Good day, ladies and gentlemen and welcome to the Fourth Quarter 2022 Hess Corporation Conference Call. My name is Kevin and I will be your operator for today. [Operator Instructions] As a remainder, 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, Kevin. Good morning, everyone and thank you for participating in our fourth 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 and 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. I will now turn the call over to John Hess.

Thank you, Jay. Good morning and welcome to our fourth quarter conference call. Today, I will share some thoughts about the oil markets and then discuss our continued progress in executing our strategy. Greg Hill will then cover our operations and John Rielly will review our financial results. Oil and gas will be needed for decades to come and are fundamental to ensure an affordable just and secure energy transition. The world faces a massive dual challenge. We will require approximately 20% more energy globally by 2050. And over the same period, we need to reach net zero emissions. At the end of last year, the International Energy Agency, or IEA, published its latest World Energy Outlook that offers three scenarios and they are scenarios not forecast for how to meet this dual challenge. In all three of the IEA scenarios, the world is facing a structural deficit in energy supply and significantly more investment is required both in oil and gas and also in clean energies. According to the IEA, a reasonable estimate for the global oil and gas investment required to meet demand growth is approximately $500 billion each year for the next 10 years as compared with approximately $300 billion to $400 billion invested annually in the last 5 years. In terms of clean energies, an annual investment of between $3 trillion and $4 trillion is needed each year for the next 10 years, significantly more than last year’s investment of approximately $1.2 trillion. Business leaders and government officials must have a sober understanding of this investment challenge, especially since capital is becoming more scarce and more expensive in the current financial environment. The energy transition is going to take a long time, costs a lot of money and require many technologies that do not exist today. To have an orderly energy transition, policymakers must have climate literacy, energy literacy and economic literacy. Our strategy is to grow our resource base, deliver our low cost of supply and generate 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 both by growing intrinsic value and by growing cash returns. In terms of cash flow growth, we have an industry leading rate of change story and an industry leading duration 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 our debt-to-EBITDAX ratio currently under 1x. As our portfolio becomes increasingly free cash flow positive, 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 to ensure that we can fund our high-return investment opportunities through the cycle. Executing this strategy in 2022, we decreased our debt by $500 million, increased our regular quarterly dividend by 50% and completed a $650 million stock repurchase program. 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 future years, share repurchases are expected to represent a growing proportion of our return of capital. 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. Key to our strategy is Guyana, which is home to the Stabroek Block, one of the largest oil provinces discovered in the world over the last 20 years, where Hess has a 30% interest and ExxonMobil is the operator. Since 2015, we have had more than 30 discoveries on the Block, including 9 last year, underpinning a gross discovered recoverable resource estimate of more than 11 billion barrels of oil equivalent with multibillion barrels of exploration potential remaining. We are pleased to announce today a significant new oil discovery at the Fangtooth Southeast-1 well, located approximately 8 miles southeast of the original Fangtooth-1 discovery. The Fangtooth Southeast-1 well encountered approximately 200 feet of oil-bearing stand stone reservoirs and was drilled to 5,397 feet of water. Fangtooth was our first standalone deep exploration prospect on the Stabroek Block and this area has the potential to underpin a future oil development. Our four sanctioned oil developments on the Stabroek Block have a breakeven Brent oil price of between $25 and $35 per barrel. We have line of sight to 6 floating production storage and offloading vessels or FPSOs [Technical Difficulty] billion, of which more than 80% will be allocated to Guyana and the Bakken. Our financial priorities are to continue to allocate capital to our high-return low cost investment opportunities, to keep a strong cash position and balance sheet, and to grow our dividend and as market conditions and our return of capital framework provide to increase share repurchases. In Guyana, 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, Payara, remains on schedule for startup by the end of 2023, with a gross production capacity of approximately 220,000 barrels of oil per day. Our fourth development, Yellowtail, is expected to come online in 2025, with a gross production capacity of approximately 250,000 barrels of oil per day. A plan of development for our fifth development in Uaru with a gross production capacity of approximately 250,000 barrels of oil per day was submitted to the Government of Guyana in November and final approval is expected by the end of the first quarter. We also will continue an active exploration and appraisal program in Guyana with approximately 10 wells planned for the Stabroek Block in 2023. In the Bakken, we plan to continue operating a 4-rig program, which will enable us to generate significant free cash flow, lower our unit cash costs and further optimize our