Good day. My name is Christie, and I will be your conference operator today. At this time, I would like to welcome everyone to the Apache Corporation First Quarter 2019 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks there will be a question-and-answer session. [Operator Instructions] I will now turn the call over to Gary Clark, Vice President of Investor Relations. Mr. Clark, you may begin your conference.

Good morning and thank you for joining us on Apache Corporation's first quarter financial and operational results conference call. We will begin the call with an overview by CEO and President, John Christmann. Tim Sullivan, Executive Vice President of Operations Support, will then provide additional operational color; and Steve Riney, Executive Vice President and CFO will summarize our fourth quarter and full-year financial performance. Also available on the call to answer questions are Apache Executive Vice Presidents, 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 conjunction with yesterday's press release, I hope you've had the opportunity to review our first 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'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 provide an overview of Apache's first quarter results, discuss our production outlook and comment on our first exploration well in Suriname, review our upstream capital budget and Apache’s commitment to return incremental cash flow to investors and highlight our progress on non-core asset sales. Apache had an excellent first quarter in terms execution, well performance and delivery against our production and capital guidance. We exceeded our U.S. production target, my 5,000 BOEs per day and our international target by 7,000 BOEs per day, on a capital budget of less than $600 million. In the Permian basin, we maintained oil production near fourth quarter levels despite placing one of our two completion crews on a frac holiday for the entire first quarter. At Alpine High, where we also had a relatively low number of completions, production was up significantly from the fourth quarter and was in line with our guidance of 70,000 BOEs per day. Overall, we delivered a 5% sequential quarterly increase in Permian basin volumes. This is an impressive accomplishment given that we placed only 39 wells online in the first quarter compared to 60 wells during the fourth quarter. Strong operational execution and well performance coupled with minimal facilities downtime drove these results. International production was up 6% compared to the fourth quarter. In the North Sea, we benefited from strong early production rates from two wells at Gartner and Callater. A continuation of good results from our revamped Waterford program in the Forties field and high facilities uptime across our operations. In Egypt, gross production was down slightly in the quarter but adjusted production net to Apache was up primarily due to the timing of cost recovery around year end. Looking ahead, second quarter Permian oil production is projected to be down slightly due to completions timing with growth anticipated in the back half of the year is the number of completions increases significantly. At Alpine High production volumes will be impacted in the second quarter by the voluntary gas deferrals we discussed in our press release last week. I would note however, that temporary deferral of this production is expected to improve our short-term net cash flow. Construction of Altus Midstream’s first two cryogenic plants is proceeding ahead of schedule with the first plant currently commissioning and expected to flow gas this month. The second plant is expected to be fully in service during July and the third plant remains on schedule for the fourth quarter. By year-end, Altus will have a total 600 million cubic feet of nameplate rich gas processing capacity, capable of producing more than 60,000 barrels of NGLs per day. Kinder Morgan's GCX pipeline is also expected to be in service beginning in October, which will give Apache access to Gulf Coast pricing on 550 million cubic feet per day of gas from the Permian. These processing and transportation catalysts will drive a significant uplift and Alpine High liquids production revenue and cash flow on which Steve will provide more detail in a few minutes. On the international side, production will decrease in the second quarter as planned. The North Sea will experience natural declines from high production wells at Gartner and Callater while only one new well is being brought online during the quarter. In Egypt, we expect gross oil production to increase as we ramp up activity and our new East Bahariya concession. However, the impact of higher oil prices on our production sharing contracts coupled with natural gas production declines will result in lower volumes net to Apache. Looking out to the end of the year, our projected growth rate guidance from fourth quarter 2018 to fourth quarter 2019 is unchanged. We continue to expect 6% to 10% growth on a total company adjusted basis consisting of 12% to 16% growth in the U.S. and a 2% to 4% decline internationally. Permian oil production is still expected to grow 5%. In Suriname, we have contracted the drillship and continue to anticipate spreading the first well on Block 58 in Suriname around mid-year. The Noble Sam Croft, which is working in the Gulf of Mexico will deploy to Suriname upon completion of its current assignment. We have secured this drillship for a one well commitment and have an option on three additional wells. While Apache is preparing to drill the first well on block 58 at 100%, we have received and are evaluating numerous proposals from potential partners. Turning now to CapEx. Our first quarter upstream capital investment was below guidance and was down 27% from fourth quarter levels. We began preparing for an activity reduction back in November, which was critical to enabling such a material change in our activity pace in less than one quarter. As planned, our second quarter CapEx will increase slightly from the first quarter as a result of increased completion spending in the Permian associated with the return of our second frac crew in the Midland basin and the timing of large pad completions of Alpine High. The timing of exploration spending mostly on Suriname, but also related to some activities in the lower 48 and lease payments at Alpine High where we are exercising some extension options due to the slower drilling activity. Despite some inflationary headwinds related to the rise in oil prices. We remain on track to deliver our 2019 planned activities set for $2.4 billion. We were experiencing cost increases in labor, trucking, fuel and chemicals, but have thus far been able to offset these through efficiency gains. We previously stated Apache's commitment to returning at least 50% of our incremental cash generation from all sources to investors before increasing our planned activity set. In keeping with this commitment, our 2019 planned capital activity and budget remains unchanged and we will began returning incremental cash to investors in the coming months. This is of course in addition to our current regular dividend. Steve will elaborate further. With the success of our organic growth and exploration program, we find ourselves with some assets in the portfolio that we do not envision funding over the next several years. These assets will be more valuable in the hands of different owners. Accordingly, we recently entered into sales agreements totaling approximately $300 million, most of which is related to an exit of the SCOOP/STACK which will close in the second quarter. In summary, 2019 is progressing very well. Overall production was strong in the first quarter and we are demonstrating excellent capital discipline and cost control. The North Sea and Egypt continued to deliver robust free cash flow with their leverage to premium Brent crude prices and higher natural gas and NGL net backs. In the Permian, we are poised to deliver attractive oil growth in a substantial cash flow uplift at Alpine High in the second half of the year. We will also be advancing our differential exploration initiatives most notably in Suriname. In closing, Apache continues to deliver on the strategy we established four years ago, which is to fund the capital program, capable of delivering long-term returns and sustainable growth, live within cash flow at reasonable oil prices, and continue to return meaningful capital to shareholders. We can accomplish this due to our high quality drilling inventory and attractive exploration portfolio, relatively low base decline rate and continuous focus on improving capital productivity and efficiency. With that, I will turn the call over to Tim Sullivan who will provide some operational details on the quarter.

