APA Corporation (APA) — Q3 2019 Earnings Call Transcript

Good morning and thank you for joining us. On today’s call, I will discuss Apache’s approach to delivering value in the current environment, provide high-level direction on our 2020 capital budget, and conclude with some comments on our third quarter performance and fourth quarter outlook. The market has come to view the lower oil and gas price environment that has been in place since 2014 as structural in nature and unlikely to improve for the foreseeable future. Compounding this, investors are frustrated with excessive capital investment by U.S. producers and the pursuit of growth which is common with the expense of both return on and return of capital. For these and other reasons, the broad energy sector is out of favor and there is very little investor interest in publicly traded E&P companies. In response, as an industry, we must generate more free cash flow and return it to investors on a more consistent basis while continuing to operate responsibly and increasing our focus on emissions reduction. In this regard, Apache’s primary objectives are simple and straightforward: deliver competitive risk-adjusted returns with a long-term moderate pace of growth, improve our free cash flow yield to a level consistent with mature industrial sectors, and progress our sustainability initiatives. As we have done for the last several years, Apache will budget using a conservative price outlook and flex our capital program in response to price volatility. We have taken a number of steps to adapt to the lower commodity price environment of the last five years. These include streamlining our portfolio, making substantial improvements to our capital allocation process, and significantly reducing our head costs. Apache has historically employed a decentralized regional focus approach to operations. In recent years, we have centralized certain key activities and today see an opportunity to capture greater efficiencies by taking further steps in that direction. To accomplish this, we have initiated a comprehensive redesign of our organizational structure and operations that will position us to be competitive for the long term. This process, which began in late summer, should be largely completed by the end of the first quarter. We are targeting at least $150 million of combined annual savings and look forward to updating you on our progress in the future. As we look ahead to 2020, our capital planning process is underway and we will disclose a final budget with our fourth quarter results in February. Based on current strip prices, we anticipate a 2020 upstream capital budget that would be 10% to 20% below this year’s program of $2.4 billion. This will enable Apache to generate organic free cash flow that covers the dividend and puts us on pace to fund a multiyear debt reduction program while also delivering modest year-over-year oil production growth. We anticipate directing the vast majority of our Permian capital in 2020 to more oil-weighted projects in the Midland and Delaware Basins. In Egypt, we have taken significant steps to build and enhance our drilling inventory and assess the potential for increased investment in the future. And in the North Sea, we intend to maintain a consistent level of activity year-over-year. Turning to Suriname, we have retained Nobel Sam Croft to drill the second and third wells on Block 58 in 2020, with options still outstanding on a fourth well. We are planning to drill these wells at 100%, but that might change should we choose to farm down our interest. As we progress through the 2020 planning process, we continue to monitor commodity fundamentals and evaluate multiple capital allocation scenarios under a number of different price outlooks across our diverse portfolio. We look forward to providing details on our outlook in February. Next, I will comment briefly on our third quarter performance and fourth quarter outlook before turning it over to Dave for more details. In the Permian Basin, our oil production in the second half of the year has been moderately impacted by some unplanned downtime events and delays in our completion schedule and well maintenance timing. Consequently, we are now projecting fourth quarter Permian oil volumes of approximately 100,000 barrels per day. At Alpine High, we have reduced our drilling activity to two rigs and have chosen to defer some fourth quarter completions into 2020. This lower activity set combined with a decrease in production outlook on one of our multi-well pads has resulted in an approximate 5% reduction in our fourth quarter Alpine High guidance. Internationally, third quarter production was in line with guidance and our outlook for the fourth quarter is unchanged. Egypt continues to deliver excellent well results and a high drilling success rate. In the North Sea, we have a significant exploratory success coming online this month and a second well at Garten coming online around year-end. The log on the Garten well shows a much larger than expected hydrocarbon column and should generate positive production momentum as we enter 2020. In Suriname, we spud the Maka Central number one in late September and expect to TD the well in November at a depth of approximately 6,325 meters as measured from the deck of the drillship. The well is designed to test multiple targets and is located roughly seven miles from the Suriname/Guyana maritime border. With the recent exercise of our option to drill a second and third well on Block 58, in conjunction with some optional future well commitments, Apache has the ability to retain the entirety of Block 58 with no relinquishment requirements until June of 2026. This provides sufficient time to execute a comprehensive exploratory program over this large block and initiate development activities as warranted. In closing, we are taking numerous decisive actions to improve our performance and positioning in this difficult macro environment. Apache has several key differentiators that enhance our investment proposition. Our diversified portfolio affords the flexibility to allocate capital across all three hydrocarbon streams and among conventional and unconventional assets as warranted by market conditions. We have a deep and diverse acreage position across the Permian Basin. Our international assets generate strong and stable free cash flow driven by premium pricing for oil, gas, and NGLs. The returns generated by these assets are highly competitive within our portfolio and tend to be less sensitive to downside commodity price volatility. Lastly, Apache has excellent organic exploration opportunities in each of its three key regions as well as a potentially transformational position offshore Suriname. With that, I will turn the call over to Dave Pursell, who will provide some operational details on the quarter.