infrastructure. We have a robust inventory of high-return drilling locations to enable us to grow net production to an average of 200,000 barrels of oil equivalent per day in 2025. Greg and his team continue to do an outstanding job of applying lean manufacturing principles to create a culture of innovation, improve efficiency and manage inflationary cost pressures. We will continue to invest in our operated cash engines offshore in 2023, where we also see attractive investment opportunities. In the Gulf of Mexico, we plan to drill two infrastructure tieback wells and two exploration wells. And in Southeast Asia, we will invest in drilling and production facilities at both the North Malay Basin and joint development area assets. As we continue to execute our strategy, our commitment to sustainability will remain a top priority. In December, we announced one of the largest private sector forest preservation agreements in the world, to purchase high-quality, independently verified REDD+ carbon credits for a minimum of $750 million between 2022 and 2032 directly from the Government of Guyana. Protecting the world’s forests and the important role they play as natural carbon sinks is foundational to the Paris Agreement’s aim of limiting the global average temperature rise to well below 2 degrees Celsius. Avoiding global deforestation was one of the major commitments made at the COP26 Climate Summit, where more than 130 countries, including Guyana, pledged to end deforestation by 2030. The Government of Guyana plans to invest the proceeds from our carbon credits purchase agreement in sustainable development to improve the lives of the people of Guyana, with 15% of the proceeds directed to indigenous communities. This agreement adds to our company’s ongoing and successful emissions reduction efforts and is an important part of our commitment to achieve net zero Scope 1 and Scope 2 greenhouse gas emissions on a net equity basis by 2050. The agreement further strengthens our strategic partnership with Guyana and demonstrates our long-term commitment to the country and its people, building upon the national healthcare initiative we announced earlier in 2022. We are proud to have been recognized throughout 2022 as an industry leader in our environmental, social and governance performance and disclosure. In November, Hess earned a place on the Dow Jones Sustainability Index for North America for the 13th consecutive year and for the first time was included in the Dow Jones Sustainability World Index. In December, we also achieved leadership status in CDP’s annual global climate analysis for the 14th consecutive year. In summary, we continue to successfully execute our strategy, which offers a unique value proposition, both to grow our intrinsic value and to grow our cash returns, by increasing our resource base, delivering a low cost supply and generating industry leading cash flow growth. 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. 2022 was another year of strong strategic execution and operational performance for Hess. Proved reserves at the end of 2022 stood at approximately 1.26 billion barrels of oil equivalent. Net proved reserve additions of 184 million barrels of oil equivalent were primarily the result of the Yellowtail sanction in Guyana and the Bakken. Excluding asset sales, we replaced 144% of 2022 production at a finding and development cost of approximately $14.80 per barrel of oil equivalent. Turning to production. In the fourth quarter of 2022, company-wide net production averaged 376,000 barrels of oil equivalent per day, excluding Libya, which was above our guidance of approximately 370,000 barrels of oil equivalent per day. Strong performance across the portfolio more than offset the severe winter weather impacts experienced in the Bakken during the month of December. For the full year 2023, we forecast net production to average between 355,000 and 365,000 barrels of oil equivalent per day, an increase of approximately 10% compared with 2022 production of 327,000 barrels of oil equivalent per day, excluding Libya. For the first quarter of 2023, we forecast company-wide net production to average between 345,000 and 355,000 barrels of oil equivalent per day. In the Bakken, fourth quarter net production of 158,000 barrels of oil equivalent per day was below our guidance of 165,000 to 170,000 barrels of oil equivalent per day, reflecting severe winter weather impacts in December, which limited our new wells online to only 15 in the quarter. For the full year 2022, net production averaged 154,000 barrels of oil equivalent per day. In 2023, we plan to operate 4 rigs and expect to drill approximately 110 gross operated wells and bring online approximately 110 new wells. In the first quarter of 2023, we plan to drill approximately 25 wells and bring 25 new wells online. In 2022, our drilling and completion cost per Bakken well averaged $6.4 million. In 2023, we estimate industry inflation will average between 10% and 15%. However, we expect to mitigate this impact through the application of lean manufacturing and technology and forecast our D&C cost to average approximately $6.9 million per well or about 8% above last year. For the full year 2023, we forecast Bakken net production will average between 165,000 and 170,000 barrels of oil equivalent per day. First quarter net production is forecast to average between 155,000 and 160,000 barrels of oil equivalent per day, reflecting weather contingencies and the carryover effects from the severe winter weather in December. Net Bakken production is forecast to steadily grow over the course of ‘23 and ‘24 and average approximately 200,000 barrels of oil equivalent per day in 2025. We expect to hold this level of production for nearly a decade. Moving to the offshore, in the Deepwater Gulf of Mexico, net production averaged 35,000 barrels of oil equivalent