德文能源 (DVN) 2017 Q2 法說會逐字稿

Welcome to the Devon Energy Second Quarter Earnings Conference Call. (Operator Instructions) Today's conference is being recorded. I would now like to turn the call over to Scott Coody, Vice President of Investor Relations. Sir, you may begin.

Thank you, and good morning. I hope everyone has had the chance to review our second quarter financial and operational disclosures that were released last night. This data package includes our earnings release, forward-looking guidance and detailed operations report. Also on the call today are Dave Hager, President and CEO; Tony Vaughn, Chief Operating Officer; Jeff Ritenour, Chief Financial Officer; and a few other members of our senior management team.

I would like to remind you that comments and answers to questions on this call today will contain plans, forecasts, expectations and estimates that are forward-looking statements under U.S. securities law. These comments and answers are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance, and actual events may differ materially. For a review of risk factors related to these statements, please see our Form 10-K.

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

Thank you, Scott, and welcome, everyone. Devon achieved another high-quality operating performance in the second quarter, building operational momentum in our U.S. resource plays and accelerating efficiency gains across our portfolio. These successful efforts resulted in record-setting well results that drove our U.S. oil production above guidance expectations with a capital investment that was 17% below our budget year-to-date.

As a result of this strong capital efficiency, we are lowering our full year capital outlook by $100 million and importantly, we have not made any changes to our planned activity levels in 2017. For more details on our very strong performance for the quarter, I encourage every investor to read about our Q2 operations report.

With this momentum, we are highly confident in our ability to deliver value and returns on our investment plans over the next few years as we navigate industry conditions. For 2017, our capital plan remains on track to reach 20 rigs running by year-end, and we expect to maintain this operational momentum in 2018. Importantly, nearly all of this planned drilling activity is concentrated within our STACK and Delaware Basin assets, which are 2 of the very best positioned plays on the North American cost curve, delivering attractive returns even at today's strip prices.

To be clear, we are not chasing production growth with our capital programs and remain keenly focused on maximizing our full cycle returns. With this disciplined approach to the business, I can confidently say that this dril-bit activity is a very appropriate level of investment for Devon in this environment.

Providing additional certainty to the execution of the business plan is our strong financial position. With a disciplined hedging strategy, we have stabilized our cash flow stream by locking in roughly 55% of Devon's estimated oil and gas production for the remainder of the year at rates well above market levels.

Additionally, we're steadily accumulating our hedge position in 2018. With this strong hedge book, we remain on track to invest within cash flow during 2017. Coupled with our investment-grade ratings, no significant debt maturities until 2021, $2.4 billion of cash on hand and the expectation of $1 billion of noncore divestiture proceeds over the coming year, we absolutely have the financial capacity and flexibility to execute our business plans.

Given our ability to organically fund capital requirements, Devon is uniquely positioned to maintain and build momentum in the future as we advance our development programs in the STACK and Delaware Basin. The quality and size of this world-class opportunity set is unmatched in the industry. Between the STACK and Delaware Basin alone, we have exposure to over 30,000 potential drilling locations concentrated in the very best portions of these plays. This premier asset base provides Devon with a sustainable, long-term growth opportunity with the lowest break-even economics of any repeatable resource play in North America.

Additionally, as these assets shift to full-field development, we fully expect to enhance returns as we reap significant efficiency gains from our multi-zone manufacturing work and further optimize our best-in-class operational performance with cutting-edge predictive analytics and artificial intelligence efforts.

Looking to the end of the decade, Devon's differentiated investment story only gets better. Our resource-rich STACK and Delaware Basin development programs will be in full-blown manufacturing mode, and a massive upside potential within these franchise assets will be further defined. As these strategic objectives are successfully met, we expect to take additional steps to further high-grade our resource-rich portfolio.

In fact, as our business evolves over the next several years, we see the potential to monetize several billion dollars of less competitive assets within our portfolio in a very thoughtful and measured fashion. Potential proceeds from these portfolio rationalization efforts will be balanced between accelerating the development of our highest rate of return inventory and debt reduction activities.

With this exciting multiyear transformation, we expect to emerge with a highly focused asset portfolio, and our profitability would be dramatically enhanced as we transition to a much higher-margin barrel. We also intend to have a fortress balance sheet with net debt-to-EBITDA target of 1.0 to 1.5x by the end of the decade. These winning characteristics will allow Devon to deliver consistent, competitive and measured growth rates along with top-tier returns on capital employed.