Thanks, John, and good morning. Our strong operational results for the third quarter reflect the benefits of the diversified portfolio. Adjusted production of 391,000 barrels of oil equivalent is nearly flat with the previous quarter, which included approximately 25,000 barrels of oil equivalent per day from assets in the Mid-Continent region that we divested during the second quarter. We are advancing a number of exploration programs both internationally and in the U.S., and development activities continue at a steady pace in our legacy U.S., North Sea, and Egypt regions. During the third quarter, we drilled and completed 64 gross wells, 48 in the U.S., 14 in Egypt, and two in the North Sea. U.S. third quarter production totaled 266,000 barrels of oil equivalent per day. In the Midland Basin, we continue to drill high productivity oil wells. Our third quarter activity included an 11 well, 1.5-mile pad at Azalea located in Midland County. This pad produces from the Lower Spraberry shale, Wolf Camp A and B, and Lower Cline formation. The Lower Cline well tested in a new landing zone with favorable results, achieving an average 30-day IP of 1,270 barrels of oil equivalent per day at 72% oil. Plans are underway to drill future Lower Cline wells to further delineate the Cline potential across our Midland Basin acreage. In Reagan County, we drilled the five-well, 2-mile pad in the Hartgrove area, producing from the Wolfcamp B1 and B4 formations. The 30-day IP averaged 1,150 barrels of oil equivalent per day with 79% of oil, with D&C cost averaging a very efficient $7.2 million per well. In the Delaware Basin, we drilled five wells with 1-mile laterals at Dixieland at an average cost per well of less than $5.3 million. As we outlined last quarter, we are still feeling the effects of completion timing on our Permian oil production. We are on pace to put all 88 planned Midland and Northern Delaware Basin wells online, but many of them were pushed back throughout the year. We have 25 wells scheduled with online dates in November or December, which based on their timing, will add only minimal production to the fourth quarter. At Alpine High, we brought 15 wells online during the quarter. This included several wells from our 14-well Blackfoot Barnett pad in the Northern Flank. We have now drilled four large multi-well pads in this area, and this most recent Barnett pad has thus far underperformed relative to the adjacent Mont Blanc Barnett pad. All 14 Blackfoot wells were completed sequentially before commencing flowback operations. As a result, the significant volume of frac water was pumped into the small areas of the reservoir, which may have impacted well productivity. We took advantage of a shutting period to soak this pad for approximately 60 days. The wells have been returned to production at higher rates. Additional modeling is underway to better understand the performance of these wells. Moving to our international regions, adjusted production came in a little higher than projected at 125,000 barrels of oil equivalent per day. In Egypt, following up on the discovery announced last quarter in our new East Bahariya area, we have received the development lease and have drilled the second well, Cobra-2, which is producing approximately 3,000 barrels of oil per day. We are currently drilling a third well with plans for a fourth well later this year. In the Matruh Basin, the Biruni-1X well tested 5,000 barrels of oil per day from the AEB 6 reservoir, plus 6 million cubic feet of gas and 228 barrels of condensate per day from the Safa reservoir. We are currently drilling and offsetting future expansion potential. In the Shushan Basin, we had a recent exploration success at the Anti-1X which tested 47 million cubic feet and 1,700 barrels of condensate per day from the Shifa formation. Turning to the North Sea, third quarter production was impacted by annual turnaround maintenance, from which we expect a significant production rebound in the fourth quarter. We have had an extremely successful drilling campaign this year, having drilled 10 producers with no dry holes. Our latest North Sea success at the Garten-2, which encountered approximately 1,200 feet of net pay in the prolific Beryl reservoir across three fault blocks, compares favorably to Garten 1, which came online in November 2018 with a 30-day IP of 13,000 barrels of oil and 17 million cubic feet of gas per day from 700 feet of pay. The Garten-2 is expected to be online around year-end. Apache holds a 100% working interest in the Garten complex, which will have several follow-on wells. The first well at our Stone development is scheduled for initial production next month. This is a high-rate gas condensate well which we anticipate will initially produce over 30% oil. The well will be tied back to the existing infrastructure that connects to the Beryl alpha platform. We plan to drill a second production well later next year. More detailed drilling pad and well highlights can be seen in our third quarter financial and operational supplement. Thank you. And with that, I will now turn the call over to Steve.