Good morning. My prepared remarks on this call will cover first quarter 2019 region highlights and a review of the excellent progress we are making at Alpine High on cost reduction initiatives and rich gas pad optimization. Operationally, we are off to a very good start with all regions performing well. Companywide adjusted production was up 4% from the fourth quarter 2018 and up 19% from the same period in the prior year. The Permian was the largest growth driver with production up 5% and 36% respectively over the same time period. As John noted, these results are particularly impressive giving our reduced activity during the quarter. Our well completions in the U.S. were down 35% from the fourth quarter, which was the result of timing and a frac holiday in the Permian Basin. We have recently added back a cleaner, cheaper natural gas field hydraulic frac fleet. In the Midland Basin where we continue to drill high productivity oil wells, our primary activity in this quarter was an 8-well Wolfcamp B pad at Powell and a 6-well Lower Spraberry pad at Wildfire. In the Delaware Basin, we completed and brought on line a 4-well Wolfcamp pad at Dixieland, and at Alpine High, we brought on line 17 wells with the primary focus on rich gas in the Northern Flank. In Egypt, as a result of our recently awarded concessions and our ongoing broadband seismic acquisition program, we have generated several hundred leads and prospects in both legacy and new concession areas. In the New East Bahariya concession, we brought on line three exploration wells that achieved the combined peak rate of nearly 4,500 barrels of oil per day and have cumed more than 125,000 barrels of oil. These are low cost, short-cycle wells that typically payout very quickly. We also continue to have exploration success on our legacy acreage. One notable well on our Seawall concession in the Faghur Basin achieved a 30-day average flow rate of 5,200 barrels of oil per day. In the Matruh Basin, our Tango North exploration well tested at a rate of 4,000 barrels of oil per day and will go on line around mid-year. We also had a very successful Q1 development drilling campaign in Egypt with 14 producers, nine of which have tested in excess of 1,000 BOE per day. As we continue our G&G work, we expect to identify and drill many low-cost high rate oil prospects throughout the Western Desert, such as the ones we drilled this quarter. Turning to the North Sea, we drilled our first development well at Storr, which was the site of our 2016 exploration discovery. This well encountered 232-feet of net pay in the Nansen and Eriksson formations similar to the results from the discovery well. As we explored deeper, this well also encountered an additional 84-feet of net pay in the Kahraman formation, which is the same sand that is highly productive at Callater. First production at Storr is expected late in the fourth quarter. At Alpine High we will reach a significant milestone this month to start up of Altus first cryogenic plant in the next two to three weeks. Before Steve walks you through the significant cash generation in margin uplift we will receive. I wanted to highlight the significant progress we have made with both costs and our rich gas optimization initiatives on the upstream side. Since Alpine High is delineation phase began in 2017, Apache has made steady efficiency gains, drilling costs per foot or down approximately 20% from 2017 through the end of the first quarter. Over the same time period, we realized that 30% reduction in completion costs per lateral foot. These costs improvements have come with only a modest increase in average lateral length. We expect to generate further efficiencies as lateral links increase over time and the average number of wells drilled per pad increases. Multiwell pad optimization has now begun at Alpine High. We are evaluating optimal pattern and spacing relationships within a section to recover larger volumes of hydrocarbons with fewer wells and less capital. As an example, we recently conducted spacing and pattern tests on two rich gas pads on the Northern Flank situated in adjacent sections. By adjusting the horizontal spacing between wells, the vertical location within target zones, and an improving our frac design. We are seeing cumulative recoveries from our 6-well Mont Blanc pad significantly outperform our 8-well Blackfoot pad. 6-wells producing from the Woodford A&B formations on the Mont Blanc pad achieved 150 days gross cumulative production of 10.5 Bcf of rich gas compared to 9.7 Bcf and the 8-well Blackfoot pad in the same Woodford A&B formations. In combination with cryogenic processing each pad was also have cube in excess of 800,000 barrels of NGLs. With 2 fewer wells, the Mont Blanc pad has not only outperform but has also realized cost savings of $12.7 million as a result of fewer well bores. Capital efficiency is vital to success in resource play development and the trends are certainly positive for Alpine High. We believe there are substantial additional cost savings to be realized through ongoing optimization initiatives which include longer laterals and larger pads. Apache has also made considerable upfront investments in water handling and reuse facilities at Alpine High, which will drive cost savings for many years to come. Our primary target formations, the Woodford and the Barnett produced very little institchu water, thereby eliminating the need to contract costly water handling trucks and salt water disposal services. We believe the Alpine High is well on its way to being the lowest cost, most efficient and most environmentally friendly rich gas play in the country. With that, I will now turn the call over to Steve.

