APA Corporation
Q3 2016 Earnings Call Transcript

Published: 3 Nov 2016

[Operator:]

Good afternoon. My name is Doris, and I will be your conference operator today. At this time, I would like to welcome everyone to the Apache Corporation third quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. Thank you. I will turn the conference over to our host, Mr. Gary Clark, Vice President of Investor Relations. Sir, please go ahead.

[Gary T. Clark:]

Good afternoon and thank you for joining us on Apache Corporation's third quarter 2016 financial and operational results conference call. Speakers making prepared remarks on today's call will be

[John J. Christmann:]

Good afternoon and thank you for joining us. Apache continues to make great progress on the goals we set at the beginning of the year, and our recent announcements and third quarter results underscore this positive performance. On today's call, I will discuss four primary topics. First, I will review the strategy we laid out at the beginning of 2015 to guide Apache through the downturn. I will outline how the execution of that strategy has positioned Apache for success in 2017 and beyond. Then, I will discuss our capital spending priorities as we look ahead to 2017. Following that, I will review our Permian, Egypt, and North Sea regions, and then conclude with a discussion of the Alpine High. At the start of the downturn, we established some guiding principles that have brought us to where we are today. These were

[Timothy J. Sullivan:]

Thank you, John, and good afternoon. My remarks today will be focused on providing more detail around results from our core areas, highlights from specific wells, and near-term development plans. Our Permian region produced 159,000 barrels of oil equivalent per day in the third quarter, or nearly 60% of Apache's total North American onshore production. Production in the Permian Basin decreased by roughly 6,200 BOE per day from the second quarter, as their declines were buffered primarily by 13 well tie-ins and our Northwest Shelf Yeso play. In our new Delaware Basin discovery, the Alpine High, we're showing results from 10 wells, comprising eight Woodford, one Barnett, and one Third Bone Springs wells. On page 15 of the operations supplement, we have updated our production curves from the wells we showed at Barclays and have included the two most recent wells. As you can see, our Alpine High wells compare favorably with the P-50 type curves for the Marcellus, Utica, and SCOOP resource plays, with half the wells producing at or above the P-50 type curves. Keep in mind, the Alpine High wells are short laterals and have not been normalized for lateral length. Also, the completions and landing zones have not been optimized. These initial wells were drilled as appraisal wells and test-of-concept and were oftentimes drilled near hazards so that we can better understand the boundaries of the play. Given this, we are excited about the early time performance. We are shutting wells in as we complete testing and we'll collect pressure buildup data. These wells will be brought back online when we begin selling gas in 2017. The two new Alpine High wells John previously mentioned are both producing from the Woodford formation. The Black Hawk State 1H, which was drilled in a normally pressured setting, has the highest oil cut in the Woodford among the wells we have drilled to date. The Redwood 1H is the deepest well we have drilled and is our highest gas producer. We have also updated production from the Bone Springs producer Mont Blanc 2H, which can be seen on page 17 of the operations supplement. The well, which was a non-optimized completion with a short lateral, has a cumulative production of greater than 40,000 barrels of oil equivalent over 100 days and is currently producing 220 barrels of oil and 580 MCF per day with a stable GOR. Also, you can see that the water production has decreased to approximately 275 barrels per day. The wells drilled to date have confirmed the unprecedented picture of the vertical dimensions of the play of the Bone Springs to the Woodford across our acreage position, with the hydrocarbon column ranging from oil to wet gas to dry gas confirming our geologic model. We have seen a range of initial oil cuts in the Woodford from zero to 20%. The shallower Barnett well has an oil cut of 21%. These yields are in line with our thermal maturity model and can be correlated to depth. The gas is extremely rich, with an average BTU of approximately 1,300. This should provide for an average NGL yield in excess of 100 barrels per million cubic feet of natural gas when permanent facilities are in place. As expected in a resource play, Alpine High is becoming more predictable. Every well we've drilled has confirmed our model. In the Pecos Bend area in the Delaware Basin, we placed seven gross operated wells on production, all of which targeted the Third Bone Springs formation. We continue to see excellent production performance across this play. Our Blue Jay Unit 103H well continues its strong performance. Using 3-D seismic, we targeted a highly fractured area. The well has produced 427,000 barrels of oil equivalent in just under seven months, achieving an average rate of roughly 2,260 barrels of oil equivalent per day. This well is currently producing approximately 1,500 barrels of oil equivalent per day, of which 60% is oil. In a less fractured area of the play, we are also able to drill economic wells by utilizing pad drilling operations. On our Falcon State lease, a 6-well pad came online in mid-September, with an average 30-day rate of 625 barrels of oil equivalent per day. This pad also demonstrated our best-in-class operational efficiencies in this basin, with an average total well cost of $3.5 million per well. In the Midland Basin, Central Basin Platform, and Northwest Shelf, we placed a combined 16 gross operated wells on production in the quarter. We ran two rigs in the third quarter, primarily in the Midland Basin, and intend to ramp up to five rigs by the end of the year. Activity is focused on stratigraphic landing zone targeting and development pad drilling in the Wolfcamp and Spraberry shale formations and our Wildfire, Azalea, and Powell focus areas. We also expect to bring 20 horizontal wells online over the next two quarters across these three areas. As we stated on our last quarter call, in the third quarter we brought online the CC 4144 East 2HM, producing from the Wolfcamp B formation at Powell. This well continues to show strong performance and