Hess Corporation

Good day, ladies and gentlemen, and welcome to the fourth quarter 2021 Hess Corporation conference call. My name is Josh, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. If at any time you require operator assistance, please press star followed by zero, and we will be happy to assist you. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Thank you, Josh. Good morning, everyone, and thank you for participating in our 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 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 HESA'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 call with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Reilly, Chief Financial Officer. In case of any audio issues, we will be posting transcripts of each speaker's prepared remarks on www.hess.com following the presentation. I'll now turn the call over to John Hess.

Thank you, Jay. Good morning. Welcome to our fourth quarter conference call. I hope all of you and your families are well and staying healthy. Today I will review our continued progress in executing our strategy and provide a look at the year ahead. Then Greg Hill will discuss our operations and John Reilly will cover our financial results. 2022 marks an inflection point in the execution of our strategy as we go from investment mode to return of capital mode while still being able to invest to grow our business. Our strategy has been and continues to be to deliver high-return resource growth, deliver a low cost of supply, and deliver industry-leading cash flow growth, while at the same time maintain our industry leadership in environmental, social, and governance and disclosure. In terms of resource growth, we have been disciplined in allocating capital to the best frocks for the best returns and have built a differentiated portfolio focused on the Bakken, deep border Gulf of Mexico, Southeast Asia, and Guyana with its multiple phases of low-cost oil developments. We expect all four of these assets to be free cash flow generative in 2022. In terms of the low cost of supply, because of the investments we are making, our cash costs by 2026 are forecast to decline approximately 25% to $9 per barrel of oil equivalent versus 2021. And our portfolio breakeven is positioned to be one of the lowest in the industry by 2026, decreasing to $45 per barrel Brent. In terms of cash flow growth, We have an industry-leading rate of change and durability story. We are positioned to grow our cash flow at a compound rate of 25% per year out to 2026 based upon a Brent price of $65 per barrel. And any business that can grow its cash flow at twice the rate of its top line is a business you want to have in your investment portfolio. Our company has been in the investment mode for the last several years, building our portfolio to where it can deliver durable cash flow growth. The Lisa Phase 2 project, which is on track for first oil this quarter, will add $1 billion of net operating cash flow annually at $65 Brent. Following project startup, we plan to repay the remaining $500 million in term loan and to increase our base dividend. As our portfolio becomes increasingly free cash flow positive in the coming years, our top priority will be both to grow the base dividend and also accelerate our share repurchases. Key to our strategy is Guyana, the industry's largest new oil province discovered in the last decade, which is positioned to be one of the highest margin, lowest carbon intensity oil developments globally, according to a study by Wood Mackenzie. The world will need these low-cost, high-value resources to meet growing energy demand, particularly given underinvestment by our industry in recent years. The International Energy Agency's latest World Energy Outlook provides multiple scenarios for addressing the dual challenge of growing global energy supply by about 20% over the next 20 years and reaching net zero emissions by 2050. In all of the IEA scenarios, oil and gas will be needed for decades to come, and significantly more investment will be required, much more in renewables and much more in oil and gas. A reasonable estimate for global oil and gas investment from these IEA scenarios is approximately $450 billion each year over the next 10 years. In 2020, that number was $300 billion. Last year's investment was $340 billion. So while investors in oil and gas companies need to remain capital disciplined, we also need to invest more in oil and gas than we are currently to ensure an affordable, just, and secure energy transition. Turning to our plans for the year ahead, our 2022 capital and exploratory budget is $2.6 billion, of which approximately 80% will be allocated to Guyana and the Bakken. On the Staybrook block in Guyana, where Hess has a 30% interest and ExxonMobil is the operator, we continue to see the potential for at least six floating production storage and offloading vessels, or FBSOs, in 2027, with a production capacity of more than 1 million gross barrels of oil per day and up to 10 FBSOs to develop the discovered resources on the block. Our three sanctioned oil developments on the block have a Brent breakeven oil price of between $25 and $35 per barrel. In terms of our Guyana oil developments, production capacity at the lease of Phase I development is expected to increase to more than 140,000 gross barrels of oil per day following production optimization work. The lease of phase two development is on track for startup this quarter with a gross production capacity of approximately 220,000 barrels of oil per day. Our third development on the Staybrook block at the Payara field is on track for production startup in 2024, also with gross capacity of approximately 220,000 barrels of oil per day. The Yellowtail development has world-class economics and will be the largest to date on the Staybrook block. developing nearly 1 billion barrels of oil, with a gross production capacity of approximately 250,000 barrels of oil per day. The Yellowtail project continues to make progress, has the full support of the government of Guyana, which is finalizing its third-party review, and remains on track for production startup in 2025. We will continue to invest in an active exploration and appraisal program in Guyana in 2022, with approximately 12 wells planned for the Staybrook block. Earlier this month, we announced two more significant discoveries on the block at the Fangtooth and Laulau wells. With these discoveries, the gross discovered recoverable resource estimate for the block is more than 10 billion barrels of oil equivalent, and we continue to see multi-billion barrels of future exploration potential remaining. Positive results at Fangtooth, our first standalone deep exploration prospect, confirmed the deeper exploration potential of the block. Both discoveries further underpin our queue of future low-cost oil development opportunities. In the Bakken, we plan to operate a three-rig program in 2022, which will enable us to generate significant free cash flow, lower our unit cash costs, and further optimize our infrastructure. Greg and our Bakken team to continue to do an outstanding job of applying lean manufacturing principles to keep driving down costs and building a culture of innovation and efficiency. We will also continue to invest in our operated cash engines offshore. In the Gulf of Mexico, we will drill the Huron No. 1 exploration well and also a tieback well at the Llano Field. And in Southeast Asia, we will invest in drilling and facilities, some of which was previously deferred due to COVID and low commodity prices. We are proud of our workforce for living that has values by working safely and delivering strong operating results, especially during the pandemic. As we continue to execute our strategy, our commitment to sustainability will remain a top priority. Our board and senior leadership have set aggressive five-year targets for greenhouse gas emissions reduction for 2025. Most recently, we endorsed the World Bank's Zero Routine Flaring by 2030 initiative and have set a target to eliminate routine flaring from our operations by the end of 2025. We are honored to have been recognized throughout 2021 as an industry leader in our environmental, social, and governance performance and disclosure. In December, we achieved leadership status in CDP's annual global climate analysis for the 13th consecutive year. And in November, earned a place on the Dow Jones Sustainability Index for North America for the 12th consecutive year. In summary, 2022 marks an inflection point in the execution of our strategy. We have built a differentiated portfolio offering a unique value proposition. delivering durable cash flow growth that enables us to continue to invest in some of the highest return projects in the industry and also to start growing our cash returns to our shareholders. I will now turn the call over to Greg for an operational update.