So in summary, before we move to Q&A, I want to leave you with a few key messages from today's call. First, Devon is consistently delivering best-in-class drill-bit results that reflect our premium assets and operational excellence. With the quality returns we are achieving in the STACK and Delaware Basin, coupled with our outstanding financial position, we are on track to reach 20 rigs by year-end and expect to maintain our strong operational momentum in 2018. And lastly, as our massive resource set in the STACK and Delaware Basin shifts to full-field development mode, we will continually high-grade our portfolio by divesting assets.

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

Thanks, Dave. We will now open the call to Q&A. (Operator Instructions) With that, operator, we'll take our first question.

Your first question comes from Doug Leggate with Bank of America.

Couple of questions, Dave. I guess, the first one is kind of a housekeeping issue on Canada. Can you just walk us through just the issues in the most recent quarter and the trajectory as we move through the back end of the year? Just trying to get a handle as to what is -- what do you think the sustaining production capacity is in the oil sand at this point? And I've got a follow-up, please.

Great. Doug, I'm going to let Tony answer the details. Obviously, we did encounter what we consider to be a onetime maintenance advantage that's impacting our production. We've actually -- in July, we've actually moved beyond that. That's fixed, that issue is. But Tony can give you the details of that. And I can tell you, the asset, in general, is performing outstanding. We just had a onetime maintenance advantage in the rearview mirror as we sit here today and things look outstanding from this point forward. So Tony, do you want to follow up a little detail on that?

Doug, at J2, we had this very large skim tank vessels there that are really large-diameter vessel that's got baffles in it. It's designed to move water and oil through a last stage of separation and extend the retention time in [handles]. What we found was we have a pretty sophisticated leak detection system in our Jackfish projects. We recognize that we had a small leak in the J2 skim tank areas. So we got in there and recognized that what we suspect is through vibration of the flow into those baffles that we were down the boat and bracket system, causing some of those brackets to drop. One dropped and punctured the bottom of that vessel. So we got in, cleaned the tank out and took a look at it. We know exactly what the problem is, so we remedied that on J2. We also just did a turnaround in J3. We suspected the same -- we suspected this issue with J2. So we've been in 2 of those skim tanks in the last 30, 40 days, and we'll be in the third at J1 within 12 months from now. So really, it was an isolated event that's now behind us and thinking we have the solution remedied. And if you just look at the forward look, just like Dave mentioned, we have production at all 3 of these Jackfish plants really operating at nameplate and above. In fact, J2 and J3, the 2 that we just took down, they're already ramped back up in excess of the nameplate capacity and expect both of those to be back in the mid-40,000 barrels of oil per day. So when we get into Q4 with a clean quarter, we'll be back into that 140,000 barrels of oil per day range and again, a long-life project in front of us. So this is just one event that's in the rearview mirror now, Doug.

I appreciate the color. I guess, the follow-up is -- not quite sure how to ask this question efficiently, but -- so when you look at the third quarter guidance, I think at least for us is the [down] sell side, it was a little bit light, but the full year hasn't changed. Which I think kind of speaks to the potential lumpiness of moving to these very large developments that are going to characterize the production profile, I guess, going forward. So just wonder if you could help us navigate that a little bit in terms of what that trajectory you've laid out with all these very large-scale full-field developments going on. What that could look like as we go into next year? And how ratably do you expect that -- those to be? And I guess, there are multiple pieces in that, but I'll leave it there and let someone else jump on.

