Devon Energy Corp (DVN) — Q2 2017 Earnings Call Transcript

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 results may differ materially. For a review of risk factors related to these statements, please see our Form 10-K. And with that, I will 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 play and accelerating efficiency gains across our portfolio. These successful efforts have resulted in record study and well reserves that grew 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 these planned drilling activities are concentrated within our STACK and Delaware Basin assets, which are two 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 drill 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 are 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 non-core divestiture proceeds over the coming year. We absolutely have the financial capacity and flexibility to execute our business plan. Given our ability to organically fund capital requirements, Devon is uniquely positioned to maintain and build momentum into the future as we advance our development programs in the STACK and Delaware Basin. The quality and size of these world-class opportunities ahead of us are 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 breakeven 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 the 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 pricing strategy. Potential proceeds from these portfolio rationalization efforts would balance between accelerating the development of our highest rate of return inventory and debt reduction activities. With this exciting multi-year 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 a net debt-to-EBITDA target of 1.0 to 1.5 times 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 Delaware results to 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. 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 will now turn the call back over to Scott.

Thanks, Dave. We will now open the call to Q&A. Please limit yourself to one question and a follow-up. If you have any further questions, you can re-prompt as time permits. With that, Operator, we will take our first question.

Thanks. Thank you. Good morning, Dave. Good morning, everybody. A couple of questions, Dave. I guess the first 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 backend of the year? Just trying to get a handle on what you think the sustaining production capacity in the area is at this point. And I have 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 one-time maintenance event that impacted our production. In July we’ve actually moved beyond that; that issue is fixed; however, Tony can give you the details on that. I can tell you the asset in general is performing outstanding; we just had a one-time maintenance event that’s in the rear-view mirror as we sit here today, and things look outstanding from this point forward. So, Tony, do you want to follow up with a little detail on that?

Yes. Good morning, Doug. At J2 we have these very large skim tank vessels; they are really large diameter vessels that have dappled water and oil through the last stages of separation, extending the retention time. What we found was we have a pretty sophisticated leak detection system in our Jackfish projects. We recognized 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 dappled tanks, some of those brackets dropped and punctured the bottom of that vessel. We cleaned the tank out and took a look at it; we knew exactly what the problem was, so we only did that on J2. We also just did a turnaround in J3; we suspected this issue in J2, so we have been into two of those skim tanks in the last 30 to 40 days, and we will be in the third at J1 within 12 months from now. So really it was an isolated event that’s now behind us, and I think we had this solution remedy. If you just look at the forward, just like Dave mentioned, we have production at all three of these Jackfish plants really operating at nameplate and above. In fact, J2 and J3, the two that we just took down that are already back up and accessible at the nameplate capacity, expect both of those to be back in the mid 40,000 barrels of oil per day. So when we get into Q4 with the claim quarter, we will be back in 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 rear-view mirror now, Doug.

I appreciate the color. Thanks for that. I guess that the follow-up is, I’m not quite sure how to ask this question efficiently. So when you look at the third quarter guidance, at least versus the dump sales that were a little bit late, but still you haven’t changed which I think speaks to the potential lumpiness of moving to these very large developments that are going to characterize the production profile. I guess I just wondered if you could help us navigate that a little bit in terms of what that trajectory you had laid out with all these very large full-field developments going on. What that could look like as we go into next year and how you expect that to be; I guess there are multiple pieces but I will leave it there and let someone else jump on. Thanks.

If you look at the issue that happened with the guidance compared to what some people expected in Q3 on the U.S. oil side, we had a large number of completions in Eagle Ford in Q1, and that caused really strong performance compared to guidance in Q1 and also carried over to some degree into Q2. But those wells fall off fairly quickly. When we originally put the budget together, we had anticipated a little bit more balanced completions in the Eagle Ford and had submitted more in Q2; it would cause a little bit higher production in Q3 than where we ended up. So, in essence, we completed those wells early, caused strong performance in Q1 and Q2; we had no Eagle Ford completions in Q2 because we got them done early, and so that caused 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. 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 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 us extreme lumpiness in the overall production profile for the company. Keep in mind also that even as we are moving into these, the bulk of these are going to be smaller to start with, and as we get further on in the development, they will grow in size most likely, but by then we have even more going. So yes, there are going to be some lumpiness to it; we anticipate with a number of lumpiness, or should I say, the number of developments we have going on. The lumpiness will not be too magnified.

I appreciate the answer, Dave. Thanks a lot. I know it’s a tough thing to describe.

And let me just emphasize, we’re still on target to grow our U.S. oil production by 2018. So there is no change in that guidance at all.