Thank you, Tim. On today's call, I will review first quarter financial results, update the status of gas production deferrals at Alpine High. Provide a few guidance changes for 2019, highlight the cash generation capacity of our rich gas production at Alpine High following cryo startup later this month and GCX startup later this year and outline our current thinking around capital return to investors. As noted in the press release issued last night under generally accepted accounting principles. Apache reported first quarter of 2019 consolidated net loss of $47 million or $0.12 per diluted common share. These results include a number of items that are outside of core earnings, which are typically excluded by the investment community and their published earnings estimates. On an after tax basis the most significant items include a $35 million unrealized loss on derivatives, a $31 million tax adjustment related primarily to evaluation allowance on deferred tax assets and $18 million of leasehold impairments. None of these items impacted cash flow in the quarter. Excluding these and other smaller items adjusted earnings for the quarter were $38 million or $0.10 per share. Highlights for the quarter include upstream capital investment of less than $600 million, which demonstrates our commitment to running a discipline program and meeting our full-year upstream capital budget of $2.4 billion. For 2019, we have locked in pricing on much of our capital costs such as drilling rigs, pressure pumping services in sand. However, as John indicated, trucking, labor, fuel and chemical costs are trending higher with oil prices. First quarter operating costs, we're generally in line with guidance. LOE per BOE costs came in a bit higher than expectations, primarily driven by Egypt. Offsetting this gathering, processing and transportation costs were less than guidance. As we look at the remainder of 2019, let me first discuss our temporary production deferrals at Alpine High. Beginning in late March, for a variety of reasons, Permian Basin natural gas dipped to extremely low, and at times negative pricing. In response, Apache chose to defer a portion of our guest production at Alpine High. In the month of April, these deferrals averaged approximately 230 million cubic feet per day of gross wellhead gas. The deferred volumes are comprised of both lean and rich gas. And now we anticipate a continuation of week gas prices, until more transport capacity comes online later in the year. We currently plan to restore all of our rich gas production as we commissioned our first two cryo facilities over the next eight to 10 weeks. Apache is cognizant of the impact that gas deferrals have on Altus Midstream Company and has agreed to reduce certain shared overhead costs. We believe this is in the best interest of both companies. It has a negligible net impact to Apache and ensures that Altus remains in a good position to deliver on the critical near-term infrastructure build out at Alpine High. With this situation and other impacts in mine, we have updated our forward looking guidance on a number of items. Taking into account, a range of potential production deferrals for the remainder of the quarter, our second quarter Alpine High production outlook is 45,000 to 55,000 BOE per day. This is projected to increase to 85,000 to 95,000 BOE per day in the third quarter, which still includes the potential for some deferred volumes. Our 2019 rig schedule and completions activity is not impacted by the deferrals. As a result, we still expect that fourth quarter and year-end exit rates from Alpine High will exceed 100,000 BOE per day. In addition to issuing at 2019 quarterly guidance at Alpine High, we have also introduced quarterly Permian oil guidance and international guidance. The details of which can be found in the supplement on our website. For upstream capital investment, we are expecting the second quarter to be in the $650 million to $700 million range and full-year capital investment remains at $2.4 billion, as originally planned. For LOE, we are increasing our guidance to recognize some additional costs in Egypt as well as the impact of lower volumes in Alpine High. Our full-year LOE is now expected to average around $8 per BOE. Next, I would like to review some upcoming changes, which will significantly improve the cash flow generation from Alpine High. While we have been clear that Alpine High is a diversified resource with all three hydrocarbons phases at its core, it is an enormous rich gas play and the key to value creation is full recovery and monetization of the NGL stream. Today we'd process rich gas through mechanical refrigeration units, which are not very efficient, so we don't recover the full NGL stream. The resulting small volumes of NGLs are currently truck to a facility where they can be transported to Mont Belvieu and fractionated. This temporary setup is relatively high costs and significantly squeezes the cash margin. Finally, we are selling most of the residue gas at Waha, which as we spoke about previously, prices at around zero today. The result is extremely low margins and minimal cash flow net to Apache. That is the reality of Alpine High today. But that is all about to start changing because of the preparations that have underway for nearly two years. By the end of this quarter, we will generate much higher NGO yields as we transitioned to cryo processing. We will receive much better NGL margins through transport and fractionation under our long-term fixed price contract with enterprise. And in a few months, when GCX is placed in service, we will transport residue gas out of the basin and receive Gulf Coast pricing. And our supplement, we have included a slide illustrating the cash generating potential at Alpine High, assuming full utilization of a single cryo unit with 200 million cubic feet per day of nameplate processing capacity. To summarize the key takeaways, 200 million cubic feet per day of gross wellhead gas process through Altus’ cryo facilities is capable of generating $270 million to $300 million of annualized revenue under a very reasonable range of commodity price assumptions. Note this is net revenue to Apache after royalties. After further netting out all gathering, processing, fractionation and transportation fees as well as projected operating costs and state severance taxes, Apache’s annualized net cash flows from a single cryo facility are expected to range from $135 million to $165 million. So this transition will begin in the next few weeks and will carry on through the rest of 2019. By the end of this year, we will have three of these cryo facilities in service with all three of them expected to be operating at full capacity sometime in 2020. Before moving to Q&A, I would like to address our thoughts on returning cash to investors. Coming into 2019, we committed to returning at least 50% of excess free cash to investors, before increasing capital activity. With the stronger than planned year-to-date oil prices and the coming proceeds from asset sales, we will soon be in a position to begin that process. We will accomplish this through debt reduction, share repurchases or most likely a combination thereof. To the extent we choose to include some debt reduction that would likely begin with retiring $150 million of debt that matures in July, all of this is of course in addition to our ongoing dividends. Also, just to be clear, we have no plans to change our capital activity set. In conclusion, we have began the year well, building on the momentum from 2018. We continue to execute on our strategy of delivering returns-focused short cycle growth in the Permian Basin, sustaining our international businesses for long-term free cash flow generation in building growth opportunities for the long-term through exploration. 2019 will be a promising step forward. Alpine High is on the doorstep of generating significant cash flow with the startup of cryo processing and transported gas to the Gulf Coast, and we will commence exploration activities on Block 58 in Suriname this summer. While we are prepared to proceed on a sole risk basis, we are actively considering proposals from numerous would-be partners. And with that, I will turn the call over to the operator for Q&A.

