Gary T. Clark - Apache Corp. John J. Christmann IV - Apache Corp. Timothy J. Sullivan - Apache Corp. Stephen J. Riney - Apache Corp. Brian W. Freed - Apache Corp..

Gail Nicholson - KLR Group LLC Charles A. Meade - Johnson Rice & Co. LLC Brian Singer - Goldman Sachs & Co. LLC John P. Herrlin - SG Americas Securities LLC Doug Leggate - Bank of America Merrill Lynch Leo P. Mariani - NatAlliance Securities Richard Merlin Tullis - Capital One Securities, Inc. Michael Anthony Hall - Heikkinen Energy Advisors LLC.

Good morning. My name is Lisa and I'll be your conference operator today. At this time, I would like to welcome everyone to the Third Quarter 2018 Earnings Conference Call. After the speakers' remarks, there will be a question-and-answer session. Thank you. Gary Clark, Investor Relations, you may begin your conference..

Brian Freed, Midstream and Marketing; Mark Meyer, Energy Technology, Data Analytics and Commercial Intelligence; and Dave Pursell, Planning Reserves and Fundamentals. Our prepared remarks will be approximately 25 minutes in length, with the remainder of the hour allotted for Q&A.

In conjunctions with yesterday's press release, I hope you have had the opportunity to review our third 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's tax barrels.

Finally, I would 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 discussed today.

A full disclaimer is located with the supplemental data on our website. And with that, I will turn the call over to John..

a development well at Caliber, a discovery well at Store (11:46) and our discovery well at Garten, which we have now accelerated into 2018. Longer-term, the Garten discovery has lowered the risk profile of several analogous exploration prospects, some of which we will likely test in 2019. Moving on to exploration.

In Suriname, we continue to progress our technical evaluation and are looking at a multitude of prospects. We will initiate a drilling program next year on Block 58, where Apache currently owns 100%. This block is untested and adjacent to the Exxon Mobil operated Stabroek Block in neighboring Guyana. In the U.S.

we have a strategy of expanding our portfolio through organic growth opportunities at a low entry cost. On-shore unconventional exploration teams are acquiring acreage in multiple respective areas focusing on oil. Our third and fourth quarter capital reflects some incremental activity in this regard.

Before turning it over to Tim, I'd would like to address reports that Apache is actively marketing certain assets in our U.S. portfolio. We regularly review the strategic value of holding assets in our portfolio.

If another party is willing to fund assets that are not attracting capital for Apache and an opportunity exists to increase value for our shareholders through a sale, our approach has always been to notify the market upon execution of a sale agreement for any material asset disposition and refrain from commenting prior to that.

To the extent we do complete asset sales, return of capital to shareholders is a high priority use of proceeds. With that, I will turn the call over to Tim Sullivan who will provide some operational details on the quarter..

Good morning. My remarks will briefly cover third quarter 2018 production and operations performance, including drilling highlights and activity in our core regions. Operationally, we had another very good quarter and saw improvement in many key areas.

We achieved company-wide adjusted production of approximately 401,000 barrels of oil equivalent per day, a 13% increase from the same period a year ago and up 3% from the second quarter 2018. The Permian Basin continues to drive our growth.

Compared with the third quarter a year ago, oil production in the basin increased 16% and total production grew 38%. These are impressive growth rates on a large production base, which reflect the success of our ongoing development in the Midland and Delaware Basins and the continued ramp up at Alpine High.

We averaged 18 rigs and five frac crews in the Permian Basin during the quarter. Compared with the preceding period, we held our oil production steady, up 1%, and with the completion schedule skewed toward the back half of the year, there will be a larger contribution to oil growth in the fourth quarter and even more so in 2019.

In the Midland Basin, we placed 13 wells online in the third quarter, all of which were on multiwell pads. This includes a nine-well pad at our Powell field, comprising a mix of mile-and-a-half and two-mile laterals.

In addition, we drilled a four-well strategic plan pad in our Hartgrove field in Reagan County, testing four separate Wolfcamp landing zones with very encouraging results. In the Delaware Basin at Dixieland, we placed on production 10 high-rate wells with one-mile laterals.