per day in the fourth quarter and 31,000 barrels of oil equivalent per day for the full year 2022. For the first quarter and full year 2023, we forecast net production in the Gulf of Mexico will average approximately 30,000 barrels of oil equivalent per day, reflecting normal field declines and planned maintenance. The Deepwater Gulf of Mexico remains an important cash engine for the company as well as a platform for growth. In 2023, we plan to participate in 4 wells, 1 infrastructure-led exploration well, 1 hub class exploration well, and 2 tieback wells. The infrastructure-led exploration well will be the Hess-operated Pickerel Prospect located in Mississippi Canyon Block 727, which is expected to spud in April and will be brought online through existing infrastructure at Tubular Bells. The well will target the same Miocene interval that was successfully drilled at Esox and tied back to Tubular Bells in 2020. The hub class exploration well will be spud in the second half of the year and will be a Hess-operated opportunity in the Northern Green Canyon area in the Gulf of Mexico, targeting high-quality sub-salt Miocene sands in areas where the application of the latest seismic imaging technology has improved the sub-salt image. The 2 tieback wells will be spud in the fourth quarter, 1 well will be at Stampede and the second well will be at the Shell-operated Llano field. First oil from both wells is expected in 2024. In Southeast Asia, net production from the joint development area in North Malay Basin, where Hess has a 50% interest, averaged 67,000 barrels of oil equivalent per day in the fourth quarter and 64,000 barrels of oil equivalent per day for the full year 2022. For the first quarter and full year 2023, we forecast net production in Southeast Asia, the average between 60,000 and 65,000 barrels of oil equivalent per day. Turning to Guyana, where Hess has a 30% interest in the Stabroek Block and ExxonMobil is the operator, the partnership delivered exceptional facilities for liability, project delivery and exploration success in 2022. Net production from Guyana averaged 116,000 barrels of oil per day in the fourth quarter of 2022 and 78,000 barrels of oil per day for the full year 2022, both above our guidance. For the first quarter and the full year 2023, we forecast net production in Guyana to average approximately 100,000 barrels of oil per day. Turning to developments. Liza Phase 1 was successfully debottlenecked in 2022 and has been operating at or above its revised nameplate capacity of 140,000 barrels of oil per day. Liza Phase 2, utilizing Liza Unity FPSO, achieved first oil in February of last year and production ramp-up from start-up to nameplate capacity was achieved in about 5 months, which is world-class performance in the deepwater. The Liza Unity is currently operating at or above its nameplate capacity of 220,000 barrels of oil per day. Production optimization opportunities are currently being considered for late 2023. The third development, Payara, is approximately 93% complete. The Prosperity FPSO is expected to depart from Singapore in late first quarter and commence hookup and commissioning activities following arrival in Guyana. The project remains ahead of schedule and is anticipated to achieve first oil by the end of 2023. Yellowtail, our fourth development, is approximately 40% complete and remains on track for first oil in 2025. The ONE GUYANA FPSO is - hull is completed and is expected to enter drydock in Singapore in April. Topside fabrication activities have commenced and module fabrication sites in Singapore and China and development drilling is underway. The final development plan for our fifth development, Uaru, was submitted in November, and we are currently awaiting approval by the Government of Guyana, which we anticipate by the end of the first quarter. Pending government approvals, our sixth development, Whiptail, is expected to be sanctioned early next year. Turning to exploration. The Fangtooth Southeast-1 well, located approximately 8 miles southeast of the original Fangtooth-1 discovery well, resulted in a significant new oil discovery, and this area could form the basis for a future oil development on the Stabroek Block. The Fangtooth Southeast-1 well encountered approximately 200 feet of oil-bearing sandstone reservoirs and further appraisal activities are underway. We continue to see multibillion barrels of additional exploration potential on the Stabroek Block. And in 2023, we plan to drill approximately 10 exploration and appraisal wells that will target a variety of prospects and play types. These will include lower risk wells near existing discoveries and several penetrations that will test deeper intervals. With regard to upcoming wells, operations are continuing at the Tarpon Fish-1 well in the northwest corner of the Stabroek Block, approximately 43 miles northwest of the Liza-1 well. The well is in the first test of cretaceous age clastic reservoirs in Northwest Stabroek. The well will also test a deeper Jurassic aged carbonate prospect. Lancetfish-1 is a deep play exploration well, located approximately 2.5 miles northeast of the Fangtooth Southeast-1 well that underlies a portion [underneath] the field. Drilling operations are underway on the Noble Don Taylor drillship. Beyond that, there is a well called Basher, which will target a deep prospect in the Fangtooth area and a well called Blackfin which will penetrate an updip upper Campanian prospect east of Barreleye. Moving to offshore Canada, we plan to participate in the BP-operated Ephesus-1 well in the Northern Orphan Basin. The well will target a very large submarine fan of tertiary age. The Stena IceMAX rig is expected to arrive on location in the second quarter despite the well, which is located in approximately 4,000 feet of water. BP has a 50% working interest and Hess and Chevron, each