Hess Corporation
Q4 2019 Earnings Call Transcript

Published: 29 Jan 2020

[Operator:]

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2019 Hess Corporation Conference Call. My name is Liz, and I will be your operator for today. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

[Jay Wilson:]

Thank you, Liz. Good morning, everyone, and thank you for participating in our fourth quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.hess.com.

[John Hess:]

Thank you, Jay. Welcome everyone to our fourth quarter conference call. I will review our continued progress in executing our strategy. Then Greg Hill will discuss our operating performance, and then John Rielly will review our financial results. We had an outstanding year in terms of operational performance and continued execution of our long-term strategy, achieving a number of important milestones and delivering higher production and lower capital exploratory expenditures than our original guidance. With Guyana and the Bakken as our growth engines and Malaysia and the deepwater Gulf of Mexico as our cash engines, our portfolio is on track to deliver increasing and strong financial returns, visible and low risk production growth and industry leading cash flow growth. It is important to note that both Guyana and the Bakken will become significant cash generators over the next several years. As we have stated in our investor presentations, where we provide a financial outlook through 2025, our portfolio is positioned to generate approximately 20% compound annual cash flow growth and more than 10% compound annual production growth. And our portfolio breakeven is projected to decrease to below $40 per barrel Brent by 2025. As our free cash flow grows, we will prioritize return of capital to shareholders both in terms of dividends and opportunistic share repurchases. Another key element of our strategy is maintaining a strong balance sheet and liquidity position and managing risk. We ended the year with more than $1.5 billion in cash and cash equivalents on the balance sheet and have hedged 150,000 barrels of oil per day in 2020 using put options, with 130,000 barrels per day at $55 per barrel WTI and 20,000 barrels per day at $60 per barrel Brent.

[Greg Hill:]

Thanks, John. 2019 marked another year of exceptional performance and strategic execution. In particular, I would like to call out three major operational highlights from 2019. First, we beat our guidance for both production and for capital and exploratory expenditures. Our 2019 net production averaged 290,000 barrels of oil equivalent per day, excluding Libya, which was above our original guidance of between 270,000 and 280,000 barrels of oil equivalent per day and also above our more recent guidance of approximately 285,000 barrels of oil equivalent per day. At the same time, our 2019 capital and exploratory expenditures were $2.74 billion, approximately $150 million below our original guidance.

[John Rielly:]

Thanks, Greg. In my remarks today, I will compare results from the fourth quarter of 2019 to the third quarter of 2019. We incurred a net loss of $222 million in the fourth quarter of 2019, compared to a net loss of $212 million in the third quarter of 2019. On an adjusted basis, which excludes items affecting comparability of earnings between periods, we incurred a net loss of $180 million in the fourth quarter of 2019 compared to a net of $105 million in the previous quarter. For E&P, on an adjusted basis, E&P incurred a net loss of $124 million in the fourth quarter of 2019, compared to a net loss of $41 million in the previous quarter. The changes in the after-tax components of adjusted E&P results between the fourth quarter and third quarter of 2019 were as follows

[Operator:]

Your first question comes from the line of Doug Leggate with Bank of America.

[Doug Leggate:]

Thanks. Good morning, everybody. Guys, it looks like the market doesn’t like the guidance too much. So I wonder if we could talk a little bit about the cadence of what’s going on with downtime through the course of the year. Greg, you touched on Tioga. But I want – obviously, you’ve given us a first quarter run rate for the Bakken. But can you kind of walk us through how that progress is through the year, because clearly 174,000 in fourth quarter and 180,000 average for the full year looks a little soft and maybe touch on the Gulf of Mexico planned downtime as well?

[Greg Hill:]

Yes. Thanks, Doug. So as we mentioned, we do have the turnaround at Tioga gas plant. It’s going to be about 45 days. And we’re going to turn it around and also tie in the gas plant expansion as we mentioned. Now that’s not going to have much impact, if any on oil. It’s going to be primarily gas. And the net effect of that is about 6,000 barrels of oil equivalent per day. If I turned it…

[Doug Leggate:]

For the year, Greg, or for the quarter?