has produced 136,000 barrels of oil equivalent in the first 90 days online, at an average of more than 1,500 barrels of oil equivalent per day. This well along with our Connell 38B 2HM and 38C 2HM wells were drilled with our improved targeting and completion design, which we highlighted last quarter. Please refer to page 18 in our operations supplement for a production update of our Midland Basin focus area. Subsequent to quarter end, we brought online the Lynch A 6HM, a Wolfcamp B producer in our Wildfire area in Midland County. This 8,500-foot lateral was completed with 146 frac stages at approximately 60-foot frac spacing, pumping 1,700 pounds per foot of sand. The well is still cleaning up and has not reached peak production but is flowing at a rate of 1,120 barrels of oil and 1.1 million cubic feet of gas per day. In addition to this well, we will be testing one Middle Spraberry and three Lower Spraberry wells in our Wildfire focus area later this month. Much of our previous strategic testing in the Wolfcamp and Spraberry involved completions and landing zone optimization. The improvements we are making, as demonstrated by these wells, will significantly enhance our Midland Basin program going forward. In the Northwest Shelf, we placed nine horizontal Yeso wells in production during the quarter and continue to generate very good production rates and economics from this play. The 30-day rate for these nine wells averaged almost 450 barrels of oil equivalent per day. With our best-in-class drilling and completion cost for these wells, we averaged less than $2.5 million per well. This program generates extremely favorable economics on a fully burdened basin. In addition to the nine horizontal Yeso wells, we also placed four vertical Yeso wells on production during the quarter. Outside of the Permian, Apache had no active drilling rigs operating in North America during the quarter. We did, however, test seven operated wells, all in Canada, in our Annie Creek, Montney, and Wapiti Montney focus areas. Most notably is our 9-of-23 well, completed in the Lower Montney in our Wapiti area. This well tested at an impressive initial rate of 10.6 million cubic feet of gas per day and approximately 2,000 barrels of condensate per day, with a total estimated completed well cost of $6.2 million. We are making great progress in North America, even at our low level of reinvestment. We remain focused on returns and are positioning the Permian Basin for a growth trajectory in the second half of 2017. Moving to international and offshore operations, in Egypt, gross production of 350,000 barrels of oil equivalent per day was up slightly compared to the second quarter. On a net basis, adjusted volumes declined sequentially by 3,000 BOE per day, primarily due to the impact of improving Brent oil prices on cost recovery mechanisms and our production sharing contracts. We continue to benefit from a robust, optimized drilling program, drilling 45 producers and only five dry holes, achieving a 90% success rate through the first three quarters of 2016. Apache placed nine wells on production in Egypt during the third quarter. Most notably is the Ptah #12, producing from the Shiffah formation, with a current peak oil production of over 2,800 barrels of oil per day. Since field discovery in November 2014, the Ptah and Berenice fields have produced a combined 17 million barrels of oil equivalent from only 14 wells and are still producing at a rate of more than 38,000 barrels of oil equivalent per day. Well costs for this play averaged only $3.2 million per well. In the North Sea, third quarter production decreased approximately 8,300 BOE per day due to downtime resulting from planned maintenance turnarounds and third-party operated facility restrictions that impacted production. This was associated with seasonal turnarounds that occur in this region during the late summer. This deferred some 3Q production into the current period, so we expect 4Q volumes to bounce back to levels we've seen in the first half the year. As John mentioned, we also made a nice discovery at our Storr prospect in the Beryl area, which encountered hydrocarbons in two separate fault blocks. The results were in line with pre-drill estimates, and we expect to test more fault blocks at Storr in the future. Apache has a 55% working interest, with Shell holding the remaining 45%. In late October, we commenced drilling our next Beryl area prospect, Kinord, which we expect to reach TD by year-end. Please refer to our November 2015 North Sea investor update for more details on Storr, Kinord, and other opportunities in the Beryl area. I would note a new high-rate development well at the Beryl field, the Nevis North NNA, which came online mid-September. The 30-day average rate for this well was 20 million cubic feet of natural gas equivalent per day. At our Aviat project in the Forties field, we have now completed and tied in the first well. As you may recall, Aviat enables a switch from diesel to natural gas as our primary source of power for the Forties field. This is an environmentally friendly project that will extend the economic life of Forties due to lower operating costs and reduce certain safety and reliability risk associated with bunkering diesel to our platforms. We estimate our annual diesel savings due to this project at $15 million per year. Importantly, using natural gas to fuel the Forties field should enable us to maintain higher and more stable water injection rates, which should in turn result in higher sustained hydrocarbon production from the field. In Suriname, we completed our 3-D seismic shoot on Block 58 in September, and we will have preliminary processing results by year-end and a fully processed data set in the third quarter of 2017. On the adjacent Block 53, we will commence drilling operations on a commitment well in the first quarter of next year, the Kolibri #1. While this is an attractive and sizable exploration prospect, very few wells have been drilled to this depth offshore Suriname, and as such, carries a significant amount of risk. The dry hole cost to Apache for this well is estimated at less than $40 million. To sum up international and offshore, while activity was limited, we had very good exploration and development results in both Egypt and the North Sea during the third quarter. We're excited about the future exploration potential in our international and offshore portfolio and look forward to providing more details in the future. I would now like to turn the call over to Steve.

