Hess Corporation

Good day, ladies and gentlemen, and welcome to the first quarter 2021 HESS Corporation conference call. My name is Katherine, 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. If any time you require operator assistance, please press star followed by the 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, Catherine. 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. As we have done in recent quarters, we will be posting transcripts of each speaker's prepared remarks on our website following their presentations. On the line with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Riley, Chief Financial Officer. I'll now turn the call over to John Hess.

Thank you, Jay. Welcome to our first quarter conference call. We hope you and your families are all well. Today, I will review our continued progress in executing our strategy. Then Greg Hill will discuss our operations, and John Riley will then review our financial performance. Let's begin with our strategy, which has been and continues to be to grow our resource base, have a low cost of supply, and sustain cash flow growth. By investing only in high return, low cost opportunities, we have built a differentiated portfolio that is balanced between short cycle and long cycle assets, with Guyana as our growth engine and the Bakken, Gulf of Mexico, and Southeast Asia as our cash engines. Guyana is positioned to become a significant cash engine as multiple phases of low cost oil developments come online. which we expect will drive our portfolio break-even Brent oil price below $40 per barrel by the middle of the decade. As our portfolio generates increasing free cash flow, we will first prioritize debt reduction and then cash returns to shareholders through dividend increases and opportunistic share repurchases. Even as we have seen oil prices recover since the beginning of this year, our priorities continue to be to preserve cash, preserve our operating capability, and preserve the long-term value of our assets. In terms of preserving cash, at the end of March, we had $1.86 billion of cash on the balance sheet, a $3.5 billion revolving credit facility, which is undrawn and was recently extended by one year to 2024, and no debt maturities until 2023. We have maintained a disciplined capital and exploratory budget for 2021 of $1.9 billion. More than 80% of this year's capital spend is allocated to Guyana, where our three sanctioned oil developments have a break-even oil price of between $25 and $35 per barrel, and to the Bakken, where we have a large inventory of future drilling locations that generate attractive financial returns at $50 per barrel WTI. To manage downside risks, in 2021, we have hedged 120,000 barrels of oil per day with $55 per barrel WTI put options and 30,000 barrels of oil per day with $60 per barrel Brent put options. To further optimize our portfolio and strengthen our cash and liquidity position, we recently announced two asset sales. In March, we entered into an agreement to sell our oil and gas interests in Denmark for a total consideration of $150 million, effective January 1, 2021. This transaction is expected to close in the third quarter. On April 8, we announced the sale of our Little Knife and Murphy Creek non-strategic acreage interests in the Bakken for a total consideration of $312 million, effective March 1, 2021. This acreage is located in the southernmost portion of our Bakken position and is connected to Hess Midstream infrastructure. The sale of this acreage, most of which we were not planning to drill before 2026, brings material value forward. This transaction is expected to close within the next few weeks. During the quarter, we also received $70 million in net proceeds from the public offering of a small portion of our Class A shares in Hess Midstream LP. The Bakken remains a core part of our portfolio. In February, as WTI oil prices moved above $50 per barrel, we added a second rig, which will allow us to sustain production and strong cash flow generation from our largest operated asset. In terms of preserving the long-term value of our assets, Guyana, with its low cost of supply and industry-leading financial returns, remains a top priority. On the Staybrook Block, where Hess has a 30% interest and ExxonMobil is the operator, we have made 18 significant discoveries to date with gross discovered recoverable resources of approximately 9 billion barrels of oil equivalent, and we continue to see multi-billion barrels of future exploration potential remaining. We have an active exploration and appraisal program this year on the Staybrook Block. Yesterday, we announced a discovery at the Waru 2 well, with encouraging results that further define the large aerial extent of this accumulation, underpinning a potential future oil development. In addition, drilling activities are underway for appraisal at the Long Tail III well and for exploration at the Coibi I prospect. Production from phase one ran at its full capacity of 120,000 gross barrels of oil per day during the first quarter. In mid-April, production was curtailed for several days after a minor leak was detected in the flash gas compressor discharge silencer. Production has since ramped back up and is expected to remain in the range of 100,000 to 110,000 gross barrels of oil per day until repairs to the discharge silencer are completed in approximately three months. Following this repair, production is expected to return two or above Lisa Destiny's nameplate capacity of 120,000 barrels of oil per day. The Lisa Phase II development is on track to achieve first oil in early 2022 with a capacity of 220,000 gross barrels of oil per day. Our third oil development on the Stabrook Block at the Piara Field is expected to achieve first oil in 2024, also with a capacity of 220,000 gross barrels of oil per day. Engineering work for Yellowtail, a fourth development on the Staybrook block, is underway with anticipated startup in 2025 pending government approvals and project sanctioning. We continue to see the potential for at least six FPSOs on the block by 2027 and longer term for up to 10 FPSOs to develop the discovered resources on the block. 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. We support the aim of the Paris Agreement and also a global ambition to achieve net zero emissions by 2050. As part of our sustainability commitment, our board and our senior leadership have set aggressive targets for greenhouse gas emissions reduction. In 2020, we significantly surpassed our five-year emission reduction targets reducing operated scope 1 and scope 2 greenhouse gas emissions intensity by approximately 40 percent and flaring intensity by approximately 60 percent compared to 2014 levels. We recently announced our new five-year emission reduction targets for 2025 which are to reduce operated scope 1 and scope 2 greenhouse gas emissions intensity by approximately 44%, and methane emissions intensity by approximately 50% from 2017 levels. In addition, we are investing in technological and scientific advances designed to reduce, capture, and store carbon emissions, including groundbreaking work being conducted by the Salk Institute to develop plants with larger root systems that, according to the Salk Institute, are capable of absorbing and storing potentially billions of tons of carbon per year from the atmosphere. In summary, our company is executing our strategy that will deliver increasing financial returns, visible and low-risk production growth, and accelerating cash flow growth well into this decade. As we generate increasing free cash flow, we will first prioritize debt reduction and then the return of capital to our shareholders through dividend increases and opportunistic share purchases. I will now turn the call over to Greg for an operational update.