[Greg Hill:]

Yes, for the year.

[Doug Leggate:]

For the year.

[Greg Hill:]

Thanks, Doug. And then if I turned to the Gulf of Mexico, we have two major shutdowns in the second quarter, one at Conger and one at Llano, both of which are down for 30 days. We also have Penn State down for about eight days in the second quarter. So the net impact of that on the quarter is about 13,000 barrels a day.

[Doug Leggate:]

Okay. That starts to make a bit more sense, and I appreciate the emphasis that oil doesn’t gets hit. Thank you for that. My follow-up is, so not to be too predictable, it’s obviously on Guyana. And I know we have the Exxon Analyst Day on March 5, so to the extent you can share. It seems that the appraisal activity focus around Turbot is probably, I’m guessing, is to define what the scale of that development is going to look like over time. And you’ve previously defined that as a major development hub, but we also know that Hammerhead has been passed to the development team for Exxon. So I’m just wondering if you can kind of walk us through your current thought on the timing over the scale of that 2025 run rate, and John Rielly, how does that impact the 2018 guidance, you gave us over run rate $3 billion capital program? And I’ll leave it there. Thanks.

[Greg Hill:]

Yes, thanks Doug. I think, as we’ve spoken before, you’re right, I mean Hammerhead has been passed off to the development team that notionally right now is about 140,000 barrels of oil capacity, kind of vessel. And then as you mentioned, all of the appraisal activities that are ongoing really what I call on the eastern seaboard between Turbot and Liza are really trying to understand, how many vessels will it take to evacuate all of that oil, which is substantial along that eastern seaboard. So clearly, vessel 5 is going to be in that area and probably several vessels after that, but we’re trying to figure all that out. How many vessels will it take? And obviously, the fifth vessel will be a large one. It’ll be in the 220,000 class, like the others are. But specific timing of the number of vessels and timing of the ones after five, that’s really what we’re working on. And that’s kind of the heavy lift for this year, Doug, to really understand that.

[John Rielly:]

And then, Doug, as far as our capital program is, as we laid out on our Investor Day, we had $3 billion this year. We do have, if you see from the Investor Day, a little bit more next year as we move on with these developments. And then as we’ve talked about as an approximate $3 billion, and right now there’s no change to that number. We’ve got a nice cadence going to Exxon, as an aside, has been doing a fantastic job on the execution of Phase 1. And now Phase 2 is the execution is going along well. And so it’s – they’re doing a great job for Guyana and for the partners. So what we’re seeing from our capital program is that, that $3 billion is a good number right now. As Greg said, we’re unsure of FPSOs beyond the five and we’ll see that. But again, that will be much later in the profile of our timing of free cash flow, because as you remember, once Phase 2 comes on, it’s a big inflection point for us from a free cash flow standpoint. So any FPSOs would be at six, seven or something beyond that. We’ll be in a good period for us when we’re generating a lot of free cash flow.

[Doug Leggate:]

I appreciate that guys and I’ll see you in a couple of weeks. Thank you.

[Operator:]

Your next question comes from the line of Ryan Todd with Simmons Energy.

[Ryan Todd:]

Great, thanks. Maybe one follow-up initially on Guyana. Can you talk about on the upwards revision to the resource estimate to 8 billion barrels, was all that based on the inclusion of incremental discoveries since the last estimate? Or was there any component driven by upward revisions to estimates at prior discovery? Maybe just can you talk about the primary drivers of what you continue to see as a significant upward pressure on resource?

[Greg Hill:]

No. I think the absolute grand majority of that was all new discoveries. So it’s just continuing to add to this extraordinary success rate, five in 2019 and already another one in 2020 with more to come.

[Ryan Todd:]

Great, thanks. And then maybe a follow-up in the Bakken. And then Bakken continues to exceed expectations in terms of productivity, and also impressive costs. Can you talk about some of the drivers of what you’ve seen in terms of the strong Bakken production? And maybe you highlighted Exxon targeted reductions of well cost for the Bakken in 2020. What are the drivers and what are you seeing there in terms of costs in the basin?

