Hess - Q1 2020
May 7, 2020
Transcript
Speaker 0
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. At this time, all participants are in a listen only mode. Later, we will conduct a question and answer session. 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.
Speaker 1
Thank you, Mae. 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 call contains projections and other forward looking statements within the meaning of the federal securities laws.
These statements are subject to known 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-nineteen 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-nineteen 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 timeline and potential magnitude of the COVID-nineteen pandemic is currently unknown. To the extent the COVID-nineteen 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 ks 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 Reilly, 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.
Speaker 2
Thank you, Jay. Good morning and welcome to our Q1 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 Reilly 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-nineteen 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-nineteen in our work environment. We are grateful to every healthcare 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 2,000,000 barrels each of May, June July Bakken crude oil production, which we expect to sell in Asia in the Q4 of 2020. As announced on March 17, we further strengthened the company's cash position and liquidity through a $1,000,000,000 3 year term loan underwritten by JPMorgan Chase. We also have a $3,500,000,000 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 $1,900,000,000 a 37% reduction from our original budget of $3,000,000,000 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. Continue to operating 1 rig in the Bakken, our largest operated asset, will help us preserve our capability 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 the 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 8,000,000,000 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 200 220,000 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 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.
Speaker 3
Thanks, John. I'd like to provide an update on our operational 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 business continuity in the midst of the global pandemic. A cross functional health 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 for personnel on work sites wherever possible.
As a result of these measures, I'm pleased to report that to date, we've had no over 2019 among HEPS 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 Cevia, which was above our guidance of 320,000 dollars to $325,000 per day. In the second quarter, we expect net production to be in the range of 310,000 barrels of oil equivalent per day excluding Libya.
This reduction from the Q1 is due to lower terminations in Southeast Asia caused by COVID demand impacts. Non operated well shut ins in the Gulf of Mexico. For the full year 2020, production is forecast to average approximately 320,000 barrels of oil per day excluding Libya. In the Bakken, we are currently operating 2 rigs and expect to be by the end of this month. Our plan is to maintain at one rate oil prices move above $50 per barrel on a sustained basis.
Operating 1 contained 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. Baja capital spend is now Bakken capital spend is now expected to be approximately $740,000,000 in 2020. And assuming a 1 program in 2021, Bakken capital spend would drop to approximately $1,000,000 next year. In the Q1, our Bakken team delivered strong results, success of our plug and perf completion designs and mild weather conditions. Before reducing the rig count 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 acquisition.
1st quarter Bakken net production, 90,000 barrels of oil equivalent per day, an increase of more than 46% from the year ago quarter, or guidance of approximately 170,000 barrels of oil equivalent per day. In 2020, we now expect to drill approximately 70 wells to bring approximately 110 new wells online. We plan to complete wells online unless netback prices drop below variable cash production costs or we are physically unable to move the barrels. In the Q2, we forecast that our Bakken net production will average to reach approximately 175,000 barrels of oil equivalent per day. Assuming a 1 rig program through next year, we forecast that our Bakken production in 2021 will average between 255,000 and 50,000 barrels of oil equivalent per day,
Speaker 4
approximately
Speaker 3
10% lower than this year. We continue planning for the Tioga Gas Plant turnaround in Q3 of 2020, while closely monitoring individual COVID-nineteen risks. Moving to the offshore. In the Deepwater Gulf of Mexico, FERC averaged 74,000 barrels of oil equivalent per day. The ESOX-one well, which came online in February, is expected to be at a plateau rate by the end of the second quarter.
No other production wells are planned to be We will participate with a 25% working DP operated Galapagos deep exploration well expected to spud later this month. This is a subclass Cretaceous aged in the Mississippi Canyon area. In the Q2, we forecast that Gulf of Mexico net production will average between 6,500,701,000 barrels of oil per day, reflecting planned maintenance shutdowns at Balde Peak. Planned 30 day shutdowns at Conger and Llano to defer to the Q3. For the full year 2020, Gulf of Mexico net production is forecasted to average approximately 65,000 barrels of oil equivalent per day.
In the Gulf of Thailand, production in the Q1 was 58,000 barrels of oil equivalent per day. During April, natural gas nominations were reduced due to slower economic activity associated with COVID-nineteen. As a result, we now have our 2nd 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
Speaker 4
per day.
