Q2 2019 Earnings Call
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 speakers remarks, there will be a question and answer session. If he would like to ask a question. During this time simply press Star then the number one on your telephone keypad.
Please limit your questions to one question and one follow up if you would like to US for your questions press. The pound key. Thank you I will now turn the call over to Mr., Gary Clark Vice President of Investor Relations you may begin Sir.
Importantly, our 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, Our Apache Executive Vice Presidents, Marc Meyer Energy technology data analytics, and commercial intelligence and Dave Purcell planning reserves and fundamentals.
Our prepared remarks will be approximately 20 minutes in length with the remainder of the hour allotted for Q in may in conjunction with yesterday's press release I Hope you have had the opportunity to review, our second quarter financial and operational supplement which can be found on our investor Relations website at Investor that Apache Corp Dot com.
On todays conference call, we may discuss certain non-GAAP financial measures a reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.
Consistent with previous reporting practices adjusted production numbers cited in today's call are adjusted to exclude non controlling interest in Egypt, and Egypt tax barrels.
Finally, I'd like to remind everyone that today's discussions will contain forward looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss today a full disclaimer is located with the supplemental data on our website.
And with that I will turn the call over to John .
Good morning, and thank you for joining us.
On today's call I will provide an overview of Apache 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 in 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 trailed 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 year end.
Internationally and at Alpine high volumes in the second quarter were in line with our adjusted production guidance construction and commissioning of Altus Midstreams first two cryogenic processing plants, we're 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 100000 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 Gcs pipeline startup. It also assumes that Altus Midstreams 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 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'd 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 in a diverse inventory of opportunities.
For more than two years now we have been running a six to 10 rig program focused on oil development in the Midland and Delaware basins, 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 it very competitive costs.
We have a large inventory of oil prone locations that continues to expand with ongoing improvements and understanding of the resource base. This position will support a higher base rig 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 are adversely impacted by very depressed gas pricing at wall Hawk. In response, we are continuing to defer the majority of our lean gas and a portion of our rich gas production until the gcs pipeline into service in late September .
From a cash flow and returns perspective, it is far more valuable to wait a few weeks and produce into an improved pricing environment.
At current gas and NGL prices, some portions of alpine high are less competitive than other opportunities within our portfolio. If this pricing situation does not improve some capital will be reallocated 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 is the country's leading oil producer, giving us 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 UK 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 Beryl area and a shallower oil decline rate in the mature forties field, resulting from a sharpened focus on waterflood 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 and the Beryl area and a second development well at garden, 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 noble Sam Croft drillship during the second half of August in 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 on both conventional and unconventional resource covering the full spectrum of hydrocarbon potential from oil to liquids rich gas to lean gas. When we began 2019 the commodity price environment was volatile, but planning based on a 50% to $55 Wi Fi and at 250% to 80 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 Wi Fi in this volatile commodity environment, a high quality diverse portfolio with the flexibility to redirect capital is a significant advantage.
As we progress our longer term planning process, we are closely monitoring macro commodity fundamentals in 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 am 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 and oil discovery in one of our new concessions in Egypt, and steady development work in the North Sea and store and garden.
Please refer to our second quarter financial and operational supplement for drilling pad and well highlights across our portfolio.
Companywide adjusted production was down from the first quarter 2019, reflecting the sale of mid continent assets during the period and deferred production and 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 two in the North Sea.
In the US second quarter 2019 production totaled 264000 barrels of oil equivalent per day.
As John mentioned Permian Basin oil production was impacted by some one off events were pads and wells are commencing production later than planned.
We are trialing and 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 $250000 in diesel savings alone, while reducing emissions an estimated 90%.
Also in the Midland Basin in early sidetrack during drilling operations.
Coupled with flowback limitations on the pad delayed peak production nearly a month from the blanked on pad, which includes nine wells drilled with two mile laterals.
This pad is now producing as expected.
In the Delaware Basin, we drilled five wells at Dixie land and have deferred the completions, while we were mediate 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 and 105000 barrels per day.
Compared to our prior guidance of 105000 barrels per day.
We are also benefiting from the startup of ounces midstreams, new cryogenic processing plants and alpine high.
