赫斯 (HES) 2020 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the First Quarter 2020 Hess Corporation Conference Call. My name is May, and I will be your operator for today. (Operator Instructions) 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.

Thank you, May. Good morning, everyone, and thank you for participating in our first quarter earnings conference call. Our earnings release was issued this morning and is on our website, www.hess.com. I would first like to express our hope that all of you listening and your families are safe and well. Today's conference call contains projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess' annual and quarterly reports filed with the SEC.

In light of the COVID-19 pandemic and reduced spending plans we've put in place, many of the forward-looking statements from our previous presentations and investor materials have changed and should not be relied upon. We will provide updated guidance during this call. As a result of the COVID-19 pandemic, our operations and those of our business partners, service companies and suppliers have experienced and may continue to experience adverse effects, including disruptions, delays or temporary suspensions of operations and supply chains, temporary closures of facilities and other employee impacts. In addition, the pandemic has adversely impacted and may continue to adversely impact our oil demand and prices, export capacity and the availability of commercial storage options, which could lead to further curtailments and shut-ins of production by our industry. To the extent we or our business partners, service companies and suppliers experience these or other effects, our production, liquidity, financial condition, results of operations and future growth prospects may be adversely affected. The time line and potential magnitude of the COVID-19 pandemic is currently unknown. To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many other risks described in our annual report on Form 10-K for the year ended December 31, 2019.

Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.

On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. In compliance with social distancing protocols, we are conducting this call remotely, so please bear with us. In case there are audio issues, we will be posting transcripts of each speaker's prepared remarks on www.hess.com, following the presentation.

I'll now turn the call over to John Hess.

Thank you, Jay. Good morning, and welcome to our first quarter conference call, and we hope you and your families are well and staying healthy. Today, I will discuss our strategic response to the market downturn and the steps we are taking to manage in a sustained period of low oil prices. Then Greg Hill will discuss our operations and John Rielly will follow to review our financial results.

As we all know, the world has been battling a global pandemic and the danger it poses to society. Our hearts go out to those who have lost loved ones to COVID-19 and also to those who are struggling with the loss of jobs. Our top priority throughout this crisis is the safety of our workforce and the communities where we operate. Our multidisciplinary Hess emergency response team has been overseeing our plans and precautions to reduce the risk of COVID-19 in our work environment. We are grateful to every health care worker and first responder for all they are doing during this very difficult time.

In addition, the pandemic has had a severe impact on the near-term oil demand, resulting in a sharp decline in oil prices. Our priorities in this low-price environment are to preserve cash, preserve capability and preserve the long-term value of our assets. In terms of preserving cash, we came into 2020 with approximately 80% of our oil production hedged, with put options for 130,000 barrels per day at $55 per barrel WTI, and 20,000 barrels per day at $60 per barrel Brent. To maximize the value of our production, we have chartered 3 very large crude carriers or VLCCs to store 2 million barrels each of May, June and July Bakken crude oil production, which we expect to sell in Asia in the fourth quarter of 2020. As announced on March 17, we further strengthened the company's cash position and liquidity through a $1 billion 3-year term loan underwritten by JPMorgan Chase. We also have a $3.5 billion undrawn revolving credit facility and no material debt maturities until the term loan comes due in 2023. We have further reduced our 2020 capital and exploratory budget down to $1.9 billion, a 37% reduction from our original budget of $3 billion. This reduction will be achieved primarily by shifting from a 6-rig program to 1 rig in the Bakken by the end of this month and the deferral of certain exploratory and development expenditures in Guyana. Continuing operating 1 rig in the Bakken, our largest operated asset, will help us preserve our capability in lean manufacturing, which over the years has generated significant cost efficiencies and productivity improvements. We plan to stay at 1 rig until WTI oil prices stabilize in a $50 per barrel range. In terms of preserving long-term value of our assets, our top priority is Guyana, which is one of the industry's most attractive investments.

On the Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator, we have made 16 discoveries since 2015. The current estimate of gross discovered recoverable resources for the block stands at more than 8 billion barrels of oil equivalent, with multibillion barrels of exploration potential remaining. The Liza Phase 1 development achieved first production in December and is expected to reach its full capacity of 120,000 gross barrels of oil per day in June.

The Liza Phase 2 development remains on track for a 2022 start-up, with a production capacity of 220,000 gross barrels of oil per day. Development of the Payara field with a production capacity of 220,000 gross barrels of oil per day has been deferred 6 to 12 months pending government approval to proceed. In addition, pandemic-related travel restrictions have temporarily slowed our drilling campaign in Guyana. As a result, our production objective of more than 750,000 gross barrels of oil per day has been moved into 2026.

