APA Corporation (APA) Q2 2019 Earnings Report, Transcript and Summary

Good morning. My name is Natalia, and I will be your conference operator today. At this time, I would like to welcome everyone to the Second Quarter 2019 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks there will be a question-and-answer session. [Operator Instructions] Thank you. I will now turn the call over to Mr. Gary Clark, Vice President of Investor Relations. You may begin, sir.

Good morning and thank you for joining us on Apache Corporation's second quarter 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 second quarter 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 20 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 second quarter financial and operational supplement, which can be found on our Investor Relations Web site 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 Web site. 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 Web site. 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 second quarter results, comment on our production outlook and capital investment program for the remainder of the year, outline our current position and initiatives in the Permian Basin, Egypt, North Sea, and offshore Suriname, and conclude with some thoughts on capital allocation in the context of the current macro environment. The second quarter Apache's total adjusted production exceeded guidance with upstream capital spending of just under $600 million. Through mid year, we have invested less than 50% of our four-year budget of $2.4 billion. We are focused on strict capital discipline which is achievable given our level loaded activity set and relatively stable operational pace over the last couple of years. Permian Basin oil volumes drove our guidance in the second quarter for a few reasons. Tim will provide more details. But in aggregate we brought online 15 fewer wells than anticipated and incurred a significant delay in initial production from several other wells. Most of these items are just timing related from which we will fully recover by yearend. Internationally and at Alpine High, volumes in the second quarter were in line with our adjusted production guidance. Construction and commissioning of Altus Midstream's first two cryogenic processing plants were on budget and ahead of schedule. The first cryo plant has already exceeded nameplate capacity. The second plant is fully in service and ramping inlet volumes. And the third plant is scheduled for startup around year end. For the remainder of 2019, capital will be at or below our second-half budget of $1.2 billion. With activity more heavily weighted toward completions, this should result in good production momentum as we exit 2019. We have revised our second-half Permian Basin production guidance to reflect the delays we experienced in the Midland and Delaware as well as projected third quarter gas deferrals at Alpine High. Our fourth quarter Alpine High production target of 100,000 BOE per day is unchanged from prior guidance. This is based on a plan to return all deferred production to sales by the beginning of October with the GCX pipeline startup. It also assumes that Altus Midstream's cryo units are operating in full ethane recovery mode. We will prioritize value over production volumes and depending on the prevailing gas and NGL prices may to choose to reject ethane at Alpine High, which would impact our reported fourth quarter volumes. Internationally, we continue to expect third and fourth quarter volumes to be in line with prior guidance. With that, I would like to offer some specific comments on our key operating areas of the Permian Basin, Egypt, and North Sea as well as offshore Suriname. In the Permian Basin, Apache has one of the industry's largest acreage footprints and a diverse inventory of opportunities. For more than two years now, we have been running a six to ten rig program focused on oil development in the Midland and Delaware basin, and a five to nine rig program focused on Alpine High. In the Midland and Delaware basins, we are in full development mode delivering highly productive top tier oil wells at very competitive cost. We have a large inventory at oil prone locations that continues to expand with ongoing improvements and understanding of the resource base. This position will support a higher base right count should we choose to add or reallocate capital from other areas. At Alpine High, we have a very large resource base, much of which has been advanced to development ready inventory. With that accomplished, Alpine High must now compete for capital with the rest of our Permian assets. In the short term, Alpine High economics were adversely impacted by very depressed gas pricing at Waha. In response, we are continuing to defer the majority of our lane [ph] gas and a portion of our rich gas production until the GCX pipeline enter service in late September. From a cash flow and returns perspective, it is far more viable to wait a few weeks and produce into an improved price environment. At current gas and NGL prices, some portions of Alpine High are less competitive than other opportunities in our portfolio. If this pricing situation does not improve, some capital will be re-allocated to areas with more leverage to oil price most likely elsewhere in the Permian Basin. Turning to Egypt, Apache is the largest acreage holder in the Western Desert and is the country's leading oil producer giving a strong leverage to Brent pricing with a substantial increase in our acreage position over the past two years and a 3 million acre broadband seismic acquisition program nearly two-thirds complete. We anticipate a significant refreshed inventory of oil focused opportunities. This should help increase capital efficiency and returns as we continue to generate a high level of free cash flow. Egypt provides tremendous long-term sustainable oil production potential. In the U.K., North Sea Apache has some of the industry's best assets and one of the lowest cost operations, production recently reached a two-year high driven by continued exploration success in the barrel area and a shallower oil decline rate in the Mature Forties Field resulting from a sharpened focus on water flow and activities. Annual capital investment has been less than $300 million and with strong leverage to Brent oil prices, the North Sea is consistently generating substantial free cash flow. In the fourth quarter, we will bring online another exploration discovery at store