Good morning. My name is Natalia, and I will be your conference operator today. At this time, I would like to welcome everyone to the Second Quarter 2018 Earnings Call. Please limit your questions to one question and a follow up. Thank you. I would now turn the call over to Mr. Gary Clark, Vice President of Investor Relations. You may begin, sir.

Good morning, and thank you for joining us on Apache Corporation's second quarter 2018 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. Our prepared remarks will be approximately 25 minutes in length with the remainder of the hour allotted for Q&A. In conjunction with yesterday'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, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interest in Egypt and Egypt tax barrels. 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. And with that, I will turn the call over to John.

Good morning, and thank you for joining us. On today's call, I will begin with commentary on Apache's second quarter production results and our outlook for the second half of 2018. Then I will provide an overview of the progress we are making in our key regions. Tim Sullivan and Steve Riney will then provide some additional operational details and summarize our second quarter financial performance and guidance before turning it back to me for closing remarks and a comment on the status of our midstream transaction. 2018 has been a year of continued progress on important strategic initiatives and operational performance. On the operational side, we have made several significant advances including drilling efficiencies, strong operational runtime, base decline mitigation, new well outperformance and a step change reduction in Permian Basin completion costs and cycle times. All of these have contributed to our positive production trends year to date. This is most evident in our strong second quarter U.S. results, where solid execution and an increasing pace of activity enabled us to exceed guidance by 7,000 BOEs per day. The Permian Basin was the primary growth driver in the quarter with oil production in the Midland and Delaware basins up almost 6,000 barrels per day from the first quarter. As highlighted in last night's press release, based on this performance, we are raising our full year 2018 U.S. production guidance to 260,000 barrels of oil equivalent per day and we are raising full year 2018 Permian Basin guidance to approximately 210,000 barrels of oil equivalent per day. Both of these are above the high end of our prior guidance, which was increased in May. In our international operations, second quarter production was roughly in line with expectations. We are updating full year 2018 guidance to approximately 134,000 barrels of…

Good morning. My remarks will briefly cover second quarter 2018 production and operations performance including drilling highlights and activity in our core regions. Operationally, we had a very good quarter and saw improvement in many key areas. We achieved second quarter company-wide adjusted production of approximately 390,000 barrels of oil equivalent per day, a 16% increase from the same period a year ago and up 6% from the first quarter 2018. The Permian Basin remains the primary driver of our growth, where oil production increased 25% and total production grew 39% from the second quarter a year ago. These increases reflect the ongoing development of oil production in the Midland and Delaware Basins and the continued ramp up at Alpine High. We averaged 17 rigs and 4 frac crews in the Permian Basin during the quarter. In the Midland Basin we placed 22 wells online in the second quarter, all of which were on multi-well pads. Results are exceeding our expectations and the information we are gathering is critical to optimizing full field development plans. During the quarter, we drilled a number of notable pads, and I would refer you to our financial and operational supplement for more details on these results. Moving to the Delaware Basin and our Wolfcamp development in the Dixieland area, we placed on production 11 high-rate oil wells that are also in our supplement. We are seeing impressive results with only one mile laterals. We have two proven targets in the Upper Wolfcamp and plan to test two additional targets later this year. At Alpine High, our well connections are heavily weighted to the last seven months of the year. We have included a chart in our quarterly supplement that illustrates this cadence by month, which as John noted, will lead to a sharp production…

