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Hess Corporation (HES) Q3 2021 Earnings Call Transcript – Motley Fool

Hess Corporation (HES) Q3 2021 Earnings Call Transcript  Motley Fool

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Hess Corporation (NYSE:HES)
Q3 2021 Earnings Call
Oct 27, 2021, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2021 Hess Corporation Conference Call. My name is Jackson. I will be your operator for today. As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Jay R. WilsonVice President, Investor Relations

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

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 case there are any audio issues, we will be posting transcripts of each speaker’s prepared remarks on our website following the presentation.

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

John B. HessChief Executive Officer

Thank you, Jay. Good morning, everyone. Welcome to our third quarter conference call. Today, I will review our continued progress in executing our strategy. Greg Hill then will discuss our operations and John Riley will cover our financial results. With COP26 beginning this Sunday, it is appropriate to address the energy transition. Climate change is the greatest scientific undertaking of the 21st century. The world has two challenges to grow our global energy supply by about 20% in the next 20 years and to reach net zero emissions by 2050. The International Energy Agency published its latest World Energy Outlook earlier this month, which provides four scenarios to shed light on these challenges. It is important to remember that these are scenarios not forecast to help guide policymakers and business leaders in their decision making. In all four scenarios, oil and gas will still be needed in the decades to come.

Significantly more investment will be required to meet the world’s growing energy needs, much more in renewables and much more in oil and gas. Our reasonable estimate for global oil and gas investment from these IEA scenarios is at least $400 billion each year over the next 10 years. Last year, that number was $300 billion. This year’s estimate is $340 billion. To ensure a successful an orderly energy transition, we need to have climate literacy, energy literacy and economic literacy.

Our strategy is to grow our resource base, have a low cost of supply and sustain cash flow growth. While delivering industry-leading environmental social and governance, performance and disclosure by investing only in high-return, low cost opportunities, we have built a differentiated and focused portfolio that is balanced between short cycle and long cycle assets. Our cash engines are the Bakken, the Gulf of Mexico and Southeast Asia, where we have competitively advantaged assets and operating capabilities. Guyana is our growth engine and is on track to become a significant cash engine in the coming years, as multiple phases of low-cost oil developments come online.

Also, by adding a third rig in the Bakken in September and completing the turnaround and expansion of the Tioga Gas Plant, the Bakken is expected to generate significant free cash flow in the years ahead. By successfully executing our strategy, our company is positioned to deliver strong and durable cash flow growth through the end of the decade. Based upon the most recent sell side consensus estimates, our cash flow is estimated to grow at a compound annual growth rate of 42% between 2020 and 2023, which is 50% above our peers and puts us in the top 5% of the S&P 500.

As our portfolio generates increasing free cash flow, we will first prioritize debt reduction and then cash returns to shareholders through dividend increases and opportunistic share repurchases. We have continued to maintain financial strength as well as managing for risk. As of September the 30th, we had $2.4 billion of cash on the balance sheet. In July, we prepaid half of our $1 billion term loan maturing in March 2023 and we plan to repay the remaining $500 million in 2022. This debt reduction combined with the start up of lease of Phase 2 early next year, is expected to drive our debt to EBITDAX ratio under 2% and also enable us to consider increasing cash returns to shareholders.

In August, we completed the sale of our interest in Denmark for total consideration of $150 million effective January 1, 2021, and received $375 million in proceeds from Hess Midstream’s buyback of Class B units from its sponsors Hess Corporation and Global Infrastructure Partners. Earlier this month, our company also received net proceeds of $108 million from the public offering of Hess-owned Class A shares of Hess Midstream. The Denmark sale and these Midstream monetizations brought material value forward and further strengthened our cash and liquidity position.

Key to our long-term strategy is Guyana, one of the industry’s best investments. On the Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator, we announced the 19th and 20th of significant discoveries during the third quarter at Whiptail and Pinktail. And on October 7th, we announced the 21st significant discovery on the block at Cataback. These discoveries will underpin our Q, our future low cost oil development. We see the potential for at least six FPSOs on the Stabroek Block producing more than $1 million gross barrels of oil per day in 2027, and up to 10 FPSOs to develop the discovered resources on the block.

On October 7th, we increased the gross discovered recoverable resource estimate for the block to approximately 10 billion barrels of oil equivalent, up from the previous estimate of more than 9 billion barrels of oil equivalent. And we continue to see multibillion barrels of future exploration potential remaining. In terms of our current Guyana developments, gross production from the lease of Phase 1 complex average 124,000 barrels of oil per day in the third quarter. The lease of Phase 2 development is on track for start-up in early 2022 with a gross production capacity of 220,000 barrels of oil per day and the leasing Unity FPSO arrived in Guyana on Monday.

Our third development on the Stabroek Block at the Payara field is on track to achieve first oil in 2024 also with a gross capacity of 220,000 barrels of oil per day. Our three-sanctioned oil developments have a breakeven Brent oil price of between $25 and $35 per barrel. The plan of development for our fourth development on the block at Yellowtail was recently submitted to the Government of Guyana for approval. Pending government approvals, the project is envisioned to have a gross capacity of approximately 250,000 barrels of oil per day with first oil in 2025.