Yes. And if you look at the issue that happened with probably maybe a little bit light guidance compared to what some people expected in Q3 on the U.S. oil side is we had a large number of completions in the Eagle Ford in Q1. And that caused a really strong performance compared to guidance in Q1 and also carried over, to some degree, into Q2. But those wells obviously fall off fairly quickly. When we originally put the budget together, we had anticipated a little bit more balanced on the completions in the Eagle Ford and have some of them more in Q2 that would cause a little bit higher production in Q3 than where we ended up. So we -- in essence, we completed those wells early, caused strong performance, Q1. Q2, we had no Eagle Ford completions in Q2 because we got them done early. And so that caused the Q3 Eagle Ford to fall off a little bit more than was originally anticipated. But again, extremely economic wells, some of the best in the portfolio. We just moved the production forward is what it boiled down to. As we get more into the full development, what's going to happen is that we are going to have multiple numbers of these multi-zone developments going at any one given time. And certainly, in any individual one, you can say there will be lumpiness, but we think there will be enough of those. It's not going to cause extreme lumpiness in the overall production profile for the company. And keep in mind also that even as we're moving into these that the bulk of these are going to be smaller to start with. And as we get further on in the development, they'll grow in size most likely. But by then, we'll have even more going. So that's -- certainly, there'll be some lumpiness to it, but I don't -- we anticipate, with a number of lumpiness -- or excuse me, the number of developments we have going on that the lumpiness will not be too magnified. And let me just emphasize too, we're still on target to grow our U.S. oil production by 2018 -- in 2018. So there's no change to that guidance at all.

Your next question comes from Evan Calio with Morgan Stanley.

When are your STACK developments scheduled for next year? Coyote is in the far northwestern area of your acreage, just any color. I mean, do you consider that to be part of your acreage as derisked and ready for -- or mature for development? Or is it dependent upon Coyote? And maybe more generally, if you could just discuss rock quality, well performance or expected well performance difference between your focus areas in Showboat, horsefly, and what you expect around the Northwest Coyote.

Evan, this is Tony here. I'd just kind of described to you that we have broken down our footprint in the STACK prospect here into several different, what we call, appraisal areas. And of course, Showboat is really an appraisal area, one where we've had some -- a lot of success, we reported on that. But we've also been in the process, both us and industry, of derisking our next couple of appraisal areas. And so the Coyote prospect will -- or project will be in one of these top couple of appraisal areas that we have been derisking. So the way we look at this is we've got great understanding in the Meramec 200 and the Meramec 300. You're starting to see some results come in across the board in the Meramec 400, some from Devon, but some from industry. We've seen some in the west from other operators that have not performed up to the same quality of results that we've seen in the 200 and the 300. None of that was unexpected, I think, from us. And I guess, I got to remind everybody on the call, Evan, that we're -- this commitment that we have to being highly data-driven is -- we think is really laying us out to be the premier operator in the field. Number one, we got what we think is the best footprint in the play. But really, we had this commitment to being data-driven and have acquired substantial amount of subsurface data. We've built that into the 3-dimensional earth models, and that's really the basis for all the design work going forward. So when you look at some of the results we have over there, the industry's done a good job right now of piloting different ideas from spacing and lateral interval to vertical connectivity type testing to just simply appraising different horizons. And we're moving into what we think are going to be the sweet spot of each of these intervals that we're in. So we're expecting a good performance out of the Coyote project.

Great. And maybe second, if I could. Jacobs Row was downsized. Again, it's not a surprise given the commentary from your partner. How do you redeploy freed-up capital from lower nonop activity in '18? And could you provide us some color on how you would compare Cana-Woodford full development returns versus your STACK Meramec or your Delaware program? And I'll leave it there.

Yes. Well, obviously, we look at our portfolio across the entire company, and we allocate our cap over to -- to those that, on a risk-adjusted basis, provide us the highest return. And so we -- when we look at redeploying capital such as that we will look across the entire company and see where the best place is, I can tell you, in general, that we'll be redeploying any capital there back into the Meramec development or into the Delaware Basin development. Those are very good returns that we think we're going to get there. But we think we have -- they're probably a little bit less, on average, we'd say that we can get from our Delaware and Meramec program, but not significantly less. But there is obviously less condensate production on those than the other plays we're pursuing. So that's where the capital would be redeployed.

Your next question comes from Ryan Todd with Deutsche Bank.

Maybe on the -- well, a question on CapEx. If you look at the CapEx reduction that you announced for the full year, what were the primary drivers? And how do you see those trends as sustaining or evolving over the course of the year?

Well, the primary driver for the CapEx reduction is just the increased efficiency that we've been able to achieve in across the entire asset base. I'd say one big factor, and that is our supply chain initiatives, where we've decoupled much of the completion activities, where we're supplying our own sand, our own diesel and we see significant savings from that. We're also just -- through the use of our advanced predictive analytics, artificial intelligence work, what we're finding that not only are we -- is it helping deliver best of any operator our 90-day IPs, that's also driving our costs lower as well. So we feel really good about where it is. We're very confident. Obviously, the $100 million reduction. There may be some upside to that. We'll have to see how the second half goes. We do anticipate there may be some increased inflationary pressure in the second half of the year, and so that may drive our costs a little bit higher than they were in the first half of the year. We'll just have to see how that goes. But we decided it's appropriate at this point to just take what we're sure of, which is a $100 million reduction, and then see how things evolve in the second half of the year.