Thanks, John. Overall, in the first quarter, we demonstrated strong execution and delivery across our portfolio. Company-wide net production averaged 315,000 barrels of oil equivalent per day, excluding Libya, which was in line with our guidance. The Bakken experienced extreme weather conditions and higher NGL prices during the quarter, both of which led to lower volumes. However, the higher NGL prices resulted in significantly higher net income and cash flows. Bakken net production in the first quarter averaged 158,000 barrels of oil equivalent per day, which was below our guidance of approximately 170,000 barrels of oil equivalent per day. Of this shortfall, approximately 8,000 barrels per day was due to the significant increase in NGL prices in the quarter. Much of our third-party gas processing from our operated production is done under percent of proceeds or POP contracts, where we charge a fixed fee for processing wet gas but take NGL barrels as payment instead of cash. Pop volumes from these contracts get reported as half net production. When NGL prices increase, as they did in the first quarter, it takes fewer barrels to cover our gas processing fees. Hence, our reported NGL production was reduced. But again, the higher NGL prices resulted in significantly higher earnings and cash flow. The other factor that affected Bakken production in the quarter was was related to winter storm Uri, which brought power outages and average wind chill temperatures of minus 34 degrees Fahrenheit for two weeks in February. These extreme temperatures were below safe operating conditions for our crews and led to higher non-productive time on our drilling rigs, significantly higher workover backlogs, and lower non-operated production. As discussed in our January earnings call, we added a second rig in the Bakken in February. In the first quarter, we drilled 11 wells and brought four new wells online. In the second quarter, we expect to drill approximately 15 wells and bring approximately 10 new wells online. And for the full year 2021, we expect to drill approximately 55 wells and to bring approximately 45 new wells online. Thanks to the continued application of lean technology, Our drilling and completion costs are expected to average approximately $5.8 million per well in 2021, which represents a 6.5% reduction from $6.2 million in 2020 and a 15% reduction from $6.8 million in 2019. For the second quarter, we forecast that our Bakken net production will average approximately 155,000 barrels of oil equivalent per day, and for the full year, 2021, between 155,000 and 160,000 barrels of oil equivalent per day. This forecast reflects the residual weather impacts, higher NGL strip prices, the sale of our non-strategic Bakken acreage, and the planned turnaround of the Tioga gas plant in the third quarter. We expect net production to build in the second half of the year and forecast a 2021 exit rate of between 170,000 and 175,000 barrels of oil equivalent per day. Moving to the offshore, in the Deepwater Gulf of Mexico, first quarter net production averaged 56,000 barrels of oil equivalent per day, reflecting strong operations following hurricane recovery in late 2020. In the second quarter, we forecast that Gulf of Mexico net production will average approximately 50,000 barrels of oil equivalent per day. For the full year 2021, we maintain our guidance for Gulf of Mexico net production to average approximately 45,000 barrels of oil equivalent per day, reflecting planned maintenance downtime and natural fuel declines. In the Gulf of Thailand, net production in the first quarter was 64,000 barrels of oil equivalent per day, as natural gas nominations continued to increase due to strong economic growth. Second quarter and full year 2021 net production are forecast to average approximately 60,000 barrels of oil equivalent per day. Now turning to Guyana, our discoveries and developments on the Staybrook block are world-class in every respect. And with Brent breakeven oil prices of between $25 and $35 per barrel, represent some of the lowest project breakeven oil prices in the industry. Production from Leesa Phase I averaged 121,000 gross barrels of oil per day, or 31,000 barrels of oil per day net to half in the first quarter. As John mentioned, Production at the Lease of Destiny was curtailed for several days following the detection of a minor gas leak in the flash gas compressor's discharge silencer on April 11. Production is currently averaging between 110,000 and 100,000 gross barrels of oil per day and is expected to stay in that range while repairs are made to the silencer. Upon reinstallation and restart of the flash gas compression system, expected in approximately three months, production is expected to return two or above nameplate capacity of 120,000 barrels of oil per day. For the second quarter, we now forecast net production to average between 20,000 and 25,000 barrels of oil per day, and our full-year 2021 net production to average approximately 30,000 barrels of oil per day. SBM Offshore has placed an order for an upgraded flash gas compression system, which is expected to be installed in the fourth quarter of 2021. Production optimization work is now planned in the fourth quarter, which will further increase the Leesa Destiny's progression capacity. I think it's important to note that the overall performance of the subsurface in Leesa 1 has been outstanding. We have seen very strong reservoir and well performance that has met or exceeded our expectations. Once the flash gas compressor is replaced, we are confident that we will see a significant improvement in uptime reliability. At LEASA phase two, the project is progressing to plan with about 90 percent of the overall work completed, and first oil remains on track for early 2022. The Leesa Unity FPSO, with a production capacity of 220,000 gross barrels of oil per day, is preparing to sail from the Keppel Yard in Singapore to Guyana mid-year. Our third development, Piara, is also progressing the plan, with about 38% of the overall work completed. The project will utilize the Leesa Prosperity FPSO, which will have the capacity to produce up to 220,000 gross barrels of oil per day. The FPSO hull is complete, and Topside's construction activities have commenced in Singapore. First oil remains on track for 2024. Front-end engineering and design work continues for the fourth development on the state roof block at Yellowtail. The operator expects to submit a plan of development to the government of Guyana in the second half of this year. Pending government approval and project sanctioning, the Yellowtail project is expected to achieve first oil in 2025. The Statebrook Block Expiration Program for the remainder of the year will focus on both Campanian, Leza-type reservoirs, and on the deeper Santonian reservoirs. In addition, Key appraisal activities will be targeted in the southeast portion of the Stabrook Block to inform future developments. In terms of drilling activity, as announced yesterday, the Wauru II well successfully appraised the Wauru-run discovery and also made an incremental discovery in deeper intervals. The well encountered approximately 120 feet of high-quality oil-bearing sandstone reservoirs and was drilled 6.8 miles from the discovery well, implying a potentially large aerial extent. The Standard Drill Max is currently appraising the longtail discovery. An additional appraisal is planned at Mako and in the turbid area, which will help define our fifth and sixth developments on the block. The Standard Caron has commenced exploration drilling at the Coeebee 1 well and an exploration well at Whiptail is planned to spud in May. Further exploration and appraisal activities are planned for the second half of 2021, with a total of approximately 12 wells to be drilled this year. The Noble Tom Madden, the Noble Bob Douglas, and the Noble Sam Croft, which recently joined the fleet, will be primarily focused on development drilling. Now, shifting back to production. Companywide second quarter net production is forecast to average between 290,000 and 295,000 barrels of oil equivalent per day. Full year 2021 net production is now also expected to average between 290,000 and 295,000 barrels of oil equivalent per day compared to our previous forecast of approximately 310,000 barrels of oil equivalent per day. This reduction reflects the following. Approximately 7,000 barrels of oil equivalent per day due to lower entitlements resulting from the increase in NGL strip prices. Again, this will be accretive overall to earnings and cash flow. Second factor is approximately 6,000 barrels of oil equivalent per day was related to the sale of our interest in Denmark and non-strategic acreage in North Dakota. for which we brought full value forward. The balance primarily reflects short-term weather impacts in the Bakken from which we expect to catch back up over the course of the year and again forecast a 2021 Bakken exit rate of between 170,000 and 175,000 barrels of oil equivalent per day. In closing, our team once again demonstrated strong execution and delivery across our asset base under challenging conditions. Our distinctive capabilities and world-class portfolio will enable us to deliver industry-leading performance and 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 2021 to the fourth quarter of 2020. We had net income of $252 million in the first quarter of 2021 compared to an adjusted net loss of $176 million, which excluded an after-tax gain of $79 million from an asset sale in the fourth quarter of 2020. Turning to E&P, E&P had net income of $308 million in the first quarter of 2021 compared to an adjusted net loss of $118 million in the previous quarter. The changes in the after-tax components of adjusted E&P results between the first quarter of 2021 and the fourth quarter of 2020 were as follows. Higher realized crude oil, NGL, and natural gas selling prices increased earnings by $192 million. Higher sales volumes increased earnings by $99 million. Lower DD&A expense increased earnings by $88 million. Lower cash costs increased earnings by $39 million. All other items increased earnings by $8 million for an overall increase in first quarter earnings of $426 million. Excluding the two VLCC cargo sales, our E&P sales volumes were over-lifted compared with production by approximately 300,000 barrels which improved after-tax results by approximately $10 million. The sales from the two VLCC cargoes increased net income by approximately $70 million in the quarter. The impact of higher NGL prices improved first-quarter earnings by approximately $55 million and reduced Bakken NGL volumes received under percentage of proceeds or POP contracts by 9,000 barrels of oil equivalent per day, compared with the fourth quarter of 2020. Turning to midstream, the midstream segment had net income of $75 million in the first quarter of 2021 compared to $62 million in the prior quarter. Midstream EBITDA before non-controlling interest amounted to $225 million in the first quarter of 2021 compared to $198 million in the previous quarter. In March, HES received net proceeds of $70 million from the public offering of 3,450,000 HES-owned Class A shares in HES Midstream. Now turning to our financial position, at quarter end, excluding Midstream, cash and cash equivalents were approximately $1.86 billion, and our total liquidity was $5.5 billion, including available committed credit facilities. while debt and finance lease obligations totaled $6.6 billion. Our fully undrawn $3.5 billion revolving credit facility is now committed through May 2024, following the amendment executed earlier this month to extend the maturity date by one year. In the first quarter of 2021, net cash provided by operating activities before changes in working capital was $815 million, compared with $532 million in the fourth quarter of 2020, primarily due to higher realized selling prices. In the first quarter, net cash provided from operating activities after changes in working capital was $591 million, compared with $486 million in the prior quarter. The sale of our Little Knife and Murphy Creek acreage in the Bakken for total consideration of $312 million is expected to close within the next few weeks, and the sale of our interest in Denmark for total consideration of $150 million is expected to close in the third quarter of this year. Now turning to guidance, our E&P cash costs were $9.81 per barrel of oil equivalent, including Libya, and $10.21 per barrel of oil equivalent excluding Libya in the first quarter of 2021. We project E&P cash costs excluding Libya to be in the range of $12 to $13 per barrel of oil equivalent for the second quarter, primarily reflecting the timing of maintenance and work overspend. Full-year E&P cash costs are expected to be in the range of $11 to $12 per barrel of oil equivalent, which is up from previous full-year guidance of $10.50 to $11.50 per barrel of oil equivalent due to the impact of updated production guidance. DD&A expense was $11.83 per barrel of oil equivalent including Libya and $12.36 per barrel of oil equivalent excluding Libya in the first quarter. DD&A expense excluding Libya is forecast to be in the range of $11.50 to $12.50 per barrel of oil equivalent for the second quarter. and full-year guidance of $12 to $13 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 $23.50 to $25.50 per barrel of oil equivalent for the second quarter and $23 to $25 per barrel of oil equivalent for the full year of 2021. Expiration expenses, excluding dry hole costs, are expected to be in the range of $40 to $45 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 $260 to $270 million for the second quarter, and full-year guidance of $1,090,000,000 to $1,115,000,000 is unchanged. E&P income tax expense excluding Libya is expected to be in the range of $25 to $30 million for the second quarter and $105 to $115 million for the full year, which is up from previous guidance of $80 to $90 million due to higher commodity prices. We expect non-cash option premium amortization will be approximately $65 million for the second quarter and approximately $245 million for the full year which is up from previous guidance of $205 million, reflecting additional premiums paid to increase the strike price on our crude oil hedging contracts. In the second quarter, we expect to sell two one-million barrel cargoes from Guyana, whereas we sold three one-million barrel cargoes in the first quarter, and we expect to sell five one-million barrel cargoes over the second half of the year. Our E&P capital and exploratory expenditures are expected to be approximately $500 million in the second quarter, and the full-year guidance of approximately $1.9 billion remains unchanged. For midstream, we anticipate net income attributable to HESS for the midstream segment to be in the range of $60 to $70 million for the second quarter, and the full-year guidance of $280 million to $290 million remains unchanged. For corporate, corporate expenses are estimated to be in the range of $30 to $35 million for the second quarter, and full-year guidance of $130 to $140 million is unchanged. Interest expense is estimated to be in the range of $95 to $100 million for the second quarter, and full-year guidance of $380 to $390 million is unchanged. 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 the 1 on your telephone. If your question has been answered or you would like to withdraw your question, press the pound key. Questions will be taken in the order received. Please press star 1 to begin. Your first question comes from Neil Mehta with Goldman Sachs. Your line is open.

