Good day ladies and gentlemen, and thank you for standing by. Welcome to the Encana Corporation's Third Quarter 2017 Results Conference Call. As a reminder, today's call is being recorded. For members of the media attending in a listen-only mode today, you may quote statements made by any of the Encana's representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Encana's Corporation. I would now like to turn the conference call over to Corey Code, Vice President of Investor Relations. Please go ahead, Mr. Code.

Thank you, operator, and welcome everyone to our third quarter results conference call. This call is being webcast, and the slides are available on our website at encana.com. Before we get started, please take note of the advisory regarding forward-looking statements in the news release and at the end of our webcast slides. Further advisory information is contained in our annual report and other disclosure documents filed on SEDAR and EDGAR. I also wish to highlight that Encana prepares its financial statements in accordance with U.S. GAAP, and reports its financial results in U.S. dollars. So, references to dollars means U.S. dollars, and the reserves, resources and production information are after royalties unless otherwise noted. This morning, Doug Suttles, Encana's President and CEO, will open the call. Mike McAllister, our COO, will then describe our operational results and Sherri Brillon, our CFO, will highlight our financial performance. We will then open the call up for Q&As. I will now turn the call over to Doug Suttles.

Thanks, Corey. Good morning everyone, and thank you for joining us early on a Wednesday morning. Q3 marks another strong quarter for advancing our strategy and delivering our five-year plan. As we head towards year end, we are well positions to deliver on our key strategic objectives for 2017. Our results highlight our ability to generate quality corporate returns through the commodity cycle. Our strategy and operational performance continues to deliver solid financial results. Through the third quarter, we've generated $899 million of cash flow plus net A&D proceeds of $660 million for a total of $1.6 billion. This compares to capital expenditures of $1.3 billion year to date. We've grown our corporate margin to $10.77 per BOE. Our focus on high value oil and condensate production, our core assets, has led us to breaking through the 300,000 barrels of oil equivalent per day mark in October. This represents a 27% increase from the fourth quarter of 2016. Our focus on high margin production puts us well on track to deliver a corporate margin of $11 per barrel of oil equivalent for the full year of 2017 and gives us confidence as we head into 2018. Our core assets are each performing very well. The startup of the Montney plants combined with excellent well productivity triggered significant condensate production growth in October. Strong well performance in the Permian is delivering substantial oil production growth as well. In the Eagle Ford, we held production largely flat while generating free cash, and in the Duvernay we set a new production record. As a result, our October oil and condensate production grew by 15% over the third quarter. We continue to innovate in all aspects of our business. This is driving upside for us by unlocking the resource on our acreage more efficiently…

Thanks, Doug. As Doug mentioned, our development approach in the Permian is generating impressive results. We've been innovating our completion design throughout the year and we continue to deliver better and better wells. I'll talk more on the next slide about some specific well results. However, the wells we brought onstream in the third quarter and early in the fourth quarter are some of our best yet. This has driven a big increase in production in October. We've now placed over 100 wells on production in our 2017 program; 16 of those have come on in just the past few weeks. Our third quarter production grew by 2,500 BOE per day as we managed through the impacts of Harvey. In addition, we experienced slower cleanup times on a number of our Q3 wells that pushed their peak production into the fourth quarter. Our October actual production was 80,000 BOE per day, which sets us up well to deliver on our Q4 target of 75,000 BOE per day. Our GORs are tracking in line with our expectations. Our type curves account for the change in GOR profiles across the basin. As a result, small fluctuations in our total production mix are to be expected depending on the relative contribution from wells across the basin. Over the past 11 quarters, our gas mix has ranged from a low of 17% to a high of 20%. This is normal and consistent with our expectations. Our October actual gas mix was 17%. Beyond production highlights, we also had another successful quarter on drilling completion costs and operating costs. Our cube development approach continues to provide significant capital cost efficiencies. Our operating cost performance continues to be strong, with total operating costs excluding long-term incentives of approximately $6.50 per BOE. Looking out to 2018, we…

