德文能源 (DVN) 2020 Q2 法說會逐字稿

This transcript is incomplete due an audio issue on the webcast. The following summary is not a verbatim representation and has been provided by the Company.

Welcome to Devon Energy's Second Quarter 2020 Earnings Conference Call. (Operator Instructions) This call is being recorded.

I would now like to turn the call over to Mr. 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 presentation that covers our results for the quarter and our updated outlook for the year. Throughout the call today, we will make references to our second quarter earnings presentation to support our prepared remarks, 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; David Harris, our Executive Vice President of Exploration and Production; and Jeff Ritenour, our Chief Financial Officer; and a few other members of our senior management team.

Comments on the call today will include 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 our cautionary language and the risk factors provided in our SEC filings and earnings materials.

With that, I'll turn the call over to Dave.

Thank you, Scott, and good morning. We appreciate everyone taking the time to join us on the call today, and I sincerely hope that everyone in our audience this morning stays safe, remains in good health.

The second quarter for Devon can best be defined by our strong operational performance as we effectively navigated the various challenges presented by the COVID-19 crisis. Our team is executing at an extremely high level and I want to take a moment to acknowledge the professionalism our workforce has demonstrated to safely execute the business plan and protect shareholder value during this unprecedented time.

For my prepared remarks today, the first topic I want to touch on is the efficiency gains that are driving, our breakeven funding levels substantially lower. In the second quarter, our capital and operating costs outperformed our guidance on virtually every measure. Specifically, on the capital front, our spending was 10% below midpoint guidance. This positive variance was once again driven by the capital efficiency gains achieved in the Delaware Basin. These efficiency gains are best visualized on Slide 10 of our earnings presentation, which highlights our Wolfcamp program, where the majority of our capital is invested in 2020.

As you can see on the far-left chart, our drilled and completion costs in the second quarter improved by more than 40% to $700 per foot compared to 2018 when we first started drilling 2-mile laterals in the play. Importantly, our capital efficiency results in the Wolfcamp are best-in-class among our peers. We're also leading the industry in well productivity. These are truly special results. I would like to congratulate our operating team for this outstanding accomplishment.

To be clear, the operating teams at Devon are not done improving and expect efficiency gains to continue, driving our capital requirements lower in 2021. This is best shown on Slide 11, where we now estimate that our maintenance capital, which is the amount required to keep our oil production flat, has improved to $950 million in 2021. This represents a $150 million reduction in capital or roughly 15% compared to our previous disclosure only three months ago. This estimate includes only efficiencies and supply chain cost reductions that we have line of sight on. So there is potential for this figure to further improve as we progress through the year. This improvement in maintenance capital does not assume a drawdown of our DUC inventory, which is estimated to be around 100 wells by year-end. However, should we desire to lower our capital intensity further in 2021, we do possess this optionality with our DUC backlog. From a sensitivity perspective, for every 25 DUCs we draw down, we could decrease our capital intensity in 2021 by an incremental $50 million.

Moving to Slide 12. We're also acting with a sense of urgency to improve our cash cost structure. With this intense focus, we expect to achieve at least $300 million in sustainable annual cost savings by year-end compared to our second-quarter results. This cost-reduction plan includes a range of actions to better align personnel with go-forward activity levels, achieve more efficient field-level operations and reduce financing costs.. These structural changes to our cost structure are material to Devon's future cash flow generation capabilities, equating to a PV-10 of greater than $1 billion over the next 5 years or roughly 30% of our current market capitalization.

Turning to Slide 13, the combination of our cost reductions and capital efficiencies lower Devon's all-in sustaining funding levels to keep production flat to a $35 WTI price. In addition to low WTI price required to fund our operations, this slide also showcases the attractive free cash flow yield that our business can deliver at various pricing points after funding maintenance capital requirements. These yields range from 10 percent at $45 WTI pricing to 21 percent at a $55 WTI, providing an attractive investment proposition compared to any sector in the market today.

Next, I want to build up on my comments from last quarter regarding our long-term approach to managing the business. With a commodity business such as ours , any successful strategy must be grounded in the supply and demand fundamentals. We understand the maturing demand dynamics for our industry and recognize the traditional E&P growth model of the past is not a viable strategy going forward. To win in the next phase of the energy cycle, a successful company must deploy a highly disciplined, financially driven

business model that prioritizes cash returns directly to shareholders. Devon is an industry leader in this cash-return movement and, slide 3 of our presentation outlines the tenets of our strategy, which includes:

Limiting top-line growth aspirations to 5% or less in times of favorable conditions, pursuing margin expansion through operational scale and

leaner corporate structure

Moderating reinvestment rates

at 70% to 80% of operating cash flow at mid-cycle pricing

Maintaining extremely low levels of leverage to establish a greater margin of safety and Returning more cash directly to shareholders through quarterly and special dividends. To be clear, when we say

special this is equivalent to what others have characterized as a variable dividend.