[Stephen J. Riney:]

Thank you, Tim, and good afternoon, everyone. On today's call, I will discuss the following. First, I will review our financial results for the third quarter and provide updated 2016 guidance on selected items. Next, I will provide a few details on our near-term Alpine High infrastructure development activities, which have the primary purpose of achieving first gas sales around mid-2017. Then I will conclude by outlining the framework that we intend to follow as we put together our 2017 capital budget. Before I dive into our (28

[John J. Christmann:]

Thank you, Steve. Before taking questions, I wanted to make a few closing comments. Apache used the industry downturn to drive substantial change and improvement. We drastically reduced our cost structure, implemented a rigorous and integrated capital allocation and planning process, upgraded and expanded our drilling inventory, improved our capital efficiency, and positioned ourselves extremely well for the future. We invested a high percentage of our precious capital in strategic testing and captured the Alpine High play. This significant new discovery reflects not only the company's strategic focus on organic growth, but also highlights the strong technical capabilities that were necessary to discover and secure it. In 2017, we will continue to manage oil and gas price volatility by setting a reasonable expected price band and gearing our capital spending, return targets, and capital structure to the lower end of that band. Should realized prices come in higher, we will maintain the operational and financial flexibility and optionality to respond accordingly, as we have done in 2016. Our overall strategic approach will remain unchanged. Apache will live within its means, maintain its strong financial position, continue to build and develop our high-quality drilling inventory, and invest our capital with a primary focus on improving long-term returns and creating shareholder value. And with that, I'll turn the call over to the operator to begin the Q&A.