Turning to sustainability. We are proud to be recognized as an industry leader in our environmental, social and governance performance and disclosure. Earlier this month, our company received a AAA rating in the MSCI ESG ratings for 2021 after earning A ratings for the previous 10 consecutive years. The AAA rating digit makes Hess as a leader in managing industry specific ESG risks relative to peers and reflects our strong management practices to reduce carbon emissions as well as our top quartile performance in areas such as biodiversity and land use, reduction of air and water emissions and waste, and making a positive impact on the communities where we operate.

In summary, we remain focused on executing our strategy and achieving strong operational and ESG performance. Our company is uniquely positioned to deliver cash flow growth over the next decade. That is not only industry leading, but which we believe will rank among the best in the S&P 500. After our term loan is paid off and our portfolio generates increasing free cash flow, we will prioritize return of capital to our shareholders through dividend increases and opportunistic share repurchases. Thank you.

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

Gregory P. HillPresident and Chief Operating Officer

Thanks, John. In the third quarter, we continued to deliver strong operational performance, meeting our production targets despite extended hurricane-related downtime in the Gulf of Mexico and safely executing a major turnaround at our Tioga Gas Plant in North Dakota. Companywide net production averaged 265,000 barrels of oil equivalent per day excluding Libya in line with our guidance. In the fourth quarter and for the full year 2021, we expect companywide net production to average approximately 295,000 barrels of oil equivalent per day excluding Libya.

Turning to the Bakken, third quarter net production averaged 148,000 barrels of oil equivalent per day. This was above our guidance of approximately 145,000 barrels of oil equivalent per day and primarily reflected strong execution of the Tioga Gas Plant turnaround and expansion, no small task in a COVID environment that required strict adherence to extensive safety protocols to keep more than 650 workers safe. For the fourth quarter, we expect Bakken net production to average between 155,000 and 160,000 barrels of oil equivalent per day. For the full year 2021, we forecast our Bakken net production to average approximately 155,000 barrels of oil equivalent per day, compared to our previous guidance range of 155,000 to 160,000 barrels of oil equivalent per day. This guidance reflects an increase in NGL prices, which reduces volumes under our percentage of proceeds contracts, but significantly increases this year’s earnings and cash flow.

In the third quarter, we drilled 18 wells and brought 19 new wells online. In the fourth quarter, we expect to drill approximately 19 wells and to bring approximately 18 new wells online. And for the full year 2021, we continue to expect to drill approximately 65 wells and to bring approximately 50 new wells online. In terms of drilling and completion costs, although we have experienced some cost inflation, we are maintaining our full year average forecast of $5.8 million per well in 2021. Since February, we’ve been operating two rigs. But given the improvement in oil prices and our robust inventory of high return drilling locations, we added a third rig in September.

Moving to a three-year three rig program will allow us to grow cash flow and production better optimize our in basin infrastructure and drive further reductions in our unit cash costs. Now moving to the offshore. In the deepwater Gulf of Mexico, third quarter net production averaged 32,000 barrels of oil equivalent per day, compared to our guidance range of 35,000 to 40,000 barrels of oil equivalent per day. Our results reflected an extended period of recovery following Hurricane Ida, which caused power outages at transportation and processing facilities downstream of our platforms. Production was restored at all of our facilities by the end of September.

In the fourth quarter, we forecast Gulf of Mexico net production to average between 40,000 and 45,000 barrels of oil equivalent per day. For the full year 2021, our forecast for Gulf of Mexico net production remains approximately 45,000 barrels of oil equivalent per day. In Southeast Asia, net production in the third quarter was 50,000 barrels of oil equivalent per day in line with our guidance of 50, 000 to 55,000 barrels of oil equivalent per day, reflecting the impact of planned maintenance shutdowns and lower nominations due to COVID. Fourth quarter net production is forecast to average approximately 65,000 barrels of oil equivalent per day and our full year 2021 net production forecast remains at approximately 60,000 barrels of oil equivalent per day.

Now turning to Guyana. In the third quarter, gross production from Liza Phase 1 averaged 124,000 barrels of oil per day or 32,000 barrels of oil per day net to Hess. Replacement of the flash gas compression system on the Liza Destiny with a modified design is planned for the fourth quarter and production optimization work is now planned to take place in the first quarter of 2022. These two projects are expected to result in higher production capacity and reliability. Net production from Liza Phase 1 is forecast to average approximately 30,000 barrels of oil per day in the fourth quarter and for the full year 2021. Liza Phase 2 development will utilize the 220,000 barrels of oil per day Unity FPSO, which arrived in Guyana Monday evening. Next steps will be more in line installation and umbilical and riser hook up. First oil remains on track for first quarter 2022.

Turning to our third development at Payara, the Prosperity FPSO hull entered the Keppel yard in Singapore on August 1st. Topside fabrication of dynamic and development drilling are underway. The overall project is approximately 60% complete. The Prosperity will have a gross production capacity of 220,000 barrels of oil per day, and is on track to achieve first oil in 2024. As for our fourth development at Yellowtail earlier this month, the joint venture submitted a plan of development to the Government of Guyana, pending government approvals and project sanctioning. The Yellowtail project will utilize an FPSO with a gross capacity of approximately 250,000 barrels of oil per day. First oil is targeted for 2025.

