Hess - Q3 2021
October 26, 2021
Transcript
Speaker 0
Good day, ladies and gentlemen, and welcome to the Third Quarter 2021 Hess Corporation Conference Call. My name is Josh, 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, Josh. Good morning, everyone, and thank you for participating in our Q3 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 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.
Speaker 2
Thank you, Jay. Good morning, everyone. Welcome to our Q3 conference call. Today, I will review our continued progress in executing our strategy Greg Hill then will discuss our operations and John Reilly 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 2,050. The International Energy Agency published its latest World Energy Outlook earlier this month, which provides 4 scenarios to shed light on these challenges. It is important to remember that these are scenarios, not forecasts, 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. A reasonable estimate for global oil and gas investment from these IEA scenarios is at least $400,000,000,000 each year over the next 10 years. Last year, that number was $300,000,000,000 This year's estimate is $340,000,000,000 To ensure a successful and 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 Also, by adding a 3rd 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 20202023, which is 50% above our peers and puts us in the top 5% of the S and 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 30, we had $2,400,000,000 of cash on the balance sheet. In July, we prepaid half of our $1,000,000,000 term loan maturing in March 2023, and we plan to repay the remaining 500 in 2022. This debt reduction combined with the start up of Liza 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 a total consideration of $150,000,000 effective January 1, 2021, and received $375,000,000 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 $108,000,000 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 20th significant discoveries during the Q3 at Whiptail and Pinktail. And on October 7th, we announced the 21st significant discovery on the block at Catapac.
These discoveries will underpin our queue of future low cost oil developments. We see the potential for at least 6 FPSOs on the Stabroek Block producing more than 1,000,000 gross barrels of oil per day in 2027 and up to 10 FPSOs to develop the discovered resources on the block. On October 7, we increased the gross discovered recoverable resource estimate for the block to approximately 10,000,000,000 barrels of oil equivalent, up from the previous estimate of more than 9,000,000,000 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 Liza Phase 1 complex averaged 124,000 barrels of oil per day in the Q3.
The Liza Phase 2 development is on track for start up in early 20 22 with a gross production capacity of 220,000 barrels of oil per day and the leasing unit FPSO arrived in Guyana on Monday. Our 3rd 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 3 sanctioned oil developments have a breakeven Brent oil price of between $25 $35
Speaker 3
per barrel.
Speaker 2
The plan of development for our 4th 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 AAA ratings for the previous 10 consecutive years.
The AAA rating does it 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 and 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 optimistic share repurchases. Thank you.
And I will now turn the call over to Greg Hill for an operational update.
Speaker 4
Thanks, John. In the Q3, 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. Company wide net production averaged 265,000 barrels of oil equivalent per day excluding Libya, in line with our guidance. In the Q4 and for the full year 2021, we expect company wide net production to average 295,000 barrels of oil equivalent per day, excluding Libya. Turning to the Bakken.
3rd quarter net production averaged 148,000 barrels of oil equivalent per day. This was above our guidance 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 Q4, we expect Bakken net production to average between 100 55,160,000 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 Q3, we drilled 18 wells and brought 19 new wells online. In the 4th 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 $5,800,000 per well in 2021.
Since February, we've been operating 2 rigs, But given the improvement in oil prices and our robust inventory of high return drilling locations, we added a 3rd rig in September. Moving to a 3 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, 3rd 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 4th quarter, we forecast Gulf of net production to average between 40,045,000 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 3rd 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. 4th 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 Q3, 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 Q4 and production optimization work is now planned to take place in the Q1 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 Q4 and for the full year 2021.
Liza Phase 2 development will utilize the 220,000 barrels of oil per day Uniti FPSO, which arrived in Guyana Monday evening. Next steps will be mooring line installation and umbilical and riser hookup. First oil remains on track for Q1 2022. Turning to our 3rd development at Payara. The Prosperity FPSO hull entered the Gepel yard in Singapore on August 1.
Topside's fabrication at Dynamac 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 4th development in Yellowtail, earlier this month, the joint venture submitted the 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 3 discoveries since July. In July, we announced that the Whiptale 1 and 2 wells encountered 246 feet and 167 feet of high quality oil bearing sandstone reservoirs, respectively. This discovery is located approximately 4 miles southeast of Uaru-1 and 3 miles west of Yellowtail.