[Greg Hill:]

Yes. So let me start with cost first. As I mentioned in my opening remarks, I’m really proud of the team and their ability to drive costs down with lean manufacturing. So if you think about our journey in 2019, we started at $7.5 million in the fourth quarter of 2018, $7.3 million in Q1, $7 million in Q2, $6.7 million in Q3, and $6.5 million in Q4. So that’s an amazing cost reduction over 12 months driven primarily by lean manufacturing, but also technology. And then as we look forward to next year, obviously that flattens out a bit part of lean manufacturing. But we still think we’ll be at $6 million by the end of the year. The biggest driver on that is going to be, again, technology and lean. But we also are seeing some softness in the sand costs and also pressure pumping. So we built some of that into our cost estimates for next year. Regarding the productivity, really a function of where we’re drilling, but also the plug-and-perf coming in very well. So on average, our IP180 are up 15%, but if you look at certain areas of the field, particularly, in the southern part of the field, we’ve outperformed that 15% in those areas and those are very good prolific areas of the Bakken. And as we look forward to our 2020 program, again, it’s 175 wells be very similar, EURs kind of in the 1 to 1.2 range, IP180s in the 1.10 to 1.20 range. And the IRR is at 60%, well above 75%. So again, a very strong program in 2020.

[Ryan Todd:]

Great, thanks Greg. Very helpful.

[Operator:]

Your next question comes from the line of Roger Read with Wells Fargo.

[Roger Read:]

Yes, thanks. Good morning. Maybe just to follow-up on that Bakken question, and this may be premature, but given that you’re continuing to see improvements as we think about holding flat at 200,000 a day, kind of end of this year onwards, any reason at this point? Or any optimism to think about that costing less, or maybe not taking quite four rigs as we go forward? Or do we just need to balance that as you kind of move from, as you mentioned the premium spots to maybe the next tier down that’s incorporated in the outlet?

[Greg Hill:]

Yes. I think it’s a balance as you said. So we’re pretty confident that we can hold it flat at the 200,000 range for at least five years and probably longer. And as you mentioned, as technology improvements to continue to occur, as costs potentially continue to come down, obviously that plateau be extended even longer. And I will mention that in our Tier 2 acreage, we are doing a lot of trials on proppant loading, on number of entry points on spacing. So we are not – we’re not decided yet in some of those areas exactly what that’s going to be. So the assumption going forward is none of that’s built-in. So I’m very optimistic that that will get much better as we go forward as we learn in those areas.

[Roger Read:]

Yes. It certainly has not been a static environment so far, right? One other question and it’s got two parts, I apologize for doing it that way, but it’s some of the pushback we’ve gotten post results here. One is the hedging programs. So I’ll just kind of put the question up to you of why hedge? The second part is, we did see debt go up in the quarter. It looks like mostly that was to take care of the Midstream side of things. But I was wondering if you could clarify on those two points for us.

[John Rielly:]

Sure, Roger, and only do the second one first, it’s quick to debt. That went up was related to Midstream and the completion of the transaction that we spoke about, the acquisition of Hess Infrastructure Partners and the conversion to the Up-C that was the debt. So it’s just purely Midstream debt. That is non-recourse to Hess. As far as the hedging, Roger, the price we have that, from our Investor Day there, with Bakken getting up to 200,000 barrels a day and bringing on Phase 2. So what we do is, we look at it year-by-year and we put these hedges on for insurance just to ensure that we can fund that investment program because of the returns of that program will drive for us. So we’re getting closer and closer. Phase 2, right, is mid-2022. We just want to finish this Guyana program, executed, continue to execute that. And as Greg say, continue to execute our six rig program, which will drop the four rigs the following year. And so we just put hedges on for insurance purposes and hopefully we don’t use them.

[Roger Read:]

I appreciate it. Thank you.

[Operator:]

Your next question comes from Jeanine Wai with Barclays.

