Good day, ladies and gentlemen, and welcome to the Third Quarter 2022 Hess Corporation Conference Call. My name is Carman, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Thank you, Carman. 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 speakers prepared remarks on www.hess.com following the presentation. I’ll now turn the call over to John Hess.

Thank you, Jay, good morning. Welcome to our third quarter conference call. Today, I will share some thoughts about the oil markets and then review our progress in executing our strategy. Greg Hill will then discuss our operations, and John Rielly will review our financial results. Global oil demand has returned to pre-COVID levels of approximately 100 million barrels per day. As we look to 2023, even with a recessionary environment and a slowing world economy, we expect global oil demand to grow by at least one million barrels per day driven by China reopening its economy and an increase in global air travel. Oil supply, on the other hand, continues to struggle to keep up with global demand. Global oil inventories are approximately 300 million barrels less than pre-COVID levels, and there is very little spare production capacity in the world. Oil markets were tight even before Russia invaded Ukraine and are expected to get even tighter this winter with the potential for further sanctions on Russian oil exports. The world is facing a structural supply deficit and significantly more global oil investment is needed. According to the International Energy Agency, a reasonable estimate for the global oil and gas investment needed for supply to meet demand is approximately $500 billion each year over the next 10 years. The last five years have seen significant underinvestment, which will tighten supply as global oil demand grows in the years ahead. The International Energy Agency’s World Energy Outlook provides multiple scenarios for addressing the dual challenge of growing global energy supply by about 20% over the next 20 years and reaching net-zero emissions by 2050. In all of these IEA scenarios, oil and gas will be needed for decades to come. So, to ensure an affordable, just and secure energy transition, we need to invest significantly more in oil and gas, and we also must have government policies that encourage investment, rather than discourage it. In a world that will need reliable, low cost oil and gas resources for decades to come, Hess is very well positioned. Our strategy is to deliver high return resource growth, a low cost of supply and industry leading cash flow growth, and at the same time maintain our industry leadership in environmental, social and governance performance and disclosure. Our successful execution of this strategy has uniquely positioned our company to deliver significant value to shareholders for years to come, by growing both intrinsic value and cash returns. By investing only in high return, low cost opportunities, we have built a differentiated and balanced portfolio focused on Guyana, the Bakken, deepwater Gulf of Mexico, and Southeast Asia. With multiple phases of low cost oil developments coming online in Guyana and our robust inventory of high return drilling locations in the Bakken, we can deliver highly profitable production growth of more than 10% annually over the next five years. As our high quality resource base expands, we will steadily move down the cost curve. Our four sanctioned oil developments in Guyana have a breakeven Brent oil price of between $25 and $35 per barrel. In terms of cash flow growth, we have an industry leading rate of change story and durability story, providing a unique value proposition. Based upon a flat Brent oil price of $65 per barrel, our cash flow is forecast to increase by approximately 25% annually between 2021 and 2026 more than twice as fast as our top-line growth, and our balance sheet will also continue to strengthen, with debt to EBITDAX expected to decline to under one time in 2024. As our portfolio becomes increasingly free cash flow positive in the coming years, we are committed to returning up to 75% of our annual free cash flow to shareholders, with the remainder going to strengthen the balance sheet by increasing our cash position or further reducing our debt. We continued common stock repurchases during the third quarter, repurchasing $150 million of stock as part of the $650 million stock repurchase program announced earlier this year, and we intend to repurchase the remaining $310 million of stock in the fourth quarter. Looking ahead, we plan to continue increasing our regular dividend to a level that is attractive to income-oriented investors, but sustainable in a low oil price environment. As our free cash flow generation steadily increases in the years ahead, share repurchases will represent a growing proportion of our return of capital. Key to our strategy is Guyana, one of the industry’s highest margin, lowest carbon intensity and highest growth oil and gas prospects according to Wood Mackenzie data. On the Stabroek Block in Guyana, where Hess has a 30% interest and ExxonMobil is the operator, we continue to see the potential for six floating production storage and offloading vessels or FPSOs in 2027 with a gross production capacity of more than one million barrels of oil per day and up to 10 FPSOs to develop the discovered resources on the block. In terms of our sanctioned oil developments on the block: The Liza Phase 1 and Liza Phase 2 developments are currently operating at their combined gross production capacity of more than 360,000 barrels of oil per day. Our third development at the Payara Field, with a gross production capacity of approximately 220,000 barrels of oil per day, remains on schedule for start up at the end of 2023. Our fourth development, Yellowtail, which was sanctioned in April, will be the largest development to date on the Stabroek Block with first oil expected in 2025. The project will develop an estimated recoverable resource base of approximately 925 million barrels of oil and have a gross production capacity of approximately 250000 barrels of oil per day. Front end engineering and design work for our fifth development at Uaru is underway, with a Plan of Development expected to be submitted to the government before year end. In terms of exploration and appraisal in Guyana, this morning we announced two new discoveries on the block at Yarrow and Sailfin, bringing our total this year to nine. These discoveries will add to the previously announced gross discovered recoverable resource estimate for the Stabroek Block of approximately 11 billion barrels of oil equivalent – and we continue to see multibillion barrels of future exploration potential remaining. In Suriname, we recently drilled the Zanderij-1 well, where Hess has a 33% interest and Shell is the operator. The well demonstrated a working petroleum system and encountered oil pay. The well results are being evaluated and further exploration activities are being considered. Turning to sustainability, we are proud to be recognized as an industry leader in our environmental, social and governance performance and disclosure. Hess has once again achieved Level 4 status in the Transition Pathway Initiative’s recent management quality assessment, which is the highest level awarded to companies that demonstrably manage climate-related risks and opportunities from a governance, operational and strategic perspective in line with the Task Force on Climate-related Financial Disclosures (TCFD) recommendations. In summary, we continue to successfully execute our strategy and deliver strong operational and ESG performance. We truly offer a unique value proposition – to grow both our intrinsic value and our cash returns by increasing our resource base, delivering a lower cost of supply and generating the best cash flow growth among our peers, major oil companies and the top quartile of the S&P 500. As our portfolio becomes increasingly free cash flow positive, we will continue to prioritize the return of capital to our shareholders through further dividend increases and share repurchases. I will now turn the call over to Greg Hill for an operational update.