In September, we announced that the Pinktail-one well located approximately 22 miles southeast of Liza-one encountered 220 feet of high quality oil bearing sandstone reservoirs. And finally, earlier this month, we announced a discovery at Catibac located approximately 4 miles east of Turbot 1. The well encountered 2 43 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 10,000,000,000 barrels of oil equivalent. Exploration and appraisal activities in the 4th quarter will include drilling the Fangtooth-one exploration well located approximately 11 miles northwest of Liza-one.
This well is a significant step out test that will target deeper Campanian and Santonian aged reservoirs. Appraisal activities in the Q4 will include drill stem tests at Long tail 2 and Whiptail 2 as well as drilling the Triple Tail 2 well. In closing, we have once again demonstrated strong execution delivery and are well positioned to deliver significant value to our shareholders. I will now turn the call over to John Reilly.
Speaker 5
Thanks, Greg. In my remarks today, I will compare results from the Q3 of 2021 to the Q2 of 2021. We had net income of $115,000,000 in the Q3 of 2021 compared with a net loss of $73,000,000 in the Q2 of 2021. On an adjusted basis, which excludes items affecting comparability of earnings between periods, we had net income of $86,000,000 in the Q3 of 2021 compared to net income of $74,000,000 in the Q2 of 2021. 3rd quarter earnings include an after tax gain of $29,000,000 from the sale of our interest in Denmark.
Turning to E and P. On an adjusted basis, E and P had net income of $149,000,000 in the Q3 of 2021 compared to net income of 122,000,000 in the previous quarter. The changes in the after tax components of adjusted E and P results between the Q3 and Q2 of 2021 were as follows. Higher realized crude oil, NGL and natural gas selling prices increased earnings by $110,000,000 Lower sales volumes reduced earnings by $147,000,000 Lower DD and A expense increased earnings by $37,000,000 Lower cash cost increased earnings by $14,000,000 Lower exploration expenses increased earnings by $10,000,000 all other items increased earnings by $3,000,000 for an overall increase in 3rd quarter earnings of $27,000,000 Sales volumes in the Q3 were lower than the Q2, 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 3 1,000,000 barrel cargoes of oil in the 3rd quarter, up from 2 1,000,000 barrel cargoes of oil sold in the 2nd quarter.
For the Q3, our E and 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 $61,000,000 in the Q3 of 2021 compared with $76,000,000 in the prior quarter. 3rd quarter results included costs related to the Tioga Gas Plant maintenance turnaround that was safely and successfully completed. Midstream EBITDA before non controlling interest amounted to $203,000,000 in the Q3 of 2021 compared with $229,000,000 in the previous quarter.
Turning to our financial position. At quarter end, excluding Midstream, cash and cash equivalents were $2,410,000,000 and total liquidity was 6 During the Q3, we received net proceeds of $375,000,000 from the sale of $15,600,000 Hess Owned Class with Hess Midstream and proceeds of approximately $130,000,000 from the sale of our interest in Denmark. In July, we prepaid $500,000,000 of our $1,000,000,000 term loan and we plan to repay the remaining $500,000,000 in 2022. In October, we received net proceeds of approximately $108,000,000 from the public offering of 4,300,000 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 Q3, net cash provided by operating activities Before changes in working capital was $631,000,000 compared with $659,000,000 in the 2nd quarter. In the Q3, net cash provided by operating activities after changes in operating assets and liabilities was $615,000,000 compared with $785,000,000 in the 2nd quarter. Changes in operating assets and liabilities during the 3rd quarter decreased net cash provided to operating activities by $16,000,000 compared with an increase of $126,000,000 in the 2nd quarter. Now turning to guidance, first for E and P. Our E and 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 Q3 of 2021.
