Good morning, and welcome to the Q1 2020 Earnings Call for ConocoPhillips. My name is Anera and I'll be the operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Ms. Ellen DeSanctis. Ellen, you may begin.

Thanks, Anera and good morning to our listeners. Thank you for joining us today to discuss this morning's press release which contained our first quarter earnings results, our dividend declaration announcement and an update on our curtailment actions. Our speakers today will be Ryan Lance, our Chairman and CEO; our Chief Operating Officer, Matt Fox; and our Chief Financial Officer, Don Wallette. Ryan will make some very short opening comments, but we'll reserve most of the time on today's call for the question-and-answer session. We don't have any slides this morning but we will post a replay of this call shortly. We don’t have any slides this morning, but we will post a replay of this call shortly. As you know given market volatility, we have temporarily suspended guidance. However we may make some forward-looking statements in today's call. Please refer to our SEC filings for a description of the risks and uncertainties that could impact future performance. And now I'll turn the call over to Ryan.

Thank you, Ellen and welcome to today's call. Well, here we are at the start of first quarter earnings for the E&P sector and it's a brave new world for all of us. Ordinarily, we would use this call to discuss our recent quarter results in detail and provide guidance for future periods, but the first quarter already feels like a long time ago. And as you know, due to significant uncertainty and volatility in the markets, we will temporarily suspend guidance. So here we are. But while we won't provide guidance, we continue to believe, it's important for ConocoPhillips to provide insights. How are we thinking about this environment? What actions are we taking or considering taking to respond? And that's how we'll intend to use this conference call time today. I'll make some very brief remarks then turn the call over to our listeners for a question-and-answer session. There are three themes I want to emphasize in these remarks. First, our underlying business is running very well. You saw our first quarter results in this morning's press release. It was quite a strong quarter operationally despite the COVID-19 pandemic. I'm certainly very proud of our organization. While some activities are changing day-to-day, I assure you that our workforce is all in on safely delivering the business, including our upcoming seasonal turnarounds and our ongoing capital activity. The second theme I want to emphasize in these prepared remarks won't surprise anybody. It's this. The next few months are going to be very bumpy for the industry and for us. A couple of weeks ago we announced plans to begin voluntary curtailments in May. This morning we announced that we expect to curtail about 265,000 barrels per day gross in May from our Lower 48 and Surmont combined. We'll --…

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Doug Terreson from Evercore ISI. Please go ahead. Your line is open.

Hi everybody.

Hi, good afternoon.

Good morning, Doug.

So Ryan your production curtailment seem to have been more market responsive than peers which may have to do with your higher proportion of operated production your working interests or your -- or other factors. So, my question is, are these the primary drivers of your curtailment decisions? Are there other control or economic factors that play into it? And then also what are the risks to recoverability for your portfolio after output starts to be restored if you think that they're meaningful?

Yes. Thanks Doug. I can probably take the first one. And Matt maybe you could provide a little bit of color on the second part of that. Honestly, Doug we'd be curtailing as much as we could right now. And I think we just don't think it's right to be accepting these kinds of netback prices for the product that we're producing. We've got a very strong balance sheet as I said in my remarks. We're taking a modeling sort of the short and the longer-term scenarios to guide our decisions, and these curtailment decisions are guided by the way we see the market playing out over the short term. We certainly have more control over things that we operate. We expect things to be coming from governments and infrastructure curtailments, but these are the things we can proactively go to do based on our recent view of the market, and based on our capacity that we've got on the balance sheet to do these kinds of things. In our view, we see this as a sign of strength, and we're deploying that, and I think acting in a recent fashion. So I'd let Matt maybe talk a little bit about the – what recovery would look like on the back end of these curtailments with improved markets.

Yeah. Doug, I think there's two aspects to the – to that answer. One is, how quickly can we bring production back? And are we taking any risks associated with the curtailment reservoir then which are other lines. And basically, we can bring the production back across North Slope Canada, Alaska within a few weeks. It doesn't take months to bring it back so the majority of it can be bought – brought back very quickly. And but to get to full production in a matter of weeks, we are making sure that we're not doing anything that's going to take any risk either from a reservoir or wells or facilities perspective. That's why we're – in Surmont, we're going down to a minimum rate so that we can still provide enough heat and temperature to the steam chambers to keep them intact. In Lower 48, we've got a very specific set of protocols in as to how we shut down and prepare those wells for restart. In Alaska, we're not shutting in completely. We're getting down to a rate plus, there's the – a minimum sort of operating level that we can consistently operate at for a period of time. Across all of these, there's no risk of reservoir damage there. So we can come back in a couple of weeks and there's no risk of any permanent damage.

