Welcome to the Apache Corporation's second quarter 2017 results earnings call. I would like to turn the call over to Gary Clark, Vice President, Investor Relations. Sir, the floor is yours.

Good afternoon, and thank you for joining us on Apache Corporation's second quarter 2017 financial and operational results conference call. Speakers making prepared remarks on today's call will be Apache's CEO and President, John Christmann; Executive Vice President of Operations Support, Tim Sullivan; and Executive Vice President and CFO, Steve Riney. In conjunction with this morning's press release, I hope you have had the opportunity to review our second quarter financial and operational supplement, which can be found on our Investor Relations website at investor.apachecorp.com. On today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, production numbers cited in today's call are adjusted to exclude noncontrolling interest in Egypt and Egypt tax barrels. Please note that all currency references in our prepared remarks are in U.S. dollars. Finally, I'd like to remind everyone that today's discussions will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss today. A full disclaimer is located with the supplemental data on our website. I will now turn the call over to John.

Good afternoon and thank you for joining us. On today's call, I will: review our approach to navigating the lower-for-longer oil price environment; discuss the strategic rationale and financial benefits of our pending exit from Canada; provide current operational highlights, including Alpine High; and conclude with our thoughts around balancing funding and spending in 2018. Since the beginning of 2015, we have restructured our business to adapt and thrive in a lower-for-longer commodity price environment. The organization reacted swiftly to the downturn in oil prices. We stressed the importance of properly aligning cost structure with commodity prices as well as achieving and maintaining cash flow neutrality. We completed a series of transactions that simplified our portfolio. We reduced operating costs, overhead, and capital commitments, and significantly improved the balance sheet. With regard to our asset base and strategy, we successfully expanded and enhanced our organic unconventional North American acreage footprint and technical capabilities. We also focused our international capital spending to deliver strong and sustainable free cash flow from our core businesses in Egypt and the North Sea. These efforts were supported by significant improvements in our planning and capital allocation processes, which helped drive our strategy of returns-focused organic growth. In early 2017, WTI oil prices were trading above $50 per barrel, with the out years of the NYMEX strip trending even higher. We had concerns about the fundamentals underpinning this oil price optimism and the corresponding cash flows from operations. At the same time, we had just announced our discovery at Alpine High, a very attractive large-scale opportunity which would require significant near-term investment. Given our strong financial position, a cost structure that was now properly aligned with commodity prices, and a deep inventory of fully burdened high rate-of-return projects, we believed it was appropriate and value creating…

Good afternoon. My remarks today will cover operational activity and key wells in our focus areas, new technologies we are applying to improve our performance and service and supply cost trends. Our second quarter production results reflect the lingering impact of last year's reduced capital and development activity. These effects, combined with the scheduled maintenance activities in Canada and the North Sea, contributed to a 3% production decrease on an adjusted basis from the preceding quarter. With those events behind us, we are shifting to a growth trajectory for the remainder of the year and beyond. During the second quarter, we increased activity at a measured pace, averaging 35 operated rigs worldwide with 17 in the Permian, 1 in the Mid-Continent, 13 in Egypt and 4 in the North Sea. In North America, second quarter 2017 production averaged 244,000 barrels of oil equivalent per day, down 3% from the first quarter. In the Permian Basin, production of 146,000 BOE per day was flat compared to the preceding period. I'll begin with an overview of Alpine High in the Delaware Basin, where we have six rigs operating today. At quarter close, 11 wells were connected and producing into our midstream facilities, five of which were constrained to control flow as we commissioned newly-installed equipment and evaluated initial reservoir performance. Six wells were in various stages of flowback and testing, and 17 wells were waiting on completion, or shut-in waiting on infrastructure. Subsequent to quarter-end, we have connected additional wells, and production continues to impress. In addition to the Alpine High parasequence wells that John mentioned, we also recently completed a Barnett well with a test rate of more than 7.7 million cubic feet of gas, 400 barrels of oil and 450 barrels of NGLs per day from a 3,300-foot lateral. I…