Thanks, John. In the third quarter, we delivered strong operational performance. Companywide net production averaged 351,000 barrels of oil equivalent per day excluding Libya, compared to our guidance of 330,000 to 335,000 barrels of oil equivalent per day. This production beat reflects strong performance across our portfolio. For the fourth quarter, we expect companywide net production to average approximately 370,000 barrels of oil equivalent per day, excluding Libya. For the full year 2022, we now expect companywide net production to average approximately 325,000 barrels of oil equivalent per day, excluding Libya, up from our previous guidance of approximately 320,000 barrels of oil equivalent per day. Turning to the Bakken, third quarter net production averaged 166,000 barrels of oil equivalent per day. This was above our guidance of 155,000 to 160,000 barrels of oil equivalent per day and primarily reflected strong execution and recovery following challenging weather conditions in the first half of the year. For the fourth quarter, we expect Bakken net production to average between 165,000 and 170,000 barrels of oil equivalent per day. For the full year 2022, we now forecast Bakken net production to average approximately 155,000 barrels of oil equivalent per day, which is the high end of our previous guidance range of 150,000 to 155,000 barrels of oil equivalent per day. In the third quarter, we drilled 20 wells and brought 22 new wells online. For the fourth quarter, we expect to drill approximately 30 wells and to bring approximately 25 new wells online; and for the full year 2022, we expect to drill approximately 90 wells and to bring approximately 80 new wells online. In terms of drilling and completion costs, although we continue to experience cost inflation, we are maintaining our full year average forecast of $6.3 million per well in 2022. Given the improvement in oil prices and our robust inventory of high return drilling locations, we added a fourth rig in July. Moving to a four rig program will allow us to grow net production to approximately 200,000 barrels of oil equivalent per day in 2024, which will maximize free cash flow generation, 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 30,000 barrels of oil equivalent per day, which was at the high end of our guidance range of 25,000 to 30,000 barrels of oil equivalent per day, primarily reflecting the successful start up of the Shell-operated Llano 6 tieback. For the fourth quarter and full year 2022, we forecast Gulf of Mexico net production to average approximately 30,000 barrels of oil equivalent per day. In Southeast Asia, net production in the third quarter was 57,000 barrels of oil equivalent per day, above our guidance of approximately 55,000 barrels of oil equivalent per day. Planned maintenance work was successfully completed at both the North Malay Basin and JDA assets during the third quarter. Fourth quarter and full year 2022 net production is forecast to average between 60,000 and 65,000 barrels of oil equivalent per day. Now turning to Guyana. In the third quarter, net production from the Liza Phase 1 and Phase 2 developments averaged 98,000 barrels of oil per day, including tax barrels of 7,000 barrels of oil per day – above our guidance of 90,000 to 95,000 barrels of oil per day. Both the Liza Destiny and Liza Unity Floating Production, Storage and Offloading vessels delivered strong operating performance and high facility uptime during the quarter. Guyana net production is forecast to average approximately 110,000 barrels of oil per day in the fourth quarter, including tax barrels of 20,000 barrels of oil per day. For the full year 2022, Guyana net production is forecast to average approximately 77,000 barrels of oil per day, including tax barrels of 7,000 barrels of oil per day, slightly above our previous guidance of 75,000 barrels of oil per day. Turning to our third sanctioned development at Payara, topsides installation and development drilling are underway. The overall project is approximately 88% complete. The FPSO Prosperity will have a gross production capacity of 220,000 barrels of oil per day and is on track to achieve first oil at the end of 2023. Our fourth sanctioned development at Yellowtail will utilize the ONE GUYANA FPSO with a gross capacity of approximately 250,000 barrels of oil per day. Fabrication of topside modules kicked off in September and the hull is expected to arrive in Singapore in early 2023. The overall project is approximately 29% complete and is on track to achieve first oil in 2025. With regard to our fifth development, Uaru, the operator plans to submit a Plan of Development to the government before the end of this year, with approval expected by the end of the first quarter of 2023. The plan utilizes an FPSO with a gross capacity of approximately 250,000 barrels of oil per day with first oil targeted for the end of 2026. As John mentioned, this morning, we announced discoveries at Yarrow and Sailfin. The Yarrow-1 well, located approximately nine miles southeast of the Barreleye-1 well, encountered 75 feet of high quality, oil bearing sandstone reservoir. The Sailfin-1 well, located approximately 15 miles southeast of the Turbot-1 well, encountered 312 feet of high quality, hydrocarbon bearing sandstone reservoir. The Banjo-1 well did not encounter commercial quantities of hydrocarbons and was expensed in the third quarter. The Banjo-1 well did not encounter commercial quantities of hydrocarbons and was expensed in the third quarter. On Block 42 in Suriname, we recently drilled the Zanderij-1 well, where Hess has a 33% interest and Shell is the operator. The well demonstrated a working petroleum system and encountered oil pay. The well results are being evaluated and further exploration activities are being considered. Looking forward, fourth quarter exploration and appraisal activities on the Stabroek Block in Guyana will include the Fangtooth SE-1 well, which is a deep test located approximately 8 miles southeast of the Fangtooth-1 discovery well. We will also drill the Fish-1 exploration well located approximately 62 miles northwest of Liza-1. This well will target multiple stacked reservoir intervals. In addition, we plan to drill the Lancetfish-1 well, located approximately 3 miles west of the Liza-3 well which will target deeper reservoirs. In closing, our execution continues to be strong. The Bakken is on a strong, capital efficient growth trajectory, our Gulf of Mexico and Southeast Asia assets continue to generate significant free cash flow, and Guyana continues to get bigger and better – all of which position us to deliver industry leading returns, material free cash flow generation and significant shareholder value. 