[Jeanine Wai:]

Hi, good morning, everyone. I guess my two questions are on CapEx and Guyana. The first one is, it looks like total E&P CapEx for the quarter came in a little bit higher than expected and I believe some of that might be related to Guyana. So can you provide any color on that and any implications for Phase 2 that it may imply?

[John Rielly:]

It did come in for the quarter, very small amount. Again, we just went out with an approximately $850 million, came in at $876 million. As Greg mentioned, with the Bakken, we did get a little bit more completions in Bakken. And so a little bit is in the Bakken, a little bit of it is an acceleration in Guyana, and the rest of it is kind of just through the portfolio, really small numbers. Again, we were just given approximate amounts. So there’s no implication on that going forward. We had the $3 billion capital that we set. We are going up approximately $300 million in Guyana next year versus 2019. And again, we laid that out for the continuation of Phase 1, $400 million for Phase 2, and then the rest of it for Phase 3 and future developments.

[Jeanine Wai:]

Okay, great. That’s really helpful. Thank you for that. My second question on Guyana, can you comment on any of the recent news headlines about the potential for contract renegotiation?

[John Hess:]

Yes. Most of the news that you hear is not from reliable sources, neither the current government or opposition government. I think they both have been pretty clear that they’re going to honor the PSC. So I think that’s the real takeaway you should have.

[Jeanine Wai:]

Okay, great. Thank you for taking my questions.

[Operator:]

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

[David Deckelbaum:]

Good morning, everyone. Thanks for taking my questions. I just wanted to ask you, you talked about having the first tanker loading attributed to Hess or allocated that has in March with 1 million barrels. How do you see the listings or tanker loadings progressing throughout the year? Should we always be thinking about the same sort of capacity and what kind of cadence are you expecting throughout the year?

[John Rielly:]

So the cadence can move around a little bit from that on how they get allocated. But here there’s a general rule of thumb, it will be 1 million barrels each lift. And for us, as you heard, Greg gave the guidance on Guyana, that it’s 25,000 barrels a day for the year. If you multiply that by 365, you’re getting just about 9 million, little over 9 million barrels. So we expect just from a forecast standpoint to have nine lifts this year. I can’t exactly be specific, which quarters that we come in our first lift, you’re right, is expected in early March.

[David Deckelbaum:]

Okay. I appreciate that. But it does sound like your net sales amount as approximating your production guidance for the year. So that’s incorrect.

[John Rielly:]

That is correct. Quarter-by-quarter, you could get some under over lifts, but right. For the full year, it – the sales should approximate the production amount.

[David Deckelbaum:]

Got it. And then just to revisit some in the Bakken guidance, I know that it’s difficult to forecast with lumpiness around the quarters. But the expectation is that you’d be exiting 2020 at approximately that 200 equivalent target?

[Greg Hill:]

Yes. Yes, we’ll achieve that sometime in the fourth quarter.

[David Deckelbaum:]

Okay. And then the – in the third quarter with the Tioga turnaround and expansion, how is it that oil volumes are not impacted there from a logistical perspective?

[Greg Hill:]

Well, again, there are separate systems, right? So you can – the gas is separated on the pad from the oil and it goes through a separate system. So you can still produce the oil, but obviously that gas goes through the plant, so that’s where the impacts going to be. So we’ll do some local flaring on the pads and some flaring at the gas plant as well during that 45 day shutdown. But the oil will largely stay on.

[David Deckelbaum:]

Okay. But I guess as a total program, you’d still be under the regulations for flaring at the state level?

[Greg Hill:]

Yes. Yes, there will be some restrictions that we’ll have to deal with. But of course, you can get some dispensation for things like turnarounds, et cetera.

[David Deckelbaum:]

I appreciate the color on that. Thank you, guys.

[Operator:]

Your next question comes from the line of Michael Hall with Heikkinen Energy Advisors.

[Michael Hall:]

Thanks. Good morning. I’m just curious a little bit of an accounting question. I guess, on the Guyana volumes the 25,000 a day, does that include costs barrel recoveries? If so, how much, if not, how should we think about that for 2020?