Thanks, guys. Congrats on a good quarter. John, you talked about accelerating returns back to shareholders when you get net debt to EBITDA sub two times. It seems like between Lisa 2 and the forward curve, you're going to get there inside of one year. So how do you think about what to do with the excess cash and the optimal allocation of that to shareholders? Thanks, Neil. Yes, now we've had a strong first quarter, and we're seeing market conditions favorable for oil right now. It is still our plan, our strategy. As Phase 2 comes on, and it's a 220,000-barrel-a-day ship, so our entitlement there will significantly drive a cash flow inflection for us next year, and therefore our debt to EBITDA will begin to get under 2%. As we take that excess cash flow, then we have and pay down the term loan. So the first thing that we're going to do with excess cash flow is pay down the $1 billion term loan. Once we have that paid off and that increased EBITDA from phase two, we will be under two times debt to EBITDA for our balance sheet. And then we'll be in that position to start increasing returns to shareholders. And we've been consistent about it. What the first thing we'll do is increase our dividend. We'll start to increase the dividends and then As our cash flow continues to grow, you know, with Piara coming on and then Yellowtail, and as like we said, we expect now, you know, up to 10 FPSOs, we'll have a significant cash flow growth. We'll begin to do opportunistic share repurchases after the dividend increase. Clear. Thank you. And the follow-up is just about the long-term value of the Guyana resource. So much has been said about long-term risks to oil demand and I'm just curious, how do you think about the value of some of the projects and the FPSOs that come in post-2026 as electric vehicles start to accelerate and some of the competitive threats start to be there for traditional transportation demand? And does that change in any way the way you think about prosecuting this project, including the potential to monetize some of the acreage earlier in order to pull forward the value to mitigate some of the long-term demand risks?