Speaker 3
Now turning to Guyana. Our discoveries and developments on the Stabroek Block, world class in every respect, with some of the lowest industry. The adjustments we have made elsewhere in the portfolio affect the long term value of this extraordinary asset. Production from Liza Phase 1 commenced in 2019 and in the Q1 averaged 58,000 gross barrels of oil equivalent per day or 15,000 barrels of oil equivalent rate net oil per day net to half. As of this, gross 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 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. ExxonMobil, some activities for the planned Payara development are being deferred pending government approval, meeting a potential delay in production startup of 6 to 12 months. As a result of pandemic related travel restrictions in Guyana, ExxonMobil has temporarily idled 2 drillships, Tenakarum and the Noble Tom Madden. These vessels are expected to resume work by June.
The development activities are continuing of the Noble Don Taylor and Noble Bob Douglas drillships. The partnership has deferred the addition of the drillship. The deferral of Payara and the reduced drilling activities to COVID-nineteen travel restrictions has resulted in reduction to our 2020 Guyana capital and exploration budget of approximately $200,000,000 In closing, Clean once again 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 to ensure the health and safety of our workforce and to ensure that our company is well positioned for this historic downturn and that is sure to come. I will now turn the call over to John Reilly.
Speaker 5
Thanks, Greg. In my remarks today, I will discuss our ongoing efforts to preserve cash in this low price environment, review our Q1 financial results and update our 2020 guidance. At quarter end, excluding Midstream, cash and cash equivalents were $2,100,000,000 and our total liquidity was $5,900,000,000 including available committed credit facilities, while debt and finance lease obligations totaled $6,600,000,000 Our fully undrawn 3.5 $1,000,000,000 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 and P capital guidance another $300,000,000 to $1,900,000,000 which is $1,100,000,000 below our initial guidance from the beginning of the year.
On March 16, 2020, we entered into a 1,000,000,000 dollars 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 $300,000,000 plus the unrealized fair value of open contracts of $1,050,000,000 results in a total realized and unrealized value of approximately $1,350,000,000 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 and P cash operating costs of approximately $225,000,000 We are continuing to look for further capital and operating cost reductions.
Now turning to results. We incurred a net loss of $2,433,000,000 in the Q1 of 2020, including non cash impairment and other after tax charges of $2,251,000,000 resulting from the low price environment compared to a net loss of $222,000,000 in the Q4 of 2019. On an adjusted basis, which excludes items affecting comparability of earnings between periods, we incurred a net loss of 100 and $82,000,000 in the Q1 of 2020 compared to an adjusted loss of $180,000,000 in the previous quarter. Turning to E and P, on an adjusted basis, E and P incurred a net loss of $120,000,000 in the Q1 of 2020, compared to a net loss of $124,000,000 in the previous quarter. The changes in the after tax components of adjusted E and P results between the Q1 of 2020 Q4 of 2019 were as follows.
Lower realized selling prices reduced results by $147,000,000 higher sales volumes improved results by $22,000,000 Lower cash costs improved results by $78,000,000 Lower exploration expenses improved results by $66,000,000 All other items reduced results by $15,000,000 overall increase in 1st quarter results of $4,000,000 Turning to Midstream, on an adjusted basis, the Midstream segment had net income of $61,000,000 in the Q1 of 2020 compared to $49,000,000 in the previous quarter, reflecting higher throughput volumes. Midstream EBITDA on an adjusted basis and before non controlling interest amounted to $193,000,000 in the Q1 of 2020 compared to $157,000,000 in the previous quarter. Turning to corporate, on an adjusted basis, after tax corporate and interest expenses were $123,000,000 in the Q1 of 2020 compared to $105,000,000 in in the previous quarter, which included capitalized interest expense of $11,000,000 for the Liza field. Capitalized interest for the Liza field ceased upon first production related to former downstream businesses. Now turning to guidance.
For E and P, as previously mentioned, our Q2 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-nineteen, 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 score 2,000,000 of each of May, June July Bakken crude oil production on the VLCCs and sell these barrels in the Q4.