In summary, our company is in a strong position to manage through this low-price environment and to prosper when the oil market recovers with our low cost of supply and high-return investments that will drive material cash flow growth and increasing financial returns.

Finally, we want to thank our employees for their strong commitment to operating safely and reliably during this pandemic. We are deeply proud of every member of our team and confident in our ability to meet the challenges ahead.

I will now turn the call over to Greg for an operational update.

Thanks, John. I'd like to provide an update on our operations and additional detail on our response to the significant decline in oil prices. First, I'd like to describe the actions we're taking to protect the health and safety of our workforce and maintain business continuity in the midst of the global pandemic. A cross-functional Hess response team has been implementing a variety of health and safety measures in consultation with suppliers and partners, which are based on the most current recommendations by government and public health agencies. This includes enhanced cleaning procedures, travel restrictions, extended work schedules at offshore platforms and social distancing initiatives such as remote working and reducing the number of personnel on work sites wherever possible. As a result of these measures, I am pleased to report that to date, we've had no reported cases of COVID-19 among Hess employees.

Turning to our operational results for the quarter. We delivered strong performance across our portfolio and especially in the Bakken. Company-wide net production averaged 344,000 barrels of oil equivalent per day, excluding Libya, which was above guidance of 320,000 to 325,000 per day. In the second quarter, we expect net production to be in the range of 310,000 to 315,000 barrels of oil equivalent per day, excluding Libya. This reduction from the first quarter is due to low nominations in Southeast Asia caused by COVID demand impacts, non-operated well shut-ins in the Bakken, and plannedmaintenance shut-downs in the Gulf of Mexico. For the full year 2020, net production is forecast to average approximately 320,000 barrels of oil per day, excluding Libya.

In the Bakken, we are currently operating two rigs and expect to be down to one rig by the end of this month. Our plan is to maintain at one rig until oil prices move above $50 per barrel on a sustained basis. Operating one rig will allow us to maintain key operating capabilities that we have worked very hard to build over the years, both within Hess and within our primary drilling and completion suppliers. Bakken capital spend is now expected to be approximately $740 million in 2020. And assuming a one rig program in 2021, Bakken capital spend would drop to approximately approximatlet $300 million next year.

In the first quarter, our Bakken team delivered strong results,capitalizing on the success of our plug and perf completion designs and mild weather conditions. Before reducing the rig count, we achieved our goal of 200,000 barrels of oil equivalent per day for 11 days in March, well ahead of schedule, demonstrating the exceptional production capacity of our Bakken position. First quarter Bakken net productionaveraged 190,000 barrels of oil equivalent per day, an increase of more than 46% from the year ago quarter, and above our guidance of approximately 170,000 barrels of oil equivalent per day.

In 2020, we now expect to drill approximately 70 Bakken wells and to bring approximately 110 new wells online. We plan to complete wells that are drilled and to keep wells online unless netback prices drop below variable cash production costs, or we are physically unable to move the barrels. In the second quarter, we forecast that our Bakken net production will average approximately 185,000 barrels of oil equivalent per day. For the full year 2020, we continue to forecast net production to average approximately 175,000 barrels of oil equivalent per day. Assuming a one rig program through next year, we forecast net Bakken production in 2021 will average between 155,000 and 160,000 barrels of oil equivalent per day, approximately 10 percent lower than this year.

We continue planning for the Tioga Gas Plant turnaround in the third quarter of 2020, while closely monitoring potential COVID-19 risks.

Moving to the offshore. In the deepwater Gulf of Mexico first quarter net production averaged 74,000 barrels of oil equivalent per day. The Esox-1 well, which came online in February, is expected to reach its plateau rate by the end of the second quarter. No other production wells are planned to be drilled in 2020. We will participate with a 25% working interest in the BP-operated Galapagos Deep exploration well, expected to spud later this month. This is a hub-class cretaceous-aged opportunity in the Mississippi Canyon area.

In the second quarter, we forecast that Gulf of Mexico net production will average between 65,000 and 70,000 barrels of oil equivalent per day, reflecting planned maintenance shut-ins at Baldpate and Stampede. Planned 30-day shutdowns at Conger and Llano have been deferred to the third quarter. For the full year 2020, Gulf of Mexico net production is forecast to average approximately 65,000 barrels of oil equivalent today. In the Gulf of Thailand, production in the first quarter was 58,000 barrels of oil equivalent per day. During April, natural gas nominations were reduced due to slower economic activity associated with COVID-19. As a result, we now forecast second quarter net production to average approximately 35,000 barrels of oil equivalent per day and the full year 2020 to average approximately 50,000 barrels of oil equivalent per day.