Okay. Thanks. And then also Ryan, there's been a lot of commentary surrounding prorationing of supply that would be mandated by regulators over the past several weeks. So, I just wanted to see where you stand on that topic and how you think it's going to play out.

Yeah. We haven't been supportive of that Doug from a regulatory perspective, because we think the market is going to ration that very quickly and either through both voluntary-type cuts that we're taking or infrastructure and storage-related cuts that become involuntary, I guess, to some degree for maybe us and other operators as well. So the market is reacting. The market's working and it's going to drive supply down to kind of match inventory levels and what the demand or what the refineries can take on the other end. So we haven't been supportive of efforts that like the Railroad Commission recently has been analyzing and thinking about.

Thank you. Our next question comes from Roger Read from Wells Fargo. Please go ahead. Your line is open.

Yeah. Thank you. Good morning. I guess, we've heard different things from different companies about the shut-in elective shut-ins and reservoir issues and I heard your answers to the first question. But I was just curious can you give us any examples of what brings you confidence about reservoir – maintaining reservoir integrity as you go through the shutdowns that you are doing or will be doing in May will be doing in June? And then, if they continue beyond that what gives you that confidence?

Roger that's a fair question. The – it's really because to some extent we go through this on a regular basis in our field generally just for a shorter duration. For example in Alaska, every other year we do a full turnaround at Alpine. And we go through shutdowns or turnarounds on different processing facilities in Kuparuk. So, we know how to take the wells down and keep them in good condition and bringing them back on again. The same is true in Surmont. I mean, occasionally we've had to put Surmont truly shut down, because of wildfires, where we've had to go down very quickly. So we know how to how to handle that as well and in the Lower 48, the most recent example for example in June Hurricane Harvey. Eagle Ford we had to go down. So we'll get plenty of both pain and experience that gives us confidence that we know how to handle this. We've got the advantage just now that we can plan it and we can get it. And so, there's no reason to be particularly concerned about that. We also understand what our decline rates are. And we also understand, what our flush production is that comes back after shut-ins. So that gives us everything that we need to make a sensible economic analysis as well. So trust me Roger this is all pretty well thought through.

Well, I didn't doubt it wasn't thought through. I'm just mostly trying to understand where the experience comes from because there are some different attitudes out there. Switching gears a little bit, Don obviously significant liquidity in the company. I was just curious is there anything else you're looking at balance sheet-wise? And I'm not just thinking about revolvers or new debt or anything like that, but also kind of how you're thinking about the working capital side of the business that we should be thinking of levers, you could pull here in coming quarters?

Not really, Roger. We -- our working capital is pretty finely managed always has been. So we don't have a lot of optionality there. We don't carry surplus inventories or anything like that. Just thinking about other items coming down the road that would affect liquidity I can't think of anything in a negative way other than the low cash from operations that we expect over the next few months as oil prices continue to be low. We do expect the proceeds from the Australia-West transaction. We still believe that that's going to close in the second quarter. So that will be coming in from a positive direction. But other than that I can't think of any big-ticket items out there.

Thank you. Our next question comes from Neil Mehta from Goldman Sachs. Please go ahead. Your line is open.

Good morning team and thanks for sense I have seen here today. The first question I had is around the sanctity of the dividend and this is for anybody who wants to take it. We assume one of your large competitors reduced their dividend today. Conoco in some ways took this medicine a couple of years ago. So -- but curious on your view about safety around the dividend and strategy around that distribution.

Yes. Thanks Neil. Yes. I think you kind of have answered the question. We declared our dividend today as you saw in our press release. That kind of remains a priority. And really we were committed to a return of cash to the shareholders of greater than 30%. We've outlined that since we see -- reset our value proposition a number of years ago. And the dividend is a fixed part of that that we expect to be able to execute through the cycles. We exercised the flexible part of that return to shareholders with the suspension of our buyback program here a month or so ago. So we're pretty confident. As you described I mean we took our pain a couple of years ago back in this last downturn and we wanted to set the company up because we knew the volatility was with us to stay. And maybe this is a three or four sigma event that's even beyond maybe what we were thinking about in a couple of years ago and what we outlined in November. But through Don's comments on the balance sheet the strength that we have as a company I think we're well positioned to get through this downturn in pretty good shape.