Eight are producing from two proven-Upper Wolfcamp landing zones, while the remaining two successfully tested two additional landing zones in the Lower Wolfcamp, adding inventory across the field. Please refer to the Quarterly Supplement for production details. Production at Alpine averaged approximately 49,000 BOE per day during the quarter.

We are currently producing approximately 55,000 BOE per day on a net basis. For the full year 2018, we are tracking toward 44,000 BOE per day net, down slightly from our 45,000 BOE per-day guidance. This reduction results primarily from a processing upset that sent moisture down the pipeline, requiring a two-day field shutdown to dig the lines.

At Alpine High, we placed 27 wells on production during the third quarter. We will remain on track to place more than 90 wells on production this year. John mentioned the results we've seen thus far on our 10-well Cypress pad, so I will note a few other results year.

Recent Barnett completions during the quarter include the Mohican 201, which averaged a 30-day initial production rate of 7.7 million cubic feet of rich gas and 319 barrels of oil per day; the (16:30), which averaged a 30-day IP rate of 7.3 million cubic feet of rich gas and 256 barrels of oil per day.

Both wells were completed with laterals averaging 5,700 feet and standard proppant loads of 1,970 pounds per foot. They produce extremely rich gas with an average BTU content of nearly 1,300. And assuming cryo-processing, we yield up to 160 barrels of NGLs per million cubic feet of gas.

We have many analogous Barnett wells scheduled for multi-well pad development in our 2019 drilling program. I also wanted to provide an update on the 12-well Blackfoot pad which we discussed last quarter. Recall that the Blackfoot tested 660-foot spacing in three Woodford landing zones.

These wells were relatively small completions, treated with only 1,600 pounds per foot of sand. The pad peaked at a 30-day IP rate of nearly 105 million cubic feet of gas and 280 barrels of oil per day following our last quarterly call. The majority of the gas is being recovered from the upper two Woodford landing zones.

Based on our frac geometry and production results, we believe we can recover most of these reserves with fewer wells and larger fracs, which will significantly enhance pad economics. This strong performance from the upper Woodford landing zones on tighter spacing has a positive impact on our location count.

On the cost side, Apache is successfully navigating a challenging inflationary environment in the U.S. Our initial 2018 budget contemplated a 10% to 15% average surface cost increase. However, steel tariffs, rising fuel and chemical prices and higher labor costs, particularly trucking and construction, have resulted in incremental inflation.

We are managing these dynamics with improved wellbore and completion designs, longer laterals, multi-well pad drilling and proactive investment in water management infrastructure. As we look into 2019, we are likely to see a continuation of higher labor, steel, fuel and chemical costs.

However, as we move through the tender process, we are realizing reduce costs for rigs and pressure pumping crews. Net-net, we believe these cost trends roughly offset each other in 2019, and we plan to budget for a relatively flat or slightly down year-over-year service cost overall.

Internationally, in Egypt we drilled and completed 24 gross wells with an 83% success rate. Noteworthy results are included in our Supplement. These are primarily high rate oil wells, all with Brent Index pricing. Our seismic acquisition on the Western Desert continues.

To date, we have acquired close to 1 million acres of a planned 2.6 million acre seismic shoot, completing acquisition in our legacy West Kalabsha and Shushan areas. We have recently initiated seismic acquisition in our new Northwest Razzak Concession. Fast track processing is bringing very exciting results.

We are seeing faults in geologic surfaces, especially in the deeper section, that we could not image before. We have identified several new leads and prospects just from this initial data review. Moving to the North Sea, production averaged approximately 51,000 BOE per day per the quarter as operations were impacted by maintenance turnarounds.

Production has begun to rebound in the fourth quarter and should continue to ramp up. In late September we brought onstream our fourth development well at our Callater Field at Beryl. This well is having a positive impact both on production and reserves and is currently producing 3,500 BOE per day net to Apache. Apache owns a 55% working interest.