Now turning to Guyana. Our discoveries and developments on the Stabroek Block are world-class in every respect, with some of the lowest break-even oil prices in the industry. The adjustments we have made elsewhere in the portfolio are designed to protect the long-term value of this extraordinary asset. Production from Liza Phase 1 commenced in December 2019 and in the first quarter averaged 58,000 gross barrels of oil equivalent per day, or 15,000 barrels per day, net to Hess. As of this week, gross production has ramped up to approximately 75,000 barrels of oil and is expected to reach its full capacity of 120,000 gross barrels of oil per day in June. Liza Phase 2 will utilize the Liza Unity FPSO, which will have the capacity to produce up to 220,000 gross barrels of oil per day. Despite some pandemic-related delays, the project is progressing to plan, with about 70% of the overall work completed and first oil remains on track for 2022. As announced by ExxonMobil, some activities for the planned Payara development are being deferred pending government approval, creating a potential delay in production start-up of 6 to 12 months.

As a result of pandemic-related travel restrictions in Guyana, ExxonMobil has temporarily idled two drillships, Stena Carron and the Noble Tom Madden. These vessels are expected to resume work by June. Development activities are continuing with the Noble Don Taylor and Noble Bob Douglas drillships. The Stabroek partnership has deferred the addition of a fifth drillship this year in Guyana. The deferral of Payara and the reduced drilling activities due to COVID-19 travel restrictions has resulted in a reduction to our 2020 Guyana capital and exploratory budget of approximately $200 million.

In closing, the team once again demonstrated excellent execution and delivery across our asset base under very challenging conditions. I'd like to personally thank all of our employees for their hard work and dedication. We have taken actions to ensure the health and safety of our workforce and to ensure that our company is well positioned for this historic downturn and for the recovery that is sure to come. I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today, I will discuss our ongoing efforts to preserve cash in this low price environment, review our first quarter financial results and update our 2020 guidance. At quarter end, excluding Midstream, cash and cash equivalents were $2.1 billion, and our total liquidity was $5.9 billion, including available committed credit facilities, while debt and finance lease obligations totaled $6.6 billion. Our fully undrawn $3.5 billion revolving credit facility is committed through May 2023. We have taken prudent steps to improve our liquidity and reduce costs. As John mentioned, we have cut our 2020 E&P capital guidance another $300 million to $1.9 billion, which is $1.1 billion below our initial guidance from the beginning of the year. On March 16, 2020, we entered into a $1 billion 3-year term loan agreement with JPMorgan Chase Bank. Aside from the term loan, which matures in March 2023, we have no other near-term debt maturities.

We also have more than 80% of our remaining 2020 oil production hedged with $55 WTI put options for 130,000 barrels of oil per day and $60 Brent put options for 20,000 barrels of oil per day. At April 30, 2020, realized settlements to date were approximately $300 million, plus the unrealized fair value of open contracts of $1.05 billion, results in a total realized and unrealized value of approximately $1.350 billion before considering premiums paid.

Finally, in response to the current low oil price environment, we have actively cut costs to align with our lower planned activity levels and to remove discretionary spend, which has contributed to a decrease in our projected full year 2020 E&P cash operating costs of approximately $225 million. We are continuing to look for further capital and operating cost reductions.

Now turning to results. We incurred a net loss of $2.433 billion in the first quarter of 2020, including noncash impairment and other after-tax charges of $2.251 billion, resulting from the low price environment compared to a net loss of $222 million in the fourth quarter of 2019. On an adjusted basis, which excludes items affecting comparability of earnings between periods, we incurred a net loss of $182 million in the first quarter of 2020, compared to an adjusted loss of $180 million in the previous quarter.

Turning to E&P. On an adjusted basis, E&P incurred a net loss of $120 million in the first quarter of 2020, compared to a net loss of $124 million in the previous quarter. The changes in the after-tax components of adjusted E&P results between the first quarter of 2020 and fourth quarter of 2019 were as follows: lower realized selling prices reduced results by $147 million. Higher sales volumes improved results by $22 million. Lower cash costs improved results by $78 million, lower exploration expenses improved results by $66 million. All other items reduced results by $15 million. Overall increase in first quarter results of $4 million.

Turning to Midstream. On an adjusted basis, the Midstream segment had net income of $61 million in the first quarter of 2020, compared to $49 million in the previous quarter, reflecting higher throughput volumes. Midstream EBITDA on an adjusted basis and before noncontrolling interest amounted to $193 million in the first quarter 2020, compared to $157 million in the previous quarter.

Turning to corporate. On an adjusted basis, after-tax corporate and interest expenses were $123 million in the first quarter of 2020, compared to $105 million in the previous quarter, which included capitalized interest expense of $11 million of Liza Field. Capitalized interest for the Liza Field ceased upon first production in December 2019. First quarter 2010 corporate expenses included a nonrecurring charge of $7 million for legal costs related to former downstream businesses.