So far, the early takeaway, which I think the Hobson Row, with some of the first kind of larger-scale unbundled efforts that you've made on supply chain management, the takeaways have been a little bit better than expected. Is that fair?

That and the efficiencies across our entire portfolio of just drilling wells more effectively, et cetera, yes.

That's great. And then maybe one -- a follow-up question on the Meramec. You have some comments in there about results that you've seen, production -- in production results today that you've seen in your spacing pilots in the Meramec. I think there's been some noise and confusion around some of the pilot results that we've seen across the play from some of your peers in the basin that's caused some concerns. So any thoughts that you can share on what you've seen so far across the spacing pilots and views on what this means for kind of full-field development in the Meramec?

I'll kick it off, and then let Tony -- I'm probably just going to repeat what Tony did, maybe with just slightly different words here. But when -- if you look at it, our operated spacing tests have been very, very successful. We have seen -- on some of the outside operated spacing tests, there has been some very successful ones. But some have had mixed results. When we look at those tests that others have done, we can't say for sure why they tested exactly what they tested, but the results are not a surprise to us. Without going through the specifics of each one, sometimes, we've seen that they've been testing zones that we know have -- would be thinner and wouldn't have the kind of productivity as other zones that are in the same geographic area. Why they tested that? They're probably just trying to get an idea of the productivity of a secondary or tertiary zone, we suspect. In other cases, we know that they've been drilled on a fringe of what we consider the key part of the play to be. In some cases, we think that they used completion designs that are not as sophisticated as what design that we are using. And we've talked a little bit in the press release about our proprietary completion design. So to our viewpoint, there's nothing that surprised us with our tests, which have been very successful or some of these others that have been -- had mixed results. And it just affirms, we have the best position in the play and we understand what's going on, on here. So that's kind of an overall view. And I'd also say that it is very early on in the play. And I suspect -- and we don't know for sure, but I suspect in some of these cases, these companies may be testing the limits of certain things. And then they learn from these and as they go into full-field development, it will be better results. And so I'd be very careful about extrapolating the results from any early experimentation that may be taking on in the play to say this is the way it's going to look on the full field. Because I suspect they knew what they were doing. We don't exactly all of the reasons they're using. We suspect they knew what they were doing, and they were just testing the limits of certain things to see if it would work or not. But again, it's no surprise to us at all in the results we've seen.

Your next question comes from David Tameron with Wells Fargo.

I'm just going to reference the slide, I think, it's 15 in your deck, just the Rattlesnake area, can you just give me an update of kind of how -- it looks like this development pattern changed from maybe what you had been thinking. Can you just give us the latest and greatest thinking as far as it relates to -- I guess, we'll just focus on this area and realize that every area's different, but can you just update us on that as far as development patterns and how many wells per section, et cetera?

Well -- and Dave, this is Scott. And absolutely, the schematic changed slightly. Yes, I think we added 1 or 2 more wells from last quarter, and we got a little bit more specific with regards to the landing zones. I think this time around, we included the XY because that's a common nomenclature in that area. And obviously, we're doing an appraisal well in the lower Wolfcamp A as well. But maybe Tony could speak to just what we're trying to accomplish at that particular pilot, which we call the Seawolf pilot.

David, the -- as Scott mentioned, the well that we reported on here in the lower portion of the upper Wolfcamp A was just below the highlighted Rattlesnake area there, gives us a little bit of upside thought process on the lower portion of the Wolfcamp. But if you go back to the last quarterly call where we've reported the results of The Fighting Okra well. It's just immediately south of the spot on the map that says the word Seawolf. And so there, you saw the outstanding results that we had there in the upper portion of the upper Wolfcamp. And this Seawolf is really going to be our first -- what we call our first multi-zone development in Rattlesnake. And we've got a substantial amount of locations that we've highlighted in our resource play, starting right here with this spud, the 12-well program and the Wolfcamp. And as we work that off, we'll just move those 3 rigs from that location, start moving to the east and fully delineate that Rattlesnake area. So what we don't show on this is a lot of industry activity that's been around us, and there's been some boomer wells there. We feel like this particular portion of not only the -- of our play, but this particular portion of the Delaware Basin is perhaps the best column in all of North America. So we're expecting a very robust long-term development just in this Rattlesnake area.