As John mentioned, we announced three discoveries since July. In July, we announced that the Whiptail 1 and 2 wells encountered 246 feet and 167 feet of high quality oil bearing sandstone reservoirs respectively. This discovery is located approximately four miles southeast of well 1 and 3 miles west of the Yellowtail. In September, we announced that the Pinktail 1 well located approximately 22 miles southeast of Liza 1 encountered 220 feet of high quality oil bearing sandstone reservoirs. And finally earlier this month, we announced a discovery of Cataback located approximately 4 miles east of Turbot 1. The well encountered 203 feet of high quality hydrocarbon bearing reservoirs, of which approximately 102 feet was oil bearing. These discoveries further underpin future developments and contributed to the increase of estimated gross discovered recoverable resources on the Stabroek Block to approximately 10 billion barrels of oil equivalent.

Exploration and appraisal activities in the fourth quarter will include drilling exploration well located approximately 11 miles northwest of Liza 1. This well as a significant step out tests that will target deeper Campanian and Santonian aged reservoirs. Appraisal activities in the fourth quarter will include drill-stem tests at Longtail 2 and Whiptail 2 as well as drilling the Tripletail 2 well. In closing, we have once again demonstrated strong execution and delivery and are well positioned to deliver significant value to our shareholders.

I will now turn the call over to John Riley.

John RiellyExecutive Vice President and Chief Financial Officer

Thanks, Greg. In my remarks today, I will compare results from the third quarter of 2021 to the second quarter of 2021. We had net income of $115 million in the third quarter of 2021, compared with a net loss of $73 million in the second quarter of 2021. On an adjusted basis, which excludes items affecting comparability of earnings between periods, we had net income of $86 million in the third quarter of 2021, compared to net income of $74 million in the second quarter of 2021. Third quarter earnings include an after-tax gain of $29 million from the sale of our interest in Denmark.

Turning to E&P. On an adjusted basis, E&P had net income of $149 million in the third quarter of 2021, compared to net income of $122 million in the previous quarter. The changes in the after-tax components of adjusted E&P results between the third quarter and second quarter of 2021 were as follows. Higher realized crude oil NGL and natural gas selling prices increased earnings by $110 million. Lower sales volumes reduced earnings by $147 million. Lower DD&A expense increased earnings by $37 million. Lower cash costs increased earnings by $14 million. Lower exploration expenses increased earnings by $10 million. All other items increased earnings by $3 million. For an overall increase in third quarter earnings of $27 million.

Sales volumes in the third quarter were lower than the second quarter, primarily due to hurricane-related downtime in the Gulf of Mexico, planned maintenance downtime and lower nominations in Malaysia and lower sales in the Bakken, resulting from the planned Tioga gas plant maintenance turnaround. In Guyana, we sold three 1 million barrel cargoes of oil in the third quarter, up from two 1 million barrel cargoes of oil sold in the second quarter. For the third quarter, our E&P sales volumes were under lifted compared with production by approximately 175,000 barrels, which had an insignificant impact on our after-tax results for the quarter.

Turning to Midstream. The Midstream segment had net income of $61 million in the third quarter of 2021, compared with $76 million in the prior quarter. Third quarter results included costs related to the Tioga Gas Plant maintenance turnaround that was safely and successfully completed. Midstream EBITDA before noncontrolling interest amounted to $203 million in the third quarter of 2021, compared with $229 million in the previous quarter.

Turning to our financial position at quarter-end excluding Midstream, cash and cash equivalents were $2.41 billion and total liquidity was $6 billion, including available committed credit facilities, while debt and finance lease obligations totaled $6.1 billion. During the third quarter, we received net proceeds of $375 million from the sale of $15.6 million Hess-owned Class B units of Hess Midstream and proceeds of approximately $130 million from the sale of our interest in Denmark.

In July, we prepaid $500 million of our $1 billion term loan and we plan to repay the remaining $500 million in 2022. In October, we received net proceeds of approximately $108 million from the public offering of 4.3 million Hess-owned Class A shares of Hess Midstream. Our ownership in Hess Midstream on a consolidated basis is approximately 44% compared with 46% prior to these two recent transactions. In the third quarter, net cash provided by operating activities before changes in working capital was $631 million, compared with $659 million in the second quarter. In the third quarter, net cash provided by operating activities after changes in operating assets and liabilities was $615 million, compared with $785 million in the second quarter. Changes in operating assets and liabilities during the third quarter decreased. Net cash provided by operating activities by $16 million compared with an increase of $126 million in the second quarter.

Now turning to guidance. First for E&P, our E&P cash costs were $12.76 per barrel of oil equivalent including Libya and $13.45 per barrel of oil equivalent excluding Libya in the third quarter of 2021. We project E&P cash cost excluding Libya to be in the range of $12 to $12.50 per barrel of oil equivalent for the fourth quarter and $11.75 to $12 per barrel of oil equivalent for the full year, compared to previous full year guidance of $11 to $12 per barrel of oil equivalent. The updated guidance reflects the impact of higher realized selling prices in 2021, which significantly improved cash flow, but reduced volumes received under percentage of proceeds contracts and increased production taxes in the Bakken.