have 25%. In summary, our execution in 2022 was again strong, and 2023 will be an exciting year with the Bakken returning to a steady growth trajectory, with an active drilling program in the Gulf of Mexico and with the advancement of our major projects and further delineation of the significant upside in Guyana, all of which position us to deliver industry-leading performance and significant shareholder value for many years to come. I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today, I will compare results from the fourth quarter of 2022 to the third quarter of 2022. We had net income of $624 million in the fourth quarter of 2022 compared with $515 million in the third quarter of 2022. On an adjusted basis, which excludes items affecting comparability of earnings, we had net income of $548 million in the fourth quarter of 2022 compared with $583 million in the previous quarter. Turning to E&P. E&P adjusted net income was $591 million in the fourth quarter compared with $626 million in the third quarter. The changes in the after-tax components of E&P earnings between the fourth and third quarter of 2022 were as follows: higher sales volumes increased earnings by $246 million; lower realized selling prices decreased earnings by $288 million; higher DD&A expense decreased earnings by $29 million; lower cash costs and Midstream tariffs increased earnings by $19 million; lower exploration expenses increased earnings by $13 million; all other items increased earnings by $4 million for an overall decrease in fourth quarter earnings of $35 million. For the fourth quarter, our E&P sales volumes were overlifted compared with production by approximately 1.3 million barrels, which increased our after-tax income by approximately $60 million. Turning to Midstream. The Midstream segment had net income of $64 million in the fourth quarter of 2022 compared with $68 million in the third quarter. Midstream EBITDA, before non-controlling interest, amounted to $244 million in the fourth quarter of 2022 compared to $252 million in the previous quarter. Turning to our financial position. At December 31, excluding the Midstream segment, cash and cash equivalents were $2.48 billion; total liquidity was $5.73 billion, including available committed credit facilities; and debt and finance lease obligations totaled $5.6 billion. During the fourth quarter, we completed the sale of our 8% interest in the Waha Concession in Libya for net proceeds of $150 million, and we purchased 5 million REDD+ carbon credits from the Government of Guyana for $75 million. Total cash returned to shareholders in the fourth quarter through share repurchases and dividends amounted to $405 million. We repurchased approximately 2.3 million shares of common stock for $310 million in the fourth quarter, bringing total share repurchases in 2022 to $650 million at an average price of approximately $120 per share. Net cash provided by operating activities before changes in working capital was $1.4 billion in both the fourth and third quarter. In the fourth quarter, net cash provided by operating activities after changes in operating assets and liabilities was $1.25 billion compared with $1.34 billion in the third quarter. E&P capital and exploratory expenditures were $818 million in the fourth quarter compared to $701 million in the third quarter. Now turning to guidance, first for E&P. We project E&P cash costs to be in the range of $14 to $14.50 per barrel of oil equivalent for the first quarter, which includes a planned workover at the Penn State Field in the Gulf of Mexico. For the full year 2023, E&P cash costs are expected to be in the range of $13.50 to $14.50 per barrel of oil equivalent. DD&A expense is forecast to be in the range of $13 to $13.50 per barrel of oil equivalent for the first quarter and $13 to $14 per barrel of oil equivalent for the full year 2023. This results in projected total E&P unit operating costs to be in the range of $27 to $28 per barrel of oil equivalent for the first quarter and $26.50 to $28.50 per barrel of oil equivalent for the full year 2023. Exploration expenses, excluding dry hole costs, are expected to be in the range of $35 million to $40 million in the first quarter and $160 million to $170 million for the full year 2023. The Midstream tariff is projected to be in the range of $290 million to $300 million for the first quarter and $1.23 billion to $1.25 billion for the full year 2023. E&P income tax expense is expected to be in the range of $160 million to $170 million for the first quarter and $590 million to $600 million for the full year 2023. As of January 24, 2023, we have purchased WTI put options for 75,000 barrels of oil per day for 2023 with an average monthly floor price of $70 per barrel. We plan to increase our hedge position to a similar level as 2022, depending on market conditions. Based on our current position, we expect non-cash option premium amortization, which will be reflected in our realized selling prices to reduce our earnings by approximately $25 million in the first quarter and by approximately $120 million for the full year 2023. Our E&P capital and exploratory expenditures are expected to be approximately $850 million in the first quarter and approximately $3.7 billion for the full year of 2023. For Midstream, we anticipate net income attributable to Hess from the Midstream segment to be in the range of $55 million to $60 million for the first quarter and $255 million to $265 million for the full year 2023. For corporate, corporate expenses are estimated to be approximately $35 million for the first quarter and $120 million to $130 million for the full year 2023. Interest expense is estimated to be in the range of $80 million to $85 million for the first quarter and $305 million to $315 million for the full year 2023. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