[Operator Instructions] And your first question comes from Bob Brackett of Bernstein Research.

Hey, good morning. I had a question on Block 58 in Suriname. It looks like the lease expires the initial exploration term June 24 of next year. Can you talk about the renewal process or the extension process on that lease?

Bob at this point, we've worked with the government of Suriname. We've got a one rig or one well, commitment kicks us into the next phase. And obviously we will commence that well ahead of that time schedule, so it'll kick us into the next phase and that's all we've shared publicly at this time.

And the next phase is a – it’s two to three-year extension, and is there any relinquishment involved?

It kicks us well into Phase II and at this point, we have not given any more color on Phase II.

Okay. Appreciate it.

Thank you.

And your next question comes from John Freeman of Raymond James.

Hi, guys.

Good morning, John.

Following up on Suriname, given the unsolicited sort of interest you've had from potential partners, and you all talked about, you'd be willing to proceed on an individual basis. Does this in any way sort of possibly delay when you spread the well while you kind of review all these proposals before you spread it?

Not at all. I mean, we're on a path. We're prepared – we’ll be prepared to drill multiple wells, and we’ve said we’ve got a one well commitment with the rig and three optional wells, and we're prepared to head down the path we're on. So not at all.

Okay. And then just on – the follow-up for me on Slide 11 on Alpine High and the cost improvements that you all broke out when you look at sort of pad development versus the other wells. Can you remind me what percentage of the activity right now is on pads versus the rest of the wells?

I mean the bulk of it is shifting to pads. What you've got in there is just the quarter numbers. It was kind of 194 versus what it would have been in terms of the pads at 153 type numbers. So we're shifting in the pads, but it's some of the testing and some of the other wells would drive that. But you're seeing us move predominantly into pad development with some larger pads coming.

Great. Thanks guys. Appreciate it.

Thank you.

And our next question comes from Douglas Leggate of Bank of America.

Well, thanks. Good morning, everyone. Thanks for taking my question. John, I wonder if I could pull this a little bit on Suriname. I would understanding is that when the well was drilled in the adjacent block, there was down or on up dip oil well that was tied by that well, which obviously bodes very well for your blog? So my question is, how have you chosen the location of the well and given that - assuming not correct. Why wouldn't you drill the location right up against the Guyana border?

Well, I mean, the first thing is we know we've got an active hydrocarbon system Doug. We've got seven plays when you look at our block, I mean it's just an unbelievable walk and as we've said more than 50, very large prospect. So we obviously have chosen our first well location. We have not disclosed that. But clearly we've taken into account any information we have through public means that's out there.

Would it be reasonable to assume that would be, how can I put it one of the top two or three targets on the block to basically try and make sure your side of it?

I wouldn't want to assume anything about the top three targets on the block, but clearly you've got a discovery a that is on the lease line and that's your bodes well for us. But I hate you assuming anything.

