Devon Energy Corp (DVN) — Q2 2020 Earnings Call Transcript

Hi, good morning, guys. I don’t know if you can hear me, because the voice is breaking up pretty badly on my end. I have two questions. One, can you tell us what’s the mechanism of the $1.5 billion debt reduction, given that you have no maturity? Is it going to be a tender offer, or are you just going to buy from the public market? And secondly, regarding the special dividend, why are we not using that money for buybacks, given how cheap the stock is currently valued? Thank you.

Hi. 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 see where the best value sits. We intend to enact that as we work our way through the rest of this year and likely into next year as well. It’s likely going to be a mixed bag. We definitely want to see interest costs come down as we’ve highlighted as our new annual run rate, and we’re also going to focus on reducing absolute leverage. So it’s going to be a balance between the two. Regarding the special dividend, as I mentioned in my prepared remarks, which you probably could not hear, the feedback from our investors has been incredibly clear. They’re looking for a continuation of cash dividends from the sector and specifically from Devon. So we think with the work that we’ve done around our cost structure, lowering our break-even, we’re uniquely positioned within the sector to provide those cash returns to shareholders. 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 on the debt reduction? Do you have a timeline for 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 is trading. We’re also comfortable holding 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 cash is earmarked for debt repayment. We absolutely expect to continue to lower our absolute leverage over time.

Thank you.

Yes, good morning. 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 decline?

Hi, Arun, this is Dave. I think David Harris is going to have some good information regarding 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 sustain 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. 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. The other half would be service cost savings that we believe we have visibility to here, just given the environment we’re in.

Got it. How much would you view that as, say, sustainable or more permanent, David?

Well, that’s a good question. I would tell you, as I’ve told you in the past, we always look to try to make this as sustainable and as permanent as we can. Certainly, here, in this part of the cycle from a supply-cost perspective, we’ve seen some pretty material reductions. We believe we can capture that. We haven’t baked in a lot of things that we don’t have line of sight to 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 including all of the leading-edge cost reductions that we have into this $950 million.

Great. 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 two years, and you can get up to a two-year extension on those. How automatic is that extension process?

Arun, you’re correct. Our federal permits have a two-year initial term and then they’re eligible for a two-year extension period. Typically, it’s a routine part of our business. We file for those extensions, say, three 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 valid for a period of five years.

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

Yes. That’s absolutely correct.

Okay. Thanks a lot.

Thanks, everyone. I don’t know what magic wand you swung there, but it seems the audio is now fine. Thank you for getting that sorted out. Hopefully, you can hear me okay. Dave, you and I have gone back and forth on this model for some time. I just want to commend you guys for introducing what I think is a really differentiated model. 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 which you intend to share, I’ll use your words from the last call, windfall cash flows with investors.

Well, thanks, Doug, we’re very proud of the model and we think it is the right business model. Certainly, we feel like we have moved this model quickly, probably as quick as anybody in the industry. Hopefully, others continue to follow it up with actions as we have already started to do here. The first thing to keep in mind is that our break-even for funding our maintenance capital is around $35 WTI. We actually fund 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? Certainly, we’re going to look at the economic climate 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 beyond that. As we sit here today, we’re obviously still in the middle of a global pandemic. Even though the strip is currently around $45, I would describe it as having a big error bar. 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 it’s $45 strip. Now we’re going to start going into growth mode. Our thought process is more to stay close to maintenance capital or at maintenance capital and return those incremental dollars to shareholders. There may come a time when we don’t feel as much risk concerning oil pricing. But we’re going to take into account all the economic conditions at the time on how to best make that judgment. It’s not going to be an absolute formula. When you try to live by an absolute formula, you will find that it doesn’t work as well as you wish it had. It’s going to involve some level of business judgment. Right now, our business judgment is that we feel it’s more appropriate to fund at a maintenance capital level and return those incremental dollars to shareholders. However, that could change in the future.