[John Rielly:]

It does include that. It’s just part of the normal production sharing contract that cost recovery barrels are included as part of our production and the partners production.

[Michael Hall:]

And do you have an estimate of how much of that is cost recovery by chance?

[John Rielly:]

I could walk you maybe through a little bit more detail after the call, but the contract that is out there that you can see, but the way it basically works is on the revenue, then 75% of the revenue goes for cost recovery for the contractors. So that’s how you can factor in. Then you go into profit share after that.

[Michael Hall:]

Okay. Yes. Just want to make sure we’re calibrating right. And then, I was curious, I guess the Gulf of Mexico, the capital on the 2020 plan. I think we backed into around $350 million or so relative to 2018 Analyst Day you talked about annual average capital of $150 million to sustain 65 MBOE a day. So I’m just trying to line those two things up and should we be – how do we reconcile those two things?

[John Rielly:]

I just want to make sure that we are on the same page with the numbers. So in our release that we went out for 2020, the Gulf of Mexico capital will be approximately $135 million for this year. That’s we’re spending from a production aspect of it. Last year we did have a higher amount, it was approximately $290 million. And that is because we were running full year, we had two rigs running for Stampede, which will be coming off contract here basically in the second quarter. So there’s lower Gulf of Mexico spend. And so as you know, we will be tying in Esox, which again helps and keeps us at that 65,000 barrels a day, that we’ve talked about.

[Greg Hill:]

And then, as we did mention, going forward, you can expect about $150 million to $200 million of CapEx per annum for infill and tie-back wells. And this is our objective in the short-term to medium-term to maintain the Gulf at about 65,000 barrels a day. And we’ve been very successful doing that. If you look at Conger-10, that was about 6,000 barrels a day. Penn State-6, about 14,000 barrels a day, Llano-5, about 8,000 and Esox is anticipated to be a very good well. We see four to six more things that we’d like to drill in the next couple of years and our expectation of keeping those hubs full. Then beyond that, of course it’ll be greenfield. So we’ll drill a greenfield expiration well probably one a year on average over the next several years. Again, trying to maintain that production or potentially even growing it with the new hub.

[Michael Hall:]

Okay. Yes, I guess – that’s helpful. I guess, maybe make sure I’m thinking about the numbers right here. I was trying to connect $1.73 billion of total U.S. capital per the release with the $1.375 billion in the Bakken and the remainder being in the Gulf of Mexico. I’m assuming some of that being for exploration. So I guess, what’s being spent in the U.S. outside of the Bakken and the Gulf of Mexico if anything? And how would you break out the $1.73 billion between the Bakken and the Gulf of Mexico?

[John Rielly:]

So let’s – so you have $1.730 billion, you’re saying in the U.S. right? So you have $1.730 billion back out the Bakken, which is $1.375 billion, right, in production. And you’re going to back out $1.35 billion for the Gulf of Mexico, right. So then the rest of that amount is in exploration. That can be wells being drilled or seismic being spent. So that approximate $200 million that you have left relates to exploration.

[Michael Hall:]

Sure. Okay. And that exploration is all in the Gulf?

[John Rielly:]

In the Gulf, correct. At U.S. piece, correct.

[Michael Hall:]

Okay. Thank you.

[Operator:]

Your next question comes from the line of Paul Cheng with Scotiabank.

[Paul Cheng:]

Hey guys. Good morning. I apologize that I joined late. So if my questions have already been answered, just let me know. So I would just look at the transcript. John, I think two quick questions for you. On the accounting, the hedging premium amortization, the $70 million a quarter, is that pretax and after? And also from an accounting standpoint it seems in Guyana, you have the government willing to pickup the income. So when you guys reported, are you going to report that the corresponding tax as it grows up and then that you report it also with the tax or that you just don’t report any tax at all. How is the accounting treatment going to be?