At Devon, we are absolutely committed to this strategy. Most importantly, we are putting our money where our mouth is by tailoring capital investment

to generate free cash flow in 2020

Taking aggressive steps to sustainably improve our cash cost structure Repurchasing up to $$1.5 billion of outstanding debt And last night we announced a groundbreaking action in the E&P space with a $100 million special dividend dividend in conjunction with the accelerated closing of our Barnett Shale divestiture. Furthermore, as we generate organic free cash flow in the second half of this year we will evaluate opportunities to return additional cash to shareholders through another special or variable dividend.

I believe these shareholder-friendly initiatives that underpin our transition to a cash-return business model will transform Devon from a highly-efficient oil and gas operator to a prominent and consistent builder of economic value through the cycle. Others may be contemplating and talking about the possibilities of a cash-return model, but at Devon we are taking action and executing on this strategy.

The final topic I would like to spend some time discussing today is the strategic optionality that our diversified portfolio provides us. This is an especially important topic to review given the heightened focus on political issues related to federal lands from the ongoing election cycle.. First, regardless of which political party wins, we expect to be able to efficiently develop our federally leased land. Nevertheless, I do want to highlight that only 20% of total company-wide leasehold resides on federal acreage. At the asset level, our largest federal acreage exposure resides in the Powder River Basin, which accounts for nearly 60% of our leasehold in that operating area.. In the Delaware Basin, roughly half of our acreage is federal, and our Eagle Ford and Anadarko Basin assets do not include any federal leasehold. . While it's difficult to project with exact certainty how the politics of this issue will be resolved, I want to emphasize we're proactively managing risks by building a deep inventory of federal drilling permits in our core development areas within the Delaware Basin and Powder River Basin.

As you can see on Slide 15, we are on pace to secure a multiyear inventory of federal drilling permits that will exceed 550 permits by the time of the election this fall. With this proactive approach to permitting, we estimate that our permits in hand will cover more than 75% of our desired activity over the next 4 years under a maintenance capital scenario.. Should the federal regulatory environment become more challenging, we have significant optionality, high quality non-federal land within our diversified portfolio. This includes non-federal opportunities in the Delaware and Powder River Basin along with high return inventory in the Eagle Ford and carried drilling activity in the Anadarko basin. Any shift of capital to these non-federal opportunities because of the slowing of federal permits would not have any meaningful impact to our capital efficiency under this maintenance capital scenario over the next four years.

The key takeaway here is that Devon has a clear strategic path forward to create value regardless of who occupies the White House.. While we are well positioned as a company to navigate these issues, I must say that we fundamentally believe that the idea of limiting drilling activity on federal lands is fraught with serious economic ramifications and puts our nation's energy security at risk. This policy would harm the communities in which we operate that financially benefit from our business activity as well as impact the broader U.S. economy from an inevitable spike in energy costs that would unnecessarily limit GDP growth.. Furthermore, if this ideology was enacted, it would have the unintended consequence of transferring the responsibility of unmet oil demand to less environmentally progressive countries. Overall, the U.S. energy industry has made amazing progress reducing emissions over the past decade by more than doubling its low cost (inaudible) any action (inaudible). -cost production while driving emissions down. Any action that limits access to developing the minerals on federal lands would only undermine the substantial progress we have made toward addressing the risks of climate change. In summary, while the current environment has provided no shortages of near-term challenges, Devon is well positioned over the long-term.. We have the right mix of assets, the right execution, the right financial strength, the right business model to deliver attractive returns for shareholders..

And with that, I'll turn the call over to David Harris to cover a few of our operational highlights.

Good morning, everyone. To reiterate Dave's comments from earlier, I also want to say that I could not be prouder of our Devon employees for the way that they have responded and their level of performance during this pandemic. Our operating teams have demonstrated amazing flexibility by quickly adapting to new ways of working as we safely execute our day-to-day operations while performing at the extremely high standards we have set for ourselves.

Given the dynamic environment we faced in the quarter, I would like to begin my comments with a brief review of our recent activity level. We entered the month of April with 15 rigs and 6 frac crews operating across our portfolio. However, in response to rapidly deteriorating commodity prices, we quickly responded with capital reductions to exit June with only 9 operated rigs and 1 frac crew.. In the second quarter, we brought online 39 new wells with activity primarily focused in the Delaware Basin.

From a timing perspective, the vast majority of these new wells were completed in early April. We ultimately opted to bring these new wells online rather than risk damaging the reservoir from leaving completion fluid on the formation for an indefinite period of time. However, to protect the economic value of these new wells , we did restrict early-time flowback to limit production into a weak commodity tape.. This restricted flowback strategy, combined with the decision to temporarily shut-in a tranche of legacy vertical wells, led to the curtailment of roughly 10,000 barrels of oil per day across our asset portfolio in the quarter. Our minimal curtailments in the quarter reflect the quality of our low-cost assets and the proactive decision of our marketing team to secure pricing points that economically incentivized us to produce.

