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. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Thank you, 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 Rielly, 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.

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 Rielly 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 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 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 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 a significant cash engine in the coming years as multiple phases of low cost oil developments come on line. 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 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 startup 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 interests in Denmark for a 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 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 queue of future low cost oil developments. 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 Liza Phase 1 complex averaged 124,000 barrels of oil per day in the third quarter. The Liza Phase 2 development is on track for startup in early 2022 with a gross production capacity of 220,000 barrels of oil per day, and the Liza 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 triple-A rating in the MSCI ESG ratings for 2021 after earning double-A ratings for the previous 10 consecutive years. The triple-A rating designates 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.

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 on line. In the fourth quarter, we expect to drill approximately 19 wells and to bring approximately 18 new wells on line. And for the full year 2021, we continue to expect to drill approximately 65 wells and to bring approximately 50 new wells on line. 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 had 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-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. The 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 mooring 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. Topsides fabrication at Dyna-Mac 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 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 three discoveries since July. In July, we announced that the Whiptail1 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-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 at Cataback, located approximately 4 miles east of Turbot-1. The well encountered 243 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 the Fangtooth-1 exploration well, located approximately 11 miles northwest of Liza-1. This well is a significant step-out test that will target deeper Campanian and Santonian aged reservoirs. Appraisal activities 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 Rielly.

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 interests 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 cargos of oil in the third quarter, up from two 1 million barrel cargos of oil sold in the second quarter. For the third quarter, our E&P sales volumes were underlifted 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 non-controlling interests, 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 interests 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 costs, 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 $1,095 million 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 million 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 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 $161 million, which will be amortized ratably over 2022. During the fourth quarter, we expect to sell two 1 million barrel cargos 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 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 million 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.

Thank you. [Operator Instructions] Your first question comes from the line of Arun Jayaram with JP Morgan.

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 first oil?

Yes, sure. So, thanks for the question, Arun. Remember now that it’s arrived in water, 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 definitive than that, but early 2022 looks like very possible.

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, et cetera, 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 provider did put some color around the subsea kit that they expect around Yellowtail and Uaru. They cited maybe a $500 million to $1 billion range for Yellowtail and a little bit over $1 billion for Uaru. So, just maybe you could just help us think about inflationary pressures, Greg?

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 one, build many strategy, to deliver efficiencies. Now, on the 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 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 superefficient 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.

Our next question comes from Doug Leggate with Bank of America.

Guys, I know you haven’t given a 2022 outlook yet. 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 at your Strategy Day. And I wonder if I could just ask you to give us a kind of framework as to how we should think about the spending trajectory? And if I may, embedded in that question, be blunt with you that I think there’s some concern over the cost, the sticker shock on Yellowtail. So, if I threw out a number and said where we should be thinking something in the $12 billion type of range, would that be off the mark?

Doug, let me start with just giving some color on our capital for 2022. Now, you know, 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 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’re looking at Bakken, approximately $250 million of a capital increase as we look at next year, obviously, with a pickup in production and an increasing cash flow that will also as well coming from Bakken. In Guyana, we expect our development spend. So, we went into the year with the guide with $780 million for our development spend in Guyana. We’re going to come in under that. And so, let me just say we’ll probably be approximately $750 million on our Guyana development spend this year. So, with Liza Phase 2 and a continued development on Payara, and we’ll 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 are Gulf of Mexico and Southeast Asia. So, on the Gulf of Mexico, 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 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 million. So I’ve got $500 million from Bakken and Guyana, $200 million Gulf of Mexico and Southeast Asia. But I have to remind everyone, we’ll have Liza Phase 2 coming on line. 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 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 on. So, that’s a directional. We’ll update in January. John, do you want to talk on Yellowtail?

Yes. And Doug on Yellowtail well, the FTP has been submitted to the government, and it is higher cost. I think everybody needs to realize that this FPSO is going to have capacity 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 its 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, 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.

So, I wouldn’t [Technical Difficulty] anyone at $12 billion…

I won’t comment on that. Let’s let the FTP be approved, and then we’ll announce the official number.

Thanks. My follow-up, hopefully a quick one. And that really is on Yellowtail. You mentioned the 250,000 is now being confirmed in the release, EIX, it’s still 220,000, 250,000. Greg, I just want to just check in with you on how should we think about production optimization on all of these FPSOs? Is it 10% to 15%, in other words, above the nameplate?

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 sizes 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 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 achieved for very low investment. And obviously, with PSC, the rapid cost recovery, these are very profitable things to do.

Our next question comes from Paul Cheng with Scotiabank.

I think previously that the expectation of the debottleneck in Liza-1 will be doing at the same time as the turnaround, and now, it’s being separate and push it to the first quarter. Is there any particular reason for that decision?

