Welcome to Devon Energy’s Third Quarter 2020 Earnings Conference Call. [Operator Instructions] This call is being recorded. I’d now like to turn the call over to Mr. Scott Coody, Vice President of Investor Relations. Sir, you may begin.

Good morning, and thank you to everyone for joining us on the call today. Last night, we issued an earnings release and presentation that cover our results for the third quarter and updated outlook for the reminder of the year. Throughout the call today, we will make references to our 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; 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 the 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 for your interest in Devon. For the purpose of today’s call, my comments will be centered on three key points, our outstanding third quarter results, our improved outlook for the remainder of the year and the benefits of our recently announced merger with WPX. On Slide 7 of our earnings presentation, I’ll begin my prepared remarks by covering a few key highlights from our outstanding third quarter results. Across the portfolio, our teams are responding to a challenging operating environment by delivering results that continue to exceed production and capital efficiency targets, while successfully driving down per unit operating costs and maximizing margins. This is evidenced by several noteworthy accomplishments in the quarter, including oil production exceeded midpoint guidance by 6,000 barrels per day, complimented with capital spending that was once again below forecast. Furthermore, we continue to expand margins through improvements in our cost structure, headlined by operating expenses of 8% below guidance and G&A costs are reduced 30% year-over-year. With this strong operational performance, we generated $223 million of free cash flow in the quarter. And just after quarter end with the closing of the Barnett transaction, we paid out a $100 million special dividend. All in all, the third quarter is an excellent one, both operationally and financially, as we executed a very high level on every single strategic objective that underpins our business model. This strong performance is a testament to the hard work and dedication of our team. And I want to thank our employees for their continued commitment to excellence. Moving to Slide 11. With the strong results our business has delivered to date, we’re now raising our outlook for the remainder of 2020.…

Good morning, everyone. As Dave touched on, Devon’s operations are hitting on all cylinders as we have repeatedly delivered best-in-class results over the past several quarters. Turning your attention to Slide 8 of our earnings presentation, our world-class Delaware basin asset is the capital efficient growth engine driving Devon’s operational outperformance in the third quarter. With our capital activity, almost exclusively focused in the Delaware, our high margin production continued to rapidly advance growing 22% on a year-over-year basis. During the third quarter, our operated activity consisted of nine drilling rigs and three dedicated frac crews resulting in 32 new wells commencing first production. With most of these completions weighted towards the back half of the quarter, only 14 of these new wells meaningfully impacted production totals in the third quarter by attaining peak production rates. Overall, initial 30-day production rates from these 14 wells average an impressive 3,900 BOE per day of which greater than 65% was oil. And those Wells collectively rank among the very best results we have delivered today in this world-class basin. While we had great results across our Delaware basin acreage position in the quarter, new well activity was highlighted by the record setting well productivity from our Cobra project in Lea County. This two wells three mile lateral development targeting the XY sands in the upper Wolfcamp achieved average 30 day rates of approximately 7,300 BOE per day or 475 BOE per 1000 feet of lateral. These wells drilled in the deepest part of the basin or the longest wells drilled in the history of the Delaware by measured depth and are the highest rate Wolfcamp wells, we have brought online to date at Devon. Importantly, the capital cost for the Cobra project came in nearly 20% below our pre-drill expectations. Our result…

Thanks, David. My comments today will be focused on a brief review of our financial results for the quarter and the next steps in the execution of our financial strategy. A good place to start today is by reviewing our financial performance in the quarter where Devon’s earnings and cash flow per share comfortably exceeded consensus estimates. Operating cash flow for the third quarter totaled $427 million, a rebound of nearly 200% compared to last quarter. This level of cash flow fully funded our capital spending requirements and generated $223 million cash flow in the quarter. At the end of September, Devon had $4.9 billion of liquidity, consisting of $1.9 billion of cash on hand, and $3 billion of undrawn capacity on our unsecured credit facility. Subsequent to quarter end on October 1, our liquidity was further bolstered by the closing of our Barnett Shale divestiture. For those of you not familiar with the transaction, we agreed to sell our Barnett Shale assets for up to $830 million of total proceeds, consisting of $570 million in cash and contingent payments of up to $260 million. After adjusting for purchase price adjustments, which includes $170 million deposit we received in April and accrued cash flow from the effective date, we received a net cash payment at closing of $320 million. In conjunction with the closing of this transaction, we returned a portion of the proceeds to shareholders by way of a $100 million special dividend. This special dividend was paid on October 1 in the amount of $0.26 per share. With the excess cash inflows, our business is on track to generate in 2020. We expect our cash balances to exceed $2 billion by year end. The top priority for the large amount of cash we have accumulated is the repayment…

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

[Operator Instructions] Our first question comes from Doug Leggate with Bank of America. Your line is now open.