in the barrel area in a second development well at Garten. We have plenty of exploration running room in the North Sea with the ability to tie discoveries back relatively quickly and inexpensively to leverage existing infrastructure. In Suriname, we currently anticipate receiving the Nobel Sam Croft drillship during the second half of August and spudding our first exploration well on Block 58 in September. We have secured this rig for a one well commitment with an option on three additional wells. We believe that Block 58 offers tremendous potential and multiple wells across the block will likely be warranted for proper evaluation irrespective of the initial wells outcome. While we intend to drill the first well at 100% working interest, we have continued interest from potential partners. To summarize, our current portfolio Apache has an extensive inventory of high quality assets ranging from significant identified resource ready for short cycle development to large scale highly prospective exploration. This includes at scale in both conventional and unconventional resource covering the full spectrum of hydrocarbon potential from oil to liquids rich gas tilling gas. When we began 2019, the commodity price environment was volatile but planning based on a $50 to $55 WTI and a 250 to 280 Henry Hub for the long-term felt prudent, if not slightly conservative. Oil prices so far are delivering on that expectation. But gas prices are significantly weaker. Additionally, NGL prices took a material downturn in the second quarter and are now trading near historic lows around 35% of WTI. In this volatile commodity environment, a high quality diverse portfolio with the flexibility to redirect capital is a significant advantage. As we progressed our longer term planning process, we are closely monitoring macro commodity fundamentals and evaluating many capital allocation scenarios for 2020 and beyond under a number of different pricing decks. We look forward to sharing our preliminary thoughts on this in the coming months. In closing, our strategy for creating shareholder value is straightforward. Flex our capital allocation and leverage our portfolio commensurate with the prevailing commodity price environment live within cash flow at reasonable oil prices and generate free cash flow to return to investors, fund the capital program capable of delivering a sustainable combination of long-term returns with a moderate pace of growth, execute on our differential high impact conventional and unconventional exploration opportunity set. I'm confident Apache can deliver on this strategy given our diversified and well-balanced portfolio, high quality drilling inventory, relatively low Permian oil base decline rate, attractive exploration portfolio 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. From an operational perspective, Apache's highlights for the second quarter 2019 include larger pads with longer laterals in the Southern Midland Basin, strong Barnett results at our Mont Blanc pad and Alpine High an oil discovery on one of our new concessions in Egypt and steady development work in the North Sea at store and garden. Please refer to our second quarter financial and operational supplement for drilling pad and well highlights across our portfolio. Company-wide adjusted production was down from the first quarter 2019 reflecting the sale of mid-Continent assets during the period and deferred production at Alpine High. Year-over-year production was roughly flat. In the second quarter, we drilled and completed 67 gross wells, 54 in the Permian Basin, 11 in Egypt and 2 in the North Sea. In the U.S. second quarter 2019 production totaled 264, 000 barrels of oil equivalent per day. As John mentioned, Permian Basin oil production was impacted by some one-off events or pads and wells are commencing production later than planned. We are trialing a new electric-powered frac fleet however, commissioning of the fleet took longer than expected and it arrived on our first location 30 days late impacting not only the initial pad but follow on pads as well. We have since fracked 11 wells on four different pads with this fleet operational efficiencies are improving and on a single well basis, we realized more than $250, 000 in diesel savings alone while reducing emissions an estimated 90%. Also in the Midland Basin an early sidetrack during drilling operations coupled with flow-back limitations on the pad delayed peak production nearly a month from the Black Dog pad, which includes 9 wells drilled with 2 mile laterals. This pad is now producing as expected. In the Delaware Basin, we drilled 5 wells at Dixie Land and have deferred the completions, while we remediate mechanical issues at two of the wells. We are working our completion schedule and expect to place these wells online later this year, but the precise timing is uncertain. The impact of these production delays has affected second quarter results and will linger into the third and fourth quarters. We expect to be caught up with all this year's plan completions by year-end and we anticipate fourth quarter oil production to come in between 100,000 and 105, 000 barrels per day compared to our prior guidance of 105,000 barrels per day. We are also benefiting from the start up of Altus Midstream, new cryogenic processing plants at Alpine High. Drilling and completion costs at Alpine High continue to improve on a cost per foot basis as we execute more development activity. Pad development continues to drive down costs into our projected range, drilling completing and equipping costs on one mile laterals are approaching $5.5 million per well. International adjusted production of 132,000 BOE per day came in as expected. In Egypt, we drilled our first lower Bahariya discovery and our new East Bahariya concession the well flowed at an initial test rate of 3900 barrels of oil per day. This success of a number of additional low cost short cycle drilling locations, we are also building inventory with our 3D seismic survey across 3 million acres in the Western Desert, where we have completed over 65% of the shoot. Turning to the North Sea third quarter production will be impacted by annual turnaround maintenance with production rebounding in the fourth quarter. The subsea tieback development at store remains on schedule for first production in the fourth quarter. We also expect to have a second producer at Garden drilled and completed by year-end. With that, I will now turn the call over to Steve.