Thanks Ryan. A follow-up question is around consolidation. I know you spoke to this a little bit on the capital spending call, but I wanted to get any updated thoughts around it. One could argue this is towards the bottom of the cycle and there's a potential to be opportunistic, but curious on your views as you've been patient in the past and had some strong views on bid and ask?

Yes. No I think you're right Neil. Our -- we haven't changed. We're patient. We're persistent. We monitor the market. I certainly believe there's going to be significant stress across the sectors as you've described. And we're -- we've been willing to transact. We've talked about that. But it has to be accretive and it can't break our long-term financial framework that we've described to the market many times. So the strong balance sheet and we won't put liquidity at risk. So I think broadly speaking it makes it obvious that this E&P industry needs structural change. The growth model is broken. There's too much G&A running around this business. And I think it was addressed -- it was an interesting article by Liam Denning in Bloomberg here yesterday. So read that I think it's reasonably accurate. There's too many names for investors. It's getting less relevant in market cap terms. So we do believe the assets could be run more rationally for improved returns over growth. But imagine the depth of this downturn. There's some pretty tough discussions going on between boards and management right now. So it will probably take time for some of this to realize, but I think it needs to happen.

Thank you. Our next question comes from Jeanine Wai from Barclays. Please go ahead. Your line is open.

Hi, good afternoon everyone. My first question is on the June production curtailments. The anticipated June curtailments they're a bit more than what you're expecting in May. And so can you talk about how you settled on the June versus the May level? Because I guess when we look at the forward curve, plus the implied CMA rule adjustment, June and July WTI pricing looks stronger than May. So is your decision based on something you're seeing in the physical market versus the paper market? Or are you just being a little bit more conservative here? Or is it just related to something else?

Yeah. I'll take that, Jeanine. This is Matt. The -- to me essentially we curtailed as much as we could while still honouring contracts that we have entered into with buyers. The -- and so we had in the previous months March and April entered into contract to sell crude oil. And we were going to honour those contracts. So what we curtailed is these where we didn't have contracts in place or where the buyer was happy not to take. And in June we have more flexibility in that respect, because we have much fewer barrels placed already. So, that's the primary reason why the curtailment is higher in June. There's also still this issue of a bit of a dislocation between the market price and the net add prices that were actually are being offered not just as everyone else. So I think that phenomenon was stacked in May. And it's still here in June. So there's an element of both of your potential responses. I think both are somewhat true.

Okay. Great, thank you. That's very helpful. And then, maybe my second question for Ryan. It's on the 10-year plan. So, I'm wondering, do you see the current or medium-term environment simply pushing out the 10-year plan? Meaning that, you would resume pretty much the exact plan maybe a year or two of delayed? Or have the conditions changed so much that you could see more value to shareholders if you make more meaningful adjustments to the underlying plan?

Yeah. Thanks, Jeanine. And I'd add to the last question to Alaska is an additional 100,000 barrels a day that, we are doing in June that we aren't doing in May so. But to your second question about the 10-year plan it was as much a philosophy and principles that we think are -- that E&P companies need to be taking to focus on returns and really bring value investors back into this business. We don't see the basic tenants of that plan changing. Strong balance sheet diverse low-cost supply portfolio returning more than 30% of our cash back to the shareholder looking through return -- through-cycle returns. I would say that, I'd remind people we've got a 15 billion barrel resource base of less than $30 cost of supply. And in that cost of supply it embeds 10% after-tax rate of return. So we've got something that's quite resilient and in sets up. And we've been long preaching about volatility and lower -- you got to be prepared for these lower prices. So they're the right ones for an E&P business. Now the tactics of the 10-year plan were based on, how we're going to optimize our investment choices that we had. So clearly, the early years of that plan has changed with the downturn. But the shape and the speed of the recovery will dictate how quickly we return and get back -- executing that previous scope and pace of work that we had outlined last November. So, when this event passes, we expect to have the same philosophy and approach. The programs might be staged and phased a different -- a little bit differently. But we intend and fully expect to emerge with an even more competitive plan when we get done.

Thank you. Our next question comes from Doug Leggate from Bank of America. Please go ahead. Your line is open.

Hello. Hi. Good morning, everyone. I hope everyone is doing okay out there. Ryan, I wonder, if I could bring you back to…

Hope you are too.