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 4,000,000 barrels of oil in the 2nd quarter and 2,000,000 barrels of oil in the 3rd quarter as a result of using the VLCCs. While we will receive cash for settlement gains as the put option contracts mature, the net price gain on contracts associated with the 6,000,000 barrels of under lifted 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 and P cash costs, excluding Libya, to be in the range of 10 dollars to $10.50 per barrel of oil equivalent for the Q2 and for the full year of 2020, down from previous full year guidance of $11.50 to $12.50 per barrel of oil equivalent, primarily due to cost reduction efforts.
DD and A expense, excluding Libya, is forecast to be in the range of $14 to $15 per of oil equivalent for the 2nd quarter $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 and P unit operating costs, excluding Libya, to be in the range of $24 to $25.50 per barrel of oil equivalent for the 2nd 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 $35,000,000 to $40,000,000 in the second quarter, with the full year 2020 guidance now expected to be $145,000,000 to $155,000,000 down from previous full year guidance of 210
Speaker 3
dollars to $220,000,000
Speaker 5
The midstream tariff is projected to be in the range of $215,000,000 to $230,000,000 in the 2nd quarter and full year 2020 guidance in the range of $905,000,000 to $930,000,000 down from previous full year guidance of $940,000,000 to $965,000,000 E and P income tax expense, excluding Libya, is expected to be in the range of $5,000,000 to $10,000,000 for the Q2 and in the range of $20,000,000 to $30,000,000 for the full year of 2020, down from previous full year guidance of $80,000,000 to $90,000,000 For midstream, we anticipate net income attributable to Hess from the Midstream segment to be in the range of $40,000,000 to $50,000,000 in the second quarter and full year 2020 guidance in the range of $185,000,000 to $195,000,000 down from previous full year guidance of $205,000,000 to $215,000,000 For corporate expenses are estimated to be in the range of $25,000,000 to $30,000,000 in the 2nd quarter and full year 2020 guidance in the range of 115 dollars to $125,000,000 is unchanged. Interest expense is estimated to be in the range of $95,000,000 to $100,000,000 for the 2nd quarter, with the full year 2020 guidance expected to be $375,000,000 to $385,000,000 up from previous full year guidance of $350,000,000 to $360,000,000 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.
Speaker 0
We have our first question from Ryan Todd, Simmons Energy. Your line is now open.
Speaker 6
Thanks. Maybe if I could start with the Bakken, obviously very strong Q1 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 that to completing through and maybe if you can repeat what the 1 rig CapEx number looks like in 2021?
Speaker 2
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 Reilly will follow-up.
Speaker 3
Okay. So Ryan, let me start with the capital for the year. The capital for the year on the Bakken will be $740,000,000 And in that 740,000,000 dollars we expect to drill approximately 70 Bakken wells and bring 110 new wells online. And we do not plan to build any DUCs. We plan to drill and complete all wells that we drill throughout the year and into next year.
Speaker 6
Great. And maybe if I could on the maybe for you John, Riley, could you or either one, could you provide some color around the decision to chart 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 price signal is there a price signal that you need to sell the barrels into the Q4 or is that all already set up and contracted?
Speaker 2
Yes. So you know the contango of the difference of the current month in Brent and the future months in Brent, let's say, out to December is already hedged.
Speaker 1
So we want that in to maximize the value of our Bakken production and reserve our cash flow for this year.
Speaker 2
We were able to use our marketing capabilities and our firm transportation to the U. S. Gulf Coast to charter 3 VLCCs to load, store and export 2,000,000 barrels per month of Bakken crude oil in May, June July. And basically that spread has been fixed in Brent. On top of it, it is Brent based pricing, which obviously provides an advantage instead of WTI.
And we plan to market the oil in Asia. And Asia demand for oil is already improving. So it is possible that we sell the oil before depending upon before the Q4, 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 are 3 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 TI, more than offsets the cost of the charters.
Speaker 0
Next question, Doug Leggate from Bank of America. Your line is now open.
Speaker 7
Thank you, everybody. 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 outlook like going into 2021 in terms of the underlying production capacity decline rate with a 1 rig program?
And I've got a follow-up for Mr. Riley, please.
Speaker 6
Yes. Doug,
Speaker 3
as I mentioned in my opening remarks, if you keep rig program through 2021, it's about a 10% decline rate for the Bakken.
Speaker 7
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 'twenty is the exit rate is risked higher?