Also, as John noted, we have accelerated development at Garten. The Beryl near field discovery we announced in March with first oil expected later this month.

By locating this test well near existing infrastructure, we have been able to reduce our cycle time, minimize development costs and bring this well into production in only seven months for $80 million, which we expect will translate to a very attractive F&D cost of less than $10 per barrel.

We anticipate achieving our highest average production rate for the year in that North Sea during the fourth quarter. To sum up, operationally, we remain on track for a very good year with growing momentum heading into 2019. We are focused on building on this success in quarters ahead. I will now turn the call over to Steve..

lower debt, robust cash flow and increasing returns, all goals we set at the beginning of the year. I look forward to reporting on our full-year financial performance in February and further discussing our outlook for 2019. And with that, I will turn the call over to the operator for Q&A..

Thank you. We'll pause for just a moment to compile a Q&A roster. And our first question comes from the line of Gail Nicholson from Stevens. Your line is open..

Good morning, everybody. You guys had really strong Permian NGL price realizations this quarter.

I was curious, what percent of your Permian NGLs are ethane? And then how is that to change post the Cryo facilities coming online in Alpine next year?.

Hey, Gail. So this is Steve. So I don't have at hand an exact number of the percent of NGLs that are ethane. Might see if we could get that before the end of this call.

But that obviously will be impacted quite a bit as we actually bring on three Cryo units in Alpine in 2019, the first one by the middle of the year and then two more before the end of the year. In aggregate, we produce about 60,000 barrels a day of NGLs in the U.S.

and most of those – those are all basically priced based on net back Mont Belvieu type of pricing, with a deduction for transportation and fractionation costs. And quick turnaround on the first part, about 42% is F8 in the Permian..

Okay. Great. And then the market we tend to be overly focused on your U.S. onshore execution, but you have some really high-quality international assets. Can you just talk about what could potentially be on the horizon in the North Sea and Egypt in 2019, specifically maybe in Egypt as maybe you return that asset more to a global asset..

Yes, Gail. Thank you. If you look at Egypt, we've got a big three-day program that's underway and we've got a lot of new concessions, and so, it's a 2.6 million acre shoot. We shot over 1 million of it. Things are progressing well and, I tell you, the early looks on the seismic are very exciting.

There's just a lot of rock to deal with out there, it's high productivity, and we've got such a massive infrastructure, backbone in place, that it will be easy to bring things on. So, we are very excited about Egypt and we are excited about getting more of the 3-D in and starting to migrate our inventory there, which really has become very robust.

Historically we have about two years of inventory that we could see because it took so long to build. Today we've got a much, much longer time horizon on our Egypt portfolio, and gives us the ability – you know, we believe we are going to be able to grow the free cash flow as well is grow production over the next several years on the new acreage.

So that's the first thing. If you look at the track record in the North Sea, Garten this year was a big discovery for us, and as we said on the notes this morning, we are going to be accelerating that from early next year into the fourth quarter. So we are excited about that.

It will be a very high rate well, it's a big structure, and there's potential in there, we'll just have to see how it outperforms, even add more wells. But most importantly, it also de-risked several other structures that are very similar to Garten. So we continue to have success in the barrel area with tiebacks.

We've got store coming as well, in 2019 we brought on another well in Callater. So we've got a lot of momentum going into 2019 in the North Sea, not to mention the work we are doing a 40s as well with the water injection. We are really starting to see some stabilization of the decliner rates there, and flattening of that which has big ramifications.

So, you know international portfolio has provided a tremendous amount of cash flow, it's Brent pricing and we get really high gas prices in the UK as well, and we're excited what that's going to continue to do for us for the foreseeable future..

Great. Thank you so much..

Thank you..

Our next question comes from line of Charles Meade from Johnson Rice. Your line is open..

Good morning, John, to you and your whole team there..

Good morning, Charles..

I wanted to – I feel like you guys talked a little bit about that para sequence test you have, and I think Tim said that was the Cyprus state pad, did I catch that right?.

You did..