Yeah. Well, I enjoy going to work in my shorts. But we'll save that for another conversation. The breakeven that you have with the adjustments you've made, I'm just wondering if you could give us a refresh with the reduced production capacity with the shut-ins. Where do you think, your breakeven is right now just to give us a kind of road map for how your cash flow capacity is coming out the other side of that? That's my first question.

Yeah, Doug, this is Don. I think on a recent call we mentioned, with -- on a go-forward basis, if you're looking at our spending for the remaining three quarters of the year, we said that our breakeven to cover CapEx was under $30 WTI.

Does that include, the dividend and the reduced -- the additional curtailments, Don?

It does not include the dividend. So to get to the dividend you'd be in the mid-30s WTI.

And with the, curtailments?

And as far as curtailments, it doesn't because we're not projecting them beyond June. We don't know what they're going to be. But I can tell you the CFO impacts of the curtailments that we've announced is quite small, because of the prices that we expect.

Of course, okay. I appreciate that. My second question, I don't know if either -- which one of you want to -- wants to take this but it goes back to the issue of sustaining -- supporting or sustaining your production capacity. So, when you think about the shut-ins that, you're taking and obviously you can recover those volumes as you discussed. But when you're not drilling against the backdrop of a declining unconventional business what happens to the underlying production capacity? Because I have to believe that, running up back down an escalator you're basically going to come out the other end of this with lower absolute production capacity, on the Big 3 and the Lower 48. Can you walk us through the dynamics there? And I'll leave it there. Thanks.

Hey Doug, this is Matt. I'll take that one. So based on the capital and operating cost reductions that we announced a couple of weeks ago and if we don't pay any attention to production curtailments, our average production for 2020, the average productive capacity would be about the same as 2019. So, capacity-wise about flat. The actual production will be whatever it ends up beginning then for the -- including the curtailments. In terms of the shape of the profile through the year, which is what I think you're getting at, I mean, obviously the capital was front-end loaded. And we're assuming in our capital program that we don't complete any wells in the Big 3 over the last eight months of the year. So that means there's some -- there's certainly some decline in capacity as we go through the year. But we're not giving specific guidance on that, because there are so many moving parts just now including the curtailments. We're concerned about getting that misleading guidance. But the overall direction is, yes, there will be some decline in capacity. Now keep mind that we -- we're actually going to be building some DUCs here probably somewhere in the region of 130 or so DUCs. Any loss in productive capacity we can recover very quickly. So this is a sort of transient thing that we can manage through. But we're not giving any specifics on that, because we're concerned about giving misleading guidance.

Thank you. Our next question comes from Phil Gresh from JPMorgan. Please go ahead. Your line is open.

Hi. Yes. Good morning. Thanks for taking the question. The first question is somewhat related to a couple of the prior ones. You've talked about this WTI breakeven in the low 30s for the full year and in the high 20s for the rest of the year. Back at your Analyst Day, it's originally going to be about $40, and then over time work its way down to $30 as you ramped some of your production objectives over the next few years. How do you think about this moving beyond 2020? Do you think it makes more sense to maintain a breakeven where you're run rating now? Or does it make sense to ramp spending back up a bit as you see increased visibility?

Yes. Phil, this is Matt. The -- that becomes a question of in the long run how we see this epidemic and implications for demand -- the implications for long-term demand and therefore prices. But generally speaking, although, we could run at a very low sustaining capital price and very little sustaining price in general, the cost of supply of our investment opportunities average below $30. We don't feel it's in our shareholders' best interest to not to exploit those development opportunities. So I think it's unlikely that the choice we would make would be to try and run it at such a low breakeven, because it would be deferring a lot of very low-cost of supply investment opportunities. Having said that, we'll just have to see how this plays out. We have to see if we sense it's a very long-term implication on the mid-cycle price. But I think it's too early to make a decision on that right now.

Yes. And I would add Phil that if you recall back in November, we talked about our asset optimization model and we've looked it, and obviously, if we come back to a different mid-cycle or a different sort of long-term price, we would -- we'd redo that. But we have a pretty strong idea of what that optimum kind of exploitation rate across our Lower 48 and unconventionals is and have applied that to our broader portfolio as well. So we obviously -- we look at that, but it is a higher level than what is -- what you might call the sustaining capital level, because there is a sweet spot of investment that we would make that would generate what we believe is the better returns in the business. And we're going through this downturn today and we've retained all of our capability. So we've not eliminated any of that organizational capacity, because again we're that -- we're informed by our short and medium-term view of the market what we think the recovery might look like and have chosen to retain that capability so we can come back strongly if we if and when we choose to.