Thank you, Tim, and, good afternoon, everyone. On today's call, I will review our second quarter financial results. I will provide an update on quarterly and annual guidance items, which will reflect the full anticipated effect of Apache's exit from Canada. And lastly, I will comment on our updated hedges and the continuing strength of our financial position. Let me begin with second quarter financial results. As noted in our press release, Apache reported net income of $572 million or $1.50 per diluted common share. Earnings were positively impacted by a net deferred income tax benefit related to a financial restructuring in Canada in preparation for the exit. This consists primarily of a $678 million reduction in a U.S. deferred income tax liability with respect to untaxed foreign source earnings. Together with some other smaller adjustments, the total tax benefit excluded for purposes of calculating adjusted earnings is $670 million. Results for the quarter also included a number of other items outside of our core earnings that are typically excluded by the investment community in published earnings estimates. These include a $26 million unrealized mark-to-market gain on our commodity price hedge positions, $25 million of unproved acreage impairment and $18 million of loss related to recent divestitures. Excluding these and other items, our adjusted loss for the quarter was $79 million or $0.21 per share. Note, this adjusted earnings still includes the effect of dry-hole costs incurred of $46 million or $0.08 per share after tax. Cash flow from operations in the quarter was $751 million. This includes a working capital benefit of $148 million. Our cash position on June 30 was $1.7 billion, a slight increase from the previous quarter. Turning to costs, lease operating expenses in the second quarter were $8.81 per parallel of oil equivalent, an increase…

Our first question is from the line of Bob Brackett with Bernstein Research. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: A question on the Midland Basin. There's been a lot of talk amongst investors about rising gas-oil ratios in that play and the potential that they're displacing forecasted oil type curves. What's your view on that? How do we think about your GORs in the Midland?

This is Tim. In the Midland Basin, our shale wells, they're performing in line with our type curves. We really haven't been surprised by the GORs. We understand the producing characteristics of our different areas that we operate in. And our GORs are performing as we would have expected. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Okay, great. Thanks. The other is, do you have an estimate of where you were Alpine High sort of end of – or currently or call it the end of 2Q?

Actually in the prepared remarks, Bob, we said we produced 7,400 BOEs a day net to Apache. 10% of that was liquids and almost all of that was oil in the month of June. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Got you. Thank you.

You bet. Thank you.

Our next question is from the line of Arun Jayaram with JPMorgan.

Yeah. Good afternoon. John, I wondered if you could give us a little bit more detail. In your prepared comments you talked a little bit about how you expect Alpine High to perform in the northern part of the field versus the south. So I wondered if you can give us a little bit more color around that.

I mean, Arun, I think the good news is, is we got online early. We were scheduled to bring everything on July 1. We have some of the stuff to talk about in the second quarter, because we were able to bring things on in early May. Things are progressing really as planned. We were able to sell net to Apache 7,400 BOEs a day in the month of June. And like I said, we've been bringing up the CPFs. If you look at kind of where we are today on the infrastructure, we now have 35 miles of the 30-inch trunkline in. We've got over 40 miles of gathering in. There are two CPFs that are operating with eight tank batteries. And then in August and September, we've got our third CPF coming in – coming on in August, fourth and fifth in September, as well as a connection to the south. And so what we've said is, our volumes are – we're currently producing about 60 million a day net to Apache. You're going to see that grow to 100 by September. And you're going to see the liquids ratio grow as well, especially as we start to bring on more NGLs. So a lot of exciting things. We only had 11 wells on in the quarter, and really five of those have been constrained. So we're really, really just getting started.

Got you. Got you. And then, just in terms of – you talked about by year-end getting to six CPFs. What type of productive capacity do you get from six CPFs?

We've said that we're going to be bringing on these CPFs in increments, 50 million to 100 million a day. They're all going to be able to be incrementally added. So what we've done is given you volume forecast and guidance. Right now, we are constrained, but we hope to resolve that as we catch up, as these things come on in the next couple of months. And then, from there, we hope to have more capacity than we'll have volumes.

Got you. And just my follow-up is just in Egypt, what is your plan to explore on some of the new licensed acreage that you've received, I think, earlier this year?

It's going to – it depends on the timing. Right now, as we've said, we're shooting a brand new high-res 3-D across our existing acreage. And as well, we'll be shooting the new permits as soon as we get the final documents signed. Everything's approved. We're just waiting on the final documents. So that should happen here pretty soon. We'll get started on the seismic in this fall, and we could potentially drill our first well this fall. We see a lot of low-hanging fruit, and we're very, very excited about the potential. I mean, they're very large concessions. We know a lot about them. And – I mean, they're going to be a real, real shot in the arm. You got to go back to over 10 years since we've had two new concessions. Not anything of this size either, so it's going to be a real shot in the arm for our Egypt production, maybe late this year, most likely as you start to go into 2018, 2019, and beyond.