Thank you, Tim. As noted in the press release issued last night, under generally accepted accounting principles, Apache reported second quarter of 2018 net income of $195 million or $0.51 per diluted common share. Adjusted earnings for the quarter were $192 million, or $0.50 per share. Second quarter financial performance was good across the board. Production volumes were strong as John outlined previously. Average realized oil price was over $69 per barrel as nearly 70% of our global oil production received Brent or Gulf Coast linked pricing. Costs remained under control as LOE, G&A, DD&A and cash taxes were all consistent with or better than latest guidance. Capital investments in the quarter were $833 million, bringing the first half total to $1.69 billion. As John noted, we plan to invest at a similar pace in the second half of the year, which will bring our total planned capital in 2018 to approximately $3.4 billion. This represents about $400 million of increased investment relative to prior guidance, which can be characterized as follows. The majority of the increase, roughly two thirds, is attributable to incremental drilling, completions and facilities investment in the Permian Basin including Alpine High. This reflects the two Midland Basin rigs we are adding in third quarter, the costs for longer laterals and larger stimulations in Alpine High and a slightly higher well count throughout the Permian due to the efficiencies in our drilling program. Approximately $145 million of the incremental investment will be at Alpine High and $120 million will be elsewhere in the Permian. For all of the reasons John outlined previously, these increases will maximize capital deployment efficiencies and will help drive incremental production in late 2018 but more materially into 2019 and beyond. Approximately $75 million of the additional capital is attributable to general…

Thank you, Steve. I would like to sum up by emphasizing that 2018 has been an exceptional year thus far in terms of strategic progress and operational execution. The capital efficiency of our drilling and completion programs is improving throughout the Permian Basin. We are running at an optimized activity level and pace demonstrating good cost discipline and generating high rates of return. At Alpine High, now we have our primary infrastructure in place and are in the early stages of a significant long-term value accretive production ramp. We are seeing some excellent well results and our cryogenic processing is on track for a mid 2019 start-up, which will drive a significant increase in liquids production, cash margins and returns. In the Midland and Delaware Basins, our wells are outperforming and unconventional oil production is the primary driver of our U.S. production guidance increase this year. Notably, in less than one year, we have completely replaced the 50,000 barrels of oil equivalent per day of the vested Canadian production with Permian volumes. This strategic portfolio rotation is positively impacting our margins and is a great example of Apache's returns-focused portfolio approach. We continue to generate substantial free cash flow in Egypt and the North Sea as these regions benefit from premium Brent crude prices as well as higher realized NGL and natural gas prices than the U.S. And lastly, I know that many of you are curious about the status of our midstream business. We have been engaged in a very thoughtful and deliberate process with regard to creating and realizing value for our Alpine High midstream assets. As you have seen in our recent announcements, we have secured equity options in five transportation projects that will move oil, gas and NGL to the Gulf Coast from the Permian Basin. These options are very strategic for Alpine High, Apache and the Delaware Basin in general. We have worked the timing of these options to coincide with consummation of a larger midstream transaction to leverage their fully integrated value potential. We are in the advanced stages of a transaction that we anticipate will close before year-end and we'll come back to you with more details on this as soon as practical. And with that, we will turn the call over to Q&A.

Your first question is from the line of Bob Brackett with Bernstein Research. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Hi. Question on the Alpine High. In the past, in recent past, you've guided toward the typical Alpine High well at say, 9 to 15 Bcfe, that upper range, 16 to 21 Bcfe. But those were at 4,400 foot laterals. So my question is two part, one, how should we think about these more recent 8,000 foot laterals in terms of EURs? And two, can you guide us directionally toward the typical well versus the upper range well? Where are the arrow bars on what those EURs could ultimately be?

Bob, good morning. It's a great question. I will tell you that we are early in changing the completions, as we've alluded to. That's one of the reasons on the capital side. We now have enough data going back to last year that confirms some of the strategic testing on the larger fracs is making a bigger impact as well. And so we're kind of shifting gears and we're early in those and for now I want to leave those because our location counts all kind of tie back to that. But we will be coming back with, as we get some more of these wells on and we do some more testing, you're going to see numbers go up as the productivity improves. So we'll come back to you with those and update, in general, the whole impact of that. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: But should I think of things in terms of EUR per foot or should I just wait?