Speaker 3
Yes. Well, the exit rate we're projecting at the end of the year, 5,000 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.
Speaker 1
Repeat
Speaker 2
that number, Greg. It got muffled again.
Speaker 3
Okay, John. 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. Wells.
Speaker 7
Okay. All right. I appreciate the color. I know it's tricky in the mountains, Greg. So I'll move on to Mr.
Riley, 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, if 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 move things around because the cash burn could be quite meaningful?
Speaker 5
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, prices will be 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, as 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 $740,000,000 this year, go down to $300,000,000 with a 1 rig program or somewhere around $300,000,000 next year. And then obviously, it will be offset by some increase in Guyana capital spend. So one looking for capital remain flat, but we'll be looking at capital reductions, 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 1 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 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 what 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 and everything we're doing even though we'll continue to fine tune and try to cut costs, but to get us through this 2 year low price environment.
Speaker 7
John, if I just need to tag on one very quickly for that. And it's maybe one for John Hess actually. 1 of your peers this morning or last night, I should say, talked about their dividend and suspended their dividend. And I think there's semantics between suspending and canceling because we know the cash flow capacity of Hess is about to inflect significantly higher. But in a scenario where we did have 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? I'll leave it there. Thank you.
Speaker 2
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.
Speaker 7
Appreciate the color, Joanna. That's a very valid point. Thanks a lot.
Speaker 0
Next in line is Devon McFarlane, Morgan Stanley. Your line is now open.
Speaker 8
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 begin to add from the current one rate cadence that you're at right now. I was wondering if you just want to clarify if I heard that correctly. And then 2, 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?
Speaker 3
Yes. So I switched phones, so hopefully everybody
Speaker 5
can hear me much better. So yes, what we
Speaker 1
Yes. So I
Speaker 3
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 rigs 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've slowly added those rigs back in order to maintain that remanufacturing edge and not have our cost raise or whatever. So as John said in his opening remarks, that is one of our key strategies this year to be able to maintain that capability so that we can smoothly ramp the Bakken, hopefully in the future.
Speaker 1
Got
Speaker 8
it. That makes a lot of sense. And my follow-up relates to the Bakken, but also the rest of the portfolio. And as we think about the level of spending required to hold production flat, is it in the Bakken, how do you think about that activity level now, given some of 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?
Speaker 3
John, why don't you take that one? Yes, John.
Speaker 5
Sure. So to get to, let's call it, this flat production level now at the lower and it's somewhere around, let's say I'll call it 3 rigs and it will be right around that level. And you could always kind of as a rule of thumb put $200,000,000 per rig. So you're talking about $600,000,000 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 Q1 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 before 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.
Speaker 8
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?
Speaker 5
So let's just talk JDA and North Malay Basin first. Under normal operations there, we've always talked about somewhere with that $150,000,000 to $200,000,000 They can come in bunches 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 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 ESOXX, the successful ESOXX well, we could hold that Gulf of Mexico flat in that 65 type level for a number of years. Now, kind of 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 decline. So you could get somewhere in, I'm going to call it 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 I mean our original goal and we'll see when 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, well the BP is drilling and 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 Diana, 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 light delay in Payara. But as John has said in his remarks, growing at 750,000 barrels a day gross by 2026. So we've got a nice balance of 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 a toggle. As we see prices improve, we'll get back to work there.
Speaker 8
Thanks for the detailed response and congrats again on the continued solid results. Thanks for taking the question.
Speaker 2
Thank you.
Speaker 0
Next question is from the line of Paul Cheng, Scotiabank. Your line is now open.
Speaker 4
I have a couple first clarification. For John Wiley that the diner production number that you guys show in the press release, is that including the tax barrel goes up?
Speaker 5
So Paul, with 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 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
Speaker 4
2020. Okay. And that going forward, should we assume that the gross up tax barrel and at that time, you're going to provide a number that in both what is the adjusted net to you and what is the report?
Speaker 5
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.
Speaker 4
Okay. And I have to apologize that the mechanic on the VLCC storage, so we're going to have that under lift in the second and third quarter. So we will assume that the entire 6,000,000 barrels based on the current plan is going to be a over lift in the Q4? Correct.
Speaker 3
Go ahead, John.
Speaker 4
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 it going to show up in the other line?