Thank you, Tim. On today's call, I will briefly review second quarter financial results and a few updates to 2019 guidance. Discuss the impact of our recent asset sales, and our continuing debt management initiatives and update the status of our promise for returning capital to investors. As noted in the press release issued last night, under Generally Accepted Accounting Principles, Apache reported a second quarter 2019 consolidated net loss of $360 million or $0.96 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 they're published earnings estimates. On an after-tax basis, the most significant items include $220 million for asset impairments, most of which were associated with our recent asset sales, $114 million of evaluation allowance on deferred tax assets, and $59 million for a loss on extinguishment of debt. Excluding these and other smaller items, adjusted earnings for the second quarter were $41 million or $0.11 per share. Upstream capital investment was less than $600 million for the second consecutive quarter, demonstrating our commitment to running a level-loaded disciplined capital program and meeting our full-year upstream budget of $2.4 billion. Capital spending in the third quarter will be biased slightly higher than the fourth quarter due primarily to P&A work in the Gulf of Mexico, and development spending on store in the North Sea. LOE per BOE for the quarter was above expectations, primarily due to higher salaries in Egypt driven by in-country inflation and increased diesel consumption in both Egypt and the North Sea. Looking ahead, we have increased our full-year LOE per BOE outlook to capture the impact of these higher cost trends and ongoing gas deferrals at Alpine High. Offsetting LOE costs, gathering, processing, and transportation costs were below guidance in the quarter. And our guidance for the full-year has been revised downward. This is primarily driven by the sale of assets. In May and in July, Apache completed the sale of midcontinent assets in two separate transactions, resulting in $560 million of net cash proceeds after typical closing adjustments. A portion of these proceeds was used to retire $150 million of bonds that matured in early July. During the second quarter, we refinanced $546 million of debt maturing over the next five years to enhance near-term liquidity. We also refinanced $386 million of higher coupon debt of various maturities to lower our cost of borrowing. Combined with the debt paydown the net result of these actions is that we reduced overall leverage and extended our debt maturity profile, significantly reducing near-term debt maturities. In February, we announced our intention to return at least 50% of our incremental cash generation to investors before any increases to planned capital activity. In keeping with this commitment, we began returning incremental cash to investors with the debt paydown in July. In the meantime, our 2019 planned capital activity has not changed, and we have no plans to do so. While oil price and sale proceeds helped create capacity for further capital return to investors, the combination of historically weak gas prices in the Permian, a result in production deferrals, and now extremely weak NGL prices have more than offset the oil price benefit. We will monitor anticipated 2019 cash flows and will continue to prioritize returns to investors over increasing capital spend. And with that, I will turn the call over to the operator for Q&A.

[Operator Instructions] Your first question is from the line of Michael Scialla with Stifel.

Hey, good morning, guys. John, you mentioned…

Good morning, Mike.