Okay. And so, John, I recognize it's early days there, but can you give a little bit more color. I know you said the wells are still cleaning up. I did a quick math and it looks like those four Wolfcamp tests are right now a little bit over 400 barrels a day of oil each.

I wonder if you would talk about how much water you are seeing? Where you think that, what would be a good result in your view on where those wells go? And also maybe you could talk a little bit about the decision to do all eight wells at onetime, rather than just kind of weigh generally into that test?.

Well, first of all, Charles, we are very excited about it. It's a 10 well oil pad test. There are four Wolfcamp A's, there are four Wolfcamp B's and two Bone Springs. Really, really high productivity. It's very early. I will tell you we were gas lifting all eight of the Wolfcamp wells.

There's extreme deliverability and productivity and they are really just starting to cleanup. So, they started cutting oil pretty early. There's a tremendous amount of fluid to move, and we are very optimistic and encouraged by those. They are still short laterals, larger fracs, about 4000 pounds a foot.

This is really 10 wells in a little over a half section. So it's like we've talked about the name of the game is getting the pad development, understanding the spacing from a spatial and pattern position. And we're excited about these.

They are going to continue to clean up, when we look at the IPR curves, there's a lot of room for these wells come up and we expect them to hold in for quite a while. So we're very encouraged. The two Bone Springs we've just really started and we've run sump pumps in those two wells. So – and they're both cutting oil but just really getting started.

So it's early and is 40 gravity oil, it's black oil and well costs were very reasonable for the size jobs we pumped, and we're very optimistic..

Got it. It sounds promising. We'll just have to stay tuned on that. And then if I could go back and touch on – you guys talked about the CapEx outlook for 2019, but that's really a piece of the free cash flow outlook for 2019.

And you guys also talked about the possibility of asset sales, and that would be the scenario which you'd look to return more cash to shareholders. So I think you guys already have a dividend.

You've maintained it through the whole downturn, but can you give us a little bit of your thoughts? Are you thinking about, how would you – if you did have more free cash flow through an asset sale or just through sustained strength in quality price, how are you thinking about maintaining or increasing your dividend going with a special dividend? And then also, you guys announced this $40 million share repurchase authorization.

Can you give us how those priorities sort out in your mind?.

Well, Charles, that's a lot of questions. I'll try to summarize in a couple points and then give you a chance to come back if we didn't answer them. But first of all, as we look to 2019, we've been running a pretty flat activity set, going back to the back half of 2017. So we're very comfortable what the capital forecast is going into next year.

We figure for $3 billion, we can deliver pretty fat flat activity set, which sets us up very nicely when you look at the corporate level in the U.S. growth which, of course will be driven by Permian.

So we also believe that we will be in a position to generate some free cash flow and clearly, a high priority with that free cash flow right now, especially with where share price is would be to supplement our dividend policy which we've maintained through the downturn.

I mean we're one of the few that did not cut our dividend, and so we see that buybacks is something we can do to supplement our dividend policy as we return incremental cash flow to the shareholders. So everything I'll say about the capital program going into next year that can easily be flexed up as we have significant inventory to do that.

But also it'll be very easy ratchet back if things change in the environment. So we'll have more color on the call in February, but very comfortable with the rates and pace we've been running at. I think we're set up for a really strong 2019 after a really good 2018, and we do see us being able to increase the stuff back to shareholders..

Thanks, John. That was the overview I was looking for. Go ahead. I'm sorry..

Yeah, sorry, Charles. I'll just add to that. Just in terms of what potential we might have on that, we ended the third quarter with $600 million of cash, with positive free cash flow planned at strip for 2019.

Through the end of 2019 and after paying the dividend and after retaining a bit of cash on the balance sheet for operational purposes, you're probably looking at as much as $500 million to $1 billion of cash available, depending on price, available for either debt reduction or further share buybacks.

And that would exclude any proceeds from asset sales..

Thanks, Steve..

Our next question comes from the line of Brian Singer from Goldman Sachs. Your line is open..

Thank you. Good morning..

Good morning, Brian..