Sure. Okay. No, I appreciate that. It's early to be asking those types of questions. The other, I guess, piece of this is there's a very lumpy part of the development plan over time, which was Willow in Alaska. And I'm just curious how you're now thinking about Willow and how the timing -- I guess just based on your base case macro view from your another -- a lot of potential outcomes. But what would be your base case on how you think about rolling looking forward and the timing around it?

Yes. So this is Matt again. We're working through Willow and we're in the concept selection stage just now. We have a time line that would get us to the end of this year with the opportunity to select the concept. And by that, I mean, how big a facility do we build, how many drill centers do we have and so on. So we're continuing to work towards that decision point towards the end of the year for Willow. And we'll make a decision at that time and then that will dictate the pace beyond. So we have not made the decision to defer Willow and -- but we have that decision is ahead of us. So we're continuing to work through that.

And we expect permits here this summer supporting the development at Willow both at the federal and state levels.

Thank you. Our next question comes from Scott Hanold from RBC Capital Markets. Please go ahead. Your line is open.

Yeah. Thanks. If we could stay in Alaska a little bit. Obviously, you've completed some of your winter program with some appraisals and tests out there. Can you give us a sense of what you have learned from that and how that helps you form your decision to the next year or so?

Yes, Scott. Good evening. And yes, we did some exploration at Harpoon and appraisal at Willow. And at Willow we drilled two wells and having planned four in Harpoon we drilled one out and planned three. And the reason that we drilled for about half the program is we were concerned the -- about having these exploration camps way out west on the North Slope if we had a COVID outbreak. And thankfully, we didn't have a COVID outbreak. We have an abundance of caution for people and our contractors. We decided to shut down the exploration program earlier. So we drilled two or four wells at Willow. And the -- those wells were the results that we were expecting and we're still on track for a concept select decision. We'll just have to decide if we want those additional wells before we make that decision then. But we were still evaluating the data just now. On the Harpoon well, which is the exploration complex in the South our original plan was to drill three wells there. We only drilled one. The -- and that well appears to have clipped the edge of the top set based on its log response. And we won't know that for sure until we get a chance to drill the second well. So we're still evaluating those results and but I think the bottom-line is that the jury is going to remain out on Harpoon until we get back out there to complete the exploration program.

Okay. I appreciate it. Good color. Good color. And this one might be for Don. The LNG outlook. And can you provide any kind of color on expectations for distributions maybe over the next quarter or a year if you have information you think that would be good enough at this time?

Sure, Scott. Actually, LNG realizations have held up pretty well so far. I think our LNG netbacks were only down about 4% from the fourth quarter. But that's because of the lagged nature. So that's going to rollover and we're going to start seeing the impacts as we go through the rest of the year. But we do have an advantage in that most of our LNG -- I'm talking about all of our projects globally. The vast majority of our LNG is under term -- long-term contracts and so they're holding up relatively well compared to the very weak current spot market. In fact, I think 90% of our total LNG sales are term and less than 10% spot. So back to your question as far as distributions as you know we reported I think about $100 million distribution in the first quarter from APLNG. We're still expecting somewhere between $500 million to maybe $550 million for the year.

Thank you. Our next question comes from Alastair Syme from Citi. Please go ahead. Your line is open.

Thank you. I had a related question for Don on the cash flow. I'm just wondering if you could give some, sort of, guidance on how you're thinking about cash tax in this environment. I think if I remember back in 2016 you had substantial tax-loss carryforwards in particularly in the U.S. I was wondering to what extent these still exist?

Yes. We're still Alastair in a non-cash tax paying position in the U.S. And I think coming into this year when markets were still stable or relatively stable we were thinking that we could come out of that position maybe as early as 2021, but probably more likely 2022. So now this is going to obviously set that time frame back because we're going to have some large losses this year. So I don't have an estimate of when we might come out of it now but it's going to certainly be beyond what we thought before.

So does that mean the U.S. is in a minimal 0 taxpaying position in 2Q in effect?

Yes. We're in a zero tax paying position in the U.S. and we expect to remain there for quite some time.

Yes. Thank you very much.

Thank you. Our next question comes from Paul Cheng from Scotiabank. Please go ahead. Your line is open.