Thanks, Mike. Our third quarter delivered strong financial performance. Our more balanced product mix and lower costs are driving higher margins. We entered the year indicating a corporate margin of $10 per BOE was achievable. Year to date Q3, our corporate margin is $10.77 per BOE. This puts us on track to deliver $11 per BOE for the year. On a dollar basis, our costs in the quarter were flat versus prior quarter, but with lower volumes in Q3, some of our per unit costs came in slightly higher. These per unit costs would have been about 4% lower excluding the impact of Hurricane Harvey and the curtailments in our Canadian gas portfolio. Looking forward to Q4, we expect per unit costs to drop modestly with the exception of our transportation and processing costs. As Mike mentioned, we began selling gas at Dawn on November 1. This additional downstream transport will increase our Canadian per unit T&P costs, but we expect these costs will be more than offset by the higher gas price we receive at Dawn. For example, using current pricing, the Dawn versus AECO off-lift is about $1.15 per Mcf versus a cost of about $0.85 per Mcf. Currently, in addition to the margin uplift, moving gas to Dawn provides market diversification and manages risk. Our guidance for the full year remains unchanged. We expect to finish the year strong with the Montney and Permian volume growth driving higher cash flow and corporate margin. Our approach to price risk management reduces cash flow volatility and helps to manage balance sheet risk. We take a fully integrated approach to market fundamentals that uses a combination of financial derivatives, transportation contracts, and a diversified physical sales portfolio to manage market access as well as benchmark price and basis differential risk.…

Thanks, Sherri. When we entered 2017, we had four key goals. The first, make 2017 the safest year in the company's history, go from decline to growth by midyear, grow production from our core assets by at least 20%, and ensure we maintained or enhanced the efficiencies we built in 2015 and 2016. We are on track to exceed each of these objectives as our core production went from decline to growth in the second quarter. And as you've already heard, we are on track to achieve 30% growth in our core assets. We are delivering this without additional capital, which points to how our business is working and we've made our business more efficient in every area. Our strategy, execution and ability to grow within cash flow has resulted in a business that is set to generate double-digit returns with cash flow growing at a compound annual rate of 25% and cumulative free cash flow of about $1.5 billion over the next five years at flat prices. We apply our deep expertise and execution with a focus on technical and commercial innovation to a world class portfolio of unconventional resource plays. All we do is unconventional resource plays. Our long history with these play types means that we have built significant technical capabilities that drive strong returns and maximizes resource recovery. Our disciplined capital allocation is tightly aligned with a clear strategy and an informed perspective on market fundamentals. We are focused on value. Our relentless focus on improvement, driven by both discipline and innovation, not only deliver strong well returns but also strong corporate returns. We are excited that the results we have delivered this year have us on track for a strong finish to 2017 and a great launching point for 2018. I appreciate you listening to us so far, and now the team would be more than happy to take your questions.

We will now begin the question-and-answer session and go to the first caller, Menno Hulshof from TD. Your line is now open.

Thanks. I'll start will a question on cube development. So, looking out into 2018, what percentage of your drill program in the Permian and the Montney will be accounted for by cube development as opposed to the drilling of single wells? And then, as a follow-up to that, where do you think you stand in terms of optimization of cube design in those plays?

Yeah. Thanks, Menno, and I'll hand it over in a second to Mike who will give the details, but I don't actually think we drill single wells anywhere anymore, but Mike can confirm that. As far as the cube development approach, I think the expectation everyone should have is this is going to continue to evolve. We continue to invest heavily in understanding how this combination of how we complete our wells with how we do three dimensional spacing of our wells is maximizing recovery and returns. And you've already seen that, that we continue to adjust it as we go forward and keep trying to optimize both as we said earlier, the returns and the recovery. But maybe Mike, you can add some detail here.

You bet. Hi, Menno. Yeah, we haven't fully set our 2018 program yet. But as Doug mentioned, I can't think of a single well that's going to be drilled that's not in a cube. We're never going to stop learning. We're never going to stop trying to improve, but we've seen some pretty significant improvements with our first 28 well cube that we drilled in the Montney up in Tower where we set a 25% reduction in our well costs. So there's more to come. There's more learnings to come, but we're really, really encouraged about what we're seeing so far.

And then yeah, just because you mentioned it, on the Tower cube, is there anything unexpected that you're seeing relative to the performance in the Permian, good or bad?

Well, with respect to D&C costs and where they are going, the reduction in D&C costs are consistent with what we would have seen in the Permian. One of the really nice highlights that we've seen in the Tower cube is that we're seeing more liquids to gas ratio than we had expected in. So that's really encouraging.

You know, Menno, the one maybe point I'd emphasize that Mike just made was 2017 is the first year we could really go to sort of industrial scale development in the Montney. And despite an inflationary environment and everything else, we've got by far the lowest cost wells we've ever drilled there, and the best wells we've ever drilled there. So, I think we're actually showing the benefits not only in the subsurface but in the surface of cube style development.