I appreciate the answer, Dave. 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. A special is just that, it’s special when you actually do it.

Okay. So my follow-up is on capital allocation. If you’re slowing down the growth rate to 5%, how does that change your capital allocation across the portfolio? 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. Thank you.

Well, I think you can look for us to continue to drive more capital efficiency into the business in general. We’re continuing to drive down the drilling and completion costs and improve the capital efficiency in the Delaware Basin. If you look at the stack play, we've done a couple of things there, redesigning our wells. When we go back out there, we feel that we will drill and complete those wells for significantly less than the last time we were out there. Additionally, we did the transaction with Dow, where we brought in promoted capital, essentially paying one-third of our costs in a given well for 50% of our working interest. This is going to drive capital efficiency. In the Eagle Ford, we work closely with BP to drive the efficiency there, and the economics on the development and redevelopment opportunities we’re seeing are very capital efficient. Finally, we’re learning a lot about the Powder River Basin, particularly in the Niobrara. So as we transition to full development in the Powder River Basin, you will see those well costs potentially move down dramatically as well. We’ll be high grading by drilling the best opportunities, but all these opportunities are going to continue to improve due to the measures we have been executing internally.

I appreciate it, and thanks, guys. Congrats, again. Thank you.

Good morning, Dave, and I’ll – maybe you guys talked a lot about these cash dividends. My question is around sort of the debt and production growth levels. Is there a certain level you want to get debt down to and sort of a certain minimum level of production growth you would like before considering these more frequent variable dividends, or how should we think about that?

On the debt front, our target in mid-cycle pricing is to get the debt-to-EBITDA down around 1.0 or less. We’re not quite there yet, and we’re probably going to need a little better pricing to achieve that. As for the variable dividend, it will depend somewhat on our perception of the economic outlook and our confidence in forward pricing regarding how much we want to just return cash to shareholders versus invest in limited growth opportunities up to 5%. We’re leaning more toward the cash return side given the uncertainty with the economic outlook on prices.

Neal, this is Jeff. I would add that a distinction for Devon versus some of our peers is that we have the cash on hand to accomplish our debt objectives and target debt levels. Any free cash flow that we generate can then go back to shareholders, as Dave articulated. Many others in the sector need to generate free cash flow and then attempt to lower their leverage objectives. We’re in a unique position with our available cash.

Great clarification. The cash is certainly obvious for you all. It gives you a lot of options. My follow-up is on – Dave, you mentioned with the strip it doesn’t cause you to think about boosting activity. But I’m just considering if the strip does get up to a point where you have more confidence behind that, would the focus still be primarily on the Delaware, or would you start looking more at the Eagle Ford, Powder, Anadarko, etc.?

Neal, this is David Harris. As we move into 2021, I think you will continue to see us have a capital program with a strong emphasis on the Delaware. However, you’ll see us bring back some activity across all three of those areas and take advantage of the diverse portfolio and high-quality opportunities we have.

Great details. Thanks, guys.

Hi, good morning, everyone. I hope you can hear me.

Yes, we hear you fine. Hope you can hear us now.

Okay. We got you. Thank you. My first question is on the reinvestment framework. I apologize if you’ve addressed this in your prepared remarks, but the 70% to 80% target for CapEx to cash flow is mentioned at a mid-cycle price. What mid-cycle price are you using? Could you provide any color on the price band or the sensitivities considered around various reinvestment and payout ratios?

Hey, Jeanine, this is Jeff. When we talk about mid-cycle pricing, we generally refer to $50 oil. The reinvestment ratio of 70% to 80% kicks in at that level. Prior to that, as Dave has articulated, we’re focused on maintenance capital, generating free cash flow, and returning that to shareholders. Once you reach those higher WTI pricing levels, we believe it makes sense to limit reinvestment to that 70% to 80% level. We can accomplish our objectives of 5% growth, our quarterly dividend, and generating free cash flow at that kind of mid-cycle pricing.