Drilling and completion costs at Alpine high continued 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 five and a half million dollars per well international adjusted production of 132000 BOE per day came in as expected.
In Egypt, we drilled our first lower bahari, the discovery and our new east three concession.
The well flowed at an initial test rate of 3900 barrels of oil per day.
This success since up a number of additional low cost short cycle drilling locations.
We are also building inventory with our Threed seismic survey across 3 million acres in the Western Desert, where we have completed over 65% of the chute.
Turning to the North Sea third quarter production will be impacted by annual turnaround maintenance with production rebounding in the fourth quarter.
The sub sea tieback development at store remains on schedule for first production in the fourth quarter.
We also expect to have a second producer and 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 in consolidated net loss of $360 million or 96 cents 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 in their 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, a valuation 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 11 cents 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 PNM 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 lower 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 then July Apache completed the sale of mid continent 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 pay down. 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 pay down 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 the resultant production deferrals and now extremely weak NGL prices has more than offset the oil price benefit we will monitor anticipated 2019 cash flows and we'll continue to prioritize returns to investors over increasing capital spend and with that I will turn the call over to the operator for today.
Ladies and gentlemen at this time, if you would like to ask a question. Please press Star then the number one on your telephone keypad again that is star one to ask a question. If you would like to withdraw your question press the pound key.
Please limit your questions to one question and one follow up.
Your first question is from the line of Michael from Miller with Stifel.
Hey, good morning, guys.
John You mentioned watermark.
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 for next year in terms of the midstream do you go ahead with any additional cryo plants there.
Or how are you thinking about.
2020 at this point for Alpine high.
Well I mean, if you look at where we were when we report. This year's plan, we had an oil price of 53 and gas will go to 80 in.
Propane and ethane were at high level 75 cents and 30 cents the gas the ethane and propane have come down significantly I think with where we sit today, Mike and Alto. So we'll have their call at one o'clock, but with where we are today with cryo sat two coming on now in three coming on in the fourth quarter.
Wherein in pretty darn good shape on that front.
So I I think they will be in a good position to have the infrastructure in place that we would need for the capital that we look at.
Okay.
And then I wanted to see if you had any updated thoughts on the.
Offset well that Humira discovery in Suriname and.
Any thoughts there on.
Any additional color you can.
Well I mean is.
As far as Suriname amino we're we're obviously anxious.
They looks like we're going to get the rig here in a couple of weeks kind of mid to late August so it's common.
And we should spud our first well in September .
Obviously from the public data we've analyzed everything we can we've we've got two D data and have looked very closely at all the activity that's going on next door to if kind of roll that in we have the benefit of a very.
State of the art three D., who with were very good resolution. So we work our walking very very.
Hard and then detail we've been doing it for multiple years. So we are obviously anxious.
If you look at the block 58, it's a very large block. It's 1.44 million acres. Today, we are planned to start our program at a 100%.
And but there is continued interest in the block so I will say that but.
When we look at it and we have not.
Given specifics on where the location will be I will tell you we have a number of wells permitted.
You know, we have a pretty good idea where scale and obviously with with with us about to get the rig, but theres seven play types. There's over 50 large prospects and Theres a pretty good chance that you will 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.
Hey, John .
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 I, if gas prices and NGL prices remain depressed.
I guess, just sort of how you're thinking about potentially increasing.
Possibly the allocation of capital to go is international.
Sort of on a go forward basis now that you are 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 a kind of a 365 days 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 that weve been funding at 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.
Under investing where we have levers the oil.
Obviously, our Midland and Delaware oil positions are two places.
We 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 three day 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.
You know there are other roles zones.
You know 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 kind of plans as we see going forward.
That's great and then just my follow up question you all that 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.
I just want to make sure I'm sort of on the same paves the way you're thinking about it so.
Is it that you are 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 right you're generating you're considering maybe reallocating reinvesting back.
Similar across the portfolio.
Well there is a there is a lot of factors that come into play ill say number one we took a frac holiday Q1.
