Devon Energy Corporation (DVN) Earnings Call Transcript & Summary

Good afternoon. This is Arun Jayaram from JPMorgan's E&P Research team. Our next presenter is Devon Energy. Very pleased to introduce Dave Hager, who's the President and CEO of Devon, which is a diversified E&P company with key operations in the Delaware, Anadarko and Powder River Basins as well as the Eagle Ford and the STACK. The company has been one of the leaders in terms of returning significant capital back to shareholders under Dave's tenure. He also represented the industry at a recent gathering at the White House with the President and key members of the administration to discuss solutions to the COVID demand response. With that, I'll turn it over to Dave for today's presentation. Dave?

Thank you, Arun. It's a real pleasure to be with you and to be with everyone out there. Really pleased to have the opportunity to tell the Devon story. On Page 2, you'll -- I do have to say before I get started, the presentation is going to have forward-looking statements. The actual results can differ from the projected results, and you can look at our SEC filings for a discussion of the risk factors. Moving on to Page 3. Well, what really defines Devon at this point? I think it really starts with the fact that we have a very strong multi-basin portfolio. We think we're in inherent advantages to having a multi-basin portfolio, but we just don't have just any ordinary multi-basin portfolio. We have acreage positions within those basins that are right at core part of each of the basins, which obviously helped to facilitate strong economic returns. We also have a very strong balance sheet with great financial strength, great liquidity. I'll go through a little bit more detail on that as well. We're a disciplined company very much. We're a returns-driven company, and we've been delivering outstanding results recently from our portfolio, and I'll go into some of those details as well. And then finally, as Arun said, we are very much focused on returning value to shareholders. We have done that consistently over the past few years, and we certainly are a leader in the new model that is more of a cash returns-based model that everyone has started to talk about. We certainly have been advocating for that and moving and -- execute in that direction and then moving further in that direction. So I'll talk about that some more as well. If you move on to Page 4 and you look at our financial strength and liquidity, we have tremendous financial flexibility of about $4.7 billion of liquidity. That's composed of about $1.7 billion of cash, which -- that doesn't include, by the way, the $170 million of deposit from the Barnett. And then in addition to that, we have a $3 billion unsecured credit facility and have no debt maturities until near the end of 2025. We think our balance sheet is really a competitive advantage versus our peers. It gives us a great deal of flexibility about how we approach the current environment. So with that, I would like to talk a little bit more about how we're going to behave in the current environment. If you move on to Slide 5. It gives some more details on that. I think, obviously, the most important thing is to protect our financial strengths. We have our revenue protected by a hedging program. We're approximately 90% hedged in 2020 with a protected price of $42 WTI on the oil side, and we're continuing to fund the dividend. We look very much at the dividend as a long-term return to our shareholders. We don't want to change this on a short-term basis. And we -- certainly, with this cash return model that is an important component of the value we're going to be delivering to the shareholders, while at the same time, we have moderate growth. We've also focused on reducing capital and operating expenses this year proactively, we've reduced the capital twice already. We have reduced our costs as well. I'll detail those out in a little bit more. So overall, we still feel there is a lot of uncertainty in the environment that we're in. But we're in great shape regardless of how the outcome is, and we think we can win in any scenario with a deep asset base, the outstanding execution that we're delivering on that asset base and the financial strength. So we can adjust our cap and really adjust with all short-term projects also, so it's easy for us to quickly adjust capital as appropriate. We have the financial strength to do that, and we're delivering outstanding results from an execution standpoint as well. I would like to talk a little bit more about where we've spent the majority of our investments here in 2020. It's in the Delaware Basin. So if we can move on to Slide 6. It really shows where we've invested the bulk of our capital program this year. It is in the 75% allocated to the Delaware Basin. We did reduce our overall capital program from around $1.8 billion. We advised it at the beginning of the year. We've done a 45% reduction to about $1 billion. And again, we are right in the core of Lea and Eddy County, the most prolific part of the Delaware Basin. Overall, we have about over 250,000 acres in the Delaware Basin. Really can produce strong economic returns in the heart of this basin. We are shifting our activity more to the Wolfcamp in the Delaware Basin. And this map highlights some of the results that we've delivered here in the Wolfcamp in each of our 5 core areas. And the story really even gets better when you start talking about the well productivity that we have realized in the Delaware Basin as well as the cost reduction. So if we move to Slide 7, you can get a feel for that. On the left side of that slide, that is actually the oil EURs for the first 180 days of the well, first 6 months of the well compared to our peer group. And you can see that we're at the top of the peer group. And then on the right side of the slide, you can see the tremendous improvement in capital efficiencies that we have achieved over the past couple of years, with an overall drilling and completion costs down 42%, 58% improvement in drilling efficiencies and 83% in completion efficiencies. To a peer group leading, we believe, $705 per foot on a drilling completion side. If you add in approximately $100 for all the facility -- $100 per foot for all the facilities and take it through flowback, still we think that is right at the best that anyone is delivering in the industry. So if you couple together both sides of this slide, when you have the highest oil productivity along with costs that are as good as anybody out there, you can see why our returns are as good as anybody in the industry and why this is where we have focused our activity through 2020. And I think a common theme that I'm going to tell you