Hess Corporation (NYSE:HES) Q1 2023 Earnings Call Transcript

Hess Corporation (NYSE:HES) Q1 2023 Earnings Call Transcript April 26, 2023

Hess Corporation beats earnings expectations. Reported EPS is $1.13, expectations were $1.06.

Operator: Good day, ladies and gentlemen, and welcome to the First Quarter 2023 Hess Corporation Conference Call. My name is Kevin and I’ll be your operator for today. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Jay Wilson: Thank you, Kevin. 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’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 Rielly, Chief Financial Officer. I’ll now turn the call over to John Hess.

John Hess: Thank you, Jay. Good morning and welcome to our first quarter conference call. Today, I will discuss our continued progress in executing our strategy. Greg Hill will then cover our operations, and John Rielly will review our financial results. We believe that Hess offers a unique value proposition for investors. Our strategy is to deliver high-return resource growth, a low cost of supply, and industry-leading cash flow growth, and at the same time, maintain our industry leadership in environmental, social, and governance performance and disclosure. In terms of resource growth with multiple phases of Guyana developments coming online, and our robust inventory of high-return drilling locations in the Bakken, we can deliver highly profitable production growth of more than 10% annually through 2027.

On the Stabroek Block in Guyana, we currently have line of sight to six floating production, storage and all floating vessels, or FPSOs, in 2027 with a gross production capacity of more than 1.2 million barrels of oil per day. In terms of the low cost of supply, as our resource base continues to expand, we will steadily move down the cost curve. By 2027, we forecast that our cash unit costs will decline by 25% to approximately $10 per BOE and that our portfolio will achieve a breakeven Brent oil price of approximately $50 per barrel. Our four sanctioned oil developments on the Stabroek Block have a breakeven Brent oil price of between approximately $25 and $35 per barrel. In terms of cash flow growth, we have an industry-leading rate of change story and an industry-leading duration story, providing a highly differentiated value proposition.

Based upon a flat Brent oil price of $70 per barrel — $75 per barrel, our cash flow is forecast to increase by approximately 25% annually between 2022 and 2027, more than twice as fast as our topline growth. And our balance sheet will also continue to strengthen with our most recent debt-to-EBITDAX ratio at approximately one-time. Successful execution of our strategy has uniquely positioned our company to deliver significant value to shareholders for years to come, both by growing intrinsic value and by growing cash returns. Our financial priorities are to allocate capital to our high-return low-cost investment opportunities, to maintain a strong balance sheet and cash position to ensure that we can fund our world-class investment opportunities in Guyana and the Bakken, where we have allocated more than 80% of our 2023 capital budget and also return up to 75% of our annual free cash flow to shareholders through dividend increases and share repurchases.

In line with our return of capital framework, in March, we increased our annual dividend by 17% to $1.75 per share. Looking ahead, we plan to continue increasing our regular dividend to a level that is attractive to income oriented investors, but sustainable in a low oil price environment. As our free cash flow generation steadily increases in future years, share repurchases are expected to represent a growing proportion of our return of capital. To manage oil price volatility, we have hedged 130,000 barrels of oil per day in 2023, of which 80,000 barrels of oil per day have $70 per barrel WTI put options and 50,000 barrels of oil per day has $75 per barrel Brent put options, which positions our shareholders to be protected on the downside, while fully benefiting on the upside.

Key to our strategy is Guyana, the industry’s largest oil province discovered in the last decade, where Hess has a 30% interest and ExxonMobil is the operator. Since 2015, we have had more than 30 discoveries on the block, including two since the start of 2023 at Fangtooth Southeast-1 and Lancetfish-1, underpinning a gross discovered recoverable resource estimate of more than 11 billion barrels of oil equivalent with multibillion barrels of exploration potential remaining. We have the potential for up to 10 FPSOs to develop the discovered resources on the block. The Liza Phase 1 and Liza Phase 2 developments produced an average of approximately 375,000 gross barrels of oil per day in the first quarter. The FPSO for our third sanctioned development at Payara arrived on the Stabroek Block earlier this month ahead of schedule and is targeted to start up early in the fourth quarter with a gross production capacity of approximately 220,000 of oil per day.