Understand. My follow-up is also about Suriname if you don't mind that. It really goes to your point about 100%. These wells and the adjacent block are quite an expensive relatively speaking $50 million to $100 million given the potential impact on farmed and value in the block. Why wouldn't you drill it 100%?

Well, I mean, as of today we still on the block 100% and that's the path we're marching down. So I mean the reason we wouldn't is because somebody talked us out and doing that.

Fair point. Forgive me. I was going to try one final one. Out of sign beat on the road, talking a little bit about this on the prospect backlog and just share with everybody what you see as your risk prospect by lock in the block. And I will leave it there. Thank you so much.

I mean I just think it's a phenomenal block. Our timing and when we picked it up, we were just fortunate that we picked this at the middle of 2015 when there was not a lot of activity, a lot of interest. We were able to do it but before Exxon drill laser and before we drilled our first well and it was a really, really low price in terms of the commitment at the time and it is very well-positioned as we've said. There's multiple plays. We've got both shallow and deepwater targets that we can get to. And I mean, when you look at the size of this 1.44 million acres, I mean, that's larger than range county just for perspective. And there's more than seven different plays and 50 plus very large prospect. So we're anxious to kind of get going.

Good luck, John. Appreciate the answers. Thank you.

Thank you.

Our next question comes from Gail Nicholson of Stephens.

Good morning, everybody. Can you talk about where the decline rate is at the 40 field now in North Sea with the Waterford management that you were doing and how that has changed maybe any near-term PNA you would have it Forties?

Gail, I mean, I think what you've seen as we've changed philosophically how we approaching that and we really are managing the Waterford. I do not have the particulars off the cuff, but we are seeing long-term trends that are flattening that decline. If you look at the abandonment timeframe, even prior it's been in the 2032 to 2035 time reframe, I think this pushes that back And most importantly, it just provides stability, to the rights out there. So but I don't have those – we’ve not what's been done. I would say you could look at some of the work that would Mac I think recently updated some of their work that is starting to reflect some of that. But I don't even think their report captures all of what we see.

Okay. Great. And then just looking at the improvement you guys have seen in the Alpine High well cost. You've only done a slightly longer laterals. Can you just talk about how you envision lateral link progression over them, the next I guess several years and what you think that the farther I do from a cost improvement standpoint on the drilling aspect?

Well, I mean the big thing we've got down there as you don't have a lot of shallow production you're having to deal with. We also don't have a lot of chirrup and hard rock like you have up in the Oklahoma area. So you can get down quickly. We've been able to eliminate some casing strings. Clearly, the land position will dictate some are lateral lengths. The other big factor we've got in the source interval as you do not have water. And so with your longer laterals, you're going to get the productivity increases on a relative as you increase your lateral foot basis. Most of our wells have been shorter in the north because that's where our land, retention has been. And so that's what you're saying. But clearly, as we get the opportunity to drill longer laterals, you'll see, us transitioning mayor and I think you're going to continue to see costs come down. If you look at our numbers, we've had great progress and we continue to see progress is those programs have continued this quarter, so a lot of really good things happening on – at Alpine High.

And our next question comes from Mike Scialla of Stifel.

Yes. Good morning. Steve, walk us through some pretty good detail on the uplift you expect to see with the cryo plants coming on Slide 12. Just wondering with Waha Hub gas prices where they are, was there any discussion with all this to maybe potentially delay a ramping up that first cryo plant until the GCX a line goes into service in October? Can you just talk about that and if not, how does that ramp at the first cryo plant look in terms of the timing?

Yes. So the back part of your question first, the cryo number one is – it is being commissioned now, and it should be a – it should be full by the end of May. In terms of – well cryo number two will be – it's actually moved up in the schedule and be commissioning in June. It will be full by the end of July. In terms of considering the possibility of moving those back in the schedule, no, we did not consider that at all. We want to get those things up and running. We want to get the rich gas flowing again and we want to get those things working to the full extent possible of extracting that NGL content out of that rich gas stream. We've got enough gas today or fill cryo number one, and we will have enough gas, by the end of July to fill cryo number two. So those will be fully functional and full of rich gas, on the day they're ready to go full. The primary reason why we didn't, as you can look at that that slide, in the pack that we gave out, you can see the gas is certainly an important part of the full operating cash margin from the rich gas at Alpine High, but it's not the dominant piece. There's some oil content in those rich gas wells and there's the NGL yields. And there's – even if gas is selling at zero, you can see that that's still above a breakeven cash flow situation. Once we get those things fall. So we want to get them operational. We're going to get them up and running and GCX is not far away. Its official startup date is October 1 and that's not that's not too long away.

Thanks for that. And maybe a follow-up, can you just talk about your outlook for NGL prices over the next couple of years, obviously a key component as you said to the economics at Alpine High?

Yes. Hi, this is Dave Purcell. If you look at wide grade today and you look at Slide 12, we're running about current spot prices in the strip. It's about $24 a barrel that's really suppressed mainly by the light ends, particularly ethane. If you look at the ethane fundamentals going through the end of this year and into 2022, two things are going to happen. There's going to be more cracker capacity added on the Gulf Coast. There also be more dot capacity for exports added. So as you look through the next 18 months, we think there's much more upside and downside to the current ethane price and we think that will start to move the overall wide grade higher.