throughout this presentation is we're not done. We're certainly proud of what we've accomplished so far. We still think there is room for even improve on these even more than what we've done. We've got some leading wells that are even beyond the averages that I've just described. And so we're confident that we're going to be able to continue to lower the drilling and completion costs and also improve the economics at the same time, which will allow us to obviously lower our maintenance costs in the future as well. So moving on to the -- to next slide, where we do talk about maintenance capital cost improvement. We estimate now that the capital levels have been reduced -- the maintenance capital levels have been reduced to about $1.1 billion in 2021, or they will be. That's about a 20% reduction from the current levels. That's really being driven by, again, the increased efficiencies that we have realized, particularly in the Wolfcamp, but also in other areas as well to some degree with lower service costs. And even with a significant reduction in capital investment, we do expect to have stable production in 2020 this year versus 2019. In 2021, we expect to have a resilient production outlook compared to the second half of 2020. And we're going to have about 100 DUCs at year-end, provide us the opportunity to really jump-start the program in 2021. So we're -- when we talk about maintenance capital here, we do not assume any sort of drawdown of the DUC inventory. I know some others when they talk about 2021 maintenance capital, they include drawdown of DUC inventory to get what their maintenance capital is or breakevens are where we say that's not a long-term sustainable thing. So we don't -- we exclude that kind of 1-year-type effect. We really look at it from a constant DUC inventory. And as I said, we're not only focused on being more capital efficient, we also have been focused on driving down the cost structure through the company. So moving to Slide 9. On that, you can see that we have continued to improve the cost structure. Our cost -- cash cost expectations are going to be down approximately $250 million versus our original expectations for the year. We've made a lot of improvements going back to 2018. We've divested our higher-cost Canadian assets. We've optimized the workforce. And it's really helped to lower the overall cost structure of the company. When I took over as CEO, I can tell you that we had about 5,200 employees. After we divest the Barnett, we're going to be at about 1,550. So much improved competitive nature on the G&A side. And I can tell you when we think about costs, just as we think about capital. We have an attitude of continuous improvement, and we're not done working on this. So we'll continue to focus on this because we think it is so fundamentally important to the go-forward strategy. So we can't control prices, so to have the lowest cost structure we possibly can, while still delivering outstanding results, it is very important. And you don't want to sacrifice costs so much -- or you drive the cost down so much, you sacrifice results. But we still think there's a possibility to lower the cost structure even more. We don't control the commodity price environment. And so the lowest breakeven possible is very important in our industry. Moving on to Slide 10. You can see how we -- our cash flow is going to trend in 2020. We are going to be net cash positive for the year. You can see the breakdown on the waterfall chart there. And again, our revenues are largely protected by hedges, about 90% protected at, at least $42 a barrel. And you see the cash flow is going to exceed the -- our cash cost by about $300 million. It's enhanced, obviously, by about $500 million of proceeds for the Barnett. But again, you can see the capital cost reduction we've done there, the cash cost reduction that we've done as well. I'd also like to talk just a little bit here about ESG. And ESG, for us, has been deeply ingrained in our culture even before it really had the formal term ESG. We have always felt as a company at Devon here that it is important to be a good citizen in the communities where we operate, to do our operations in a very safe manner. And we have a motto here, it is always do the right thing. And even when no one is looking, we often add to that as well. And it's just a culture that we have at the company. Now we have obviously enhanced this even more as ESG has become a focus. And so when we think about it at Devon, we think you have to have strong assets, you have to operate those assets very well, execute on your capital program extremely well, maintain financial strength, and we're thinking now net debt-to-EBITDA of 1.0 or less. But in addition to that, ESG is important. And so we have focused on that as well. There are a number of organizations that are listed on the lower right of this slide. We're somewhere between top half and top 10% by essentially every one of these. We have incorporated certain ESG metrics into our compensation structure. We have a methane intensity-reduction target individual to our company. And so this is -- I could go on, I'm going to be a panelist tomorrow morning at the conference to talk about it more. So I'm not going to go in too much detail here. But again, we think it's important just as to have high-quality assets, execute on those assets extremely well and to have financial strength. So moving on to Slide 12. I talked about that we think that there's a new model out there for the industry. And I've been pretty vocal about the fact that we don't think it's appropriate to maximize production growth, spend all your cash, maximize production growth, maximize NAV but not return cash to shareholders along the way. And we think that a more cash-oriented model is more appropriate where we return value to shareholders along the way while we moderate the production growth as we move back to a more normalized environment, that's exactly where we're going to be. So it's going to be a disciplined strategy. We're going to have strong assets. We're going to execute extremely well to drive down the capital -- or drive up the capital efficiency, drive down the cost, lower the breakevens, moderate the growth and return cash to shareholders. As we are fortunate enough, which is obviously not the case right now but as we're fortunate enough to have higher commodity prices, we'll be returning that excess cash to shareholders. So we're really excited about where we are at Devon. We've executed largely on what we've needed to do strategically to position the company well. But again, there's the attitude of continuous improvement, and we're not done. So that's my presentation for today, Arun. We'll be glad to take any questions.