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 2022 to the second quarter of 2022. We had net income of $515 million in the third quarter of 2022, or $583 million on an adjusted basis. Net income was $667 million in the second quarter of 2022. Turning to E&P. E&P adjusted net income was $626 million in the third quarter compared with $723 million in the second quarter. The changes in the after-tax components of E&P earnings between the third quarter and second quarter of 2022 were as follows: Higher sales volumes increased earnings by $370 million. Lower realized selling prices decreased earnings by $314 million. Higher DD&A expense decreased earnings by $70 million. Higher cash costs and Midstream tariffs decreased earnings by $55 million. Higher exploration expenses decreased earnings by $22 million. All other items decreased earnings by $6 million for an overall decrease in third quarter earnings of $97 million. In the third quarter we sold eight cargos of crude oil in Guyana, up from six cargos in the second quarter. For the third quarter, our E&P sales volumes were underlifted compared with production by approximately 1 million barrels which decreased our after-tax income by approximately $50 million. In the fourth quarter, we expect to sell nine cargos from Guyana. Turning to Midstream. The Midstream segment had net income of $68 million in the third quarter of 2022 compared with $65 million in the second quarter. Midstream EBITDA, before noncontrolling interests, amounted to $252 million in the third quarter of 2022 compared to $241 million in the previous quarter. Turning to our financial position. At September 30, excluding the Midstream segment, cash and cash equivalents were $2.38 billion, and total liquidity was $5.73 billion including available committed credit facilities, while debt and finance lease obligations totaled $5.60 billion. In the third quarter, we continued our common stock share repurchases with the purchase of approximately 1.4 million shares for $150 million. We intend to acquire the remaining board authorized amount of $310 million in the fourth quarter of this year. Total cash returned to shareholders in the third quarter amounted to $265 million including dividends. Net cash provided by operating activities before changes in working capital was $1.4 billion in the third quarter compared with $1.5 billion in the second quarter, primarily due to lower realized selling prices. In the third quarter, changes in operating assets and liabilities decreased cash flow from operating activities by $66 million. E&P capital and exploratory expenditures were $701 million in the third quarter and $622 million in the second quarter. Now turning to guidance. First for E&P, our E&P cash costs in the third quarter of 2022 were $13.19 per barrel of oil equivalent, including Libya, and $13.64 per barrel of oil equivalent, excluding Libya. We project E&P cash costs, excluding Libya, to be in the range of $13 to $13.50 per barrel of oil equivalent for the fourth quarter and in the range of $13.50 to $14 per barrel of oil equivalent for the full year, which is unchanged from our previous guidance. DD&A expense was $12.56 per barrel of oil equivalent, including Libya and $13.03 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 $12.50 to $13 per barrel of oil equivalent for the full year, which is also unchanged from our previous guidance. This results projected total E&P unit operating costs, excluding Libya, to be in the range of $26 to $27 per barrel of oil equivalent for both the fourth quarter and full year 2022. Exploration expenses, excluding dry hole costs, are expected to be approximately $40 million in the fourth quarter and approximately $155 million for the full year, which is down from our previous full year guidance of $160 million to $170 million. The Midstream tariff is projected to be approximately $310 million for the fourth quarter and approximately $1,205 million for the full year, which is within the range of our previous full year guidance of $1,190 million to $1,215 million. E&P income tax expense, excluding Libya is expected to be approximately $210 million for the fourth quarter and approximately $560 million for the full year, which is up from our previous full year guidance range of $540 million to $550 million. We expect non-cash option premium amortization, which will be reflected in our realized selling prices, will be approximately $165 million for the fourth quarter. Our E&P capital and exploratory expenditures are expected to be approximately $800 million in the fourth quarter and full year guidance of approximately $2.7 billion remains unchanged. For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be approximately $65 million for the fourth quarter and approximately $270 million for the full year, which is the midpoint of our previous full year guidance range of $265 million to $275 million. For corporate; Corporate expenses are estimated to be approximately $35 million for the fourth quarter and approximately $135 million for the full year, which is down from our previous full year guidance of approximately $150 million. Interest expense is estimated to be approximately $85 million for the fourth quarter and approximately $345 million for the full year, which is at the lower end of our previous full year guidance range of $345 million to $350 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] Our first questions come from the line of Arun Jayaram with JPMorgan Securities. Your line is open.