Thanks, John. 2021 was another year of strong operating performance and strategic execution for HESS. Starting with reserves, Proved reserves at the end of 2021 stood at 1.3 billion barrels of oil equivalent. Net proved reserve additions in 2021 totaled 348 million barrels of oil equivalent, including positive net price revisions of 107 million barrels of oil equivalent, resulting in an overall 2021 production replacement ratio of 295%. and a finding and development cost of approximately $5.25 per barrel of oil equivalent. Now, turning to production. In the fourth quarter and full year 2021, company-wide net production averaged 295,000 barrels of oil equivalent per day, excluding Libya, in line with our guidance. For the full year 2022, we forecast net production to increase by 12 to 15%, an average between 330,000 and 340,000 barrels of oil equivalent per day, excluding Libya. For the first quarter of 2022, we forecast net production to average between 275,000 and 285,000 barrels of oil equivalent per day, excluding Libya. This forecast reflects the impact of severe weather in the Bakken, remedial maintenance work at the Bald Pate and Penn State fields in the Gulf of Mexico, and planned downtime on the Leeds of Destiny FPSO for production optimization work. Company-wide net production is forecast to significantly increase over the course of the year, driven both by Guyana and the Bakken, with the fourth quarter expected to average between 360,000 and 370,000 barrels of oil equivalent per day. In the Bakken, both fourth quarter and full year 2021 net production were in line with our guidance, averaging 159,000 and 156,000 barrels of oil equivalent per day, respectively. We have a robust inventory of approximately 2,100 drilling locations in the Bakken, that can generate attractive returns at $60 WTI representing approximately 70 rig years of activity. In 2022, we plan to operate three rigs and expect to drill approximately 90 gross operated wells and bring approximately 85 new wells online. In the first quarter of 2022, we plan to drill approximately 22 wells and bring 10 new wells online. For the balance of the year, we expect to bring online an average of 25 wells per quarter. In 2021, our drilling and completion costs per Bakken well averaged $5.8 million, which was $400,000 or 6% lower than 2020. In 2022, We expect to fully offset anticipated inflation through lean manufacturing and technology-driven efficiency gains, and therefore, DNC costs are expected to be flat with last year at approximately $5.8 million per well. For the full year 2022, we forecast Bakken net production to average between 165,000 and 170,000 barrels of oil equivalent per day, a 69% increase over 2021. First quarter net production is forecast to average between 155,000 and 160,000 barrels of oil equipment per day. Beginning in the second quarter, we expect to benefit from the addition of the third rig, which we added last September, and improving weather conditions. Net production, net Bakken production is forecast to steadily ramp over the course of 2022 and to average between 175,000 and 180,000 barrels of oil equivalent per day in the fourth quarter. Moving to the offshore. In the Deepwater Gulf of Mexico, net production averaged 39,000 barrels of oil equivalent per day in the fourth quarter and 45,000 barrels of oil equivalent per day for the full year 2021, in line with our guidance. The Deepwater Gulf of Mexico remains an important cash engine for the company, as well as a platform for growth. In 2022, we will resume drilling operations after a two-year hiatus, with one tieback well planned at the Shell-operated Lano Field and one exploration well planned at the Hess-operated Huron Prospect on Green Canyon Block 69. Over the last five years, we have focused our efforts on getting best-in-class imaging across our acreage position in Northern Green Canyon, where we believe there is high potential for multiple high-return hub-class Miocene opportunities. Huron is the first of these opportunities, which attracted interest from multiple parties during the farm-out process. We expect to spud Huron in the first quarter, with Hess having a 40% working interest as operator and Shell and Chevron at 30% each. As part of our agreements with Shell and Chevron, we have also accessed additional myosin prospects across Green Canyon and are excited about further potential in the play. In February, Shell plans to spud the Lano 6 development well, in which Hess has a 50% working interest. The well will be tied back to Shell's auger platform with gross production from the well expected to build to a plateau rate of between 10,000 and 15,000 barrels of oil equivalent per day by the end of this year. For the full year 2022, we forecast net production in the Gulf of Mexico to average approximately 35,000 barrels of oil equivalent per day. First quarter net production is forecast to average between 30,000 and 35,000 barrels of oil equivalent per day. In Southeast Asia, net production from the joint development area in North Malay Basin, where HESS has a 50% interest, averaged 66,000 barrels of oil equivalent per day in the fourth quarter and 61,000 barrels of oil equivalent per day for the full year 2021 in line with our guidance. For the full year 2022, we forecast net production in Southeast Asia to average approximately 65,000 barrels of oil equivalent per day. In the first quarter, we forecast net production 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 state brick block and ExxonMobil is the operator, we have continued our extraordinary run of exploration success and increased our estimate of gross discovered recoverable resources to more than 10 billion barrels of oil equivalent. Net production from Guyana averaged 31,000 barrels of oil per day in the fourth quarter of 21 and 30,000 barrels of oil per day for the full year 2021 in line with our guidance. For the full year 2022, we forecast net production in Guyana to average between 65,000 and 70,000 barrels of oil per day. In the first quarter, we forecast net production from Guyana to average between 25,000 and 30,000 barrels of oil per day, reflecting planned downtime on the lease of destiny for production optimization as previously mentioned. And net production in the fourth quarter will increase to between 85,000 and 90,000 barrels of oil per day. Earlier this month, we announced significant discoveries on the Stabrook Block at Fangtooth and Laulau. Positive results at Fangtooth, our first standalone deep exploration prospect, help confirm the deeper exploration potential of the Stabrook Block. In the coming months, we will complete the analysis of the exploration well results. Appraisal activities will then be conducted to determine the optimum development approach and timing. Laulau further underpins our queue of future low-cost development opportunities in the southeastern portion of the Statebrook Block. This discovery will also require appraisal to determine the ultimate development approach and timing. We continue to see multi billion barrels of exploration potential on the Statebrook block and in 2022 we plan to drill approximately 12 exploration and appraisal wells that will target a variety of prospects and play types. These will include lower risk wells near existing discoveries, higher risk step outs, and several penetrations that will test deeper, lower Campanian and Santonian intervals. Expiration wells planned for the first quarter of 2022 include Barilai 1, located approximately 20 miles southeast of Leza. The primary target is lower Campanian with shallower and deeper secondary targets. The well spud on December 30th. Tarpon 1, which is located approximately 63 miles northwest of Lisa, will target lower Campanian scholastics plus a deeper Jurassic carbonate. The well will spud following completion of fangtooth operations. Potwa I is near our turbid area discoveries. The well is approximately three miles northwest of the Cadabac I discovery with targets in upper Cretaceous scholastic reservoirs. This well is anticipated to spud in March. Leuconinae I is in the southeastern part of the state brook block, located approximately two miles west of Pluma, and is anticipated to spud in March. The primary target is Maastrichtian-age plastic reservoirs with secondary objectives in lower Campanian reservoirs. The appraisal program in 2022 will be focused on delineating future developments. First quarter appraisal activities will include the Tilapia 2 appraisal well located approximately 24 miles southeast of Leas 1. The well will appraise the February 2019 Tilapia 1 discovery in the turbid area and is anticipated to spud in March. In addition, we plan to conduct drill stem tests at Tilapia 1 and Pinktail I. Turning now to