Okay. And then I'll wrap things up with a question on the 2018 outlook. So, we've got WTI trading in that $55 to $57 range. You're currently budgeting $50 for your five-year plan. Is that causing you to reconsider activity levels for the coming year? And I'm asking that with the full understanding that you haven't nailed things down yet. Or is the better way to think of that being that any surplus cash flow just gets thrown at the balance sheet and delevering?

Yeah, Menno. Good question. Now first of all, that five-year plan, we weren't forecasting commodity prices. We were doing, what we were showing was how the company would perform at a flat $50 and $3 deck. And the purpose of that was to show that this business works at all dimensions, generates strong returns and generates free cash flow over the period. The exact price deck in any given year, we'll actually take a look at that as we enter the year. But I will tell you that our focus on efficiency, I mean, one of the things we've talked about for a long time is we want price to go to margin not to cost. So if we ramp up activity, if we believe prices were strong, we'd only do that if we believe it's going to generate quality returns and we're not going to see erosion through higher cost. So, I think in the shorter term, I'd be surprised if we adjusted our plans much on near-term movements on price. In the longer term, it would be a combination of being convinced that the price is being sustained, and we're actually going to generate quality returns and quality margins in that price environment. We've never been chasing production. Our goal has always been to generate quality returns through the cycle.

Thank you. That's it for me.

Our next question comes from the line of Greg Pardy from RBC Capital Markets. Sir, your line is now open.

Thanks. Thanks, good morning. Doug, I wanted to touch on a couple of areas, but the first one just being how does the Eagle Ford fit into your plans on a go-forward basis? I mean it's obviously, it's one of the smaller of the four, but you've also got compelling well results as you were mentioning.

Yeah, Greg, I think that the Eagle Ford, just to be honest, it sort of reinforces our deep belief in why we want to be in the best parts of the best basins, because you could argue the returns and the performance in the Eagle Ford today is better than it's ever been, even though prices are lower, much lower than they were three or four years ago. These well rates are incredible that we're seeing. We have wells that routinely pay out in months, not years. The impact of enhanced completion designs there has been incredible. And in fact, even at the Investor Day, we indicated in the short term, the Eagle Ford may attract a bit more capital than maybe what we had thought of a year or so ago just because the performance has been so strong. It does have a more limited land base. We've kind of said for quite some time that we see it around the 50,000 barrel a day asset through the end of the decade. That may go a little longer now with some of the performance we're seeing. But the returns are incredible and I think Mike mentioned on his piece, despite investing reasonably heavily in that asset, it's a big free cash generator for the company, which just emphasizes the quality of that resource.

Okay. And then what about, I mean, I know you've been facilities constrained, but what about rates? Potentially, do you look at optimizing how much you can actually put through these plants and takes rates up beyond the, call it, 51,000 or so?

Yeah. What we've been doing, particularly over the last year or two, has been focusing our drilling program where we had excess facility capacity. It was the most capital efficient way to go. We have a few areas of our acreage which we need to build new tank batteries. We'll be doing some of that in 2018 according to how we see the plants today, which will give us some potential there. And the team is constantly trying to figure out can we get more volumes through what we have today. It's a bit early to say exactly what that'll mean to the 2018 rate. But one of the challenges there is when you drill these incredibly strong wells, in some cases, we've had to restrict them for a while just because we didn't have the processing capacity and then, or suggests a drilling program. So, we're not drilling wells that we can't flow. But this has been a very good problem to have as you can imagine.

Okay. Great. And then just shifting gears, is there anything incremental to say on the San Juan?

Well, we've now got all of the six wells online. The last two have been on about two months now. There's two horizons in there. One is the Tocito which is the main one, and the second one is the Alvedo (32:35). Five of the six are in the Tocito and they've all performed very well. In fact, Mike and I were just out in our San Juan operation recently. The team has done a very nice job, but it's just a bit early days. But we're really encouraged by the results so far. They've been at or above our type curves in the early performance.

Okay. So, thinking is still probably early next year in terms of yay or nay as to whether this becomes the next core area for you?