Secondly, when we brought in our claim fleet. It was a low 30 days late on the commissioning. So we actually are a kind of backend loaded in the Permian or we're going to bring on a I think 60% of our wells in the back half of the year in the Permian, So thats a little bit of a John secondly, the we've got the surname oil out there that is moved.
You know what we've always thought most would be third quarter and fourth quarter spam, but its shifted a little bit so some of its timing.
There are areas, where we're seeing at alpine high our well costs come down.
And so we're seeing some areas that are helping us a little bit but.
Yeah, 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.
Good morning, John as you and your team.
Good morning Charles.
I wanted 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 Lisa I think you heard you say David.
You guys care getting this rig in next couple of weeks by the September you're going to have the 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 100% so.
You know we have a one well commitment with the rig we have an option for three additional wells and the.
Realistically, we've got one in the budget and.
I mean, that's where I'll leave that.
Okay got it. Thank you and then John going back to two Alpine high I'm wondering if you could you could talk talk us through the process of two things what is the what's the sequencing.
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.
Recover or reject ethane.
Well I mean, obviously, we have to watch the dynamics I mean, we think Gee CX coming online is a is a big event for the basin. It's a big event for us and a big event for Alpine high.
As we have a quarter of the volume on the two bcf over what like 550 of the two Bcf a day, it's going to move so.
You know for us.
The first thing is we want to see what what happens with differentials when we want to see the impact that that might have on the follow through on the NGL prices. So we'll be watching that very carefully.
We want to make sure we're looking out in in looking at longer term views on things because you can't be shifting capital around our knee jerk short term decisions, but so we're going to take a very methodical and deliberate approach additive, 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 the plan for some multiple scenarios and so we'll be ready to go with multiple scenarios and what kind of watch and see how that 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 the ethane rejection side, the crowds are up and running they've they've operationally flex them for full rejection and full extract ethane extraction mode and so we will have the operational flexibility.
To to react at the field to Wahab pricing and and Waha gas and Gulf Coast NGL prices. So.
John's 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. David John Thank you.
Thank you.
Your next question is from the line of Gail Nicholson with Stephens.
Good morning, everybody and questions NRC with a final agreement and barrel can you talk about the potential opportunity set 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 the North Sea, we have done a really good job over the last few years of being able to generate strong free cash flow.
From our operations there you've seen the track record.
With calendar and then garden in terms of tie backs to the infrastructure.
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 we had 100% of that acreage and so we've been at Brent able to bring a partner in it will get a couple of wells carried that I think are or upside kind of to our picture, but we're very excited about theres been some tertiary discoveries and we've got some very nice looking prospects that we'll be able to get drilled.
As you move into later this year and into next year.
Great and then one for Steve have a housekeeping question.
Capex is in Threeq you forgot.
Yes, Gail I will remember the exact number but it's in.
I think it's in the 50 to 100 million range, it's probably a little bit less than that 50.
Matt Rand right around 50 million Gail.
Okay, great. Thank you.
Your next question is from the line of Bob Brackett with Bernstein Research.
Hey, Good morning had a question on the line fill process and Gulf Coast Express I understand we are undergoing line fill 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 a 30 year youre kind of we kind of look at it 30 to 60.
But we'll see.
Okay. So 30 to 60 days and would you plan to announce results immediately on TD or is that something you'd wait for a conference call to announce.
We just have to see so I mean, it's a there's a good there will be multiple targets and I'll just leave it will will kind of play that by ear.
And by multiple targets does that mean, you think you could hit perhaps Miocene and Cretaceous reservoirs with a single wellbore and 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.
Okay. Thank you good morning, everyone. Good morning, John .
Good morning, Doug joined I Wonder if I could take up to four if you. If you don't mind first of all on.
Alpine high in Midland.
Can you philosophically it sounds like.
You can read rationalizing.
A pivot towards the more oil part of the basin.
If that's the case can you touch on the inventory depth.
That you have in the Midland side and also the trajectory then for all time high with the objective then be could basically filled the cryo funds and hold it flat after launch or are we thinking about it.
Well I mean, I think what you're what we're going to have.
Q 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 where we hold a lot of the acreage.
It won't take a lot of drilling to hold the acreage that we view as very perspective.