Now turning to guidance. For E&P, as previously mentioned, our second quarter net production is estimated to be in the range of 310,000 to 315,000 barrels of oil equivalent per day. With the unprecedented reduction in oil demand due to COVID-19, U.S. commercial storage is approaching capacity, resulting in a sharp decline in oil prices. To maximize the value of our production, we have chartered 3 VLCCs and plan to store 2 million barrels each of May, June and July Bakken crude oil production on the VLCCs and sell these barrels in the fourth quarter. We have hedged the contango in the forward Brent curve for these barrels. We do not expect to shut in any of our operated production due to our marketing arrangements and our VLCC storage.

From an accounting standpoint, sales volumes will be underlifted by approximately 4 million barrels of oil in the second quarter and 2 million barrels of oil in the third quarter as a result of using the VLCCs. While we will receive cash for settlement gains as the put option contracts mature, the net realized gain on contracts associated with the 6 million barrels of underlifted oil comprised of the cash settlement less the associated amortization of premiums paid will be deferred until the volume stored in the VLCCs are sold. We project E&P cash costs, excluding Libya, to be in the range of $10 to $10.50 per barrel of oil equivalent for the second quarter and for the full year of 2020, down from previous full year guidance of $11.50 to $12.50 per barrel oil equivalent primarily due to cost reduction efforts.

DD&A expense, excluding Libya, is forecast to be in the range of $14 to $15 per barrel of oil equivalent for the second quarter and $15 to $16 per barrel of oil equivalent for the full year of 2020, down from previous full year guidance of $16.50 to $17.50 per barrel of oil equivalent as a result of the asset impairment charges. This results in projected total E&P unit operating costs, excluding Libya, to be in the range of $24 to $25.50 per barrel of oil equivalent for the second quarter and $25 to $26.50 per barrel of oil equivalent for the full year of 2020.

Exploration expenses, excluding dry hole costs, are expected to be in the range of $35 million to $40 million in the second quarter, with the full year 2020 guidance now expected to be $145 million to $155 million, down from previous full year guidance of $210 million to $220 million. The Midstream tariff is projected to be in the range of $215 million to $230 million in the second quarter and full year 2020 guidance in the range of $905 million to $930 million, down from previous full year guidance of $940 million to $965 million. E&P income tax expense, excluding Libya, is expected to be in the range of $5 million to $10 million for the second quarter and in the range of $20 million to $30 million for the full year of 2020, down from previous full year guidance of $80 million to $90 million.

For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be in the range of $40 million to $50 million in the second quarter and full year 2020 guidance in the range of $185 million to $195 million, down from previous full year guidance of $205 million to $215 million.

For corporate. Corporate expenses are estimated to be in the range of $25 million to $30 million in the second quarter and full year 2020 guidance in the range of $115 million to $125 million is unchanged. Interest expense is estimated to be in the range of $95 million to $100 million for the second quarter, with the full year 2020 guidance expected to be $375 million to $385 million, up from previous full year guidance of $350 million to $360 million due to the new term loan.

This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

(Operator Instructions) We have our first question from Ryan Todd, Simmons Energy.

Maybe if I could start with the Bakken. Obviously, very strong first quarter production. You gave some guidance around the rest of the year. I think some of the numbers cut out as Greg was talking, could you maybe get some clarity around what completion activity looks like. With the 1 rig running, will you be building ducts you're completing through? And maybe if you can repeat what the 1-rig CapEx number looks like in 2021?

Yes, Greg, why don't you give it a try and just maybe we speak just a little slower to let the phones catch up. And if we don't get it, John Rielly will follow up.

Okay. So Ryan, let me start with the capital for the year. The capital for the year in the Bakken will be $740 million. And in that $740 million, we expect to drill approximately 70 Bakken wells and bring 110 new wells online, and we do not plan to build any ducts. We plan to drill and complete all wells that we drill throughout the year and into next year.

Great. And maybe if I could, on the -- maybe for you, John Rielly or either one, could you provide some color on the decision to charter the VLCCs in terms of how you view the relative pluses and minuses of storing the barrels on the ground versus on the VLCC? And what sort of pricing -- or is there a price signal that you need to sell the barrels into the fourth quarter? Or is that all already set up and contracted?