Okay, great. Thank you for that clarification. My follow-up is on the Delaware and well productivity. In maintenance mode, it looks like you’ve mitigated a significant amount of risk in the Delaware through good forward permitting. Can you talk about well productivity? How does this vary between your federal and non-federal acreage? Thank you.

Jeanine, it’s David. Although about 55% of our acreage in the Delaware is federal, our highest return opportunities lie in the core areas of Lea and Eddy County. We want to highlight, from a permitting standpoint, of those 400 or so permits expected by the fall in the Delaware, about half include our drilling program for the next two years. They’re specific to those programs and what we would expect to see. We plan to lean on that permit inventory, drill those wells, and then supplement it with state wells as needed.

Okay. Thank you very much.

Good morning, all.

Good morning, Matt.

Two asset-specific questions. Just curious as you look into 2021, with the improvement in the gas forward curve, how you’re thinking about capital allocation to the stack, specifically with the carry that you have with the Dow JV?

Matt, it’s David. We were scheduled to begin that activity this year. However, with the pandemic and commodity price situation, we’ve deferred that activity. We’re currently working with our partner and would contemplate restarting that activity in 2021. Our best guess based on that is probably a two-rig program in 2021 to begin the initial stages of the Dow partnership.

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

We work very closely with BP on the capital allocation there. So far, we’ve remained aligned, and I believe they’re extremely happy with that asset, considering it one of the best they’ve picked up in the BHP transaction. Even with their strategy shift, I suspect this asset will continue to be highlighted within their portfolio. We have not encountered any significant alignment issues with them regarding this. If there comes a time they don’t see that asset as valuable, we’d love to discuss that as well. But for now, we remain aligned.

Thank you very much.

Yes, thanks. Question on the 2021 plan in the DUCs. How should we think about that? Do you expect to work through the DUCs in 2021? What are those decision points?

We’re still finalizing our 2021 capital allocation, so it’s a little premature to say how much. I do know we’ve got 22 DUCs in the Eagle Ford that we DUCed in the second quarter. Those are definitely going to be utilized in early 2021, giving us a good start to production that year. Beyond that, the level at which we may draw down that inventory is still being determined. Generally, you can consider that a normal working level of DUCs. We’re always going to have some inventory, but there are a few we could draw down if it seems appropriate.

Right. So just to clarify. Of the roughly 100 DUCs – some of that would just be a normal work-in-inventory, is that accurate?

That’s right.

Yes, yes. Okay. Fair enough. And then with regards to the special dividend, 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 once you start to initiate it, and it could be off and on depending on your view of the commodity and macro conditions. Is that a fair statement? Or are you designing this to be something shareholders can expect regularly?

We are very dedicated to the cash return model for shareholders. We feel that we’re the first to take action with a special or variable dividend. There can be a few different cases for this. One is when we anticipate extra cash from the Barnett Shale. The second is, as we generate excess cash flow from our ongoing business, we will return that to shareholders. However, are we going to be formulaic about that approach? No. We won’t be saying we’ll do a specific amount every quarter. When we’re confident we have generated excess cash flow beyond our company needs and are limiting growth to 5%, you can expect us to return that cash to our shareholders. We’re just not being very specific as to how that might look. Jeff may have additional comments on this.

Scott, no, I think, Dave said it well. Our traditional quarterly dividend will return cash to shareholders throughout the year. Depending on market conditions, we'll evaluate what makes sense for the variable dividend. Our expectation is, with our break-even levels, you can use whatever price deck you prefer, but we should generate free cash flow moving forward. Our plan is to return that to shareholders through both dividends. As for timing, we’ll confer with our Board regularly, at least quarterly, to evaluate what makes sense based on market conditions and our other objectives.

You might look at Slide 13 in our operations report as well, which shows amounts of free cash flow we could yield at maintenance capital at various WTI prices. We anticipate significant free cash flow and withholding returns to shareholders.

Understood. Thank you.