our Guyana developments. Development activity this year will include drilling for both the Leesa Phase II and Piara projects. Initial development drilling activities will also begin for the Yellowtail project following approval of the field development plan by the government. A planned turnaround will be conducted in March on the Leesa Destiny FPSO. Work activities will include production optimization work designed to increase the vessel's production capacity. At Leesa Phase 2, the Leesa Unity FPSO vessel is undergoing final hookup and commissioning after arriving in Guyanese waters in October 2021. Unity is on track to start production in the first quarter of 2022 with a capacity of approximately 220,000 gross barrels of oil per day. With regard to our third development of Piara, the overall project is 66% complete. Surf activities are progressing ahead of plan and we're preparing for a 2022 installation campaign. The hull for the Prosperity FPSO vessel is complete and topside construction activities are ongoing in Singapore for planned production startup in 2024. The field development plan and environmental impact assessment for the fourth potential project, Yellowtail, have been submitted for government and regulatory review. The government is supportive of the project and startup remains on track for 2025. We look forward to continuing to work with the government of Guyana and our partners to realize the extraordinary potential of this world-class project. Moving to Suriname, Planning is underway for our second exploration well on Block 42 at the Zanderai 1 prospect, targeting the santonian and deep play potential. The operator, Shell, has indicated that they expect to drill the well around mid-year. We see the acreages of potential play extension from the Stabrook block with similar play types and trap styles. Shell, Chevron, and Haas each have a one-third working interest in Block 42. In closing, our execution continues to be strong. The startup of Leesa Phase 2 and steadily increasing production in the Bakken are expected to drive an approximate 30% increase in net production between the first quarter and fourth quarter of 2022, along with a significant increase in operating cash flow, which will underpin our commitment to increase cash returns to shareholders. 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 2021 to the third quarter of 2021 and provide guidance for 2022. Turning to results, we had net income of $265 million in the fourth quarter of 2021, compared with $115 million in the third quarter of 2021. On an adjusted basis, third quarter net income was $86 million, which excludes an after-tax gain of $29 million from the sale of our interests in Denmark. Turning to E&P, E&P had net income of $309 million in the fourth quarter of 2021, compared with adjusted net income of $149 million in the third quarter. The changes in the after-tax components of adjusted E&P results between the fourth and third quarter were as follows. Higher sales volumes increased earnings by $158 million. Higher realized selling prices increased earnings by $103 million. Higher DD&A expense decreased earnings by $44 million. Higher midstream tariff expense decreased earnings by $22 million. Higher cash costs decreased earnings by $21 million. Higher exploration expenses decreased earnings by $10 million. All other items decreased earnings by $4 million for an overall increase in fourth quarter earnings of $160 million. For the fourth quarter, our E&P sales volumes were over-lifted compared with production by approximately 690,000 barrels, which increased after-tax income by approximately $17 million. Turning to midstream, the midstream segment had net income of $74 million in the fourth quarter of 2021, compared with $61 million in the prior quarter. Midstream EBITDA before non-controlling interest amounted to $246 million in the fourth quarter of 2021, compared with $203 million in the previous quarter. Turning to our financial position, at quarter end, excluding midstream, Cash and cash equivalents were $2.71 billion, and total liquidity was $6.3 billion, including available committed credit facilities, while debt and finance lease obligations totaled $6.1 billion. In the fourth quarter, net cash provided by operating activities before changes in working capital was $886 million, compared with $631 million in the third quarter. primarily due to higher realized selling prices and sales volumes. In the fourth quarter, net cash provided by operating activities after changes in operating assets and liabilities was $899 million, compared with $615 million in the third quarter. In October, we received net proceeds of $108 million from the public offering of 4.3 million HESS-owned Class A shares of HESS Midstream. In January 2022, we paid accrued Libyan income taxes and royalties of approximately $470 million related to operations for the period December 2020 through November 2021. Post the startup of the LISA Phase II development, we intend to pay off the remaining $500 million on our term loan and increase our dividends. With our strong cash and liquidity positions and our industry-leading cash flow growth, we are well positioned to significantly improve our credit metrics and increase cash returns to shareholders in the coming years. We remain committed to returning the majority of our increasing free cash flow to shareholders through further dividend increases and share repurchases. Now turning to guidance, first for E&P. We project E&P cash costs, excluding Libya, to be in the range of $13.50 to $14 per barrel of oil equivalent for the first quarter, reflecting the impact of lower company-wide production and higher initial per-unit costs for Lisa Phase II during its production ramp following first oil. Cash costs, excluding Libya, for the full year 2022 are expected to be in the range of $11.50 to to $12.50 per barrel of oil equivalent as the low-cost Guyana production reduces our unit cash costs in the second half of the year as LISA Phase II reaches capacity. DD&A expense, excluding Libya, is forecast to be in the range of $11.50 to $12 per barrel of oil equivalent for the first quarter and $11.50 to $12.50 per barrel of oil equivalent for the full year. This results in projected total E&P unit operating costs, excluding Libya, to be in the range of $25 to $26 per barrel of oil equivalent for the first quarter and $23 to $25 per barrel of oil equivalent for the full year 2022. Expiration expenses, excluding dry hole costs, are expected to be in the range of $40 to $45 million in the first quarter and $170 to $180 million for the full year. The midstream tariff is projected to be in the range of $285 to $295 million for the first quarter and $1,190,000,000 to $1,215,000,000 for the full year 2022. E&P income tax expense, excluding Libya, is expected to be in the range of $40 to $45 million for the first quarter and $300 to $310 million for the full year 2022. For calendar year 2022, we have purchased WTI collars for 90,000 barrels of oil per day with an average monthly floor price of $60 per barrel and an average monthly ceiling price of $100 per barrel. We also have entered into Brent collars for 60,000 barrels of oil per day with an average monthly floor price of $65 per barrel and an average monthly ceiling price of $105 per barrel. We expect non-cash option premium amortization, which will be reflected in our realized selling prices, to reduce our results by approximately $55 million per quarter or approximately $225 million for the full year 2022. In the first quarter, we expect to have three liftings from Guyana, with two lifts coming from the lease of destiny and our first lift from the lease of unity expected to occur at the end of March. In the second quarter, we expect a total of five liftings. After the Lease of Unity reaches full production, which is currently projected for the third quarter of this year, we expect to have eight liftings per quarter in Guyana from these two FPSOs. For the full year 2022, we expect 24 liftings in Guyana. Our E&P capital and exploratory expenditures are expected to be approximately $650 million in the first quarter, and approximately $2.6 billion for the full year 2022. For midstream, we anticipate net income attributable to HES from the midstream segment to be in the range of $65 million to $70 million for the first quarter and $275 to $285 million for the full year 2022. For corporate, corporate expenses are estimated to be in the range of $35 to $40 million for the first quarter and $120 to $130 million for the full year. Interest expenses estimated to be in the range of $90 to $95 million for the first quarter and $350 to $360 million for the full year 2022. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