Thank you.

Thanks, Mike.

And your next question comes from Charles Meade of Johnson Rice.

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

Good morning, Charles.

If I could ask two questions on Alpine High. One just the quick one, real quick is to clarify. So when you have this cryo startup in July, you may still have some issues with the natural gas pricing. But your NGL pricing at that point you're connected at the tail pipe to get Gulf Coast pricing at that point for your engine.

Yes. It will start moving to Mont Belvieu through our enterprise agreement. So we'll start see an immediate uplift.

Got it. And then the second question, this gets more on the well spacing and those kind of intriguing results you guys put out with the Mont Blanc and the Blackfoot pad. I recognized this early, but does this suggest that there's going to be any changes to the type curve – individual well type curve in the number of locations that you guys have in the Woodford or is this perhaps instead just something that's going to be localized to these areas?

No, I mean, I think it shows the process, and the methodical process we've taken to kind of break the rock down and get to what we think is the optimal development scenarios. In both cases, we drilled some Woodford C because we needed to see as thick is the column is as much rock as we have to deal with, we needed to see how the A's, B's and C's performed together. We clearly went a little wider spacing, a little larger fracs at the Mont Blanc, you're seeing some pretty impressive results. So some of that's also about changing. So as we've said, in the future you're probably going to see us drop the A's a little deeper, drop the B’s a little deeper or eliminate the C’s and a little wider spacing and then we'll continue to learn on the fracs. But I think, the big thing is the last location count we put out was fall of 2017, I think, October, 2017, and we're still in a position where location count would go up given the assumptions we've got in place. And that's why we've been very careful to do our testing and understand it. We never assume more than two in the Woodford or the Barnett. And we're very confident in those numbers. And you're seeing some strong performance.

That's helpful context. Thank you, John.

You bet, Charles.

And your next question is from Brian Singer with Goldman Sachs.

Thank you. Good morning.

Good morning, Brian.

I wanted to touch based on a couple of items, the first on exploration outside of Suriname. Can you just give us an update on how that's progressing and any expectations for making any of the ideas you're pursuing open to the public market? And then also a follow-up on the comments you made on assets sales to what degree are you pursuing and how meaningful could further assets sale will be?

Well, I mean, I think from the get-go, we've always said we were going to differentiate ourselves through exploration. And we do have a Lower 48 program, it’s focused DUS, it's focused more oil, it's focused more on conventionally, and our strategy has always been to try to build positions of scale and size where there was an opportunity – and low cost, where there was an opportunity to try to do in order to create meaningful value for our shareholders. So we have a program there. With the appropriate time, we'll talk more about that. As far as your second question on the asset sales, clearly we have over $300 million now that's under contract. As we said, the bulk of that is our SCOOP/STACK position. And I think the point there, Brian, as we look at our portfolio and we look at the things that we will be funding to the extent there's things that we will not fund in the future and if there's an opportunity for somebody else to own those and create value by purchasing those then we're not afraid to do that. And that's where we find ourselves today with the success we've had through our organic expiration program. We continue to take a long-term view through our portfolio model at our areas and what's going to attract capital. And we did not see the SCOOP/STACK is an area where we would be putting capital and therefore, we have it under contract.

Great. Thanks. And if I could ask one more. On Slide 8, you highlight a trajectory in the Permian relative of the timing of completions and as you show in both 2018 and 2019, you've had a couple of quarters of frac holidays? Is that's kind of the way you're planning going forward to achieve desired growth there to basically try to batch completions into two quarters of the year or is that just the way it's ended up?

No. It's just really coincidental with the way - the programs is lined up. When you go to larger pads, it becomes a little more lumpy. I think the key here for us is early in 2018, we had to put a crew on a frac holiday because we'd had the drilling efficiencies and picked up and in terms of the – on the - well I'll say the completion efficiencies and picked up and they're drilling rates hadn't caught up yet. And so we had to set up frac crew down and what’s you saw as the timing of that. The one going into this year was really his prices dropped in November. We anticipated that we needed to drop a couple of rigs. We put a frac crew on holiday, that's really so we could deliver the capital budget that we have set for this year. So I think those were actions we've taken to level low the activity set to where we need to be for this price environment. And so we dropped a couple of rigs and put a crew on holiday. The trade-off there is as your second quarter production. We'll dip a little bit. But we think in the grand scheme of things, I would rather have more of a level loaded program throughout the year, which is how we positioned ourselves.

Just adding to that a little bit, Brian. John commented on the lumpiness of the activity said. That just becomes a lot more visible when your capital program is reduced to the size of what we're – where we are today. The lumpiness of an efficient drilling and completion had level activity set just becomes a bit more visible. That's all.

Okay. Thank you.

And your next question comes from Scott Hanold of RBC Capital Markets.

Thanks. My first question, hopefully pretty quick on the NGLs. Once a cryos are on, could you remind us what the product breakdown of that NGL basket is going to be for you guys?

Yes. I don't think the NGL yield in Alpine High is going to be any different than the NGL yield anywhere else. We have an operated these types of cryo units before. So that would probably be a good question for a second or third quarter results when we've actually operated a couple of them for a bit.

