Hess Corporation

Good day, ladies and gentlemen, and welcome to the first quarter 2022 Hess Corporation conference call. My name is Liz and I will be your operator for today. At this time, all participants are in 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, Liz. Good morning, everyone, and thank you for participating in our first 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 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 line with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Riley, Chief Financial Officer. In case there are audio issues, we will be posting transcripts of each speaker's prepared remarks on www.hess.com following the presentations. I'll now turn the call over to John Hess.

Thank you, Jay. Welcome, everyone, to our first quarter conference call. Today, I will review our continuing progress to execute our strategy. Greg Hill will then discuss our operations, and John Reilly will cover our financial results. With Russia's invasion of Ukraine, the spotlight has been put on energy security and the critical importance of oil and gas to the global economy. Energy security is essential for an orderly energy transition. Oil markets were tight even before the Russia-Ukraine conflict. We have now had seven consecutive quarters of global oil inventory draws, and at the end of March, global oil inventories were estimated to be more than 400 million barrels less than pre-COVID levels. The world is facing a structural oil supply deficit, and the only way to address it is through more industry investment, and that will take time to have an impact. According to the International Energy Agency, a reasonable estimate for global oil and gas investment is at least $450 billion dollars, each year over the next 10 years to meet demand. In 2020, that number was $300 billion, and last year's investment was $340 billion. So, to ensure an affordable, just, and secure energy transition, we need to invest significantly more in oil and gas. And we also must have government policies that encourage investment rather than discourage it. In a world that will need reliable, low-cost oil and gas resources now and for decades to come, HESS is in a very strong position, offering a differentiated value proposition. Our strategy is 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 performance and disclosure. Our successful execution of this strategy has uniquely positioned our company to deliver long-term value to our shareholders by both growing intrinsic value and growing cash returns. In terms of resource growth, we have built a balanced portfolio focused on the Bakken, Deepwater Gulf of Mexico, Southeast Asia, and Guyana. With multiple phases of low-cost oil developments coming online in Guyana, and our robust inventory of high-return drilling locations in the Bakken, we can deliver highly profitable production growth of more than 10% annually over the next five years. Our expanding high-quality resource base positions us to steadily move down the cost curve. Our four sanctioned oil developments in Guyana have a break-even Brent oil price of between $25 and $35 per barrel, And by 2026, our company portfolio breakeven is forecast to decrease to a Brent oil price of approximately $45 per barrel. In terms of cash flow growth, we have an industry-leading rate of change and durability story. 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. Our balance sheet will also continue to strengthen in the coming years, with debt to EBITDAX expected to decline from less than two times in 2022 to under one time in 2024. Our financial priorities are, first, to have a disciplined capital allocation process so that we invest only in high return, low cost opportunities. Second, to maintain our investment-grade credit rating and have a strong cash position and balance sheet to ensure that we can fund our world-class investment opportunities in Guyana. And third, to return up to 75% of our annual free cash flow to shareholders. With a successful startup in February of the lease of Phase II oil development offshore Guyana, which at capacity will add $1 billion of net operating cash flow annually at a $65 Brent oil price. In late February, we repaid the remaining $500 million of our billion-dollar term loan scheduled to mature in March 2023. And on March 1st, we increased our regular quarterly dividend by 50%. In April, HES received total net proceeds of $346 million, from the secondary offering of HESS-owned Class A shares of HESS Midstream and the sale of HESS-owned Class B units to HESS Midstream. Post these transactions, HESS owns approximately 41% of HESS Midstream. To manage oil price volatility, we have hedged 150,000 barrels per day of oil production for 2022. 90,000 barrels of oil per day with $60 per barrel WTI put options, and 60,000 barrels of oil per day with $65 per barrel Brent put options. Given the significant increase in volatility and liquidity risks in the oil markets following Russia's invasion of Ukraine, in March we removed the $100 WTI and $105 Brent call options that we previously had in place. HES is now positioned to fully benefit on the upside while remaining protected on the downside. As our portfolio becomes increasingly free cash flow positive in the coming years, we commit to return up to 75% of our annual free cash flow to shareholders, with the remainder going to strengthen the balance sheet by increasing our cash position or further reducing our debt. We 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, share repurchases will represent a growing proportion of our return of capital. Key to our strategy is Guyana, the industry's largest oil province discovered in the last decade. According to a study by Wood Mackenzie, Guyana is one of the highest margin, lowest carbon intensity oil developments globally. As discussed earlier, the world will need these low-cost oil resources for decades to come to meet future energy demand. On the Staybrook Block in Guyana, where Hess has a 30% interest in ExxonMobil as the operator, a number of important milestones were recently achieved. Current production at the LISA Phase I development is 130,000 barrels of oil per day ahead of its original gross nameplate capacity. And following production optimization work on the LISA Destiny FPSO is expected to increase to more than 140,000 barrels of oil per day over the course of this quarter. The LISA Phase II development, which achieved first oil in February, is ramping up ahead of schedule and expected to reach its gross production capacity of approximately 220,000 barrels of oil per day by the third quarter. Our third development on the Staybrook block at the Piara Field with a gross capacity of approximately 220,000 barrels of oil per day is also ahead of schedule and is now expected to start up in late 2023. In early April, we announced the sanction of the Yellowtail development after receiving government and regulatory approvals. The Yellowtail development has world-class economics and will be the largest to date on the Staybrook block. The project will develop an estimated resource base of approximately 925 million barrels of oil and have a gross production capacity of approximately 250,000 barrels of oil per day, with first oil expected in 2025. Front-end engineering and design work for our fifth development at Waru Meiko is underway, and we anticipate that ExxonMobil will be in a position to submit a plan of development to the government by the year end. We want to thank and congratulate ExxonMobil for their outstanding work as operator in delivering exceptional project management and execution. According to a Wood Mackenzie study, the production growth ramp for the Staybrook block is the best in the industry compared with other major deepwater developments, which will benefit the people of Guyana and our shareholders. We continue to see the potential for at least six floating production, storage, and offloading vessels, or FPSOs, on the block in 2027 with a production capacity of more than 1 million gross barrels of oil per day and up to 10 FPSOs to develop the discovered resources on the block. In terms of exploration and appraisal in Guyana, we continue to invest in an active exploration program with approximately 12 wells planned for the Staybrook block in 2022. In January, we announced two more significant discoveries on the block at the Fangtooth and Laulau wells, which further underpin our queue of future low-cost development opportunities. Yesterday, we announced three additional discoveries at Barilai, Lukanani, and Potwa, which further strengthens the development potential of the block. With these discoveries, the gross discovered recoverable resource estimate for the block has been increased to approximately 11 billion barrels of oil equivalent, up from the previous estimate of more than 10 billion barrels of oil equivalent, and we continue to see multi-billion barrels of future exploration potential remaining. Now turning to the Bakken, where we have an industry-leading position with approximately 460,000 net acres in the core of the play. We are currently operating a three-rig program. Given the strength of the oil market and the world's need for more oil supply, we will give serious consideration to adding a fourth rig later this year. which would accelerate our production ramp up to approximately 200,000 net barrels of oil equivalent per day, a level which will maximize free cash flow generation, lower our unit cash costs, and optimize our infrastructure. As we continue to execute our strategy, our commitment to sustainability will remain a top priority. We are honored to have been recognized as an industry leader in diversity, equity, and inclusion in January. with a top score of 100% on the Human Rights Campaign's Corporate Equality Index for 2022, as well as earning a place on the Bloomberg Gender Equality Index for the third consecutive year. In summary, our differentiated portfolio is uniquely positioned to deliver industry-leading cash flow growth and financial returns in the coming years. As our portfolio becomes increasingly free cash flow positive, We commit to prioritizing the return of capital to our shareholders through further dividend increases and share repurchases. I will now turn the call over to Greg for an operational update.