Further refer really rich gas.
NGL and gas production and so we're at a point today, where we can let the economics and leverage our portfolio. So.
You know there is a couple of different scenarios I think the.
The cryo shows.
Recognizing that we own 79% of Altus.
And factoring that in as 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 weve been predominantly focused and we've run more rigs and we're running at a day in three areas in the Midland Basin.
Powell wildfire Azalea and in there we have drilled somewhere between 20 and 30% of the locations that we see there we're now adding more landing zones.
But you got to understand that Thats really only about 20% of our acreage footprint and you look at the other areas, we've gone out and drill.
Well some test wells.
Ben a dumb heart 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 to make sure. We got 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 kind of weigh that with the integrated economics in the price deck of how we look at.
The options in our portfolio.
Consider the cool onto a month my follow up is on multiples.
For the month.
I was wondering about to run some cost to get your sense of that so it seems to me that when we think about probability of geological success of the oxo on my model was basically units.
Some of the parameters, including liquidity, particularly hydrocarbon system obviously.
How do you guys think about the PG Reportability geological success on ongoing the wells that you're going to drill in response to calls can you confirm or could you maybe speak to.
Well it seems to me that Wouldnt make a lot of sense at this point to drill an offset local how model. So are you going to go and also or is that completely independent course, but I'll leave it there.
Thanks.
Well I mean first of all it is it is exploration so.
If I try to pin my guys down there and tell you you're no better than one one and four.
And that's just because its 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 boundary. So.
Clearly it that does two things it proves that there's hydrocarbons in the system.
When we look at the views across by kind of stitching together the two day in the Threed data you will find that the geologic setting is not changing much.
But you know weve its 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 a 100%.
With our interest.
John just to be clear.
Are any of the four wells potentially planned direct offsets time Laura.
We have multiple wells permitted Doug and.
Hi will.
Mothers I'll, just say, we'll we'll play them as we go and as we learn.
Awesome. Thanks for the thanks for the answers.
Your next question is from the line of Scott Hanold with RBC capital markets.
Yeah. Thanks.
I was curious.
Now that.
I guess, the cryo plant one is been up and running for bid than the number two is obviously.
Getting.
Some traction here do you have a sense that.
What.
In.
In north like Youve, your normalized kind of commodity prices like.
Where do you all think sort of the mix of.
Of that NGL basket would be in terms of product.
Yes. This is Dave Purcell.
Right now were these are.
The technology used in the Crows were removing almost a 100% of the ethane so as a result.
If you compare to an average NGL barrel this will be a little little more heavily weighted to to ethane and propane.
We're still.
We're still lining them out.
We would we would.
Anticipate as we move forward, we will get a richer gas stream come to the inlet of the cryo does and.
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. Okay, that's sort of the next Bachelor come on you'll get a better sense okay.
And then just to stay on one other thing there too Scott is going to change based on the formation we're into a lot of what we're flowing through there right now is.
There's going to be what version as you get into the bar to add so it's going to get a little heavier as well but.
So there's there's a lot of dynamics that will build dictate that going forward.
Right and that's all part of the capital allocation process for the future.
Alright, Okay, and so then if you look at.
What 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.
Being more competitive today.
Well I mean, where we started this year when we were kind of thinking 53 oil one to 80 gas and we have 75 cents on propane 30 cents on ethane.
We like the mix, where we have so we're obviously not there today.
With where the NGL sales have come down and gas specifically, so clearly thats going to be somewhere between where we were and where we are today.
Okay, well, that's a good benchmark give us a sense of where 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 which is with regards to Egypt you talked about this new discovery on about Korea 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 that could have to either capital investment or our growth in Egypt.
Well I mean, if you if you step back and look Egypt's got some of the highest returns in our portfolio. So.
It competes very very well.
You know, we're shooting a large area and the nice thing about Egypt is it's stacked pays but their conventional rock can so you can get a three or 4000 barrel a day IP from a vertical well is going to cost you $2 million to $3 million. So.
Stacks up very very nicely in the portfolio.
And I think with the new seismic yes.
If you look back over the last.