[Operator Instructions] Our first question comes from Arun Jayaram with JPMorgan. Your line is open.

Yes. Good morning.

Good morning.

Greg, I was wondering if you could give us a bit of a teach-in on the deeper sand channels that you’re exploring and have had success at Fangtooth. I know you’re drilling Lancetfish. But give us a sense of – are you still in the Campanian, but a little bit of a teach-in on what you’re exploring for?

Well, thanks for the question, Arun. Again, as we have said before, if you look at the deeper interval, it’s only 3,000 feet below the upper Campanian in which the majority of our discoveries and if you look at that interval, it really underlies a lot of Stabroek Block. And over the past couple of years, we’ve had a number of penetrations in that tails of existing wells. But I think importantly, the Fangtooth discovery was our first stand-alone deep prospect and the Fangtooth-1, the first well had 164 feet of pay. In the Fangtooth Southeast well, which is located 8.5 miles southeast of that original discovery well, it had 200 feet of oil-bearing pay. And so we are going to continue to appraise that this year, probably get a DST in it. And as you mentioned, there are some other channels in and around Fangtooth, there is one called Lancetfish that’s northeast of Fangtooth, and there is a prospect called Basher, which is actually west of Fangtooth and the combination of all that is pretty exciting. And as John mentioned in his opening remarks, it could mean a potential future oil development in there. We will also continue to explore the deep as we kind of go through the next couple of years. But I think it’s very encouraging, and we will just continue to add to the discovered resource and also the significant exploration upside we see.

Got it. Just a follow-up, I know, Greg, you mentioned you’ll do a DST later this year. But what is it about Fangtooth that’s kind of moving it up the development queue, perhaps maybe after Whiptail to be the seventh boat on the Stabroek Block?

Yes. I think it’s that we’re seeing good quality reservoir and again, oil bearing. So our strategy is to continue to progress the oil developments as quickly as we can on the Stabroek Block. So good quality sand and oil bearing. So it’s coming up in the queue.

Great. Thanks a lot.

[Operator Instructions] Our next question comes from Jeanine Wai with Barclays. Your line is open.

Hi, good morning, everyone. Thanks for taking our questions.

Good morning, Jeanine.

Good morning. Maybe just going to cash returns real quick here. You’re committed to returning up to 75% of annual adjusted free cash flow through dividends and buybacks. Can you talk about what determines where you fall within that range for 2023, whether it’s related to oil prices, the balance sheet or maybe anything else? I mean we note that you have a really healthy cash balance right now and your debt maturities in ‘24 and ‘27 are pretty manageable.

Yes. No. Excellent question, Jeanine. As I said earlier, with this capital budget of $3.7 billion, our first priority is to continue to allocate capital to our high-return, low-cost investment opportunities. That’s really priority number one for this year. Along with that, the next priority is to keep a very strong cash position and balance sheet. You heard John saying we bought some puts to provide downside protection, still have unlimited upside appreciation for our shareholders. But I want to protect the downside where it’s a volatile market, and we want to make sure the downside is protected. And then in terms of return on capital, yes, over the year, 75% of that free cash flow will be returned to our shareholders as we did last year. The first priority within that, Jeanine, is to grow our dividend. So our Board meets regularly and will give strong consideration to increasing our dividend during this quarter. Then as the year goes on as market conditions and our return of capital framework provide, then strong consideration will be to increase share repurchases as we did last year.

Great. Thank you. And maybe turning back to Guyana here, the Uaru development project, I believe, is anticipated to be around $12.7 billion. Would you be able to comment on the moving pieces versus the Yellowtail cost estimate? For example, how much is related to additional scope versus inflation? And are there other things that aren’t included in that $12.7 billion? And should we consider that as the baseline for future projects, which look to be a similar size or maybe even bigger? Thank you.

Yes. So the $12.7 billion is consistent with the estimate that the operator submitted as part of their EIA to the Government of Guyana. And that number is going to be finalized as the project progresses. And once we sanction it, we will give the final details. But in any case, the final cost of Uaru reflects a couple of things. It reflects current market conditions and then also additional scope. One example is, is the surf is twice as big as Yellowtail, for example, because it connects a number of further away kind of reservoir systems. But we will give you a final color on that once the project is finally sanctioned.