Yeah. We're still looking at where does it fit strategically and how will it compete for capital, and trying to figure out how do you efficiently. One of the challenges in the San Juan is it has a whole lot less industry activity than obviously areas like the Permian or even the Eagle Ford. So we have to make sure, as we think about development, that we can do it efficiently. It is at the end of the pipes and it's at the end of the supply chain, so we're working on that pretty hard. We're just thinking about how efficiently could we develop this asset, and a lot of work is going on in that today.

Perfect. Thanks very much.

Thanks, Greg.

Our next question comes from the line of Josh Silverstein from Wolfe Research. Your line is now open.

Hey, good morning, guys. Just wanted to touch on the Permian growth program going forward. Obviously, a little bit of lumpiness in there as you guys are moving towards that development mode. But clearly, there was a step function in 2Q, and then another one in the fourth quarter coming forward. I was just thinking about looking out to the fourth quarter 2018, if this kind of 25 MBOE per day growth rate is kind of what you guys are forecasting in that outlook for next year, knowing there may be a little bit of lumpiness, but considering the rig program and the CapEx is roughly the same, if that's how we should be thinking about that.

Yeah, Josh, it's a bit early to get too precise on that. But you're pointing out something that's pretty important that folks understand, which is as we go to this cube development, ratability sort of month to month or quarter to quarter really just depends on when does a cube come online. And as you pointed out, we had big growth in 2Q. And as you've seen, we have big growth going into 4Q, a little flatter in 3Q. You should expect that. But I think what we're also strongly indicating is what we expect to deliver in the Permian this year both for the full-year rate and the exit rate, we're very confident in. So this sort of a bit of flux between quarters just should be seen as normal as you go to this larger industrial scale development approach. We'll even see a little of that over time even in the Montney as we bring on these big pads. So, I think you should just expect that. As far as where we expect to land in the fourth quarter of next year, I think we gave a pretty good indication for our core assets year over year, pretty similar to what we've done this year. Of the exact spread between them, as Mike said, we're still looking at how to optimize capital deployment across the core right now.

Yeah, so that's helpful. Yeah, I was just thinking about it in terms of the moving parts for next year with the Montney growth rate that you guys have outlined and then the Eagle Ford and Duvernay roughly flat. There is not that much growth that's actually needed to be at the $420 million (35:51) top end of the range, so that's what I was trying to get at there.

Yeah. I understand. And I'm just saying, it's a bit early. I mean, I think at the Investor Day, we kind of indicated that we may be putting a little more capital into the Eagle Ford than maybe we thought about a year ago because of some of these very, very strong results we've seen and a couple of other operators have seen. But we're not going to change the total plan which is grow within cash flow and also indicated that we expect capital would be broadly in line in 2018 with what we're spending this year. So, if we're going to spend a bit more in one area, we're going to have to spend a bit less in another area to maintain that discipline. But we're still doing that optimization right now.

Great. Thanks for that. And I'm curious, the Duvernay has definitely been kind of the deemphasized of the four core assets given what's happened elsewhere. But now that you've seen the playbook for a success in the Montney, I'm wondering if any thought has changed there about any sort of midstream development in the Duvernay?

Well, you're pointing to the right issue, which is to do any substantial growth there, we'd have to build out additional gas processing. It's the one place in the company where we actually own it, of course with our partner, PetroChina there. And that's got a two, plus or minus, year build time on it. And as we've been going through this inflection and trying to maximize capital productivity, that's actually led us to stay kind of flattish and basically a largely a drill to fill program. We continue to look at the out years around that. But at this point, I don't anticipate spending any large capital to expand the midstream in the Duvernay next year.

All right. Thanks, guys.

Our next question comes from the line of Gabe Daoud from JPMorgan. Your line is now open.

Hey, good morning, Doug, morning everyone. Maybe just going back to the Permian and the recent Qs. Can you maybe just talk a little bit about what was done differently if anything on the completion side relative to the earlier pads? And then specifically on the most recent pads, which zones were tested with those?

Yeah, thanks, Gabe. I'll hand that over to Mike to kind of walk you through what we're doing with completion design.

Hi, Gabe. Yeah, so most recently our latest couple of pads have gone to tight cluster spacing. So typically before that, we had sort of 50-foot clusters. We took that down to 25 foot while holding our sand concentration in that 2,000 pounds per foot. And that's what's given us the really encouraging results from our latest couple pads. And in the zones that we're developing is Lower Spraberry and Wolfcamp A primarily on those pads that we've been bringing online.