EUR per foot, I can tell you, we're seeing is translating pretty equivalently. So the longer laterals are going up on the lateral side, but I think with the opportunity to see even more changes is going to be on the completion designs which we're about to start doing on some of these pads. So for now, lateral foots, you can probably translate to what we've shown. But we'll come back to you when we've got more data to prove it. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Okay. Thank you. Quick follow up. What are you doing exactly to save $400,000 on the completion side? Is it efficiencies or technology or some combination?

Bob, a lot of it is just operational efficiencies. On the completions side, we've really been able to reduce our pump time substantially. We're drilling out our plugs even quicker and we've even made progress just on frac crew moves. And this is related to, it's given us a 20% reduction in our cycle time, which is on a mile and half lateral is about $400,000 savings. So it's primarily just completion efficiencies.

And, Bob, I'll add to what Tim just said. If you go back, I mean we realized in early May we were running into it was going to create some challenges. And the good news is, we set a frac crew down in the Midland basis for two months, both June and July, and still been able to come in ahead of guidance on the numbers. So I really have got to give a lot of credit to the operational folks and the teams for the progress that we're making. And we said this would happen. I mean this goes back to the strategic testing we did last fall when we started doing pads on half section tests in the Midland Basin, you're seeing those results and now you're seeing us also doing similar things at Alpine High. So really, really credit to the field folks and the engineers and technical support.

Your next question is from the line of John Freeman with Raymond James. John A. Freeman - Raymond James & Associates, Inc.: Hi, guys.

Good morning, John. John A. Freeman - Raymond James & Associates, Inc.: So the first question related to Alpine High midstream, and I'm just wondering if you can kind of talk about how you sort of think about the trade-off with any potential deal where you're trying to remove future CapEx while also trying to retain as much equity as possible given the knowledge that, as Alpine High volumes ramp pretty dramatically in the next few years, the value of the Alpine High midstream goes up considerably as well.

Well, I mean in a lot of ways you just kind of answered your question. But I'll say a few words here, a little more than in the prepared remarks. We're deep in the process and we are very confident that we will get something done by year-end. Clearly the number one objective has been to remove capital from where it's competing directly with our upstream capital, which and moving it into a separate funding vehicle, which we will do. The second thing, as you pointed out, we want to maintain as much of this enterprise as possible purely because number one, I think everybody's going to figure out that it's much more valuable to Alpine High, to Apache, and even the whole Delaware Basin than people realize. And secondly, we see that value as growing and accreting significantly over the next several years. So we'd like to hang on to as much of it is possible from that standpoint. On the timing, we've had to kind of coincide this with some of the equity options that we've been announcing and as we alluded to in the comments, there's now five of them, so we've kind of had to run those in parallel paths. But we're now deep into the throes and clearly we want to be able to hang on to as much of it as possible. John A. Freeman - Raymond James & Associates, Inc.: Thanks, John, and then my follow-up, just on looking at the revised CapEx budget, the changes on the U.S. side makes perfect sense. When I'm looking at the international CapEx number, which actually didn't change despite the increased kind of fast tracking on Garten, and then what's happening with Suriname, is there some other areas internationally that either are getting less capital than previous or you're just doing better on some costs? Or just, what allowed international to stay flat despite what's happening with Garten and Suriname?

I think that's just kind of in the round off. I mean the big thing is capital is actually going up in the North Sea with Garten as we now have 100% of it. But the other thing is, some of it's timing of the Ocean Patriot and we've reset that rig contract now to a significantly lower number than we've been burdened with the last three years. So it's kind of getting caught in the round off there, but it actually has gone up as we accelerate Garten on the capital side. John A. Freeman - Raymond James & Associates, Inc.: Great. Thanks, John. Nice quarter.

Thank you.

Your next question is from line of Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Co. LLC: Good morning, John, to you and your team there.

Good morning, Charles. Charles A. Meade - Johnson Rice & Co. LLC: I wanted ask a question about the Blackfoot pad and what you guys are seeing on the early flow-back there. I know you talked a little bit about in your prepared marks and you put some stuff in your slide presentation. But I wonder if you could share any more color on where you are on the flow back of that pad, if you're almost done cleaning up or you're still in the early stages of cleaning up on some of those wells. And what, if anything, you're seeing between, what kind of variation you may be seeing between the upper Woodford landing zones and the lower Woodford landing zones?