And I think, Jeanine, what’s also important is Uaru still offers some of the best returns in the industry. So even though there is cost inflation with the resource we’re developing. The fact that it’s low cost, low carbon, it still offers some of the best returns in the industry.

Great. Thank you, gentlemen.

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

Hi, good morning, everyone.

Good morning.

Guys, I wonder if I could ask a kind of a longer-term question. So Exxon had signaled a couple of years ago that if the deeper horizon worked, John, I think you’ve talked about this a number of times, we could be looking at double the resource potential at the time they were talking 10, so that would be 20 billion BOEs. It seems crazy to think that. But my question is, are you going to have enough time because the exploration phases on the stand that runs out in 2026. And this thing continues to get bigger, we’re already in 2023. What needs to happen for you guys to retain everything that you ultimately could find over the next several years? And what does that mean for development time lines and, I guess, relinquishment of block acreage and so on?

Yes, Doug, excellent question. We still see multibillion barrels of exploration potential remaining. Greg made some great context remarks on the deeper horizon at 18,000 feet versus where most of our development efforts and exploration efforts have happened at 15,000 feet. We are still in the early innings of defining the deeper potential, definitely multibillion barrels potential remaining. And to get after that, that’s why ExxonMobil is doing an excellent job developing this block, has a six-rig program. Three of them are for development activities and three really are for exploration and appraisal. So, we are going to continue to have a very active exploration appraisal program this year and future years to make sure we capture all the high-value resources that we think are on the block.

So, just to be clear, John, you think you are going to have enough time in terms of securing the development approvals before ‘26, or do you have an extension on that to secure the development approvals?

No. The reason we are doing the exploration and appraisal program, Doug, is to get ahead of that to make sure we capture all the resources that we can, and we work closely with our joint venture led by ExxonMobil and the government to do that.

Thank you. Appreciate that, John. My follow-up, I here want to take this is it’s kind of a two-parter, if you don’t mind, because I think you did mention Uaru's EIS but you have also given guidance on Guyana for this year, which has got a lot of kind of cryptic comments perhaps around downtime for debottlenecking Liza and so on. So, there is a lot of things going on in terms of that 3-year, 4-year visibility. So, my question is this. First of all, can you give us some kind of a guide as to what the downtime and ultimate capacity would look like for Liza-2 as we go through this year? Some sort of trajectory, I guess. And then my kind of Part B is, a lot of people are freaking out over the $12.7 billion number that Exxon put in the EIS. Now, we know that the absolute cost recovery is not a big of a deal. But you guys typically have come in lower than that because of contingency. Can you tell us what Hess’ number is relative to that $12.7 billion?

Yes. Thanks Doug. So, let me take your first question. So, as I mentioned in my opening remarks, we are looking at a potential debottlenecking sometime in the latter half of 2023 for Phase 2. Now, as we have spoken before, each one of these is going to be bespoke, depending on the vessel. You typically want a year of dynamic data before you engineer the project to understand where the pinch points are on the vessel. As I have said in the past, I think you can expect kind of a 10%-ish uplift in any kind of debottlenecking. I think that’s in the range of possibilities here as well. Again, we are just in the early stages of engineering that. So, that would maybe come on in the fourth quarter. So, we have included some downtime for that in the guidance for Guyana. I think the quarter four of 2022 basically had no downtime. And as we project forward to 2023, we are really trying to include pigging and the normal maintenance downtime, some debottlenecking downtime in those production estimates for next year and also the tax barrels are a little bit different what John can talk about. And John can also talk about the CapEx for Uaru. So, John Rielly

Yes. On the $12.7 billion, Doug, right now, look, we are going to wait for the final sanction where we come out with our estimates. But you are correct, there was always a contingency in at the beginning of these projects and rightfully so, several years of construction. What we can say is that ExxonMobil has done a fantastic job on every single project, meeting or beating their estimates on cost and on time on execution. So, John has said it earlier, this project will have world-class breakeven, will be world-class returns there in Uaru. We are excited about that. Final details once the government has approved it, we can provide.

And it’s not lost on as its 30% bigger. Thanks so much John. I appreciate it.

[Operator Instructions] Our next question comes from Paul Cheng with Scotiabank. Your line is open.

Hey guys. Good morning. Couple of questions, I think the first kind of is two part is for John Rielly, just to clarify. When you say 75,000 for $70, is that Brent or WTI? And also that when you are talking about in the fourth quarter, the $75 million, the carbon credit purchase, where does it show – where did you show up in the income statement and the cash flow for the fourth quarter?