The fourth sanction development, Yellowtail is expected to come online in 2025 with a gross production capacity of approximately 250,000 barrels of oil per day. Government and regulatory approvals are expected very soon, hopefully this week for our fifth development at Uaru, which will have a gross production capacity of approximately 250,000 barrels of oil per day, a plan of development for our sixth development Whiptail, is expected to be submitted to government and — for regulatory and government approvals later this year. Turning to the Bakken. We plan to continue operating a four-rig program, which will enable us to grow net production to approximately 200,000 barrels of oil equivalent per day in 2025, lower our unit cash, fully optimize our infrastructure and generate significant levels of free cash flow.

Greg and his team continue to do an outstanding job of applying lean manufacturing principles to build a culture of innovation, improve efficiency and mitigate inflationary cost pressures. As we execute our company strategy, we will continue to be guided by our long-standing commitment to sustainability and are proud to be an industry leader in this area. Earlier this month, we announced a $50 million donation over the next five years to the Salk Institute harnessing plants initiative, which is a potential game changer in tackling the global challenge of climate change by developing plants, crops and wetlands natural ability to capture and store potentially billions of tons of carbon per year from the atmosphere. We are proud to once again have received a AAA rating in the latest MSCI Environmental, Social and Governance rating assessment.

AAA, which is MSCI’s ESG’s highest rating, designates our company as a leader in managing industry-specific ESG risks relative to peers. We received our first AAA rating in 2021 after earning AA ratings for 10 consecutive years. In February, Hess also earned a place on the 2023 Bloomberg Gender Equality Index for the fourth consecutive year. In summary, we continue to successfully execute our strategy, which offers a unique value proposition for our industry by growing both our intrinsic value and our cash returns, with multiple phases of low-cost oil developments coming online in Guyana and our robust inventory of high-return drilling locations in the Bakken. Our portfolio is positioned to become increasingly free cash flow positive and as it does, we will continue to prioritize the return of capital to our shareholders through further dividend increases and further share repurchases.

I will now turn the call over to Greg Hill for an operational update.

Greg Hill : Thanks, John. We demonstrated strong operational performance across our portfolio in the first quarter. Company-wide net production averaged 374,000 barrels of oil equivalent per day, above our guidance of approximately 345,000 to 355,000 barrels of oil equivalent per day. For the second quarter, we forecast the company-wide net production will average between 355,000 and 365,000 barrels of oil equivalent per day, reflecting planned maintenance activities at Liza Phase 2 in Guyana, several of our Gulf of Mexico fields and at North Malay Basin in Southeast Asia. For the full year 2023, we now expect company-wide net production to average between 365,000 and 375,000 barrels of oil equivalent per day, an increase from our previous guidance of 355,000 to 365,000 barrels of oil equivalent per day due to strong performance in the first quarter of 2023.

In the Bakken, first quarter net production of 163,000 barrels of oil equivalent per day was above our guidance of 155,000 to 160,000 barrels of oil equivalent per day, reflecting high uptime and strong recovery from challenging weather conditions this winter. In the first quarter, we drilled 25 wells and brought 24 new wells online. In the second quarter, we expect to drill and bring online approximately 27 new wells. For the full year 2023, we expect to drill and bring online approximately 110 new wells. Individual well results in terms of EURs and IP 180s continue to meet or exceed expectations. For both the second quarter and full year 2023, we expect Bakken net production to average between 165,000 and 170,000 barrels of oil equivalent per day.

Moving to the offshore. In the Deepwater Gulf of Mexico, first quarter net production averaged 33,000 barrels of oil equivalent per day, above our guidance of approximately 30,000 barrels of oil equivalent per day, primarily reflecting better uptime. In the second quarter, we expect net production to average approximately 25,000 barrels of oil equivalent per day, reflecting planned maintenance at several of our Gulf of Mexico fields. For the full year 2023, we continue to forecast Gulf of Mexico net production to average approximately 30,000 barrels of oil equivalent per day. The Deepwater Gulf of Mexico remains an important cash engine for the company as well as a platform for growth. In May, we plan to spud the Pickerel 1 well located in Mississippi Canyon Block 727.

Pickerel is an infrastructure-led exploration prospect, which will be tied back to Tubular Bells. Following Pickerel, we plan to drill another tieback well at Stampede and a hub class exploration well in the Green Canyon area. In Southeast Asia, first quarter net production averaged 66,000 barrels of oil equivalent per day. Second quarter net production is forecast to average approximately 60,000 barrels of oil equivalent per day, reflecting planned maintenance at North Malay Basin. Full year net production for Southeast Asia in 2023 is now forecast to average approximately 65,000 barrels of oil equivalent per day compared with our previous guidance of 60,000 to 65,000 barrels of oil equivalent per day. In Guyana, where Hess has a 30% interest in the Stabroek Block, the operator ExxonMobil continues to deliver outstanding facilities reliability and project execution success.