Thank you. As a reminder, ladies and gentlemen, if you have a question, please press star followed by 1 on your phone. If your question has been answered or you would like to withdraw your question, press pound. Questions will be taken in the order received. Please press star 1 to begin. Your first question comes from the line of Janine Way with Barclays.

Hi. Good morning, everyone. Thanks for taking our question. Good morning. Our first question is on cash returns for John Hess. How are you thinking about the trajectory of the base dividend increases? In the past, you've commented that the majority of your shareholders think that the base dividend needs to be higher than the S&P, but any more color on where your target is on that? And then for the buybacks, you've been pretty clear that the base dividend is the first priority, but is the catalyst for more meaningful share purchases, is that really Piera coming online in 2024, but you could maybe initiate them on an earlier but more modest level and then accelerate them?

Mr. Jeanine, thank you. In terms of our return of capital framework, you know, once the lease of phase two is up and producing oil, we will pay off the $500 million remaining on our term loan and we'll start to increase our base dividend. At that time, we'll also communicate our return of capital framework. not just where we want to take the dividend, but also how we plan on returning our free cash flow. As a reminder, as you said earlier, we've been consistent in saying that our cash flow compounding, as it does, we intend to return the majority of our free cash flow to our shareholders by further increasing our dividend rate. and also accelerating share repurchases. And in terms of the dividend itself, the base dividend, as our cash flow grows, we plan to have a dividend that will have a meaningful premium to the S&P 500 dividend yield.

Okay, great. Thank you for that color. Our second question, maybe for John Reilly, it's on Libya, and just maybe a housekeeping clarification thing. The release indicated that in January, has paid accrued Libyan income tax and royalties of $470 million, and that was related to operations from last year. Can you just provide a little bit of color on this and what, if anything, more we can expect for the rest of 2022?

Sure, Janine. Basically, you know, we had tax and royalties related to our production on the Oaxaca concessions And these taxes and royalties were held by HESS and our other WAHA partners after receiving instructions from the Libyan authorities to withhold payment. Then, you know, just recently, the authorities instructed us to make those payments. So we did release it. HESS and our partners released those taxes and royalties and paid during January, as was mentioned in the release and I mentioned earlier in my discussion. Going forward, this is just normal taxes and royalties related to our production. It's typically paid monthly. We expect it to be paid monthly here in 2022. So that's what I would say the go forward is. And just so you know, I mean, all those... Those are just normal taxes and royalties. They were all accrued, all in earnings, all in cash flow from operations during 2021.

And as a reminder, Janine, you know, Total recently announced the sale of our interests in Libya to both Total and ConocoPhillips, and we are still awaiting final approval from the government on that sale.

Great. Thank you.

Thank you. Thank you. Your next question goes from Arun Jairam with JP Morgan.

Yeah, good morning. John, for you, as you talked about adopting a formal capital allocation returns framework kind of near term, and I was wondering if you could give us maybe some insights on how you're thinking about this. You know, some of your E&P peers have a very formulaic approach to this while some of your major peers are a little bit more flexible. So I was wondering if you could maybe give us a little bit of thoughts on how you and the board are thinking about that.

Yeah, no, great question. We will be coming out with a framework that will be pretty clear about how we allocate capital, but also how we intend and how much we intend of our free cash flow to return. It will have some flexibility in it, but it will be very clear of our commitment to return the majority of our free cash flow to our shareholders by further increasing the dividend. We'll have our first increase in the dividend once lease of phase two is up and running and producing oil. But then we will intend, as our cash flow compounds, the majority of that free cash flow will go back to our shareholders by further increasing the dividend and also accelerating the share repurchases. I think the return of capital framework, when we announce it, will be clear and help provide clarity to the question you're asking.