Yeah. Good morning, Arun Jayaram from JPMorgan.

Morning.

Morning guys. John, I know you guys are pretty knee deep, in your planning and budgeting process, but I was wondering if you could offer any, soft guidance commentary for 2023 as we think about volumes and CapEx and what is obviously in a little bit more of an inflationary environment in particularly offshore.

Sure, Arun. Thanks for the question. As usual, we will provide, to your point, our 2023 capital guidance in January, but I'll try to give you some high-level information now compared to 2022. So if we're going to start with Guyana. In 2022, we have $1 billion of development spend. And as you know, that includes two projects, Payara and Yellowtail. So in 2023, we will continue spending on Payara and Yellowtail, but we will add, subject to government approval, a third development project at Uaru. And, to a lesser amount a gas to energy project as well. So while the Uaru project is going to have industry-leading returns and a low cost of supply, the cost of the Uaru project, as you mentioned, will be higher, reflecting the current market conditions as well as additional scope to reduce greenhouse gas emissions. So with that, we currently expect our Guyana spend to increase by approximately $500 million to $700 million in 2023. So the midpoint of that would be going up from $1 billion to $1.6 billion. In the Bakken, we are spending approximately $850 million this year, and we added the fourth rig later in the year. So we expect an additional $250 million of spend in 2023, reflecting a full year of a 4-rig program. And that 4-rig program as well as the expected industry inflation drives that $250 million increase there in the Bakken. In the Gulf of Mexico, we are still finalizing our 2023 program, but we do see the potential for two well tiebacks and also one hub class exploration opportunity. So with that is approximately $150 million increase in the Gulf of Mexico. So therefore, adding those up, taking the midpoint of the Guyana number, we expect our 2023 capital exploratory spend, and again, it's preliminary to be approximately $3.7 billion or about $1 billion more than 2022.

Great. And any thoughts on just overall volumes or too premature at this point?

It is premature at this point. And I mean, again, think about us from a longer-term standpoint on production growth, we've seen that we can grow our top line production growth. And it's just an output of the great opportunities that we have in Guyana that over the long term, we can grow at greater than 10%. Because – just think about in 2024 now, as Greg mentioned earlier, we'll get the Bakken to 200,000 barrels a day. And then we'll have Payara on as well. So that's going to add another 50,000 to 55,000 barrels. So right then add those two together, you're almost up 25% absolute from where we are right now. So again, as we move into next year, we'll give that production guide early in the year. But the growth is going to be lumpy basically when the FPSOs come online. So that's how you should think about it as we move into next year.

Great. And just my follow-up, I wanted to – I've gotten some buy-side queries on Exxon's release today. And maybe you could just help clarify they mentioned in their release that they expect Guyana's oil productive capacity to be more than 1 million barrels by the end of the decade. John, today, you mentioned you'll have six FPSOs by 2027, which is in line with the consortium's previous outlook. Anything in that comment, in Exxon's release that you could kind of clarify?

No, you have to ask Exxon about that but our comment about by 2027 having productive capacity growth of over 1 million barrels of oil per day. That's very consistent with what Exxon has said the last several years, and that's the correct…

Okay, great. Probably just semantics. Thanks a lot, John.

Thank you. [Operator Instructions] Our next question comes from the line of Doug Leggate with Bank of America. Your line is open.

I love the pronunciation. Good morning everybody.

Good morning Doug.