Hey, guys. Good morning or good afternoon depends on where you are. Ryan, I think your overall business model you are not changing. You have a good business model of a balanced growth and cash return to investors. But with this event, is there in any shape or form that have changed some of the parameters whether it's the leverage ratio that would consider as a acceptable or a comfortable range? Or what that -- what is the percent of the reinvestment? Any of those parameters within your framework because of this event has been changed? If not why not?

Well I think time is going to tell Paul. I think we got to go through this, find out where demand returns to, if there is any permanent demand loss as a result of this pandemic changes in consumer behaviors that might drive a different longer-term view of the price. So I don't think we -- we're kind of like a lot of people watching that very closely to try to understand where supply and demand rebalances out at the end of this downturn. So it's probably a bit early, but we'll continue to again rely on the fundamentals of the business that I talked about earlier the strong balance sheet executing on a low-cost of supply resource base. And we're committed to the value proposition that we laid out at back in November. We've really been -- we reinforced back in November and what we've been operating under for quite some time or at least the last few years. So I think your question around capital intensity and how you return money back to the shareholders, we just have to see what the long term -- our long-term view of prices ends up being and where supply and demand rebalances itself as we come out of this downturn.

Ryan, that's fair. I mean, with the -- the only problem is that we probably won't know what is the real long-term impact or if there's any maybe for four or five years. I mean, that I think by the end of this year or the more for next year, I'm not sure we can really tell that we know what is the long-term impact. So yes, that means that you guys are probably not going to do anything differently until maybe four to five years down the road for you that you have some kind of confidence level that you really know what is the long term impact? Is that the way how we should look at it?

How long have you noticed Paul to take five years to react to market environments that we're in? We're pretty -- we've run our scenarios. We know what we're doing. We know what the philosophy is around the business. And we'll match our efforts around capital and return back to shareholders and where we put the balance sheet and how much cash we need to have on the balance sheet based on the environment that we find ourselves in. And we have confidence because the low cost to supply resource base that we have existing in the company competes in a very low commodity price environment. So we know what wins and that's what we're going to be focused on. And we're going to be flexible and do what we have to do to make sure we're putting the money into the portfolio in the right places and reacting to the kind of environment that we find. We certainly won't wait five years.

Thank you. Our next question comes from Josh Silverstein from Wolfe Research. Please go ahead. Your line is open.

Thanks everybody. Just on the Alaska volumes, we've typically thought about A&S and Brent just kind of interchangeably there. That relationship has broken down over the past month. Can you just remind us how you sell those volumes and like how that might be different from how you're selling the Lower 48 volumes?

Josh, I'll take that one. Yes. Most of our A&S sales go into the West Coast, which is why you're seeing the traditional relationship between A&S and Brent break down because of the very low refinery utilization rates in pad 5. So we would expect that that relationship would return once demand picks up in California and the rest of the West Coast. Some of our cargoes we do if the opportunity is open for us. We do send them to Asia as well. But generally, our A&S sales wherever they go, they're going to correlate usually very closely with Brent except under unusual circumstances as we're facing today.

Great. Thanks. And then right now there's a lot of defense being played right now, whether it's by Conoco or everybody else in the market. Just wondering where Conoco can play offense in this environment to lower the forward breakeven price. I guess the M&A question was asked before, but is there anything from a service cost standpoint or anything else that Conoco can pull the lever on to get that breakeven price lower?

Yes, Josh. I mean, obviously, we're working with our supply chain partners on the opportunity to see some deflation in this environment. We have a strong relationship with suppliers. We -- and there may be some of that value there. We also see value. We've had a very strong focus on innovation in the company over the last many years and so there are opportunities to accelerate the adoption of new technology and find ways to continue to drive across the supply down. We've made incredible strides on that over the last few years and we're not done yet. I mean, we know that part of our job is to continue to drive cost of supply down, because what wins in the end in the commodity business is low cost of supply. And that mantra is fully understood by everybody that works here and we're focused on moving every little -- every sense we can on the cost of supply over time.

And our workforce, Josh, sees the volatility in the market. So they see what happens in these volatile markets and why, as Matt said, we have to continue to lower the breakeven and drive the cost of supply down.

Thank you. Our next question comes from Michael Hall from Heikkinen Energy. Please go ahead. Your line is open.

Thanks. Good morning. I guess, I was just curious as you think about bringing back the curtailed volumes. Do you expect to see any sort of material or notable incremental operating costs and/or capital costs associated with bringing those back for things like workovers or ESP refurbishment or any other associated costs that are associated with restarting those volumes?

