about the Delaware position that we have in the five core areas. We're diversified across the basin of Southeast New Mexico and think that that will continue to be an exciting area for us going forward.
Great. Thanks for those comments.
Your next question comes from Doug Leggate of Bank of America.
Thanks. Good morning, everybody. Actually I'm wondering if I could just follow-up on Arun's question on the Delaware inventory. Dave, we haven't really heard you talk about inventory depth in quite a while at least not in terms of numbers in your slide deck. So, I just wondered if you could give us an update as to how that risk development inventory looks, particularly in the Delaware.
And if I may this bolt-on a part B to that, we haven't really heard a lot of people talk much about interference or parent-child issues since I guess about a year ago. So I just want to make sure that we're -- you guys are comfortable with the spacing that you're developing the Delaware at this point.
Yeah. Thanks Doug. Well, frankly we have the inventory slide in our corporate deck I think everything up until this presentation. There's no big news. We just had a lot of other information we wanted to cover on in this operations report. So, we didn't have it in there. But there's -- and David Harris can give you a little bit more detail on this, but we have a very deep inventory in the Delaware Basin that is going to compete for capital for many, many years. And that's going to be the underpinning of the growth in the company.
Now when we say we have that kind of inventory, we are obviously thinking about issues such as what is the right spacing, parent-child relationships, et cetera. That's all incorporated in that. Now, I think you may in the future and we're constantly refreshing this, our feelings on this, you may see at some point that the actual number of locations may change.
But that's because we're driving to longer and longer laterals all the time, and so it may take less wells to deliver the same resource. But -- which is again part of the capital efficiency drive that we're on as a company. But the resource is really not -- I don't think is going to be changing significantly. So David, do you want to add any beyond that?
Yeah. You bet. I guess one thing I would add specifically in addition to some of the things that Dave noted, from a capital efficiency perspective as we laid out the roughly 2,000 wells of risked Delaware inventory last year and we're going to bring on about 130 spuds or so this year, so that's about 15 years of inventory. As Dave said, we have a long, long runway of high-quality things to do.
One of the things that we really haven't reflected go forward that we think will continue to improve the quality of that inventory is the capital efficiency and the step change that we're seeing. There's -- when you're able to reduce your cost and cycle times as material as we have been and think we'll be able to continue to do, and as you're able to enhance the productivity of your well certainly that's going to have a positive impact as you roll forward and think about the development of that resource base going forward.
Appreciate the answers, fellows. I want to maybe jump to a question for Jeff, if I may. It's got a bit of a Delaware question embedded in it. But Jeff you talked about the 5% to 10% payout ratio for dividends. Can you talk about what the right mix -- I actually just want to think about how you think about the right mix of cash returns. The long-term mid-cycle or mid-single-digit growth I should say, is kind of a new number. Is that an output of the planning process? Is that a target? How do you mix all those things together? And I guess I'll leave it at that. Thank you.
Yeah. Doug I would say it's more of an output. It's a balance. We've had a balance for all the different targets and metrics that we've been talking about from a growth standpoint, from the payout ratio and the dividend. Actually I would back up and say, what underpins all of that is that lowering that breakeven funding level for us. So you heard us talk about the $46.50 for 2021.
We're working obviously to lower that every day. And that's really going to underpin our financial strategy going forward as we add high-margin assets to the portfolio through the capital allocation that we've talked about more so to the Delaware on a go-forward basis. So, when we think about how that competes relative -- not only to our sector, but I would point you to the broader S&P 500 sector, we've looked at what is the kind of free cash flow yield that looks competitive.
We think it's probably something in the 5% to 10% range. You marry that with what you -- what our dividend should look like and how competitive that is not only again to the S&P -- excuse me, to the E&P sector, but the broader S&P 500. And then we try to marry all that together and spit out what we think is a pretty competitive game plan not just from growth but on all those free cash flow metrics as well.
So Jeff to be clear you're tapping the spending or are you targeting a growth rate?
Yes. It's really a returns-based focus. So we start from the ground up in building our game plan and portfolio and we allocate as much capital as we can to the highest-return products and everything else just falls out of that.
All right. Thanks so much, guys.
And we measure that against the broader competitive landscape to make sure that we're in line and competitive with our peers and then the broader S&P 500.
Doug I guess, what we're trying to say here is we look at a combination of returns, growth and free cash flow generation and try to optimize at a level that is the best for all three of those metrics. And so it's not an absolute one or the other. It's an interactive look at those variables and see what we think makes the most sense overall.