[Operator:]

Our first question is from the line of Ed Westlake with Credit Suisse. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Congratulations again on Alpine High. Just on the gas line first, I mean a 30-inch line. Maybe give us some idea of how much capacity that would have because obviously that's probably going to be the governor on the size of the play in the beginning.

[John J. Christmann:]

Ed, at this point I don't want to talk about capacity. I think a 30-inch line will tell you that it will move a tremendous amount of gas. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) That's what I thought.

[John J. Christmann:]

So I just want to leave it at that, because obviously with compression and so forth, you can do a lot there. But we're not in the position to talk about scale. That's just the main trunk line through the field and in terms of what we have to run from north to south. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Okay. And then slide 17 caused some debate today. Bone Spring well, obviously great initial rate, and then a decline down to 220 barrels a day. Maybe talk a little bit about the proppant loading, the landings and optimization, because in delineation you're not doing a lot of that. So maybe talk about the hopes you have to improve that performance over time. Obviously this is a short lateral as well.

[John J. Christmann:]

I think the first thing is, and Tim Sullivan did a good job in the script of walking through this. What we've got is a hydrocarbon system that has 5,000 feet of stack pay. And so what the purpose of that well really to do was, was to prove that we have oil production at a depth of around 9,000 feet, which confirms our geologic model and our thermal maturity model. So quite frankly, we're very pleased with that well. It's a very short lateral. It's a small frac. It was more designed to test the geologic model and the maturity model. And quite frankly, what's impressive about it is the GOR has been stable and is relatively flat, and you've seen the water lines come down. So we're quite pleased with it. As we've said all along, we have not tried to drill big press release wells that are going to blow everybody away with their production rates. This was a well that was designed to confirm we have oil production. We have a very rich column all the way from 9,000 feet down to 14,000 feet, which the Redwood confirmed when we move from oil down to wet gas down to dry gas. And the beauty of it is, unlike other plays where you have a 200-foot zone that you're trying to track aerially across windows, we've got such a thick column here and we have the maturity all the way up the column. So all we have to do is move our pole and we will have more oil and so forth. So as we get into further test points and start to delineate and start to drill some other wells, we'll bring on some other things. But the important point here is it validates there is oil production at 9,100 feet and 43 gravity API, and I think it's something we're very excited about.

[Operator:]

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

[Arun Jayaram:]

Good afternoon. John, I was wondering if you could maybe just compare and maybe contrast the opportunity set for oil in the Woodford and Barnett. I think you talked about in the prepared remarks thinking about maybe a 20% oil cut in the Barnett, zero to 20% in the Woodford. And then maybe also talk about how things could play out for the Bone Spring and Wolfcamp.

[John J. Christmann:]

Arun, as I just mentioned, we've got a model that is confirmed and has been validated. And really, the oil cut is going to be a function of thermal maturity and the depth of burial. And so as you move up, the only Barnett well we've drilled has a 20% cut. Below that, in the deeper Woodford wells we've drilled, we've anywhere from zero up to 21%. So the point in this whole thing is that we've got multiple zones across a window, a hydrocarbon system that we know has hydrocarbons ranging from oil from 9,000 feet and probably shallower – I mean, we've got some other indications it could go shallower – down to 14,000 feet. So those cuts are going to be a function of which rock we place in those depths. And quite frankly, the transgressive sequence from the Woodford up through the Penn, it really doesn't matter what age it was laid down. It's more a function of where it is in the maturity model. And so as we move up, we will see higher oil cuts, and we're confident in that. And we've got wells that we're drilling that we'll be bringing forth in the future that will design those. You can look at the oil cut in the Mont Blanc 2H, and it's very good at 9,100 feet. So I've tried to articulate what you've got is a hydrocarbon system, okay, which is unique because we've got five stack pays, different types of rocks. And as you move up, the cuts are all going to be a function of depth and temperature. And that's the good thing about it is everything's been validated and we can predict it, and everything's coming in at or better than our model would suggest.