Sure. So, let me do your first question was on the hedges that we put on. We have WTI put options on right now. So, that’s 75,000. And like I said, we do intend to get to a similar level as last year. And combined between WTI and Brent, we had about 150,000 barrels a day hedged last year. So, again, you should be looking for us to add to this position. But currently, that 75,000 is for WTI put options at $70.

And John, for the 120 million on the premium for the full year, is that just for this not in anticipation of the increase in the put option you are going to put?

That is correct. That is just for the 75,000 we have. Simple math, if you want to double it to get to 150,000, you could double it, but we will give you updates on that as we increase our hedge position. Then your second question on the carbon credits. So, what we have, that 75,000 – 75 million purchase on the carbon credits, you will see it on our balance sheet in other long-term assets. And when you look at, there is nothing on the income statement because that is an asset being held. And on that cash flow statement, it is in working capital.

Okay. And my final question is for Greg. Bakken, can you tell us what is the winter storm impact in the fourth quarter? And also, I understand the first quarter you have been conservative contingency on the weather. But for the full year production, it seems now you have low compared to what we have expected even after taking into consideration of the first quarter. Is the number of wells that you plan for this year end up is going to be lighter than previously, or is there anything that you can share that seems to be low comparing to what I think previously has been discussing?

No. So, I think let me talk first about the snowfall for that. The severe snowfall coupled with really low wind chill, significantly impacted our ability to mobilize resources. You just can’t put people to work at minus 30, minus 40 wind chill. And so what that did was it significantly increased our backlog of down wells. And then importantly, it delayed bringing new wells online. We projected 25 new wells online coming on in the fourth quarter, that number was 15. So, we lost 10 wells. And if you assume those things come on at 1,100 barrels a day, 1,200 barrels a day, you can see that’s a fairly significant impact. I think we are in recovery mode. We expect to recover in the quarter from that. It just takes time to build and dig out of that literally. But importantly, Paul, I think the Bakken now is on this steady build, this steady cadence, a steady build to get to that 200,000 barrel a day average in 2025, so there will be this regular cadence. We will probably touch 200 towards the end of 2024. But I think importantly, we will average 200,000 barrels a day in 2025. So, we are on a solid trajectory from here to 2025 and not concerned at all about it. Wells are performing as expected. You are coming in with these IP 180s of 120, EURs of 1.2. That’s in spite of going into a little bit less quality acreage. So, the reservoir is performing exactly as expected. These are just weather aberrations as you kind of go through the year. That’s all it is.

I see. Great. Do you have an estimate what is the exit rate for this year in Bakken?

No, not yet and we will guide that as we go through the year, Paul. And as I am always kind of hesitant because fourth quarter is always a little odd on weather, so we wait until we are closer and kind of look forward at weather forecast before we like to project that far out.

Okay. Thank you.

[Operator Instructions] Our next question comes from Neil Mehta with Goldman Sachs. Your line is open.

Hey. Thanks guys. And I just want to follow-up on Jeanine’s question around capital returns. In the fourth quarter, you bought $310 million worth of stock, and I think you did $650 million last year. The share prices have done really well, so congrats on that. Has the appreciation of the share price changed your – how aggressive you want to be around buying back stock? And as we think about this year, recognizing to prioritizing the dividend, should we think that there will be a ratable buyback as well?

Thanks Neil. Just going back to what John has said a little early, you reiterated our priorities, invest in those high-return opportunities Guyana and Bakken, maintain that strong balance sheet. So, the first thing, as John had mentioned, we will be looking at the dividend because that will give strong consideration first to that dividend increase. And then in line, we are going to return cash up to the 75% through further share repurchases then. So, as we look at – as you said, with the stock appreciation, we are committed to that return framework, and we will return up to that 75% through both the dividends and share repurchases. And the way we look at it right now is we currently only have two FPSOs on producing in Guyana. We have Payara starting in this year. And remember, every time an FPSO comes on and once it’s fully ramped, Payara is going to be about 55,000 barrels a day, 60,000 barrels a day to us and $1 billion in cash flow. So, then you have Yellowtail similarly in 2025, a little bit bigger. So, 65,000 barrels a day approximately. When that’s fully up and running, a little bit more cash flow than that $1 billion. Now, we have got Uaru in ‘26, and we got up to 10 FPSOs to develop all the resources we have found. So, we believe in buying our shares in advance of that significant cash flow growth and NAV accretion that each of these FPSO generates. So, we believe that will deliver significant value to shareholders by continuing the share repurchases.