Given the improvements we're seeing in strip prices, we do not expect to shut-in or restrict flowback on the wells in the second half of the year. While pricing has certainly improved from historic lows since set in the second quarter, we have no plan [at this time] to modify our capital activity for the remainder of the year. In fact, based on efficiencies achieved year-to-date, we are lowering the midpoint of our [full year] capital spending guidance to $975 million, an improvement of $25 million from our previous forecast. For the second half of the year, we plan to invest around $200 million per quarter with the strategic objective to preserve operational continuity in our franchise asset, the Delaware Basin. This level of activity is generating attractive returns at today's strip pricing and will generate the necessary cash flow to effectively operate our business.

Looking specifically at the third quarter, a number of new wells we expect to bring online will be limited to around 30 wells due to the timing of completion activity.. As you would expect, this activity is concentrated in the Delaware Basin, but we also plan to bring online a handful of wells in the Powder River Basin as we wrap up that program for the year. Because of this lower activity, we project that our oil production output in the third quarter from will mark the low point for the year, declining to thea range of (inaudible)138,000 to 143,000 barrels of oil (inaudible).per day.

In the fourth quarter, we established our operating momentum heading into 2021, we plan to increase the number of new wells brought online to around 40. We expect this level of activity to increase our oil production to a range of 141,000 to 146,000 barrels per day. As Dave discussed earlier in the call, with the capital efficiency gains and service cost reductions we are attaining, we now expect to be able to maintain our Q4 2020 oil production exit rates into 2021 with only $950 million of capital spend. It could be even lower should we choose to draw down on our DUC inventory. While it is premature to provide specific guidance on 2021, at today's strip pricing, we are very confident in the returns of our projects and the cash flow our business can generate under a maintenance capital scenario. We plan to provide firmer thoughts on our 2021 outlook later in the

And with that, I will turn the call over to Jeff Ritenour for a brief financial review.

Thanks, David. My comments today will be focused on detailing the next steps in the execution of our financial strategy. Beginning with the review of our balance sheet, we have a tremendous amount of flexibility when it comes to our financial position. At the end of June, Devon had $4.7 billion of liquidity, consisting of $1.7 billion of cash on hand and $3 billion of undrawn capacity on our unsecured credit facility that does not mature until the end of 2024.

As you can see on Slide 8, also adding to Devon's financial margin of safety is our low leverage with no outstanding debt obligations until the end of 2025. Our near-term debt maturity runway is best in class within the industry, with more than 5 years of time until our first tranche of debt comes in. This is a critical competitive advantage in this period of economic uncertainty. Given these traits, we are confident we possess the financial strength to navigate these challenging times and flourish when the recovery does come.

While our balance sheet is in great shape and we have tremendous flexibility, we're not done making improvements. Looking ahead in the second half of 2020, we expect our cash balance to build as we have taken decisive action to scale our operating cost to generate free cash flow. In addition to our free cash flow-generating capabilities, another item that will bolster our liquidity is the expected closing of our Barnett Shale divestiture. We recently received notice from our counterparty requesting an early close and now expect to complete the transaction on October 1. For those of you not familiar with this transaction, we agreed to sell our Barnett Shale assets for up to $830 million of total proceeds, consisting of $570 million in cash at closing and contingent payments of up to $260 million. After adjusting for purchase price adjustments, which includes a $170 million deposit we received in April and accrued cash flow from the effective date we expect to receive a net cash payment of greater than $300 million at closing.

As I've mentioned many times in the past, the top priority for the large amount of cash we have on hand is the repayment of debt. As Dave mentioned earlier, we intend to repurchase up to $1.5 billion of additional debt. This debt reduction plan will provide a nice uplift to our cash flow, resulting in a go-forward interest savings of approximately $75 million on an annual run rate basis. Given the uncertainty we still face with the COVID-19 crisis, we will remain flexible with the timing of our program and how we execute the repurchases, which may include both open market transactions and tender offers. Longer term, it is our fundamental belief that a successful E&P company going forward must maintain extremely low levels of leverage. In accordance with this belief, we will continue to manage toward our stated leverage target of less than 1.0x net debt-to-EBITDA in a mid-cycle pricing environment.

Another key financial objective for Devon is to accelerate the return of cash to shareholders. With our improved cost structure and lower breakeven, we are well positioned to deliver. Feedback from our shareholders has been consistent regarding the desire for cash dividends.

With regards to our dividend policy, we plan to maintain our quarterly dividend and target a sustainable payout ratio of up to 10% of operating cash flow at a mid-cycle pricing level. In addition to our traditional quarterly dividend, we are also excited to announce our first special dividend. Given our expectation for the generation of excess cash flow in the second half of the year and the early closing of the Barnett transaction, our Board has approved a $100 million special cash dividend. The special dividend will be payable on October 1 to shareholders of record on August 14. This action clearly demonstrates our commitment to returning cash to shareholders and we are eager to utilize the special dividend in the future as circumstances warrant.

As Dave mentioned, as we generate additional free cash flow throughout the remainder of this year and into the future, we will evaluate additional special dividends based on expected market conditions at the time. As we look to the future of this business, we have a high degree of conviction that a special dividend is a necessary capital allocation tool for a well-managed E&P company. This mechanism provides us flexibility to return cash windfalls to shareholders without overcommitting to an unsustainable quarterly payout that has often plagued the industry in past cycles.