First quarter net production averaged 112,000 barrels of oil per day above our guidance of approximately 100,000 barrels of oil per day, primarily driven by strong facility uptime and well performance. For the second quarter, net production from Guyana is expected to average between 105,000 and 110,000 barrels of oil per day, reflecting reduced capacity at Liza Phase 2 for planned maintenance. We now expect full year 2023 net production, the average between 105,000 and 110,000 barrels of oil per day compared to our previous guidance of approximately 100, 000 barrels of oil per day. Turning to Guyana developments. The Prosperity FPSO, with a production capacity of approximately 220,000 gross barrels of oil per day, arrived at the Stabroek Block on April 11.

The vessel is undergoing hookup and commissioning and is targeted to achieve first oil from Payara, our third development early in the fourth quarter. Yellowtail, our fourth development is approximately 45% complete and remains on track for first oil in 2025. The 250,000 barrel of oil per day One Guyana FPSO hull entered dry dock in Singapore on April 2. Topside fabrication and installation activities have commenced and development drilling is underway. Government and regulatory approvals are expected very soon for our fifth development at Uaru, with a gross production capacity of approximately 250,000 barrels of oil per day. Finally, for our sixth development, Whiptail, the partnership is on track for final submission of the field development plan to the government of Guyana later this year.

Now, turning to exploration. The Lancetfish-1 Well, located 4 miles southeast of the Fangtooth 1 discovery, encountered 92 feet of oil-bearing sandstone reservoir. This discovery further underpins the potential oil development in the Greater Fangtooth area. Drill stem tests and core analysis are underway at Fangtooth 1 and further appraisal activities for Lancetfish and Fangtooth Southeast are planned for later in the year. In the second half of the year, we plan to drill the Bacher 1 well, which is a deep prospect located approximately 7 miles west of Fangtooth 1 and another deep exploration prospect called Lancetfish, located 2 miles southwest of Fangtooth 1. Moving to offshore Canada, we expect to spud the BP-operated Episys 1 well in the Northern Orphan Basin in May.

The well will target a very large submarine fan of tertiary age. BP has a 50% working interest in Hess and Chevron, each have 25% interest. In closing, our execution continues to be strong. The Bakken is on a steady growth trajectory. Our Gulf of Mexico and Southeast Asia assets have active drilling programs and we continue to advance our major projects and further delineate the enormous upside in Guyana, all of which position us to deliver industry-leading performance and significant shareholder value for years to come. I will now turn the call over to John Reilly.

John Rielly: Thanks, Greg. In my remarks today, I will compare results from the first quarter of 2023 to the fourth quarter of 2022. We had net income of $346 million in the first quarter of 2023 compared with $497 million in the fourth quarter of 2022, or $522 million on an adjusted basis, which excluded items affecting comparability of earnings. Turning to E&P. E&P net income was $405 million in the first quarter of 2023 compared with an adjusted net income of $565 million in the fourth quarter of 2022. The changes in the after-tax components of E&P earnings between the first quarter of 2023 and fourth quarter 2022 were as follows. Lower sales volumes decreased earnings by $138 million lower realized selling prices decreased earnings by $45 million.

Lower cash costs and midstream tariffs increased earnings by $16 million. Lower exploration expenses increased earnings by $7 million for an overall decrease in first quarter earnings of $160 million. For the first quarter, our E&P oil sales volumes were under lifted compared with production by approximately 325,000 barrels, which decreased our after-tax income by approximately $15 million. Now, turning to Midstream. The Midstream segment had net income of $61 million in the first quarter of 2023 compared with $64 million in the fourth quarter of 2022. Midstream EBITDA, before non-controlling interest amounted to $238 million in the first quarter compared to $244 million in the previous quarter. Turning to our financial position. At March 31, excluding the Midstream segment, cash and cash equivalents were $2.1 billion, total liquidity was $5.4 billion, including available committed credit facilities, and debt and finance lease obligations totaled $5.6 billion.