Thanks, John. Let's begin with several positive developments on the Staybrook block that have created significant long-term value for the people of Guyana and our shareholders. Current production on the Lease of Destiny FPSO is 130,000 barrels of oil per day, ahead of its original base nameplate capacity and is expected to increase to more than 140,000 gross barrels of oil per day over the course of this quarter. Production on the Leesa Unity FPSO is ramping up ahead of schedule and is expected to reach its gross capacity of 220,000 barrels of oil per day by the third quarter. The Piara development is also ahead of schedule and is now forecast to start up in late 2023 versus 2024 previously. Pulling forward production startup reflects strong execution by the operator and significantly enhances the net present value of the project. The PIAR development will utilize the Prosperity FPSO with a gross capacity of 220,000 barrels of oil per day. In April, we sanctioned the Yellowtail development This project is designed to develop 925 million barrels of oil and will utilize the one Guyana FPSO with a gross capacity of 250,000 barrels of oil per day, and first oil is planned in 2025. We have also made five additional discoveries this year, which have increased the estimate of gross discovered recoverable resources to approximately 11 billion barrels of oil equivalent. We've also faced some challenges this year in the form of transitory weather issues in the Bakken and cost inflation across our portfolio. In March, we revised our Bakken and company-wide first quarter and full year 2022 production guidance lower to reflect impacts from severe weather in North Dakota as well as higher NGL prices in the first quarter, which enhanced profitability but reduced production entitlements under our percentage of proceeds contracts. These weather conditions continued in April but are transitory and we expect to recover and resume normal operations over the balance of the second quarter. Like our competitors, We are also seeing upward cost pressure across both our onshore and offshore businesses. We are mitigating many of the effects through lean manufacturing, strategic partnerships with key service providers, and technology-driven cost efficiency gains. Nevertheless, we now expect additional cost inflation of approximately 3 to 4 percent on our 2022 capital program, including higher drilling and completion costs in the Bakken that we now expect to average approximately $6.2 million per well, or 7% above last year. Of course, higher oil prices are also driving much higher earnings and cash flow. Now let's review our operating results and forecast. In the first quarter, company-wide net production averaged 276,000 barrels of oil equivalent per day, excluding Libya, which was above the high end of our revised guidance range of 270,000 to 275,000 barrels of oil equivalent per day that we provided in March. For the second quarter, we forecast that company-wide net production will average approximately 310,000 barrels of oil equivalent per day, which is 12% above last quarter. For the full year 2022, We now forecast our company-wide net production to be at the low end of our 325,000 to 330,000 barrels of oil equivalent per day guidance range due to the previously mentioned weather impacts in the Bakken in April. In the Bakken, net production in the first quarter averaged 152,000 barrels of oil equivalent per day compared to our revised guidance of 150,000 barrels of oil equivalent per day. In the first quarter, we drilled 19 wells and brought 13 new wells online. In the second quarter, we expect to drill approximately 22 wells and to bring approximately 18 new wells online. And for the full year 2022, we expect to drill approximately 90 gross operated wells and to bring approximately 85 new wells online. For the second quarter, we forecast that Bakken net production will average between 140,000 and 145,000 barrels of oil equivalent per day, and that our full year 2022 net Bakken production will be near the bottom of our previous guidance range of 160,000 to 165,000 barrels of oil equivalent per day, again, reflecting the severe weather impacts. Net production in the Bakken, however, is expected to build in the second half of the year, reaching 175,000 to 180,000 barrels of oil equivalent per day in the fourth quarter, with more wells online and improving weather conditions. We plan to bring approximately 54 new wells online in the second half of this year, compared with 31 wells in the first half. It's also important to note that well results have been strong with IP180s and EURs comparable to last year's results. As John mentioned, we're giving strong consideration to adding a fourth operated drilling rig later this year. Moving to the Gulf of Mexico, first quarter net production averaged 30,000 barrels of oil equivalent per day, which was within our guidance range of 30,000 to 35,000 barrels of oil equivalent per day. In the second quarter, We expect to maintain net production of approximately 30,000 barrels of oil equivalent per day. And for the full year 2022, we forecast net production to average between 30,000 and 35,000 barrels of oil equivalent per day, reflecting the addition of the Shell-operated 106 well, in which Hess has a 50% working interest late third quarter. The well will spud in May by Shell and 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 the