Thank you, Dave. On today’s call, I will review third quarter financial results, provide a few updates to our 2019 guidance, and briefly share some thoughts on 2020. As noted in the press release issued last night under Generally Accepted Accounting Principles, Apache reported a third quarter 2019 consolidated net loss of $170 million or $0.45 per diluted common share. These results include a number of items that are outside of core earnings which were typically excluded by the investment community in their published earnings estimates. The most significant difference was a $53 million valuation allowance for deferred income tax benefits. Excluding this and other smaller items, adjusted earnings for the third quarter were a loss of $108 million or $0.29 per share. Production volumes were strong, but oil and NGL realizations weakened during the quarter. Gas prices increased a bit with some improvement at the Waha hub, but generally remained very low. All major expense items were in line with or below our guidance for the quarter, with the exception of DD&A, which rose to $17.30 per BOE. This was primarily due to reduced proved reserves at Alpine High associated with the recent deterioration in the NGL and natural gas prices. Both the GCX gas pipeline and the Shin Oak NGL pipeline were commissioned during the third quarter. With transport capacity on both of these pipelines, Apache now has access to attractive marketing margins over and above the pipeline tests. In terms of full-year 2019 guidance, we are increasing our annual DD&A to $15.25 per BOE for the impacts previously described. There are a few other smaller changes to full-year 2019 guidance, all of which can be found in our financial and operational supplement. As John indicated, we are deep into the planning process for 2020 and beyond. As in past years, we will take a conservative approach to pricing assumptions. We will plan for free cash flow over and above our normal dividend. At current strip pricing, this would indicate a 10% to 20% reduction in capital from 2019. Through the pricing cycle, we believe this approach can combine an attractive free cash flow yield with a moderate pace of production growth. For the next few years, most free cash flow will be used to reduce debt. Our debt maturity profile is now in good shape with just under $1 billion of debt maturing in the 2021 to 2023 timeframe. Our plan is to retire all of this debt as it comes due. As a reminder, for reporting purposes, Apache consolidates Altus' long-term debt. This debt is non-recourse to Apache and amounted to $235 million at the end of the third quarter. So, as we look forward to 2020, Apache is in a good situation, while the gas and NGL price environment will cause a slowdown at Alpine High. We have a well-diversified portfolio to allocate capital towards more oil-focused opportunities. We will continue to be long-term returns focused with an appropriate balance of free cash flow and moderate growth. And with that, I will turn the call over to the operator for Q&A.

John, I wonder if I could hit a couple of things first of all, at a high level, I understand you haven’t given guidance for 2020, but will you see modest growth, what does that mean?

We don’t see any modest growth at this point, Doug. We’re in the middle of the planning process, and the kind of pace we’ve been on would suggest modest growth.

Okay. I thought that would be a quick answer, but I appreciate you trying to at least answer the question. My second one is on Suriname, much and you’re not going to get low on this. But I wanted to ask a very specific issue around Suriname, you’ve said for some time Apache had a differentiated view of the block. My question is, you've never released the result of the Popokai well, but a couple of your engineers did talk about the Popokai changing your view on the thermal maturity of your block. So wonder if I could ask you to characterize, what are the type of targets you’re looking for and address specifically whether you believe this is our predominantly gas prone area that you’re testing? And any color around the spud specific issue would be really appreciated?