Okay. And I'd just note the B -- maybe versus the prior, the Wolfcamp B is no longer part of that plan. Can you talk a little bit about -- I know others have done the same, but can you just talk about your thinking there?

There's not been a lot of data points that have come through in the lower portion of the Wolfcamp A or the B. There's been some other nomenclatures, Wolfcamp 300 and 400. There's been some data points out there, few and far between. Some of those have been, in fact, a bit disappointing. So we know there's a very rich hydrocarbon column here, a lot of oil in place. We think it will come with time, but we also think we can maximize our present value by focusing on the upper portion of the Wolfcamp, and we know that we can come back and drill back through that zone and get to the lower portion of the Wolfcamp, which we -- but frankly, right now, we're not prioritizing in our development because we just have not derisked it. We don't see the activity from industry really showing us the results either.

Okay. And then Dave, can I just ask one about -- is this the south of Barnett or portion of the Barnett? And I could imagine what your answer's going to be, but -- because we've talked about it in the past. But I'm just thinking about -- and in terms of returns and generating cash flow, historically it's generated a lot of free cash flow. It doesn't look like you're going to need that over the next couple quarters to cover the spending gap or -- can you just talk about your decision there?

Yes. Well, you're right, we don't need it for the shorter term. What I tried to paint in my prepared remarks at the beginning of the conference call here is where we see directionally we are going by 2020. And that is as we're moving into full-field development in the STACK, in the Delaware, that we will become a more streamlined company eventually. And we see in the billions of dollars of asset sales that we may accomplish over that time frame, in a very measured way, as we balance our cash inflows and our cash outflows. Certainly, there are several different areas that we can consider, and I'm not going to go into detail on any decision or regarding any specific area or asset that we have that we may consider for monetization. But in general, you'd -- I mentioned that we would certainly most likely be divesting several billion dollars of assets. We see using some of that to further development activity in the STACK and the Delaware Basin. And then also, repaying debt with a portion of those proceeds to build an extremely strong balance sheet with a net debt to EBITDA on the order of 1 to 1.5. So we think that financial strength is going to certainly position us with a great deal of strength in any commodity price environment. We think that's really the key for a top performing E&P company is to have -- we have franchise assets. We're executing very well on those assets, and we will further streamline the portfolio and we'll have one of the best balance sheets, if not the best balance sheets in the industry when we're finished with this total transformation. And so certainly, the Barnett or some other assets configure into that equation. Again, we're making no decision on that today and certainly no announcement on that today. But we certainly have a lot of flexibility about how we go about accomplishing this strategic objective, but that's where we're going.

Your next question comes from Charles Meade with Johnson Rice.

I'd like to ask 2 questions on the Delaware Basin. First, on the Seawolf development, can you talk about what, if any lessons, you're able to bring from your multi-zone high-intensity development plans over in the STACK to the Delaware Basin and to that development? Or is it more of just a blank slate and there's not a lot of portability of lessons from one to the other?

Thanks for the question. We do find the ability to transfer learnings between our Delaware and STACK teams. In fact, we've been on this multi-zone design for about 2 years now. That's some really thoughtful work that has gone on with our technical teams in both areas. They meet with each other. So we transfer learnings quite easily here. We're all centralized in this building, so it makes it really advantageous from that perspective. One of the things, I think, unique about the Delaware is really the federal permitting aspects. It's a little bit more complicated than it is in STACK. And I think in the last conference call, we talked about receiving our first master development plan, which was, I believe, was a 162-well permit that we received in Cotton Draw. And we feel like we're very close to having 3 more of those master development plans approved by the BLM, which will set us up for about 600 to 750 potential locations left. And the benefits we see from this multi-zone development concept is just much more efficient, not only permitting exercise that we're going through, as I just described. But really, we lay out the integrated surface facility concept for each of these areas. And in that, we're able to use these centralized production facility not just by 1 pad or 2 pads. But in our planning there, when we start looking at the Gantt chart and laying out all of these different projects, we continue to use these surface facilities for a given area. So for instance, in Seawolf, while that will be the first 12-well project we'll drill, we'll continue to run additional projects producing through that centralized production facility for some time to come. So we'll maximize the rate capacity in that facility for a while. We also feel like there's tremendous ability to increase the efficiency of all operations. And just to give you the order of magnitude of that, when we put in and park about 3 rigs in a half section or a quarter section type area and don't have to really move those rigs from location to location, we'll knock out about 3 days of rig time out of the -- what is normally about a spud-to-TD time of about 10 days. So the more we keep our operations centralized there, we can continue to think of things in terms of batch operations. So we'll use -- had the flexibility to use spudder rigs to get the surface hole drilled and then come back behind it with our conventional rigs for the production string. We'll also be able to do simultaneous operations, and it will actually have some frac operations ongoing in some of these projects while we drill and produce. So tremendous amount of present value uplift by thinking a little bit differently than the industry has thought of in the past. And we're incorporating the same concept throughout the Delaware and the STACK developments, Charles.