[John Rielly:]

Okay. So first on the hedges, it is pretax and post-tax. So that will be the same amount, because we have a valuation allowance against our net operating losses in the U.S. So that will be the same number. In Guyana, we do pay taxes. It’s in the entitlement of our contract. So the taxes are embedded in our entitlement, effectively reducing our entitlement. And therefore, what we do then with our entitlement for financial reporting purposes is disaggregate that, and then show the tax and gross it up from relating to that. I can walk you through that more after the call, but that is how we are doing it.

[Paul Cheng:]

Yes. Because I think that’s how Apache have done in Egypt. I just wanted to make sure that that’s the same methodology because that’s how we modeling right now.

[John Rielly:]

Yes. That is how we’re working. Happy to discuss that further, we can do that.

[Paul Cheng:]

Okay. And Greg, when I’m looking at your production guidance that seems conservative. Is there any area that maybe we have a bit of more of the upside?

[Greg Hill:]

I think you probably miss the – you probably missed the start of the call where we kind of went through the shutdowns. Again, Tioga Gas Plant down 45 days and then a heavy maintenance buried in the Gulf of Mexico where we have two of our big assets down 30 days in the second quarter. So that’s really kind of what reduced our normal capacity of our production with those two shutdowns.

[Paul Cheng:]

Okay. I will read the transcript. And then the final one, have you guys booked any additional reserve related to the Liza 1 last year?

[John Rielly:]

We booked a minor amount for the wells that we were drilled here. Again, rule of thumbs, Paul probably we’ve got a third of the reserves on the books right now for Phase 1. And then as we get the dynamic data, see how the injection goes, we’ll begin to pick up additional reserves.

[Paul Cheng:]

All right. Thank you.

[Operator:]

Your next question comes from the line of Pavel Molchanov with Raymond James.

[Pavel Molchanov:]

Guys, thanks for taking the question. So this year after about five years, you will begin to drill on a brand new exploration block Indiana. And given your experience on Stabroek, I’m curious, what kind of expectations should we be thinking about in terms of pre-drill estimates and the geology of this new acreage that you are going to be getting underway?

[Greg Hill:]

No. I think you’re referring to the Kaieteur Block, which is outboard of Stabroek, which we have a 15% interest in Exxon, the operator. See very similar play types that exist on the Liza block around the Stabroek Block. And in fact, we’ll split our first well a well called Tanager this year on that block, so stay tuned.

[Pavel Molchanov:]

Okay. All right, fair enough. And a question about Hess Midstream. So now that the Bakken is very close to it, if it’s not reaching plateau. What’s going to be the dropdown model for the MLP if the underlying production is essentially flat-lining?

[Greg Hill:]

So for Hess Midstream now, it’s not an MLP and all the assets in North Dakota have been acquired by the Midstream, because we completed that transaction in the fourth quarter. So they now have all the gathering facility there and the Tioga Gas Plant. So from the old dropdown model that won’t be happening going forward. So what you do have here is this growth that we have. So in the Bakken, obviously, we’re going from 180,000 to 200,000 barrels a day, they’re going to pick up that growth, the Hess Midstream picking up that. Then as you know, the flaring regulations get tighter and tighter as we move on in North Dakota. And so what Hess Midstream is doing now is they’ve completed the LM4 plant and so picked up additional gas processing capacity there. We’re doing the expansion of the Tioga Gas Plant. And so that’s going up to 400 million cubic feet a day and it is looking to pick up third-party business as these flaring regulations get tighter and tighter and we are in a good infrastructure position in a good position to pick up that. So there’s a lot of growth going from there and they’ll look for other opportunities up there in North Dakota.

[Pavel Molchanov:]

All right. Appreciate it guys.

[Operator:]

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

[Brian Singer:]

Thank you. Good morning. Can you talk about the benefits and risks in Guyana, co-development of FPSOs and how discussions and plans with the operator are evolving, if at all? As you ramp up the first FPSO and you gain greater insight into the reservoir and processes. How on the table is this when you look out to FPSO three, four, five or beyond?