Wanted to touch on Alpine High well productivity. You talked to some of the success and endeavors you're taking, extending laterals and also greater proppant loads.

Can you add a little bit more color on what you're seeing, and more specifically whether when you talk about the improvement in productivity that is increasing EURs in recovery rates, or that is just bringing forward production?.

Yeah, Brian. I think the thing we've determined and we now have substantial flow time on it is that the larger fracs are definitely increasing productivity. We're also seeing that in the Woodford and the Barnett, and longer laterals are pretty much one to-one in terms of lateral foot for the productivity.

So in both cases we're getting benefit from longer laterals as well as the bigger fracs. The last pad we brought on, the Blackfoot, was the smaller fracs. We did that even knowing going into that we knew the larger fracs were doing more but we needed to see the data point in terms of the number of landing zones and the spatial placement between those.

And it's confirmed what we believed that we're probably going to be able to develop at Woodford with two landing zones, drop the As and Bs a little bit lower with a little larger fracs. And then we've got to come back and pump the bigger fracs on those to then figure out the optimal number of wellbores.

But the good news is our location counts have had very conservative assumptions. We've proven that at less than 2,000 pounds we can place the wells 660 feet apart and our well count assumptions were 925 to 1,000.

So well count is going to go up when we come back and quantify that, but we've still got some more work to do in terms of what's going to drive the greatest return and PV per capital dollar invested with how we develop these patterns. We've got the 12 wells in the Blackfoot. We're going to come back right now.

We're in the process of completing 10 wells in the Barnett and at a later date you'll see us come back with a pair sequence. So at the Mont Blancs right now we're in the process of flowing back or starting to flow back some Woodford and Barnett tests, which have a little larger fracs.

So there's a lot of data that's coming and has been designed to help us yield what's going to be critical to the development scenario. So a lot of good work and a lot of progress, and at some point we'll come back and unfold a lot of that for you..

Great. Thank you for that. And then my follow up is with regards to use of capital Permian and M&A.

Can you just kind of talk to, to what degree M&A opportunities are competitive or not competitive relative to share repurchase for use of free cash and where the Permian outside Alpine High plays into that if at all?.

Well, I mean, I think if you look at us today first of all, as I said in the closing part of my comments, if there's an asset that we're not funding and there's an opportunity for somebody else to put capital in that asset, then there may be an arbitrage and the ability to create some value for shareholders.

So we're constantly looking at the portfolio and you've seen that historically with us. We exited Canada last year. So it's something we're constantly looking at. Clearly, right now, if you look at our portfolio, we're very excited about where we are in the Midland Basin.

We've been predominantly working three areas and, as Tim mentioned, we branched out past those three areas in the Permian. But if you look at those three areas, it's less than 20% of what we'd call our core Midland Basin acreage and we've really developed less than 20% of the locations we see in those.

So there's tremendous amount of running room in our Wolfcamp and Spraberry locations in our Midland Basin. And then if you look at our portfolio from an expiration standpoint, we believe today you're better served – the best impact's going to be through organic well-designed expiration. And Alpine High was a result of that.

We've put together a tremendous portfolio over the last few years on the conventional side. We've got a block down in Suriname that we're very, very excited about and we've also got some new plays that we've been working on the unconventional side.

As you know, it's a depleting business and you have to continue to find areas, and we think organically through the expiration if you can do it with low-cost, high-impact areas, we think that's the best way to create value. And it's also why we also like our share price right now..

Thank you very much..

Our next question comes from the line of John Herrlin from Société Générale. Your line is open..

Yes. Thanks. Just one quick one for me.

Are you going to be buying puts for next year's oil production?.

John, historically we've put things in place to protect our programs. And I think fundamentally we like to stay away from hedging unless we feel like we need to do something.

And at times when we felt like we had a capital program like the midstream and Alpine High we've done things to protect that cash flow or through acquisitions there's ways to fund those. So I think as we go into 2019 we're in a position today where with the capital program, we can ratchet that up or down if necessary.

So it's just something we'll have to kind of look at..