In March, we received net proceeds of $50 million from the sale of approximately 1.8 million Hess-owned Class B units to Hess Midstream. In the first quarter of 2023, net cash provided by operating activities before changes in working capital was $1 billion compared with $1.3 billion in the fourth quarter of 2022, primarily due to lower sales volumes and realized selling prices. Changes in operating assets and liabilities during the first quarter decreased cash flow from operating activities by $394 million, which includes premiums paid for hedging contracts. E&P capital and exploratory expenditures were $765 million in the first quarter of 2023 compared to $818 million in the fourth quarter of 2022. Now turning to guidance. First, for E&P.

Our E&P cash costs were $12.96 per barrel of oil equivalent in the first quarter of 2023, which was lower than our guidance of $14 to $14.50 per barrel of oil equivalent due to higher production and the deferral of workover spend to the second quarter. We project E&P cash costs to be in the range of $15.50 to $16 per barrel of oil equivalent for the second quarter, reflecting planned maintenance activities at the Liza Unity, North Malay Basin and several facilities in the Gulf of Mexico and higher workover spend in the Gulf of Mexico. Full year cash cost guidance in the range of $13.50 to $14.50 per barrel of oil equivalent remains unchanged. DD&A expense was $13.16 per barrel of oil equivalent in the first quarter of 2023. DD&A expense is forecast to be in the range of $13 to $13.50 per barrel of oil equivalent for the second quarter and full year DD&A expense in the range of $13 to $14 per barrel of oil equivalent remains unchanged.

This results in projected total E&P unit operating costs to be in the range of $28.50 to $29.50 per barrel of oil equivalent for the second quarter and $26.50 to $28.5 0 per barrel of oil equivalent for the full year 2023. Exploration expenses, excluding dry hole costs, are expected to be in the range of $40 million to $45 million in the second quarter and full year guidance of $160 million to $170 million remains unchanged. The midstream tariff is projected to be in the range of $305 million to $315 million for the second quarter and full year guidance of $1.230 billion to $1.250 billion remains unchanged. E&P income tax expense is expected to be in the range of $170 million to $180 million for the second quarter and $670 million to $680 million for the full year, which is up from previous guidance of $590 million to $600 million due to higher commodity prices.

During the first quarter, we purchased WTI put options for 80,000 barrels of oil per day for 2023 with an average monthly floor price of $70 per barrel and Brent put options for 50,000 barrels of oil per day for 2023 with an average monthly floor price of $75 per barrel. We expect non-cash option premium amortization, which will be reflected in our realized selling prices will be approximately $50 million for the second quarter and approximately $190 million for the full year 2023. Our E&P capital and exploratory expenditures are expected to be approximately $975 million in the second quarter and full year guidance of approximately $3.7 billion remains unchanged. For midstream, we anticipate net income attributable to Hess from the Midstream segment to be in the range of $55 million to $60 million for the second quarter and full year guidance of $255 million to $265 million remains unchanged.

For 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 $80 million to $85 million for the second quarter and full year guidance of $305 million to $315 million remains unchanged. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

Q&A Session

Operator: Thank you. Our first question comes from Ryan Todd with Piper Sandler. Your line is open.

Ryan Todd: Great. Thanks. Sorry, I was on mute there.

Greg Hill: No worries.

Ryan Todd: First off, I guess, congratulations on very strong production in Guyana this quarter. Can you talk about what you’ve seen on productive capacity on these first two developments, both on the reservoir side, what you’re seeing subsurface there, as well as post debottleneck surface facility side. What should we expect these two facilities to sustainably produce going forward?

Greg Hill: Yes. Thanks, Ryan. So, first of all, the wells have been performing extremely well above expectations. So subsurface going great, continue to see further upside in the subsurface as we kind of produce the wells. And then, as I mentioned in my opening remarks, Exxon Mobil and SBM are just doing an outstanding job of topsides reliability and also the debottlenecking side. Recall that Phase 1 was debottlenecked to the 140,000 barrels, it’s actually producing between 140,000 and 150,000 barrels, sort of in that range. And then if you look at Phase 2, it has a nameplate of 220,000 barrels. It’s on track to be debottlenecked towards 250,000 barrels by the end of the year. So, again, more upside coming on Phase 2. And it’s been operating kind of 230,000 barrels or so on a regular basis, but we’ll pick up that up towards 250,000 barrels by the year — by the end of the year. So upside, upside.

Ryan Todd: Awesome. Thanks, Greg. And then, maybe, just one on cost inflation and what you’re seeing. It’s obviously very topical across the space right now. I mean, can you talk about what you’re seeing in the Bakken onshore and offshore as well in terms of kind of leading-edge trends across various silos of what you’re seeing on service costs?