year. The Gulf of Mexico is an important cash engine and a platform for growth for the company. We have multiple options for tiebacks to our three Gulf of Mexico hubs, including both infill and near-field exploration prospects. Recent acquisition and processing of proprietary ocean bottom node 3D seismic across all three areas has identified opportunities for drilling in 2023 and beyond. In terms of Mexico exploration, we spud the Huron 1 well in February on Green Canyon Block 69, where we are targeting a hub class Miocene opportunity. Results are expected during the second quarter. Hess is the operator with a 40% working interest, and Shell and Chevron each have a 30% interest. Moving to Southeast Asia, first quarter net production was 64,000 barrels of oil equivalent per day in line with guidance. Second quarter and full year 2022 net production are forecast to average approximately 65,000 barrels of oil equivalent per day. Now turning to Guyana. Our discoveries and developments on the Stabrook Block, where Hess has a 30% interest and ExxonMobil is the operator, are world class in every respect, with some of the lowest project break-even oil prices in the industry. First quarter net production averaged 30,000 barrels of oil per day, which was at the high end of our guidance range of 25,000 to 30,000 barrels of oil per day. As a result of the LESA phase one optimization work and the continued ramp up of LESA phase two, we forecast second quarter net production from Guyana to average between 70,000 and 75,000 barrels of oil per day and to increase to 85,000 to 90,000 barrels of oil per day in the fourth quarter. Our full year 2022 net production guidance for Guyana remains unchanged at between 65,000 and 70,000 barrels of oil per day. Turning to expiration, in January, we announced significant discoveries on the Staybrook block at Fangtooth and Laulau. Positive results at Fangtooth, our first standalone deep expiration prospect, will help confirm the deeper potential of the block. Laulau further underpins our queue of future low-cost development opportunities in the southeastern portion of the Staybrook Block. Yesterday, we announced discoveries at Barelai, Lucanani, and Potwa, all of which will require appraisal, but will further underpin future developments on the block. Upcoming wells in the second quarter will include Seabob, targeting Campanian Reservoirs and located 10 miles south of Yellowtail, and Kirukiru, targeting Campanian and Santonian reservoirs and located three miles southeast of Cadabac. A fang-toothed appraisal well is also planned for the fourth quarter of this year. Moving to Suriname, planning is underway on Block 42 for drilling the Zanderi I prospect around mid-year. The well will target both Campanian and Santonian aged reservoirs. We see the acreage as a potential play extension from the Staybrook block with similar play types and trap styles. Hess, Chevron and Shell, the operator, each have a one-third interest in the block. In closing, while we are managing some short-term issues with weather and cost inflation, our long-term outlook has never been brighter. Our distinctive strategy and world-class portfolio have positioned us to deliver differentiated value to our shareholders 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 first quarter of 2022 to the fourth quarter of 2021. We had net income of $417 million in the first quarter of 2022, compared with $265 million in the fourth quarter of 2021. On an adjusted basis, first quarter net income was $404 million, which excludes items affecting comparability of earnings of $13 million included in corporate interest and other. Turning to E&P, E&P had net income of $460 million in the first quarter of 2022, compared with $309 million in the fourth quarter of 2021. The changes in the after-tax components of E&P earnings between the first quarter of 2022 and fourth quarter of 2021 were as follows. Higher realized selling prices increased earnings by $227 million. Lower sales volumes decreased earnings by $154 million. Lower DD&A expense increased earnings by $62 million. All other items increased earnings by $16 million. for an overall increase in first-quarter earnings of $151 million. For the first quarter, our E&P sales volumes were under-lifted compared with production by 945,000 barrels, which decreased our after-tax income by approximately $40 million. Turning to midstream, The midstream segment had net income of $72 million in the first quarter of 2022 compared with $74 million in the fourth quarter of 2021. Midstream EBITDA before non-controlling interest amounted to $241 million in the first quarter of 2022 compared with $246 million in the previous quarter. Turning to our financial position, At quarter end, excluding midstream, cash and cash equivalents were $1.37 billion, and total liquidity was $4.94 billion, including available committed credit facilities, while debt and finance lease obligations totaled $5.61 billion. In April, we received total net proceeds of $346 million from the public offering of approximately 5.1 million HESA class A shares of HESA midstream and the sale of approximately 6.8 million HES owned Class B units to HES midstream. Pro forma for these two transactions, our cash balance at quarter end excluding midstream was approximately $1.7 billion. In the first quarter of 2022, provided by operating activities before changes in working