Yeah, and Gabe, one thing I'd add is, Mike and I just recently were down with our Eagle Ford team in the operation. We actually sat in the frac van and watched them pump one of the stages. And one of the things Mike and the team are really working hard on is, how do we now get the well performance and recovery results from these more intense completion designs but at lower cost. And I'm not going to tell you exactly what we did there yet, but we actually sat on location and watched them pump one of those tests right then and we'll be bringing these two wells on shortly. Because the whole idea is how do we actually get strong recovery and strong well performance at the lowest possible cost. And now we're trying to figure out how to actually get more efficient on these more intense completions, a big focus in 2018.

Got you. Thanks, guys. That's helpful. And then sticking to the Permian, in 3Q, I understand obviously there were issues with Harvey, but outside of Harvey, are you seeing any bottlenecks on the services side whether it's ancillary type stuff or maybe sand delivery to the wellhead? Are there any bottlenecks in particular that you're seeing?

I think there's lots of, depending where you are, but in particular places like the Permian and the Montney, which are very busy. You have to just manage the supply chain. And, so I think what you're seeing is some companies having their plans and programs being impacted by either access and availability to services or the performance of those services. We've been able to manage through that with some great supply chain work. As you know, we generally self-source things like sand ourselves and we manage the logistics. So we're trying to be in front of that. Mike already mentioned we've already essentially secured our frac services for 2018. Not only is that about availability and price, but we work really hard with those service companies to get it to the very highest performance and then we keep the crews. We don't want our crews rotating on to other operators' locations because we get them to a high-performing level and keep them there. So, I think it's good. A little bit of pressure around steel prices, which is a global commodity, but we'll manage that. And our goal here is any inflationary pressures, we'll find an efficiency in the business to offset those.

Got it. Thanks. Then just finally, again in the Permian, October had 80,000 BOE a day with oil around 50,000 BOE a day. 4Q, set it around 75,000. Is that just kind of conservative? Do completions slow throughout the rest of the year to kind of get to that 75,000 average? And then, and on the oil mix, 63% in October, does that ultimately stay there around 4Q or how does that change? Again, I understand that things move around, but just trying to get a better sense I guess of those two.

Yeah. I wouldn't, at this point, I wouldn't aim you off the 75,000. I mean as Mike mentioned, we had two things. We brought on a lot of new wells at the end of the third quarter with some of our latest completion designs, which were strong results. And we had had a few wells slow to clean up and have kind of been peaking now, or peaked in October. So, there's always a bit of that phase kind of behavior. But what I'd tell you is, is we feel good about the 75,000. And also the mix, I think Mike mentioned it, the oil mix here is, it's been around 17% plus or minus all the way. And it just moves around a bit because some areas have a little more gas and others are a little oilier, and it's just the mix as you bring those on. But I wouldn't aim you off 75,000 right now. It's sort of just the phasing of cubes and bringing wells online.

Sure. Makes sense. All right. Thanks a lot everyone.

Thank you.

Our next question comes from the line of Amir Arif from Cormark Securities. Sir, your line is now open.

Thanks. Good morning, guys. Just the well performance was very strong in 4Q and then you're setting up very well relative to 4Q production. And as you talked about earlier, you're talking, or I think on your Investor Day, you laid out about a 30% growth from 4Q 2017 to 4Q 2018. Just curious if there's any acceleration of volumes into 4Q 2017 or is it purely just on well performance in terms of how we think about growth exit to exit from 2017 to 2018?

Yes. It's really, you really nailed it with the second part there. I mean, trying to drive continued strong well performance has given us a stronger finish than we originally indicated at the beginning of the year for 2017. There is always a bit of a lumpy quarter to quarter shape as we've talked to already. But what we actually, I think Mike mentioned and Sherri mentioned, our capital guidance for the year is unchanged. So we haven't pulled in, if you will, capital from 2018 into 2017 to deliver this. We've done it within the budget that we set out for ourselves. So, it feels good. At this point, another 30% in the core, 4Q to 4Q feels good for 2018 and the exact shape of that and the exact distribution of the capital, we're still optimizing as we go through our budget process.

I appreciate the color. And then on Pipestone, the recent wells that you brought on, I mean they seem to be performing very well. They don't even seem to have turned over at all yet. Any update in terms of when you start debottlenecking your Pipestone area a bit more? I think you have something planned in late 2018 but any plan to try to increase that takeaway in a more meaningful fashion?