[Arun Jayaram:]

That's helpful. And just switching gears a little bit, Steve, I was wondering if you could just comment. In Egypt, they did free float their currency, and there has been a pretty significant devaluation versus the dollar. Can you talk about the impact to Apache in terms of the devaluation?

[Stephen J. Riney:]

Yeah, so the direct financial impact is pretty minimal, actually, Arun. By contract, all of our revenues come in U.S. dollars, both on the gas and on the oil side. Oil, we actually export, sell in the open market, and get U.S. dollars into U.S. bank accounts. On the cost side, we do have some costs that are based in Egyptian pounds, which means that we're a net Egyptian pound buyer. On a quarterly basis, we buy about $100 million worth of Egyptian pounds. And we buy them obviously at a rate at which we would consume them. So the logical conclusion would be that the devaluation would benefit us on the cost side. But actually, we would anticipate that inflation would mostly offset that over time. And then, just as a general rule, on a day-to-day basis, we generally hold a pretty minimal amount of Egyptian pounds at any one point in time. And just as an example, at September 30 we had a little over $50,000 worth of Egyptian pounds on hand. So the actual exposure to the Egyptian pound in a direct financial basis is pretty minimal. Of course, the more macro issue is that Egypt is going through a very difficult time. They're doing all of the right things, but it's going to be very difficult, and it's going to be tough on the economy, and we obviously keep a very close eye on that.

[Operator:]

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

[Brian Singer:]

Thank you. Good afternoon. I wanted to follow up on a couple of the earlier questions. First with regards to the midstream and Alpine High, if you can't give us the specifics on the capacity on the gas front that you're trying to expand to at least initially, can you just talk to the CapEx strategy and what we should expect that midstream spending to look like for at least the shorter term, kind of next year, year and a half type piece?

[John J. Christmann:]

Brian, when we come out in February with our year-end call and give a look on 2017, we'll give some specific color. Obviously, this year, we've ramped up to $500 million in the Alpine High play, and we said 40% of that would be towards the midstream. I'll say directionally, you'll probably see numbers go up next year in Alpine, but I'm not in a position to give you a whole lot more color than that. I mean, the good news is we can fund it, and we're on a pace to bring on really this first big phase that will carry us through what ultimately would be a bigger build-out in subsequent years. So it'll be done incrementally and in a way that we can handle it.

[Stephen J. Riney:]

Yeah, I would also say – so let's start with the 30-inch trunk line. That is a trunk line through the field, but we have three directions in which we can connect to markets. And eventually I would hope and assume that we would be connected in all three directions, and therefore the trunk line can flow in different directions. And obviously therefore, it's not – the amount of gas that the field can produce is not limited by a unilateral flow of gas through the trunk line. It can flow in different directions. And then there will be a third connection most likely to the east from the middle of the field over to Waha. So the capacity of the field to produce and transport gas out is not actually limited by one-direction flow of a 30-inch line with compression. I think you could probably get a pretty good estimate of what the capital costs are going to be over the next few years. We're going to put in all the pipes and the connects over the next two years, 2017-2018. We're actually going to begin construction on the trunk line before the end of this year. So we'll have trunk line connections, hopefully north-south into Waha, and an NGL line, most likely into the Waha direction as well, by the end of 2018. And I think industry estimates probably work to figure out the cost of that. A 60-mile trunk line less than 10 miles to the north and south, and then just less than 50 miles over to Waha. On the processing side, we're going to be – you can put in refrigeration units in the 50 million to 100 million cubic feet per day increments. That works economically. And for both processing and compression, an industry cost estimate of somewhere in the $0.40 to $0.60 per cubic feet per day in terms of capital spending is probably a reasonable estimate. So whatever you're assuming in terms of our development profile and production profile, you can pretty much match a field processing and compression profile with that and get a decent estimate of the capital spending. We do anticipate that we will put in processing and compression capacity in advance of us needing it, so we won't be takeaway constrained – processing or takeaway constrained. We'll be well deliverability constrained.