Okay. Thanks. I got it. Thanks so much, guys. I appreciate the – answer the question.
Your next question comes from Jeanine Wai of Barclays. Please go ahead. Your line is open.
Hi, good morning, everyone.
Good morning.
My first question is on the updated corporate breakeven. So your two-year now is averaging $46.50 WTI and $2 Henry Hub. Can you just talk about how the breakeven in 2021 compares to 2020? And any changes you have to the assumptions that are embedded into that?
I guess kind of what we're getting at is that the 2020 breakeven benefit from momentum in 2019 and hedges and that's true for a lot of E&Ps right now but there's also some offsets as well for you guys too. But the average $46.50 over two years seems to imply an improvement in 2021. So just any color that you would have on that would be great beyond just the timing of the Wolfcamp activity?
Yes. Jeanine you're spot on. That's exactly right. It does imply improved breakeven in 2021 versus 2020. You're right. We do get – we have taken the benefit of the hedges that we have in place as it relates to 2020 but I'll point you back to some comments Dave made earlier, which is a function of our capital program. The capital that we're spending and the allocation to the Delaware and specifically the Wolfcamp in 2020 is what's really driving that improved capital efficiency in 2021. And so it's just increasing our ability to lower that breakeven in future years.
Okay. And then my second question is on dividend coverage. We've seen a lot of increases so far this earnings season. And when Devon thinks about dividend growth and the risk/reward associated with that, on what WTI price are you comfortable with in terms of dividend coverage on an unhedged basis?
Yes. We – Jeanine, as we said in our prepared remarks and I think we've talked about in the past, we've tried to build the business around a $50 oil and kind of $2 gas price. So that's where we start with our base business plan and then evaluate obviously the different market dynamics as we go through each year with our Board to determine where the – where the dividend ultimately lands. But as we – as I discussed in my prepared remarks, what underlies our policy, our dividend policy is that 5% to 10% kind of payout ratio, which we think is very competitive with the peer group and the broader S&P 500.
Okay. Great. Thank you for taking my questions.
Your next question comes from Paul Cheng of Scotiabank. Please go ahead. Your line is open.
Hi, good morning.
Good morning, Paul.
Two questions. Hi, Dave. Dave, can you maybe share if there's any information about the Atlas West data you moved into the full development? What kind of resource potential number of prospect inventory that kind of information that maybe we – you can share with us?
Paul, this is David Harris. If I understood the question correctly you were asking about resource potential and potential inventory in our Atlas West area is that correct?
That's correct that you were talking about, if the 2020 delineation to be successful as expected then you will move into development in 2021. So I mean, how big is this development plan? Or that is the area that we are talking about?
Yes. So when we talk about Atlas West and Atlas East, it's our entire 200,000 acre position in the northern part of Converse County. So as a reminder that doesn't include any of our acreage up in Campbell, where other operators have been active in the Niobrara.
As we think about that position, it's probably early before we move into development to really give you specific resource sort of numbers. But if you just did some pretty simple math at kind of the three-well spacing, which we think is kind of the bottom end of where we'd be that likely points you to something in the neighborhood of about 500 locations.
Okay. Great. And
And…
Yeah. I’m sorry.
I was just going to clarify that that's -- those would be two-mile locations.
Right. And then that's including both Atlas West and Atlas East or just Atlas West?
Both.
Both. Okay. The second question is that in the event when you guys just looking at any inorganic opportunity, what financial and operating matrix that will be used in the valuation? And what type of minimum matrix that you need before you would even consider? So we're trying to understand the process there. How that works?
Well, the first -- yeah, and again the most important thing to think about on this is what I said earlier in response to I think Doug's question is that we have a great game plan internally to start with. So we feel no need to do any inorganic type activity at all.
Now as I said, we are in a deal flow, but we're going to be extremely disciplined. Frankly, we're in a deal flow for a couple other publics that transacted recently including the -- or a couple of deals including the Felix deal that transacted recently. So we're there and we understand what's going on overall.
But to give you some idea for the criteria that we look at for any sort of M&A activity, we wanted to first off to be accretive to our financial metrics on a per-share basis. Second, it also has to fit strategically within the framework of our asset portfolio. So that it an area frankly where we can realize some sort of synergies beyond what are -- the way that is being executed right now whether that be G&A synergies, LOE synergies or capital efficiency synergies -- do we feel that we have a better way to develop these assets than are currently being developed.