So the contango of the difference of the current months in Brent and the future months in Brent, let's say, out to December is already hedged. So we've locked that in. But to maximize the value of our Bakken production and preserve our cash flow for this year, we were able to use our marketing capabilities and our firm transportation to U.S. Gulf Coast to charter three VLCCs to load, store and export 2 million barrels per month of Bakken crude oil in May, June and July. And basically, that spread has been fixed in Brent. On top of it, it is Brent-based pricing, which obviously provides some advantage instead of WTI, and we plan to market the oil in Asia. In Asia, demand for oil is already improving. So it is possible that we sell the oil before the fourth quarter, depending upon market conditions. But the point is we've hedged it, we've locked it in and, basically, the contango in the market and the fact that we used Brent-based pricing offsets the cost of the charters. There're three different charters, different terms, different rates, but the contango in the market that we've hedged and the fact that it's Brent-based pricing, not WTI, more than offsets the cost of the charters.

Next question, Doug Leggate from Bank of America.

I hope everybody is doing well out there. I guess, my first question would be for Greg, probably. Greg, the resilience of the Bakken has obviously left you with your guidance unchanged. But what does that look like going into 2021 in terms of the underlying production capacity decline rate with the 1-rig program? And I've got a follow-up for Mr. Rielly, please.

Yes. As I mentioned in my opening remarks, if you keep a one rig program through 2021, it's about a 10% decline rate for the Bakken.

No, I apologize, I think I missed that. So let me take a second pop at it then, if I may. If the capacity was already north of 200,000 barrels a day, and you hadn't extended that growth through the back end of this year, does that say the trajectory through the back end of 2020 into 2021 as the exit rate is risked higher?

Yes. Well, the exit rate, we're projecting at the end of the year is 175,000 barrels a day, Doug. So the behavior of it this year is relatively flat because, of course, we built quite a backlog with the 6 rigs. And we're going to go ahead and complete those wells this year.

Repeat that number, Greg, it got muffled again.

Okay, John.

Your exit rate.

Again, the exit rate is going to be 175,000 barrels a day. And the reason it's relatively high is because, with the 6 rigs, we built a fair number of wells to complete. And our plan, of course, is to complete those.

I appreciate the color. I know it's tricky in the mountains, Greg. So I'll move on to Mr. Rielly, if that's okay. John, the -- you were very early to lock in the hedges for this year, and it's obviously paying huge dividends at this point. But as you look into 2021, at the current strip price, it would still have you with a bit of a cash burn if you maintain the current level of spending. So can you walk us through what your flexibility is in the event that the current strip turned out to be right, obviously, we all hope it isn't. But where else do you -- are you able to do things around because the cash burn could be quite meaningful.

So let me first start with, you're right, we've got a great hedge position this year, and we'll continue to monitor the market as we go through the year, and we'll clearly look to put on hedges for 2021 as we get closer to the end of the year. Hopefully, price is way better, and then we can get hedges on. But let me then follow your question along, should prices stay lower. So everything we've done and the plans we put in place is set up for a 2-year low price scenario. With the term loan, with the hedges this year, with the reductions in capital that we've made this year. And if we were looking at strip prices going -- these prices, you said, going into next year, our production -- I mean, sorry, our capital spend should be flat to potentially down a little and it's due to -- with the 1 rig in the Bakken, as Greg mentioned, it's $740 million this year, going down to $300 million with a one-rig program next year. And then obviously, it will be offset by some increase in Guyana capital spend. So we are looking for capital to remain flat, but we'll be looking at further capital reductions, further operating cost reductions as we move through this year and into 2021, especially if prices stay low.

And then obviously, we do have the one rig. It's not something we want to do as you move into 2021. However, if prices did stay low, it's something that we could reduce down to 0, at least for a period of time and bring back on. As Greg had mentioned, we've spent a lot of time building up this lean manufacturing capability. So we really don't want to do that, but it's clearly a lever that we can look at as we move into 2021. So I think that's why we are constantly looking for other things that we can do.

But I also would tell you is the plans we put in place are set for this low price environment to get us all the way through 2021, without incurring any additional debt through the end of that year and then being in a place where phase 2 starts up right there in 2022, and we're getting an additional, say, 65,000 barrels of Brent-based oil from Liza Phase 2. And the hope would be, by 2022, you're getting a bit better prices there. So we really have put this plan in place in everything we're doing, even though we're continuing to fine-tune and try to cut costs but to get us through this 2-year low price environment.

John, if I just may tag on very quickly to that. And it's maybe 1 for John Hess, actually. One of your peers this morning or last night, I should say, talked about their dividend and suspended their dividend. I think there's semantics between suspending and canceling because we know the cash flow capacity for Hess is about to inflect significantly higher. But in a scenario where we face an extended period of depressed prices, is the dividend an option in terms of at least temporarily a source of incremental cash? How are you thinking about that? And I'll leave it there.

Yes. Doug, I believe the company you're talking about is in a much different financial position than we are. So I wouldn't want to try to compare us to anybody else. But having said that, look, if oil prices are severely depressed for a long enough period of time, all options would be on the table. Having said that, we think we've taken the steps to put ourselves in a strong financial position, as John said, and we are committed to our dividend and certainly are not contemplating a cut in it at this time.