We project E and P cash costs excluding Libya to be in the range of $12 to $12.50 per barrel of oil equivalent for the 4th 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 on a percentage of proceeds contracts and increased production taxes in the Bakken. DD and A expense was $11.77 per barrel of oil equivalent, including Libya and 12.38 per barrel of oil equivalent excluding Libya in the Q3. DD and A expense excluding Libya is forecast to be in the range $13 to $13.50 per barrel of oil equivalent for the Q4 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 and P unit operating costs, excluding Libya, to be in the range of $25 to $26 per barrel of oil equivalent for the 4th 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 $50,000,000 to $55,000,000 in the 4th quarter and approximately $160,000,000 for the full year, which is at the lower end of our previous full year guidance of $160,000,000 to $170,000,000 The midstream tariff is projected to be approximately $295,000,000 for the 4th quarter and approximately $1,095,000,000 for the full year. E and P income tax expense, excluding Libya, is expected to be in the range of $35,000,000 to $40,000,000 for the 4th quarter, and the full year is expected to be in the range of $135,000,000 to $140,000,000 which is up from previous guidance of $125,000,000 to 100 $35,000,000 reflecting higher commodity prices. We expect non cash option premium amortization will be approximately $65,000,000 for the Q4. For the year 2022, we have purchased WTI collars for 90,000 barrels of oil per day with a 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 100 and $61,000,000 which will be amortized ratably over 2022. During the Q4, we expect to sell 21,000,000 barrel cargoes of oil from Guyana. Our E and P capital and exploratory expenditures are expected to be approximately $650,000,000 in the 4th quarter. Full year guidance remains unchanged at approximately $1,900,000,000 For Midstream, we anticipate net income attributable to Hess from the Mid Stream segment to be approximately $70,000,000 for the 4th quarter and the full year is projected to be approximately $280,000,000 which is at the midpoint of our previous guidance of $275,000,000 to $285,000,000 Turning to corporate. Corporate expenses are estimated to be in the range of $30,000,000 to $35,000,000 for the 4th quarter, and the full year is expected to be in the range of 125 to $130,000,000 which is down from our previous guidance of $130,000,000 to $140,000,000 Interest expense is estimated to be in the range of $90,000,000 to $95,000,000 for the Q4 and the full year is expected to be in the range of 3.75 to $380,000,000 compared to our previous guidance of approximately $380,000,000 This concludes my remarks.
We will be happy to answer any questions. I will now turn the call over to the operator.
Speaker 6
Thank
Speaker 0
you. Your first question comes from the line of Arun Jayaram with JPMorgan. You may proceed with your question.
Speaker 7
Good morning. 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 1st oil?
Speaker 4
Yes, sure. So thanks for the question, Arun. Remember, now that it's arrived in waters, the first thing that we have to do is more to the seafloor. And then obviously, there's 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 an early 2022 start up.
And don't think I could be more And even that, but early 2022 looks like very possible.
Speaker 7
Great, great. And then my follow-up, Greg, maybe for you as well. One of the questions from the buy side is just around overall inflation and just how to think about Some of the inflationary pressures, raw materials, etcetera, on future phases of the project. I know that you're in the market now with Exxon on Yellowtail. And then one of your key subsea A provider did put some color around the subsea kit that they expect around Yellowtail and Uaru.
They cited that maybe a $500,000,000 to $1,000,000,000 range for Yellowtail and a little bit over $1,000,000,000 for Uaru. So just maybe you could just help us think about Inflationary pressures, Greg?
Speaker 4
Sure. I think, first of all, yes, there is inflation going on. I think There's 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 1, Build Mini strategy to deliver efficiencies. Now on Yellowtail, we still don't have the final numbers. 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 to 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, very much at all, right, because of that super efficient PSC. And the breakevens for Yellowtail, We project even with some cost increases, we'll be in the 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.
Speaker 7
Great. Thanks a lot, Greg.
Speaker 0
Thank you. Our next question comes from Doug Leggate with Bank of America, you may proceed with your question.
Speaker 8
Thanks. Good morning, everybody. Guys, I know you haven't given Our 2022 outlook, yes. But given the oil price recovery that we've seen and the very smart hedges, I think you guys have put in place, I go back to the CapEx guidance that you gave in 2018 in the strategy day. And I wonder if I could just ask you to give us a kind of framework How should we think about spending trajectory?
And if I may embedded in that question be blunt with you that I think there's some concern over Also the sticker shock on Yellowtail. So if I threw out a number and said we should be thinking something in the $12,000,000,000 type of range, That'll be off the mark.