Great. And just my follow-up is on Guyana. Greg, you mentioned that the Yellowtail project could include resources of a billion barrels. I was wondering if you could kind of compare how this development looks like relative to Piara. I think the subsea kit's a bit more, it's a lot bigger of an FPSO, so maybe give us some thoughts on how this could look like, and then as well as maybe provide some insights on the objectives of the 2022 exploration program in Guyana. It looks like you're maybe targeting some more elephants, but I wanted to get some thoughts on those two questions.

Sure. So let me take your second question first, Tarun. So as I mentioned in my opening remarks, you know, the objectives of the program this year or twofold, like they always have been, the first one being to explore for new opportunities. So that includes things in the upper Campanian, but also more penetrations in the deeper zones, such that we saw as Fangtooth, right? And so if you look at the 12 wells that we're going to do this year, about two-thirds of those wells are exploration wells, and about one-third is appraisal wells. So pretty active this year on the on the exploration side and again we're going to be testing deeper zones and also shallower zones. You know, with that exploration program and I kind of lined out that the first quarter my opening remarks as to where we're where we're headed with that. And then appraisal, of course, is about, you know, appraising You know the existing discoveries so that we can figure out what that development queue is You know for the the play out of the vessels, you know the up to 10 FPSOs that we've talked about Now if I get back to your question on yellowtail, so first of all, you know The yellowtail developments world-class economics will be the largest to date on the Staybrook block it's as you mentioned it's going to develop nearly a billion barrels of oil and have a gross capacity of 250,000 barrels a day. So it's got a little bit bigger top sides, and it's also got more wells. So Piara has 41 wells, whereas Yellowtail will have 51 wells. So it's just a bigger project, very large area extent, very fantastic reservoir. So it's going to be one of the, again, the world-class economics.

Yeah, some of the highest returns in the oil industry, comparing it to shale or comparing it to offshore developments, and it's going to have a break-even cost that will be lower than Piara.

Great. Thanks a lot, gents.

Thank you. Your next question comes from Doug Legate with Bank of America.

Thanks. Good morning, everybody. I don't know if it's too late to say Happy New Year, but Happy New Year, everybody.

Happy New Year as well.

So, John or Greg, I'm not sure who wants to take this, but I want to ask a portfolio question, given you touched on the Libya news earlier. You have a very, very large footprint in the Gulf of Mexico, obviously. You've taken advantage of lease rounds when no one else cared and so on. But when I look at Payara Yellowtail adding... essentially five times the current production in the Gulf of Mexico. I got to ask if the Gulf of Mexico is a keeper longer term for the portfolio, given the effort that has to be put into maintaining the production and so on. So just long-term thoughts on whether the Gulf stays in the portfolio.

Yeah, Greg.

Yeah, sorry. It took me a second to get off on mute. So, Doug, as we talked before, you know, the Gulf of Mexico remains an important cash engine and platform for growth for HESS. We have top quartile capability in both deepwater drilling and project delivery in the Gulf. And so our objective is maintain that cash hub, sustain production, and cash flow generation through both tiebacks and also selectively pursuing these high return hub class exploration opportunities, hopefully Huron would be the first cap off the rank there. And as you said, we've been selectively rebuilding our Gulf of Mexico portfolio, acquired more than 60 lease blocks at really low prices. And that's, again, that balance of high return tieback opportunities and up-class prospects. It remains a very important province for HASS, good returns in the Gulf of Mexico. And as I mentioned, we do have the capability to execute well there. So it's a core hold for us.

Okay, that's very clear. I appreciate the answer. My follow-up is actually a balance sheet question, so it's probably a John Riley question. John, I'm just curious, when you think about the scale of the free cash flow that you're going to be able to generate, you still carry in absolute terms, you know, a sizable amount of debt. What do you see as the right level of debt? Where does the priority sit in the cash return framework to actually bring that debt down to, let's say, sector leading levels like some of your peers are now talking about zero net debt, for example?

Sure, Doug. So as you know, right, once we start up LISA Phase 2, we are going to pay off the remaining $500 million of that term loan. Then our next maturity, because we've got a nice liquidity position, isn't until 2024, and it's $300 million. We do intend, as you said, with our rising free cash flow to pay off that maturity in 2024. And then we don't have really another debt maturity until 2027. So we're happy when we pay off that 2024 amount with the absolute level of debt that we have. And if we're, let me just say it, like $65 Brent, and we run this out, we bring Piara on and obviously other FPSOs, we're going to drive our leverage down to under one times debt to EBITDAX. We're going to have really a strong, low-leverage position improving credit metrics, as I mentioned earlier. So we're happy with that debt level, that absolute debt level, as our EBITDAX grows from there. And so there's no real benefit. We've run NPVs on doing some things with either. just paying off the debt at this point. But right now, with our low leverage, we are very comfortable with leaving the debt levels where they're at, And then, like we said, with that balance sheet so strong at that point and the rising free cash flow from PIAR, from Yellowtail, from the fifth development, we will then increase returns to shareholders. Obviously, with the rising free cash, more of that free cash will return versus will be share repurchases, but we'll also be growing our dividend over the time, too, as well. So I think we're in a really good position for this with Guyana coming on, these low-cost developments, strong balance sheet, and increasing return returns. of capital to shareholders.

Great. I appreciate the answer, fellas. Thanks again.

Thank you. Your next question comes from Neil Mehta with Goldman Sachs.

Good morning, team. A couple of questions here. Morning, Neil. Morning, John. Our first one's around Lisa, too. We're weeks away here from Startup. How do you think about any gating issues around the startup? And just can you give a sense from an operational standpoint, how is it going around construction at Piara as well? So just any thoughts around the logistics of getting these assets turned on?

Yeah, Greg, please.

Yeah, sure. So let me just talk about phase two first. So, you know, we'll have 19 whales available at startup. Those are all ready to go. All the risers have been recovered. So they're hooked up into their porches now. We've got a few left to commission. So we've still got some commissioning of those risers. The FPSO topside's readiness is nearly complete. So, you know, what that means is we are on track for that first quarter, you know, startup, as we said in our opening remarks. And if you look at PIARA, again, it's still relatively early in the project, but, you know, right now we're running slightly ahead of schedule in PIARA. So, I would say we're firmly on track for that 2024 startup. So the project is about 66% complete as we sit here today. So we're in good shape, but again, it's early days in Piara. So I think the operator having some contingency in there is wise at this point, but on track for 2024 startup.