Our next question is from the line of David Tameron with Wells Fargo.

All right, good afternoon. John, could you talk about – do you guys have a definitive timeline as far as when we'll get more clarity around the potential resource at Alpine High?

David, as we've said, we're ramping up most of our wells, like the wells we disclosed on the last earnings call. We cleaned them up and shut them in. Most wells have been waiting. We've got – as Tim said in his notes, we've got a lot of wells waiting on the infrastructure. Now that we have the facilities and things, it doesn't make a lot of sense to be flaring volumes and things. And so, as we bring more things on, I think you're going to continue to see a lot of data coming. And when we get to a point that it makes sense to talk more definitively, what we really want to do is get the processing facilities lined out, get more time behind the wells, continue with our optimization work, and at some point, we'll come back with something very meaningful and very definitive. But I think what we've continued to state is that we feel very, very good that we have more than 3,000 wet gas locations. Your best EURs would be to look at what we disclosed at Barclays almost a year ago. And now we said with the two Wolfcamp wells that are, by the way, in two different zones in the Wolfcamp, in a significant distance between those wells, we feel very confident now that we have hundreds of locations in the Wolfcamp, so – that will be oil locations. And – so we'll come back as we get more data. We're really just getting started with our infrastructure and being able to bring things on and produce them into ideal production situations.

Okay. I think – let me just stay with Alpine High then. Midstream, future funding, there's been a lot of talk about whether you sell it, whether you bring a partner in, whether you're going to go out alone. Any additional color you can give us on that?

Well, I think what you've seen is this year we had an outspend on our infrastructure side and now we've more than covered that. As we look at 2018, we – the 2018 budget had originally looked at $55 as a price target. We've said that there are lots of options we have on that. Our spend in 2018 is planned around $500 million. We're probably going to pull some of that into this year as we stated within our $3.1 billion budget. So we feel very comfortable that we're going to be able to handle that funding without having to stress the balance sheet, issue equity, or really put ourselves in a bind.

All right, thanks.

Our next question is from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Good afternoon, thanks. In the Alpine High, specifically on the oil zone test, I realize that it's early. But can you speak to your initial thoughts on the deposition of both the Wolfcamp and Bone Spring across your position?

It's going be very similar, the parasequences. So they were laid down at a time when you had very rapidly rising sea level. And so there is some discontinuity in them just like there is in all of the Delaware Basin, so very similar. And so you've got a lot of mixed things in there. But we're very excited about what we've got. And these two wells are going to perform very similar to the other wells in the Delaware Basin. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Great. And then staying in the Alpine High but on optimized completions, can you give us some detail on what you're testing, when we can expect to hear more, and what early indications you have, if any?

When we talk about optimization, there's really a lot of things. It involves targeting, spacing tests, pattern tests, landing zone, lateral length, the orientation, and in the completion design. And even in the completion design, you've got your fluids in terms of your volumes, your sand concentrations, the stages, clusters, everything. So we have begun the optimization process. We've actually had 11 wells into the system at the end of the quarter. As we bring more in, clearly we're going about it very methodically like we have the whole play. And as we get to points where we draw some conclusions, we'll start to make those more clear. But we're doing a lot of things. We've got some longer laterals. We've got some larger fracs, targeting, azimuth, everything. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Thank you.

Our next question is from the line of Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs & Co.: Good afternoon.

Hey, Brian. Brian Singer - Goldman Sachs & Co.: A couple follow-ups on the capital allocation question. When you say moderate outspend for the near term, can you add more color on the length and threshold for that outspending? And I guess relatedly, if Alpine High midstream is where you see the outspend happening, when does the midstream achieve critical mass, and then when would we expect the outspend to end?