Good morning, guys. This is actually Kalei on for Doug. I’ve got two questions, if I may. Both are related to public policy on oil and gas. So under a potential Biden administration, obviously, if there is a risk to the industry. Firstly, what’s your understanding of the potential of subsidies to the industry that could be targeted? And specifically, I’m thinking about items like IDCs or even a minimum book tax that could raise cash costs on the business. How would this change items like your breakeven and how you pursue your activity levels?

This is Jeff. To be honest, I don’t have a lot of specific details around any changes that the Biden administration is planning or as talked about, certainly to the extent that IDC were to be limited or changed in some way that would be impactful, certainly to our financial results and the taxable income that we would generate as a company. So that’s something, we’ll certainly, have to be on a watch for and be mindful of, but we don’t have any specific details at this point in time.

All right, thanks. For my second question, I just like to ask for an update on your federal acreage plans. How many permits have been secured? To what date does that bring you to? And if that window – if you anticipate that window closing under a new administration, to obtain permits, what’d you think that would close?

Well, I’ll start off here and David can provide detail. So I think we’ve said in our prepared remarks, so we anticipate having about 650 federal permits by the end of the year. 80% of those are going to be in the Delaware basin or about 520 federal permits in the Delaware basin by the end of the year is our anticipation. The key point of that is that covers four years of activity that we would anticipate in a Delaware basin. And that’s keeping in mind, when I say that even under the maintenance capital scenario or production overall for the company would remain flat. That means though in the Delaware basin, we would be growing our production. So that’s a level of permits that would allow production to actually grow in the Delaware basin while keeping the overall production for the company as flat. And the other thing, I’d mentioned too is keep in mind, we are very well aligned with the state here. The 40% of the revenue in New Mexico comes from oil and gas activities. And the state understands extremely well. Governor Grisham who’s on the Biden transition team understands and supports very much oil and gas activity in the state. So I know there’s a lot of discussion around this and I understand, if why, but the alignment with the state and what we do as an industry for the state to help out with other social needs that the state has is extremely important. And everyone in the state of New Mexico understands that. And so it’s a great hypothetical question, but frankly, we think most likely is that things will slowdown. But there’s not going to be a stopping of activity on federal acreage. Even if there is, we have four years worth of activity covered with the permits we anticipate by the end of the year. So David, did I miss anything there?

No, you didn’t. I couldn’t have said it better myself. I think you’ve covered all the relevant points and agree with everything you said.

Guys, I appreciate that answer. Maybe if I get to that follow-up for clarification, I’m just wondering if any of the 650 permits that have been secured, if they require any extensions by the federal government, because four years is obviously a long period at the time?

Yes. Federal permits are issued with a two-year term and then you have the ability to extend them for an additional two years. So certainly, permits that are out would be out past that two year-term, would require us to go through the extension process. But a couple of things I’d point out to you there, we’ve never had an extension denied before. And it’s important to know that the permits are under lied by environmental assessment. That’s done as part of the permitting process and those environmental assessments are good for a period of five years. So the answer to your question is yes, but we don’t foresee many material impacts from that.

Perfect. I appreciate it guys. Thank you.

Our next question comes from the line of Brian Singer with Goldman Sachs. Your line is now open.

Thank you. Good morning. Another topic that’s come up here and with some of the M&A that’s happened in the Permian basin after the Devon WPX announcement is the topic of decline rates. And you highlighted the very strong well performance that you’re seeing and have been seeing in the Delaware basin. And I wonder if you could give us an update on where you see your Permian and corporate decline rate and how you expect that to evolve in 2021 in a maintenance program?

Good morning, Brian, this is David Harris. Yes. As we’ve talked about in the past, if you – just starting with our year ends reserve report that we filed last year, if you look at those decline rates on a company-wide basis that put us in kind of a high-30s percent on an oil basis and in the low-30s on a BOE basis. As we move forward into this year and as we’ve been moderating capital, then combined with some of the fantastic work that the teams are doing from a base production perspective, which we continue to see outperform quarter-over-quarter. Our expectation is that on a company-wide basis, that oil rate would move from the high-30s to the low-30s and on a BOE basis down into the mid-20s.

Great. Thank you. And then my follow-up is also with regards to the Permian. On Slide 10, you talk about in some detail the various projects that you have and where and the order of completion, drilling and production they lie. And I wondered as you contemplate the WPX acquisition. And you think about where a maintenance drilling program between the two companies where you would prioritize, how would you see the Devon legacy drilling activity, evolving, how would this, the main areas that you highlight on the top left of right hand? Would you be drilling more – fewer wells there? How would you think about the prioritization in the context of having WPX assets?