Okay. I understand. Thank you. And that sort of the – so just certain average barrels which you're basing that $24 a barrel assumption right now that you put out there?

Well, we just stuck an assumption out there on the pricing at $24. We just said 40% of WTI, that's about where it's trading today. That's a reasonable assumption. We think that's conservative for the long-term for multiple reasons that Dave Pursell laid out earlier. And just on a mixed NGL barrel basis, 40% of WTI is probably especially if you look back in time it moves around a lot obviously, but 40% is probably a conservative assumption.

Okay, fair enough. And my follow-up question is regarding the free cash flow, you all talked about ones these cryos start coming on online or at least the cash flow generation and also the asset sale proceeds and utilizing that. When you step back and look at him in a Apache stock is compared to say the last call it five years, it's at a pretty low point? Does it make sense to like, as you look to return cash to shareholders to be a little bit more focused on share buybacks right now or in how does that's potential Suriname well sort of play into that decision?

Well, I don't think that Suriname well plays into that decision for 2019. Let's get the transactions close, which will happen in the second quarter. We'll proceed slowly, but we said we would return the excess free cash at least 50% of that shareholders before we changed our activity level. I think we said it a couple times in the prepared remarks. We'll say it again. There's no change in activity level for 2019. We're still on the 2.4 billion capital program. And I just remind everybody that the startup of the cryo facilities and the cash flows from those were in the plan for this year. So those aren't necessarily delivering excess free cash flow. They're delivering the plan free cash flow to the extent they start early, to the extent that NGL prices improve. To the extent that they give us a greater yield than we may have planned. And those types of things deliver excess free cash flow, but not just the startup from them. And we will look at I think as we get to the second half of the year, which is a going to be upon as pretty quickly, that's when we'll get into the discussions about how do we use that excess cash flow. And I could assure you that both the debt reduction and a share buybacks will be on that agenda. And in that conversation you were likely to do some of both there's some debt maturing 150 million of debt maturing in July. If we choose to paydown any debt, then that would probably be where we would start.

Understood. Thank you.

And our next question is from John Aschenbeck from Seaport Global.

Good morning everyone and thank you for taking my questions.

You bet, John.

Thanks John. So there's been a lot of commentary around 2019 spending. So I apologize if I missed this. But just thinking about the remainder of the year, if I run and admittedly over simplified exercise and take your Q1 spend and your Q2 guidance, it would just indicate that spendings coming down in future quarters. So is that an accurate assessment? And then secondly, it just – how should we think about the cadence of spending and the second half of the year? Thanks.

Well, I mean, I think the first thing is we're down 27% over fourth quarter and we actually came in right at 25% of what we guided for the year. So first quarter was pretty evenly run for how the year would pan out. We walked through in the prepared remarks, some things that could cause second quarter would be a little higher, which is kind of why we guided there, but there are more exploration driven. So I think from our perspective, we took the bigger decision in November and December to drop some rigs and put a crew on holiday to kind of do that now. And it puts us in a nice position for the back half of the year. So we're very confident in the capital number. We will come in under – or at the $2.4 billion for this activity set and feel really good about it.

Okay, great. That's helpful John. So just to make sure I clarify there Q2 has some one time spending a lot of it exploration activity that you just wouldn't expect to repeat and future quarters. Is that fair?

I would just say that in terms of the timing of how we – what we have budgeted for a Suriname and the exploration, a big chunk of that is in Q2 and the other thing you need to look at is if you look at our first quarter numbers, we do have some assets sales. We've had a couple of rigs running up there too. So our run rate for Q1 would have even been a little lower on what are going our existing asset base remaining will be.

Okay, great. I'll go ahead and leave it there. Thanks for the time.

And your next question comes from Richard Tullis with Capital One Securities.

Thanks. Good morning, John. Two quick questions.

Good morning.

Going back to the M&A, I know you touched on this a bit little earlier, but as you look at the North Sea, I know the market there seems a little more active. How do you view those assets in your portfolio today? Given the healthy margins there, but balancing that with maybe a more healthy M&A market in the North Sea?

Well, I mean I think the big difference with us is, as opposed to what's being divested by some of the other parties is we invested in the infrastructure. If you look at our efficiency and our up times and our run rates and our LOE, we're very competitive. I mean we typically lead in production efficiencies and low cost and it's because, we were fortunate that after we bought these properties in the 2003 with BP for 40s and then 2011 with Beryls. We invested heavily in rebuilding the infrastructure, which really puts us in a nice position. So you look at those two assets. They're fantastic assets. They're different. 40s, we've just got a massive 5 billion barrel in place. Field is produced over 2.5 and it just continues to give. And so it's real easy to manage that for the long-term with the water flood work we're doing, and we love the Brent pricing. We love the margins and it's not like we have a lot of stuff looming that would require you to want to move out of it. If you look at Beryl, it's a totally different asset, very prolific in its own right as you've seen. The way we've been able to leverage the infrastructure with the subsea tie backs by bringing on Callater and bringing on Beryl or Gartner. And now you into the Beryl facility and now you look at the Storr well, we just announced, I mean, we found a whole another section there in the cormorant that we were not expecting. So there's a lot to do up in the Beryl area and we've got nice infrastructure. It's been invested in. It's in great shape and it gives us a differential advantage. So we love the cash flow. We love the Brent pricing exposure. Your gas receives a higher price. So it's an asset that we quite frankly, I liked the cash flow profile from.