[Brian Singer:]

Great, thank you. And the follow-up is I had a couple small questions on the international front. One, in your prepared comments, you referenced I think a reserve reservoir performance issue in Canada. I just wondered if there's a little bit more color there. And then on the back of Arun's question on Egypt devaluation, do you have confidence that for domestic consumers of oil and gas that the prices will be – the currency devaluation will be passed along?

[John J. Christmann:]

A couple things, Brian. I didn't see anything on a reserve impact in Canada. I'm looking at Steve...

[Stephen J. Riney:]

It was the impairment.

[John J. Christmann:]

It was the impairment.

[Stephen J. Riney:]

So we had an impairment in Canada, and it was due to reserves related to both well performance but also to net-back realizations and the impact on PUDs that were booked at that point in time. So we took a reserve write-down in Canada, and the $355 million pre-tax impairment was related to the reserves.

[John J. Christmann:]

In regards to Egypt, Brian, having just gotten back from there the week before last, and my third trip over there, I've actually seen President Al-Sisi twice this year. I've got to give them a lot of credit. They're on the right path. They're doing the right things. They're in the process of securing a loan from the IMF. This is all part of a process to go through and start to take some of the subsidies out and do the things to put the country onto the right track. So I actually feel very good about where things are. Our relationship is good. I think they understand how important Apache is. So we feel very good about that aspect of it. They've just got to go through a reset. And the good news is they're taking this head on and they're working on doing that. So we feel good about our overall situation though.

[Operator:]

Our next question is from the line of John Herrlin with Société Générale.

[John P. Herrlin:]

Close enough, guys. Anyway, you're not willing to quite say what you think everything can do with the Alpine High when it's installed and you don't want to front 2017 expenditures. But looking out and saying longer term, what do you think a normalized volume growth model would be for Apache once you're further along versus an also fiscally conservative approach where you're not diluting people, where you're living within your means?

[John J. Christmann:]

Obviously, John, you can look at the math, and things change significantly for us starting in the back half of 2017. What I'll say is when we look at the volumes coming out of Alpine High, we're not talking hundreds of millions of cubic feet of gas a day, you're probably talking billions a day with a lot of oil and liquids associated with it. So our profiles are going to change dramatically. I think when we come out in 2017, we'll talk a little bit about 2017, and most of that is going to occur in the back half of 2017. So we'll start to give some color, but it's going to be a different profile then we've probably had in our history.

[John P. Herrlin:]

Okay, that's fair. Regarding the Midland, a lot of companies now are going out 10,000 feet and beyond. Is that something in your wheelhouse too that you're considering doing?

[John J. Christmann:]

Yes. The big controlling factor there, obviously, is the land ownership. We showed a well in the ops report today that's about 8,500 feet. So clearly where we have the land to do that, your limitation isn't the rock in terms of how far you can drill. So we'll be drilling as long laterals as we can and optimizing those on pads.

[Timothy J. Sullivan:]

Brian, one comment I might make as well on that is we spent a good portion – or a good amount of work this year on blocking up our acreage at three of our fields at Powell, Wildfire, and Azalea. And as a result, we feel like about 2/3 of our locations now will be extended laterals between the mile and a half to two mile.

[Operator:]

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

[Bob Alan Brackett:]

I had a question on – I hear you saying that you want to live within cash flow to grow this program. Would you consider asset sales as another source of funds to maybe accelerate this program, and are there parts of the portfolio that would be ripe for that?