Speaker 5
Doug, let me start with just giving some color on our capital for 2022. Now, obviously, we will finalize that and we'll give our full guidance in January. But From a directional standpoint, let's start with the Bakken. We've added a rig there. Rule of thumb, when we add a rig, it's approximately $200,000,000 We had 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 $50,000,000 in our non op JV wells next year. So if If you're looking at Bakken, approximately $250,000,000 of a capital increase as we look at next year, Obviously, with a pickup in production and an increase in 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 $780,000,000 for our development Spent in Guyana, we're going to come in under that. And so let me just say, we'll probably be approximately $750,000,000 on our Guyana development spend this year.
So with Liza Phase 2 and the continued development on Payara and we'll begin spending on Yellowtail, we think it's approximately $1,000,000,000 will be the Guyana Capital for the developments next year. So approximately again another $250,000,000 there. The other areas then are Gulf of Mexico and Southeast Asia. So on Gulf of Mexico, we're basically not spending much money at all this year in the Gulf of Mexico. We typically spend $150,000,000 to 200,000,000 And we do plan to drill a tieback 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 200,000,000 So you've got $500,000,000 from Bakken and Guyana, dollars 200,000,000 from Gulf of Mexico and Southeast Asia. But I have to remind everyone, we'll have Liza Phase 2 coming online. And so I'll just do I always do that simple math 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 cost, We pick up $1,000,000,000 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 on. So that's a directional. We'll update in January. John, you want to talk Yellowtail?
Speaker 2
Yes. And doggone Yellowtail, well, the These have been submitted to the government and it is higher cost. I think everybody needs to realize that this FPSO is going to have capacity of Approximately 250,000 barrels of oil per day on a gross basis. It'll be our largest oil development to date in Guyana. And while its Costs 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 $32 per barrel Brent. So it's outstanding economics. Yes, the costs are higher, but the resource we're recovering is much higher and these are some of the best economics in the industry.
Speaker 8
So I wouldn't embarrass anyone at $12,000,000,000 what was John?
Speaker 2
I won't comment on that. Let's So let the FDP be approved and then we'll announce the official number.
Speaker 8
Thanks, Matt. My follow-up hopefully a quick one and it really is on Yellowtail. You mentioned The 250 is now being confirmed in your release. The EIS is still 220, 250. Greg, I just want 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?
Speaker 4
Yes, Doug. So I think based on again, this is just my experience being 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 a range of 10% to 20% capacity for debottlenecking or capacity increases. This is a reasonable expectation. Again, everyone will be a little bit bespoke.
You'll wait and get some dynamic data, 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 achieved for very low investment. And obviously with PSC, the rapid cost recovery, these are very profitable things to do.
Speaker 8
Appreciate the answers, guys. Thank you.
Speaker 2
Thanks.
Speaker 0
Thank you. Our next question comes from Paul Cheng with Scotiabank. You may proceed with your question.
Speaker 6
Hey, guys. Good morning.
Speaker 2
Good morning.
Speaker 6
Great. I think previously that the expectation of the debottleneck in Liza 1 We'll be doing at the same time as the turnaround and now is being separate and push it to the Q1. Is there any particular reason for that decision?
Speaker 4
Greg? Yes. So Paul, as you said, the optimization work on DEFCE is now planned for the Q1. 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 in completing a bunch of other work at the same time while they had the vessel down, which we fully support.
Speaker 6
Would that be more efficient that when the vessel gets done, then you do the optimization? I mean, I'm not actually surprised you say it will be more efficient to separate out into to events.
Speaker 4
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 etcetera, and that's why it got pushed to the Q1.
Speaker 6
And Greg, I think originally when you signed the agreement with the Guyana government, At some point that you guys supposed to develop the gas resource there. I mean now that I think up So, it doesn't seem like you guys are going to do it. So, any kingpin win that The gas will need to be developed or that's been in no big timeline, yes, we need still subject to
Speaker 2
Yes, Greg.
Speaker 4
Yes. So I think there's 2 pieces, Paul. So the first piece is the gas to energy project, right? It's going to be a slipstream of gas, if you will, 50,000,000 to 100,000,000 cubic feet a day pipeline to shore That is would supply gas and onshore power plant to generate lower cost, cleaner, more reliable energy for the benefit of the people of Guyana. 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 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 5 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 increased recovery? And the other unique part about the gas is it's miscible.
