Hess Corporation

The conference will begin shortly. To raise and lower your hand during Q&A, you can dial star 1 1. Good day, ladies and gentlemen, and welcome to the fourth quarter 2022 Hess Corporation conference call. My name is Kevin, and I'll be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. As a reminder, this conference is being recorded for replay purposes. I would 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 that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the risk factor section of HESS's annual and quarterly reports filed with the SEC. Also on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John HESS, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Reilly, Chief Financial Officer. I'll 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 Reilly 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 forecasts, 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 dollars each year for the next 10 years as compared with approximately 300 billion to 400 billion invested annually in the last five years. In terms of clean energies, an annual investment of between three trillion dollars and four trillion dollars is needed each year for the next 10 years, significantly more than last year's investment of approximately 1.2 trillion dollars. 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, cost 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 a 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 one time. 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 Staybrook Block, one of the largest oil provinces discovered in the world over the last 20 years, where Hess is a 30% interest and ExxonMobil is the operator. Since 2015, we have had more than 30 discoveries on the block, including nine last year, underpinning a gross discovered recoverable resource estimate of more than 11 billion barrels of oil equivalent with multi-billion barrels of exploration potential remaining. We are pleased to announce today a significant new oil discovery at the Fangtooth Southeast One Well, located approximately 8 miles southeast of the original Fangtooth One discovery. The Fangtooth Southeast One Well encountered approximately 200 feet of oil-bearing sandstone reservoirs and was drilled to 5,397 feet of water. Fangtooth was our first standalone deep exploration prospect on the Saybrook Block. And this area has the potential to underpin a future oil development. Our four sanctioned oil developments on the Staybrook block have a break-even Brent oil price of between $25 and $35 per barrel. We have line of sight to six floating production, storage, and offloading vessels, or FBS. $7 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 in our return of capital framework provide, to increase share repurchases. In Guyana, the Lisa Phase 1 and Lisa 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 at Waru, 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 Staybrook block in 2023. In the Bakken, we plan to continue operating a four 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 Plus 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 one and scope two 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, HES 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 of 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. Approved 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 yellow toll 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 four 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 costs per Bakken well average $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 DNC costs 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 four wells, one infrastructure-led exploration well, one hub-class exploration well, and two 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 subsalt Miocene sands in areas where the application of the latest seismic imaging technology has improved the subsalt image. The two tieback wells will be spud in the fourth quarter One 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 to average between 60,000 and 65,000 barrels of oil equivalent per day. Turning to Guyana, where Hess has a 30% interest in the STABREF block and ExxonMobil is the operator, the partnership delivered exceptional facilities reliability, 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, Leesa Phase 1 was successfully de-bottlenecked in 2022 and has been operating at or above its revised nameplate capacity of 140,000 barrels of oil per day. Leesa Phase 2, utilizing the Leesy Unity FPSO, achieved first oil in February of last year, and production ramp-up from startup to nameplate capacity was achieved in about five months, which is world-class performance in the deepwater. The Leesa 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, Piara, 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 hull is completed and is expected to enter dry dock in Singapore in April. Topside fabrication activities have commenced at module fabrication sites in Singapore and China, and development drilling is underway. The final development plan for our fifth development, Waru, 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 expiration. The Fangtooth SE 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 Statebrook Block. The Fangtooth SE 1 well encountered approximately 200 feet of oil-bearing sandstone reservoirs, and further appraisal activities are underway. We continue to see multi-billion barrels of additional exploration potential on the state brick 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 Staybrook Block, approximately 43 miles northwest of the Leza 1 well. The well is in the first test of Cretaceous Age plastic reservoirs in northwest Staybrook. The well will also test a deeper Jurassic Age carbonate prospect. Lancet Fish 1 is a deep play exploration well located approximately 2.5 miles northeast of the Fangtooth southeast one well that underlies the portion that leads the field. Drilling operations are underway on the Noble Don Taylor Drill Ship. 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 up-dip upper Campanian prospect east of Barrow Eye. 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 to spud 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 Reilly. 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 over-lifted 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 31st, 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 Plus carbon credits from the government of Guyana for $75 million. Total cash return to shareholders in the fourth quarter through share purchases 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 purchases 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. Expiration expenses, excluding dry hole costs, are expected to be in the range of $35 to $40 million in the first quarter and $160 to $170 million for the full year 2023. The midstream tariff is projected to be in the range of $290 to $300 million for the first quarter and $1,230,000,000 to $1,250,000,000 for the full year of 2023. E&P income tax expense is expected to be in the range of $160 to $170 million for the first quarter and $590 to $600 million for the full year of 2023. As of January 24th, 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 2023. For midstream, We anticipate net income attributable to HES from the midstream segment to be in the range of $55 to $60 million for the first quarter and $255 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 to $130 million for the full year 2023. Interest expense is estimated to be in the range of $80 to $85 million for the first quarter and $305 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.