Well, Charles, I'll say it's dynamic. I mean, first thing is as you know, this is 12 wells in the Woodford in a half section. So this would translate into a full section of 24 Woodford wells only, which is a lot. They're on 660 foot spacing. We are not seeing any interference. I will tell you, it's is very, very dynamic and we're very early. In fact, we went to print yesterday with our numbers and this morning, the Blackfoot now is at 102 million a day from the 93 that we had in there. So that shows you kind of the trajectory that it's on. We still do not have everything unloaded. So it's climbing very well. It's performing very strongly, so we're very, very excited about what we're seeing. And changing quickly, so tomorrow I'd have a different answer for you. Charles A. Meade - Johnson Rice & Co. LLC: Okay. Thank you, John. And then on the other side of the Permian, I wondered if you, Tim went through a lot of detail on how you've changed your, not just your designs but also your operational pace on that side. And I wondered if you could talk about the Lynch pad, which is that 8 well pad in the Wildfire area that you guys brought online. It had some good rates, but is that benefiting from these new designs, the new approach? Or maybe just add a little color to what was happening there.

Yeah, on the Lynch pad, it's an 8 well pad that's in the Wolfcamp B. And this was really a spacing test. We did some 10-bys and 8-bys in this pad, 7,300 foot lateral length. And you can see the rates are good, 1,275 barrels of oil equivalent per day and mostly oil from the IP. And we continue to do spacing tests. We've got another 10 wells that are online and some of them are Wildfire as well, very early stages of flow back, but they are on 6-by spacing. So we'll share results with you about that next quarter. But these are spacing test wells in the Wolfcamp B and we're going to compare them to 6-by next quarter. Charles A. Meade - Johnson Rice & Co. LLC: And so, I'm sorry, just real quick clarification, Tim. The 10-by spacing, so that's spacing equivalent to 10 wells across a section?

That's correct. Part of the pad is 10 wells per section spacing and part of it's 8-by. Charles A. Meade - Johnson Rice & Co. LLC: Got it. Thank you, Tim.

You bet.

Your next question is from the line of Scott Hanold with RBC Capital Markets.

Thanks. Good morning, guys.

Good morning, Scott.

Hey. Can you talk about how you're looking to go about Alpine High right now? It sounds like you're starting to move into some optimization based on what you've seen. But I know early on you were trying to do things like separate various factors, right, lateral length, frac that you're putting on this to get a good sense of really what's driving performance. Where are we with that? And how does that sort of drive you for these 60, 70 completions you've got at the end of this year and maybe into 2019?

Well, I mean, it's exciting because now we've got data and we've been deliberate on those tests. And as you've correctly noted, we weren't moving many dials, except one usually for a reason, so we have a good baseline. It's clear to us now that we're going to be increasing the frac size. It's clear to us that we can go tighter with the current frac designs. And now, we're moving into the pattern and spacing tests, where we're testing things between zones, between formations, both aerially, spatially and so forth. And so, now you'll see us start to move some of those dials as we crank up the completions. So we'll continue the very deliberate process. It just takes time to do it right. If you jump out there and go drill too many wells and pump too big of fracs and you get a lot of interference, then you got to go back and try to figure out how you unwind that. And so, what we've been is very deliberate with it and we're moving into that next phase. And we've got a plan. We've stuck to it and you're starting to see the benefit come and we're really excited about the results and the learnings that we continue to incorporate.

All right. Great. Appreciate that. And a follow-up on the Egypt, with some of this enhanced seismic imagery you've gotten back, it sounds like you got some of it back, how much now maybe you had it in your hands to take a look at it? And what are you seeing now versus maybe what you had thought of it going into it?