And with that, I'll now turn the call back over to Scott for Q&A.

Thanks, Jeff. We recognize from some feedback from our audience, we're having some audio issues. So what we'll do to combat that, we will send out a script to our audience today. And so you can see what our prepared remarks are.

That being said, we will pivot into the Q&A conversation. (Operator Instructions) This will allow us to get to more of your questions, which I'm sure you're going to have since some of the prepared remarks were at times inaudible. So we apologize for that, but we'll do our best to bridge that gap. That being said, operator, we'll take our fist question.

End of non-verbatim summary.

(Operator Instructions) Your first question comes from Paul Cheng with Scotiabank.

I don't know if you can hear me because the voice is breaking up pretty bad on my home. I think 2 questions. One, can you tell us what's the mechanism of the $1.5 billion debt reduction since that you have no maturity? Is it going to be a tender or that you're just going to buy from the public market? And secondly that on the special dividend and why we are not using that money for buyback given how cheap is the valuation the stock is currently in.

Yes. Yes, this is Jeff. So as it relates to the debt repurchase, the $1.5 billion that we've highlighted, our expectation is to do probably a mix between open market and tender. That's going to be dependent upon market conditions. So we're going to evaluate the maturities across the curve and where the best value sits. And then we'll enact that as we work our way through the rest of this year and likely into next year as well. So it's likely going to be a mixed bag. We certainly want to see interest reduction -- excuse me, interest costs come down as we've highlighted as our new annual run rate, but we also are going to have a focus on reducing absolute leverage. So it's going to be a balance between the 2.

As it relates to the special dividend, as I mentioned in my prepared remarks, which you all probably could not hear, the feedback from our investors has been incredibly clear. They're looking for a continuation of cash dividends from the space and specifically from Devon. And so we think with the work that we've done around our cost structure, lowering our breakeven, we're uniquely positioned within the sector to provide those cash returns to shareholders. So it's really consistent with what we're hearing from our largest shareholders. And we're excited to move forward with not only our quarterly dividend but the potential for variable dividends as we move through the next couple of years and evaluate market conditions.

Jeff, can I just follow up that on the debt reduction? Do you have a time line when you think you will complete it?

Yes. We're certainly going to look to do some of that here over the next several months, again, as market conditions allow. And then likely, some of that will move our way into 2021 as well. So again, it's going to be a function of the market conditions and what we see with how the debt's trading. We're also comfortable holding the cash on the balance sheet to the extent that the value proposition isn't there. But the key point we want to make is that, that cash is earmarked for debt repayment. So we are absolutely expecting to continue to lower our absolute leverage over time.

Your next question comes from Arun Jayaram.

I was wondering if you could maybe elaborate on the $150 million reduction in sustaining CapEx, from $1.1 billion to $950 million. Just help us think about the broad buckets that drove that pretty material climb there.

Arun, this is David. I think David Harris is going to have some good information around that.

Arun, this is David. Yes. Thanks for the question. Yes. As you've noted, we've driven that 2021 maintenance capital level down about $150 million from our prior disclosure to a level that we think we can carry out in 2021 of about $950 million. In broad buckets, I would tell you that's equally split between capital efficiencies we're seeing particularly in the Wolfcamp as well as the impact of lower decline rates. I'd note that a lot of the production outperformance we saw this year has come from the good focus we've had on our base production levels, and we continue to outperform from a base perspective. So those lower decline rates certainly give us a boost as we think about the maintenance capital we need to drive the business forward. And then the other half would be service cost savings that we believe we have line of sight to here just given the environment we're in.

Got it. Got it. How much would you view that as, call it, sustainable in the future or more permanent, David?

Well, it's a good question. I would tell you, as I've told you in the past, I mean we always look to try to make all of this as sustainable and as permanent as we can. Certainly, here in this part of the cycle from supply/cost perspective, we've seen some pretty material reductions. We believe we can capture that. We haven't baked a lot of that, that we don't have line of sight to and going forward. So I think it's consistent with what we think we're going to see here over the next 12 to 18 months.

Arun, I might just add that we've even seen some service cost reductions beyond what we've built into this at this point. So we're not building all of the leading-edge cost reductions that we have into this $950 million.

Great. Great. I guess my follow-up was just on -- I appreciate the disclosure around your federal permit backlog in both the Delaware and the PRB. My understanding is that the permits are valid for 2 years, and you can get up to a 2-year extension on those. How, call it, automatic are the -- is that extension process?

Arun, you're correct. Our federal permits have a 2-year initial term and then they're eligible for a 2-year extension period. Typically, it's a routine part of our business. We file for those extensions, say, 3 months out from when those permits will expire. Typically, it's a very quick approval process. We've never been declined an extension. And importantly, the environmental assessments that underlie those permits are good for a period of 5 years.