Greg Hill: Sure. Yes. So in some areas such as oil country tubular goods, we’re expecting some moderation in inflation coming. Onshore rigs pretty much staying flat, but we’re still seeing some pressure in certain areas, particularly labor. Now, specifically in the Bakken, we anticipated year-over-year inflation of between 10% to 15%. That’s about where it’s running. However, remember, we’re mitigating about half of these impacts through the application of strategic contracting, lean manufacturing and technology. So, our Bakken well guidance of $6.9 per well for the year, remains unchanged. So if we look at the offshore, we’re expecting year-over-year industry inflation there between 15% and 20%. Now remember, in Guyana, the first four FPSOs are contracted, so they’ll have limited the exposure going forward.

And then in addition, ExxonMobil is just doing a fantastic job of mitigating kind of inflation effects through their outstanding execution and performance using that design one, build many strategy, which is sort of like lean manufacturing in the offshore. And then finally, in our Gulf of Mexico operations, we contracted our services in 2022, so we missed some of the recent uptick. So because of that, our overall capital guidance of $3.7 billion remains unchanged this year.

Ryan Todd: Great. Thanks, Greg.

Operator: One moment for our next question. Our next question comes from Doug Leggate with Bank of America. Your line is open.

Doug Leggate: Thanks. Good morning, everybody. Thanks for getting me on.

John Hess: Good morning.

Doug Leggate: Gents, I wonder if I could kick off with one on the somewhat rare event nowadays of a dry hole in Guyana. I know that’s a little bit flippant, but I’m curious as to where you think you are on the cleaning curve at this point. This was obviously a step out carbonate. You haven’t really talked about it. How many more of those do you think you’re going to be pursuing, I guess. And if I could just do a quick add-on to that, when you talk about the 11 billion barrels, what are we actually talking about is actually included in that versus the — I guess, north of 30 discoveries you have so far.

Greg Hill: Yes. Thanks, Doug. So let me co-quarry first. Recall that was a higher-risk carbonate play that was located 37 miles from Liza 1 and it didn’t encounter commercial hydrocarbons, but it did provide a lot of valuable data that further improves our understanding of the subsurface. Going forward, Doug, we still continue to see multibillion barrels of upside that hasn’t changed. And finally, in reference to your question, the 11 billion barrels, the majority of that is in the upper campaign. And obviously, with our exploration program this year, we’re really starting to understand the deep and what potential that holds. But across the block, this multibillion barrels of additional upside remains unchanged. Yes, we’ll have a few dry holes as we test different things along the way, but there’s still a lot more to play with.

Doug Leggate: So, are we talking like two-thirds of the wells are the 11 billion barrels or the discoveries rather? If not 31 is my point. What’s the — what’s not included?

Greg Hill: What’s not included in the 11 billion? So, the recent discoveries that we’ve had are obviously not included in that. Again, Doug, it’s mainly Upper Campanian, right? So, as we get results, the lower Campanian, obviously, that will be incorporated. But the multibillion barrels of additional upside encompasses the upper and the lower. It’s not just the lower. It’s — there’s still a lot of upper Campanian to play for as well.

Doug Leggate: Thank you for that. I’ll take the rest offline. My follow-up is just a housekeeping question, maybe for John Rielly. John, you walked through the working capital moves. I guess my question is, when I look at the accretion mass on Guyana, the NPV accretion with the potential buybacks, it seems kind of obvious that the value that you’re in your share price today, a lot of it is obviously not being reflected. So, I’m curious on what the strategy is for the buyback program, meaning, is it a — after working capital cash flow number that you’re looking at, or is that’s obviously going to move around quarter-to-quarter? Just how are you thinking about it because we were anticipating you might have a little quicker buyback pace this quarter.

John Rielly: Sure Doug. So, let me just back up and talk about our financial priorities that we have. So, the first priority is obviously to invest in these high-return opportunities, obviously driven by Guyana and the Bakken because that’s going to drive our free cash flow growth. And as John said earlier in his comments that we can grow intrinsic value and cash returns and it’s Guyana Bakken that will allow us to do that. Our second priority is to maintain a strong balance sheet. Again, we’re in a good position with that. We want to also have a strong cash position, and we do have $2.1 billion of cash on the balance sheet. So, we’re in a good place with that to fund our high-return projects. So, for us, we have this capital return framework, and we’re going to follow that, that we put out.