capital was $952 million compared with $886 million in the fourth quarter of 2021. changes in operating assets and liabilities during the first quarter of 2022, decreased cash flow from operating activities by $1.1 billion, reflecting payments made for previously accrued Libyan income tax and royalties of approximately $470 million for the period December 2020 through November 2021, premiums paid of $325 million to remove the ceiling price on outstanding WTI and Brent crude oil callers effective April 1, 2022, and an increase in accounts receivable due to higher crude oil prices. In the first quarter, capital expenditures for E&P and Midstream totaled $580 million, and in February, we repaid the remaining $500 million outstanding of our $1 billion term loan. With the payoff of the remaining balance on the term loan, our leverage stands at 1.6 times E&P debt to EBITDAX. Our goal is to reduce our leverage to under one times E&P debt to EBITDAX. Based on our projected cash flow growth at $65 Brent, we expect to achieve this target in 2024 while continuing to increase returns to shareholders through dividend increases and share repurchases. Turning to 2022, in the first quarter, we sold 2.3 million barrels of oil from Guyana and expect to have seven one-million-barrel liftings in the second quarter and eight one-million-barrel liftings in both the third and fourth quarters. This ramp in liftings from Guyana is expected to result in significant cash flow growth over the next three quarters. Now turning to guidance, first for E&P, Our E&P cash costs were $13.79 per barrel of oil equivalent, including Libya, and $14.54 per barrel of oil equivalent, excluding Libya, in the first quarter of 2022. We project E&P cash costs, excluding Libya, to be in the range of $15 to $15.50 per barrel of oil equivalent for the second quarter, reflecting planned maintenance and work overspend in the Gulf of Mexico and North Dakota and higher price-driven production taxes. For the full year, cash costs excluding Libya are expected to be in the range of $13.50 to $14 per barrel of oil equivalent, compared with prior guidance of $12.50 to $13 per barrel of oil equivalent, primarily due to the impact of price-driven production taxes and the expectation production comes in at the low end of our full-year production guidance. DD&A expense was $10.96 per barrel of oil equivalent, including Libya, and $11.54 per barrel of oil equivalent, excluding Libya, in the first quarter. DD&A expense, excluding Libya, is forecast to be in the range of $12 to $12.50 per barrel of oil equivalent for the second quarter, and full year guidance of $11.50 to $12.50 per barrel of oil equivalent is unchanged. This results in projected total E&P unit operating costs excluding Libya to be in the range of $27 to $28 per barrel of oil equivalent for the second quarter and $25 to $26.50 per barrel of oil equivalent for the full year 2022. Expiration expenses excluding dry hole costs are expected to be in the range of $35 to $40 million in the second quarter and full-year guidance of $170 to $180 million is unchanged. The midstream tariff is projected to be in the range of $290 to $300 million for the second quarter, and full-year guidance of $1,190,000,000 to $1,215,000,000 is unchanged. E&P income tax expense, excluding Libya, is expected to be in the range of $135 to $140 million for the second quarter and $460 to $470 million for the full year, which is up from previous guidance of $300 to $310 million due to higher commodity prices. We expect non-cash option premium amortization, which will be reflected in our realized selling prices, will be approximately $165 million for the second quarter and approximately $550 million for the full year, inclusive of the additional premiums paid to remove the previous ceiling price on outstanding crude oil hedging contracts for the remainder of this year. Our E&P capital and exploratory expenditures are expected to be approximately $750 million in the second quarter. As Greg mentioned earlier, we are considering adding a fourth rig in the Bakken, which could add up to $100 million to our 2022 capital budget of $2.6 billion in the second half of the year. And we also expect industry cost inflation to potentially add another $80 to $100 million for this year. we will provide an update on our capital spend during our second quarter conference call. Turning to midstream, we anticipate net income attributable to HES from the midstream segment to be in the range of $60 to $65 million for the second quarter, and the full year is expected to be in the range of $265 to $275 million, which is down from previous guidance of $275 to $285 million reflecting the impact of the midstream capital transactions completed in April. Turning to corporate, corporate expenses are estimated to be approximately $30 million for the second quarter, and full year guidance of $120 to $130 million remains unchanged. Interest expense is estimated to be in the range of $85 to $90 million for the second quarter, and $345 to $355 million for the full year, which is down from previous guidance of $350 to $360 million due to the repayment of the remaining $500 million outstanding on our $1 billion term loan. 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 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 one to begin. Your first question is from the line of Doug Leggett with Bank of America.