Great. Great. And so you're saying today that under a sustaining CapEx mode, that 75% of your contemplated activity over the next 4 years would be kind of with permits in hand? Is that the correct understanding?

Yes. That's absolutely correct.

Your next question comes from Douglas Leggate with Bank of America.

I don't know what magic wand you swung there, but it seems the audio is now fine. So thank you for getting that sorted out. Hopefully, you can hear me okay.

Dave, you and I have gone backwards and forwards on this model for some time. I just want to commend you guys for introducing what I think is a really differentiated model. And I'll be curious to see how this is received by the market. My question, however, is I wonder if you or Jeff could explain the mechanism by how you intend to share, I'll use your words from the last call, windfall cash flows with investors.

Well, I think -- thanks, Doug. And we're very proud of the model, and we think it is the right business model. And certainly, we feel like we have moved this model quickly and probably as quick as anybody in the industry. And hopefully, others continue to follow it up with actions as we have already started to do here.

I think the first thing to keep in mind is that our breakeven is now -- that funds our maintenance capital is around $35 WTI. And then -- and we actually then funded the dividend, the normal dividend plus our maintenance capital around $39 WTI. So where you start really getting into the issue is when you start to balance our growth opportunities beyond -- if we're in an environment above $39 WTI, how do you balance that with the return of free cash flow to shareholders. And certainly, we're going to look at the economic climate that we're in at the time to make that call whether we would undertake select growth opportunities or whether we think it's better to return that cash to shareholders as we move above that.

As we sit here today, we're obviously still in the middle of a global pandemic. And so even though the strip is sitting there at currently somewhere right around $45 today, the way I would describe it is there's a big error bar on that strip. There's a lot of uncertainty associated with that strip at this point and how sustainable that is. So we are not, at this point, prepared to say, "Okay. It's $45 strip." Now we're going to start going more into growth mode. Our thought process is more we're going to stay closer to maintenance capital or at maintenance capital and return those incremental dollars to shareholders.

Now there may be an environment in the future where we don't feel as much risk as there is on oil pricing right now given the global pandemic that we're still under. So there may be at some point where we do start to -- as we get above $40 and towards $45 where we say we're going to mix in a little bit of growth and with the return to value to shareholders. But we're going to take into account all the economic conditions at the time on how to best make that judgment.

So it's not going to be an absolute formula. I think if you -- inevitably, I think whenever you try to live by an absolute formula, you will find that the formula doesn't work as well as you wish it had. And so it's going to involve some level of business judgment, where our business judgment is right now that we feel it's more appropriate to fund at maintenance capital level and return at incremental dollars to the shareholder. But that could change at some point in the future.

I appreciate the answer, David. If I may offer a comment, I think there is a subtle difference in perception between a special dividend and a variable dividend. So presumably, you're talking about a variable dividend.

Yes. Yes. We are talking about a variable dividend. And yes, I think we see there's a subtle difference, too. And a special is one -- it's really special when you actually do it. And so that's why we call it special, and we've done it.

Okay. So my follow-up is hopefully...

I'm being a little funny there for you.

Yes. Capital allocation, Dave, if you're slowing down the growth rate up to 5%, how does that change your capital allocation across the portfolio? And I guess it's really a question about high-grading inventory. I'm just wondering if the incremental drilling activity sees another upward reset in productivity and capital efficiency because you're obviously slowing down the activity level as well. I'll leave it there.

Well, I think you can look for us to continue to drive more capital efficiency into the business in general. You're seeing how we're continuing to drive down the drilling and completion costs and improve the capital efficiency in the Delaware Basin. You can -- if you look at the stack play, we've done a couple of things there where we have really redesigned our wells. And when we go back out there, that we feel that we're going to be drilling and completing those wells for significantly less than when the last time we were out there. In addition, we did the transaction with Dow where we brought in promoted capital, where essentially we'll be paying 1/3 of our costs in a given well for 50% of our working interest. So that is certainly going to drive capital efficiency.

Eagle Ford. We work very closely with BP to drive the efficiency there and really the economics on the remaining development inventory as well as the redevelopment opportunities we're seeing are very capital efficient.

And finally, we're learning an awful lot about the Powder River Basin particularly in the Niobrara. And we have really just been in appraisal mode up there so far. So as we go into full development in the Powder River Basin, you will see those well costs potentially move down dramatically as well. So absolutely, we'll be -- in a sense, we'll be high grading by drilling the best opportunities, but all of these opportunities are going to continue to improve because of the measures that we have been executing on internally.

Your next question comes from Neal Dingmann with Truist Securities.

Dave, you guys talked a lot about these cash dividends. I mean my question is around sort of the debt and production growth levels. So I just want to make sure clear. Is there a certain level you want to get debt down to and sort of a certain minimum level of production growth you'd like before sort of considering these more frequent variable dividends? Or how should we think about that?

Well, I tried to say -- first, on the debt, I mean our target in mid-cycle pricing is get the [debt -- the EBITDAR] down around 1.0 or less. Now we're not quite there yet, and we're probably going to need a little bit better pricing to do it.