John, I guess I would like to – sorry to be up on this last point that Arun mentioned. But I know I've asked you and I've asked Exxon this before and anyone who's listened – knows that Exxon's answer is they're basically being conservative. But tell me why, with the long plateaus that you're clearly going to have in these boats, so the production capacity of an additional [indiscernible] doesn't get you close to $1.3 billion. Over $1 million just seems to me is getting a bit old, pardon my expression, but it looks to us, at least 30% over that was what you've got line of sight on. Why is that not right?

Doug, I think the 2027 number of six FPSOs and at least 1 million barrels a day of gross production is a good number. It's a conservative number, and is there some upside to that? Yes, there certainly is.

Is my math wrong?

No. Well, as opposed to talking about your math, let's talk about our math. We're saying 1 million barrels a day, six FPSOs, 2027, there's upside to that number.

Okay. All right. Sorry to press. All right. My follow-up is as you look into – John's obviously walked through the CapEx story. Obviously, the cash – the recovery of the cash flow of CapEx in Guyana makes a lot of that, obviously, just somewhat move to the overall cash return story, I guess, given how quickly you get the money back. So I guess my question is that the 75% of free cash flow target, you're clearly lagging that this year. What can we expect by way of an inflection in cash returns in 2023 at pricing current strip?

Yes Doug, thanks for the question. It's an excellent one. As we look to 2023, our financial priorities remain first, to invest in our high-return opportunities, especially in Guyana and Bakken that John talked about, the $3.7 billion capital program. Second to maintain a strong cash position and balance sheet to ensure that we can fund these high-return opportunities and investments through the cycle. Then we would give strong consideration next year to further increasing our regular dividend. And then following that, in line with the capital return program, where we have committed to returning the remainder of our free cash flow up to 75% through share repurchases. And similar to this year, we have the flexibility to return in excess of 75%. You'll recall, at the end of the quarter, we had $2.38 billion of cash on the balance sheet. So we have flexibility for next year. So depending upon market conditions, oil prices, financial prices, where the recession and the economic slowdown come out, we'll be positioned to increase our return on capital further. But that's going to be a decision that we'll make as we go into next year. First, to make sure that we can fund our high-return programs; second, keep the strong balance sheet; third, increase the dividend. And then anything left over as we go out, not just next year but in the years ahead, and we deliver increasing levels of free cash flow. We expect share repurchases will represent a growing proportion of our capital return program in the years ahead.

So, John, just to be clear, you've got a debt maturity next year. How much is that?

It's actually in 2024, and it's $300 million, in 2024. And we do expect to...

2024, got it.

Yes. Hey Doug, I just want to make sure what you said earlier because this year, we are actually returning more than our 75% in our framework. So just remember, our framework, we did our debt reduction of $500 million. And as John mentioned, our framework has the flexibility when oil prices are strong to do more than 75%. And that's what we are doing this year. As John mentioned, we'll complete the $310 million in the fourth quarter. So again, we have that flexibility to stay strong. And as John said, depending on market conditions, we'll do 75% or more, we'll see.

Thanks so much guys.

Thank you. [Operator Instructions] Our next question comes from Stephen Richardson with Evercore. Please go ahead.

Good morning. Thank goodness for easy to pronounce names. Could I was wondering if I could ask Greg, a couple on exploration. On one, it seems that you've got a success at Uaru and Banjo-1 sounds like it wasn't. Our recollection was that this was testing for the inboard oil play to the Southeast. Could you maybe talk about a little bit more to the extent that you're able in terms of those two? And what was confirmed and what wasn't? And what we should take away from that?

Yes, sure. So first of all, I would say the inboard oil play has been very successful because we've had four discoveries in the area. So recall, Barreleye had 230 feet of high-quality pay. Seabob had 131 feet of high-quality pay, as we announced this morning; Uaru had 75 feet of high-quality pay. And finally, Lukanani had 115 feet of high-quality pay. So all of those will help to underpin a future development. And even though Banjo was dry, it had noncommercial qualities of – quantities of hydrocarbons; it had hydrocarbons that went through it. We've got more wells to drill in that area. So if I step back and say four successes, one non-commercial and more to come, I still feel very optimistic about – I still feel very optimistic about the inboard play. And also, I think it's important to know that Banjo was the Western most prospect that we drilled in that inboard play as well.

That's helpful. And maybe, Greg, I mean, this whole semantics around the 1 million barrels or the six boats or the 10 boats or whatever it may be, could you maybe – at what point should we be thinking that we get more clarity in terms of the length of plateau versus additional boats? Is this something that we're going to be – get some additional clarity on the next 12, 24 months? Or is this a longer event as we kind of see how the reservoirs react in production? But it seems to us that’s the – as we think about recovering 11-plus billion barrels, those are kind of the two variables?