Yeah, great question, Neil. Thank you. A couple points we'd like to make. You know, look, the world has two future challenges. One is how do we provide more energy supply, 20% more energy supply by 2040, and how do we get to net zero emissions by 2050? I think the best resource to provide insights into these challenges is the World Energy Outlook of the International Energy Agency. And under their sustainable development scenario, which says that even if all the pledges of the Paris Climate Accord were met, oil and gas would still be 46% of the energy mix in 2040. So it's not just about climate literacy. It's also about energy literacy. Oil and gas are still going to be needed 20 years out. the key to all of this because none of us can call oil price there's always going to be volatility and some other pressures you're talking about obviously you're going to be a factor in that the key will be having a low cost of supply and we believe that you know we're uniquely positioned in that regard with a growing resource a low cost of supply that positions our company with the differentiated portfolio of assets that we have with a growing resource that low cost of supply to deliver sustainable and industry-leading cash flow growth and financial returns for our shareholders. And when you talk about the longer term, I think it's important to realize that, you know, Guyana isn't as longer term. We're bringing forward almost every year, first in 2022 with Lisa 2, then in 2024 with Piara, then Yellowtail in 2025. The payouts are very quick and the returns are very high. So, you know, we are going to be bringing value forward, and you can look at a cadence most likely of bringing on one of these low-cost developments about every year thereafter. So we are bringing the value forward, and with low costs of supply, we think we're going to be uniquely positioned to provide sustainable and industry-leading cash flow growth.

Thanks, John.

Thank you. Our next question comes from Arun Jairam. with JP Morgan. Your line is open.

Yeah, good morning. Morning. Morning. Yeah, Greg, I was wondering if you could provide an update on the de-bottlenecking project at LISA Phase 1 and maybe discuss how the repair activities on the flash gas compressor impact the timing of that project. And also wanted to see if you could provide a little bit more color. You mentioned that SBM may be replacing the flash gas compressor, so maybe a little bit more color around that.