Okay. No, that's fine. I didn't figure you'd be putting any on, but I was just asking. And then Altus closes this month, end of month, mid-month, or....

Yeah. I'll let Brian....

Yeah, this is Brian. The proxies were mailed out on October 22 and we've got the Shareholder Meeting scheduled for November 6 with the close and funding scheduled for November 9, and at that point in time the ticker symbol will change to ALTM and the name will change at closing to Altus Midstream from Kayne Anderson Acquisition Company..

Great. Thank you..

Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your line is open..

Thank you. Good morning, everybody. John, I wonder if you could help me with really a bit of a production visibility question for next year, and it's really about how we should think about the fractionation start-ups and how we could see your liquids yield evolve from the wet gas you've got currently.

Because, obviously, that's going to be a pretty significant catalyst, I think, for your step change in cash flow as you go over the next year or so..

Yeah, I think, Doug, clearly 2019 will be an inflection-point year for the NGLs at Alpine High. If you look at 2018 to 2020, we showed a transition where our NGLs would grow from 10% in 2018 to 30% in 2020. We've got one Cryo coming on in the second half – or the back end of the first half of the year. Then, we got two coming on in the second half.

So, it'll all happen, kind of start happening second and third quarter of next year..

Yeah. And, Doug, I'd just add to that. Our contract with Enterprise provides for a ramp-up of volumes to 205,000 barrels a day and that's a fixed contract. They've got to take it. It's a fixed-fee structure for transportation and fractionation.

And as I said in my prepared remarks, we actually have some options to even further enhance margins beyond just a Mont Belvieu mixed NGL barrel pricing netted back to Alpine High..

Steve, just to be clear, when would you expect to fill that capacity? I know it's a bit of a stretch question, but can you provide any visibility as when you would expect that volume to be achieved?.

No. Not at this time, Doug. I think what I'd recommend is let's wait until the next plan rollout in February and we could probably have a better view of that kind of stuff. But, obviously, I'll just state the obvious and that is as we – we're bringing on three Cryo facilities in 2019, two more in 2020. That won't be the end of it.

But, obviously, as we bring on Cryo facilities, the goal would be to have a drilling schedule that fills those as quickly as possible..

Thank you. My follow-up, John, I don't know how you want to deal with this one. It's on Egypt. It's about, I guess, seven or eight years now since everything kind of went toes up in the country and things have changed dramatically, as you know.

I'm just curious, we haven't really had a formal update on your plans for Egypt with the new seismic program and so on. The visibility for the sustaining business sort of growth plan going forward. And it strikes me that the market could probably benefit from getting a refresh on that. I'm just wondering if you can update.

Do you have any intention of doing that and any high-level plans that you can share as you think about the next several years?.

Well, I mean, if you look back, we've been able to maintain our Egypt production level with a much lower rig count. We were running 28 rigs in Egypt in 2014 and we got down as low as six or seven.

We've been running around 12 rigs, and we've been able to really stabilize that, and that's with the (48:22) starting to get towards the point where it would go on decline. So we've done a really, really good job.

And I think our productivity and capital efficiency in Egypt has gone up significantly, and that was really two discoveries Ptah and Berenice, which helped drive that, which we had in early 2015.

If you look at the new seismic, I think, as we – with the new concessions, and we get the new seismic back, we would be in a position, Doug, to kind of unfold some of that as well. So, we've expanded a lot over the last three years. We've landed a lot of acreage in Egypt.

And as I mentioned earlier, we've got great infrastructure and a great track record. And so we look at Egypt as an area we can continue to grow the free cash flow. You can't underestimate what we've done with that and what it's been able to do for us over the last several years and grow our production.

So Egypt's actually an improving position for us as well, and we've got better there over the last couple of years. And I think once we get the new seismic back, and then we would be in a position to unfold that a little..

Just one closing comment from me, John, if I may. It's just an observation more than anything else. This asset obviously throws off a lot of free cash. The market still seems to apply a data discount to that asset. And if you could provide some visibility on the sustainability of that free cash, I think it would really pay dividends.