Well, the first thing I’ll say Doug is the team was very impressed with the work that we did from the data that’s out there. So, we thought you did a fantastic job on your report. We said that we have seven different play types on Block 58. The Maka-1 Central well is going to be targeting two of those play types. They’re in the Cretaceous. And I will just suggest that we obviously feel like we would be in an oil window or we wouldn't be placing a well there.

I appreciate that. Last one very quickly, I wonder if you could just address the recent management change and followed by price capabilities in Suriname, and I would note that I believe you saying the PSC before Mr. Kim joined Apache. So if you could just offer some clarification that would be great?

Actually, we picked this block up in 2015. Steve had been on board with us, but he was not working the conventional exploration stuff at that time. So, this is something that actually we did on my watch early in 2015, before any other results were down in Guyana or our wells. So, Steve did not have anything to do with us getting into Suriname or taking this block. Secondly, I want to thank Steve for his time here. He made great contributions to the organization and is truly a world-class explorer. As we disclosed on the call today, I have been thinking about a long-term vision for the company and working on some significant organizational changes. Steve's remaining tenure was shorter than the time I was planning for. So, that required he and I to have a conversation around succession. I proposed an appropriate transition and very simply he just elected to resign, but it had nothing to do with Suriname.

Hi, John. Regarding your initial comments on 2020, it seems that you mentioned we should expect capital allocation in the North Sea to remain flat year-over-year. Given the success you've had in Egypt, along with additional insights from the seismic shoot, I assume there will be increased investment there. It also appears that for the Permian/Alpine High, there will be a shift in capital towards some of the more oil-rich areas in Midland and Delaware. When I consider the overall region, historically it's been around a 70:30 split between U.S. and international. I'm curious about how much that might change, as it seems like only the international sector is trending upward.

Yes. I would say, John, first and foremost, we spent more money at Alpine High, and that capital is going to come down, so that in itself will change the percentages of the pie. The exploration spend in Suriname could be a little larger as well, so that also would tilt the international. But, we stated that the Permian capital is going to come down, but in general the oil drilling is going to go up.

And then just the follow-up until we’re given any additional information, can we just continue to assume for these additional, these other two Suriname wells around that $60 million to $65 million per well similar to the first?

Yes. I mean the spread shouldn’t change much. I mean we’ve got Nobel Sam Croft. Rates were negotiated and there is actually another extension we could take and have just preserved that option for the future. So, it's going to be pretty similar. A lot of that will just depend on what we do and how long we’re on the wells and how much testing, and all those things will drive that cost.

I wanted to see, just a follow-up on John’s question there. More of a bigger picture, if you could paint a picture of how Suriname success or lack of excess is going to impact your capital allocation strategy? So, in a successful case, would you finance development fully and entirely via selling down a stake? Would there be openness to outspending cash flow? Would you need to issue equity? Would you think about just reducing activity elsewhere in the portfolio? And in a lack of success case, what would be your interest for a need for inorganic portfolio replenishment?

Well, Brian, we feel good about the portfolio with or without Suriname. So I think we got a very diverse portfolio; we’ve got great optionality; we’ve got lots of onshore unconventional inventory that is all weighted, as well as some optionality on the rich gas side. We got good inventory both in our international areas, and then obviously Suriname offers a new playground for us. So, we feel good about the inventory and feel good about the direction of the company. I think that’s one thing. If you look back over the last four years from where we sit today, from where we were, we have a lot more inventory than we have on all fronts. So, as far as financing or success case at Suriname, we still have a 100% equity in that block, and we made a very clear that our intent would be to likely bring in a partner, and we feel like that would play a role in how that would be funded. So, I am not in a position to give you a lot more color than that, but I don’t see us having to stop some of the other things that we would be doing or significantly stress our balance sheet.

No, I think that’s good, John.