Hi, good morning, guys. Yes. When are your STACK developments scheduled for next year? Coyote, it’s in the far northwestern areas of your acreage. Just any color, do you think that will be party or acreage that’s de-risked or mature for development, or is that dependent upon Coyote? And maybe more generally, if you can just discuss raw quality well performance or expected well performance difference between your focus areas in Showboat and what do you expect around the Northwest Coyote?

This is Tony here. I just want to describe to you that we have broken down our footprint in the STACK prospect into several different areas called appraisal areas. Showboat is really in appraisal area one where we’ve had a lot of success; we’ve reported on that, but we’ve also been in the process, both us and the industry, de-risking our next couple of appraisal areas. The Coyote project will be in one of these top couple of appraisal areas that we have been de-risking. The way we look at this is we have a great understanding of the Meramec 200 and the Meramec 300; you are starting to see some results come across the board and Meramec 400 from Devon but also from industry. We have seen some results 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 300; none of that was unexpected on our part. I’ve got to remind everybody on the call that our commitment to being highly data-driven is really laying us out to be the premier operator in the field. Number one, we have what we think is the best footprint in the play, and we really have this commitment to being data-driven and have acquired substantial subsurface data, building that into three-dimensional earth models, which is really the basis for all the design work going forward. When you look at some of the results we have over there, the industry is doing a good job right now of piloting different ideas from spacing and lateral intervals to vertical connectivity type testing to just simply appraising different horizons. We are moving into what we think are going to be the sweet spots of each of these intervals we are in. So, we are expecting good performance out of the Coyote project.

Great. Thanks. And maybe second if I could. Yes, Jacobs Row was downsized, I guess not a surprise given commentary for your partner. How do you deploy a free capital from lower non-op activity in 2018? And could you provide us some color on how you would compare Woodford full development returns versus your STACK Meramec or your Delaware program? I will leave it there.

Yes. Well obviously we look at our portfolio across the entire company, and we allocate our capital to the projects that, on a risk-adjusted basis, provide us the highest return. So 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 will be redeploying any capital back into the Meramec development or into the Delaware Basin development; those are very good returns, so we think we’re going to get there. However, they are probably a little bit less on average compared to what we can get from our Delaware and Meramec programs, but not significantly less, as there is obviously less condensate production on those than the other plays we are pursuing. So that’s where the capital would be redeployed.

Okay. Thanks a lot, guys.

Thanks. Maybe one question on CapEx. If we look at the CapEx that you announced for the full year, what were the primary drivers, and how do you see those trends sustaining or evolving over the course of the year?

Well, the primary driver for the CapEx reduction is just the increased efficiency that we have been able to achieve across the entire asset base. I would say one big factor in that is our supply initiative where we have decoupled much of the completion activities. We are supplying our own sand and own diesel, and we see significant savings from that. We’re also, through the use of our advanced predictive analytics, artificial intelligence work, finding that not only are we helping deliver the best of any operator at a 90-day IP, but it’s also driving our costs lower as well. We feel really good about where it stands. We’re very confident obviously about the $100 million reduction; there may be some upside to that; we will 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 will just have to see how that goes, but we decided it was appropriate at this point to take what we are 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 is which I think Jacobs Row with some of the first kind of larger scale unbundled efforts that you had made on supply chain mainly. The takeaway has been a little bit better than expected. Is that fair?

And the efficiencies across our entire portfolio of just drilling wells more effectively, etc. Yes.

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

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

Great. Thank you.

Thanks. Good morning. I’m just going to reference the slide, I think it’s 15 in your deck, just the route area. Can you just give me an update on kind of Seawolf? 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 that relates to or I guess the focus on this area, realizing every area is different? Can you just update us on that as far as the development patterns and how many wells per section, etc.?

Dave, this is Scott. Absolutely, that is a systematic change slightly. I think we added one or two more wells from last year, and we got a little bit more specific with regards to the landing zone. I think this time around, we included the X, Y because that’s a common nomenclature in that area. Obviously, we’re doing an appraisal well in the lower Wolfcamp 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, as Scott mentioned, the well that we’ve reported on here in the lower portion of the upper Wolfcamp A, was just below the highlighted Rattlesnake area there. It 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. You saw the outstanding results reported there in the upper portion of the upper Wolfcamp, and this Seawolf is really going to be our first multi-zone development in Rattlesnake. We have got a substantial number of locations that we have highlighted in our resource play, starting right here with this planned 12-well program in the Wolfcamp. As we work that out, we will move those three rigs from that location to start moving to the east and probably delineate that Rattlesnake area. What we don’t show on this is a lot of industry activity that’s been around this, and there have been some good wells. We feel like this particular portion of our play, and specifically this Delaware Basin, is perhaps the best column in all of North America, so we are expecting very robust long-term development just in this Rattlesnake area.