Great. Dave, thank you again for your presentation, and we do look forward to your ESG panel tomorrow morning and I think it's going to be one of the key presentations for tomorrow.

Dave, I've broken down my Q&A into a few different topics. And my first broader topic, obviously, you did highlight some of the response from Devon to COVID-19 and in terms of the amount of capital that you're cutting. I did want to see if you could talk about your expectations around free cash flow this year. Obviously, depressed commodity price environment, you had 90% of your volumes hedged. But where do you expect the company to be from a free cash flow perspective this year? And also, if you could maybe talk a little bit about the steps you need to take to close that Barnett deal later in the year, which would obviously even further improve your balance sheet?

Sure. And I think there was a slide in there that showed that overall, with including the Barnett proceeds of about $500 million, we'll be free cash flow positive by about $300 million. So just slightly less in free cash flow this year without that. So -- but close. And frankly, with where our capital costs are trending, it may be even a little more positive than the way I'm describing it right now. If you look at it in the future, and again, we don't assume any sort of drawdown of DUC inventories in these numbers here. But we see that it takes -- right now, approximately $40 WTI for us to be cash flow neutral at maintenance capital. But again, that's a current estimate, and that's no assumption around further cost reductions or around capital efficiencies beyond what I've already described. And I'm very confident those are continued. So we're going to drive those down even more. And that's $40 without a dividend, with the dividend, yet another $2 or $3 to that currently. But again, we think there's going to be significant room to improve that in future years. And again, that's some of -- I know a lot of people when they talk about that for 2021, they assume some sort of drawdown on DUC inventory when they describe what their breakeven price is. And this is not any sort of drawdown of DUC inventory. We certainly have that optionality, but I haven't assumed that. And in regards to the Barnett, really, it's -- we think it's very high likelihood of closure. We have $170 million deposit that's in the bank right now. The effective date versus the closing date is going to provide $100 million-plus of cash flow that would accrue to the purchaser. So if you think about it, we're going to have $270 million into this, and you compare that to the purchase price, it's the incremental cash that they have to come up with and the incentive to come up, frankly, with that incremental cash is pretty strong. So we feel really confident that it's going to close. We obviously had anticipated an earlier close. So from a transition standpoint, we're really in good shape. It's just -- I want to give a little more flexibility to the purchaser, given what they were going through as well during this very difficult time to make sure they feel comfortable about it, but we're confident it's going to happen.