Two years, we really kept Egypt flat with two discoveries at P. tall, and Bernice 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 three but the three d. back we think our capital productivity.
Can improve as the quality of the prospects goes up and.
We love the leveraged Egypt.
I mean, I know you manage to cash flow and not to production mix, but as the.
Wet gas picks up then.
In in Alpine high thus there is there any interest in kind of offsetting that with greater investments in either Egypt, there were there or the north sea, both to improve cash flow and mix.
We will look as we as we talked about as I've talked about answering some of their request and 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 or Delaware basin.
But we will clearly.
Yes that will be factored into our capital.
He loved the Brent price Ics, we love the Brent price exposure in the cash flow.
On the international side.
Great. Thank you.
Your next question is from the line of David Deckelbaum with Cowen.
Good morning, John team, Thanks for taking my questions.
Yes.
Just wanted to follow up on that.
Some of the discussion around your sensitivities next year.
You commented on the NGL prices.
Hi on gas prices.
I guess with TCX coming online and the half a b 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.
Maybe 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 too.
Just kind of treated as something where you would just benefit from the marketing margin for the time being.
Well I mean, I think the thing you look at number one at Alpine high we're we like the asset its large resources we've proven.
Theres 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 were in a position where.
We can continue to high grade acreage.
And maintain that footprint and keep the Optionality I think as Gcs comes online we've been 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 as you know, we're such a short time away from seeing some increased cash flow. So it's an asset that we will look to leverage and.
You know and try to maximize yes, but the important thing is we have a portfolio and we only have limited capital we can put and so we have to balance that in regard with the with our other assets.
Got it thank you guys.
Oh, you were successful in the mid Con asset sale anything else. The Hopper. These days 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.
We're always looking to trim, if there's things, we're not going to invest in those 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 Arena, Joe Ron with Jpmorgan.
Yes, good morning, perhaps for Steve I was wondering Steve how you think your gas and NGL realizations, we will try and call it relative to benchmarks post the startup of TCX.
In the Permian or corporate wide.
Yes. This is this is Dave Purcell, Iran.
We once gcs starts up.
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 you're likely going to see the Permian basin.
Realizations track the in line with with the Gulf Coast benchmarks less transportation, Steve would you add anything to that.
The only thing I would add David is that.
There are some 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 impacts on pricing.
Both on the Gulf Coast and back to Wahab going back to the Permian basin as well.
Okay and my follow up is you guys.
And now it's kind of an agreement which is near.
On.
On an LNG type pricing structure.
I think it was in the beginning just wondered if you could maybe shed some light on that and talk about submit 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 structures. So first of all it is 140 million a day.
140 million cubic feet a day, so it's not a significant amount of.
Volume that we're producing in gas that thats price based on that.
But it was it's consistent with what we've always been talking about.
Around the alpine high in the Permian basin more generally.
And that is we want we want to get a diversified portfolio. If you will of.
Marketing based sources of realized price for the gas coming out of the Permian basin, 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 from realized prices at landing points.
Okay any any detail just on the mechanism is just trying to understand maybe the financial impact on that's 140 million a day.
The mechanism is that it's a relatively simple when we have flexibility as to where the product.
Goes in terms of pricing and it's a netback.
Based on tolling arrangements and shipping costs.
Okay, Okay fair enough. Thanks.
Your final question is from the line of Michael Hall, with Heikkinen Energy.
Thanks.
Good morning, good afternoon.
Yes, I was just curious what the base case assumption our thought process is on.
Extending the rig.
To drill the follow up wells in Suriname at this point.
Well you guys go ahead and.
And drill those three wells is that is that kind of the base thought.
Or is that dependent on whether or not you secure a JV partner in the area.
It's purely an option.
Michael and the.
All we've said is we're committed to one we have the option to.
To take the rig and drill three more.
And that the blocks going to be good going to need additional wells.
And if you were to extend that.
And take and go kind of heads up on that on your own.
Is that how would that kind of fall in.
In the pecking order in 2020 in terms of capital allocation given that it's.
Yes, it's not there is no clear, yes commodity.
Linkage yet.
Yes, so how do you I guess.
Ill, 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 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 we 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 will 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.