Next in line is Devin McDermott, Morgan Stanley.

I wanted to ask the first one on the Bakken and clarifying some of the remarks, I think, Greg made during his opening remarks here, and that's on just the point at which you'd start to bring back activity in the Bakken. And Greg, I think you said that it was around $50 WTI, where you would begin to add from the current 1-rig cadence that you're at right now. I was wondering if you just would clarify if I heard that correctly. And then two, a bit more detail on how you think about the economics and decision-making behind beginning to increase CapEx to the extent we see higher prices in the future.

Yes. So I switched phones. So hopefully, everybody can hear me much better. So yes, what we'd have to see is -- what we say is a strong stable $50 oil price before we'd add a rig back in the Bakken. And obviously, when we got to that point, we would decide at what pace and what cadence we would add those back. So we would -- similar to what we did last time during the downturn where we dropped down to 2 rigs, we slowly added those rigs back in order to maintain that lean manufacturing edge and not have our cost [rate] or whatever. So as John said in his opening remarks, that is one of our key strategies this year, is to be able to maintain that capability so that we can smoothly ramp the Bakken, hopefully in the future.

Got it. That makes a lot of sense. And my follow-up relates to the Bakken and all the rest of the portfolio. How should we think about the level of spending required to hold production flat. In the Bakken, how do you think about that activity level now going from the efficiency gains and overall cost deflation that you've seen? And then for the rest of the portfolio, ex Guyana, just an update on what that maintenance level of spending is.

John, why don't you take that one?

Yes, John?

Sure. So to get to, let's call it, a flat production level now at the lower, and it's somewhere around, let's say, call it, 3 rigs, and it will be right around that level. And you can always kind of, as a rule of thumb, put $200 million per rig. So you're talking about $600 million then maybe to get it back and keep it at a flat level where we're at right now. Once you go back to, say, 4 rigs, we could start to grow it from this level, again. And you saw the capability that we have in the Bakken in that first quarter to deliver when, obviously, weather was good, but just our operations just ran at a really high level. And so if you started going back to 4 rigs, you could begin to grow this again. But again, as Greg said, getting a solid $50 WTI price in place if we start putting it back, 3 rigs, we could sustainably hold the level, and then we can decide from there whether to grow.

Great. And the rest of the portfolio in terms of holding everything else flat? How should we think about that maintenance CapEx level of spending?

So let's just talk JDA and North Malay Basin first. Under normal operations there, we've always talked about somewhere with that $150 million to $200 million that can come in bunch as the capital because you're putting wellhead platforms there, but you can pretty much hold that flat at that 60,000 to 65,000 barrels a day for a number of years, basically out through the end of the PSCs with that type of capital levels. The GOM is the interesting one because, again, what we had been saying is we need to do some tieback wells over time, and we could hold it flat, let's say, for 3 to 5 years, if we were putting in these tieback wells like Esox, the successful Esox well, we could hold that Gulf of Mexico flat now in that 65,000-type level for a number of years.

Now as Greg said on his opening remarks, we're not drilling in the Gulf of Mexico. We're not doing tieback wells, and we're not -- there's no plan for us right now in 2021 in this low price environment to put a tieback well in. So with the additions we've done this year, you won't get as much of a decline. Next year, you're still going to get some declines, you could get somewhere in -- I'm going to call an approximate 10% decline for the Gulf of Mexico going into 2021. And then if we don't put further wells in there, the Gulf of Mexico will continue to decline. So our original goal and we'll see when the prices get back to more appropriate levels is to get those tieback wells in. Greg mentioned, we have the exploration well. The Galapagos deep well that we're drilling -- a well that BP is drilling. We're a partner in. So we do have a very exciting Gulf of Mexico lease portfolio that we would like to get some exploration wells in over the next couple of years as prices get better. And then we do think we can grow the Gulf of Mexico production.

And then in Guyana you obviously know, we're going to be in a growth mode there. Phase 2 coming online early 2022, all on track for that. Then we've got the delay, 6 to 12 months delay in Payara. But as John Hess said in his remarks, growing at 750,000 barrels a day gross by 2026. So look, we've got a nice balance in the portfolio. So we're not just tied to the shale production. So obviously, we're reducing our rigs there, but we have the offsetting growth here coming in Guyana. And Southeast Asia can stay relatively flat with limited capital. And then the Gulf of Mexico will be down a bit.. As we see prices improve, we'll get back to work there. Great.

Next question is from the line of Paul Cheng, Scotiabank.

I have a couple. First, clarification. For John Rielly that, the Guyana production number that you guys show in the press release, is that including the tax barrel gross up?