Well, we’re still in the process of developing a – obviously, a combined 2021 capital program. We don’t have anything specific to leg out there. But obviously, in the Delaware basin, where we’re drilling the legacy Devon wells, we’re delivering best-in-class costs for these wells. Productivity that’s as good as is about anybody out there. And obviously, even get a little bit of advantage of a lower royalty rate on federal acreage as well. And so the economics on the Devon legacy activity are incredibly strong. Probably on average, I’d say even a little bit stronger than the WPX, but the WPX is extremely strong also. And that’s why we like it. But it’s hard to talk, what you can do right here in Lea and Eddy County. And so I’d see, we haven’t gotten – we haven’t developed any sort of combined budget, but it’s – they’re both highly economic areas, probably the overall edge on an average basis would probably go to the activity in Lea and Eddy County on the federal – on the Devon legacy, Devon acreage.

Got it. Great. And the last one, if I could just add one more of the $560 per foot, the cost that you achieved in the third quarter of 2020. Do you care to hazard a forecast for where that could be in 2021 in a maintenance type scenario?

Well. We have been highlighting improved performance on a cost per foot basis every quarter for the last couple of years. I mean, we just continue to find ways to step that down. And to your comment about hazarding, I guess, frankly, to points to levels that I’m not sure I would’ve thought, we could get to. And so I think a lot of what we’re doing here, there is a bit of service cost inflation in there. But I would tell you in my mind, probably three-fourths of the improvement that we’re making, here over the last quarter – in the last several quarters is efficiency driven. And so we believe that’s going to be more structural. So we absolutely believe we can carry forward these levels and continue with rate of change. As we move forward into 2021, and we think that’s going to be a nice capital efficiency tailwind, and another leg to the capital efficiency story. Brian, one thing that, people will say, why are you doing this? How can you do this? Well, I’d say one of the big things that we have going for us is that we went – we were the first ones to go to 10,000 foot laterals in the Wolfcamp out here. And we admittedly, we had a few wells and at the beginning, where I’d say we stubbed our toes a little bit, they were challenging at first for us. Most industry are drilling 7,500 foot laterals. We went to 10,000. But because we went early and we figured it out and we went up – what we call a modified swim hole design, that design has turned out to be very robust and be the appropriate design that we have now stayed with for a long time. So we have many, many reputations of drilling the same type well over and over and over many more than I think that many of our peer companies out there with this particular design. And that just allows us to be further down on the efficiency curve. Now, are we done? We absolutely are never done. No way. But I think if there’s a question – this almost seems too good to be true. Why are you able to do this? I would say those are a couple of the big things, as well as allowing us to optimize our costs from our vendors when you go to that fixed design like that.

Thank you.

Our next question comes from Neal Dingmann with Truist Securities. Your line is now open.

Good morning, guys. Dave, my first question for you or Jeff, is to get kind of talked about a little bit, that’s really on Slide 14. And you’ve talked a lot about your thoughts about the variable dividend, but I just want to make sure I’m clear. On that Slide, you talk about that the dividend can be up to a 50% of excess free cash. I’m just wondering when deriving that or thinking about that, how should we think of that prior to that, where you want the debt level – is that once you get the debt level to a certain point, and once you have growth at a certain point, I’m just wondering how I should think about that when sort of factors in leverage and the growth?

Well, I’ll start off here, and then Jeff can chime in. So what we’ve said and I’ll talk about the combined Devon WPX here, pro forma that we are breakevens for maintenance capital would be $33 WTI. And frankly, with what we’re talking about this morning, it looks like, we’re tending to drive that lower. We don’t have a new number for you today, but obviously the results that we talked about today would tend to drive that breakeven even lower. Then if you add the fixed dividend that would take the breakeven up to $37 and we’ve said that we will invest at maintenance capital levels up to around $45 per share. So we would be building free cash flow in that range. And once we get to $45 we’d mix in a combination of a little bit of growth, select growth, along with it adding to the free cash flow at the same time. And by the time, we get to $50 or so for – from $50 WTI, may I said for sure, $50 WTI, we can accomplish all of our strategic objectives of 5% growth and really strong cash flow yield. So back when we start generating free cash flow, and we think we’re in a healthy enough financial position that we can do a combination of debt pay down and the variable dividend. Now obviously, all you want to maintain some flexibility around how much we do to each. But we think we’re in a good position on both. And so we’ll make judgment calls on how we think the appropriate mixture is, but it’s not like we have to get one done before we start together. We have to have a certain level of growth before start the picks, the variable dividend policy. We anticipate once we start generating free cash, if we see an appropriate commodity price outlook, that we will start the variable dividend policy. So Jeff, can you…