Thanks, Greg. And the follow up here is for John and John on the hedging strategy here. You did provide an update around the collars and increased the ceiling price there. Just talk about how you think about the optimal way to approach hedging is. And, John, if you don't mind tying that into your own view of the oil macro as you've been constructive here. We're nearing 90 Brent. Is anything changing for the better or for the worse relative to what you've talked about over the last couple of years?

Sure, Neil. I'll start and hand it over to John Hess. But our hedging strategy, it really is consistent what we're doing with our past strategy. So as we continue to invest in our world-class opportunity in Guyana, we want to ensure that we have significant price protection, which we did in 2022. So just to reiterate, we have 90,000 barrels of oil per day with WTI puts at a floor of $60.00. And then we have 60,000 barrels a day of Brent puts at a floor of $65. Now, this year, we did use high ceiling calls. So we have a call at 100 for the WTI and 105 for Brent to reduce the cost of the program while retaining exposure basically to greater than $2 billion in additional cash flow in the case of higher oil prices above the hedged floor. So in addition, we haven't hedged all of our oil production. And obviously, we have unhedged NGL and gas production as well that will benefit from higher prices. So what I say, this is consistent with our strategy. We provide significant downside protection while also giving the majority of upside to our shareholders as we continue to invest the opportunity in Guyana.

Yes, Neil, and obviously it does reflect a constructive view on the market. and very consistent with our approach of protecting the downside and giving the majority of the upside to our shareholders. On the macro oil outlook, on the demand side, V-shaped recovery, temporary setback of about a million barrels a day globally because of Omicron, starting to see cases going down, thank God. We think we'll be back at pre-COVID global demand levels of 100 million barrels a day. in the next month or so. And as the year unfolds, we see jet demand increasing as international travel increases and probably see a number of about 102 million barrels a day by the end of 2022. Supply side, different. It's a U-shaped recovery, more sticky. Shale is growing, but at a more tempered pace. Function of the rig count of about 604 U.S. rigs operating, we think that adds about 750,000 barrels a day over the year of increased oil production. Remember, U.S. production probably end up at the end of the year about 12.2 million barrels a day. That's still short of the 13 million barrels a day we had pre-COVID. So shales on the recovery, but not at pre-COVID levels in terms of absolute U.S. oil production. OPEC sounds like they're going to stick to their 400,000 barrels a day increases each month, as has been written by a number of commentators. A couple of countries are not meeting their quotas there. So, again, I'd say disciplined tempered recovery on OPEC+, disciplined tempered recovery in shale, all of which adds up to global oil inventories, which had been a year and a half ago, April. a billion, 200 million excess inventories globally. That's all been eaten up. And now we see global oil inventories about 200 million barrels less than pre-COVID levels. So as you go through this year with demand increasing, global inventories tight, not much spare capacity in OPEC Plus, we're pretty constructive on the oil market. And really, the oil price is giving a signal that investment has to increase, which is why I referred to the World Energy Outlook earlier. Depending upon what scenario you pick, any credible scenario from the International Energy Agency, more investment is going to be needed to grow oil and gas supply to meet global oil and gas demand. And currently, we're not investing enough as an industry to do that. So we're going to have to have the right balance of being capital disciplined, returning capital to shareholders, but at the same time, grow the resource and grow the production capacity of the world. So that's the challenge that we have ahead. And I think that also really presents a constructive oil market as the year unfolds.

Thanks, Jeff. Thank you. Thank you. Your next question comes from Paul Chen with Scotiabank. You may proceed with your question.

Hey, guys. Good morning. Morning. Thank you. Two questions. One for Greg and the other one is for John Marley. Greg, when you're looking at the Frank 2 and the other that you also have penetrating the deepest formation, is there anything you can tell us that in terms of the oil and gas ratio, in terms of the permeability, oil quality compared to the more shared information. Is there any significant differences that we see or any kind of conclusion that you can share?

So, Paul, you know, I guess the first thing I'd say is, you know, the positive results at Thangtooth, which, you know, was our first standalone deep exploration prospect. And remember, it's up towards Lisa, so it's kind of in that country. So very good oil quality. And it confirms, you know, the deeper exploration potential of this table block. So in the coming months, we're going to complete the analysis of that well, the Fangtooth well, and then plan appraisal activities, you know, to really determine, you know, the best development approach. So generally, we see these deeper zones as being developed through a combination of standalone developments and tiebacks potentially to existing FPSOs. So very encouraged. very pleased by the results, you know, we saw at Fangtooth. Also, remember, we had other penetrations prior to Fangtooth into those deeper zones that confirmed the same thing, good reservoir quality and good, you know, good fluid properties. So very excited. That's why we're going to drill a lot more wells, you know, in kind of the deeper zones. prospectivity this year than years past, and so watch this space, but we're encouraged by the outcome in particular of FANG2.

Well, we understand that, but is there any contrast or comparison you can provide in terms of the gas-oil ratio, the degree of the oil, and the permeability, any kind of data that you can share?

No, not at this point because, again, we need to do some more analysis of the wells and do some more appraisal, particularly in the Fang Tues area. Okay.

The second question is for John Marley. By the fourth quarter, as you indicated, your unit cost is going to come down a lot because Guyana needs a two-year ramp to the full capacity and all that. So what's the target unit cost that you have by the fourth quarter in Guyana? And also that have you looked at, I know you guys talking about next year that you may start the buyback, but have you visited between the variable dividend and the buyback and that the plus and minus is that and that have you and that why you decide that variable dividend is not a better tool and then buyback is the right tool for the company? I'm not saying that you should be variable dividend. Just curious how the internal debate that has been the case.