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.
Speaker 6
And the final question for me, I think, is John, I think you mentioned that once that your net debt to EBITDA That you say below 2x, you will consider increasing the cash return to shareholder. And at that point that how should we look at it? I mean is there a ways of you targeting that the incremental cash flow, say, 50% still going to the balance sheet and 50% for incremental cash return to shareholder or any kind of Estimate that you can share. And also at that point, should we assume that The main vehicle is going to be buyback or is just going to be increasing the common dividend or that is the payable dividend. How should we be looking at those?
Speaker 5
Sure. So, It's 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 we'll 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 So comes on, we get significant as I mentioned earlier, another $1,000,000,000 with Payara, another $1,000,000,000 with Yellowtail.
We'll have increasing free cash flow. We can we'll still progressively increase the dividend, but when we have that free cash Well, the majority of that will go back to shareholders. And that point we'll be looking at opportunistic share repurchases.
Speaker 6
John, when you're talking about that once you drop below 2x, I suppose that Your ultimate target will be much below the 2x EBITDA ratio. So what is that ultimate Ratio, you won, is it less than one time or less than half a multiple pawn?
Speaker 5
Yes. I'm going to answer it 2 ways. So once we do get under 2, we are comfortable with our absolute debt levels. We have Our liquidity is very good. We have a $300,000,000 maturity coming in 2024 and our next maturity is into 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.
Speaker 6
I see. Thank you.
Speaker 0
Thank you. Our next question comes from Philip Johnston with Capital One. You may proceed with your question.
Speaker 9
Hey, guys. Thanks. Just one for me. I guess on last quarter's call, we did touch on your strategic thoughts around Hess Midstream, 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 asset just by selling it to a third party and Bring up capital in the process just to potentially return that to shareholders.
Speaker 5
Philip, I mean, we are very happy with our midstream Investment in GIP is too. So the midstream continues to add what we believe is differentiated value to our E and 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, the high value markets. And as John mentioned earlier, we're very focused on minimizing our mission.
So it 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 helped Hess Midstream optimize Capital structure getting to that 3 times leverage position. So pro form a for these transactions Hess Midstream, it maintains a strong credit position And it has continuing free cash flow after distribution.
So, it will continue to have that low leverage and ample balance sheet capacity because With the free cash flow, we'll 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.
Speaker 2
Okay. And to be clear, our objective is to maximize the value of Hess Midstream to Hess and also maximize the value of Hess Midstream to its unitholders and GIP as well.
Speaker 9
Okay. Sounds good guys. Thank you.
Speaker 0
Thank you. Our next question comes from Neil Mehta with Goldman Sachs. You may proceed with your question.
Speaker 10
Good morning, team.
Speaker 2
Good morning, Steve.
Speaker 10
Good morning, guys. The kickoff question is on hedging. And You made some progress in terms of 2022 and implemented this collar strategy. Can you just talk high level Why you thought that was the appropriate way to attack hedging and it does appear to still leave you a lot of optionality on the On the upside while protecting your downside, but maybe kick off there.
Speaker 5
Sure. So I mean, our hedge strategy, I mean, this For 2022, it's consistent with our past strategy. We look to provide significant downside protection to put Do this while also giving 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 90,000 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 the program just to be more efficient with our hedging program.
But also, As you mentioned, we retain the exposure to greater than $2,000,000,000 in additional cash flow in the case of high oil prices above those hedge floor prices. So in addition, we have not hedged any of our natural gas, obviously, no NGL production is hedged and 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 for with higher oil prices. But again, We've got that significant price protection on the downside to continue the investment.
Speaker 10
Great, guys. And then the follow-up is just on the Bakken. Can spent 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
Speaker 4
Yes, Greg? Yes, 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, at $60 WTI, we have 2,200 future locations, which assuming You would go up to 4 rigs over 50 rig years of inventory. Our ultimate objective is to we'd like to get the Bakken back to 200,000 barrels a day. Why? Because that optimizes our infrastructure and maximizes the free cash flow generation of the Bakken. We can do that by adding a 4th rig And depending on market conditions next year, we would consider adding that 4th rig at the end of next year.