Yes. Steve, I want Greg to answer that. But you have the clarity on what production is going to be. It grows a million barrels a day at least in 2027. I think that’s really important. So people don’t get confused by other releases. That is the number, and there’s upside to that. Now, Greg can talk more about tiebacks and plateaus, but that million barrels a day is a very good number that people should use in terms of having clarity and visibility of the production growth trajectory.

Okay. Great. So, I think the plateau rates or lengths, I should say, are going to vary by vessel. However, given the high resource density and the potential for near-field tiebacks. And that’s in both the upper campaign and the deeper plays, because remember, the deep play underlies the shallow or upper campaign in reservoir. So, we expect to see these production plateaus main for a longer period than what would be typical for other deepwater development. So, I’m pretty optimistic about the length of the plateaus. But again, each one will be bespoke based upon the reservoir density in and around each vessel.

Thank you.

Thank you. Our next question comes from the line of Neil Mehta with Goldman Sachs. Please go ahead.

Good morning team.

Good morning.

Morning, John. First question is around the Bakken. Really good quarter for you guys here after some weather issues earlier this year. Can you just refresh us on how we should be thinking about the trajectory in the Bakken in 2023 and then as you get into 2024 as well?

Sure. So, we guided $165 million to $170 million in the fourth quarter of this year. And that really reflects a couple of things. One is most of the wells are going to be completed at the back end of the quarter. We also looked at our historic kind of weather performance in the fourth quarter, and we increased our contingency a little bit in the fourth quarter to reflect that. If you think about where we’re headed in the Bakken with the four rigs, that’s going to allow us to increase production to about 200,000 barrels a day in 2024. And with our extensive inventory of high-return wells, we expect to hold this plateau for nearly a decade and then generate significant free cash flow. And during that period of time, you can assume that the oil percentage of the wellhead is going to be broadly flat at around that 65%. So, you can almost end point this year and pretty much straight line to the end of 2024, assuming the end of 2024 would be 200,000, and that will give you a reasonable approximation of what the trajectory will be.

All right. That’s good color here. And then, John, if I could ask you to step back and talk about your view on the macro, you always have a good read on the oil markets. Just your perspective on where we are in terms of the rebalancing as you go into 2023? And how that feeds into your framework around hedging given the backwardation in the curve?

Yes. I’ll give some remarks on further detail on how we see the oil market, and John Rielly will talk about our hedging. Look, the impact of high interest rates, strong dollar, inflation obviously is being felt in the financial markets. You know better than anybody, from your perspective, it’s already being felt, not only in the financial markets and the pullback, but also in certain parts of the economy. But I have to say, even though we’ve seen a slowing of demand in China and in Europe overall, global oil demand continues to be pretty resilient. And we’re not seeing a major impact from inflation in the high dollar in oil demand itself. And in fact, as we look out to next year between China reopening its economy and continuing to increase overall global air travel, we see upside to current demand globally of 100 million barrels or going up a million barrels a day next year. I don’t think if there is a pullback in the economy where it does affect oil demand, I don’t think it’s going to be anywhere near what it was during the world financial crisis, which was upwards of two million barrels a day. But I think part of what’s going on here, there’s been a slow but steady increase in demand recovering from COVID, and we haven’t completed that recovery yet. And that’s the major reason, oil demand. We think as you go into next year, we’ll go up at least a million barrels a day from the 100 million a day right now. The risk, I think, is to the upside. What’s going to happen with Russia oil supply, what’s going to happen with Russia gas supply? How do we get through the winter? I think – how cold is the winter? That if anything, could increase that million barrels a day that I just talked about. As you know, there’s oil substitution for gas supply industrially, some residential, commercial, both in Europe and Asia, obviously, on the electricity side. How much that fuel substitution remains to be seen as well. So, we see the market if anything, having strengthening impact tailwinds going into the winter. And as such, I’d say there’s more upside to the price from where we are now than there is downside. But with that sort of as a backdrop, John, how about our hedging?

Sure. So with that backdrop, I mean, Neil, what we do is, we use put options for our hedging strategy. And with all the variables that John just mentioned and the time value here the volatility levels right now, putting on the puts would be too expensive. So, we do plan to get the similar level of hedge protection that we had this year. Now, we will continue to watch the market. We’ll try to get some on in the fourth quarter, but it could be early next year that we get these hedges on. So, you should expect us to get that – a similar hedge position on. It will just be a matter of timing when we do it. And again, just with put options.

And again, to underline what John said, that’s to protect the downside and still give our shareholders the benefit of the upside.

Makes a lot of sense. Thank you both.

Thank you. [Operator Instructions] Our next question comes from the line of Roger Read with Wells Fargo. Please go ahead.

Yes. Good morning. Going to come back, I guess, a little bit on the CapEx, and I know you’re hesitant to get any more than what you’ve had. But I’m just a little curious as you look across the various regions you operate onshore, U.S., offshore, U.S. and Guyana, how much of – when you look out, you can say, is fairly well committed or contracted, signed where there’s not a lot of risk of a surprise as we think about 23% on the CapEx front, the underlying inflation that we’re just kind of seeing everywhere?