DD&A expense was $11.77 per barrel of oil equivalent including Libya and $12.38 per barrel of oil equivalent excluding Libya in the third quarter. DD&A expense excluding Libya is forecast to be in the range of $13 to $13.50 per barrel of oil equivalent for the fourth quarter and the full year is expected to be in the range of $12.50 to $13 per barrel of oil equivalent. This results in projected total E&P unit operating costs excluding Libya to be in the range of $25 to $26 per barrel of oil equivalent for the fourth quarter and $24.25 to $25 per barrel of oil equivalent for the full year of 2021.

Exploration expenses excluding dry hole costs are expected to be in the range of $50 million to $55 million in the fourth quarter and approximately $160 million for the full year, which is at the lower end of our previous full year guidance of $160 million to $170 million. The Midstream tariff is projected to be approximately $295 million for the fourth quarter and approximately $1.95 billion for the full year. E&P income tax expense excluding Libya is expected to be in the range of $35 million to $40 million for the fourth quarter and the full year is expected to be in the range of $135 to $140 million, which is up from previous guidance of $125 million to $135 million, reflecting higher commodity prices. We expect non-cash option premium amortization will be approximately $65 million for the fourth quarter. For the year 2022, we have purchased WTI collars for 90,000 barrels of oil per day with the floor price of $60 per barrel and a ceiling price of $90 per barrel. We have also entered into Brent collars for 60,000 barrels of oil per day with a floor price of $65 per barrel and a ceiling price of $95 per barrel. The cost of this 2022 hedge program is $161 million, which will be amortized ratably over 2022.

During the fourth quarter, we expect to sell two 1 million barrel cargoes of oil from Guyana. Our E&P capital and exploratory expenditures are expected to be approximately $650 million in the fourth quarter. Full year guidance remains unchanged at approximately $1.9 billion. For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be approximately $70 million for the fourth quarter and the full year is projected to be approximately $280 million, which is at the midpoint of our previous guidance of $275 million to $285 million.

Turning to corporate, corporate expenses are estimated to be in the range of $30 million to $35 million for the fourth quarter and the full year is expected to be in the range of $125 million to $130 million, which is down from our previous guidance of $130 million to $140 million. Interest expense is estimated to be in the range of $90 millon to $95 million for the fourth quarter and the full year is expected to be in the range of $375 million to $380 million, compared to our previous guidance of approximately $380 million.

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

Questions and Answers:

Operator

Your first question comes from the line of Arun Jayaram with JP Morgan. You may proceed with your question.

Arun JayaramJPMorgan — Analyst

Good morning.

John B. HessChief Executive Officer

Good morning.

Arun JayaramJPMorgan — Analyst

Greg, I wanted to maybe start with you on Liza Phase 2. You mentioned that the ship got to the Stabroek Block on Monday. But just using Liza Phase 1 as a guide, can you give us a sense around how many days — months do you think you could be the first oil?

Gregory P. HillPresident and Chief Operating Officer

Yeah, sure. So thanks for the question. Arun, you to remember now that it’s arrived in water. The first thing that we have to do is more to the sea floor and then obviously, there is a lot of flow lines and risers and umbilicals to get hooked up to the vessel. So what I would say is we are firmly on track for early 2022 start up and don’t think I could be more definitive than that but early 2022 looks like a very possible.

Arun JayaramJPMorgan — Analyst

Great, great. And then my follow-up. Greg, maybe for you as well. One of the questions from the buyside is just around overall inflation and just how to think about some of the inflationary pressures, raw materials etc. on future phases of the project. I know that you’re in the market now with Exxon and Yellowtail, and then what are your key subsea provide, did put some color around, the subsea kit that they expect around Yellowtail and Uaru, they cited it maybe a 500 million to $1 billion range for Yellowtail and a bit over $1 billion for Uaru. So maybe you could just help us think about inflationary pressures, Greg?

Gregory P. HillPresident and Chief Operating Officer

Sure. I think first of all, yes, there is inflation going on and I think there is a couple of things we have to remember. First of all, for the first three phases, which you mentioned those are under existing EPC contracts. So we’re basically insulated from cost increases on those EPC contracts. And then ExxonMobil is doing an extraordinary job, I think, of utilizing this design one build many strategy to deliver efficiencies. Now on the Yellowtail, we still don’t have the final number. So once that project is sanctioned, we’ll give the market color on what the costs are. I do think it’s important to remember the nature of the PSC though. So, by the time you get the Yellowtail, the efficiency of the PSC is so rapid that any cost increases rapidly get recovered. So the impact on overall project return is not very much at all, right, because of that super-efficient PSC. And the breakevens for Yellowtail, we project even with some cost increases will be in that firmly in the $25 to $32 barrel range. So, one of the best projects on the planet even with some potential cost increases, great project.

Arun JayaramJPMorgan — Analyst

Great. Thanks a lot, Greg.

Operator

Our next question comes from Doug Leggate with Bank of America. You may proceed with your question.