On the variable dividend, so I tried to lay out that it's going to depend somewhat on our perception of the economic outlook as to how much we want and our confidence in forward pricing as to how much we would just return cash to shareholders versus invest in a limited amount of growth opportunities up to 5%. So -- and I tried to highlight that we're going to assess that at the time. Right now, we're not particularly confident in the economic outlook on prices. It may prove better, but we're still in the middle of a pandemic. So there's a lot of uncertainty around it. So we'd be leaning more towards the cash return side of it right now.

Neal, this is Jeff. But just one thing I would add is a distinction for Devon versus some of our peers is we have the cash on hand to accomplish our debt objectives, our target debt levels. So any free cash flow that we generate can then go back to shareholders, as Dave articulated. A lot of other folks in the sector are going to have to generate free cash flow and then try to accomplish their lower leverage objectives. But we're in a unique position with the cash that we have on hand. We can take care of that and then generate free cash flow with the lower breakevens that we've created and return that to shareholders.

Great clarification. The cash is certainly obvious for you all. It gives you a lot of options. And then just one follow-up. On -- Dave, you mentioned with the strip, it doesn't cause you to think about boosting activity and sort of with this whole -- ties in with this plan you've been talking about. But I'm just thinking when -- if the strip does get up to a certain point where you have more confidence behind that, would the focus essentially still initially just be Delaware? Or would you continue -- would you start looking more at the Eagle Ford, Powder, Anadarko, et cetera?

Neal, this is David Harris. I think as we move into 2021, I think you'll continue to see us have a capital program with a pretty heavy Delaware emphasis. But I do think you'll see us bring back some activity across all 3 of those areas and take advantage of the diversity in the portfolio and, as Dave alluded to, the high quality opportunity set we have across those areas as well.

Your next question comes from Jeanine Wai.

I hope you can hear me.

Yes. We hear you fine. Hope you can hear us now.

Okay. We got you. So I guess my first question is on the reinvestment framework. And apologies if you addressed this in your prepared remarks. But the 70% to 80% target for CapEx to cash flow, you mentioned this is at a mid-cycle price. What mid-cycle price are you using? And could you provide any color on the price band or the sensitivities that you looked at around various reinvestment and payout ratios?

Jeanine, this is Jeff. Yes. So when we talk about mid-cycle pricing, we generally talk about $50 oil. So that reinvestment ratio that we talk about, the 70% to 80%, it obviously really kicks in when you get to those sorts of levels. Prior to that, again, as Dave has articulated, we're going to be focused on the maintenance capital and generating free cash flow and returning that to shareholders. But once you get to those higher levels of WTI pricing, given our low breakevens, we do think that it makes sense to limit our reinvestment to that 70% to 80% kind of level. And effectively, we can accomplish all of our objectives of the 5% growth, our quarterly dividend and generating free cash flow when you get to that kind of mid-cycle type pricing.

Okay. Great. My follow-up is just moving to the Delaware and [well] productivity. Maybe following up on Arun's question on the federal. In maintenance mode, it looks like you've mitigated a significant amount of risk in the Delaware through a lot of good forward permitting. But can you talk about in terms of the well productivity? How does this vary between your federal and nonfederal acreage?

Jeanine, it's David. As we've said before, although about 55% of our acreage in the Delaware is federal, certainly, as you think about the core of Lea and Eddy Counties, that's where some of our highest return opportunities are. And so that's why we wanted to highlight, from a permitting standpoint, of those 400-or-so permits that we expect to have by the fall in the Delaware, about half of those include our drilling program for the next 2 years. So they're specific to those programs and what we would expect to see. And so I would expect that you'll continue to see us lean on that permit inventory, drill those wells and then supplement it with state wells where we can and need to.

Your next question comes from Matt Portillo with TPH.

2 asset-specific questions. Just curious as you look out into 2021. With the improvement in the gas forward curve, curious how you're thinking about capital allocation to the stack, specifically with the carrier that you have with the Dow JV.

Matt, it's David. We were scheduled to begin that activity this year. Obviously, with what we've seen from a pandemic and a commodity price standpoint, we've deferred that activity. We're currently working with our partner and would contemplate restarting that activity in 2021. I think that our best guess based on those discussions and sort of how we would see that plan laying out is probably something like a 2-rig program in 2021 potentially to prosecute the initial stages of the Dow partnership.

Perfect. And then just a follow-up question. Your partner in the Eagle Ford laid out a pretty significant strategy shift over the next 10 years. And I was just curious how you guys are thinking about capital allocation to the Eagle Ford with that as the backdrop.

Well, we work very closely with BP on the capital allocation there. And so far, we've remained aligned. I will say I think probably better to hear this from BP, but I think, overall, they're extremely happy with that asset and feel that's one of the best assets they've picked up and, if not the best, they picked up in the BHP transaction. So I would think that even though they're having a strategy shift, I would suspect that this is one that's going to continue to be highlighted within their portfolio. So far, we have not seen any significant alignment issues with them around that. Obviously, if there's some point they don't consider that asset to be very valuable in their portfolio, we'd love to talk to them about that as well. But right now, I can tell you we remain very aligned.