That's really what I was getting at. So I appreciate your answer. Thanks..

That's a great comment, Doug. Thank you..

Our next question comes from the line of Leo Mariani from Nat Alliance. Your line is open..

Hey, guys. I wanted to dig into the forward plans at Altus a little bit. Obviously, I know the vote is a handful of days away. I guess you've got a central closing coming up soon as well.

But assuming everything closes as planned, how do you see, sort of, the progress over the next couple of quarters? I know you guys have some significant options to purchase some equity interests and some rather large pipelines. I know you guys have talked about our other organic growth opportunities.

Can you just, kind of, refresh everyone in terms of what you plan to do here in the short term when all this post close?.

Yeah, this is Brian Freed. I'll address that a little bit. I mean, quite frankly, what we have in front of us, we've got a lot to say grace over in front of us in terms of the work we've got in front of us. We've got the Cryos that John mentioned that need to come on in 2019 and the equity options that we will start exercising by the end of this year.

We've got a supplement out on the website that shows when some of those option exercise dates are, so you can dig into the details there. So I won't burden this call with all of that.

But we do expect to start exercising these options by the end of the year, and then we have a lot of gathering and processing to continue to build out through the rest of this year and into 2019 as well, too..

Okay. That's helpful. And I guess just jumping over to Suriname, obviously an area you guys are quite excited about here. I wanted to see if you could give us a little bit more color on, sort of, the capital plan there for 2019 in terms of how much money you plan to throw at it and how many potential wells you guys could drill..

Well, I mean, it's a large area. We've got about 1.4 million acres. There are number of prospects that are very high quality. We will drill at least one well in 2019, and there will be options to make that program much larger. So that's one of the things we're looking at. But we'll include at least one well..

Okay. That's helpful.

And I guess, is that well likely to, kind of, come by midyear? What can you tell us on timing there?.

I would – I'd probably say late second, early third quarter, likely, but....

Okay. Thank you. Thank you..

Our next question comes from the line of Richard Tullis from Capital One Securities. Your line is open..

Hey. Thanks. Good morning, John. Just a couple of questions on the exploration side. I know that's not a topic discussed all that much in E&P land these days.

But regarding the planned Surinam well next year, how are you able to use that data from the other recent unsuccessful wells drilled offshore Surinam by all the operators? And then you had your own well there.

How useful was that data in trying to plan your 2019 well?.

Well, I mean, I think if you go back and look at our Block 53, the two wells that we've drilled over the last, call it, three years, we've learned a lot from both of those. You look at 58, it's positioned differently. It's in a different part of what's a very large basin. It's a very large block, so we feel like that Block 58 is ideally positioned.

And it really – the results outbound the Block 58 will not have an impact on our view of Block 58..

Okay. John. Thank you for that. And then just to continue with exploration, you talked a little bit about expiration potential in the portfolio.

What areas globally look interesting to Apache at this point, either as operator or non-operator? And what percentage of the budget, as you start to generate the excess cash flow moving forward, 2019 plus, what percentage of the budget could expiration represent going forward?.

Well, it's something you've got to keep in check. If you look on our international portfolio, of our international capital, we spend some expiration dollars in both the North Sea and in Egypt, right, so. And those are continual programs that we've had great results from, so there's a small portion there.

Suriname is the one place outside where we operate today that we will be active next year. And then on the unconventional side, it's more you U.S.

focused and it's more oil focused, and those are things where we don't spend a lot of money because we're looking at things that are off the radar from other companies where we think we can add value, pick up meaningful acreage positions at low cost that could have a really high impact. And so that's how we approached the unconventional side.

But you've got to keep it in check. You've got to have the lion's share of your capital going into your development programs that are driving your returns and your volume growth and the cash flow..

That's it for me. Thanks a bunch, John..

Our next question comes from the line of Michael Hall from Heikkinen Energy Advisors. Your line is open..

Thanks. Good morning. Maybe following up a little bit on the last couple on Suriname and exploration. How are you thinking about ownership on that Block 58? You currently have 100% on it.