You mentioned Alpine High is going to have to compete with the rest of the portfolio with lower than expected NGL and gas prices. Just wondering what your preliminary thoughts are for next year in terms of the midstream, do you go ahead with any additional cryo plants there or how you're thinking about 2020 at this point for Alpine High?

Well, I mean if you look at where we were when we reported this year's plan we had an oil price of $53, and gas was at $2.80, and propane and ethane were at high levels, $0.75 and $0.30. So the gas and the ethane and propane have come down significantly. I think with where we sit today, Mike, and Altus will have their call at 1:00 o'clock. But with where we are today with cryo, two coming on now and three coming on in the fourth quarter, we're in pretty darn good shape on that front. So I think they'll be in a good position to have the infrastructure in place we would need for the capital we look at.

And then I wanted to see if you had any updated thoughts on the offset well at Haimara discovery and Suriname, and any thoughts there on any additional color you can…

Well, yes, as far as Suriname, I mean we're obviously anxious. Looks like we're going to get the rig here in a couple of weeks, kind of mid to late August, so it's coming, and we should spot our first well in September. Obviously, from the public data we've analyzed everything we can. We've got 2D data and have looked very closely at all the activity that's going on next door, and we've kind of rolled that in. We have the benefit of a very state-of-the-art 3D with very good resolution. So we've worked our block very, very hard and in detail, and been doing it for multiple years. So we're obviously anxious. If you look at the Block 58 it's a very large block, it's 1.44 million acres today. We have planned to start our program at 100%, and but there is continued interest in the blocks, I will say that. But when we look at it we have not given specifics on where the location will be. I will tell you we have a number of wells permitted. We have a pretty good idea where it's going, obviously with us about to get the rig, but there's seven play types, there's over 50 large prospects, and there's a pretty good chance that you'll see us lining up some of those targets with where we will choose to drill the early wells. I will tell you, it's going to take multiple wells in this block to fully evaluate it.

Very good. Thanks, John.

Thank you.

Your next question is from the line of John Freeman with Raymond James.

Hi, guys.

Hi, John.

So sort of following up a little bit on Mike's question, when we look at sort of the really strong margins that you all are getting internationally, and I guess if gas prices and NGL prices sort of remain depressed, I guess just sort of how you're thinking about potentially increasing possibly the allocation of capital that goes international sort of on a go-forward basis now that you're basically saying that Alpine High will have to start competing more on a return basis going forward?

Well, we have a very elaborate dynamic planning process, and it's turned into kind of a 365-day-a-year process. And we're in the throes of that now. And when we look at the portfolio I think the first thing I'll say is we have a very diverse portfolio with many investment options, and none of those have been funding it full capacity over the last couple of years. So we've got a lot of opportunity. Secondly, I would say is that we have a very deep understanding of our asset base, which gives us the ability to make sure we're making those right calls on where we're going to put that capital. And the big thing is we're going to allocate capital to drive long-term value. So when you look at where we sit today there are numerous places where we have been under investing where we have leveraged oil. Obviously our Midland and Delaware oil positions are two places. We've had a great track record of results there. Those are areas we could go to. When you look at Egypt, we're in the middle of working through the big 3D shoot, and so we're kind of anxious to see what comes out of that shoot, but I can tell you the early returns look very promising. So there are places we can do that as well. There are other oil zones up at Alpine High. And we've got some other places in the portfolio as well. So we have an abundance of deep places where we can put capital, and we'll work through that under normal course and come back later in the year on our plans as we see going forward.

That's great. And then just my follow-up question, you've done a great job on the CapEx front, and obviously are tracking below what would have been expected so far this year. And I guess when you sort of talk about anticipate spending at or below the $2.4 billion budget, I just want to make sure I'm sort of on the same page as the way you're thinking about it. So is it that you're sort of being conservative and you want to wait to see another quarter play out to make sure things still track the way they have so far this year, or is it possible that some of the savings that you're generating you're considering maybe reallocating, reinvesting back somewhere across the portfolio?