The only thing I'd add to that -- Charles, the only thing I'd add, I think you had really strong list of bunch of stuff there that one thing is -- we probably have as much experience as anybody out there in the industry, what we would call the parent-child relationship in any given area. The -- in other words, a relationship between the first well and a section and then what the ultimate down-spacing might be and what kind of completion designs optimize recovery given that. And so that's something that we've obviously studied from the Eagle Ford to STACK and the Delaware. And we are -- we feel we have a really good understanding. There's -- you have to actually drill the wells, in many cases, to know the absolute results. But we have a pretty good understanding, I'd say, of what is going to optimize the overall recovery for the highest returns around that. And that comes from experience and drilling in a number of different areas and transferring those learnings from one place to another.

Right. That's great color. You guys certainly are pushing the envelope within the industry on that kind of concentrated development. And that actually leads to my second question. You guys have highlighted the Seawolf development, but I couldn't help but notice that just to the north, you've got this Medusa development who -- that's just maybe a little bit behind on-schedule with actually more wells. And so maybe can you give us a little more color on what the plan is there?

Charles, what we've laid out, I think what we show here, to be really the projects that will be initiated through the latter part of '17 and into the early part of '18. So we've got a Gantt chart that actually goes beyond that with additional projects there. But as you -- the focus for what we call the Thistle area is really largely going to be the Leonard and the Bone -- a little bit of Bone Spring type work and some Wolfcamp work there. So it's just another -- the project that we've talked about in the last operating report and the one that we mentioned in this, the Anaconda, is really a 3-interval test on the Leonard that we're completing those wells and we're starting to bring those online. We'll have operating results of those in Q3. But at this point, we're looking at those as very favorable results. So Medusa is just really just a continuation of the development of that column.

Your next question comes from Arun Jayaram with JPMorgan.

Dave, I wanted to see if you could elaborate more on your thoughts on this longer-term vision, perhaps this leaner and meaner Devon with a focus on the STACK and the Delaware Basin. I'm just trying to get a sense of how we should think about how other assets fit into the Devon portfolio as you're thinking about maybe deleveraging through asset sales and in particular, Canada.

Arun, we obviously have a number of strong assets throughout our portfolio. It appears that those have the greatest development opportunity -- they are going to be the STACK and the Delaware Basin with -- and then to probably a lesser degree, in the anticipated price environment. And again, we're basing -- we're going to thrive in the $45 to $50 world, and we're not counting on higher prices. So we're going to -- we are building a company here that's going to succeed and be one of the top companies in the current price environment. And in that world, it looks like STACK and Delaware are probably going to lead the way as far as development opportunities, while a number of the other areas will have some developments, such as the Rockies, and others are going to be providing more cash flow to the company. So we -- we're on the cusp of really moving into full-field development in the STACK and the Delaware plays. And when we do, these plays are going to be able to absorb and generate very strong returns. And again, I want to emphasize again, we are a returns-oriented organization. We're not just growing for growth's sake, but we think we can generate very strong returns in those plays in this price environment. If there's any question about the quality of the wells that we're drilling, again, I'd refer people back to Page 6 of the operations report where we show we have the highest 90-day IP in the industry. So we can talk -- you can 24 hour, you can talk 30 days and all that, but when it comes to 90 day, we're the leader and we can generate strong returns from that. So as we do, we do see that some of these other areas could potentially provide divestiture opportunities that would allow us to further our development in the STACK and the Delaware Basin. I'm not going to go as far as saying which specific ones because that's going to be -- or continue to look at that and we will continue to look. It will be a measured, a very thoughtful process. We'll be balancing our cash inflows and cash outflows, as I said, and we're going to use some for debt repayment to build this fortress balance sheet also. So beyond that, there is no, at this point, no further discussion. But obviously, we're going to look at all the key criteria when making that call. But it's a great position to be in, where we have a very strong asset base. We're executing now. I feel very well on that asset base. We're -- and we are going to continue to increase the focus of the company.