Ladies and gentlemen, if you have a question, please press star 1-1 on your phone. If your question has been answered and you would like to withdraw your question, please press star 1-1 again. The questions will be taken in the order received. Please press Star 1 to begin, and we'll pause for a moment while you compile our Q&A roster. Our first question comes from Arun Jayaram with JPMorgan. Your line is open.

Yeah, good morning. Craig, I was wondering if you could give us a bit of a teach-in on these deeper sand channels that you're exploring and have had success at it. I know you're drilling lengths at fish, but give us a sense of, are you still on the campaigning, but a little bit of a teach-in on what you're exploring for.

Well, thanks for the question, Arun. Again, as we've said before, if you look at the deeper interval, it's only 3,000 feet below the upper campaigning, which is the majority of our discoveries. And if you look at that interval, it really underlies a lot of the state brook 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 standalone deep prospect. And the Fangtooth 1 well, the first well, had 164 feet of pay. And the Fangtooth Southeast well, which is located 8 and 1 half miles southeast of that original discovery well, it had 200 feet of oil bearing pay. And so we're 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's one called Lancet Fish that's northeast of Fangtooth. And there's 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 go through the next couple of years, but I think it's very encouraging, and we'll just continue to add to the discovered resource and also the significant exploration upside we see.

Got it. Just to 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 Staybrook block?

Yeah, I think it's that we're seeing a 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 Staybrook block. So you know, good quality sand and oil bearing. So it's coming up in the queue. Great. Thanks a lot.

One moment for our next question. Our next question comes from Jeannie Ray with Barclays. Your line is open.

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

Morning, Jeannie.

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.

Excellent question, Janine. 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 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, Janine, 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 the strong consideration will be to increase share of purchases as we did last year.

Okay, great. Thank you. Thank you. And then maybe turning back to Guyana here. The Araru Development Project, I believe, is anticipated to be around $12.7 billion. Would you be able to comment on the moving pieces versus the yellow tail 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, you know, a similar size or maybe even bigger? Thank you.

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

And I think, Janine, what's also important is Waru 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.

And one moment for our next question. Our next question comes from Doug Leggett with Bank of America.

Your line is open.

Well, hi. Good morning, everyone. 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 miles. It seems crazy. crazy crazy to think that but my question is are you going to have enough time because the exploration phases i understand it 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 timelines and uh you know, I guess, relinquishment of block acreage and so on.

Yeah, Doug, excellent question. You know, we still see multi-billion barrels of exploration potential remaining. Greg made some, you know, 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're still in the early innings of defining the deeper potential. Definitely multi-billion 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. We're 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're going to have enough time in terms of securing the development approvals before 26th? Or do you have an extension on that to secure the development approval?

No, the reason we're doing the expiration 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. I appreciate that, John. My follow-up, whoever wants to take this, is kind of a two-parter, if you don't mind, because I think you did mention Wairu's EIS earlier. but you've also given guidance on Guyana for this year, which has got a lot of kind of cryptic comments perhaps around, you know, downtime for de-bottlemaking Leesa and so on. So there's a lot of things going on in terms of that three, four 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 Leesa too, as we go through this year? you know, some sort of trajectory, I guess. And then my kind of part B is, you know, a lot of people are freaking out over the $12.7 billion number that Exxon put in their EIS. Now, we know that the absolute cost recovery is not that big of a deal, but you guys typically come in lower than that because of contingency. Can you tell us what Hess's number is relative to that $12.7 billion? Thanks.

Yeah, thanks, Doug. So let me take your first question. So As I mentioned in my opening remarks, we're looking at a potential de-bottlenecking sometime in the latter half of 2023 for phase two. Now, as we've 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've said in the past, I think you can expect kind of a 10%-ish you know, uplift in any kind of debubling. I think that's in the range of possibilities here as well. Again, we're just in the early stages of engineering that. So that would, you know, maybe come on, you know, in the fourth quarter. So we've included some downtime for that, you know, in the guidance, you know, for Guyana. I think, you know, that the quarter four of 2022 basically had no downtime. And as we project forward to 2023, we're really trying to include pigging and, you know, the normal maintenance downtime, some de-bottlenecking downtime, you know, in those production estimates for next year. And also, you know, the tax barrels are a little bit different, which John can talk about. And John can also talk about the CapEx for a while. So, John Reilly?

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

And it's not lost on us. It's 30% bigger. Thanks so much, John. I appreciate it.

One moment for our next question. Our next question comes from Paul Cheng with Scotiabank. Your line is open.

Hey, guys. Good morning. Good morning. A couple of questions. I think the first, yes, two part is for John Raleigh, just to clarify. When you say $75,000 or $70, is that Brent or WTI? And also that when you're talking about in the fourth quarter, the $75 million, the carbon credit purchase, Where does it 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. Again, you should be looking for us to add to this position, but currently that $75 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're going to put?

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

Okay.

And my final question is for Greg. Barkin, can you tell us what is the winter storm impact in the fourth quarter? And also, I understand the first quarter you've been conservative. contingency on the weather, but for the four-year production, it seems like it's a tad 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 going to be lighter than previously, or is there anything that you can share? It does seem to be low compared to what I think previously has been discussing.