Yeah. So at the Investor Day, what we indicated is that, one, and we've had this sort of debottlenecking. It's really what we call a liquids hub which we expect to bring on late next year in Pipestone. We've had that kind of in the plan now for about a year or so. The new piece we talked about at Investor Day is substantial new growth in processing capacity that would come online towards the back end of the five-year plan. That's got kind of a two and a half year permitting and build time on it, but we're now confident we are going to expand beyond the existing facilities. The exact way we'll do that, we're still working through. Our preference is not to own the midstream. We're prepared to, but our preference is not to. And we're working that today, but the five-year plan does have additional growth in Pipestone kind of showing up in the 2021, 2022 timeframe.

Okay. Thank you.

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

Good morning and congratulations on the big uplift in October. My first question was just to better understand what's the approach in the Eagle Ford for 2018. Are drilling locations being prioritized to capture the Austin Chalk in a stacked configuration or are they also driven by other things like maybe optimizing infrastructure?

Yeah. Jeff, it's a mix of the two. I mean, I think that this year about a third of our locations were Austin Chalk wells. It's a little early. I don't know that that ratio will change in a big way. And obviously, we and a few others have had some incredible Chalk results. I would also point out, we've had some really good Eagle Ford results this year as well. So, and one of the things as you know, we've stepped kind of cautiously into the Chalk because it's more complex geologically. And what we wanted to do is make sure we didn't rush in and end up with poor wells to go with some good wells, to have some. And it's worked really well for us so far, because we've essentially only had good wells in our Chalk program. And then, the other thing we're trying to do is how do we do this in the most capital efficient manner, which obviously is trying to maximize the use of our existing facilities as opposed to building new ones. One of the things you may not be aware of, but tank batteries, which are the main facilities in the Eagle Ford, the gas is gathered at higher pressure than it is in a place like the Permian which means the tank battery is more expensive. It's more complicated. It takes compression and other things. And that's one of the reasons why we're trying to maximize the use of what's already on the ground, because it's a little more expensive to build it there than in other parts of the portfolio. And that's what Mike and the team are trying to optimize. We will be building some new tank battery processing capacity next year. But what we're trying to do is do it as efficiently as we can.

Okay. Thank you. That makes sense. My other question was, throughout this call, you mentioned with regard to the Midland cubes, you've tested a number of zones, experimented with well densities and mentioned a wide spectrum of wells per section. And then we also, a little while back, talked about a pad coming on. That was mainly Lower Spraberry and Wolfcamp A. I was just wondering if you could kind of just step back, and we realize there's going to be local variability, but can we just broadly say right now what are the zones that are going to be predominant over the course of the five-year plan? And maybe an average number of wells per section that we would expect to see. Thank you.

Yeah, I don't know the averages. But as you know, it actually depends kind of, you can almost think of it which county you're in. So, if you're in kind of the heart of Midland and northern Upton, today it's easily five zones at work and it could be as many as eight, because you've actually seen, and if we roll up and include Martin, which captures the real core of the basin, you've actually seen everything from the Jo Mill to the Middle Spraberry all the way down through the Wolfcamp C working. And in fact, one of the interesting things is that we were pulling some of our Midland Basin assessment work from 2014 and looking at what was working then and what we thought might work, and the list is a whole lot bigger today than it was then, which by the way, we believed would ultimately happen. But things like the Jo Mill and the Middle Spraberry were kind of gleams in the geologists' eye at that point as opposed to real. So it's expanding. As you go to the east and start to come up out of the basin, you sort of move into the more of the two to three zones, which will work. In terms of spacing, there's two dimensions to think of there. Laterally, I think what we've shown is we've gone down in the high 300s all the way to 660s. We think it will vary a little bit by zone and county. Generally, it will be less than 660s. We don't think it will be 330s, though. It's maybe 450, 500, but it will vary some. And then, some of the zones, particularly the Lower Spraberry and the Wolfcamp A are so thick, they may take two wells in sort of a wine rack pattern to ultimately recover the resource. All that's still evolving. But I would say when you're in the core of Midland and Upton, what we're doing now is kind of focusing on up to five zones. And then if you think that you could end up with something more than eight wells per section, that's how you get into that 40 to 50 wells per section. And then, if you go over into maybe somewhere like Howard, where it's three or two to three, you may end up more like 25 to 30.

Okay. That was very helpful. Thank you. Congratulations again.

Yeah. Thanks, Jeff.

At this time, we have completed the question-and-answer session and I would turn the call back to Mr. Code.

Thank you. This now concludes our call.