Is that something you likely want to sell down? And is that probably something you'd do before, or would you wait for the results after the first test on that block?.

Michael, it's something we own 100% today; there is quite a bit of interest in the block. And so that's just something we'd have seen the future..

Okay.

Sounds like you're up for taking the full interest on the first well?.

We're definitely prepared. We like the risk to upside profile. Wells are not real expensive. You're probably $55 million to $60 million tops for one of the deeper water wells. So it's something we can easily do a couple wells on. So we'll just see. It's a block we are very excited about, and we'll just kind of see how it unfolds..

Okay. That makes sense. That's helpful. Thanks. And then I guess bigger picture, just thinking about the 2019 outlook relative to the kind of back half experience here in 2018. I know obviously, we've been – you've been executing on production, taking that up, pointing to the high-end of the 2019 production guide or prior guide.

But at the same time, capital has also been moving higher in the last couple of quarters.

How do we get comfortable with that planned ramp down and quarterly spending rate? What are the key drivers of giving you confidence in planning around that at this point?.

Yeah, I'll let Steve give you some specifics. But if you look at our last six quarter, we've been running a pretty flat activity set. And if you look at the actual EMP capital, it's been pretty flat. I mean you saw little bit of a rise in the back half this year and that's been toward acreage, but I will let Steve give you little bit more color..

Yeah, I think that's the story, Michael. I mean for four quarters in a row, leading up to third quarter, we've spent less than $750 million per quarter on upstream capital, if you just set aside the Midstream stuff and Alpine High.

In the fourth quarter, of 2018, we've guided to $800 million, but $65 million of that is going to be exploration land acquisition, kind of a one-off land acquisition, so really we're under $750 million underlying kind of baseline upstream spending in the fourth quarter of 2018. The third quarter, there's a bit of a lumpiness to it.

Again, there's about $800 million excluding land acquisitions in the third quarter, and that's just a bit of lumpiness, why that's over $750 million. There's a lot of lumpiness around activity on completions. Remember, we took the completion holiday and we had some backlog there.

We upsized quite a number of those completions, so there's some lumpiness and some facility spending and some other type of stuff. So I would say that the exception was the third quarter at $800 million on an underlying baseline upstream spend rate as opposed to the second half.

The other way to look at it is second half of 2018, we'll spend, in round numbers, $1.65 billion. We've got a little over $100 million of land acquisitions, lease extensions and acquisitions, so we're just – we're a little bit over $1.5 billion in the second half of 2018 and running at about $1.5 on a half year basis going into 2019.

So I just, I think that the number in the third quarter was the anomaly and the exception. It's not underlying, we're spending at or even possibly slightly below for most of the last four quarters $750 million a quarter in the upstream. And we're not meaningfully changing activity levels here..

Okay.

And I guess on that land acquisition site in the fourth quarter, that $65 million you highlighted, sorry if I missed, where is that roughly?.

We have not, Michael, we have not disclosed that. It's part of our unconventional programs that would be areas that at some point in the future we would talk about..

In the U.S.....

Some portion of that, Michael, is lease extensions ending and some of it is new lease acquisition..

Okay. Thanks very much..

There are no further questions at this time. I would now like to turn the conference back over to Mr. John Christmann..

Well, thank you all for joining us today. I would like to leave you with three key takeaways from today's call. First, Apache had an excellent quarter both operationally and financially. We significantly exceeded consensus earnings and cash flow estimates.

We beat and raised our production guidance for the third quarter in a row and we outlined a strong 2019 view. Second, we are planning a year-over-year reduction in upstream capital in 2019 and upon closing, Altus Midstream will fund our Alpine High infrastructure spend.

This creates good visibility to free cash flow for which a high priority will be share repurchases. And lastly, we are realizing significant benefits from our diversified portfolio and strong leverage to oil prices.

In 2019, as we ramp are wet gas volumes at Alpine High in conjunction with Cryo installation, we will see a step function change in margins and cash flow from the play. I look forward to sharing our ongoing progress with you in the future..

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