Speaker 5
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 Q4 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 under lift in the second and third and you should assume in the 4th quarter that we will have the over lift of the 6,000,000 barrels coming in, in the 4th 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 costs and the DD and A associated with the production of the 6,000,000 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 Q4, 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.
Speaker 4
I see. Thank you. You're welcome.
Speaker 0
Next is Roger Read from Wells Fargo. Your line is now open.
Speaker 5
Yes. Thank you. Good morning.
Speaker 1
Good morning.
Speaker 5
Yes, hopefully everybody can hear me. Some of these conference calls have been pretty weird. I just was curious if we could get into the impacts of the deferrals down in Guyana, thinking, first off, the near term issues with the 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 date to use? Or are we at risk of further delays there?
Speaker 2
Yes. Greg, why don't you grab that? Greg, you didn't you're following?
Speaker 3
So Roger, in my opening remarks, I talked about that's solely COVID-nineteen related to those 2 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 pack. 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 June forward, there's really 3 objectives that we're trying to do. 1 is finish the appraisal yellowtail. 2 is get 2 to 3 more exploration wells in the ground, including a couple that have tails to go down and test the deeper or penetrate the deeper Santonion.
And then the 3rd 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 lay out between now and the end of the year.
Speaker 5
Okay, great. Thanks. And then, question going back to the, BLCC play here. I just want to make sure I understand what the ongoing risk reward is here or is everything and the way you're thinking about the price realizations when you actually physically deliver the barrels in the Q4 is already set? I guess what I'm trying to remember 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?
Speaker 2
No, it's a great question. Basically, look at it this way. We have our oil hedged already in the $55 $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.
Speaker 0
Next question is from Arun Jayaram, JPMorgan. Your line is now open.
Speaker 1
Good morning, team. 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, Exxon, are adjusting your longer term development exploration activities pending governor approvals COVID-nineteen. And then a specific one is how is this impacting? How you're thinking about the lease versus guide timing on the FPSO as well as the longer term thoughts on versus exploration versus development spend?
Speaker 2
Yes. No, thanks 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, newly elected sitting government, we would assume the first, second and third priority for us in Exxon and CNOC is to move the approval for the Payar 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 the start up of the 4th and 5th 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 a 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.
Speaker 1
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 is on the quarter?
Speaker 3
Yes. So there was really 2 major things. One was the weather, which we had. So Mother Nature was kind to us, in the Q1, 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 Q1.
But even more important is the wells that we brought on in the Q4 just behaved really well. And so we had planned to convert those to rod pump during the Q1. And in fact, we didn't need to because the wells still were flowing well through the Q1. So we got a really nice production bump from the wells that were turned online in the Q4, but also in the Q1. So it was a combination of those two things that would further outperform.
Speaker 0
We have our next question from Pavel Molchanov, Raymond James. Your line is now open.
Speaker 9
Thanks for taking the question. 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 2021 story. Have you changed any of the medium term plans for beginning drilling there?
Speaker 2
Greg?
Speaker 3
Yes, sure. No, our plans are still to drill that well in 2021 in Suriname.
Speaker 9
Got it. Okay. Is that contingent on level of commodity prices?
Speaker 3
No, I think that's the the operator is in control of that, in Kosmos, but the latest discussions we've had with them, we are still planning the well for 2021.
Speaker 9
Okay. Appreciate it, guys.
Speaker 0
Next in line is Brian Singer, Goldman Sachs. Your line is now open.
Speaker 1
Thank you. Good morning.
Speaker 3
Good morning. Good morning, Brian.
Speaker 1
On Guyana, looking beyond Phase 2, realize that there are some understandable delays at Basis III plus 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
Speaker 2
in? Yes. Greg, do you want to take that, please?
Speaker 3
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 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, buyers, to adjust to the activity, but also keep continuity of the crews and bring some more cost 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.
Speaker 1
Great. And then my follow-up is with regards to the Malaysia, Asia gas demand. You 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?
Speaker 2
Yes, we definitely think it's one off and we already see demand recovering. But John Reilly, you want to elaborate?
Speaker 5
Sure. No, that's what we are seeing. Obviously, Malaysia, they had their shelter in place. They called it 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-nineteen 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.
Speaker 3
Great. Thank you.
Speaker 0
Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.