And so what we do is return up to 75% of our free cash flow on an annual basis, so that is after working capital, that is after capital expenditures, and even after debt maturities, which we don’t have any this year, we do have $300 million in 2024. And so first thing that we’ll do in that return of capital framework is focused on the dividend. As John mentioned in his opening remarks, we want to increase that dividend each year. And we did do that in March, so we had that 17% increase $0.25 per share increase and so that is going to be the first thing. So, we did increase our returns shareholders here in the first quarter with that dividend increase. Then the remainder of that free cash flow, that 75% will be done in share repurchases. And you’re right, we agree with you about the NAV accretion that we’ll be having with these FPSOs. And just to remind everybody, with each FPSO comes on, like obviously, we have Payara here coming early this year that generates net to us $1 billion of cash flow.

So, again, the Payara and the Yellowtail wireless. So we’re getting that $1 billion kind of a year adding to our portfolio. And so as we go forward, more and more of our capital returns will be share repurchases. And so buying our shares basically in advance of those as we get — as Payara comes on, generates that $1 billion and gets in front of Yellowtail and Uaru, obviously, will be, I think, be able to deliver significant value to shareholders just following this framework that we have.

Doug Leggate: Okay. That’s very clear. Thanks.

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

Neil Mehta: Yeah. Good morning team and congrats on a super quarter. John, first question is for you about building downside resiliency in the business model. Obviously, there’s a lot of reasons to be constructive long-term – near-term is more uncertain from an economic perspective. And so just curious on how having gone through the last 10 years with a lot of volatility, have you built in defenses within the Hess business model? I think you talked about one, which is the hedging strategy and then also improving the balance sheet. But just any thoughts around that as we think about creating defensive attributes?

John Hess: No. Look, we obviously focus — and thank you for the question. We focused our portfolio on high return, low cost of supply opportunities. Obviously, we think we have built a highly differentiated value proposition and part of that is the low-cost model. The fact that over the next five years, we can get our breakeven to $50 Brent. Also, the cash cost going down 25% as well. I think that makes our portfolio very resilient in a low price environment. John Reilly talked about capital discipline and also the priority on keeping a strong balance sheet and cash position, our cash position at the end of the quarter was over $2 billion. And we will continue to hedge by buying puts to protect the downside and still give our shareholders the upside. So I think relative to a lot of our competitors that are having cost pressures going up, our costs are going down, and we’re going to keep a strong balance sheet to stay resilient through the cycle.

Neil Mehta: Yeah. That’s very clear. And then a follow-up just on the Bakken. Can you talk about the trajectory that you anticipate over the course of the year? And then what do you think we get to plateau and at what level?

Greg Hill: Yeah. So we exited Q1 in line with our forecast, a little bit ahead of guidance, but it was in line with our forecast, and we expect to see a build through the end of the year as we continue to steadily bring wells online. Now we’ll provide guidance for the Bakken as usual, in our second quarter conference call for the rest of the year. But I think, Neil, just expect sort of a steady increase with a four-rig program across 2023 and 2024. We’ll get to 200,000 barrels a day in 2025. And then be able to hold that flat for almost a decade with the inventory that we have. So steady increase to 200,000, hold it flat for a decade. I want to remind people that when Bakken reaches that 200,000 plateau, it will generate about $1 billion of free cash flow. So steady cash flow generator for the company.

Neil Mehta: Thanks guys.

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

Paul Cheng: Hey guys, good morning.

John Hess: Hi. Good morning.

Paul Cheng: Two questions. Just curious that, I mean, John, how important is the Hess Midstream for the longer term of the company? I mean, do we need to have the ownership over there, especially then, I mean once you get Bakken, say at 200,000 barrels per day, do we still need to have the operatorship or even the ownership? That’s the first question.

John Rielly: Sure, Paul. I mean we remain committed to maximizing the long-term value of Hess Midstream. It’s been a key strategic partner for us. It adds differentiated value to our E&P assets up there in the Bakken with us maintaining that operational and marketing control so we get provides takeaway optionality to high-value markets. Also, it’s key to our gas capture and driving down flaring in our GHG emission intensity. So I would say think about Hess Midstream more of the same, they’ve been doing — they’ve been executing brilliantly really for us on the ESG and also just getting the E&P production to markets. And then when you think about Hess Midstream, it has a very strong credit position and continues to generate free cash flow growth.