When we think about – right now we're just talking 2017 and 2018 is what we've been looking at. So if you look at 2017 and 2018, that would be that time period. I think the important thing with our infrastructure at Alpine High is it's going reach a critical mass where we really believe middle of next year we could be in a position to start to monetize a portion of it or do something there. So we'll look at 2018 as we start to roll into – later this year or early next year, we'll start to give another look into 2018 and beyond. But we're looking right now at 2018. The other thing I'll say about 2018 as our original budget had it – which is really flat activity to this year, had a $55 deck in there. $5 in oil price means about $350 million of cash flow to us. And so we see we have a lot of flexibility with our program. One, we can reduce activity. Two, if we really are in a sub-$55 world next year, then our cost structure is going be lower than what we have in that budget. So there will be the ability to get more for that activity set. I think we've shown this year we can do some non-material asset sales, which I would not put the strategic exit from Canada in that bucket. I've touched on the Alpine High midstream, and then we also have a very nice $1.7 billion of cash on the balance sheet. Brian Singer - Goldman Sachs & Co.: Great, thank you. And then switching to the Alpine High Wolfcamp oil well, the first well that you announced where you talked about 1,000 BOE a day, it looks like that would imply about 700 barrels a day of oil in the first month, and then about 350 to 360 barrels a day for the remainder of the 75 days. I just wanted to check in on both your expectations for well costs for these wells and then if these rates are in line with your type curve and what rates you're looking for from the next batch of wells.

It looks really good. I think the thing we'll say, number one, it's approximately 4,500 foot lateral. It has come on 70% oil. And the 30-day average is actually greater than 1,000 BOEs a day, and it did produce 37,000 barrels of oil in the first 75 days. A lot of the research this morning has come out tagging that as BOE, which is not correct. Very typical profile to a lot of the other Delaware wells. Good charge. We'll have more water than we'll have in our resource zones in the Woodford, Barnett to pin, so it's going to be very typical characteristics and very, very strong profile, and performing very, very well.

Our next question is from the line of Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Company LLC: Good afternoon, John, to you and the rest of your team there.

Hi, Charles. Charles A. Meade - Johnson Rice & Company LLC: Thank you. You guys have fielded a lot of Alpine High questions, so I'm going to go a slightly different direction. I think you – perhaps Tim hinted at this in some of his earlier comments. When I look at the wells you guys have drilled already, you've drilled 1-mile laterals with a significantly lower completed well cost than your peers have been delivering in the area. But I think what I heard is that going forward, at least in the back half of 2017, you guys are going be going after longer laterals which presumably will have some higher completed well costs. And I wonder if you could characterize for us where you think you are on your optimization of your well design and your completion time design for those Midland Basin wells.

Charles, what we've been doing primarily is we've been drilling mile laterals in our three core focus areas; Wildfire, Powell, and Azalea. If you go back to 2016, we changed our completions dramatically since then. And one thing I might note though, if you look at our completed costs from 2016 to today on those mile laterals, our completed well costs have remained relatively unchanged at about $4.5 million. And a lot of that has been the conversion from drilling one-offs to going to pad drilling and getting the efficiencies obviously from batch drilling and the savings that we see there. Going forward, we've got about 30 wells. We've got about five different pads that we anticipate we're going bring online in the second half, and most of those are going be mile and a half type laterals. And we are still doing a little bit of spacing testing and landing zone testing along with this development drilling that we're doing as well. So the completions are still – we're still working on them, and every area is a little bit different, so I don't think we'll ever get to one completion design that will be standardized across the entire play. It's going be tailored to the type of rock that we've got at each field that we have. So it's something that we will continue to optimize, and we'll really never be done with that process. Charles A. Meade - Johnson Rice & Company LLC: Okay, thank you for that, Tim. And then if I could ask a question about the North Sea, and you had those impressive well results with Callater. And I'm wondering if you can guide our expectations a bit with respect to North Sea results going forward. Should we look at Callater and particularly at the idea that this most impressive well was on offset fault block? Should we be looking for more sorts of results like this, or is this a one-off sort of thing that we ought not look for a repeat?

Callater is a well we disclosed in 2015. It was a new discovery. There will be some offsets. We announced another fault block there with that, so we're very excited about the area. I think the best thing to do in terms of forecast is just look at what we've guided to, Charles. I mean, we've had this well planned in and this development baked in. It's really a function of the exploration program. We've had a series of announced discoveries over the last couple of years that are in the queue to be coming on in the future, and Callater is kind of in the first of those that we're tying in, in 2017, so...

Our next question is from the line of Evan Calio with Morgan Stanley. Evan Calio - Morgan Stanley & Co. LLC: Hey. Good afternoon, guys. Maybe I'll bring it back to the Alpine High. And maybe I missed it, but when do you guys expect to reveal the larger development plan you discussed in the call? Is it – is that in connection with the 2018 CapEx budget? And if there's no specific date, what still needs to happen there before you feel confident in that plan?