Yes. So on the inflation, like our competitors, we’re seeing upward pressure across both our onshore and offshore businesses and steel prices, labor costs, rig rates. So let’s talk about the Bakken first. Regarding the Bakken, now what we’ve seen this year, the industry has seen overall inflation of 15% to 20% versus 2021. However, as you know, our teams have been able to reduce this to 8.5%. And we’ve done that through lean manufacturing, strategic contracting and technology, and that’s enabled us to deliver that B and C cost of $6.3 million per well in 2022. So our net inflation has been about half of what the industry has seen in the Bakken, if you will. Now, if we look to 2023 in broad terms, we’re anticipating a further 15% to 20% inflation in oil country tubular goods, even though steel prices are moderating, the mills are still at capacity and demand is very strong. We’re also expecting 15% to 20% potentially in drilling rigs and 5% to 10% inflation in frac spreads, frac sand and labor. So that kind of gives you an idea. Now of course, we’re working to mitigate some of these further increases, and we’ll guide well cost in the Bakken in January 2023 as usual. And recall in Guyana, the first four FPSOs are contracted and have limited exposure to inflation, and I should add that operators have done an excellent job of offsetting any inflation in oil country tubular goods, et cetera, through the efficiency gains that they’ve realized in Guyana. Now as already mentioned, the Uaru FPSO cost is going to reflect current market conditions as well as scope changes, and we’ll give an update on Uaru once the project has been approved and sanctioned, but it will still be world-class, still have world-class breakevens.

Yes, it’s certainly something to watch down there. And the only other question I had is related to Guyana. Has there been any update, any change to the thoughts of gas development down there long term? I mean I know we have the pipeline to be onshore, but anything else as you’ve had these additional discoveries and as you’re thinking about out to the 2027 period with six FPSOs?

No. I think in the short term, it’s all about the gas pipeline to sure slipstream [indiscernible] off of Liza and supply onshore clean power plant that the government will build. Beyond that, very long term in terms of LNG or anything like that’s way down the road. We are focused on optimizing the development plan to move those oily developments forward. And as John said, we have clear visibility to six, and the seventh is likely just around the corner. That will be an oily boat as well.

Great. Thank you.

Thank you. [Operator Instructions] Our next question comes from the line of Paul Sankey with Sankey Research. Your line is open.

Good morning, everyone. John Hess, while you’re on the subject of oil markets, could you give an update and outlook for Libya, please? Thank you.

Paul, thanks for the easy question. Look, Libya is still having political unrest, political divide between the east and the west. And there are some encouraging signs that they’re going to start coming together for the leadership of the country. But it would be premature for me to comment further on that. We are still hopeful that we’re going to be able to conclude our sale of our assets there to total and ConocoPhillips, but it needs a leadership approval from the government and that’s a work in progress.

Understood. Another thing which is a little bit inside baseball, but maybe an opportunity for you to talk about a big theme is the asset retirement obligations that you had in the quarter. Is that a sort of a one and done payment that you’re making in the Gulf of Mexico? Is there an outlook there for more of the same, or is that sort of putting an end to it? And could you comment on the overall attractiveness and position in the Gulf in Mexico and your plans there? We don’t really talk too much about it. But obviously, we’re aware you’ve got a pretty good position. Thanks.

So I’ll start with the asset retirement obligations, then I’ll hand it over to Greg for the Gulf. So the asset retirement obligations that we had that we took the charge on this quarter, it was basically for non-producing properties that we just updated our estimates on those wells that are being abandoned. And this is really kind of near-term wells that we’re going to be working on. So that yes, is more of a one time. Now overall, like we’ve got a lot of wells that will come to be abandoned, but over the long term, and the change in the estimate for all those wells, were not that much, but what happens from an accounting standpoint is when they’re producing, you increase the liability, increase the asset. So again, I would say you don’t have to think about it more as a recurring type thing. This is kind of a one off for these non-producing properties that we have in the near term.

Thanks. And Paul, let me talk about, kind of where we’re headed, in the Gulf. So, as you kind of intimated, the Gulf of Mexico remains in a really important cash engine and platform for growth for us. And so our objective is to sustain or grow production there through both tiebacks and hub class exploration opportunities. So we’ve been selectively rebuilding our Gulf of Mexico portfolio, as you know, in the last six years, and we’ve acquired more than 60 new lease blocks and have a really good balance of both types of opportunities. So I think a good planning assumption is that we would drill two wells per year for the next several years, and then if we kind of hone in on 2023, we’re still finalizing the program. But we’re seeing the potential next year for two tiebacks and one hub class exploration opportunity based upon the success of our Huron well this year. And also in most of these prospects that I talked about, our partners are Shell and Chevron. So we’re in with a very good partnership in the Gulf.

Got it. And I’ll ask a leading question, has government policy made a difference to the way you’ve looked at the Gulf of Mexico? And I’ll leave it there. Thanks.