Your next question comes from Scott Hanold.

Question on the 2021 plan in the DUCs. And so how should we think about that? I mean do you all expect to work through the DUCs in 2021? Or what are those decision points?

Well, we're still finalizing our 2021 capital allocation. So it'd be a little premature to say how much. I do know that we'd have 22 DUCs down in the Eagle Ford that we've -- that have been there that we [docked] in the second quarter. And so those are definitely going to be drawn down in early '21, which will give us a really good start to 2021 production.

I think beyond that, the level at which we may consider drawing down that inventory, we're going to have to -- we're working on that right now and deciding whether -- how much we may consider doing that. For the most part, I think you would consider that to just be normal working level of DUCs that you would -- always going to have some inventory, but there probably are a few that we could draw down if it seems appropriate.

Right. Right. So just to clarify. Of the -- I think it was roughly 100 DUCs. Some of that, you would include normal work in inventory. Is that right?

That's right. That's right.

Yes. Yes. Okay. Fair enough. And then with regards to the special dividend -- and correct me if I'm wrong. The way you guys laid it out, it doesn't sound like it's going to be highly consistent going forward once you start to initiate it and that it could be off and on, I guess, depending on your view of the commodity and the macro and some other things. Is that a fair statement? Or are you guys designing this to be something shareholders can understand we're going to get something this quarter, we don't know what it is, but you're going to have some sort of a plan for that?

Well, make no mistake that we are very dedicated to the cash return model to shareholders. And I feel that, frankly, we're the first ones to actually take action with a special or variable dividend. There are probably a couple of different cases where you can do this. And we use the words synonymously, frankly. One is in this case, where we have some extra cash we're anticipating because of the Barnett sale. The other is, I believe probably Pioneer talked about this morning, and certainly, we're going to be doing the same thing, is as we generate excess cash flow from our ongoing business, that we will be returning that to shareholders as well.

Now are we going to be absolutely formulaic around that approach and say we're going to do so much every quarter? No. We're not saying that. But when we are confident that we've generated excess cash flow in the right business environment beyond what we need as a company, and again, we're limiting our growth to 5%, then you can look for us to return that cash to our shareholders. We're just not being so specific as to say exactly how it might be. Now Jeff I know may have a few additional comments or some thoughts that he's had around this as well.

Yes. Scott, no, I think Dave said it well. The one thing I would add is obviously our quarterly -- our traditional quarterly dividend is going to return cash to shareholders throughout the year. And then as Dave articulated, depending on market conditions, we'll evaluate what makes sense at the time as it relates to the variable dividend. But our expectation is, again, I would just point you to our breakeven levels, and you all can use whatever price deck you prefer. But as we've articulated, with the breakeven that we have in our maintenance capital level, we should be generating free cash flow into the foreseeable future. And our game plan is to return that to shareholders via the dividend, both dividends, the quarterly traditional dividend and the special.

As it relates to timing, obviously, we'll debate that with our Board. Our Board meets multiple times throughout the year, at least quarterly, and evaluate what makes sense based on the market conditions and the other objectives we're trying to achieve at the time.

And we -- you might look at Slide 13 in our operations report, too. That also shows what amounts of free cash flow we could yield at maintenance capital at various WTI prices. So just as Jeff said, we anticipate that there is going to be significant free cash flow and that we would look to return that to shareholders.

Your next question comes from Nitin Kumar with Wells Fargo.

I guess a lot of ground has been covered on this cash return side. You did mention in your slides that the buyback is still a component of -- share buyback is a component of your cash return. Can you help us understand the prioritization of how you are looking at the different avenues for shareholder return?

Yes. Nitin, this is Jeff. You're right. Certainly, in the past, we've utilized the share buyback approach as a way to return cash to shareholders as well. As I said, and I appreciate you didn't hear them given our audio difficulties, but in our prepared remarks, the feedback that we've got from shareholders has been pretty loud and clear and consistent around cash returns and cash dividends. And so going forward, our absolute expectation is to return the cash versus -- excuse me, to return cash via the dividend versus the stock buyback.

Great. That's helpful. And then this is going to be for you as well, Jeff. But on Slide 12, you've talked about the financing cost reductions of $75 million, but you also mentioned about $125 million in reductions from LOE and GP&T. Granted there may be many moving parts here, but just could you help us understand what are the targets? And how are you improving your LOE? And then particularly, I'm interested in how you're improving your GP&T going forward.

Yes. So -- and I'm happy to answer that. The $125 million of LOE and GP&T cost reduction that we highlighted, about $65 million of that is an MVC that we have in Oklahoma and our stack asset...

Volume commitment.

Sorry, minimum volume commitment that we have in Oklahoma is rolling off in 2021. So that's about half of that $125 million. And then beyond that, frankly, we're seeing lower costs in all of our categories. David mentioned some of this earlier. He can add more detail. But whether it be chemicals, compression, our teams have done a great job of -- as we've changed our level of activity and our cadence of work to really work hard to lower the cost. Some of that, of course, is the benefit of the deflation that we've seen here lately. But what we're really seeing from the teams is an ability to lock some of that in and, again, we believe keep those lower cost sustainable into the future. I'll let Dave add any color that he may have.