Good insight John. Appreciate that. And just lastly, what's the current outlook for Alpine High natural gas to be sold into the Mexican market, say, over the next year or two?

Well, I mean, I think the first thing is, if you look at how we're positioned physically for gas to flow, we couldn't be better. But I think we recognized from the get-go that, you don't want to be trying to develop a resource play and waiting on Mexico or dependent on Mexico for your gas deliveries. And so that's why we work the options to the Gulf Coast and what you'll find is Mexico will be an option for on down the road, which I think can become a premium. But today it's not something we're counting on. I mean, that's why we work the Gulf Coast options. We will be mainly insulated from Waha here pretty quick, which is going to put us in a differential advantage on our gas. And, and really it's the NGLs that really make this thing fly. The NGLs cost structure and the lack of water or the things that really differentiate the rich gas played at Alpine High.

Very good. Thanks John. Appreciated.

Yes. Richard, if I could just add to that. I don't know the exact numbers, but today Mexico takes about 4 Bcf a day from the U.S. via pipeline. And 3 to 3.5 of that comes along the Gulf Coast. And so while we've got these great pipelines running by Alpine High, those are for the future more than the current. And so I think your question was related to the near-term. The near-term is we get gas to the Gulf Coast with the startup of GCX this year and Permian Highway next year. You can easily access the Mexican market and you might imagine that we probably have been considering that are working on that.

Okay. Thank you.

And your next question comes from Jeoffrey Lambujon of Tudor, Pickering.

Good morning. Thanks. First question is just on gas coverage with Gulf Coast Express. Once that system comes online and thinking about your capacity there, can you speak to how long you are able to receive Gulf Coast pricing for 100% of your Alpine High volumes?

Sorry, Jeff, can you just repeat that question?

Yes. So once GCX comes online, just trying to get a sense for how long you expect to receive Gulf Coast pricing for your Alpine High production?

How long before we receive it or how long will we receive it?

How long will you receive coverage for 100% of your production?

Well, with Gulf Coast Express, we will pretty much be selling all of the residue gas at Gulf Coast pricing with the startup of GCX and then Permian Highway comes a year later. So Gulf Coast Express, we have 550 million a day of capacity, and then with Permian Highway, we have another 500 million.

Got it. And then just a follow-up on the liquids front. Appreciate the color on ethane, Dave, and sorry if I missed any follow-on comments on the LPG outlook, but could you just speak to what you're seeing there over the near-term?

Yes. So Jeoffrey, you're talking about – define near-term for me?

Next 12 to 18 months.

Yes. Again, if you think about the NGL barrel, the bottom end of the barrel is going to trade with crude and gasoline and gasoline has been much improved over the last three or four months. So we're really thinking about butane and pentane, that's a call on crude and gasoline. So I'll leave that to you. Propane and ethane, we're going to see improvements in the fourth quarter in dock capacity through this and really through the summer and we think that'll help relieve some of the congestion with better exports. And then on ethane, in addition to better export capacity, we're seeing later this year and into 2020 more cracker capacity coming on line, and significant percentages of total – of current capacity. So at least in the next 18 months, I can envision a much more robust NGL pricing environment, particularly given improvements in ethane and propane.

Thank you.

And your next question comes from Arun Jayaram of JPMorgan.

Hi, good morning. Just a couple of quick questions. One, have you guys quantified the production impact from the planned SCOOP/STACK asset? So I was just wondering to know and does that already included in the guidance?

Arun, it’s not included, once it closes – but if we look at the first quarter numbers, it would've been about 10,000 BOEs a day, and about 13% oil, it's mainly gas.

Mainly gas. Okay, that's helpful. And just a question…

And more importantly, Arun, our lease up income was about 14, we spent half of that just in CapEx. So I mean it's a…

It's not a big free cash flow again.

It’s not a big impact on the EBITDA.

Fair enough. And just a question for the participation on the equity on the pipes, do you guys have an estimate of what the cost would be to Altus to participate in the pipes? Just the CapEx.

I think at 1 o'clock when the Altus is called is on Arun, you got to pop on and you can get Mr. Bretches at that time and you’ll feel that one, so.

Okay. All right. Fair enough. Thanks a lot, John.

Appreciate it.

And we have passed the top of the hour. I'll now turn the call back to John Christmann for closing remarks.

Well, thank you for joining us. So just want to end on a couple of points. We're executing extremely well, delivering on both capital and production and are reiterating our $2.4 billion capital budget for the year. Alpine High will hit at an inflection point in the very near future as the three Altus cryos come on line and we'll generate a substantial cash flow uplift. And lastly, we're looking forward to the initiation of our exploration program at Suriname very soon.

And thank you all for joining today's Apache Corporation first quarter 2019 earnings conference call. You may now disconnect.