Well, I haven't seen the new data. I've seen snippets of the new data. We've actually compared it to some of the 2013 vintage stuff. I'm looking at one of my ops guys over here, but I will tell you, I've heard now we're seeing some fault lines in some of our existing fields, which probably sets up more drilling, so you could see some things at Ptah, Berenice. I'll be over there in the fairly near future. We'll get to review some things, but we're excited about it. It's what we thought it would be. It helps us see image better, the subsurface, which is going to lead to more wells, stronger results and a better understanding. And plus, we're going to have a better handle on some of the recoveries and things. So, it's a whole new lens and it's going to be very helpful.

Thanks for that.

Your next question is from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Good morning, and thanks for taking my questions. My first one is on what I guess a midstream monetization could mean for the budget this year. Are you able to eliminate some of the planned incremental spend with a deal and for parts of the budget that have been spent ahead of an announcement or a closing? Is there an opportunity for rebates or reimbursements for at least the Alpine High piece?

Jeoff, obviously, we could make it look however we want to look. I mean, we could take a lot of cash out. We could eliminate capital and we could make the effective date whenever, whatever we want that date to be. So we've made pretty clear in here that our CapEx guide for the year-end still includes 100% of the midstream spend. We've made it clear that getting something done could pull some of that back and there's opportunity there. So I'll just say wait with us. It's going to have an impact but wait with us until we're in a position to disclose more because we're deep in the process, so. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Got it. And then just digging into the incremental Alpine High piece by itself, should we think of that as all or just maybe primarily longer laterals and completion enhancements? Or is there a portion related to midstream spend that was accelerated into this year from next year's plan initially?

It was a little bit of the midstream that we were looking at trying to accelerate cryo, but as we've said, most of the two thirds of the CapEx increase is going into drilling completions and it's new activity. When we made very clear that two thirds of it's new activity that will be incremental. Most of it is this back half of the year, which is why it'll impact 2019 and 2020. There's a little bit of impact on 2018, but not much. There has been a little bit of inflation, about I'd say just under 20% is, and we budgeted a 10% to 15% rise, but anything that has to do with trucking, people, steel, or chemicals, there are some headwinds out there. And so there's a portion of it that's tied to that. And then we mentioned some on the exploration side, so. But most of it's new activity and two-thirds of it in Permian and it's new activity. Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.: Thank you.

Your next question is from the line of John Herrlin with Société Générale. John P. Herrlin - Société Générale: Thanks. You're gathering a lot of water at Alpine High. Are you going to be able to recycle any of it?

John, everything we're gathering, we're recycling. And the beauty of our transgressive source center rolls, it doesn't produce very much. So it's really the frac water that we're gathering. We produce it back, is load, and then we recycle it and reuse it. So I'll let Tim jump in on some more details.

Yeah, we've currently got five water recycling facilities out there and we are currently recycling about 90% of our produced water right now. That really is only about half of our frac water needs currently. So we do have to have makeup water and we do use brackish source for that. But by year-end, we feel like we'll be able to utilize about 80% of recycled water for our fracs. John P. Herrlin - Société Générale: Okay. Great. Next one for me is on Dixieland. You had slightly stronger well results in the first quarter at Burnside and one other, and I was wondering how much heterogeneity do you have? Like Burnside and Bull Run were a little bit stronger than some of the other wells. So I'm not worried about everything always staying at the same level, but I was wondering how much heterogeneity do you see since you're basically doing similar type completions?

So, John, as you know, that's why we talk about Bone Springs and Wolfcamp as being pair sequences. Geologically, you have heterogeneity. Tim, do you want to add anything specifically to that area?

Yeah, I mean, we only have seven sections there. It's not like it's a big area, so it's fairly consistent. We've got two proven landing zones. We will be testing two additional landing zones out there. We brought 20 wells online here in the first half, 11 in the second quarter, and they're about 1,500 BOE per day. And these are just mile laterals, actually 4,400 foot laterals. So it's been a very, very economically attractive program for us. So we think we've still got a pretty bright future for the next couple years. John P. Herrlin - Société Générale: Okay. Great. Thank you.