Well, we feel confident in the plan, Evan. I mean, obviously, we gave guidance this year for a two-year look. We've given you a 2018 4Q exit rate, and we didn't touch any of those numbers this quarter. In fact, didn't really touch our guidance at all, other than adjusting for Canada. So we have a plan that we're working on. We're always updating it with new data. We've still got a lot of areas we are testing and bringing things in, but we have a base plan and we gave you a two-year look at it this year. Obviously, we'll choose as we're phasing in and bringing things on. We've said we're at 60 million a day net today, and we'll be north of 100 million in September. And as we get more color and continue, we'll come at it sometime in the future and give you a longer look. But we gave you a good two-year look, and for now, we have a lot of confidence in that. Evan Calio - Morgan Stanley & Co. LLC: And maybe to follow up on that, the 100 million guide, can you walk us through how that estimate is billed? Meaning, how many wells are connected and what percentage of them will be on constrained flow because it's harder to – it's harder to kind of model for us?

The better thing to do is look at the numbers we gave you and run off of those, because we've gone end of the first – end of the second quarter we had 11 wells on and five of them are constrained. And we should get to a point where we don't have constrained wells as we get these next three CPFs up over the August and September timeframe. But we haven't given an absolute well count, as that's dynamic. But what we have given you is ranges, Evan. And we said, in June we produced 7,400 barrels of oil equivalent a day net. It's not gross; that's net. And it was 10% liquids, and almost all of that was oil. And the liquids ratio is going to grow as the volume grows in the future.

Our next question is from the line of James Sullivan with Alembic Global Advisors.

Hey. Good morning – good afternoon, guys, there. I just wanted to go back to that Wolfcamp oil well real quick. You talked, John, about there being a nice charge in that well there, and a couple of comments on the overpressure there. Could you just talk about how you released that well, I mean, in terms of initial chokes and how you were kind of letting it out there? Any color you can give on that would be great. And on pressure drawdowns, too.

It's just a very, very strong well. We've flown it back naturally, and there is a sub pump in there today. And it's very typical to the other wells we have and the other areas of the Delaware Basin.

Okay. Great. Sounds good. Just on – over to the North Sea real quick, you guys did the turnaround over there. Can you quantify the amount of volume that was offline there for the quarter?

For the second quarter, it was just under 7,000 barrels of oil equivalent per day. That was offline. Some of that turnaround got pushed into the third quarter. So we'll see some downtime from turnarounds in the third quarter as well.

Okay. And then Q4 will be more like your run rate?

Correct.

Great, thanks so much.

Our next question is from the line of Michael Hall with Heikkinen Energy Advisors.

Thanks. I guess just a couple on my end. As it relates to the DUCs and wells waiting on infrastructure and just I guess general backlog in the Alpine High, how many of those at present are currently in the oilier zone?

Yeah. Right now, Michael, we've got a mix. We haven't given breakdowns on that. You've got a range, some of those are going be wet gas wells. Some of them are going to be – there's a few we've got several that are in flow-back. So it will be a mix kind of like we have across our play.

Okay. But specific to the Wolfcamp or Bone Spring, you don't, by chance, have that available?

There's going be more than two, and I'll just say that.

Okay, fair enough. And then I guess the other was just still on the Permian, but higher level. I was just curious when you guys think you'll see oil volumes in the Permian turn around? They've been obviously on decline, but you've got a big back-half ramp that you've outlined. Do you think we'll see sequential growth in oil volumes in the third quarter or how should we think about that?

Yeah. So, we have turned the corner now on growth, not only in international and in North America, but just on North – our Permian oil growth will be – continually grow quarter-after-quarter.

Okay. Appreciate it. Thank you.

Our next question is from the line of Jeffrey Campbell with Tuohy Brothers.

Good afternoon.

Hey, Jeff.

Hey, John. In the Permian Basin, many producers are moving towards completing all the locations of a given zone or maybe even several zones and wants to avoid well interference and enhance efficiencies. I was just wondering what is your completion approach as you're increasingly focusing on drilling more wells and zones per pad.

That's a novel idea. We've always talked about – ultimately you do your testing, so you can get to pad development, and that is the optimal way to do that. So you want to get in the pads where you can develop the rock and produce it in the best way, shape or form. So it's exactly the approach we're taking. That's – we've got some 10, 11 well pads coming on later this year in Midland Basin. So I mean it's clearly the direction you want to go with all of it.