Good morning, gentlemen, and thanks for taking my questions. A lot of ground has been covered on the cash return side. You mentioned in your slides that the buyback is still 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. In the past, we’ve used share buybacks to return cash to shareholders. However, the feedback we’ve received from shareholders has been clear and consistent around cash returns and cash dividends. Going forward, our absolute expectation is to return the cash through dividends rather than stock buybacks.

Great. That’s helpful. On Slide 12, you’ve discussed the financing cost reductions of $75 million, and you also mentioned about $125 million in reductions from LOE and GP&T. Granting there may be many moving parts, could you help us understand the targets and how you are improving your LOE? Particularly, I’m interested in how you’re improving your GP&T going forward?

The $125 million of LOE and GP&T cost reduction that we highlighted includes about $65 million from the minimum volume commitment in Oklahoma that rolls off in 2021. Beyond that, we’re seeing lower costs across all our categories. David mentioned some of this earlier. It includes chemicals, compression; our teams have worked hard to reduce costs as we have changed our activity levels. Some of that is indeed the benefit of deflation we’ve seen lately, but we’re locking in many of those lower costs, believing we can keep them sustainable into the future. I’ll let David provide any additional details he may have.

Jeff, I think, you covered it well. From an operational perspective regarding LOE, we always start by trying to reduce downtime. We’ve instituted decision support centers that provide real-time data on our operations, allowing quicker responses to downtime events, and in many cases, we can predict them and proactively address them. It varies by area how we handle specific line items based on asset nature. Still, Jeff covered it well—compression costs, chemical costs across the Anadarko and Eagle Ford are key focuses. In the Rockies, we’re piloting additional technology opportunities to automate operations. This approach has halved our downtime year-over-year while improving costs and environmental performance. We believe we can get our recurring LOE in the Rockies down from approximately $6.50 to mid-4s. We see this as a significant step change. In the Delaware, we’re leveraging critical infrastructure from both water and otherwise to manage and keep costs down.

Excellent. Thank you so much.

Thank you. Good morning.

Good morning, Brian.

I wanted to follow-up on that growth outlook. If we find ourselves in an above mid-cycle scenario, i.e., prices above $50, would 5% still be the maximum growth outlook? Is that correct?

Yes.

As you think today…

Yes.

Okay. I guess as you think about the impact of having a growth rate that’s a little slower than before, does that impact or limit the consideration Devon would have regarding M&A and consolidation?

M&A consolidation is recognized as potentially beneficial. Overhead is currently too high in the entire E&P system. If consolidation can reduce overhead and capture operational synergies, there can be benefits. I don’t see the limitation of the growth rate significantly affecting that. Many companies are pivoting to the same model that we are. We might be more advanced in implementing this model than they are. This strategy can be suitable for acquisitions if it seems appropriate.

Fair enough. My follow-up relates to base decline rates. Assuming you’re at or below that 5% growth level, how do you see your corporate base decline rate evolving? Where have you been most effective in managing that base decline more recently?

Brian, it's David. Entering 2020, our decline rate was in the high-30s percent on oil and low-30s on a BOE basis. As we roll forward a year, we expect the oil decline rate to move to the low-30s and BOE to the mid-20s. It's been a big emphasis for us to arrest base declines and deploy workover capital effectively. Our teams have done an excellent job to shallow declines as much as possible, especially as we move toward this cash return model with moderate growth.

Great. Thank you.

Good morning, and thanks for taking my questions. 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 going forward? Any surprise learnings throughout that whole process during the quarter?

Hey, Brian, it’s David. Good to talk to you again. No, I wouldn’t say there were any surprises or differences in our approach. As we think about flowback strategy, that’s important to our operations. We do occasionally experiment with that. We will have projects where we restrict flowback for interference testing and others, but nothing major or transformative that would change how we conduct business going forward.

So it sounds like we should anticipate a return to normal in the second half of the year concerning completions?

Yes. I think that’s right.