Thank you. Good morning. Excuse me. Good morning, everybody. Good morning, Doug. Good morning, John and team. I guess I've got two questions, if I may. I mean, Guyana just continues to get better and better, obviously, with the accelerated timing on Piara, perhaps. But my question is really about the line of sight you guys have through 2027, at least. You still talk about six FPSOs, six development phases, but your production guidance or outlook is still a little bit different from what the operator ExxonMobil is saying. So I'm curious if you can just help us close the gap Is it plateau rates? Is it more conservative assumptions? What's the difference? Because clearly it seems to us that your guidance is more realistic than what the operator is saying at this point.

Yeah, Doug, great question. You know, I think ExxonMobil will be addressing that on their call, I understand. But we're sticking to the guidance that we gave, which by 2026 will be 2027. will be over a million barrels a day capacity. And I'd say that's a conservative number.

I would concur completely. Thanks, John, for the clarification. My follow-up is related to the hedging buyout. And it's kind of an obtuse question, I guess. The fact that you no longer have the upside cap on the hedges and the forward curve for both oil and gas is inflected in the way that it has, what does that do to the timing of your inflection period? to paying cash taxes in the U.S. Has it changed any?

No, Doug, it really has not changed. Our 10K, so we do have a U.S. net operating loss in excess of $16 billion here for the U.S. So from a cash tax payment, the horizon really hasn't changed. So we do not anticipate paying cash taxes, you know, in the next five years or more.

I was going to say, if I said 10, would I be wrong?

I don't want to go out that far, Doug. But, yeah, nothing in the near term.

All right, fellas. Thanks very much indeed. Thank you.

Your next question comes from Paul Chang with Scotiabank.

Hey, guys. Good morning. Morning. Morning. A couple questions here. and i i think uh with the prior uh the schedule is being pushed forward uh john you talk about uh the potential inflation impact uh for 2022 as well as the fourth week that you may how about for the prior uh the good thing is that you accelerate the development uh how about in the in terms of the budget impact

So, Paul, as you know, those contracts are EPC contracts, right? So a lot of those costs are locked in. There has been inflationary pressures on the tubulars and the drilling side. But again, I want to compliment ExxonMobil. They're doing a fantastic job of driving efficiencies to offset a large part of those cost gains. So we should be in good shape.

Yeah, and just to add to that, Paul, we don't have anything really right now from an add to our 2022 capital budget related to Piara. The Guyana developments are actually – this is really just great execution by Exxon and SBM. So there's been no add to our budget for this acceleration of the Piara startup.