Sure. So let me start with cash costs. So through the year, as I said and you mentioned, our unit costs will be dropping basically as Guyana Phase 2 comes online and it's lower cost. Let me just remind you where the costs are for Guyana. On Phase 1, obviously it's a smaller boat. And what we've been saying is that the cash cost per barrel there were $12. However, you did hear it was mentioned that we're doing the production optimization work so that 120 gross capacity is going up. So the cash cost per barrel for phase one will be decreasing as that production optimization is completed. On phase two, the cash cost per barrel are $10 per barrel for phase two when it is fully up and running. I also should mention that both of these is when we're leasing the FPSOs. So phase two will actually drop down to $7 to $8 post-purchase of the FPSOs. But for this year, around $10. So you have cash costs for phase two at $10, and you've got phase one under $12. And what it does, along with increasing production in the Bakken, is by the fourth quarter, our cash costs will drop to around $11 per barrel for the company in the fourth quarter.

then I'll pass it over to John oh is that you Paul yes yes okay yeah no we were getting some feedback in terms of the dividend you know we've done studies we don't think the variable dividend is sustains the creation of long-term value. We believe strengthening the base dividend and consistent share repurchases are a better way to go. And in terms of the timing on that, as I said, once lease of phase two is up and producing, we pay the $500 million of remaining debt off from our term loan. We will increase our base dividend. We will start the process of that increase. And then as you look forward in time, further dividend increases and accelerating share repurchases will be a function of market conditions and the growth in our cash flow. So the framework for that will be very clear and I think something that will be very competitive.

Okay. Thank you, John. John Lally, can I go back into your, when you're talking about the Guyana unit cost, wondering that what is the timeline in terms of when the consortium will decide to buy back the FPSO or that, I mean, for both NISA 1 and NISA 2? And secondly, that when you're talking about those numbers, $12 for phase 1, $10 for phase 2, Are those, what is the denominator on that? Is that based on, say, in Phase 2, $220,000 per day, but your actual reported in your financial statement would be different, or that this is what you expect to report in your financial statement?

Okay, so answering your last question first, yes, that's what will be reported in our financial statement. So that's our if you want to call it, our net cash costs on our entitlement production in Guyana. So those are those numbers. And as far as the FBSO purchases, the operator, ExxonMobil, is still in discussions with SBN on the actual date of the purchases of the FBSOs. And we'll give you the specific timing to that when that is set. But having said that, as you noted, when our 2022 CapEx release, we don't expect any purchases in 2022 or in 2023. Thank you. You're welcome. Thank you.

Your next question comes from David Duckelbaum with Calend.

Thanks, John. Thank you guys for squeezing me in here. I'll try to make it quick. I had one question just on the reserve report. It looked like your net additions organically at the drill bit, like 241 million, were noted in the press release were primarily from the Bakken. Is that just reflecting increased gas capture, or have there been some performance revisions there as well?

John? No, there have been...

Go ahead, Greg. You go first.

Yeah, so look, there were both performance additions in the Bakken, plus we brought additional wells into our five-year plan due to price increase, which was $107 million, but then the other wells bring it in. So if you look at the Bakken, we had ads of about $209 million in and then the price of about $119 million specifically to the Bakken, right? So both performance adds and also bringing additional wells into the five-year plan.

Great. Thanks, Greg. Appreciate the call on that, Greg. And then maybe for John, just my last question, just around you've laid out the timeline for paying down the $500 million term loan, noted the fact that you don't really have that many maturities. As, I guess, the free cash profile ramps here, you talked about getting sub one times leverage, which we have on our numbers at a run rate sort of in that 2Q, 3Q timeframe. Should we be thinking about investment grade sort of coinciding sort of with midyear? And how do you think about the tangible benefits from that outside of the obvious of refinancing some of that higher cost debt stack?

So, again, with our growing free cash flow and obviously our growing cash flow and our growing free cash flow, our debt metrics are going to significantly improve. And basically, as each FPSO comes on, And like I said, we are targeting to be on a gross debt to EBITDAX under one, and we will achieve that as the cash flow grows. Now, I can't specifically say, you know, with the rating agencies on timing. Obviously, we are investment grade with two of them, and we're below on one, but have a positive outlook with the one. So, I do expect, as our cash flow improves, that we'll become investment grade, and actually we'll improve from where we are today as our cash flow grows. So, What we try to do from our own strategy standpoint is we want to have a strong balance sheet, obviously to fund the growing resource base that we have and also for further return to shareholders. So from our standpoint, that will be the outcome of our strategy of having a low leverage, strong liquidity position, which you mentioned as well. And then as each FPSO comes on, it will just continue to improve and will improve our credit metrics. as well as still providing increasing cash returns to shareholders so the portfolio is set to be in a nice spot as john has mentioned earlier this is kind of the inflection year and we'll expect to grow on it from here appreciate the answers guys thank you thank you your next question comes from ryan todd with piper salmon great thanks um maybe just a couple quick ones uh i know on

as we think about the medium-term outlook in the Bakken, I know you've talked about eventually wanting to get back to a four-rig program and a production plateau closer to 200,000 barrels a day. How much impact does the price of oil have on the timing of adding a fourth rig? Is that something that would be possible by the end of this year if prices stay high, or is that further down the line? Go ahead, Greg.

Yeah, again, you know, Ryan, I think as we've talked before, you know, the role of the Bakken in the portfolio is to be a cash engine, so any decisions on pace or timing of addition of a fourth rig is going to depend upon corporate cash flow needs and also returns. Now, having said that, assuming prices hold at this relatively high level, we would look to add that fourth rig next year, and by doing so, we could then take the Bakken to 200,000 barrels a day, And with the inventory we have at four rigs, we could hold that flat at broadly that 200,000 barrels a day for almost a decade with that fourth rig. Now at 200,000 barrels a day, we really maximize utilization of the infrastructure. So that would be another objective to fill that infrastructure up. And of course, you know, gosh, at these prices, you know, the Bakken becomes, you know, this massive cash generator that And at that 200,000 barrels a day, even at $60 to $65, it generates about a billion dollars of recash flow. So you can see the real cash firepower of the Bakken.

Thanks, Greg. And then maybe I appreciate the comments on cost inflation and well cost in the Bakken earlier. As you think about the rest of the portfolio, any comments on what you're seeing in terms of service or material cost inflation in an offshore environment, particularly as we as we think about upcoming potential project sanctions. Greg, please.