This is Matt, Michael. And not particularly. But they -- we have slowed down our well work and workover activity. Its part of our operating cost reductions. So when prices recover and we want to produce those barrels and we go ramp that back up again. But for the most part, the reduction at the payrolls don't result in any incremental -- significant incremental workover activity, for example, to bring them back on again. I think that's what you were getting at.

Yes. That's helpful. And, I guess, also as you think about the second quarter, I mean, are there anticipated turnarounds that we ought to keep in mind as well that would go beyond any of these curtailments outside of the Lower 48 Canada and Alaska, just thinking the rest of the global portfolio? Is there something that was already baked in that we just ought to be keeping in mind as we head into the second quarter?

Yes. We have sort of standard turnarounds going on across the portfolio this year. Last year was a very heavy year for turnarounds. It's less heavy this year but we're keeping to that schedule and there are no hugely notable ones that are unusual as we go through the year, but they will be occurring predominantly in the second and third quarter. We did take a turnaround in Qatar in the first quarter, but the majority of them will happen in second and third quarter.

Thank you. Our next question comes from Paul Sankey from Mizuho. Please go ahead. Your line is open.

Hi. Good morning everyone. There's a lot of disconnect between paper markets for oil and physical markets. And, obviously, within that physical dynamic, there's tremendous differences across the board in regional crude prices. Could you just talk a bit about how that's been affecting you? And I'm also wondering about some of your crude quality. There's been a lot of talk that very high API crude has been a problem. And then, while we're going there, could you also -- there's a bull case for natural gas here as people shut down production. Could you talk about your exposure to the natural gas theme, please? Thanks.

Yes, Paul. I'll take that one. This is Don. Yes. It's been two different worlds, really, the last month or so, speaking to your comments about what's happening in the physical markets versus what's going on in the financial markets. We've certainly seen that in the U.S. in particular. And that's really driven our decisions around curtailment that the netback prices are lower than what you might assume reading the screen. So, I would say, we haven't had any – we haven't faced any problems in placing the volumes that we wanted to place. So we call these voluntary curtailments and they are. They are elections that we're making just, because we don't like the price that's being offered, but we haven't faced a situation where we've had difficulties finding the market for our crude. Not here in the U.S. and not anywhere in the world, not yet that may be coming. On the natural gas side, I mean, we are seeing some -- at least, somewhat bullish views on the natural gas side. We just don't have the same exposure that we used to have. Our exposure is mainly on the LNG side and on the European gas side. We have very little domestic production anymore.

Understood. You do have – can you talk a little bit as a follow-up about your infrastructure positioning, and how that -- how markets are around the positions you have in North America? And I'll leave it there. Thanks a lot.

Yeah, Paul, I guess you're talking more about some of our marketing activities. And well maybe both equity and marketing. But we do have long-haul positions on both the oil side and the gas side probably more on the natural gas side because we've been such active marketers of natural gas in North America. So, we've been marketing our own equity gas out of the Permian Basin, generally moving at West towards California, Santa Mexico, Arizona, and up the West Coast as well. But we also move a lot of third party volumes as well.

Thank you. Our next question comes from Bob Brackett from Bernstein Research. Please go ahead. Your line is open.

Great. Thank you. As I read the release, you mentioned the Kamunsu East Field is not moving forward into development. Can you kind of talk to that? And talk about as an example, how is your capital allocation philosophy changed at least in terms of sanctioning projects this year, if it has at all?

Hey, Bob, this is Matt. The Kamunsu East and that was simply a sort of financial recognition of the fact that the timing of when we would develop the KME -- it's essentially a satellite to Kebabangan, KBB. And because KBB has been slowed down by this pipeline issue, third party pipeline issue on -- between Sabah and Sarawak, the license for KME is going to expire before we can bring it to an economic development. So we were just recognizing that in our book's treatment of the asset. And so that was what caused that and recognition in this quarter. In terms of the second part of your question, I wouldn't say that there has been any significant change in our view of how we should be allocating capital. We should be allocating the lowest cost of supply. And we should be facing it, so that we're doing that in the optimum weight. And so, no significant change. At least not yet, Bob, in our thinking on that.

Okay. A quick follow-up on Ankor, you are -- sorry on Harpoon. You mentioned that you clipped the top sets, which tells us something about missing reservoir, but you didn't mention fluids. Did you encounter hydrocarbons in that?