And then it have to compete for capital allocation within our portfolio as well. So those are some of the highest. A lot of say -- probably also one you might add would be margin expansion. Obviously, we're looking for ways that we can expand our margins overall as a company, and again, are there ways that we can reduce the cost overall of the combined entities.
So that's overall the type criteria that we look at. Again, it's -- we're going to be -- remain extremely disciplined around these, because we think we absolutely have a strong strategy as it is. We have a strong asset base and we have the right people internally to execute on that these opportunities. And so we'll see if anything comes along to fit those criteria or not, but if it's -- if it doesn't that's fine because we feel very confident in our strategy.
Thank you.
Your next question comes from Matt Portillo of TPH. Please go ahead. Your line is open.
Good morning.
Good morning, Matt.
My first question relates to STACK capital allocation. Just given the depressed natural gas and NGL environment at the moment, could you provide some color on how you're thinking about rates of return in the STACK JV at strip? And is there a price at which you might consider delaying development until you see an improvement in the forward curve, while pulling forward more free cash flow generation in 2020?
Matt, this is David Harris. Yeah. In terms of STACK activity with Dow, as we've highlighted the first phase of the work that we're going to do with them is in the Jacobs Row, which is a Woodford Row development similar to some of the ones that we've done before. These are very predictable projects, and we're going to be looking at starting that project in the second quarter likely in the May time frame, which just given the size of the project likely means that the production isn't coming on until the first part of 2021.
As we've modeled that, even at the strip today where we currently sit that initial project in the Jacobs Row represents a fully burdened rate of return of about 20%. So, given the predictability of that project, we feel good about that project internally.
With respect to competing for capital obviously we have a partner. We want to stay aligned with them and so we'll continue to be mindful of the commodity price environment as we go forward and have the right kind of dialogue that you would expect as we think about forward decisions around the program.
Great. And then just a follow-up question on capital allocation. The PRB is still receiving a large portion of the development capital and looking back over the last two years on a capital efficiency basis, definitely appears that it's lagging the Delaware to some degree, but you're progressing a couple of different initiatives especially on appraisal. Just curious as you guys think about the 2020 program for the PRB, are there some indicators on the horizon that might show a step change in capital efficiency metrics this year as it relates to that asset? And then over time, if you don't see a material change in capital efficiency, is there the potential to reallocate more capital to the Delaware Basin?
Yes. This is David again. Yes. I think the punchline answer to your question from a capital efficiency perspective you've already kind of hit on just in terms of the little earlier stage, nature of the assets, some of the appraisal work we're doing. So clearly we've got some science and data acquisition capital there as we're seeking to best understand the resource and how to move it into full-field development. And so I think throughout 2020 and into 2021, particularly with the Niobrara as we move into more of a development mode, we think you'll see a step change in that capital efficiency as we start to mature that asset.
You've seen the changes in the Wolfcamp as an idea of how much we've been able to drive down drilling costs and completion costs once we go into full development mode and we haven't done any of that yet in the Niobrara. And so at this point, it's just really appraisal mode. So I don't know if the numbers are going to be identical to that or not, but I -- there is definitely -- teams have internal goals I can tell you that are pretty aggressive around cost reduction that they can achieve. Once we get into full development mode and great confidence, we're going to be able to do that. But right now the focus has been as David said more on the appraisal and understanding the resource. But once we get into the development mode then things can change pretty quickly.
Thank you.
Your next question is from Brian Downey of Citigroup. Please go ahead. Your line is open.
Good morning and thanks for taking my questions. Maybe a follow-up on that one. So if you do move Atlas West and the PRB towards development in 2021, I'm curious broad-strokes that your flattish total 2021 CapEx level isn't how that may shift based on capital level allocation from elsewhere in 2021?
Probably not a significant shift. We'd just be able to do more activity much more efficiently, but not a significant overall shift in the capital allocation.
Okay. And then I had a question on your outlook to 2021. I was curious what service cost environment is currently contemplated in your updated 2020 CapEx guidance versus perhaps what pricing you saw in 4Q 2019, and then what if any deltas you're assuming on pricing or further efficiencies in the 2021 CapEx commentary?