Yeah, sure. So, you know, like the onshore, we're also seeing some inflation, you know, in the offshore. However, recall the majority of our offshore portfolio right now is driven by Guyana. And, of course, the projects currently in development are covered by EPC contracts. So we're largely insulated, you know, from cost increases in the offshore, current cost increases in the offshore, plus, you know, ExxonMobil contracts. with this Design One, Build Many strategy is just doing an outstanding job of delivering efficiencies across that portfolio down there as well. If you look in the Gulf of Mexico, the rig that's going to drill the Huron well, $255,000 a day rate. So I think that still reflects the low cost on a relative basis of the offshore drilling

Thanks for all the help.

Thank you. Your next question comes from Bob Brackett with Bernstein Research.

Good morning, all. Had a question around PIARA. And I'm going to try to type a date and a percent completion. So if I'm not incorrect, PIARA was sanctioned maybe five quarters ago. First production is expected maybe eight plus quarters from now. But at the same time, it's 66% complete. If those numbers are right, can you talk about maybe the rate-limiting steps for PIARA and maybe for future developments?

Morning, Bob. Great question. Greg, it's yours.

Sure. Yeah. Bob, so PIARA, I think, you know, what's different about PIARA is there are three offshore installation campaigns. So, yes, the project is 66% complete. But because there's three installation campaigns, you will build a little bit more contingency, you know, into that project. Because while you don't have... you know, hurricane issues or anything down there, you do have some current issues, you know, offshore currents during the installation campaign. So that's why there's still contingency in Piara. We agree with the operator that that's the appropriate thing to do, you know, at this stage of the project. And so we are firmly on track for a 2024 startup. Little ahead right now, but again, it's early days.

Understood. Is there a good rule of thumb for the number of development wells a drill ship in Guyana can do in a year?

You mean in terms of drilling? No, Bob, it's really kind of bespoke. Some of these horizontals are longer than other ones, for example, in some of these developments. So there's not a great rule of thumb that I would say because, again, each development is very bespoke on not only, you know, the length of the horizontals, but also what reservoirs they're tapping into as well.

Okay, fair point. Thanks, all.

Thank you. Thank you. Your next question comes from Noel Parks with Tuohy Brothers.

Good morning.

Good morning. I had a general question about the exploratory program this year. I was wondering what's the next most informative data point you're looking for out of the program? Because there's quite some large step outs there, so there's possibility for aerial expansion. And then it also sounds like some of the particular formations you're going at are, I believe, the first time you're going to be tapping them in Guyana. And so I was wondering if any of these really opens up a lot of new doors if it meets or surprises your expectations. Yeah, Greg?

No, I think, again, you know, the objectives of this year's program is, you know, A, to, you know, continue to do kind of the upper Campanian, you know, expiration. But also, most importantly, is to get more penetrations, you know, in the deep. So, you know, the deep penetrations that we're going to be watching closely are And these are wells that we're going to spud in the first quarter are Baralai 1, which is a lower Campanian primary target, but it's also got some shallower things as well. And then Tarpon 1, which is another lower Campanian well, plus a deeper Jurassic carbonate feature that we see. And then kind of in the upper Campanian space, you know, is Leuconini 1. But it also has some objectives in the lower Campanian reservoirs. And then finally, Potwell 1, which has got some targets in the upper Cretaceous reservoir. So you can see it's a mixture, you know, play type. So I wouldn't want to call one out specifically and say, oh, that's the most significant. They're all significant in this year's program. They're all very promising wells on seismic activity.

And then are most of those deeper targets then things that you've identified largely through seismic or are any of them, are your expectations informed by any of them by actual analogies you have or have already seen?

No, I think they all have seismic features, right? So the primary driver down here is their seismic signature. Now, obviously... As we've gotten more data in the deep, we're getting better at teasing out what that seismic is going to show us. And the additional data we pick up from these deeper wells will improve that even more, you know, kind of as we go forward.

Okay, great. Thanks a lot.

Thank you. Your next question comes from David Aiken with Pickering Energy.

Good morning, guys, and really just making sure that I'm thinking about this correctly. You all continue to be cash taxpayers in the U.S. and Malaysia and then continue to build a cost pool at a faster pace, given your spending and the ring fencing in Guyana for the next couple of years. Just thinking 80 plus dollar oil 2022 and 2023 is you got this call it the hug of higher oil prices, but a punch of higher cash taxes. But you're already Essentially a full payer is the way we're thinking about it. Is that correct?

David, no. So for us, we are not cash taxpayers in the U.S. We have a net operating loss carry forward. How long does that last? Yeah, I don't see us paying cash taxes even with these high prices. Let's just say for five years and beyond. Perfect. That's where we are in the U.S. The only place that we really are paying cash taxes is in Southeast Asia. And it's a small amount in the portfolio.

I think I said that opposite. Sorry, I've got a little COVID brain fog.

No, no. The only thing you would see is when you're looking at it, because I always do it ex-Libya. Libya obviously has a 93.5% tax rate. So that's the one place. you know, that we are paying cash taxes. And then the Guyana taxes are actually within the PSC. So it's in the economics and in our net entitlement. So we pay them there.

Yeah. Again, you just keep building a cost pool for the next three years, even at these prices. Correct. Yeah. Okay. Thanks, guys. I think I said that opposite. My apologies.

No, no problem.

You've answered my question. Thank you all.

Thank you. Your next question comes from Felix Johnson with Capital One.

Hey, guys. Thanks. Just one question for Greg and the production outlook. You guys have a large ramp throughout the year, and I know you don't give specific guidance on oil production, but just wondering if you could help us with the oil mix in both the Bakken and the Gulf of Mexico and how those numbers should trend throughout the year. I realize both the Bakken mix can fluctuate depending on gas capture and NGO prices, but just from a high level perspective, should we stick with around 50% of the Bakken and around 65% or so for the Gulf of Mexico for the rest of the year?

Yeah, so let's address the Bakken first. So first of all, the mix at the wellhead is constant at around 65% and will be for the next several years for us in the Bakken. And that's because we still have a lot of undeveloped well locations. Now you're right, when you get to the corporate results, it goes to 50%. And that's because of increased gas capture and, you know, our third party volumes and our pop contracts and all that. That's how you get to the 50%. So at a corporate level, broadly, you could assume that that's going to be the the same mix, and you're on target for the Gulf of Mexico, kind of that 65% or so mix in the Gulf.

Okay, perfect. Thanks, Greg. Thank you.

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