Greg?

Yes. So, Paul, as you said, the optimization work on Destiny 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 had the vessel down, which we fully support.

Would that be more efficient that when the vessel is done, then you do the optimization? I mean, I’m actually surprised you say it will be more efficient to separate into two events.

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 et cetera and that’s why it got pushed to the first quarter.

And Greg, I think originally, when you signed the agreement with the Guyana government, at some point that you guys are supposed to develop the gas resource there. I mean, now that I think up to Yellowtail, it doesn’t seem so you guys are going to do it. So, any game plan when that the gas will need to be developed or that means time line still subject to the negotiation with the government?

Greg?

Yes. So, I think there’s 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, 50 million to 100 million cubic feet a day pipeline to shore that is -- would supply gas in 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 a sanction. Regarding the long-term gas solution, which is what I think you were referring to, there are studies out today, but it’s way out in the future, Paul. So, it’s not anything certainly we need to worry about 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 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.

And the final question for me, I think, it’s for John. John, I think you mentioned that once that your net debt to EBITDA get to say below 2 times, you will consider increasing the cash return to shareholders. And at that point that how should we look at it? I mean, is there ways you’re 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 it’s just going to be increasing the common dividend, or that is the variable dividend? How should we be looking at those?

Sure. So, our strategy remains the same, and you said it, basically would get Phase 2 on line, 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 comes on, we get significant -- as I mentioned earlier, another $1 billion with IR, another $1 billion with Yellowtail, will have an increasing free cash flow. We’ll 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.

John, when you’re talking about that once you drop below 2 times, I suppose that your ultimate target will be much below 2 times EBITDA ratio. So, what is that ultimate ratio you want? Is it less than 1-time or less than half a multiple point?

Yes. I’m going to answer it two 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 maturity -- $300 million maturity coming in 2024. 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 1 time fairly quickly actually when these FPSOs come on line. 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.

And your next question comes from Phillips Johnston with Capital One.

Just one for me. I guess, on last quarter’s call, we did touch on your strategic thoughts around test 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 200,000 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 freeing up capital in the process just to potentially return that to shareholders?

Phillips, I mean, we are very happy with our midstream investment and GIP is two. 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, 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, as Midstream get their liquidity up there. And the Q3 buyback actually helped 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 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.

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.

Our next question comes from Neil Mehta with Goldman Sachs.

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 upside while protecting your downside, but maybe kick off there.

Sure. So, I mean, our hedge strategy, I mean, this is 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 collars, 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 at $65 and the ceiling at $95. We use those high ceiling collars 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 billion 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 productions 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 with higher oil prices. But again, we’ve got that significant price protection on the downside to continue the investment.

Great, guys. And then, the follow-up is just on the Bakken. Can 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?

Greg?

Yes, sure. So remember, 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. 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 we’d like to get the Bakken back to 200,000 barrels a day. Why? Because that optimizes -- maximizes the free cash flow generation of the Bakken. We can do that by adding a fourth rig. And depending on market conditions 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 4 rigs, 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 million and $1 billion 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.

Our next question comes from Noel Parks with Touhy Brothers.

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 just particularly interested, at the announcement, you said that some of that came from new discoveries, like Cataback. But I’m just wondering the degree -- well, two things, the degree that maybe derisking from the most recent drilling help contribute to the incremental increase. And also, maybe you could drill down a little bit on sand quality in the most recent discovery. The porosity is the consistent -- consistent with your predrill analysis, et cetera?

Yes, Greg.

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 were Whiptail-1 and Whiptail-2 and Pinktail and Cataback. So, those were the primary drivers of taking that number from the 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’s 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’s no issues with sand quality or reservoir quality in any of those wells.

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

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 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’ll drill a well called Fangtooth that’s specifically aimed at the deep stratigraphy. And when I say deep, it’s lower Campanian, upper Santonian, which is about 3,000 feet deeper than those upper Campanion reservoirs. And then the third objective of our 2022 exploration and appraisal program is continue to appraise all these outstanding discoveries that we’ve made, right? So, appraise, explore upper Campanion, explore the deeper reservoirs. Those are our three primary objectives next year.

Our next question comes from David Heikkinen with Pickering Energy.

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?

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.

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 talking -- 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.

Yes, it’s a much bigger barrel extent, it looks like.

Exactly.

A huge area of being developed with that versus Payara, 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?

No, that increase that I gave before. So, it was 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.

Okay. I thought…

Yes, no problem. And then, obviously, I just always have to point out what Phase 2 comes on, we’re picking up that at $60 Brent, $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.

And that’s before a potential fourth rig in the Bakken that would get you upto 200,000 barrels equivalent a day?

That’s correct.

Perfect. I’ve got my numbers right, now. Thanks, guys.

Thank you.

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