[John J. Christmann:]

Bob, the thing I would say is the good news is our pace for the development of Alpine is going to be governed at the start based on the build-out of the infrastructure and just the amount of time it takes to collect the data and do this properly in a way that's going to maximize the NPV and the returns. So it's not a matter of needing more capital to try to accelerate Alpine, the Alpine High play. It's going to get its capital at that pace. And then amazingly, it becomes cash flow positive pretty fast and self-funding. I think the bigger question will be as we look at the portfolio, Steve mentioned in his comments, we've got a lot of things we can defer as we have really the last two years. As we shut down, we're doing strategic testing and stuff. Most of our acreage is HBP. We've got a lot of really other attractive plays, and a lot of that will depend on what capital budget we want to run and what price deck we're comfortable spending at in terms of how we feather those in and that sort of thing. If there clearly are things at higher prices that we don't envision ourselves getting to, then obviously we would be looking at some of those options over the next couple years. So those are all things that would be on the table.

[Bob Alan Brackett:]

Thanks, and a quick follow-up. Can you talk about the process by which you got board sanction for this big 30-inch pipe big infrastructure investment? Did you present them with a 20-year project asset level, and what was that process like?

[John J. Christmann:]

What I would say is they had the scope and scale of the Alpine High. We're in a process where they have seen numbers going into 2017 and have sanctioned those. And the cost of this for what we've got identified looks fantastic, but it is a board-level approval and has been approved by our Board of Directors under our normal course of business.

[Operator:]

And our last question is from the line of David Tameron with Wells Fargo.

[David R. Tameron:]

Thanks for squeezing me in. John, if I think about – I know you said you won't comment on 2017, but I'm going to try to ask anyway. If I just think about your regional CapEx mix that was in your slide deck this morning on page 26, you have 50% – Permian and Alpine High get 50%, and then 50% other are outside of U.S. onshore. Is that the right way to think about it as far as a 2017 number, just based on obviously whatever the cash flow and prices end up being? But is that the right allocation?

[John J. Christmann:]

What I would say is Alpine is going to get its capital. We're going to invest to sustain North Sea and Egypt. Permian is going to get a big chunk of its capital. And then how that pie changes is going to be a function of what price deck we're comfortable running with and how much capital we pour. So we've seen a lot of volatility. We've gone from the low $50s to the mid-$40s. And so obviously every $5 of oil price and the movement of gas price means a lot to us in terms of that. So as we start out 2017, a lot of that's just going to hinge on what price we've got we feel comfortable using. The good news is we made a lot of progress over the last 18 months, not just on our Alpine and just on our Permian. We've got a lot of really strong projects that are very competitive. We've got a nice SCOOP position in the Woodford with 52,000 net and 200,000 gross acres out there, a nice little position in the STACK. You've seen some of the results from some of the Montney and the Duvernay today. So we've got a lot of other quality projects that we're fortunate that we can defer a few of those. But it's all going to hinge on ultimately where we shake down on the capital plan going into 2017 is going to be where will we'll start. And of course, the main thing is we're going to maintain the flexibility like we did this year by budgeting a little bit conservatively to then react and ramp up because we've got a lot of optionality and a lot of opportunity in our portfolio both within the Permian and the other parts of the portfolio.

[David R. Tameron:]

Okay, let me jump real quick to Suriname. Can you just give me your latest and greatest thoughts as far as – I know Hess made some noise about Liza a few weeks back. But can you just give me some color around that?

[John J. Christmann:]

What I'll say is, number one, we completed our 3D shoot on Block 58, so we'll be looking at that. We'll get that seismic in full evaluation sometime next year. So we're excited about Block 58. It's right in the kitchen. We own it 100%. Block 53 we're partners in. we've got 45% of that. We have a commitment well that we're going to spud first quarter, the Kolibri #1. We're very excited about it. It's a very, very strong prospect. There are some follow-on prospects. And quite frankly, it's an exploration well, but it needs to be drilled, and we're very excited about it. But it's exploration, and it will be first quarter of 2017.

[Operator:]

That's all the time for questions we have for today. I would like to turn the call back over to Mr. Clark for any closing remarks.

[Gary T. Clark:]

Thank you all for joining us today. There were a number of you left in the queue, so if we didn't get to your question, please feel free to reach out to the IR team as always. Thanks.

[Operator:]

Ladies and gentlemen, that does conclude today's conference call. You may now disconnect.