So Paul, I don't know if you remember, at the end of last year, we put up some deferred tax assets with the start of first production, essentially NOLs. So there were a lot of expenses incurred in Guyana. So we've built up this NOL here at the start. So there, we'll be utilizing that NOL and do not expect any gross up tax barrels in 2020.

Okay. And going forward, should we assume there's a gross up tax barrel? And at that time, are you going to provide a number that in both what is the adjusted net to you and what is the report?

Yes, yes. We will get that number. So and again, we'll be disclosing the current taxes that are there in Guyana, along with that revenue adjustment. And yes, that will be something that will be available, and you will be able to see and model.

Okay. And on the -- I have to apologize that the mechanic on the VLCC storage, so we're going to have the underlift in the second and third quarter. So we will assume that the entire 6 million barrels, based on the current plan, is going to be an overlift in the fourth quarter? That -- what's the price that we should assume? I'm trying to understand how we expect that. And also in the second and third quarter, you actually already have the cash coming in because of the settlement, right? So is that going to show up in the working capital? Or is going to show up in the other line?

Correct. So let me start with the hedges. The cash, we will be receiving the cash from there, and that will show up in the working capital line. Then in the fourth quarter, when it is recognized because we'll defer the gain on that, that's when it will then come back out of working capital at that point. And to your question, again, yes, it's right. So we will have the underlift in the second and third, and you should assume in the fourth quarter that we will have the overlift of the 6 million barrels coming in the fourth quarter. And just so you know also, just going through the accounting. In the second and third quarters, we will have all -- you will see the production cost and the DD&A associated with the production of the 6 million barrels, that will be there. Then what we do is put it into inventory on the balance sheet and put a credit through our marketing line. So you will get to see the actual costs associated with it. Then when we lift in the fourth quarter, we'll remove the inventory and the cost of those barrels will go through the marketing line, and that's when we pick up the revenue as well.

Next is Roger Read from Wells Fargo.

I just was curious if we could get into the impacts of the deferrals done in Guyana thinking, first off, the near-term issues would be deferrals on the rigs, how that affects kind of overall economics of the wells. And the June start date, how good does that look at this point? Is there something specific we're waiting to see that, that is a good day to use, or are we at risk of further delays there?

Greg, why don't you grab that?

So Roger, in my opening remarks, I talked about that's solely COVID-19 related that those rigs have been idled, and that's purely to do with crew changes. And so in order to protect those crews, they're quarantining people for 14 days. So if you kind of run through all the math on that, ExxonMobil made the decision really to hot stack. We are on track to get both of those rigs running again by June. So we're in good shape, no worries there.

In terms of the wells, really no impact on the economics of the wells, right? I mean really what has been deferred is the start of Phase 2 drilling. And of course, the exploration that we want to get done as well. And so as we look forward now with 4 rigs going by June forward, there's really 3 objectives that we're trying to do. One is to finish the Phase 1 Yellowtail. Two is get 2 to 3 more exploration wells in the ground, including a couple that have tailed to go down and test the deeper -- or penetrate the deeper Santonian. And then the third objective is to continue drilling on Phase 1 and get started on Phase 2, producer drilling. So that's how the program is going to kind of layout between now and the end of the year.

Okay. Great. And then question, going back to the VLCC play here. I just want to make sure I understand what the ongoing risk reward is here? Or is everything, in the way you're thinking about the price realization when you actually physically deliver the barrels in the fourth quarter is already set? I guess what I'm trying -- is the volatility we've seen in the market, forward curve looks good today, but who knows when we get there, better or worse. And so I'm just trying to understand, again, are the barrels only weighing on physical delivery and the price is all set? Or are we still looking at additional price volatility as a reward or as a risk here?

No, it's a great question. Basically, look at it this way. We have our oil hedged already in the $55 and $60 range that I talked about. You add the contango. It is Brent based, and you get an advantage uptick for TI, and this would be originally TI based. And then you take off the VLCC charter. And when you do that, the price is set and you're actually getting a value uptick because of moving it out of the United States where oil is locked up into a market that will take it. So it's really to deal with the physical risk and the financial risk has pretty much been laid off.

Next question is from Arun Jayaram, JPMorgan.

John, I was wondering if you could provide maybe a little bit of perspective on where we're at in terms of the Guyana election and perhaps provide some details on how you and Exxon are adjusting your longer-term development exploration activities for a phase beyond pending governor's approvals, COVID-19. And specifically, I was wondering how is this impacting, how you're thinking about the (inaudible) timing on the FPSOs as well as the longer-term thoughts versus exploration versus development spend?