Yeah, John, I think obviously that this is early to talk about 2023 – CapEx and activity level. But can you give us maybe some guidance in terms of direction and give and take how that CapEx directionality, how that is going to move?

Yes, sure. So, again, with this year, right, let's just do a reasonable approximation. As Greg mentioned, you know, 3% to 4% inflation, so that's $80 to $100 million on this year, plus adding the fourth rig, which we're giving serious consideration to, up to $100 million. So, Let's talk this year with an approximation around $2.8 billion. And then I just have to remind everybody going back to the Guyana list with two lifts in the first quarter, seven in the second, eight in both the third and fourth, that even with any increase in our capital budget, we're going to have significant cash flow growth and significant free cash flow growth throughout this year. Then start talking about next year. Now with Piora coming forward, it obviously accelerates our cash flow growth from our previous profile. So again, this durability story on our cash flow growth really can, you know, goes out, as John was mentioning earlier, to 2027. So when you look at the capital increase for next year, so what that really means if we accelerate this fourth rig in, and if I can just round it to $100 million, typically adding a rig is 200 million rule of thumb. So for a full year, you're going to add another 100 then to, you know, for Bakken standpoint. Then Guyana, to your point, I just want to say you did say it's early. So this is early. But, you know, clearly there will be some increase in Guyana capital, nowhere near matching this increase in cash flow growth that will be happening. Because at that point now, you're going to have finishing up work on phase two, but then you're going to have Piara in full swing, you got Yellowtail, and then really that fifth FPSO that we talked about. So we're going to have those three FPSOs in capital. So there will be an increase, can I say several hundred million in that capital in Guyana as you move into next year. Should be some offsets then, Southeast Asia, you know, down a little bit from this year. But that's kind of a rule of thumb, I would say, Paul. But the biggest thing for us is we've got this just increase in cash flow starting really next quarter with Guyana and now with Piara coming next year. First, we have phase two and phase one operating at full capacity and then Piara coming in. So significant cash flow growth tied into, you know, some additional capital.

John, should we assume next year the inflation will add maybe another 5% to 10% to the cost? So if this year is 2.8%, should we assume the inflation will add at least another 200 million?

So the way I would look at it is we picked up this inflation for the second half of the year. It's really that's what's happening. A lot of it, we did have some tubular steel kind of locked up in the first half, and we're seeing some increases now going into the second half of the year. So we're picking it up for half the year. I don't necessarily think you then need to double this as you move forward. We'll see what happens with oil prices and basically industry investment, too, for next year. So At this point, I wouldn't want to guide to that kind of level, Paul. And again, we do everything we can with lean and with different technology, as well as, again, a lot of these contracts for Guyana, as Greg mentioned, we've kind of fixed these prices that we have so far. So at this point, I think it's early for us to talk about what the inflation will be next year.

Thank you. Can I just sneak in a real short accounting question?

Sure.

When are you guys going to start booking income tax in your U.S. operation, given the substantially higher commodity prices that we see?

Okay, so as mentioned previously, from a cash tax standpoint, we will not be incurring cash taxes, let me just say, for five years or anything in the near term. To your point, what happens now with higher prices and more income here in the U.S., we have a full what we call, sorry, this is going to be accounting technical valuation allowance against that net operating loss. So there will come a point in time where we will release that valuation allowance, effectively book a big gain, increase equity, and then what would happen is as you use the NOL, we would be recording deferred tax expense. The exact timing of that, Paul, I don't know at this point. But again, this would all be non-cash from that standpoint.

All right. Thank you.

Your next question comes from Arun Jayaram with JP Morgan.

Yeah, my first question goes back to the yellow tail FID. Greg, you FID'd that with Exxon at a gross cost of $10 billion, which is called $1 billion more than Piara. Yet, you're doing a lot more wells, 51 versus 41, a lot more resource. And we are in a more inflationary environment. So I was wondering if you could kind of walk through, you know, the cost numbers at Yellowtail, which, you know, was a little bit lower than we were thinking, just given some of the inflationary pressures.

So, again, as when we announced Yellowtail, remember, you know, it's got a $29 break even. So this project is class and. Arun, it's exactly what you said. The costs are a little higher because, of course, it's a bigger ship. You've got 30,000 more capacity on the oil side and also on the injection and water side. So it's a much bigger boat to start with. As you mentioned, there's more wells. There's more subsea manifolds associated with those wells. So it's really all just that extra kit that has been the primary driver. Wasn't a whole lot of inflation that we saw, you know, coming through the yellow tail line. It's more just scope, um, you know, and scale, you know, exciting. It's on track for 2025 startup. The whole is actually done. It's sitting in Indonesian waters, waiting to come into Singapore, uh, as soon as Pyara is complete and it floats away. But again, it's a world-class project, $29 a barrel break-even. And of course, remember, it's developing 925 million barrels of reserves versus Pi-R that was 600, right? So for all those reasons, a little bit higher cost, but extraordinary world-class economics.