Doug LeggateBank of America — Analyst

Thanks. Good morning, everybody. Guys, I know you haven’t given ’22 outlook yet, but given the oil price recovery that we’ve seen on the very smart hedge is, I think you guys are putting the inputs, I’ll go back to the capex guidance that you gave in 2018 on the Strategy Day, and I wonder if I could just ask you to give us kind of a framework, just how we should think about spending trajectory, and if I may, embedded in that question be blunt with you that, I think there is some concern over the costs, the sticker shock on Yellowtail. So, if I threw a number and said where we should be thinking something in the $12 billion type of range, will that of the March?

John RiellyExecutive Vice President and Chief Financial Officer

Doug, let me start with just giving some color on our capital for 2022. Now, you know, obviously we will finalize that and it will give our full guidance in January, but from a directional standpoint, which start with the Bakken, we’ve added a rig there, when we had rigs approximately $200 million when we add a rig in the Bakken. We’re also to your point with the higher prices we’re seeing more ballots for non-operated wells. So, for that, we could see an increase of approximately $50 million in our non-op JV wells next year. So, if you look at Bakken approximately $250 million of a capital increase as we look at next year, obviously with the pickup in production and an increasing cash flow though also as well coming from Bakken. In Guyana, we expect our development spend, so we went into the year with the guide was $780 million for our development spend in Guyana. We’re going to come in under that, and so, let me just say we’re proud to be approximately $750 million on our Guyana development spend this year. So, with Liza Phase 2 and the continued development on Payara and will begin spending on Yellowtail, we think it’s approximately $1 billion will be the Guyana capital for the developments next year, so approximately again another $250 million there.

The other areas then our Gulf of Mexico and Southeast Asia, in Gulf of Mexico, you know we’re basically not spending much money at all this year in the Gulf of Mexico and we typically spend $150 million to $200 million and we do plan to drill at tie-back well and one exploration well next year. And in Southeast Asia, we’re looking to complete our Phase 3 and Phase 4 developments in North Malay Basin, so we’ll have some increase there. So, I’d say combined those will be about $200 million, so you’ve got $500 million from Bakken and Guyana, $200 million from Gulf of Mexico and Southeast Asia. But I have to remind everyone, we will have lease of Phase 2 coming online. And so, I’ll just do — I always do that simple math if when Liza Phase 2 comes on in full and we have our share of 220,000 barrels of oil per day. We’re basically — and I’m just going to use a $60 Brent price and about a $10 cash costs, we pick up a $1 billion of additional cash flow from Liza Phase 2 alone when that comes on. And then, obviously, you have Payara and Yellowtail, so we’ll get much more cash flow as each FPSO comes. So that’s a directional, we will update in January. John, will you talk?

John B. HessChief Executive Officer

Yeah. And Doug, on Yellowtail well, they have to be been submitted to the government and it is higher cost. I think everybody needs to realize this FPSO is going to have capacity of approximately 250,000 barrels of oil per day on a gross basis. It will be our largest oil development to date in Guyana and while it’s cost will be higher. the resource we are developing is significantly higher and this development has simply outstanding financial returns, some of the best in the industry as Greg mentioned, and a breakeven cost between $25 and $32 per barrel Brent. So its outstanding economics. Yes, the costs are higher, but the resource we’re recovering as much higher and these are some of the best economics in the industry.

Doug LeggateBank of America — Analyst

So I won’t embarrass and want to $12 billion, John.

John RiellyExecutive Vice President and Chief Financial Officer

I won’t comment on that. Let the FPTB approved and then we will announce the official number.

Doug LeggateBank of America — Analyst

Thanks. My follow-up with a quick one. And it really is on Yellowtail, you mentioned the 250, has now been confirmed in your list?

John RiellyExecutive Vice President and Chief Financial Officer

Yeah. It’s still 200 to 250.

Doug LeggateBank of America — Analyst

Hi, Greg. I just wanted to just check in with you on how should we think about production optimization on all of these FPS stores? Is it 10% to 15%? In other words, above the nameplate.

Gregory P. HillPresident and Chief Operating Officer

Yeah, Doug. So I think, based on — again this is just my experience been in this business 38 years, I would think that for developments of these size and everyone will be bespoke, so everyone will be a little bit different, but I think the range of 10% to 20% capacity for debottlenecking or capacity increases is a reasonable expectation. Again, everyone to be a little bit bespoke your wait and get some dynamic data to see where the bottlenecks are, but I don’t think that’s an unreasonable expectation for future vessels. And I think the second point is, remember these increases in capacity are typically achieve for very low investment, and obviously with the PSC, the rapid cost recovery, these are very profitable things to do.

Doug LeggateBank of America — Analyst

I appreciate the answer Greg. Thank you.

Gregory P. HillPresident and Chief Operating Officer

Thanks.

Operator

Thank you. Our next question comes from Paul Cheng with Scotiabank. You may proceed with your question.

Paul ChengScotiabank — Analyst

Hey guys, good morning.

John B. HessChief Executive Officer

Good morning.

Paul ChengScotiabank — Analyst

Great. I think previously that the expectation of the debottleneck in Liza 1, we’ll be doing at the same time it the turn the wrong and now is being separate and push it to the first quarter, is there any particular reason for that decision?