Thanks, John.

Your next question is from the line of Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs & Co. LLC: Thank you. Good morning.

Good morning, Brian. Brian Singer - Goldman Sachs & Co. LLC: In Alpine High, how do the results of some of the efficiencies, lateral length and spacing tests in areas like Dogwood change the relative rates of return and prioritization of the wet gas versus dry gas drilling? And how, if at all, does that influence your focus areas over the next few quarters?

Well, I mean if you look at the wet gas, dry gas, the breakevens on the wet gas are still going to be much better just because of the amount of the liquids. So it won't really change the pecking order there, but what it really changes is is number of wells we need to drill and some of those things in terms of the plan. So it can change the cadence and the sequence as you look at the capital that's going to the, what we'll call, retention wells versus the impact wells. Brian Singer - Goldman Sachs & Co. LLC: Got it. Thank you. And then you've highlighted across the portfolio, but particularly in the Alpine High various efficiencies. And I wonder if you could talk about where you see these efficiencies going from here, whether we've just had a surge or whether you think this pace is going to continue. And how do you draw the line on when you let those efficiencies play through to higher CapEx versus just choose to become more narrowly focused within the portfolio?

Well, I mean I think if you look at our Permian, Brian, we've been running 17 rigs since the second quarter of last year. And so we're at what we think's a pretty darn good baseload. Clearly the frac efficiencies took a step function forward and we've seen that. Now we're seeing the drilling time and the footage take a step function move forward, so this is a continual ebb and flow as you continue to get better reduced cycle times and so forth. But if you step back and look at our program and then you look at the results over the last year, Permian's up 39% year-over-year and oil's up 25% year-over-year and we've been pretty steady on the program. So what's changing at Alpine High is the completion design and more on the spacing tests, but when you look at the size program we're running, you look at the size cash engine that we're building to fund it, those are the things you have to factor in and you have to continue to integrate your learnings and be continuous improvement. And we stress to our folks to continue to get better in everything we do. And so you're going to have times where we're going to have to make adjustments as we continue to incorporate learnings. But it was a pretty easy call here as we look at what the engine for this thing looks like going into 2019. Brian Singer - Goldman Sachs & Co. LLC: Is it fair to say that if there is a free cash buffer to offset efficiency driven or even inflation driven increases in CapEx with no further change in activity, that that would be sufficient for you to further increase your budget?

Well, I mean I don't think you can assume everything on the free cash side goes to budget, right? I mean what we're trying to do with our efficiency programs and what you've seen with the size is ultimately it's returns and value driven. And so that's the big factor. I mean, you look at our activity, it's really hasn't changed and it's not going to change much going into the fall. We've got to sprinkle a few rigs in to kind of keep it there with the frac crews and so forth. But we're getting to a point in the, we get the midstream deal done in the very near future with the engine that we've built that we actually see free cash flow. And it puts us in a position where we can start to truly, for the first time since coming out of this downturn, we can look now at other things to do. And those are things that we're very excited about because we can see a pathway to it, pretty near future. Brian Singer - Goldman Sachs & Co. LLC: Thank you.

Your next question is from the line of Leo Mariani with National Alliance Securities.

Hey, guys. I was hoping that you could delve a little bit more into some of the exploration efforts that you guys alluded to on the call. You guys did mention kind of an unconventional U.S. exploration program. Just trying to get a sense of maybe what the dollars are that are exposed to that in next year's budget. And also was hoping for a little bit more detail on Suriname in terms of when you guys might spud a well there. What's your working interest there, as in what do you see as the potential in Suriname?