Great. And just my follow-up, Greg, I was wondering if you could just maybe give us a little bit more detail about on some of the transitory weather issues in the Bakken. We're seeing, call it gas flows are running, call it 400 million a day in the basin versus 2.1 BCF a day or so, which is more typical. So can you give us more details on the weather event and how this is impacting you and the rest of the industry in April and maybe any implications for the rest of the year?

Yeah, well, of course, that's why we lowered our guidance, you know, for the second quarter and also lowered our year end to be more at the bottom end of our guidance of 160 to 165. You know, in the Bakken, hey, it's been a tough winter with, you know, record storms in March and April. And, of course, that has impacted our production. But, you know, Arun, it's not our first weather rodeo in the Bakken. You know, it's transitory. We'll fully recover over the course of the quarter and then really be back on track, you know, to deliver our Q4 production in the range of 175 to 180. And that's, you know, a 15% increase from Q1. So, again, it's transitory. We've been through this before. Just take a little time, but, you know, we're on our way back.

All right, great. Thanks a lot, Greg.

Your next question comes from Jeanine Wye with Barclays.

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

Good morning.

Good morning. Our first question is on cash returns, and our second maybe we'll hit back on Guyana. On the cash return, so you've committed to returning up to 75% of free cash flow through dividends and buybacks. You're already above the billion-dollar reserve cash level. Can you talk about how you see the allocation between dividend increases and buybacks and what are really the gaining factors for starting the buyback? And I guess maybe on that, like how do you avoid the common investor concern that buybacks are cyclical? We've been hearing a lot more of that pushback recently.

Sure. No, great question, Janine. I think a couple of perspectives on this. Obviously, We have a unique value proposition that we offer, which is industry-leading cash flow growth of compounding 25% a year each year out for the next five years based upon $65 Brent. So we certainly can see the visibility of our cash flow growth compounding and our free cash flow along with it. In terms of the timing of the share repurchases and commencing that, look, based upon market conditions and our significant cash flow growth that John Reilly was discussing earlier, we will give serious consideration to commencing our share repurchases this year. And as we look forward, we plan to continue increasing our regular dividend to a level that is attractive to income-oriented investors, as we said, but also sustainable in a low-price environment. And as our free cash flow generation steadily increases, share repurchases will represent a growing proportion of our return of capital. We will try as best we can to be opportunistic in buying our stock, buying more on dips, but at the same time we do have a commitment to, on an annual basis, to return 75% of our free cash flow annually. But as you look forward, we'll continue to grow our dividend and then the greater proportion of our return of capital will be share repurchases And based upon the market and cash flow growth for this year, we'll give serious consideration to moving forward with our share of purchases this year.

Terrific. Thank you for all that color. And then maybe going back to Guyana on the discoveries that you announced last night, can you just maybe discuss how the results compared to your expectations, especially since two of those wells, they were pretty meaningful step outs and We were also very interested in your commentary on the high quality feed of oil versus just the hydrocarbon bearing oil or hydrocarbon reservoir feed. Thank you.

Oh, you know, thank you for the question. We're very pleased with the results. As you mentioned, you know, Barilai, 230 feet of hydrocarbon bearing reservoirs and 52 feet of that was high quality oil bearing. Lucanini 115 feet of sandstone, 76 of which was high quality oil bearing. So very, very pleased. And as you mentioned, it does, you know, these are further step outs. And I think what it does show is just how massive this accumulation is down in Guyana. And it just keeps getting bigger and better, you know, as we continue to, as we continue to grow. And then we talked about Potwa, you know, 108 feet of hydrocarbon-bearing sandstone reservoirs. Now, what do all three of these mean? Well, you know, they basically have allowed us to increase the expected gross recoverable hydrocarbons to approximately 11 billion barrels, including Fangtooth and Laulau that we announced earlier in the year. Now, how and when, you know, these resources will get developed will be a function of appraisal, drilling results, and development studies. But we are very pleased with the results of all of the wells that we've seen this year met or exceeded all of our expectations.

Great. Thank you very much.

Thank you.

Your next question comes from Neil Mehta with Goldman Sachs.

Thanks, team. A lot of the questions have been asked already, so I'll do two quick ones here. The first is, as you think about taking up that fourth rig in the Bakken area, Any gating factors in terms of executing it? Certainly the commodity price environment would suggest it could make sense, but just any questions around that, comments around that. And the second is, John, any perspective on the relationship you have from a regulatory and a fiscal perspective in Guyana? It seems like that has been stable, but given it represents a disproportionate amount, of the asset value, we always want to stay on top of any inflections that might be happening there. Thank you.