And then, the follow-up is with regard to the onshore inventory you mentioned, some improved performance or economics on the Cline. Can you just talk to what you’re seeing in terms of supply cost coming down either by cost reduction or improved performance in the Permian? And then any update on exploratory efforts in the onshore?

At this point, we do not have anything that we prepared to update on the onshore exploratory side. I will say in general, costs are a kind of mixed bag; some things are coming down and some of the services there have been some slowdowns. Some of it remains tight, so we’re managing that, and so it's really a function of the individual services. I think what you’re seeing now is having been in kind of a development mode with those pads. A lot of the synergies and things were driving out in the costs, it’s really more function just the efficiencies that come with larger scale pad development where you have all the infrastructure in place. I’ll put it over to Dave to comment on the Cline.

Yes. So, thanks, John. The Cline well, just a little more color than in the prepared remarks. It's one well that’s been online for 120 days. We’re happy with its performance. We look at our portfolio when we think we have opportunities under a couple of fields at least. And so, you’ll be hearing more about that as we kind of get to the end of 2020.

Good morning. I’m looking at that TVD of the Market Central at 6,325 meters, that's considerably, say, several thousand feet deeper than Haimara, which is maybe your closest offset well from the industry. Does that suggest you’re trying to tap the top of the Jurassic? Or is that landing somewhere in the Cretaceous?

I would just say at this point that most of our targets, the two plays we'll be testing here are in the Cretaceous.

A quick question then, what about the Miocene? You didn’t mention that as one of the play types?

At this point we’ve gone through a full evaluation of all of the play types, so Bob that’s where we are; this is two in the Cretaceous in a very nice stick section.

Yes, concurred. In terms of the modest oil production growth that you highlighted, should I stay specifically into focus on oil production growth or should gas be flat or down or just gas track with that oil?

We would be emphasizing the modest oil plays.

I would like to understand that while there is significant attention on this first well, I would appreciate it if you could provide more details about the two upcoming wells. Since you have the rig set to drill these consecutively, I assume you have already identified the locations for those wells and that they will be separate from the results of the first well. Could you clarify if my understanding is correct? Additionally, how do you expect the next two wells to progress?

Charles, we actually permitted nine different wells. So, there are multiple, multiple targets. I’ll just say since it is the first well in this area that we’ll be gathering data and there are some decision points that will drive the exact thoughts and process.

I would like to discuss the Blackfoot pad in the Alpine High. Dave, I appreciated your comments about it in your prepared remarks, but I was curious to hear you mention that you left the frac water soak on that pad for approximately 60 days. Can you explain if this has been a standard procedure at Alpine High? Is this something new or different that you chose to implement? Or was it just a matter of timing? Could you clarify whether this is part of a standard plan or a one-time occurrence, and what insights you expect to gain from this moving forward?

Yes, Charles, good question. We’ve had some opportunities in the past to soak wells, really due to facility constraints. So what we found in some cases is that well performance improves with a soak. When we frac the 14 well Blackfoot pad, remember that was, the wells were all completed sequentially. So, we put a lot of produced water into a relatively compact part of the reservoir. And we thought, well, let's take advantage of well commodity prices and initiate a 60-day soak. We were really trying to understand if it is a relative permeability issue, or what are the mechanisms for the underperformance? We’ve had the pad back online for about 30 days. The gas rate came back above the pretty soak rate and it's actually holding in pretty flat, which means there was some impact and the condensate rate came up higher than the pre-soak rate. So, what we’re doing is evaluating that. We have a team of folks doing some detail work on Blackfoot and all of the multi-well pads that we've drilled and completed to date.

I see that Egypt had strong results this quarter. When you look at 2020 cash and CapEx, do you have an updated estimate for what maintenance CapEx in Egypt would be to keep adjusted at 72,000 flat?

Gail, we’ve got results from the new 3D that we're starting to see from our prospect inventory that should improve, which is what we’re excited about. So, we don’t really look at rig count to maintain things flat because we’re just working on what projects are going to be best in terms of the allocation. But as we’ve said, with the new inventory and the things we’re seeing, I think there is potential to actually return Egypt on the oil side to grow, and so, we’re excited about that.

Looking at the recent exploration at G12 and the condensate discovery, how might that impact future gas development potential in Egypt?