Yes. Thank you, John. And the follow-up is just around post-2023 CapEx, recognizing again that there is a cost recovery element here. And we just try to calibrate our models post-2023. Any moving pieces that you would point us to, to help us think about where we should test those numbers?

So, obviously, this is really early, Neil, so thanks for that question. But as you move into next year, just think Bakken steady four-rig program shouldn’t be much changes there. Gulf of Mexico, we will see what happens. Greg had talked about the wells we are drilling this year and we will see what – any follow-ons as it relates to that. So, it’s a little early. Southeast Asia may be slowly coming down. You saw it came down a bit in ‘23 from last year. And then Guyana, obviously, the big spend. So, we will continue to have three FPSOs kind of coming in line. So, Payara will be on, but we will still have three FPSOs that are in the development phase. So, with those, I mean you see with current market, so the current market is a bit up, so you can kind of take up those three FPSOs a bit as compared to what we have this year. And then the one other piece to add is the FPSO purchases, which we expect to have our first FPSO purchase in early 2024.

Great. Thank you. Thanks John. Very helpful.

[Operator Instructions] Our next question comes from Ryan Todd with Piper Sandler. Your line is open.

Thanks. Maybe just a couple of quick ones. First off, I appreciate you talked about some of the cost inflation that you have seen and been able to mitigate there in the Bakken. I don’t know you have talked about it indirectly with the Uaru number. But what are you seeing in terms of cost inflation on the offshore rig rates are certainly up? I mean as we look at things in Canada and Gulf of Mexico and across your portfolio, what type of inflation are you seeing year-on-year, and where is it worse in the offshore?

Well, I think as you mentioned, I mean certainly, rigs are going up kind of the mid to high-3s, approaching 400, I think for offshore rigs, not unreasonable. Now remember, we are largely insulated from that because the – certainly, the first three developments in Guyana are actually already locked in four actually with Yellowtail. So, those costs were locked in. Some of the rig rates flowed a little bit. And obviously, oil country tubular goods were up, but I will say that ExxonMobil has done an outstanding job of delivering improvements to offset both rig cost increases and oil country tubular good increases. So, we are fairly insulated because of the projects we have going on. And as we mentioned, the cost in Uaru will reflect that market inflation, and we will get into details all that once it’s finally sanctioned. But those are sort of the levels we are seeing. But again, we are largely insulated from that in our portfolio because of the nature of Guyana.

Great. Thanks. And then maybe just a philosophical question on the hedging, I appreciate the detail on this year’s hedging. As we think longer term, as production capacity continues to increase in Guyana and that stable cash flow kind of grows, do you expect to reduce your hedging amount over time, or do you view that as just kind of a strategic importance from an insurance point of view?

We definitely view it as strategic importance from an insurance point of view. And I think you can clearly expect our WTI hedge levels to remain at similar levels that we have done before, again, the tax and royalty aspect of it. Percentage-wise from on the Brent side as production keeps growing each time we bring on FPSOs, you could see maybe percentage-wise that we could have a lower hedge percentage overall. But again, I think you should expect us to have a good significant insurance protection each year just to protect that downside and again, leave the upside for investors.

Thanks John.

[Operator Instructions] Our next question comes from Noel Parks with Tuohy Brothers. Your line is open.

Hi. Good morning.

Good morning.

I just wanted to touch base on something that was mentioned earlier on. You were just talking about experiencing exceptional facilities reliability in Guyana. I was wondering if you could talk a little bit about maybe how that contributed to results? I was just curious if you had modeled some maintenance or slowdown in there that you want it not having to do?

No. What my earlier comment was if you look at Q4 in Guyana, there was little maintenance at all in Guyana. And then as we look forward for a whole year, you have to build some of that in. You will have some pigging runs and some facility maintenance. So, we had to build that into the downtime as we kind of look forward for a full year of Guyana production, but Q4 was exceptional, very high reliability.

Okay. Great. And I apologize if you touched on this. I dropped off for a minute. But the offshore Canada prospect that you mentioned, I just wondered if you could talk a little bit about the geology of that and how it was identified?

Yes, sure. So, we identified this prospect with a number of partners really about the same time that we identified the Guyana opportunity. And this is a very large stratigraphic trap. There is only a one-well commitment. As we mentioned in our opening remarks, the rig will show up in the second quarter. The prospect is very shallow. It’s about 15,000 feet or so, and it’s only in 4,000 feet of water, total depth 15,000. So, this is going to be a kind of a one-well wonder, and we will see where it goes. But it’s very large.

Okay. Great. Good to hear. Thanks.

Thanks.

Thank you.

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