So the Hess Midstream, they did outline that they have about $1 billion of financial flexibility through 2025 for capital allocation, which includes then the potential for incremental returns of capital, like the recent $100 million transaction that they just did. And so that $100 million is a small part of that $1 billion financial flexibility. So Hess Midstream has the potential to execute multiple buybacks basically each year through 2025. So I think you can think about it just more of the same that way, Paul, and we are happy with the investment.

Paul Cheng: Okay. Second question, I think this is for Greg. Greg, I think that I’ve been saying that the Yellowtail is going to be 2025 versus oil. Any kind of maybe a new bit narrower window? Is it going to be in the first half, second half or any kind of color you can provide? And also, how many exploration wells, not appraisal well, but exploration wells, the consultant plan to drill between now and the expiration of the exploration basis?

Greg Hill: So let me answer the exploration part first. So Paul, remember, we’ve got multibillion barrels of upside. The license expires in October of 2026. We will take the next four to five years to fully understand that potential get it locked down. So I think you should think about three wells — three exploration rigs a year pretty much going through 2026. And we can drill usually about 10 or so exploration and appraisal wells a year. So think of that sort of a level exploration prospectivity going forward, again, going after that multibillion barrels of upside that we continue to see. Your question on Yellowtail. Look, Yellowtail…

Paul Cheng: Sorry. For the 10 well per year, do you have a split roughly that the — between exploration and appraisal?

Greg Hill: No, we don’t. Obviously, that’s going to depend upon success, right? So when we have an exploration success, we tend to then want to appraise that success. Just like we’re doing at Fangtooth, remember, Fangtooth 1 was 160 feet. Fangtooth Southeast was 200 feet. Now we have Lancetfish with 92 feet of pay, probably going to be a development. So we’re going to want to appraise around that greater Fangtooth area. So it’s really going to depend upon success as we go forward as to what the split is. Yes. Now regarding Yellowtail, look, it’s too early. I mean Yellowtail is running ahead of schedule right now. Looking good, but these are major projects. So I think just right now, in 2025 is the right way to think about it. And obviously, as we get further down, we’ll narrow the window on those dates.

Paul Cheng: Right. Thank you.

Operator: One moment for our next question. Our next question comes from Noel Parks with Tuohy Brothers. Your line is open.

Noel Parks : Hi. Good morning.

John Hess: Good morning.

Noel Parks : I wondered if I could get you to talk a little bit about your thinking on hedging policy. You laid in the put options. So that’s certainly interesting. And you have, of course, big production ramp-ups ahead with new development coming online from Guyana. So I guess just as you look ahead and over the years, we certainly have had periods of backwardation in the curve. I just wonder if you — maybe just as you’re looking ahead, say, to 2024, what’s on your radar screen? How — what’s your balance of thinking about downside protection versus realizing upside and so on?

John Rielly: Sure. So our philosophy on the hedging is we believe it is strategic importance, just like you said, from the downside protection. We view it as an insurance, and so what we do ensure we buy the insurance, and we use puts. Our strategy is to use puts to protect full downside, but leave the upside for investors. So again, that’s what we did this year. And you see we have 130,000 barrels a day this year, very comfortable with that level. We had 150,000 barrels a day last year. So I think you can think about that, let’s just say, approximately 150,000 barrel a day level as we go forward. And for your question like for 2024, you can assume we’ll put on insurance or hedges at that type of level as we move into 2024. And with the put options, the way we do that is we’ll look more to do that in the latter part of this year, right, because of the cost, the time value of the money on the put option.

So you typically would see us putting it on either towards the end of 2023 or early in 2024, like we did this year. And again, so we’re trying to get — obviously, within our putting the insurance on trying to be as opportunistic as possible, but we will eventually get that hedge on because we want that downside protection, really just as John Hess mentioned earlier.

Noel Parks : Great. Thanks. And I want to turn to on the regulatory side. You mentioned that a lot of you expecting government approvals this year. I’m just wondering, as you have keep teeing up each next development, is the approval process? Is it becoming pretty cut and dry at this point from — or even easier from one development to the next, or I was wondering, have you seen any shifts over time in terms of what the Guyana officials are scrutinizing sort of what their basis for approval is for each project?