[Greg Hill:]

No. I think, Brian, the current strategy, which we agree with is, the design one, build many, because you can get such leverage of learnings as you go from vessel one to two to three, right? Now, what is likely going to happen is the timeframe between those vessels will begin to collapse. So from a cadence of maybe one a year, maybe becomes every nine months or potentially even every six months, as you get out in time. That’s what those synergies will do for you. So that’s what we really see. We don’t really see doubling or tripling up because that’s very inefficient. But rather design one, build many that continue to collapse the timeframe based on efficiencies.

[John Hess:]

Yes. And just to embellish on that. It’s really a phased approach to be capital efficient. ExxonMobil has done a great job of optimizing the development, lowering the costs, the learnings from ship one, help us in ship two and that will continue in ship three. So we’re really looking at a phased approach, but as Greg said, maybe with more compression of the timeframe. I just want to remind everyone, the 8 billion barrels of oil equivalent we talked about, we’ve had 16 successes. So it’s basically a 500 million per discovery. And that’s world-class and it’s got very low cost, very high returns. And ExxonMobil is doing a great job moving the project forward.

[Brian Singer:]

Great. Thanks. And then John, in your opening comments, you talked about cash flow overtime going to dividend increases and opportunistic share repurchase. Is there any change in the timing of when you would expect to consider that? Is that still when you get more indifferent cash flow mode post or with the startup of Phase 2 in Guyana? Or is that something that we could see earlier or later than that?

[John Rielly:]

No, I would say right now stick with our guidance that it’s going to be timed with Phase 2 coming online. Again that is the big inflection point for us from a free cash flow and earnings standpoint.

[John Hess:]

And the priority would be on increasing the dividend as the first call.

[Brian Singer:]

Great. Thank you.

[Operator:]

Your next question comes from the line of Vin Lovaglio with Mizuho Securities. Mr. Lovaglio, your phone may be on mute.

[Paul Sankey:]

Hello? Hi. Sorry, it’s Paul Sankey here. Can you hear me?

[John Hess:]

Yes, we can hear you Paul.

[Paul Sankey:]

Sorry about that. I got myself on mute. Guys you put out a note on the ESG and oil and gas, and you attested very, very well in terms of certainly your disclosures. Can you talk a little bit about some of the areas where you think you can still get better? And I’m specifically thinking about flaring. And beyond that could you talk about the impact of Guyana and how that will change some of the metrics that you do such a great job of disclosing? Thanks.

[John Hess:]

Thank you, Paul. Obviously, ESG sustainability is core value for the company. We’ve been doing a sustainability report for 22 years. We’re honored and proud to be an industry leader. We want to make sure we continue that leadership role. As we look at our flaring, let’s say in the Bakken, we’re ahead of the state limits and we have a program in place to continue that. And we’re looking at updating our sustainability efforts in terms of the environment. And we’ll be coming out with some new targets within the year for the next five years. So that’s a work in progress. But we always want to stay ahead of the regulations. And in terms of Guyana, the gas is basically reinjected. Again, ExxonMobil does a great job, minimizing the flaring in startup, et cetera. But the majority of gas is reinjected, so there’s really not an issue there. And one of the things we’re going to be looking at in Guyana is how can we help the country going forward in social responsibility, which is something that’s very important to our company and our board and every employee.

[Paul Sankey:]

Got it. John, thanks very much for that. And then a follow-up on the previous hedging question, totally different subject. How do you expect that hedging program that has sort of changed around a little bit overtime? I wonder how you expect Guyana to affect that going forward and whether or not you will have a different hedging strategy, let’s say in perhaps five years time? Thanks.

[John Rielly:]

Sure. I mean, we do look at it, Paul, year-to-year and make our decisions on our hedging requirements. And right now, obviously with the investment still going in for Guyana until we get to that Phase 2, we wanted to put a significant amount insurance on to ensure we fund that. As we move forward and we get to more free cash flow, we’ll still be, obviously have a heavy oil portion in our portfolio. We’ll make those decisions year-to-year and we could make some different decisions at that point in time.

[Paul Sankey:]

Thank you, guys.

[Operator:]

Thank you very much. This concludes today’s conference. Thank you for your participation. You may now disconnect. Have a great day.