Well, there's a lot of factors that come into play. I'll say number one, we took a frac holiday Q1. Secondly, when we brought in our clean fleet, it was a lot -- 30 days late on the commissioning. So we actually are kind of back in loaded in the Permian and we are going to bring on, I think, 60% of our wells in the back half of the year in the Permian. So that's a little bit of a John. Secondly, we've got the Suriname oil out there that is moved. We've always thought most would be third quarter and fourth quarter span, but it's shifted a little bit, so some of it's timing. There are areas where we're seeing it Alpine High, our well costs come down. And so, we're seeing some areas that are helping us a little bit, but there's just a lot of factors that kind of leave us in that position. I think the point to underscore though, is you will not see us increase the activity set. And we feel very confident that we can deliver that activity set for the $2.4 billion or potentially less.

Thanks, John, I appreciate the answers.

You bet.

So our next question is on the line of Charles Meade with Johnson Rice.

Good morning, John to you and your team.

Good morning Charles.

Hey, I want to just pick up where you just left off there. Just a quick question, in Suriname, in answering the last question, you said the Suriname well, at least I think I heard you say that. But either guys are getting this rig in next couple of weeks for the September, you're going to have time on the calendar to drill at least one more well, so. So how many wells are in your plan or in that -- in the capital budget as it exists right now?

Well, in the 2.4, we had budgeted one well a 100%. So we have a one well commitment with the rig, we have an option for three additional wells. And, realistically, we've got one in the budget. And, that's where I'll leave that.

Okay, got it. Thank you. And then John, going up back to Alpine High, wondering if you could talk us through the process of two things, what is the -- what's the sequence? And what's it going to look like for you guys? And what are you going to be focused on as that Gulf Coast Express comes on beginning of October, maybe mid of September? And how is that going to interact with your decision to recover or reject ethane?

Well, I mean, obviously, we have to watch the dynamics. I mean, we think GCX coming online is a big event for the basin, it's a big event for us and a big event for Alpine High, is we have a quarter of the volume on the 2 Bcf over from like 550 of the 2 Bcf a day is going to move. So, for us, first thing is we want to see what happens to differentials. We want to see the impact that that might have or the follow-through on the NGO prices. So we will be watching that very carefully. We want to make sure we're looking out and looking at longer-term views on things because you can't be shifting capital around need your short-term decisions, but -- so we're going to take a very methodical and deliberate approach. But we'll be cognizant of how those things, kind of play out over the longer-term and what it looks like they're going to do will dictate, how we run some of our capital programs. And we've got the flexibility with the inventory to plan for some multiple scenarios. And so, we'll be ready to go with multiple scenarios. And we'll kind of watch and see how that all unfolds. I think it's going to be good for the Basin. Dave, is there anything you want to add?

No. John, the one thing I'd add is on the ethane rejection side. The crowds are up and running. They've operationally flexed them for full rejection and full extract, ethane extraction mode. And so, we'll have the operational flexibility to react at the field to Waha pricing and Waha gas and Gulf Coast NGO prices. So, John is right, we're going to make long-term capital decisions based on long-term views but we will be able to react on a relatively short basis on the -- with the cryo operations.

Thank you. That's helpful, Dave and John. Thank you.

Thank you.

Your next question is on the line of Gail Nicholson with Stephens.

Good morning, everybody. Question on the North Sea with the final agreement in barrel, can you talk about the potential opportunity set that there and what you guys are looking for with that first well in the fourth quarter?

Well, I mean. Again, we're excited about the North Sea. We've done a really good job over the last few years of being able to generate strong free cash flow from our operations, or you've seen the track record, with calendar and then Garten in terms of tie backs to the infrastructure. You know, what we've been able to do is leverage some of the little further out acreage; we've got a nice tertiary play there. And, you know, we had 100% of that acreage. And so, we are not able to bring a partner in, and we'll get a couple wells carried that I think are, are upside kind of to our picture, but we're very excited about there's been some tertiary discoveries, and we've got some very nice looking prospects that will be able to get drilled as you move into later this year, and then the next year.

Great. And then, one for Steve a housekeeping question. How much PNA CapEx is in 3Q for Gham [Ph]?

Yes, there's Gail. I don't remember the exact number, but it's in. I think it's in the $50 million to $100 million range. It's probably a little bit less than that $50, around $50 million, Gail.

Okay, great. Thank you.