Yeah, sure. So let me take it in two pieces. So first, let's talk about the flash gas compressor. As John and I both mentioned in our opening remarks, we had a couple days of downtime associated with that where production was curtailed for a couple days. That flash gas compressor is now back in Houston being torn down, looked at, with the expectation that it will be restored you know, within the next three months, right? So once that happens, then we'll get back to that 120,000 barrels a day plus. So say that's July. Then the next increment, as you mentioned, is the debottlenecking project, which now is going to occur in the fourth quarter. And that will take leaves at phase one up another increment of production. Now they're still in final engineering phase of that, so I can't give you an exact number as to what that's going to be, but that will come in the fourth quarter. Also in the fourth quarter, Exxon is going to replace the existing flash gas compressor with some of the components that have been redesigned. So that shutdown in the fourth quarter, about 14 days, will accomplish those two things. It'll be the de-bottlenecking and also the installation of a a new redesigned flash gas compressor for Phase 1.

Great. And my follow-up is perhaps for John Reilly. John, how does the improvement in oil prices impact yours and Exxon's thinking on the purchase versus lease decision on the FPSO from a timing perspective?

Right now, Exxon is in discussions with SBM. They're having commercial discussions on the purchases of that. So it is ongoing. The oil price itself doesn't really have a factor in there, but they're going through these discussions. We expect to have that information later in the year, and we'll provide the guidance on the timing of the FPSO purchases when we get that information.

All right, fair enough. Thanks.

Thank you. Our next question comes from Doug Leggett with Bank of America. Your line is open. Thanks.

Good morning, everyone. Good morning, Doug. So, Greg, PIARA, 38% complete. At least on the whole, SEM is telling us 12 to 14 months is the standard sort of top-size installation for these standardized units. which would put you middle of next year for a completed FPS. So can you walk me through how you get from the middle of 2022 to 2024 for first oil when the boat's ready middle of next year?

Well, I mean, Doug, as you know, PIAR does have a very extensive drilling and surf program. In particular, the surf requires three – three open water seasons, if you will, to get all that subsea kit in. So, you know, look, PIAR is going well. There is still contingency built into the project, which I think is prudent at this point, given that significant amount of surf work that has to be done. But, you know, ExxonMobil is executing extremely well. You know, hopefully, you know, PIAR will come on earlier in 2024. So, But we'll see, Doug. There's a lot of work left to do yet.

Okay. We've got to get an in-person dinner, Greg. I'll take a small bet with you that we see a 23 in front of that at some point. Okay. My follow-up is on the exit rate in the bucket. How have you been able to lose 7,000 to 8,000 barrels a day of NGLs in the top contracts? But on the fourth quarter, you also guided to an exit rate of about 175. It's been reasonable even with the second rate. So can you just walk us through what's going better there to allow you to stick with the same guidance? I'll leave it there. Thanks.

John, do you want to answer the POP contract question, John Riley?

Yeah, sure. So first I can just start with the way the POP contracts work. The amount – For the full year in our guidance, you saw that it's about a 7,000 barrel a day reduction from original guidance. Now, it's a little higher in the first, second, and third, and a little bit lower in the fourth. So we're not hit with as high a number on that pop in the fourth quarter. But yet, there is still impact in that. And originally, we were guiding at that 175. Now we're at the 170 to 175. That pop does have impact to it. And I'll start with Greg, but the well performance is good. The wells that we're bringing on, we're seeing very good initial production. We're seeing better expectations. Now, you've got to remember, we had 12 on in the fourth quarter, only four in the first. We're just beginning now to pick up from the second rig, and that will really pick up in the third and fourth quarter. So we see the performance from those wells will pick that up and give us that ability to get back to that exit rate of 170 to 175. Greg, I don't know if there's anything else you want to add.

No, I think you nailed it, John.

Yeah. No, that's really helpful, guys. Thanks very much indeed. Thank you.

Thank you. Our next question comes from Janine Way with Barclays. Your line is open.

My first question is on Guyana. The latest well, the Waru II, you indicated it encountered newly identified intervals below the original discovery well. Can you provide just any color on the commerciality of those zones, and have you seen them elsewhere on the block, and do you plan to test them elsewhere this year?

Go ahead, Greg. Yeah, thanks, Janine. So, you know, again, you know, Waru II was a great result, right? We had high-quality oil sands, 120 feet. I think the most significant part about Wauru was that it was 6.8 miles from Wauru 1, which demonstrates a very large aerial extent for the Wauru Reservoir itself. As you said, we did discover a deeper zone. It's in the lower part of the Campanian, and that does have read-through to other parts of the block. but certainly the reason we didn't call it a 19th discovery is in this particular location, it's clearly not as significant as the other 18, right? But it does have some read-through to other parts of the block.

The key is that the appraisal is very encouraging results. You have excellent reservoir characteristics. You have high-quality oil. And given that Waru I versus Waru II is 6.8 miles away, you know, it shows the potential for large aerial extent of a highly prolific, high-quality reservoir.

Okay, gotcha. That's really helpful. Thank you. My second question is maybe just going back to the de-bottlenecking discussion and Arun's question. Lisa, on capacity, going up in Q4, we'll find out what to level later. But in terms of future potential opportunities, are there any bottlenecking opportunities built into the 220 nameplate capacities for the upcoming ships? It just seems like, you know, that's pretty standard for a lot of these major capital projects, including FPSOs. And at least when we do the math, if you do any kind of moderate to bottlenecking, it really pulls forward a lot of NAV there. So just wondering kind of the potential for that for the 220 ships.

Yeah, Janine, you know, I think you could assume that there would be, you know, de-bottlenecking potential on all those ships. You know, what typically happens is you will bring these facilities up to their nameplate, and then you gather a lot of dynamic data, and you really need that data. So you need fluids running through the facility at full capacity to determine – where are my pinch points, where are my bottlenecks, and what can I do to increase that capacity? And, you know, that's why you typically see these debottlenecking projects occur, you know, a year after, you know, that operating experience on the vessel, because the key piece of data that you have to have is the dynamic data of how is that vessel really operating under dynamic conditions. So, but I think you can expect every one of those will get the bottleneck above their nameplate in the future.