And I think the other thing that's important to remember is 4 rig to the maximum we will run-in the Bakken. That's 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 $750,000,000,000 $1,000,000,000 of free cash flow. So it just becomes 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.
Speaker 10
Thanks, team.
Speaker 0
Thank you. Our next question comes from Noel Parks with Tuohy Brothers. You may proceed with your question.
Speaker 3
Hey, good morning.
Speaker 2
Good morning.
Speaker 3
I was wondering if you could maybe Walk through some of the components of the resource estimate increase. You took it from 9,000,000,000 barrels to 10,000,000,000 barrels for the project. And I'm just particularly interested At the announcement, you said that some of that came from new discoveries like Catavac. But I'm just wondering The degree well, 2 things, the degree that maybe derisking from the most recent drilling helped contribute to the incremental increase. And also maybe you could drill down a little bit on sand quality in the most recent discoveries, The porosity is consistent with your pre drill analysis, etcetera.
Speaker 4
Yes, Greg? Sorry, I was on mute for a second. Look, I think the resource It was a combination of a lot of things. Obviously, the big things were Whiptail 1 and Whiptail 2 and Pinktail and Catibac. So those were the Primary drivers of taking that number from the 9 greater than $9,000,000,000 to approximately $10,000,000,000 So that was the majority of the change, that move.
I think it's important to also remember that in In spite of that, there's still multibillion barrels of additional upside above and beyond this 10,000,000,000 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 Catibac well, the last well that we announced had 102 feet of oil bearing sand, but 243 feet of hydro Carpet 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's no issues with sand quality or reservoir quality in any of those wells.
Speaker 3
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, does that helping form your optimism for future drilling and as you step out further?
Speaker 4
Sure. I think what it confirms is that that entire Eastern seaboard is what I like to call it from Turbot all the way to Liza and further north is just great reservoir rock. And so part of our strategy going forward In 2022, we'll 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 2022 is to get more penetrations in the deep. That's the one with the most uncertainty now. As we mentioned in 4th quarter, we'll drill a well called FANG2 that's specifically aimed at the deep stratigraphy.
And when I say deep, it's lower campaigning 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 programs continue to appraise all these outstanding discoveries that we've made, Right. So appraise, explore Upper Campanian, explore the deeper reservoirs, those are our 3 primary objectives next year.
Speaker 3
Great. Thanks a lot.
Speaker 0
Thank you. Our next question comes from David Heikkinen with Pickering Energy, you may proceed with your question.
Speaker 11
Good morning. I just wanted to check a couple of things on Yellowtail. Have you guys finalized, is it 45 or 55 wells with the 8 different Subsea sites? Just again trying to narrow down on what the total cost is going to be as we're putting estimates together.
Speaker 4
Yes. No, That's still under discussion with the partnership exactly what that configuration will be. And as we said, when we take final sanction, We'll be able to share all those details as to what the final project actually looks like.
Speaker 2
And to follow-up on the point that Greg was making, Yellowtail has world class economics and returns because we're covering a lot larger resource. So while people are focused on cost, they Should be focused on the resource, which is a lot higher. Once we get the FTP, we can give granularity on that. And again, the breakeven is going to be between $25 and $32 per barrel Brent.
Speaker 11
Yes. Yes. It's a much bigger aerial extent, it looks like.
Speaker 4
It is. Exactly.
Speaker 11
A huge area being developed with that versus IRR even. And then it was very helpful to put together the Incremental capital year over year. If I did my math right, is that roughly $2,000,000,000 $2,500,000,000 before exploration expense?
Speaker 5
No, that increase that I gave before. So it's 500 combined Bakken and Guyana and then 200 with Gulf of Mexico and Southeast Asia. So 700 from our 1.9 and that includes expiration.
Speaker 11
Okay. I have double added.
Speaker 5
Yes. No problem. And then obviously, I just always have to point out with Phase 2 comes We're picking up that at $60 Brent, that $1,000,000,000 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.
Speaker 11
And that's before a potential 4th rig in the Bakken, that would get you up to 200,000 barrels equivalent a day?
Speaker 5
That's correct.
Speaker 11
Perfect. I've got my numbers right now. Thanks guys.
Speaker 2
Thank you.