Okay, and just noticed the B maybe versus the prior Wolfcamp B is no longer part of that plan. Can you talk a little bit about that? I know others have done the same. Can you just talk about your thinking there?

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

Okay, thanks for that color. And then Dave, can I just ask one about selling the Barnett or a portion of the Barnett? I can imagine what your answer is going to be, but because we’ve talked about it in the past, but I’m just thinking about in terms of returns and generating cash flow, you know historically it has generated a lot of free cash flow, it doesn’t look like you are going to need that over the next couple of quarters or a couple of spending gaps. Can you just talk about your decision there?

Well, you are right; we don’t need it for the shorter term. What I tried to portray in my prepared remarks at the beginning of the conference call here is where we see directionally we are going by 2020. As we move into full-field development in the STACK and the Delaware, we will become a more streamlined company eventually and see in the billions of dollars of asset sales that we may accomplish over that timeframe in a very measured way as we balance our cash inflows and cash outflows. Certainly, there are several different areas that we can consider, and I’m not going to go into detail on any specific area or assets we may want to monetize, but in general, 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 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. We think that financial strength is going to position us with a great deal of strength in any commodity price environment. We believe that’s really the key for a top-performing E&P company to have. We have franchise assets, we’re executing very well on those assets, and we will further streamline the portfolio, emerging with one of the best balance sheets, if not the best balance sheet in the industry when we’re finished with this transformation. So certainly, the Barnett or some other assets factor into that equation; again, we’re making no decision on that today and certainly no announcement on that today. However, we do have a lot of flexibility about how we accomplish this strategic objective, but that’s where we’re going.

Good morning, Dave and to the rest of the team there. I would like to ask two questions on the Delaware Basin. First on the Seawolf development. Can you talk about what, if any, lessons you are able to bring from your multi-zone high-intensity development plans over in the STACK to the Delaware Basin in 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?

Hi, Charles. Thanks for the question. We do find the ability to transfer learning between our Delaware and STACK teams. In fact, we’ve been on this multi-zone design for about two years now, and there’s really thoughtful work that has gone on with our technical teams in both areas. I meet with each other, so transferring learnings is quite easily here; we’re all centralized in this building, so it makes it very advantageous from that perspective. One of the things I think is unique about the Delaware is the federal permitting aspects are a little bit more complicated than they are in STACK. In the last conference call, we talked about receiving our first master development plan, which was for a 162 well permit received in the past. We feel like we’re very close to having three more of those master development plans approved by the BLM, which will set us for about 600 to 750 potential locations left. The benefits we see from this multi-zone development concept include much more efficient permitting exercise that we are going through as I just described, but really we laid out the integrated surface facility concept for each of these areas. In that, we’re able to use centralized production facilities not just for one pad or two pads, but in our planning, when we start laying out all of these different projects, we continue to use these surface facilities for a given area. For instance, in Seawolf, while that will be our first 12 well project, we will continue to run additional projects producing through that centralized production facility for some time to come. We will maximize the rate capacity in that facility for a while. We also feel like there is tremendous ability to increase the efficiency of our operations. To give you an order of magnitude on that, when we put in a park of three rigs in a half-section or quarter-section type area and don’t have to really move those rigs from location-to-location, we can reduce the rig time to about three days, compared to what is normally about a spud to TD time of about 10 days. So the more we keep our operations centralized, we can continue to think of things in terms of batch operations. We can also use spudder rigs to get to surface pull drill, and then come back behind with our conventional rigs for the production stream; we will be able to do simultaneous operations, which will actually allow for fracking operations to be ongoing in some of these projects while we drill and produce. There’s a tremendous amount of present value uplift by thinking a little differently than the industry has in the past, and we’re incorporating the same concept throughout the Delaware and STACK development shows.

Charles, the only thing I would add is that I think we have as much experience as anybody out there in the industry with what we would call the parent-child relationship in any given area. In other words, it is the relationship between the first well and what the ultimate down-spacing might be and what kind of completion designs optimize recovery given that. That’s something that we have studied from Eagle Ford to the STACK and the Delaware, and we feel we have a really good understanding of what is going to optimize overall recovery for the highest returns. 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, guys, and you guys are pushing the envelope within the industry on that concentrated development. 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 have got this development that may be a little bit behind schedule with actually more wells. Can you give us a little more color on what the plan is there?

