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. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations.

Please proceed..

Thank you, 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 Factors section of Hess' annual and quarterly reports filed with the SEC.

Also on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.

On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. In case there are 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..

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 the successful start-up in February of the Liza Phase 2 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 $1 billion term loan scheduled to mature in March 2023.

And on March 1, we increased our regular quarterly dividend by 50%. In April, Hess 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 risk 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. Hess 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 Stabroek Block in Guyana, where Hess has a 30% interest and ExxonMobil is the operator, a number of important milestones were recently achieved. Current production at the Liza Phase 1 development is 130,000 barrels of oil per day, ahead of its original gross nameplate capacity.

And following production optimization work on the Liza Destiny FPSO is expected to increase to more than 140,000 barrels of oil per day over the course of this quarter.

The Liza Phase 2 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 Stabroek Block at the Payara 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 Stabroek 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 Uaru Meco 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 Stabroek 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 6 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 Stabroek Block in 2022.

In January, we announced 2 more significant discoveries on the block at the Fangtooth and Lau Lau wells, which further underpin our of queue of future low-cost development opportunities. Yesterday, we announced 3 additional discoveries at Barreleye, Lukanani and Patwa, 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 multibillion 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 3-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 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 Stabroek Block that have created significant long-term value for the people of Guyana and our shareholders.

Current production on the Liza 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 Liza 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 Payara development is also ahead of schedule and is now forecast to start up in late 2023 versus 2024 previously.

Pulling forward production start-up reflects strong execution by the operator and significantly enhances the net present value of the project. The Payara 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 1 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 5 additional discoveries this year, which have increased the estimate of gross discovered recoverable resources to approximately 11 billion barrels of oil equivalent. We have 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 business.

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% 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 Llano 6 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 over -- to our 3 Gulf of Mexico hubs, including both infill and near-field exploration prospects. Recent acquisition and processing and proprietary ocean bottom node 3D seismic across all 3 areas has identified opportunities for drilling in 2023 and beyond.

In terms of -- for 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 Stabroek Block, where Hess has a 30% interest and ExxonMobil is the operator, are world-class in every respect with some of the lowest project breakeven 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 Liza Phase 1 optimization work and the continued ramp-up of Liza Phase 2, 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 exploration. In January, we announced significant discoveries on the Stabroek Block at Fangtooth and Lau Lau wells.

Positive results at Fangtooth, our first stand-alone deep exploration prospect, will help confirm the deeper potential of the block. Lau Lau further underpins our queue of future low-cost development opportunities in the southeastern portion of the Stabroek Block.

Yesterday, we announced discoveries at Barreleye, Lukanani and Patwa, all of which will require appraisal but will further underpin future developments on the block.

Upcoming wells in the second quarter will include CBOB targeting Campanian reservoirs and located 10 miles south of Yellowtail; and Kiru targeting Campanian and Santonian reservoirs and located 3 miles southeast of Catabac. A Fangtooth 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-1 prospect around midyear. The well will target both Campanian and Santonian aged reservoirs. We see the acreage as a potential play extension from the Stabroek Block with similar play types and trap styles. Hess, Chevron and Shell, the operator, each have a 1/3 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 Rielly..

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 underlifted 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 noncontrolling 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 Hess-owned Class A shares of Hess Midstream and the sale of approximately 6.8 million Hess-owned Class B units to Hess Midstream.

Pro forma for these 2 transactions, our cash balance at quarter end, excluding Midstream, was approximately $1.7 billion. In the first quarter of 2022, [indiscernible] 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 collars 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 1.6x E&P debt to EBITDAX.

Our goal is to reduce our leverage to under 1x 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 1 million-barrel liftings in the second quarter and eight 1 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 3 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 workover spend 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.

Exploration expenses, excluding dry hole costs, are expected to be in the range of $35 million to $40 million in the second quarter, and full year guidance of $170 million to $180 million is unchanged.

The Midstream tariff is projected to be in the range of $290 million 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 million to $140 million for the second quarter and $460 million to $470 million for the full year, which is up from previous guidance of $300 million to $310 million due to higher commodity prices.

We expect noncash 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 million 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 Hess from the Midstream segment to be in the range of $60 million to $65 million for the second quarter.

And the full year is expected to be in the range of $265 million to $275 million, which is down from previous guidance of $275 million 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 million to $130 million remains unchanged.

Interest expense is estimated to be in the range of $85 million to $90 million for the second quarter and $345 million to $355 million for the full year, which is down from previous guidance of $350 million 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..

[Operator Instructions] Your first question comes from the line of Doug Leggate with Bank of America..

I guess I've got 2 questions, if I may. So I mean, Guyana just continues to get better and better, obviously, with the accelerated timing on Payara perhaps. But my question is really about the line-of-sight you guys have through 2027, at least.

You still talk about 6 FPSOs, 6 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..

Yes, Doug, great question. 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 -- '27 will be over 1 million barrels a day of capacity. And I'd say that's a conservative number..

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.

But 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 to paying cash taxes in the U.S.? Has it changed any?.

No, Doug. It really has not changed. If you read our 10-K, 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 in the next 5 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 yes, nothing in the near term..

Your next question comes from Paul Cheng with Scotiabank..

Couple of questions. And I think with Payara, the schedule is being pushed forward. John, you talked about the potential inflation impact for 2022 as well as the fourth rig that [indiscernible]. How about for the Payara? The good thing is that you accelerate the development.

How about 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, in the drilling side. But again, I want to complement 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..