Yes. No. This is Jeff. We have built in some of the efficiencies that we saw in the second half of 2019 and in the fourth quarter of 2019 into the program. But as it relates to service costs inflation or deflation, we really left that flat. So we have seen some -- continue to see some deflationary environment on some of the services, so it could be a potential tailwind for us in 2020. But generally speaking, we've just assumed that that would be flat for the year.
And is that flat from...
And Brian just let me add a few other tidbits. You were asking about other nuances that may impact the modeling of that. And one thing you have to be mindful of is what the differentials we just carried forward kind of the current state that we're seeing right now into 2021. Where there could be upside on that is obviously is the Permian highway or Whistler comes online, you could potentially see some substantially improved realizations, but we did not build that in. And then also we saw the -- our LOE costs continue to go down as well in 2021, especially after some MBC payments roll off in the STACK. That will be a nice tailwind for us. And one other item you want to notice, we expect our G&A cost to continue to gravitate towards that $350 million target. So that would be another improvement you should account for when you're trying to calibrate to our estimates. Sorry. I didn't mean to cut you off there, but I'll let you ask your next question.
Yes. No problem. Just to clarify on the flat service price comment. Is that flat from 4Q, flat from 2019 levels? Just want to make sure I'm clear on what the baseline is there.
Flat from full year.
Okay. Perfect. Appreciate it. Thanks.
Your next question is from Neal Dingmann of SunTrust. Please go ahead. Your line is open.
Good morning all. Dave, my first question is for you or Jeff around your financing. Specifically, the recent drilling partnership with Dow, is this something that we could see in additional areas in the STACK or potentially other plays?
Well, we have a great relationship with Dow. And we started our relationship in the Barnett actually with them with a similar type deal. This is a little bit larger deal. And so -- and we think this is going to work very well. And so, there may be potential for Dow somewhere else. There's also -- we're looking at some opportunities around OBO capital that are not going to fit our return criteria, whether there's opportunities to bring in a partner for some of those opportunities rather than just go non-consent on those wells, but actually have someone else come in and execute a program associated with that. So, that's -- that is another type deal that we're out there working on right now. There's a possibility in the future. And I'm not talking about with Dow at this point, but it could be with other partners.
Interesting. Okay. And then, my follow-up my second question is on your shareholder return. You all have been aggressive in the last several months with stock repurchases. And I'm just wondering, would you all share some details on how you all think about capital allocation between these repurchases and the growth of dividends. And more specifically, I was just wondering about if you would continue to aggressively repurchase this much stock. Do you base it on what your yields or growth levels are? Just wondering, how you sort of balance those things. Thank you.
Well, I'll just start off saying, we want to have a dividend and Jeff's outlined the 5% to 10% of cash from operations. We don't want to have a dividend that is sustainable and can grow through time and so we are I think a measured approach there. We have about a 2% yield right now I think where we're currently trading. But it's something that should be sustainable and grow through time.
Jeff, can go through the numbers, the cash we have and the cash we're going to be bringing in and why we feel, we can continue to be aggressive on that side. We've set out our capital program. Again, we optimized that capital program already on the basis of how we think about our -- the returns on the program, the capital efficiency this generated, the growth rate that we feel is appropriate and the free cash flow that that will generate. So that's essentially established. So then, you go back to the free cash flow that we -- or the cash that we have as a company. And bottom line, we have the cash. Jeff can go through that and we think we're significantly undervalued. So it's a great investment opportunity.
Yes. So Dave, you summed it up well. The only thing I would add is some specifics around the cash balances. We talked about this a little bit in the opening remarks, but we have about $1.8 billion of cash at year-end. We'll add to that with the Barnett divestiture, the $770 million roughly. And so, as Dave articulated, we feel like we can accomplish our financial objectives both on the debt repurchase and with $1 billion share repurchase program that our Board has approved for this year. So, we feel really good about our ability to continue returning cash to shareholders via the dividend and the share repurchase this year.
That will make sense. Thank you, both.
Your next question comes from Kevin MacCurdy of Heikkinen Energy Advisors. Please go ahead. Your line is open.
Hey good morning. Just looking at slide 16, do you have the oil mix breakdown between the Wolfcamp and the Bone Springs? And was the Spud Muffin mix different than other pads?
And you're asking about the oil mix with regards to -- could you give us a little bit more detail? Specifically, are you looking for the quarter or just the projects that we brought on for the quarter?
Yes, the projects that you brought on for the quarter in slide 16 the overall oil rate.