Well, we’ve got a lot of infrastructure from Qasr. The nice thing about some things is they can be tied in. Most of our drilling will be focused on oil, but we do have a lot of gas infrastructure and capacity. So, it’s not a big deal, and if we find it, it’s still very economic for us as we get about $265 NIM for that.

Just wanted to see if there is anything you could say about what you've seen so far in the Maka Central wells at this point?

I’d say we’re drilling ahead, and Mike, the only thing I’ll say at this time is that we have not seen anything that would be unexpected.

And just wanted if you could give any more color on the organizational initiatives that you put in place?

Yes. I think we see an opportunity to reduce, kind of take $150 million out of the system. I think it's going to enable us to deliver more proactive planning and improve capital allocation, which is something we strived to continually do. I think it's going to enable us to advance our resource progression from access to exploration to development and operations. It's going to allow us to right-size both the corporate and regional offices to more efficiently support the new organization. We’re going to minimize duplication, eliminate some redundancies, and it also is going to help us really enable the collaboration on the value-adding technology adoption.

John, my question is based on the early strong Lower Cline test that you've seen in that Driver Schrock pad. Do you have plans to increase activity targeting this zone? Or I guess maybe I’ll ask a different way, could you all just discuss your upcoming multi-zone development pad around the Midland Basin?

Yes. I think we’ve got our inventory so lined out, but it doesn’t impact the next couple of pads. But what it does is we’re constantly dipping down and testing things that we can add in the future. And so, we can’t jump around the next pad and move here. I mean we’ve really got this machine lined out and we’re in an execution mode. But we factor that in, we’re testing things that we think can add material inventory and then we will start planning that into our future pads, which is the way I think about that and is where we approach things.

Just a couple of more on the Alpine High, John, could you talk a little bit about reserve write-downs that you took in the quarter related to the lower commodity pricing?

Yes. This is Dave Pursell. So, there will be more color at the end of the year in the K, and there may be some commentary in the Q, but what you see in any price revision was primarily on gas and NGLs in the Permian Basin. There were very modest performance revisions, so the price revisions were due to low basin gas and NGL prices, focusing primarily on the Permian Basin.

And Dave, do you expect any additional year-end write-downs in addition to what you referenced in the 3Q?

Yes, it's a good question. If you examine the pricing over the last four quarters, we are still seeing some benefits from the high prices in the fourth quarter of 2018. However, as we move forward and consider the future prices for the fourth quarter of 2019, we will no longer benefit from that high quarter in our averages. If the forward prices remain stable, we anticipate some additional price adjustments in the fourth quarter. It’s still difficult to quantify these changes accurately, but that's our current perspective.

That’s helpful. Thank you. And just my last question also related to Alpine High. Do you have any sort of minimum volume commitments with Altus that you have to maintain?

No, acreage dedication.

So circling back on the CapEx split between U.S. and international, just back of the envelope here, it appears that the 4Q shift will see the U.S.-international split move towards 65:35 based upon the updated annual guide for 2019. Is that broadly how we should think about the split in 2020, overall, would yield modest spending growth abroad, is that how we should think about it?

I mean what I would say, I hate that you just look at the one quarter, right, because things move around. But I would say in general, our CapEx is going to come down as we set. You’re going to see less gas drilling at Alpine High and you’re likely to see a pretty flat pace in the North Sea compared to where we are, and we actually have some exploration wells. So that number might come down a little bit. Egypt should be flat to slightly up, and our oil projects in the U.S. are going to be a little higher as well. So, we’ll give you more color in February when we come out with our final 2020 plans.

And then just on the UK given the production momentum heading into next year, what are you guys looking at in terms of production over the full course of 2020? Can you generate some growth from the UK next year?

Once again, we’ll hold off on the 2020 specifics until we come out with the plan, but we’re very excited about the program. They’ve done a tremendous job this year at Garten 2, absolutely exceeded our expectations. We’ve got an entire fault block there that looks just fantastic that we had upside at the Storr well. So, we’ve got some big things coming on, and it sets up as Dave said in his prepared remarks, it sets up some additional drilling at Garten in the future. So, the shape of the curve going into 2020 is going to have a lot of momentum for the North Sea.