Great. Economic shut-ins have also been a key topic with the investors. Your -- the level of shut-ins that you articulated on your 1Q call is quite a bit lower than peers. But could you maybe provide a little bit of color around how much volume did Devon eventually shut in? And your views, June, July nominations, how that's -- your current outlook on that?

Sure. And when we -- and I tend to talk about more, what I call curtailments versus pure shut-ins. Because, in our mind, curtailments includes both actual shut-in as well as new wells that we are just choking back. And frankly, if you look at some of the productivity on some of our new wells in the Eagle Ford, they haven't been quite as high as historically. That's just to cover keeping them on much smaller chokes. That's no ideal productivity of the reservoir. So in Q2, we've anticipated to have about 20,000 BOE per day curtailed and about 10,000 barrels of oil. So 20,000 equivalent, 10,000 oil. And of that, really is about 8,000 from just choking back wells or slightly delaying wells and 2,000 actual shut-in. So not very much. And you might say, why is it so low on the shut-in? Well, a couple of reasons. Again, the areas where we have -- first, we've tremendously high-graded the portfolio. So we don't have a lot of old legacy assets that have high levels of fixed costs compared to the variable. And so that's not really an issue for us. We don't have exposure, frankly, to some of the areas that had the highest differential, whether that be in Alaska or the Bakken. And then additionally, our marketing people were really good, and they anticipated the issue that was going to come up in the Delaware with regard to the production getting lighter and the development of new crude grade of WTL. And so we built into our marketing agreements that even if we produce crude at that API gravity, we get the Midland pricing. So we were not subject to the WTL blowout. And so you put all those factors together, we look at obviously, revenue versus variable expense and make a decision that way. And the -- additionally, I would say there was some thought, and I understand, well, if you got significant contango, maybe that justifies it. I mean I think the reality is we have to keep in mind that you nominate a month before you actually know the prices. That's the way it works in our model. And so what's happened in reality is that significant contangos, some anticipated, didn't play out in reality [indiscernible] of prices recovered so much. And so when we look at June, we're in the process of bringing all of that back on. And with prices where they are now, if they stay above $30, I wouldn't expect any significant curtailments from us in Q3 or beyond.

Great. We're going to switch gears and talk -- in terms of the topics, talk a little bit about the individual basins. Firstly, capital allocation. We've been looking at kind of operator activity levels and perhaps supporting the attractive low breakevens. We've noted that Devon has still kept one of the larger programs active in the Delaware Basin. I think you've recently been at 10 rigs, maybe that's trending down. But maybe talk about the ability to sustain, call it a higher rig count, than your peers during this period just to kind of sustain the operating -- the efficiencies and things like that during this difficult period.

Sure. And we have focused our capital back on the highest return area in our portfolio, which is in the Delaware Basin, and we shifted more to the Wolfcamp as well. And the slide in the deck really kind of tells the story there that when you couple peer-leading oil EURs on a 6-month basis, which is the best we can do to estimate the overall productivity of the well, at least early on, you couple that with industry-leading or near industry-leading costs, you can see that -- that shows that we're going to have as good a returns as anybody out there on the portfolio that we're executing. And furthermore, it really makes sense to just concentrate your activity when you have lower levels of capital investment. That way, you can really balance out how many rigs you have running versus the number of completion crews you have. And for us, it has been up around 10 rigs, we're going to be around 8 here by the end of June. And we're going to be essentially having, give or take, site variations occasionally in the program around 8 rigs and 2 completion crews working in the second half of the year. And that's a fairly optimized mix. And again, it helps to concentrate versus having one-off rigs, like you might have otherwise. But again, we're not so much constrained by returns. We're more constrained by how much cash we want to spend to maintain our financial strength in this period where there's a great deal of uncertainty. We're all feeling a little bit better with the reopening. But also -- it's just a great deal of uncertainty still. Is there going to be a second wave of the pandemic? Can there be a demand impact on that? So we're going to approach it -- even though we have a great balance sheet, significant liquidity, we are approaching it from a conservative standpoint while at the same time, keeping some operational momentum going so that we can come out of this as appropriate with whatever the right level of activity is depending on where prices end up. So again, I think we can win either way. We have the financial strength to be successful when prices are low and if they stay low and we have the inventory and the execution and we have -- since they're all short-term projects, it's a lot easier to adjust our capital spending, and we can adjust it on really high-return projects when the right time comes.