Okay. Yes. It's going to be about -- for the 30-day rates that we achieved in the quarter. It's going to be about 70% oil for those projects. Some are a little bit above that and some are a little bit above, but that's a good way to think about it.
And do you have the mix between the Wolfcamp and the Bone Springs just thinking about as the program goes more towards the Wolfcamp next year?
Just scanning the numbers here, directionally they look about the same. So, they're around that 70% mark. So there's be -- big differentiation there on a 30-day rate or an EUR basis for that matter between the Wolfcamp and the Bone Spring.
Great. Thanks. And as a follow-up the Eagle Ford capital was a pleasant surprise. Do you have what the current well costs are there?
This is David Harris. They're about $6 million plus or minus.
Great. Thank you, guys.
And just as a point of clarification. That's for about -- given the configuration of that development that's for about a 6,000 foot lateral.
Your next question comes from Charles Meade of Johnson Rice. Please go ahead. Your line is open.
Good morning, Dave you and your whole team there. I have just a couple of questions on the Delaware. The first one of the big things last quarter which is -- seems like it's dissipated here was the concern around federal land. And so it seems like that has -- it's at least receded this part of the conversation. But can you give us your view whether it's a -- whether it's kind of receded as an operational concern for you guys and if it's something that we should continue to focus on?
Well, it's something that we're certainly aware of and we follow but we feel that we have a good plan and can adjust as appropriate. And I don't want to get into all the various legal arguments so -- on what could or could not take place. We've -- I can tell you we've studied it pretty extensively. And we think from a practical standpoint the most likely thing that could happen would be a slowdown in the permitting process with the BLM.
And in preparation for that we are building an inventory of permits. The permits just so you know on federal land are actually two-year permits and then you can apply for a two-year extension on the permits. That's the max that anybody can get. And so we're building up our permit inventory if that eventuality would take place. Under the Obama administration, it took about 18 months or so to get a permit. Under the Trump administration, it's more like 6 months to get a permit and so we're preparing for that. But again that's one of the advantages of also having a multi-basin portfolio too is that we can reallocate capital away from federal lands.
But in the meantime we're growing up the inventory if the permitting process does slow down. And again I know there's talk of other things that are more dramatic than that and we don't have time to get into all that from a legal discussion here on the call, but I think we've looked at a lot of those issues. And this is what we think is by far the most likely scenario that we should prepare for.
Got it. Thanks for that Dave. And then I just want to touch on one other base with respect to the shift to the Wolfcamp and the better capital efficiency. So I think you've said that you've that -- you made note earlier in the call about how you really worked hard to get your drilling times and your D&C costs down on the Wolfcamp and the Delaware Basin.
But the other piece of that puzzle the well productivity can you just recap for us what if anything is changed or what you've learned over the last year or the last six months that is the other part of the puzzle that is going to power this step higher in capital efficiency as you shift to the Wolfcamp in the Delaware?
Yes. And first off Charles if you look at slide 18 you'll show -- we showed the drilling and completion costs. For the Wolfcamp wells we had $880 per foot. I think that compares extremely well against what some other people are talking about probably even today and that's again just the Wolfcamp. And if we looked at our entire well mix it would -- of the Delaware Basin it'd be even a much lower dollar per foot. And so just keep that in mind when you hear some other numbers out there that -- about the on the efficiency side.
On the productivity side I think we're finding and we've learned a lot about the Wolfcamp. I'll tell you who can probably get a little bit more detail. David why don't you run with it here? I got a few ideas but I think you probably have better ones than I do. So take that off.
Yes. You bet. I think at the core of it over the last several years as we've increased our technical focus we are really doing integrated reservoir modeling from a multidisciplinary approach and what that's led to is a high-grade of landing zones and targets. And so I think that's probably -- as much as anything that's the biggest driver that you're seeing from a productivity standpoint is the higher-end technical work we're doing.
We're targeting the best parts of these landing zones. Our geo-steering capabilities is something we've invested in over the -- several years ago starting several years ago keeping those wells in zone substantially through that entire lateral. All those things add up on a cumulative basis to kind of -- to drive the step change performance that you've seen from a productivity perspective.
Thank you for the color, David.
Well I see we're at the top of the hour. So I appreciate everyone's interest in Devon today. And if you have any further questions please don't hesitate to reach out to the Investor Relations team at any time which consists of myself and Chris Carr. Have a good day.
This concludes today's conference call. Thank you for your participation. You may now disconnect.