Great. Thank you very much.

Thank you. Our next question comes from Paul Chang with Scotiabank. Your line is open.

Hey, guys. Good morning. Good morning, Paul. I think several questions. First, John, the net debt to EBITDA are less than $2 billion. And at $60 plus, that doesn't seem to be a very conservative number. I presume it's just a near term. So what is the longer-term expectation? I mean, does the EBITDA change a lot due to the commodity prices?

Yes, you're right. I mean, let alone are EBITDAs going to change, one, from commodity prices, and two, as each FPSO comes on in Guyana, obviously our EBITDA is going to jump. with each ship coming online. So for us, what we did was set that two as kind of a max. And once we got to that net debt to EBITDA being under two, that's when we would start with the returns to shareholders. Now, we have no intention of increasing debt during that future time period because now we'll be generating free cash flow. So what we will have with each ship coming on as the EBITDA goes up that the EBITDA is going to drive down and is going to drive under one. So, look, we're going to have a very strong balance sheet and obviously be in a position for beginning to increase dividends first and then, because of that free cash flow position, doing opportunistic share repurchases.

Do you have a net debt target at all?

So, really short term, as we said, it is that two times. And then after that, it's just going to be a function of our free cash flow driving it. So quite frankly, I'd love to have that, keep it underneath one. And we have the portfolio to do it. We're just unique. Each FPSO coming on, I mean, I'll let you put your own Brent assumptions in there, but for the amount of production that we get, all Brent-based production, we're just going to have significant EBITDA growth there. And therefore, that's going to put our balance sheet in a very strong position. And so we'd like to keep that debt to EBITDA very low from that standpoint. And what we do with that excess cash, as John said earlier, is we'll return it to shareholders through dividend increases and share buybacks.

John, the first quarter working capital was a big use of cash. And in the second quarter, any kind of guidance that you can provide?

So let me just do the first quarter first, and I'm going to give the normal recurring, and there were two non-recurring things that offset each other. So the basic driver of the $220 million draw was an increase in receivables of $150 million, which we're happy to have. Obviously, oil prices going up, so our receivables went up from that standpoint. And then we did have – you saw the lower cash costs, the lower capital numbers – So we did have a reduction in payables of $70 million. So that $150 million and $70 million was the draw in working capital. We did have two non-recurring items. One was as we increased the strike prices on our hedges, so we had premiums paid there, but we also had the reduction in inventory from our VLCC sales. So they net against each other. So as you move into the second quarter with receivables, that should balance out now with the prices. Now, you know, if prices continue to go up, you'll still see that potential increase in receivables. And then we should be building, as we mentioned in our guidance, on capital. So I would expect the payables, you know, to be, let's just call flat. So not forecasting a draw, per se, in the second quarter.

Okay, thank you. Greg, if I could have a quick question on Barkin. I think in the past that the expectation is that you will get to about 200,000 bale per day and soil per toll at that for a number of years. So is that still the medium-term objective for Barkin? And then finally on these on the debuttoning, can you tell us where's the critical path or that what is the unit that In the LISA-1, your debottleneck allows you to get a higher production capacity from that ship.

Thank you. So let me take the second one first. So, you know, again, all the engineering is still underway, you know, on LISA Phase I optimization project or debottlenecking. There's nothing remarkable in it. It's piping changes, et cetera, just to eliminate, reduce the friction, basically, flowing through the facility on the top sides. So we can get more color as the engineering of that project gets done. Now, regarding the Bakken, again, the primary role of the Bakken in our portfolio is to be a cash engine. And so, as such, the decision to add any rigs in the Bakken is going to be driven by corporate returns and corporate cash flow needs. Now, if prices remain strong in the second half of this year, we're considering the addition of a third rig in the fourth quarter of 2021. And then, as you indicated, our medium-term or long-term objective, again, going to be driven by returns. and drove my corporate cash flow, would be to get the Bakken back to 200,000 barrels a day. That would probably require a fourth rig, and by doing so, at $60 WTI, the Bakken would be a billion-dollar-a-year free cash flow generator at 200,000 barrels a day. The other nice thing about the 200,000 barrels a day is it optimizes efficient use of the infrastructure that we have built up there. So it's sort of the ultimate sweet spot for the Bakken. But, again, whether we add that fourth rig or the third rig is going to be driven by returns and corporate cash flow needs because the role of the Bakken is to be a cash engine. Thank you.

Thank you. Our next caller. Our next question comes from Ryan Todd with Simmons Energy. Your line is open.

Good, thanks. Maybe a quick one on Guyana. As you think about your drilling program over the rest of the year and maybe into the first half of next year, what are the key issues that you're looking to address or the key questions that you're looking to answer over the next six to 12 months?

Greg? Sure, Ryan. So, you know, there's really three objectives here. of the expiration appraisal program this year with the three drilling rigs. You know, the first one is to appraise existing discoveries, and that's really to underpin the fifth and the sixth ship in Guyana. So, you know, Wauru was first cab off the rank, if you will. Longtail's next. Turbot will be after that. We'll also do Mako as well. So we want to get those understood with appraisal wells and some DSTs to really inform where is ship five and where is ship six going to go since Yellowtail is number four. The second objective is to continue to explore the Campanian to really fill out that patchwork quilt of prospectivity, if you will, between Turbott and Leesa. And you'll see in our investor pack there's a number of polygons there that we'd like to get drilled you know, this year as well. And then the third objective is can we get some deeper penetrations in the San Tonian? Certainly the San Tonian, you know, has the potential, you know, to be a very large addition to the recoverable resources in Guyana. Now, remind everyone we've had four penetrations coupled with Apache's results. you know, we see that as very positive. But we've got a lot more drilling to do to understand it, and that is another key objective this year is to get some more penetrations in that so we can begin to piece the puzzle together on the San Antonio.