Your next question is from the line of Bob Brackett with Bernstein Research.

Hey, good morning. I had a question on the line field process at Gulf Coast Express. I understand we're undergoing line field now. Is that a benefit to you guys in terms of either volume or price?

Bob? I would just say yes.

Okay. Second question, then the September spot in Suriname or that -- is that a 40 day well?

Well, it could be as short probably as 30. Or, we kind of looked at 30 to 60. But we'll see.

Okay, so 30 to 60 days. And would you plan to announce results immediately on TV, or is that something you'd wait for a conference call to announce?

We just have to see. So I mean, it's -- there's -- there will be multiple targets? And I'll just leave it -- it will kind of play that by year.

And by multiple targets, does that mean, you think you could hit perhaps Miocene and Cretaceous reservoirs with a single well born or maybe a sidetrack?

I won't get into as much detail but I think we will be able to stack several of our objective plays.

Great. Thanks for the color.

Your next question is from the line of Doug Leggate with Bank of America.

Thank you. Good morning, everyone. Good morning, John.

Good morning, Doug.

John. I wonder if I can just take a twofer. If you don't mind, first of all on Alpine High in Midland, can you -- philosophically, it sounds like you're kind of rationalizing a pivot towards the more oil part of the basin. If that's the case, can you touch on the inventory that you have in the middle inside? And also the trajectory then for Alpine High would the objective then be to basically fill the cryo funds and hold it flat after that or what are you thinking about it?

Well, I mean, I think what you're -- what we're going to do is basically allocate capital based on how we see the commodity price dictate. And then, we've got the luxury to do that, we're at a point today at Alpine High, where we now have that luxury, we hold a lot of the acreage, it won't take a lot of drilling to hold the acreage that we view is very perspective for really rich gas NGO and gas production. And so, we're at a point today where we can let the economics and leverage our portfolio. So there's a couple different scenarios. I think the cryo is recognizing that we own 79% of Altus. And factoring that in is something we will factor into our calculus of how we look at the value proposition there with those -- with prices. As far as the depth of inventory in the Midland Basin, we feel very good about that, we've been predominantly focused, and we've run more rigs than we run at a day in three areas in the Midland Basin Powell, Wildfire and Azalea. And in there we've drilled somewhere between 20% and 30% of the locations that we see there. We are now adding more landing zones. But you got to understand that that's really only about 20% of our acreage footprint. And you look at the other areas, we've gone out and drill some test wells, Benedum and Hartgrove fantastic results. So we've got a really deep inventory in the Midland Basin. We've been focused on getting to pad development. We went through a period, where we did a lot of testing and slowed down and make sure we get spacing, right, understood gas-oil ratios, where we could move forward and you're seeing the results of those programs. And so, we have a lot of inventory there that is sitting - ready to drill and we just kind of weigh that with the integrated economics in the price deck of how we look at the options in our portfolio.

I appreciate the full answer. My follow-up is on, obviously is on [indiscernible] I just wonder if it sort of run something past get your sense of the - so it seems to me that when we think about the probability of geological success of the Exxon Haimara has basically de-risked some of the parameters that we contributed, particularly hydrocarbon system obviously, how do you guys think about the PG, the probability of geological success on the wells that you're going to drill and if that's the case, can you confirm or could you maybe speak to -- it seem to me that it wouldn't make a lot of sense at this point to drill in the immediate offset well behind Haimara. So, are you going to drill in offshore or is it's a completely independent prospect? And I'll leave it there, thanks.

Well, I mean, first of all, it is exploration. So if I try to pin my guys down there. I'll tell you, you're no better than one in four and that's just because it's exploration. Now that being said, they've moved into a phase where they're better than exploration right next door to us and you have a discovery on the International Water boundaries. So clearly that does two things. It proves that there are hydrocarbons in the system. When we look at the views across by kind of stitching together the 2D and the 3D data, you'll find that the geologic setting is not changing much, but you know, it's exploration. So I'm not going to come out and tell you that it's any higher than that at this point. But we're obviously very anxious to get started. And we're very comfortable going forward at 100% with our interest.

John, just to be clear, any of the four wells potentially planned direct offsets to higher MRO?

We have multiple wells permitted, Doug. And we'll - I'll just say, we'll play them as we go and as we learn.