Yes. 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 Payara. 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 Payara start-up..

Yes.

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 your take that the CapEx directionally, how that is going to move?.

Yes, sure. So again, with this year, right, let's just do a reasonable approximation, as Greg mentioned, 3% to 4% inflation so that's $80 million to $100 million on this year, plus adding the fourth rig, which we're giving serious consideration to, up to $100 million. So look, let's talk this year with an approximation around $2.8 billion.

And then I just have to remind everybody going back like to the Guyana lifts, with 2 lifts in the first quarter, 7 in the second, 8 in both the third and fourth, that we're -- 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 Payara 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 -- 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 million then to -- from Bakken standpoint.

Then Guyana, to your point, I just want to say you did say it's early so this is early, but 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 2 but then you're going to have Payara in full swing.

You got Yellowtail and then really that fifth FPSO that we talked about. So we're going to have those 3 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 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 Payara coming next year.

First, we have Phase 2 and Phase 1 operating at full capacity and then Payara coming in, so significant cash flow growth tied into some additional capital..

John, should we assume next year, the inflation will add maybe another 5% to 10% to the core, so if this year is $2.8 billion, should we assume that 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..

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

Sure..

So 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 5 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 noncash from that standpoint..

Your next question comes from Arun Jayaram with JP Morgan..

Yes. My first question goes back to the Yellowtail FID. Greg, you FID-ed that with Exxon at a gross cost of $10 billion, which is, call it, $1 billion more than Payara 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 the cost numbers at Yellowtail, which was a little bit lower than we were thinking, just given some of the inflationary pressures..

So again, as when we announced Yellowtail, remember, it's got a $29 breakeven, so this project is world-class. And Arun, it is, it's exactly what you said. 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 coming through the Yellowtail line. It's more just scope and scale. Exciting it's on track for 2025 start-up. The hole is actually done.

It's sitting in Indonesian waters, waiting to come into Singapore as soon as Payara is complete and it floats away. But again, it's a world-class project, $29 a barrel breakeven.

And of course, remember, it's developing 925 million barrels of reserves versus Payara that was 600 million, 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 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?.

Yes. Well, of course, that's why we lowered our guidance for the second quarter and also lowered our year-end to be more at the bottom end of our guidance of 160 to 165 in the Bakken. Hey, it's been a tough winter with record storms in March and April, and of course, that has impacted our production.

But Arun, it's not our first weather rodeo in the Bakken. It's transitory. We'll fully recover over the course of the quarter and then really be back on track to deliver our Q4 production in the range of 175 to 180, and that's a 15% increase in Q1. So again, it's transitory. We've been through this before.

Just take a little time but we're on our way back..

Your next question comes from Jeanine Wai with Barclays..

Our first question is on cash returns, and our second, maybe we'll hit back on Guyana. On the cash terms, so you've committed to returning up to 75% of free cash flow through dividends and buybacks. You're already above the $1 billion reserve cash level.

So can you talk about how you see the allocation between dividend increases and buybacks? And what are really the gating 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, Jeanine. 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 5 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 Rielly 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 repurchases this year..

Terrific. And then maybe going back to Guyana on the discoveries that you announced last night.

Can you just maybe discuss how the results compare to your expectations, especially since 2 of those wells, they were pretty meaningful step-outs and we were also very interested in your commentary on the high-quality of oil versus just the hydrocarbon bearing oil or hydrochain reservoir feet?.

Thank you for the question. We're very pleased with the results. As you mentioned, Barreleye, 230 feet of hydrocarbon-bearing reservoirs and 52 feet of that was high-quality oil bearing. Lukanani, 115 feet of sandstone, 76 of which was high-quality oil-bearing, so very, very pleased. And as you mentioned, it does -- 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 as we continue to grow. And then we talked about Patwa, 108 feet of hydrocarbon-bearing sandstone reservoirs.

Now what do all 3 of these mean? Well, they basically have allowed us to increase expected gross recoverable hydrocarbons to approximately 11 billion barrels, including Fangtooth and Lau Lau that we announced earlier in the year.

Now how and when these resources will get developed to 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..

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

A lot of the questions have been asked already, so I'll do 2 quick ones here. The first is, as you think about taking up that fourth rig in the Bakken, 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..

Yes. 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 our contractors and suppliers up there so we're in really good shape.

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, 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 availability equipment or anything.

So we're in good shape..

Yes. 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 has 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 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 Liza Phase 1, ahead of schedule on Liza Phase 2, ahead of schedule on Payara.

And that track record is to the benefit of the Guyanese people as well as our shareholders..

Your next question comes from Roger Read with Wells Fargo..

Seems like the Bakken fourth rig thing has been hit quite a bit, but I do have just 1 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 is 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. 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 cost, cash operating costs, 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. So 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..

Your next question comes from Bob Brackett with Bernstein..

I had a question on that cash cost as a follow-up. The long-term guide was marching down towards, say, $9 BOE of cash costs. Much of that is mix shift as 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. 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 $12.60. Why? Again, because Guyana continues to build up its production.

So the more and more now that Payara is moving up early, and 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, we'll optimize our infrastructure and lower our unit cost in the Bakken as well..

That's clear.

And then a second question on Yellowtail, draining 925 million barrels, is that just from the Yellowtail Field or are some of those nearby fields being tied into that?.

No. There's also a Redtail discovery that's being tied into that as well..

Got it..

And then, Bob, I think also we -- as we've mentioned before, the plateau on all of these vessels, really, they're all going to be -- 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 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..

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