Let me talk first about the snowfall. 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. What that did was it significantly increased our backlog of downed wells. Importantly, it delayed bringing new wells online. We projected You know, 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, 1,200 barrels a day, you can see that's a fairly significant impact. I think we're in recovery mode. We expect to recover in the quarter from that. It just takes time to, you know, build and dig out of that literally. But importantly, Paul, I think, you know, the Bakken now is on this steady build. this steady cadence, this steady build to get to that 200,000 barrel a day average in 2025. So there will be this regular cadence. It 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're on a solid trajectory from here to 2025 and not concerned at all about it. Wells are performing as expected. You know, you're 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's performing exactly as expected. These are just weather aberrations as you kind of go through the year. That's all it is.

I see. Greg, 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. I'm always kind of hesitant because fourth quarter is always a little odd on weather, so we wait until we're closer and kind of look forward at weather forecasts before we like to project that far out. Okay, thank you.

One moment for our next question. Our next question comes from Neil Matthew with Goldman Sachs. Your line is open.

Hey, thanks, guys. I just wanted to follow up on Janine'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 in the share price changed how aggressive you want to be around buying back stock? And, you know, as we think about this year, you know, recognizing the prioritizing the dividend, should we think that there'll be a rateable buyback as well?

Thanks, Neil. You know, just going back to what John has said, you know, a little early, you know, you reiterated our priorities, you know, invest in those high return opportunities, Guy and Bach, and maintain that strong balance sheet. So the first thing, as John had mentioned, we'll be looking at the dividend and because that will give strong consideration first to that dividend increase. And then in line, you know, we're 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 Piara starting in this year. And remember, every time an FPSO comes on and, you know, once it's fully ramped, you know, Piara is going to be about 55,000, 60,000 barrels a day to us and a billion dollars in cash flow. So then you have Yellowtail similarly in 2025, a little bit bigger. So, you know, 65,000 barrels a day approximately when that's fully up and running, a little bit more cash flow than that billion. And we've got Waru 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.

Thank you, John. And the follow-up is just around post-2023 CapEx, recognizing, again, that there's 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 set those numbers?

So, obviously, this is really early, Neal, so thanks for that question. But as you move into next year, just think Bakken, you know, steady four-rig program, you know, shouldn't be much changes there. Gulf of Mexico, we'll see what happens. You know, Greg had talked about the wells we're drilling this year, and we'll 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'll continue to have, you know, three FPSOs kind of coming in line. So Pyro, you know, will be on, but we'll still have three FPSOs that are in the development phase. So with those, I mean, you see what current market, so the current market's 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. Yeah, thanks, John.

Very helpful.

One moment for our next question. Our next question comes from Ryan Todd with Piper Stanley. Your line is open.

Thanks. Maybe just a couple quick ones. First off, I appreciate you talked about some of the cost inflation that you've seen and been able to mitigate there in the Bakken. I know you've talked about it indirectly with the OOARU 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, you know, as you mentioned, I mean, certainly rigs are going up, you know, kind of the, you know, mid to high threes, you know, approaching 400, I think, for offshore rigs, you know, not unreasonable. Now, remember, We're largely insulated from that because certainly the first three developments in Guyana are actually already locked in for actually with Yellowtail. So those costs are locked in. Some of the rig rates float a little bit, and obviously oil country tubular goods are 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're fairly insulated because of the projects we have going on. And as we mentioned, the costs in Wauru will reflect that market inflation, and we'll get into details, all that, once it's finally sanctioned. But those are sort of the levels we're seeing. But again, we're largely insulated from that in our portfolio because of the nature of Guyana.

Thanks. And then maybe just a philosophical question on the hedging, and 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 from an insurance point of view?

We definitely view it as a strategic importance from an insurance point of view. And I think you can clearly expect our WTI hedge levels to, you know, remain at similar levels that we have done before. Again, the tax and royalty aspect of it. Percentage-wise, you know, from on the Brent side, as production keeps growing, you know, each time we bring on FPSOs, you could see maybe percentage-wise that we're, 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.

One moment for our next question. Our next question comes from Noel Parks with Tui 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 wound up not having to do.

No, what my earlier comment was, was, you know, if you look at Q4 in Guyana, there was little maintenance at all in Guyana. And then as we look forward, you know, for a whole year, you have to build some of that in. You'll have some pigging runs and some facility maintenance. So we had to build that into, you know, the downtime as we kind of look forward for a full year of Guyana production. But key four 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.

Yeah, sure. So we identified this prospect with a number of partners. Um, really about the same time that we, uh, identified the Guyana opportunity. Um, and this is a very large, uh, stratigraphic trap. Um, there was only a one well commitment. Um, as we mentioned in our opening remarks, the wriggle show up in the second quarter. The prospect is very shallow. Um, you know, it's about 15,000 feet or so, and it's only in 4,000 feet of water. Total depth, 15,000. So, you know, this is going to be kind of a one-well wonder, and we'll see where it goes. But it's very large.

Okay. Great. Good to be here. Thanks.

Thanks. Thank you. Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect.

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