Okay. And just to synthesize your thoughts on outlook comments called on production is 2020 pretty similar to 2019 on the oil side. And then if you spent $1.1 billion, you could hold, is it the back half or the fourth Q kind of exit rate flat, that would be your sustaining CapEx number as we sit here today?

Yes, that's essentially right. So I -- the overall year is going to be flat we think but we will be declining if you look at Q4 '19, which is [ I think ] anomalously high month for us because we had a lot of really high-impact completions in that quarter. But even if you take that as a reference point against Q4 of '20, there is going to be a decline of approximately 10%, even though the average for the year will be approximately flat. And that will take us down to probably somewhere around 140,000 barrels of oil per day. And then we think with the capital that we're talking about, we can roughly keep production flat in 2021 and live within cash flow. Well, not -- well, with the maintenance capital of $1.1 billion.

With the maintenance Capex. Yes. Okay. A couple of questions left. I did want to talk about the cost reductions in the Delaware Basin. Impressive, you're in the low 700s on a per foot basis. Quickly, what is driving the lower cost at Devon relative to your peers? And how much more room do you have to further reduce your D&C costs on a per lateral foot basis?

Yes. And that's probably 75% or so driven by just efficiencies versus service cost reductions. Now we've assumed overall about 10% service cost reductions across our entire portfolio. Frankly, we think we're going to do a little bit better than that. But the bulk of the improvement is really through increased efficiencies. So first, on the drilling side, if you go back a couple of years, we used a larger hole design and then we adjusted and went to a slim hole design. The slim hole design had some -- a lot of positive characteristics. But we did have some issues with that design, I would say, with just the cost of slim hole tool rental and the reliability of those tools. And so we then went to a well design, it was slightly larger than the slim hole design, to eliminate the need for those rentals. And then frankly, we just started getting a lot of repetitions on that, and we really leaned out the, what I call the flat time, the nonproductive time. We have very sophisticated geosteering techniques that we use. We maximize the amount of time that we -- the bits last in each section of the hole, just a lot of all incremental improvements that our team has been able to do to drive down those drilling costs at what they're focused on every day. And a similar story on the completion side, I would say, it's having the same crews, eliminating nonproductive time, particularly when you're doing zipper fracs and the time that you move back and forth between wells, things like that, that have driven it. And we're not done, as I said. I mean we've got -- we've had some activity even better than what I'm describing today and team's optimistic that they can continue to reduce dock cost. And it's just -- some of it is hard to describe, frankly, Arun, but it's just a very tight interaction that we have with our teams and the focus on it, coupled with what we think is an improved casing design.

Dave, we're running out of time. I was wondering if you could quickly give the audience a little bit of an update quickly on what's going on in the Powder River Basin in terms of your delineation of the Niobrara?

Sure. Well, we are still in what I would consider the appraisal phase for the Niobrara. We think it's potentially productive across 200,000 acres. We completed some wells earlier this year that had demonstrated that we have -- we do have a viable reservoir. It's more of a shale with 3 chalky intervals. We tend to complete it in the middle layer of the chalk. We found with our fracs that we are fracking down into the lower layer, the C, but probably didn't reach up the A because we tried a little bit lower, smaller completion design. We're getting ready. We're actually bringing on right now, some wells. We used a little bit larger completion design that we think may stimulate all 3. So we didn't get quite the rates we anticipated, but we do show that we have a nice productive reservoir. And we still have a ways to go on the well costs, obviously, because we haven't really moved and we're doing a lot of science, and we haven't moved into the full development mode like we have at Wolfcamp. So the wells will trend to cost over $8 million. We think we can get that down below $7 million. And we're optimistic. Now -- and mainly, this is more of an oil price, but very sensitive oil prices, it's more like 80% to 90% oil. And so at these prices, it's pretty marginal to noneconomic, down below $40, I would say. But as we get improvement in prices, coupled with optimized completion design, lowering the well cost, we think it's a play that will compete for capital in the future.

Great. David, on behalf of the JPMorgan Energy team and management, thank you so much for participating in today's virtual conference and look forward to seeing you in the future. And again, thanks to you and your team.

Great. Thank you, Arun.