Okay, that's great. And just my follow-up, Dave, you -- in a $45 to $50 world, we had been thinking about, Devon, based on your previous kind of commentary, of kind of balancing your internally generated cash flows plus the EnLink distributions with your CapEx. Given how you may be embarking on this asset sale program beyond the 20% sale in the Barnett, is there comfort, perhaps, to spend above that amount with asset sales kind of plugging that -- the delta there?

In essence, yes is the quick answer to that. Now again, we are driven by returns first, and we are -- we only do it if we feel we are -- can generate good returns with the capital that we're deploying. We are confident in that price environment that we can generate good returns in the STACK and Delaware Basin plays. And so depending on the circumstances, we'd certainly be open to using a portion of the divestment proceeds to further development of those plays and then a portion of that to pay down debt to build this strong balance sheet as well.

(Operator Instructions) Your next question comes from David Heikkinen with Heikkinen Energy Advisors.

Just a quick question on Jackfish 1. Do you expect similar skim tank issues and inspections ongoing and potential downtime?

David, we could. We saw a little bit of evidence of the bracket issue in J3 skim tank. We have no leak detection at this time at J1. You also have to remember, we've already been in the skim tank at J1 in the previous turnaround. So we're really not expecting it to be an issue, but we'll certainly make the same type of proactive repair work that we did in J2 and J3 while we're in the tank.

Okay, and then just on the Hobson Row. You highlighted that in your 2Q ops report. Can you talk at all about what the current production is and how it actually contributed to the volume? I'm just trying to get an idea of how those 39 wells are actually producing.

Well, obviously, the Hobson Row's the key driver behind our growth in the STACK issue. We've advanced STACK production by about 20%, and that's largely driven by just the success of the Hobson Row and what we're seeing there. And maybe I'll hand it off to Tony where he can talk about just what we're seeing from the type curves and more importantly, how we're going to deploy that success to the Jacobs Row. Tony?

David, I don't have a whole lot to add to that. We reported a little bit of the results in the last operating report. The work that we've done so far in this particular quarter has been type curve type results, so we didn't really highlight it individually. But I'll tell you, we've pumped 500 million pounds of -- near 500 million pounds of sand in that work. And from an execution perspective, the team did outstanding results. And there's a great partnership between the operating guys and the supply chain guys that we have there. This, as I think Dave mentioned earlier, this is the first area that we decoupled. Great success there, and we think we dropped about 15% of the cost of those -- that work out of the system just through that operating efficiencies there. We're very excited about extending the work from the -- normal lateral work that we've historically done into the long laterals. We've got the -- all the wells completed now. They're all starting to flow back. We'll be able to report on those results in the next quarter. But again, when we start looking towards the future in this and understanding what the value of the long lateral will bring, we think the returns for this development are as competitive as much of what we have in the portfolio.

And just on that cost savings, how do you think that will flow through to your future development cost reported in your reserve reports? Should we expect a downward trend in Devon's future development cost as you kind of lock in the decoupling of services and just trend with positive wells costs?

Well, I think that certainly is a positive driver towards -- yes, towards lower F&D now. Obviously, as you pursue more oil-oriented plays, as you well know, David, those tend to be a little bit higher F&D type plays in general. But that's -- but that element would help mitigate that, absolutely.

And to add on that, Dave, real quick is just ultimately, as you start hitting towards those multi-zone developments where the majority of our capital is going to be concentrated going forward, that's going to be another tailwind as well. So very concentrated capital programs, combined with the supply chain, we would expect to show very well in this metric in the upcoming years.

Well, I guess, looks like there's no one else in the queue, so we'll wrap up the call today. We appreciate anyone's interest in Devon and if you have any other questions, feel free to call the IR team at any time, and that consists of myself and Chris Carr. Have a good day.

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