Charles, we have laid out what we show here to be really these projects that will be initiated through the later part of 2017 and into the early part of 2018. We have a gain chart that actually goes beyond that with additional projects there. The focus for what we call the distilled areas will largely be the Leonard and just a little bit of the Bonds claim type work and some Wolfcamp work. It’s just another project that we have talked about in the last operating report, and the one that we mentioned in this is the Anaconda, which is really a three-interval test on the Leonard. We are completing those wells and starting to bring those online. We will have operating results of those in Q3, but at this point, we’re looking at those as very favorable results. So, I did say it’s just really a continuation of the development of that column.

Yes. Dave, I wanted to see if you can elaborate more on your thoughts on this longer-term vision, perhaps this leaner and meaner Devon with the focus on the STACK and 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 are thinking about maybe deleveraging through asset sales, particularly at Canada?

Well, thanks Arun. We obviously have a number of strong assets throughout our portfolio, but it appears that those with the greatest development opportunity are going to be the STACK and Delaware Basin. To probably a lesser degree, the anticipated price environment—again, we’re thriving at $45 to $50 wells, not counting on higher prices—so we are building a company here that succeeds and is one of the top companies in the current price environment. In that world, it looks like STACK and Delaware are probably going to lead the way as far as development opportunities, but we will have some developments such as Rockies and others providing more cash flow to the company. We'll soon move into full-field development in the STACK and Delaware plays; when we do, these plays are going to absorb and generate very strong returns. I want to emphasize again that we are a returns-oriented organization; we’re not just growing for growth’s sake, but we believe we can generate very strong returns in those plays in this price environment. Any question about the quality of the wells we’re drilling could refer people back to page six of the operations report, where we show we have the highest 90-day IP in the industry. So, we can talk 24 hours, you can talk 30 days, all that; but when it comes to 90 days, we’re the leader. We can generate very strong returns from that. As we do, we see that some of these other areas could potentially provide divestiture opportunities that would allow us to further our development in the STACK and Delaware Basin. I’m not going to mention specifics because we’re going to continue looking at that, and it will be a measured, very thoughtful process. We will balance our cash inflows and cash outflows as stated, and we’re going to use some for debt repayment to build this fortress balance sheet. Beyond now there are no further discussions, but we’re going to look at all the key criteria when making that call. It’s a great position where we have a very strong asset base. We’re executing very well on that base and will continue to increase the focus of the company.

Okay, that’s great. And just in a $45 to $50 world, we had been thinking about Devon based on your previous commentary of balancing your internally generated cash flow plus the in-link distributions with your CapEx. Given how you are 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 plugging the delta there?

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

Good morning, guys. Thanks for taking my question. Just a quick question on Jackfish one. Do you expect similar skim tank issues and inspections ongoing and potential downtime?

David, we saw a little bit of evidence of the bracket issue in J3 skim tank. We had no detection this time at J1. You also have to remember we have already been in this skim tank at J1 in the previous turnaround. So, we’re really not expecting it to be an issue, but we will certainly take the same type of proactive repair work that we did in J2 and J3 while we are 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 those 39 wells that are actually producing?

Obviously the Hobson Row is the key driver behind our growth in STACK this year. We have revamped STACK production by 20%, and that’s largely driven by just the success of the Hobson Row and what we are seeing there. Maybe I should hand it over to Tony, where he can discuss the type curves and more importantly how we are going to deploy that success to Jacobs Row.

Dave, 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 we have done so far in this particular quarter has been type curve results, so we didn’t really highlight that individually. However, I will tell you we pumped nearly 500 million pounds of sand in that work, and from an execution perspective, the team did outstanding results. There’s a great partnership between the operating guys and the supply chain guys that we have there. I think Dave mentioned earlier, this is the first area that we decoupled and had great success there. We think we dropped about 15% of the cost off that work out of this system just through that operational efficiency. We are very excited about extending the work from the normal lateral work we have historically done to long laterals. We got all the wells completed now; they are all starting to flow back. We will be able to report on those results in the next quarter, but again, when we start looking towards the future, our understanding of the value of the long lateral will bring competitive returns like much of what we have in the portfolio.

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

I think that certainly is a positive driver towards a downward trend. Now, obviously, as you pursue more oil-oriented plays, as you well know, those tend to have a little bit higher future development costs in general. But that element would help mitigate those costs.

Yes. One other thing to add on that, Dave, real quick is as you start heading toward those multi-zone developments for the majority of our capital will be concentrated going forward, and that’s going to be another tailwind as well. So very concentrated capital programs combined with the supply chain improvements, we would expect to show very well in this metric in the upcoming year.

Thanks, guys.

Well, I guess it looks like there is no one else in the queue. So, we will wrap up the call today. We appreciate everyone’s interest in Devon. Do you have any other questions? Feel free to call the IR team anytime, consisting of myself and Chris Carr. Have a good day.