Okay. Thanks. And my other question is in Egypt. With the large increase in acreage, how will you allocate capital there over the next year or two? I mean, obviously you're having great success in the areas where you have concentrated operations. So I'm just wondering how will exploration spend on the new acreage look relative to the spending as a whole.

It's probably going be pretty similar to how it's been. I mean, we drill quite a few exploration wells in Egypt every year anyways. So as Egypt continues to generate more free cash flow, potentially you could see more capital. But we're not going to change philosophically how we're thinking about that. But it's an exciting place. I mean, I think we're going to find ourselves with better – some pretty strong deliverability things, much like Ptah and Berenice have been over the last couple of years. So a lot of low-hanging fruit that should help us with volumes and also with the ability to generate more free cash flow and also reinvest more.

Okay. Thank you.

And our last question is from the line of Doug Leggate with Bank of America.

Thanks, everybody. Good afternoon and thank you for getting me on, John. John, you guys are...

Only for you, Doug.

I'm trying to take advantage of you a little bit here, John, because you're uniquely qualified with your background and your vertical well inventory for the history of Apache to really opine on this issue that, I guess, Bob brought up earlier. Obviously, sector is getting annihilated in the back of this GOR issue. So I'm wondering if you could take just a little bit of time and just maybe do the market a favor and explain what you meant by the type curve or the gas breakout, the GOR has not changed adverse to your expectations. And what I'm getting at is the difference between the pressure drawdown in the vertical versus the pressure drawdown in the horizontal. What are you seeing there? Is there anything different in the oil recovery in your Midland Basin wells versus what you expected and versus what you've planned on based on that vertical well history? Because there seems to be a little bit of a panic going on that this is actually a deterioration of oil recovery as opposed to an enhancement of gas and NGL recovery. Could I ask you to...

I'll say a few things. Number one, we've always forecasted our oil and gas streams separately. Like – I mean, it's just fundamental petroleum engineering. Anybody forecasting BOE curves and you've got changing dynamics out there you have to model it. I mean, it's like anything else though, Doug. You do your core work, you do your fluid analysis, you look at your pressure and temperature data. And we can model that. We've got a lot of history and we do a lot of time modeling that. And so our wells are producing and – as our type curves are laid out. And we have not had any surprises in terms of the forecasted volumes with how they are performing. Areas behave differently. And if we go back to some of our earlier areas where we drilled some wells in 2010 and 2011, they were in a little less mature area, a little higher GORs, they're going to behave differently. We've got a lot of history and have a deep understanding of how this works. And so we're not surprised by the GORs and you have to examine those very carefully. And – but every rock, every area, the rocks will differ depending on the play, and that's why it takes time to collect the data properly, do the core work, do the fluid work, do the pressure work and create your material balance just like you would in conventional rock. But there's a difference.

I appreciate that.

There's just a real difference between how conventional and unconventional reservoirs behave and there's a difference how they behave over time. And you'll see contribution from different types of the fabric as it goes forward.

So just to be clear, I know we're out of time here. So if I could just add two quick pieces to that, one is, related to that, the vertical pressure drawdown versus a horizontal pressure drawdown, would you concur with the idea that the horizontal is getting the gas breakout quicker but not changing the material balance?

I wouldn't say that rock is going to drawdown and break out exactly how it's exposed to the surface. So that's just a function of temperature and pressure and the drawdown. The orientation of the well isn't going to have as big of an impact as just how the rock is going to behave under pressure and temperature and how the makeup of it is.

Okay. And my last one is more Apache-specific. What do you need to see to declare a broader oil inventory in the Alpine High? Obviously, you've given another couple of wells today. And if I may, when that happens, I assume it's going to happen at some point, would it change your targeting on how your initial development plan versus – oil versus gas? And I'll leave it there. Thank you.

I'd say any incremental well, obviously, you tweak your plans as you go through it. You'll see more from us as we bring more wells out. We've had 11 wells on the end of June, half of them, or five of them were flowing constrained. We've just got a lot of data coming over the next couple of quarters. But it's very exciting. We're going to be very deliberate on what we disclose. We're not going to come out with big location counts unless we're confident in those location counts. And there's a lot of rock to test even in our parasequence zones. So there's a lot of exciting things. We've got a big thick column, 5,000 feet of hydrocarbons over a 65-mile area down there, and a lot of rock to work with, so you're going to see a lot more locations coming out of us in the future.

And that does conclude the Q&A portion of this call today. Thank you for your participation. Ladies and gentlemen, you may now disconnect.