Yes. That’s well said, Dave. But the short answer I would give you is we’re already there. So, we’ve got the cash balance. We feel like we have the strong balance sheet. And we’ve got a constructive view of the commodity price outlook that we highlighted in that step two on Slide 14. So obviously we’ve seen some weakness here in prices this week and that could certainly continue into next year. So we’ll be mindful of that. But as Dave said, in our minds with the combined company, we’re already in a position to where we can deliver cash returns to the shareholders via the fixed and the variable dividend along with accomplishing our debt reductio, target over time. So we feel like we’re there and in good shape.

Great, great details. And then just one follow-up. Dave, you also talk a lot about – I just wanting to make sure I’m clear on this as well, around the term maintenance capital. You had a lot of efficiencies, just a lot of improvements that continue to improve what that sort of level is. On a go forward, how should we – I guess, how do you define that these days? I guess, given all the improvements you have. And how should we think about – when we think about potentially maintenance capital in-depth 2021, how should – how would you like us to think about it?

Well, first off, we’re trying to use what I would consider more of a Webster’s Dictionary book, definition of maintenance capital. It’s not an optimized 2021 maintenance capital. In other words, we’re not counting on any sort of drawdown of DUC inventory in this at all. This is more of a pure how much capital do we think we need to spend, or what price WTI do we need given the capital we need to spend in order to keep production plat without any drawdown of DUCs, if we would draw down DUCs, it could be even better. And so certainly as we have accomplished better capital efficiency along with the cost synergies that we’re anticipating out of the merger that’s what’s allowing us to lower that maintenance capital significantly. I would anticipate that’s going to continue to lower through time as we continue to achieve even greater capital efficiency, more cost efficiencies. And frankly, as Brian Singer brought up earlier as our overall corporate decline rate becomes lower and outer years then the amount of capital required to maintain the production should tend lower also. So what we’re giving you is just kind of a definition of where it is just slamming together the two companies what we both defined as a maintenance capital, I think it was $950 million on the Devon side and the remainder on the WPX side. But again, the results we’re seeing today are tended to indicate that even now it’s going to be lower in 2021. But we’re not giving an exact number.

Very good. Thanks for the detail.

Our next question comes from Derrick Whitfield with Stifel. Your line is now open.

Thanks and good morning all.

Good morning.

I appreciate your earlier comments on federal and state alignment and selection rents are certainly top of mind with investors. Regarding the 650 permits you’re expecting to have on hand at year end, did the permit comprehend any change in development approach from your current practices, including spacing, lateral length, et cetera. And as a slight build on that question, if a negative election and/or regulatory outcome were to occur, could the permit be amended at a layered time for longer laterals, if you needed to accelerate resource to conversion.

Derrick, this is David Harris. Thanks for your question. Yes, 650 permits that we have in hand contemplate our current development strategy around the zones that we’re the most focused on and that spacing as well as giving us some flexibility for some down spacing. To your question about the transition to 3 mile laterals. Just for your background, kind of the quick rule of thumb is, if you’ve got a drilling permit in hand and you make a change, if it doesn’t result in a different level of surface disturbance, you don’t need to get a new permit. You go through, what’s called a sundry process, which is a really quick and routine process that we have. We do these from time to time, when we tweak landing zones or bottom hole locations. And so that’s the process that we would go through as we look for opportunities to incorporate more extra long lateral development into the programs. And certainly with the – not just the results we’ve seen in Cobra but the results we’ve seen over the last couple of years across the portfolio, that’s something we’re actively looking at. We’ve drilled about 30 wells across the company that are 2.5 mile laterals or longer about half of those are in the Delaware, but importantly, we’ve drilled them in all three of our other assets as well. So we’re getting increasing revs there as Dave alluded to and increasing confidence in our ability to make that a meaningful part of the program go forward. And I think you’d expect to see probably a half dozen or so 3 mile wells in the Delaware next year, and upwards of 20%, 25% that our 2.5 mile laterals or longer. So we think this is going to be an important part of our development approach going forward. We think obviously as you saw from Cobra, a big capital efficiency pickup, as we successfully execute this.

Got it. It’s fantastic detail. And then as my follow-up, really more broadly on integration efforts to date, as your teams have begun to work together, are you guys sensing any areas of potential synergy beyond what’s been disclosed?