John B. HessChief Executive Officer

Greg?

Gregory P. HillPresident and Chief Operating Officer

Yeah. So, Paul, as you said that the optimization work on best TV is now planned for the first quarter. This was simply deferred to allow other planned maintenance and inspection work to be done concurrently, which is much more efficient. So, the operator just pushed it to get some efficiencies and completing a bunch of other work at the same time while they have the vessel bound, which we fully support.

Paul ChengScotiabank — Analyst

With that being more efficient that when the vessel down, then you do the optimization, I mean, I’m not supposed to say, you will be more efficient to separate into two events?

Gregory P. HillPresident and Chief Operating Officer

No, it won’t, that’s what I meant, Paul, is that — when we take it down to do the optimization, ExxonMobil wanted to do some other work, while the vessel was down, so pulling some work forward some maintenance work that was scheduled for later in the year. By doing that, all at the same time concurrently, it’s just much more efficient, and so they needed parts and pieces and etc. And that’s why I get pushed to the first quarter.

Paul ChengScotiabank — Analyst

And Greg, I think regionally when you signed the agreement with the Gayana government, at some point that you guys are supposed to develop the gas resource there, I mean now that I think up to you doesn’t, it seems though you guys going to do it. So, at any time when that the gas we need to be developed? I mean there is no fixed timeline. Yes, we need still subject to negotiation with the government.

John B. HessChief Executive Officer

Hey, Greg.

Gregory P. HillPresident and Chief Operating Officer

Yeah. So I think there is two pieces, Paul. So, the first piece is the gas to energy project, right. It’s going to be a slip stream of gas, if you will, 5,200 million cubic feet a day pipeline to shore, that is wood supply gas to an onshore power plant to generate lower cost cleaner, more reliable energy for the benefit of the people on it. That project is in the design phase right now. And once it’s done, then we’ll share the details of the project after sanction. Regarding the long-term gas solution, which is what I think you were referring to, there are studies that may but it’s way out in the future, Paul. So, it’s not anything, certainly we need to worry about in the next five years potentially even well beyond that. So, but there are studies going on, because remember the highest value of the gas is pressure maintenance of these reservoirs significantly increase and the other unique part about the gas is its miserable. So there will be an enhanced oil recovery effect as a result of putting that gas back in the reservoir. So the highest and most beneficial use, if you will, of that gas is actually reinjection.

Paul ChengScotiabank — Analyst

And the final question from me, I think is for John. John, I think you mentioned that, once that your net debt to EBITDA target to say below two times, you will consider increasing the cash returned to shareholders? And at that point, how should we look at it, I mean, is there ways of you’re targeting that the incremental cash flows, a 50% still going to the balance sheet and 50% on incremental cash return to shareholder or any CAIO estimate that you can share? And also at that point, should we assume that the main vehicle is going to be buyback on or it’s Just going to be increase in the common dividend or that is the payable dividend, how should we be looking at those?

John RiellyExecutive Vice President and Chief Financial Officer

Sure. So, our strategy remains the same. And you said it basically we get Phase 2 online, we pay off the remaining part of the term loan and our debt to EBITDAX will be below 2% at that point and will begin increasing returns to shareholders. What we’re going to do first with the returns is increase our dividend, we’ll start there and then obviously as each FPSO comes on, we get significant, as I mentioned earlier, another $1 billion was Payara, another $1 billion with the Yellowtail, we will have increasing free cash flow. We will still progressively increase the dividend, but when we have that free cash flow, the majority of that will go back to shareholders, and that point, we’ll be looking at opportunistic share repurchases.

Paul ChengScotiabank — Analyst

John, when you’re talking about that once you dropped below 2 times, I suppose that your ultimate target will be much below 2 times EBITDA ratio. So, what is that, how would ratio you want, is it less than one-time or less than half a multiple point?

John RiellyExecutive Vice President and Chief Financial Officer

Yeah. I’m going to answer it two ways. So, once we do get under 2, we are comfortable with our absolute debt levels. Our liquidity is very good. We have a $300 million maturity coming in 2024 and our next maturity is in 2027. So, we’ll continue, we can pay off the maturity as they come due. And then, what will happen is because the EBITDA just increases so much with each FPSO, will drive under one times fairly quickly actually when these FPSOs come online. So yes, we do want to be below 1 and look, we can do that at various commodity prices just again due to the great returns that we have in Guyana.

Paul ChengScotiabank — Analyst

Thank you.

John RiellyExecutive Vice President and Chief Financial Officer

Thank you.

Operator

Our next question comes from Phillips Johnston with Capital One. You may proceed with your question.

Phillips JohnstonCapital One — Analyst

Hey guys, thanks. Just one for me. I guess on last quarter’s call we did touch on your strategic thoughts around Hess Midstream arms. But I just wanted to follow up on the topic, just given the size of that asset. It seems like you guys obviously want to get your Bakken volumes up to that optimal level of 200 a day before plateauing at that level. Once that occurs and once operational and marketing control of Midstream is perhaps less critical, would you think it makes sense to harvest that as I’ve just by selling it to a third party and freeing up capital in the process to potentially return that to shareholders?