John Hess: No. The Guyana government is very rigorous and overseeing the government and regulatory approvals. I think there’s a very good working relationship with ExxonMobil as operator and the government itself. I think the approval process is appropriate for both sides. And the fact of the matter is, hopefully, this week, we’ll be getting approval on Uaru, and I think that speaks volumes about the approval process. So it’s going appropriately in timing and also in depth of analysis by the government. The government obviously has their own priorities and the ExxonMobil as operator addresses those. So I’d say the approval process continues to be one that’s diligent and thoughtful for both sides.

Noel Parks: Perfect. Thanks a lot.

Operator: One moment for our next question. Our next question comes from Arun Jayaram with JPMorgan.

Arun Jayaram: Hey, good morning.

John Hess: Good morning, Arun.

Arun Jayaram: Greg, maybe for you. Good morning, John. Greg, I was wondering if you could give us kind of the path to first oil at Payara. I know the vessel landed in Guyana on April 11. And just give us a sense of the activities you kind of required to hit that early 4Q start-up and maybe a sense of what you’ve risked in terms of the guidance for Payara barrels in your updated guidance for volumes?

Greg Hill: Sorry, I turn. Yeah. Thanks, Arun. So first oil from Payara, remember now has been brought forward. So we were saying into the fourth quarter to early fourth quarter now. So we’ve already pulled it forward few months. In terms of what has to be done, remember, Payara is more extensive than Phase 2. So it’s got 30% more wells. It’s got 80% more surf the leads of Phase 2. And so it’s expected to take a bit longer to hook up and commission in Phase 2 is. But things are well on track. I think we’ve adequately risked things as well as the operator, ExxonMobil to confidently say at this point, early first quarter or early fourth quarter of this year, yeah.

Arun Jayaram: And what have you all included in terms of the updated guide for Payara?

Greg Hill: We haven’t included anything yet. So at the midyear, obviously, as we get closer to that first oil date, we’ll be updating our guidance.

Arun Jayaram: Okay. Great. And maybe just a follow-up also in Guyana. You’ve announced discoveries at Fangtooth, Fangtooth Southeast and Lancetfish. Greg, have you all done a DST yet at Fangtooth? And do you think there’s enough resource between those three discoveries to underwrite a seventh boat, or will you need some success at Bacher, and you mentioned, I think, Lancetfish on today’s call.

Greg Hill: No. I think about the Fangtooth area as a big hub. And as you mentioned, we do have both drill stand tests and core analysis for Fangtooth-1 and Fangtooth Southeast. Fangtooth 1 is underway. Fangtooth Southeast is planned for later in the year in terms of the DST. And then we also are planning an appraisal well at Lancetfish. So as you intimated when you add Bacher in and the other wells that we’re going to drill Lancetfish, obviously, there’s potential for a hub there, but we really need that DST data to figure out what the field development plan will be.

Arun Jayaram: Great. Thanks a lot.

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

Paul Cheng: Hey, thanks. This is for John Rielly. Just a quick follow-up. Related to Guyana, it looks like you guys have been booking some deferred tax on there. Can you give us a trajectory that — how that is going to shape up over the next several quarters or over the next several years? I assume that at some point, it will catch up maybe by 2026, 2027 and whether that will be on the ballpark correct? Thank you.

John Rielly: So you’re right, we are booking deferred tax in Guyana. Guyana has a 25% statutory rate. So we will be recording a 25% effective rate and it’s just similar. Let me just say to like the US, where the tax rules for depreciation, you can amortize the fixed assets quicker for the tax basis, so you get a higher deduction for tax purposes versus book. And so as a result of that, your current cash tax rate is lower than the $25 million, and therefore, we book deferred taxes. I would, Paul, just for guidance purposes, let’s just say, for the rest of this year, it can change obviously as we continue to bring on more and more boats, but use a similar deferred tax level that you see in the first quarter for Guyana.

Paul Cheng: John, how about for the next several years?

John Rielly: I don’t want to go in the next several years because every year when we add the capital and it changes the depreciable base, and you’re going over five years, so you get higher depreciation. So it’s difficult to provide that to you for the next couple of years. So we’ll try to guide you year-by-year as the boats come on.

Paul Cheng: Can we assume in this way that as you still ramping up more projects and from say, maybe two projects at the same time, go to three projects, and so your CapEx is rising. So as a result, we’re going to see the deferred tax continue to be a passive until that you sort of stabilizing your investment?

John Rielly: Yes. Yes, you can assume that.

Paul Cheng: Okay. Very good. Thank you.

Operator: There are no further questions at this time. Thank you very much. This concludes today’s conference. Thank you for your participation. You may now disconnect, and have a great day.