I think the short answer is, yes. When you get good people together and they start talking about – and I think particularly on the capital side, we’re seeing that there are going to be improvements even just from pure scale on the supply chain and what the incremental scale will provide as well as just optimizing programs as well. Yes, it’s still early days, but I can tell you, there’s a lot of excitement and enthusiasm that the synergies are not only achievable, but we’re going to see more than that. So Jeff and David, you’re even closer to it to me.

No, Dave. I think you hit the high points. That’s exactly right. As the teams have gotten together again, it’s early days still for sure, but already started to think about specific areas across the organizations. And I think there’s no doubt in our mind that we’ve got a lot of momentum there and should see an increase to those synergies over time in most areas.

And I’ll just say philosophically, I think one of the reasons that this – we’re going to make this work so well is, it’s our whole approach to this is a more of a merger of equals. So we’re – both sides are taking the attitude that, okay, we both done well on our own, but are there some things that we can do to create a better company that are even better than either one is individually. And it’s that open-minded attitude about really not focusing on what I do great, or my company does great. It’s more about, okay, we’ve – how can we really create something that’s better than either one of us and not worried about where it comes from, whether it’s from the WPX side or the Devon side, just how can we do better? And I think there’s a lot to be said for just that mental attitude of really trying to take the best from both sides. It’s going to allow even more synergies in a situation where you just have something that’s just much more of a takeover and you don’t learn as much from the other side as you do in this type of situation.

That’s very helpful. All great update.

Our next question comes from Jeffrey Campbell with Tuohy Brothers. Your line is now open.

Hi, Dave. I wanted to ask a more specific WPX question and then one broader question. With regard to WPX, it’s tended to invest elsewhere, then it’s Eddy County assets, whereas Devon has outstanding results there as illustrated on Slide 8. I was wondering if you see the potential to bring some capital to WPX’s Eddy acreage when the merger is complete.

Yes. We don’t have a specific plan, but I mean, they have some outstanding acres just across the state line and an area actually called the state line area as well as their – they picked up from Felix, and in which Felix, we think – and they feel very much so – to did not optimize the development plan on that. So, yes, it’s going to compete for capital very well. I did say, I think maybe on average to Devon’s a little bit better, but the legacy results we have are a pretty high bar to meet. And I don’t know that anybody that we would look at when quite the match up to that. But that doesn’t mean that WPX is really, really good. Frankly, we did quite a bit study on those before WPX acquired both those positions. So we understand those positions pretty darn well. So David, do you want to add anything?

No, I think that’s exactly right. Jeff, you may have been referencing some of the acreage that’s further North in Eddy County that would be kind of Northwest of Potato Basin area. Some of that acreages is operated and our understanding is, is some of its non-operated. But that would certainly be a place as we think about acreage trades and other things that we’d be looking at potential for bringing some of this extra long lateral development approach today.

Yes, that was exactly what I was thinking about.

Sorry, Jeff, I kind of misunderstood your question. I thought you meant…

It was good color anyway, it was fine. Then my broader question is bearing in mind, Devon’s go-forward focused on free cash flow and considering the merger. Is there any part of the portfolio that’s struggling to generate free cash now? And would this be a yardstick for not only attracting capital in the future, but maybe some portfolio management longer-term? Thanks.

Well, we have – as you think about it, we have three areas of generating really strong free cash flow right now. Pro former that will be generating really strong free cash flow at Baken, Eagle Ford and Anadarko basin. Obviously the biggest growth engine with 400,000 really high quality acres in the Delaware basin that’s going to be the biggest growth engine. And then you have the Rockies, it’s more of a longer term growth play. It’s not as much of a free cash flow play right now. And it’s a smaller asset. But it’s a very oily base. And we know there is very good potential in a, in Niobrara there across probably a couple hundred thousand acres or so. And our approach right now, we think is most appropriate, just take a very measured approach. We’ve drilled some Wells there. We’re learning a great deal from the wells we did about what worked extremely well and where our challenge is still lie. It’s probably an environment that is going to – it’s very oily up in the powder. It’s going to take probably $45, $50 oil to really compete effectively for economics, but there’s a lot of hydrocarbon there. So, it’s the one that’s not as strong and contributor currently, but I don’t feel – we’ll obviously look as a combined company. We neither side has been afraid to make the right decision at the appropriate time, but there’s nothing obvious because those companies have really high graded their portfolio a lot historically. And we like the asset base, that’s obviously the stage of each of them. And we understand that, we’ll look at it.

Great. Thanks. I appreciate the color.

Well, it looks like we’ve gotten through our question queue. We appreciate everyone’s interest in Devon today. And if you have any further questions, please do not hesitate to reach out investor relations team at any time. Have a good day. Thank you.

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