Gregory P. HillPresident and Chief Operating Officer

Philip, I mean, we are very happy with our Midstream investment and GIP is too. So the Midstream continues to add what we believe is differentiated value to our E&P assets. Like you said, being able to get it up to 200,000 barrels a day. Also with that maintaining the operational and marketing control, it provides takeaway optionality for us to high value markets and as John mentioned earlier, we’re very focused on minimizing our mission, so gives us the ability to increase our gas capture and drive down flaring. So both GIP and Hess remain committed to maximizing the long-term value of Hess Midstream. So the offerings we did, we had the secondary in Q1 and earlier this month, they were designed to increase the float of Hess Midstream get their liquidity up there and the Q3 buyback actually helps Hess Midstream optimize its capital structure, getting to that 3 times leverage position. So, pro forma for these transactions Hess Midstream, it maintains a strong credit position and it has continuing free cash flow after distributions. So it will continue to have that low leverage and ample balance sheet capacity. Thanks guys. With the free cash flow will continue to drive that leverage down so that can support future growth there on the Midstream side or incremental return of capital to its shareholders, including Hess. So basically what we’re talking about is continuing what we’ve been doing here with Hess Midstream.

John B. HessChief Executive Officer

And you can clear, our objective is to maximize the value of Hess Midstream — to Hess and also maximize the value of Hess Midstream to its unit holders and GIP as well.

Phillips JohnstonCapital One — Analyst

Okay. Sounds good, guys. Thank you.

Operator

Our next question comes from Neil Mehta with Goldman Sachs. You may proceed with your question.

Neil MehtaGoldman Sachs — Analyst

Good morning. team.

John B. HessChief Executive Officer

Good morning.

Neil MehtaGoldman Sachs — Analyst

Good morning, guys. Kick off question is on hedging and you made some progress in terms of 2022 and implemented the scholar strategy. Can you just talk high-level why you thought that was the appropriate way to attack hedging and it does appear to still believe you a lot of optionality on the upside while protecting your downside but maybe kick-off there?

John B. HessChief Executive Officer

Sure. So I mean, our hedge strategy, this for 2022, it’s consistent with our past strategy. We look to provide significant downside protection to push to do this, while also given the majority of upside to our shareholders and we’re looking for that price protection as we continue to fund our world-class investment opportunity in Guyana. So with it — as I mentioned, we have the callers 90,000 barrels of oil per day of WTI puts at a floor of 60 and the ceiling at 90 and the 60,000 barrels of oil per day Brent puts floor 65 and the ceiling at 95, we use those high ceiling calls to reduce the cost of program just to be more efficient with our hedging program, but also as you mentioned, we retain the exposure to greater than $2 billion in additional cash flow in the case of high oil prices above those hedge floor prices. In addition, we have not hedged any of our natural gas, obviously no NGL production schedule. We haven’t hedged all of our oil production either. So we continue to be in a good position to be able to accrete up value with higher oil prices, but again we’ve got that significant price protection on the downside to continue the investment.

Neil MehtaGoldman Sachs — Analyst

Great, guys. And then the follow-up is just on the Bakken, you spend some time just talking about your development strategy there. What would it take with oil prices up here for you guys to pursue a growth strategy as opposed to a free cash flow strategy in the Bakken?

John B. HessChief Executive Officer

Yeah. Greg?

Gregory P. HillPresident and Chief Operating Officer

Yeah, sure. So, remember that the primary role of the Bakken in our portfolio is to be a cash engine, so that’s the first thing. And as such, any decision to add rigs in the Bakken is going to be driven by returns in our corporate cash flow position. And now, having said that, it’s $60 WTI. We have 2,200 future locations, which assuming you would go up to four rigs over 50 rig years inventory. Our ultimate objective is that we’d like to get the Bakken back to 200,000 barrels a day, why because it optimizes rent procure and maximizes the free cash flow generation of the Bakken. We can do that by adding a fourth rig, and depending on market conditions in the next year, we would consider adding that fourth rig at the end of next year. And I think the other thing that’s important to remember is that is four rig the maximum we will run in the Bakken, that sort of the efficient frontier, if you will, to just take the Bakken to 200,000 barrels a day plus or minus and then just hold it with that inventory we have for nearly a decade at 200,000 barrels a day. And at that point, depending on oil price, it generates between $715 million to $1billion of free cash flow. So it just became to this massive cash annuity for a very long time and that is the strategy, get it up to that level and just hold that cash annuity position with our inventory as long as we can.

Neil MehtaGoldman Sachs — Analyst

Thanks, Team.

Operator

Our next question comes from Noel Parks with Tuohy Brothers. You may proceed with your question.

Noel ParksTuohy Brothers — Analyst

Hey, good morning.

John B. HessChief Executive Officer

Morning.

Noel ParksTuohy Brothers — Analyst

I was wondering if you could maybe walk through some of the components of the resource estimate increase you took it from 9 billion barrels to 10 billion barrels for the project, and i’m just particularly interested at the announcement you said that some of that came from new discoveries like Cataback. I’m just wondering the degree — what you think degree that may be derisking from the most recent drilling contribute to the incremental increase? And also maybe you could drill down a little bit on sand quality and the most recent discoveries the porosity to the consistent with your pre-drill analysis, etc.?