Awesome, thanks for the answers.

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

Yes, thanks. I was curious, you know now that I guess the cryo plant I, it has been up and running for a bit and the number two is obviously getting some traction here. Do you have a sense that you know what -- if you were normalized kind of commodity prices like, where do you all think sort of the mix of that NGL basket would be in terms of products?

Yes, this is Dave Pursell. Right now, these are the technology used in the cryos, we're removing almost 100% of the ethane. So as a result, if you compare it to an average NGL barrel, this will be a little more heavily weighted to ethane and propane. We're still lining amount - we would anticipate, as we move forward. We'll get a richer gas stream kind of the inlet of the cryos and so, ultimately the NGL barrel will look a little closer to what the traditional Midland barrel looks like with maybe a tad more ethane in it.

Okay, so that's sort of the next batch command, you'll get a better sense of that. Okay and then just to stand…

One other thing there too Scott, it's going to change based on the formation. We're into a lot of what we're flowing through there right now is, and as you get into the bottom edge, it's going to get a little heavier as well, but so there is, a lot of dynamics that will, dictate that going forward.

Right, and that's all part of the capital allocation process for the future. All right, okay and so then if you look at what do - are some of those product prices, need to do to make Alpine High say compete to say your standard oily Midland. Well, I mean how much, how far off? Are we forward to being more competitive today?

Well, I mean, where we started this year, when we were kind of thinking 53 oil and 280 gas and we have $0.75 on propane $0.30 on ethane. We like the mix where we have. So, we're obviously not there today with where the NGLs have come down and gas specifically. So, clearly that's going to be somewhere between where we were and where we are today.

Okay, well that's a good benchmark to give us a sense of where it shifts. I appreciate that, thanks.

Your next question is from the line of Brian Singer with Goldman Sachs.

Thank you. Good morning.

Good morning, Brian.

Just one question on our end, which is with regards to Egypt, you talked about this new discovery on the Bahia area. Can you just add some greater color, on how we should think about the resource potential? How that competes in the portfolio and any impact that could have to either capital investment or growth in Egypt?

Well, I mean if you step back and look. Egypt has got some of the highest returns in our portfolio. So it competes very, very well. We are shooting a large area in the nice thing about Egypt is, it's stack pays. But, they're conventional rock and so you can get a 3,000 or 4,000 barrel a day IP from a vertical well. It's going to cost you $2 million to $3 million. So it's tax out very, very nicely in the portfolio, and I think with the new seismic. If you look back over the last two years, we really kept Egypt flat with two discoveries at Peter and Bear Nice and just drilling offset wells there. So it doesn't take a lot to have a real impact on us and we're obviously anxious to get 3-D. The 3-D back, we think our capital productivity, can improve is the quality of the prospects goes up and we love the leveraged Egypt.

I mean, I know you manage to cash flow and not the production mix, but as the wet gas picks up in Alpine High is there,-- any interest in kind of offsetting that with greater investments in either Egypt or the North Sea both to improve cash flow and mix?

I mean, we will look as we talked about, as I talked about answering some of their Rick questions. We'll look at the whole portfolio and we'll balance that and look at where you can move short term. It's easier to move into probably our Midland Delaware Basin. But we'll, clearly that will be factored into our capital. We love the Brent price, we love the Brent price exposure in the cash flow or on the international side.

Great, thank you.

Your next question is from the line of David Deckelbaum with the Cowen.

Good morning, John and team. Thanks for taking my questions.

Yes

I just wanted to follow-up on some of the discussion around your sensitivities next year and you commented on the NGL prices at Alpine High and gas prices. I guess with TCX coming online and they have to be a day that, you have on there? I guess how do you think about the asset, in terms of minimum activity that you'd be willing to pursue and may be considering the asset as a marketing asset near term to take advantage of that spread and I guess how wide would that spreads have to be for you to us this kind of treated as something where you would just benefit from the marketing margins for the time being?