Yes. Jeff, I think you covered it well. I think what I would tell you is from an operating perspective on the LOE side, we always start with trying to reduce downtime as best we can. We've got our decision support centers that feed us data on our operations on a real-time basis. And so not only are we able to respond more quickly to downtime events, in many cases, we're able to predict them and get in front of them. And so that's keeping our operations up and running, as always, the first order of business. It varies a little bit by area how we attack the line items just given the nature of the different assets, but Jeff, I think, covered it well. Certainly, compression costs, chemical costs across both the Anadarko and the Eagle Ford are things that we're focused on pretty heavily and the Rockies.

We're doing -- we're piloting some additional technology opportunities to automate the way we work. So far, those have allowed us to cut our downtime in half year-over-year while improving those costs and our environmental performance. And so there, we believe we've got a stretch target there to get our recurring LOE in the Rockies down from something on the order of $6.50 down to the mid-4s. So we believe there's a step change there that we can continue to get. And then in the Delaware, obviously, those types of things as well, but we've got a lot of important infrastructure there from both a water standpoint and otherwise that we're leveraging to manage our costs and keep those down.

Your next question comes from Brian Singer.

I wanted to follow up on that growth outlook, and it's really just to ask if they were an above mid-cycle scenario, i.e., price is above $50, is the 5% still the max growth outlook? So any price, 5% would be the max you would consider. And then as you think today...

Yes.

Okay. And then I guess as you think about the impact of having a growth rate that's maybe a little slower than it was at some time, does that impact or maybe even limit the consideration that Devon would have to either participate in or be a part of M&A and consolidation?

Well, I'd say M&A, consolidation is something that we obviously recognize there can be benefits out there. There's too much overhead sitting in the entire E&P system. And to the extent that which there can be some consolidation and eliminate some of that overhead and also, in many cases, capture operational synergies that may exist between various companies, there could be some benefit there. So I don't really see that the limitation of the growth rate has a significant impact one way or the other. I think, frankly, many of the companies are pivoting to the same model that we are. I think we're just a little more advanced with the implementation of this model than they are. So I think this is a strategy that can make sense with acquisitions if there could be something that would be appropriate.

And just on the -- I gave the very quick answer, one-word answer of yes on limited to 5% growth rate. That is absolutely the answer. The rationale behind that, I think, we all understand is that why does it -- it just doesn't make any sense for our industry to grow at a much higher rate than the demand for the product is. And we count on OPEC to cut supplies to bail us out on prices. And so I think hopefully, everyone is learning their lesson on that. And I think -- and frankly, I think the industry is learning their lesson on that. So that's why it's just so straightforward for us to answer it the way I did.

Fair enough. And then my follow-up is with regards to base decline rates. Assuming you're at that 5% or lower growth level, how do you see the evolution of your corporate base decline rate? And can you talk about where you've been most effective in managing that base decline here more recently?

Brian, it's David. As we've talked about previously, as we came into 2020, our decline rate was probably in the high-30s percent on oil and the low 30% on a BOE basis. I think as we roll forward a year, we would expect that, that oil decline rate moves to the low 30s and on a BOE basis into the mid-20s or so.

And then really, I would say from a base production standpoint, it's become a big emphasis for us across all of our asset areas. I think all of our teams have done an excellent job arresting base declines and accretively deploying workover capital and some creative solutions to try to shallow these decline rates out as much as we can. And certainly, as we move into this cash return model with a more moderate growth rate, that's an extremely important part of the business that maybe people took for granted in times past, but I can tell you, our teams certainly don't.

(Operator Instructions) Your next question comes from Brian Downey with Citigroup.

From the prepared remarks on Slide 9, you're understandably still restricting flowback on newer wells due to market conditions. I'm curious if that experience has changed how you're thinking about early time initial flowback or pressure management on a go-forward basis, if there are any surprise learnings throughout that whole process during the quarter.

Brian, it's David. It's good to talk to you again. No, I wouldn't say that there's been any surprises or any differences in terms of how we would approach that. Certainly, as we think about flowback strategy, that's an important part of how we develop our asset. And so from time to time, we do experiment with that a bit. Certainly, as we're doing some appraisal work, we'll have projects where we're restricting flowback for interference testing and the like but no big or shattering changes or revelations that you should expect in terms of how we conduct the business.

Okay. So sort of back to normal in the second half of the year, we should anticipate on the completions there?

Yes. I think that's right.

All right. It looks like we're at the top of the hour. And I think we've got through all the questions. We appreciate everyone's interest in Devon today. And once again, given some of the audio issues we've had, we'll send out the prepared remarks to our audience. And then we'll also post them on the website for everyone's convenience for viewing. If you have any other further questions as well, please don't hesitate to reach out to the Investor Relations team at any time.

Thank you, and have a good day.

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