John B. HessChief Executive Officer

Yeah, Greg.

Gregory P. HillPresident and Chief Operating Officer

Sorry I was on mute for a second. Look, I think the resource estimate was a combination of a lot of things, obviously the big things we’re Whiptail 1 and Whiptail 2 and Pinktail and Cataback. So those were the primary drivers of taking that number from greater than 9 billion to approximately 10 billion, so that was the majority of the change that move. I think it’s important to also remember that in spite of that there is still multibillion barrels of additional upside above and beyond this 10 billion barrels already. Regarding sand quality, it’s all very good, I mean, everything we’ve discovered this year has extraordinary sand quality. As we mentioned, the Cataback well, the last well that we announced, had 102 feet of oil bearing sand, but 243 feet of hydrocarbon bearing reservoirs and also Whiptail 1 was 246 feet, Whiptail 2, 167 feet, so these are very large, very high quality reservoirs in all three of those discoveries. So there is no issues with sand quality or reservoir quality in any of those wells.

Noel ParksTuohy Brothers — Analyst

I’m just wondering in the more recent discoveries, anything you can — you’ve been able to extrapolate, I guess maybe just from the consistency among the findings, is that helping from your optimism for the future drilling and as you step out further?

Gregory P. HillPresident and Chief Operating Officer

Sure. I think what it confirms that that entire Eastern Seaboard is what I like to call it from Terabit all the way to Liza and further north is just great, great reservoir rock, and so part of our strategy going forward in 2022 will be to continue to build out the prospectivity that we see and continue to explore in those very high quality upper Campanian reservoirs that I just talked about. The second objective we will have in 2022 is to get more penetrations in the deep, that’s the one with the most uncertainty now. As we mentioned in the fourth quarter, we will drill a well called specifically aimed at the deep stratigraphy and when I say deep, it’s lower Campanian and upper Santonian, which is about 3,000 feet deeper than those upper Campanian reservoirs. And then the third objective of our 2022 exploration and appraisal program is to continue to appraise all these outstanding discoveries that we’ve made, right. So appraise, explore upper Campanian and explore the deeper reservoirs, there are three primary objectives next year.

Noel ParksTuohy Brothers — Analyst

Great. Thanks a lot.

Operator

Our next question comes from David Heikkinen with Pickering Energy. You may proceed with your question.

David HeikkinenPickering Energy — Analyst

Good morning. I just wanted to check. A couple of things on Yellowtail, Have you guys finalized the 45 to 55 wells with the 8 different sub sites, just again trying to narrow down on what the total cost is going to be as we’re putting estimate together?

John B. HessChief Executive Officer

Yeah. No, that’s still under discussion with the partnership exactly what that configuration will be and as we’ve said, when we take final sanction, we will be able to share all those details as to what the final project actually looks like.

David HeikkinenPickering Energy — Analyst

And to follow up on the point that Greg was making the Yellowtail has world-class economics and returns because we’re covering a lot larger resource. So while people are focused on costs, they should be focused on the resource, which is a lot higher?

John B. HessChief Executive Officer

Once we get the FDP, we can give granularity on that and again the breakeven is going to be between $25 and $32 per barrel Brent.

David HeikkinenPickering Energy — Analyst

Yeah, it’s a much bigger areal extent it looks like it is actually a huge area being developed with that IRR even and then it was very helpful to put together the kind of incremental capital year-over-year. I did my math right, is that roughly 2.5 billion before exploration expense?

Gregory P. HillPresident and Chief Operating Officer

Now, that increase that I gave before, so is a 500 combined Bakken and Guyana and then 200 with Gulf of Mexico and Southeast Asia, so 700 from our 1.9 and that includes exploration.

David HeikkinenPickering Energy — Analyst

Okay. And it will add.

Gregory P. HillPresident and Chief Operating Officer

Yeah, no problem. And then obviously I just always have to point out with Phase 2 comes on. We’re picking up that at $60 Brent, that $1 billion of additional cash flow there. So, and then Bakken, obviously we’re going to pick up some additional cash flow as well from the higher production.

David HeikkinenPickering Energy — Analyst

And that’s before a potential fourth rig in the Bakken, they would get you up to 200,000 barrels equivalent a day.

Gregory P. HillPresident and Chief Operating Officer

That’s correct.

David HeikkinenPickering Energy — Analyst

I have got my numbers right now. Thanks guys.

Gregory P. HillPresident and Chief Operating Officer

Thank you.

Operator

Duration: 57 minutes

Call participants:

Jay R. WilsonVice President, Investor Relations

John B. HessChief Executive Officer

Gregory P. HillPresident and Chief Operating Officer

John RiellyExecutive Vice President and Chief Financial Officer

Arun JayaramJPMorgan — Analyst

Doug LeggateBank of America — Analyst

Paul ChengScotiabank — Analyst

Phillips JohnstonCapital One — Analyst

Neil MehtaGoldman Sachs — Analyst

Noel ParksTuohy Brothers — Analyst

David HeikkinenPickering Energy — Analyst

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