Well, I mean I think that the thing you look at number one Alpine High. We like the asset, it's a large resources, we've proven there is tremendous rich gas potential. We now have a lot of the infrastructure in place that we need. And quite frankly, we hold a lot of the acreage that is important to us. So from our perspective, we're in a position where, we can continue to high grade acreage and maintain that footprint and keep the optionality. I think as GTx comes on line, we've been waiting for that, I think it's a big event for the gas help here that's kind of why we've elected to curtail some pads, that we're bringing on and wait until it does come online because, there were such a short time away from seeing some increased cash flow. So it's an asset that, we will look to leverage and try to maximize but the important thing is, we have a portfolio. When we only have limited capital, we can put in. So we have to balance that, in regard with our other assets.

Got it. Thank you, guys. And you were successful in the mid-count asset sale, anything else in the hopper these days that you guys are looking at selling?

Not anything that I would call major that we'd have out there, but we're always looking at the portfolio, always looking to trim if there's things we're not going to invest in, if there is areas that others would put, what we would view as good value on our premium value. We're not afraid to turn things loose.

Thanks for the color, guys.

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

Yes, good morning. Perhaps for Steve, I was wondering Steve, how you think your gas and NGL realizations will trend call it relative to benchmarks post the startup of GTx in the Permian of corporate wide.

This is David Pursell, Arun. Once GTx starts out, it would be our anticipation that Waha starts to trade in a more normal position relative to Gulf Coast less transportation. So I think our Permian and we think that will normalize some of the other hubs in the basin. So, you're likely going to see the Permian Basin realizations track in line with the Gulf Coast benchmarks less transportation. Steve, would you add anything to that.

Yes, the only thing I would add, David, is that there are some, significant events in terms of increased source or new sources of demand both for gas and for NGLs and for export capacity of NGLs coming online later this year. That would certainly potentially have some impact on pricing both on the Gulf Coast in back to Waha and back to the Permian Basin as well.

Okay. And my follow-up is, you guys announced kind of an agreement which near on an LNG type pricing structure. I think, is in the beginning, I'm wondering if you could maybe shed some light on that and talk about maybe some of the longer term implications from that?

Yes, we're probably not going to shed a whole lot of details on that, but basically its structure. So first of all, it's 140 million a day, 140 million cubic feet a day. So, it's not a significant amount of volume that, we're producing and gas that's priced based on that. But it was, it's consistent with what we've always been talking about around Alpine High in the Permian Basin more generally and that is we want, to get a diversified portfolio if you will marketing based sources of realized price for the gas coming out of the Permian Basin and particularly Alpine High. And that's 140 million a day that gives us some flexibility in accessing various LNG markets around the world and getting netback from realized prices at landing points.

Okay. Any details, just on the mechanism just trying to understand maybe the financial impact on that 140 million a day?

The mechanism is it's a relatively simple one. We have flexibility as to where the product goes in terms of pricing and it's a net-back based on tolling arrangements and shipping costs.

Okay, fair enough thanks.

Your final question is from the line of Michael Hall with Heikkinen Energy.

Thanks, good morning or good afternoon. Yes, I was just curious what the base case assumption; our thought process is on extending the rig to drill to follow-up wells in Suriname at this point? Well, you guys go ahead and drill those three wells. Is that kind of the base thought, or is that dependent on whether or not you secure JV partner in the area.

It's purely an option, Michael, and all we've said is we're committed to want to, we have the option to take the rig and drill 3 more and that the block is going to be going to need additional wells.

And if you were to extend it and take and go kind of heads up on that on your own, is that - how would that kind of fall in the pecking order in 2020 in terms of capital allocation given that it's - there is no clear - commodity linkage yet.

I'll just say it would be exploration dollars with material upside and I'll leave it there.

All right, fair enough. Thanks guys.

Thank you.

There are no further questions. I will turn the call back over to John for closing remarks.

So first, I want to end on a -- just a couple of points, approximately 60% of our planned 2019 Permian oil weighted wells will come online in the second-half of the year, giving us confidence in our year-end oil production exit rate. Second, our 2019 upstream capital spending is on track and will be at or below $2.4 billion. Next year's capital plan, assuming current strip around these levels will be $2.4 billion or more likely less. And lastly we are closely monitoring oil, NGL and natural gas fundamentals and we'll allocate capital within our portfolio in response to the longer-term price signals. Thank you very much.

This concludes today's earnings call. Thank you for your participation. You may now disconnect.