Thanks, Greg. That was really helpful. And maybe, John, one for you on a higher-level issue. As we, you know, Hess has always been active on the ESG-related front, including efforts, as you talked about earlier, to reduce scope one and two emissions. As you step back and consider the ongoing energy transition and look a little further down the line, are there other roles in which you think HESS may be able to participate, or is the best use of your time and capital really just going to be bringing on low-cost-of-supply barrels?

Yes. No, our strategy remains to be focused on growing our resource. The oil resource is going to be needed in the next 20 years. The key is having a low cost of supply and putting ourselves in a position to generate sustainable and industry-leading cash flow growth. That's how we're going to maximize returns and value for our shareholders. Having said that, You know, climate change is real, the greatest scientific challenge of the 21st century. I'd recommend everybody to read Bill Gates' book, How Do We Avoid a Climate Disaster?, because it really talks about the technological challenges ahead of us, the innovation needed. There are no easy answers. The energy transition is going to take a long time, cost a lot of money, and need many, technological breakthroughs to be able to provide more energy to the world, as I talked about before, but also get on a track to net zero emissions, greenhouse gas emissions, by 2050. And, you know, one way that we are going to lead in that, be part of that, is obviously get our own carbon footprint down for Scope 1 and Scope 2 emissions. The targets that we've set for 2025 actually get us on a trajectory better and superior to the OGCI or the oil industry targets. standards that have been set, number one. And number two, you know, we are looking at groundbreaking research, and we think nature offers that opportunity to really make a difference in the work we're doing at the Salk Institute. We're very enthusiastic about where, you know, most people don't realize, but there's more carbon in the soil than there is in the atmosphere. And if we can figure out by supporting the great research at the Salk Institute to capture and store carbon in the soil at a much higher rate and a much higher density than currently is being done, that could be a potential game changer and contribute to getting us to net zero carbon emissions. So we're trying to play our role, but the first, second, and third priority is to maximize value for our shareholders.

Great. Thanks, John.

Thank you. Our next question comes from David Deckelbaum with Cowan. Your line is open.

Sorry about that. Thanks for squeezing me in, guys. I just wanted to just follow up on some of the Bakken conversations. You had a really attractive disposition earlier in the quarter. I think some of the You know, ideology behind that was the production wasn't hooked up to some of the HES midstream. Are there still remaining assets up there that fit similar profiles that would be amenable to pruning right now?

No. You know, the majority of our inventory, very high return locations, really underpinning, if you assumed a four-rig program, a 15-year drilling inventory, that's intact. This is the southernmost part that, quite frankly, the returns there weren't as attractive as our current inventory. It wasn't accretive and strategic to estimate streams. So I would say that was more of a one-off unique opportunity where we brought value forward. The rest of our acreage, we're very excited to have. And again, as Greg said before, the key role of the Bakken is to generate cash flow and free cash flow for the company, and we're going to be guided by returns in terms of what our rig program is.

I appreciate that. Just a follow-up for me. You talked earlier about sort of the optimal level of Bakken production and really how it becomes like a cash cow now, and that's really its role in the portfolio. How do you think about Gulf of Mexico along the same vein as as it relates to sort of maintaining volumes. Are there attractive exploration targets there or tiebacks that you're looking at beyond 21 that sort of make sense here, or how does the GOM fit in right now?

Yeah, Greg, I think it would be great if you would just talk about, you know, the role that the Deepwater Gulf plays in terms of being a cash engine as well, but it does have some growth opportunities.

Absolutely. So, you know, the Gulf of Mexico is like the Bakken. You know, it remains an important cash engine and a platform for, you know, higher return opportunities for half. So our minimum objective is to hold it flat. And we have an inventory of tieback opportunities that we believe we can hold it flat, you know, in the short term, three to four years probably. once we get back to work with some of the tieback opportunities. First of these high return opportunities, Lawn 06, which we're currently evaluating with Shell. And if we sanction that, it could quickly add production with expected first oil four months from the spud. And then we also have a large number of exploration blocks. So during the downturn, as you recall, When everybody was focused on the Permian, we stayed focused on the offshore, and we acquired 60 new leases in the Gulf, existing leases, so they won't be affected by the Biden moratorium, particularly on new leases. And in that, we see some very good hub class opportunities as well, both in the Miocene and the emerging Cretaceous four-foot play. So we'd like to get back to work on a hub class opportunity. The first one is likely going to be a well called Huron, which is a very large Miocene opportunity. So we've got the inventory to, as a minimum, hold it flat and then potentially even grow it. But like the Bakken, investment in the Gulf of Mexico is going to be a function of returns and cash flow needs of the corporation. But we certainly got the inventory to do it. and would like to get back to work as soon as we can.

Thanks for the update, guys.

Thank you. Our next question comes from Roger Reed with Wells Fargo. Your line is open.

Hey, good morning. Thanks. Good morning. Just two things, I guess, to follow up on kind of on the smaller side of things, at least the first one. But as you talked about the improvement in capex per well in the Bakken. I was just curious over the 19, 20, 21 period, is that truly apples to apples with the wells? In other words, you know, kind of similar completion methods and what you're seeing in terms of production per well. In other words, is there an efficiency above and beyond what you're seeing on the capex side? And then my other question was going to be on NOLs and the possibility of a change tax rate, how you think about that affecting utilization of those over time.