Yeah. We did encounter hydrocarbons. We're still interpreting the results there but the -- and it's -- it looks from a lithological perspective similar to other lithological signatures we're seeing on the edge of these top sets. But we speed two other wells to drill. We would have got a lot more information had we been able to finish the program but for safety reasons we chose not.

Thank you. Our next question comes from Devin McDermott from Morgan Stanley. Please go ahead. Your line is open.

Hey, thanks for taking the question. There are a few asked already on capital spending in the balance sheet, but I wanted to just follow-up in a bit more detail on that. And you provided back at the Investor Day, your helpful analysis of stress testing. The balance sheet and cash flow profile through a low commodity price period. And clearly what we're seeing right now is a bit unprecedented different than that stress test, but the balance sheet is still a very strong competitive advantage for you. I was wondering if you could just give an update on how you're thinking about the required cash balance and willingness to take on kind of additional leverage here or early in on the balance sheet to the extent we see a sustained period of long -- of low prices over the next few quarters to years. And at what point further CapEx cuts become consideration?

Hey, Devin, this is Don. I'll take that. As far as cash balances back at the Analyst Day I think we said that we had an operating requirement of about $1 billion and we felt like we wanted to keep a reserve balance on top of that of $2 billion to $3 billion. I think generally we feel the same way about it. Technically, it's probably -- those numbers have probably come down a little bit. Operating cash is not quite $1 billion because -- mainly because of some of the assets that we've sold. We just don't need that much. And the reserve capital or the reserve cash -- that's a number that we recalculate every month based on our outlook for the next six to 12 months. And that number has probably come down a little bit because of our lower spending on CapEx, OpEx by the suspension of our buyback program. But it might be $1 billion lower than what we were thinking in November, but that's about it. So those numbers are still pretty good. We think we'll -- as we look out, say, to the end of the year, we think that we'll be able to maintain cash balances above those levels of operating and reserve cash. So that would imply that we don't expect to have to access the debt capital markets.

Thank you. Our next question comes from Pavel Molchanov from Raymond James. Please go ahead. Your line is open.

Thanks for taking the question. You may have mentioned a few minutes ago, are you going to be having any involuntary shut-ins in Norway or Indonesia, both of which were part of the OPEC Plus agreement?

Yes. I'll take that, Pavel. We just saw today, as you did, in Norway announced that they would be participating in the OPEC cuts. They announced a 250,000 barrel a day curtailment for June and about 135,000, 134,000 I think it was, in the second half of 2020. So we are likely to be allocated to some of that in Norway. But we're working -- they have a reasonably complicated way of working that, and so there's likely to have some impact in our Norway business. Our estimate at the moment is it will be in terms of the impacts of -- on our average rate for the year, it will be in the low single digits barrels a day for the year for us. But we are still working through that. And they also made some interesting changes to the tax regime over there, and the most interesting one being accelerating the depreciation schedule to one year for capital. So that was a pretty smart strategic response from the Norwegian government, as you would expect. In terms of Indonesia, I think you mentioned Indonesia. We sell gas in Indonesia and to the domestic market; most of the fixed prices are take-or-pay commitments. So we're not going to be affected by any Indonesian action to support the OPEC Plus group. So we may be affected in Malaysia, and the Malaysian government has announced that they are going to participate to some extent but we don't know the details yet of how that will play out.

So Amera, this is Ellen. We're getting close to the top of the hour, so I'm going to ask that we take just one more question. Apologies to our participants, but we'll wrap it up here with one more.

Thank you. Our last question comes from Phillips Johnston from Capital One. Please go ahead. Your line is open.

Yes, thanks. Your oil mix in the Lower 48 has been pretty consistent over the last several quarters in the 57% to 60% range. As you mentioned, you aren't planning on any well completions in this environment. So my question is, if we look 9 to 12 months out, would you expect your oil mix to move significantly lower from that range just as GORs and existing wells naturally move higher without any new volumes to offset that mix shift?

Yes, Phillips, there may be some modest increase in the gas ratio over there as we go through the year, but it shouldn't be that significant. We'll have declining production in the Bakken and the Eagle Ford, the Permian. And with that, there'll be some increases in GOR, but it shouldn't be that significant.

Thank you. I'm not showing any further questions at this time. I would like to turn the call back over to Ms. Ellen DeSanctis.

Thanks and our -- excuse me -- thanks to our listeners. If we left anyone in the queue, we'll come back to you. Thanks for your participation, and stay safe.

Thank you. And thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.