Well, a couple things, Leo, and thanks for the question. I mean, number one, I'll address them kind of in the order. On the unconventional side in the U.S., there's not a lot of dollars. What we're looking for there is large impact, large scale opportunities that are in various stages that we could acquire at low cost. And much like when we put something like Alpine High together, we put together 350,000 acres out there for less than $1,300 an acre. So it would be those types of things, but there's not a lot of capital at this stage but if you're looking in the right places, it doesn't take a lot of capital to go a long way. So not a position to say a lot more than that, but we do have some things we're working on on the unconventional side. As it relates to Suriname, clearly what we've said, we've got 2 blocks in the offshore there, Block 58, we own 100%. It's about 1.4 million acres. We have 45% of Block 53. We will definitely commence a program in 2019 and we've started to purchase the long lead items. We got the 3D back and we're very, very excited about the potential. We're on trend with the success that's happened across the water boundary in Guyana and it's exploration that could be very, very impactful for Apache and currently today we own 100% of it.

All right, guys, thanks.

Thank you.

Your final question is from the line of Doug Leggate with Bank of America Merrill Lynch.

Thanks, John, good morning. I got a couple to close us out here, it looks like. My first one is on Egypt. As we understand it, in the last six or nine months, the government's gone through quite a lot of change in deregulating its gas market. It's removed subsidies from local industrial prices. You know everything that's going on there, and it's incentivizing exploration. I'm curious if any of that is filtering through to what you're doing, especially in your new concession, how you see the prognosis for seeing us maybe starting to see an uplift in your exploration activity translating to higher price realizations? And then I've got a quick follow up, please.

Well, I mean I think the key for us, Doug, is number one, all the activity, all the gas coming on has been very beneficial for Egypt, which is a good thing, and that translates into the country's just financial wherewithal. So things are going extremely well. I think the key for us is, is we've been able to pick up new concessions for the first time since 2006. We're shooting a large 3D. We're in between areas where we know there are big structures and really, really fertile ground. So we're very excited about that. We're excited about the opportunity to continue to grow the free cash flow and we think we can be in a position to also grow our volumes in Egypt, and especially on the oil side. So I think in general, it's a very promising environment for Apache and things are going extremely well and we're very excited about the future.

Just to be clear, has the new exploration acreage come with come with different terms as it relates to realized gas pricing?

All the concessions are, you bid those. The thing I will say is, is we've kind of stuck to our guns historically, which is why you went through a drought where others came in and picked up other concessions. We've stuck to our guns in terms of how we've approached it. So we feel good about that. We feel good about the new concessions, and we like the terms.

Understood. My follow up, if I may, is just jumping back to Alpine High very quickly that it's kind of a follow-up to Bob's question earlier about the 4,500 foot laterals and getting bigger and so on. Clearly it seems that there is upside risk to the guidance you gave us a couple years ago. How would you think about what that, how that translates to your production profile through 2020? Do you have lower decline rates by choking back the wells, for example? Do you have faster acceleration? Just if you could characterize how all of that plays into the infrastructure plan and so on, and I'll leave it there. Thanks.

Well, we have just a tremendous resource. And as we've said on today's call, we would tend to the high side of the previous guidance that we gave earlier this year. And clearly, productivity is improving. Wells are performing extremely well. We're shifting to pads. So I would just steer to the high side numbers as it relates to 2019 is what we've said now and we'll come back with some updated numbers as the year moves along.

Great stuff. Thanks, fellows. Appreciate you taking my questions.

Thank you all. I just want to wrap up and like to leave you with three key takeaways from today's call. First Apache had another great quarter. We exceeded guidance and raised our 2018 outlook. Second, looking ahead to 2019 and 2020, there is a significant upside bias to our production outlook due to the added capital, which will benefit primarily 2019 and 2020, the capital efficiency improvements and strong well performance all in our Permian Basin. Additionally, total capital spending is likely to come down in 2018 to 2020 with the completion of our midstream transaction. And lastly, at Alpine High, we are seeing very good results from our strategic tests and production growth has entered the acceleration phase. I look forward to sharing our ongoing progress with you in the future.

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