No, it hasn’t.

Thanks.

Thank you. One moment for our next question, please. Our next question, one moment. [Operator Instructions] Our next question comes from the line of Bob Brackett with Bernstein Research. Your line is open.

Hey, good morning. Thanks for the color on the Uaru development and you mentioned 250,000 a day, I’d seen third party reports at 275 [ph] a day. And it sort of begs the question, given that standard haul, how large could you get in terms of what’s the capacity limit for an FPSO of that class?

Oh, thanks, Bob. I think, the opportunity to kind of debottleneck is going to be bespoke. So it’s going to be vessel by vessel. Now, recall with debottleneck Phase 1, it went from 120 to 140. Based on the early production performance of Phase 2, it looks likely that we will probably have some debottleneck potential there. As these well – as these vessels come on, based upon the early production history, call it the first year or so, that is when you’ll decide, where your pinch points are and how much bottlenecking capability there is on each vessel. So it’s going to be bespoke and we’ll just have to wait and see what that early production data shows.

And in terms of maximum capacity, any guess?

Well, I think, 10% to 15% is kind of what would be typical, if you look at Phase 1 and maybe potentially Phase 2, 275, I don’t know, I just don’t know. Again, every vessel is going to be different and I think it’d be premature to throughout numbers like that.

Yes. And Bob, obviously, this is all subject to government approval. We’re going to be putting our plan of development in and assuming something in the range conceptually of 250 a day is probably a good planning assumption, but again, it’s subject to government approval.

Very clear. Follow-up then, this has been your biggest year of sort of deeper Santonian exploration Guyana, any update on progress and learnings thoughts about the Santonian?

Well, I think, the results speak for themselves. I mean, the deep is very promising. And I think we will continue. As I said in my opening remarks, we will continue to really understand, the deep potential with many of the wells that we’re going to be drilling in the fourth quarter. Fangtooth Southeast, for example, located eight miles Southeast of Fangtooth is going to spud. And then that, Fangtooth is a very high quality, very large reservoir system, and putting another well, eight miles Southeast of there will tell us a lot. So I am very optimistic about the deep.

Yes. And there are a number of other prospects that we had a recent review on one’s called Lancetfish, which is the East of Fangtooth. Then we have Fish-1 and Fish-2 that are reasonable distance to the West and Northwest of Fangtooth. So, there’s a lot of prospectivity to come. As we get more success in finding these deeper horizons, our ability to correlate the seismic new prospects are lighting up. So there’s a lot more upside that Greg’s talking about that hopefully in the next six months we’ll be able to give updates on.

Yes. And Bob, just to remind you that, the Phase 1 is 62 miles Northwest of Liza-1, so that gives you an idea the extent of some of these deep reservoir systems, what we see. And then of course, Lancetfish is tuck close to Liza, it’s about three miles west of the Liza-1 well, and it’s targeting deep sands that underlie that Liza complex.

Thanks for that.

Thank you. One moment for our next question, please. All right. And our last question is from the line of Noel Parks with Tuohy Brothers. Your line is open.

Hi, good morning.

Morning.

I was wondering at Banjo if you could just talk a bit about how the results there sort of maybe ripple through your analysis. It – thinking about maybe the seismic interpretation or if there is anything else you learned about beyond just the aerial extent of the resource there?

No, look again, I think we already talked about the significance of Banjo. I think that the question is really about the inboard oil play. And recall, we’ve had four discoveries in this area, Barreleye, Seabob, Uaru, Lukanani, which all had significant amounts of oil pay. Banjo was the western most well, so in that area, it was a bit of an out step, if you will, from the fairway. We’ve got a bunch more wells to drill in that area. So I don’t think you should read anything negative into the Banjo result at all.

Okay. fair enough. And I just wanted to turn to the Bakken for a minute, and just wondering if you had any updated thoughts on or experience with recompletions up there. If I recall, you had done some work going back to some of the oldest vintage wells were done sort of with the original much lighter completions out there. And so, and if you have been doing anything out there, what adventure, I guess, about what the returns might look like for that sort of work?

Well, we have been doing a number of refracts and the results have been very good. And in some cases, the wells, the IP rates that we’re seeing are as good as some of the new wells. And that’s not surprising because these were kind of vintage 001 completions. We have several hundred wells that we could refrac and we will fit them in our program as we go forward. One of the advantages of the refrac program is it allows you more continuity with a frac crew. So we’ve been sort of dovetailing some refracs into our program just to maintain continuity of a second frac crew. So you’ll see more of that activity next year. But so far so good. The results are good and the returns are very good because all the infrastructure are already there, the well’s there, so.

Okay. Thanks a lot.

Yep.

Thank you. One moment for our next question, please. Our next question comes from the line of Ryan Todd with Piper Sandler. Please go ahead. Oh, and Mr. Todd – remove himself. So thank you very much. This concludes today’s conference. Thank you for your participation and you may now disconnect.