Yes. No. Thanks, Arun, for that question. In terms of Guyana, and the political landscape, the recount for the Guyana national election actually resumed yesterday. And United States and international observers have encouraged this process to go to completion. So it will reflect the will of the Guyanese people. And we expect a transparent election results in the weeks ahead. And at that time, when there is a new sitting government, a newly elected sitting government, we would assume the first, second and third priority for us in Exxon and CNOOC is to move the approval for the Payara development forward, working with the government. And so that pretty much explains the 6- to 12-month delay on Payara. And then a combination of the COVID-initiated delays in staffing the rigs has made us have a slowdown for a few months. But as Greg said, we should be going back to a 4-rig program in June.

The first, second and third priority will be development wells, but then we'll start feathering in exploration wells and appraisal wells as well. So a temporary interruption, yes, but not a major one. And then we would move forward with our exploration and appraisal activities and development activities accordingly. On top of that, that 6- to 12-month delay in Payara will affect start-up of the fourth and fifth ship as we currently have it contemplated, such that we will have the -- we plan now on having the 5 ships and at least 750,000 barrels a day of oil production online in 2026 instead of 2025. So a delay, yes, but not a major one. And it certainly still is our top investment priority and the top priority for Exxon to move forward with the plans that we've outlined in the past, some minor delays but not major delays.

Great. And just a quickie for Greg. You see a big size Bakken beat in 1Q. Could you just give us maybe the drivers of the beat relative to your guidance? I know weather was pretty benign, but maybe thoughts on weather as well as the well productivity that you saw in the quarter?

Yes. So there was really 2 major things. One was the weather, which we had. So mother nature was kind to us in the first quarter, which is, as we all know, has a big impact sometimes in the Bakken. So we built some of that into our contingency, in our forecast for the first quarter. But even more important is the wells that we brought on in the fourth quarter just behaved really well. And so we had planned to convert those to rod pump during the first quarter. And in fact, we didn't need to because the wells still were flowing well through the first quarter. So we got a really nice production bump from the wells that were turned online in the fourth quarter, but also in the first quarter. So it was a combination of those 2 things that where they outperformed.

We have our next question from Pavel Molchanov, Raymond James.

Obviously, most of your CapEx cuts pertain to your domestic operations, and I suppose, Guyana as well. What about exploration? I'm particularly thinking Suriname, which was supposed to be kind of a late 2020 or early '21 story. Have you changed any of the medium-term plans for beginning drilling there?

Greg?

Yes, sure. No, our plans are still to drill that well in 2021 in Suriname.

Got it. Okay. Is that contingent on level of commodity prices?

No, I think that's -- the operator is in control of that and Kosmos, but the latest discussions we've had with them, we are still planning the well for 2021.

Next in line is Brian Singer, Goldman Sachs.

On Guyana, looking beyond phase 2, I realized that there are some understandable delays and phase 3 [cuts]. I wonder if there's any benefit that you could see or are seeing on the cost front. Can you talk to the cost environment that you're seeing for sanctioning longer-term deepwater offshore projects and whether you see any adjustments to that just as a result of the environment that we're at?

Yes. Greg, do you want to take that, please?

Sure. Yes. So Brian, as you know, the majority of services have been contracted, certainly for Phase 2 and also Phase 3. Now later on in time, as you get into other phases, there could be -- depending on commodity prices, obviously, there could be concessions there. But a large part of the contracts are already underway for, certainly, the activity in Guyana that we're doing now. Now as I look across our portfolio and kind of what we're seeing and we're in the midst of this, working with all of our contract partners now, suppliers to adjust to the activity, but also keep continuity of the crews and brings more costs out, we're seeing kind of on the order of 10% to 15%, and that is both in the offshore and the onshore parts of our business. So I think that's a reasonable number because as you know, those companies were potentially already distressed. So they don't have as much to give maybe as they did in the last downturn. So 10% to 15% is what we're seeing.

Great. And then my follow-up is with regards to the Malaysia [annual] gas demand. Highlighted some of the weakness that you're seeing here near term. Do you -- or do you get any sense as to whether there are secular impact here to demand and ultimately to production versus just these being cyclical on a sign of the current environment?

Yes, we definitely think it's one-off, and we already see demand recovering. But John Rielly, you want to elaborate?

Sure. No. That's what we are seeing. Obviously, Malaysia, they had their shelter-in-place, they call that MCO, the movement control order. They actually did lift it a little earlier than the original plan. So again, we do see this from a cyclical just standpoint here, kind of one-off. So you see the Q2 number, we are forecasting at 35%, almost kind of equal production out of NMB and JDA. And then we have a slow ramp forecasted for the rest of the year. And again, we just going back to the uncertainty around COVID-19 and the resulting business activity. But we are seeing some green shoots here. So we just do think it's more of a one-off.

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

Thank you.