Yeah, thanks for the question, Neil, about the fourth rig. So we don't anticipate any bottlenecks or issues in getting that rig going. We're in active discussions with, you know, our contractors and suppliers up there. So we're in really good shape. And, you know, so why would we want to add that fourth rig? Well, given the high prices and world demand for oil, The world needs the oil. Plus, as you and I have talked before, you know, that fourth rig would allow us to optimize our in-basin infrastructure, increase production to about 200,000 barrels a day. And as you recall, with our extensive inventory of high return wells, we could hold that plateau for almost a decade and generate significant free cash flow from the Bakken as a result. So that's the logic for the fourth rig. We do not see any issues getting that fourth rig started up with crews or available equipment or anything. So we're in good shape.

Yeah, and Neil, in terms of the Guyana government, our company and our joint venture have an excellent working relationship, a very constructive one with the government. Testament is the early April approval of Yellowtail. The government's been very clear with us that they would like us as a joint venture to accelerate the development of their oil resources to basically improve the economic prosperity and have shared prosperity for all Guyanese citizens. So it's a very constructive working relationship. It continues. We also want to help the government in social responsibility as well. trying to make a better future for all Guyanese. So it's an excellent relationship, and we continue to work with them. And as I said before, ExxonMobil has done an outstanding job on project management and execution, bringing a lot of value forward for our joint venture, for the people of Guyana, and for our shareholders in the excellent achievements they've had in terms of being really ahead of schedule now on lease of phase one, ahead of schedule on lease of phase two, ahead of schedule on PIARA. And that track record is, you know, to the benefit of the Guyanese people as well as our shareholders. Thanks, Tim.

Your next question comes from Roger Reed with Wells Fargo.

Yeah, thanks. Good morning. Seems like the Bakken fourth rig thing has been hit quite a bit, but I do have just one question on that. What at this point would be the reason for not pulling the trigger on that at some point this year, meaning would it be hard to get a rig in the Bakken with crew and all the other associated items you need, or is it just an internal decision on your part?

No, really, it's related to operations because really the best time to build locations is after the ice out's over. So we'll go in and build those locations, get some new pads ready for that rig to operate on. So we don't sit around with idle pads laying around. We like to do it just in time. So we'll build those pads and get going drilling as soon as we can.

Okay, thanks. And then comments earlier about inflation at the CapEx side, which all makes sense. I was just curious and not trying to go against the guidance on the LOE side, but what should we think about in terms of inflationary pressures, if any, at the cash OpEx level?

Roger, it was baked in there. We're not seeing as much there on the cash operating costs of the capital. There's no question there is some. It was in the number. But the biggest driver on that increase in the cash cost per BOE is the production taxes, which is driven by higher prices. again, that helps our margins that way. So that, when you're seeing that real increase there, it's really that increase in production taxes that's driving that higher cash cost.

Great. Thank you.

Your next question comes from Bob Brackett with Bernstein. Good morning.

I had a question on that cash cost as a follow-up. The long-term guide was marching down towards, say, $9 BLE of cash costs. Much of that is mixed shift as Guyana grows. Is any part of that also assuming deflation or operational improvements?

No, not really, Bob. Now, look, we did set that out in a $65 world. That's for sure. You know, that was how we set that up. All our forecasts going out is in a $65 world. So obviously there can be impact. Again, like I just mentioned with production taxes being higher. from that standpoint, but you are correct that really what drives that down is Guyana. And in fact, if you look just at our numbers and the guide I gave, and you just did the math on the second half of the year, second half of the year has to average about $12.60 on that cash cost to get to those numbers. basically in the midpoint. And what's going to happen is third quarter will be a little bit higher, and then the fourth quarter is going to be lower than that 1260. Why? Again, because Guyana continues to build up its production. So the more and more, you know, now that Piara is moving up early and, you know, that it's to your point, it's that mix and having Guyana just drive down our cash costs, as well as Greg mentioned, getting that fourth rig on, you know, we'll optimize our infrastructure and lower our unit costs in the Bakken as well.

And then a second question on yellow tail draining 925 million barrels. Is that just from the yellow tail field or some of those nearby fields being tied into that?

No, there's also a red tail discovery that's being tied into that as well. Gotcha. And then Bob, you know, I think also we've, as we've mentioned before, You know, the plateau on all of these vessels, really, they're all going to be, you know, they'll all be bespoke. But I think you could assume extended plateaus on all the vessels as we go out in time just because of resource density, you know, in and around these hubs. So they'll be longer than what a typical deepwater development would be. But, again, they'll all be different.

Thanks a lot.

All right. Thank you.

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