Maybe a follow-up question on Alpine High and Altus in particular, I mean, given the reduction activity at Alpine High, I know you have MVC. But how do you think about the go-forward options at Altus longer-term in terms of future capital to spend on the G&P side, potential options to address the value and/or structure of the entity?

Ryan, I’ll ask you to hop on the Altus call this afternoon at 1 o'clock, and we'll let Clay and the team there handle all of those questions directly.

Maybe one follow-up on Egypt, I mean, you've mentioned the possibility to generate long-term growth as opposed to just holding volumes flat in the region. I mean, what would you need to see to move in that direction? Would you need to see continued exploration success? Have you seen enough already? And is there anything else that would dictate kind of how aggressive you would or could be there?

No, I mean, we've got very large positions, right; and we’ve got a very large base. I think the technology that we’re applying, the new acreage we picked up with the new 3D puts us in a position for some pretty interesting inventory. I think it's going to be more driven off the inventory and the opportunity set than anything.

Just wanted to follow up on some of the Egypt questions. I make sure I got some of your remarks correct. So, in your prepared remarks you've indicated that you’re building and enhancing drilling inventory there. And so, can you provide us with an update on what the current capital efficiency looks like because that might have changed over the past couple of years as you're spending below maintenance? And then, how productive the first call and incremental capital sounds like, because it seems like there could be some exploration? I know you said there is already some gas facility there, but not sure what’s there on the oil side in order for you to increase production?

Yes, Jeanine, I think if you look at Egypt, I don’t think we’ve been under-investing. So, that’s the first thing I’d say; I think we’ve been investing at an appropriate pace. We had a very large discovery in Qasr many years ago, which is pretty unique. If you take that out and look at the portfolio, we’ve been on a really good pace. You look at the Ptah and Berenice discoveries, we had in late 2014 early 2015; things have been going quite strong. So, we’ve got a big footprint. We’ve been there a long time. We spread out over a very large area. And my point on the other tie ends is, we just have a lot of capacity there for more gas yields. And so, I think things are going quite well and we do see the potential to improve our productivity with the new inventory.

And then just to follow up on Alpine High, in terms of giving away some Alpine High CapEx to other early plays. At what commodity prices do you think that Alpine High can beat your capital? And I guess what we’re thinking is just that, you’re takeaway contracts specifically for Alpine High for NGLs and crude, those are acreage dedications, so you have a ton of flexibility there. The gas takeaway I believe has that MVCs, but I’m pretty sure that you wouldn’t have an issue arbing those out. So, just trying to really figure out kind of what the push and pull is on CapEx allocation to that play?

I mean it's purely going to be based on a forward look at the incremental economics.

Thanks. A lot of been addressed, I guess maybe going back to Suriname. Now, you’ve got the Maka Well location out there. Is there any additional color you can provide as to why this was the first of the test of the nine wells you’ve permitted and any additional color on the thought process there?

Well, it’s located in a favorable area, and we really like the well. Some of the prospects there allow us to test two of them, which is why we decided to proceed with this one.

And were there any risks in the other wells that you were mitigating with the selection of this well?

With exploration, your first well in, it’s a process right. So, since it has the word exploration in it, there's always risks that you're assessing and you learn from. But this was the order of the first well we thought we should drill, and from there, we got numerous options to go. There are seven different play types; there are many, many significant good-looking prospects, so we just had to get started somewhere.

And then I guess just to come back on the Alpine High economics side of things, I think in the past you’ve talked about mid-$20s or 7 handle on propane as kind of the level to think about where Alpine High will compete for capital. Are those still fair levels to watch?

Michael, we’ll come back on that. I mean once again, we've got four pads that we’re evaluating, and it really is going to boil down to now that we have the infrastructure in place. It's more about the incremental economics relative to our other portfolio opportunities. So, thank you. In closing, Apache is taking significant steps to lower our cost structure and to further optimize our capital allocation. Our goal is to improve free cash flow yield inclusive of the dividend, increase returns, and continue our pace of modest oil growth. We have some very attractive exploration opportunities throughout the portfolio that make Apache a differential investment opportunity. Thank you and happy Halloween.