Yeah, Greg first and then John.

Yeah, sure. So on the Bakken, no, those wells, let's say the last three years, we've been drilling the same types of wells, you know, really for the past three years. So there's no differences in, say, like shorter laterals or anything like that. So that you know, the trajectory of well costs coming down is purely lean manufacturing and technology gains, you know, along the way. And so the wells that we are drilling this year, you know, have been the same. They've been the 1.2 million barrel recoverable IP180s of about 120, which was the same as last year. And I think, importantly, IRR is averaging nearly 90% at current oil prices. So, again, a great inventory. Got a lot of confidence on my team, you know, just as we showed with plug and perf or sliding sleeve. We're doing the same with plug and perf. Through lean manufacturing and technology, we just continue to drive those well costs down and improve productivity as well.

And then, Roger, on the tax policy, so it's a little early for me to be able to comment on them because from what's been released, there's more headlines and there's just not that much detail on these areas. Now, to your point, we do have a significant net operating loss carry forward, which will mitigate the effects of increased tax rates or changes in depreciation methods. So we'll just have to wait for more details.

All right. Thank you.

Thank you. Our next question comes from Bob Brackett with Bernstein Research. Your line is open.

Good morning, all. Thanks for taking my question at the end here. I had a question. As you return to the southeast part of the block and explore, it sounds like the targets are going to be those deeper penetrations in the Fantonian. Can you talk about, one, is there a double opportunity there? Are there still ways to drill wells to hit Campanian plus Santonian, and maybe a broader question about the future of exploration. Are there big, perhaps riskier prospects that you could target in future years that could be somewhat game changers that could move up the queue in terms of the development plan? Yeah, thanks, Bob.

Greg?

Yeah, so Bob, look, no, you know, the Santonian really underlies the entire Lisa complex, so I don't want to imply that you know, that the southeast portion of the block is the best area for the San Antonio. It really underlies, you know, all of the Campanian. Now, having said that, we need more penetrations, you know, to understand it. And we'll get a number of penetrations this year through both ways that you suggested. One is through deepening, deeper tails on Campanian exploration wells. but also some stand-alone santonian penetrations as well. So we'll get a good sense, you know, with the four that we have under our belt, coupled with Apache's results, you know, we're pretty excited about the santonian, but we've just got more drilling to do. But again, the aerial extent of the santonian reservoir system is as big or bigger than the Leza complex, so they're, you know, I wouldn't pick any areas being particularly the sweet spot yet.

Yeah, and Bob, to your other point, you know, we still see significant exploration prospectivity on this block as we drill more and get more seismic definition on drilling opportunities. Some of it's going to be Campanian. Some of it's going to be Santonian. Some of it's going to be further out. Obviously, we have this aggressive and active program this year. There's more to come. And, you know, our partner, ExxonMobil, I think in their investor day made it pretty clear that there's potential to double the discovered resource on the block, and we would stand by that in terms of the expiration upside that still remains. Thanks for that.

Thank you. Our next question comes from Vin Lavaglio with Meet Mizuho. Your line is open.

Hey, guys. Thanks for taking the question. First one on cash return. Different operators have kind of laid out different strategies, I think, based on business mix. But, you know, mainly centered around percentage of operating cash flow or percentage of excess cash flow generated back to shareholders. You guys are in a unique spot with Guyana. Just wondering if the asset kind of pushes you in one direction or the other as far as percentage of operating cash flow or percentage of free cash flow back to shareholders or maybe something entirely different. Thanks.

Yeah, those formulas are mainly for shale producers. That's more an assembly line of cash flow generation. You know, we have sustainable and industry-leading cash flow growth, so percentages I don't think are as relevant to us. But what we've been very clear on as we generate free cash is As John Riley said, the first priority is to pay down the term loan. And then after that, the majority of our free cash flow will go back as cash returns to shareholders, first increasing the dividend and then opportunistic share repurchases. So the word majority is the key word there.

Great. Thanks. And maybe just to Guyana quickly, you had outlined basically a one FPSO per year rate. kind of starting with PIARA in 2024. In the release, you did mention at least six FPSOs by 2027. Maybe reading a little bit too deep into it here, but just wondering if there's any hurdles, factors, or variables that we should be considering or that you guys are considering that could potentially accelerate the FPSO deployment schedule? longer term?

Yeah, look, our exploration appraisal program this year is to really help define what the fifth ship will be and potentially the sixth ship in terms of development. And I think the cadence of about one ship a year is the one we're aiming at in terms of design one, build many, being capital discipline, bringing value forward. ExxonMobil, as Greg said before, is doing an outstanding job of project management on building these ships and bringing them into theater. Obviously, debugging Lisa 1, but we'll benefit for Lisa 2 in terms of that. And, you know, it's basically this cadence of about one ship a year and The expiration appraisal program is to give definition to those future developments.

Thanks, guys. Appreciate it.

Thank you. Our next question comes from Monroe Helm with Borrow Hanley. Your line is open.

Thank you very much for getting me in the queue. Congratulations on continuing to execute on your game plan, which is a differentiated asset base, and the market is starting to recognize it. Thank you, Monroe. I had my questions that were kind of follow on to the questions on the San Antonio. Greg, can you be more specific about any of the wells that you've identified to drill in the first half of the year targeting the San Antonio? I was kind of curious along that line as to what the long-tail sidetracks are about.

Yeah, so there will be, Monroe, certainly in the early first part of the year, first half of the year. Long tail three will have a tail on it that will dip down into the santonian and whiptail will as well. So recall whiptail is kind of the next Campanian expiration prospect in the queue right after coibi. So both of those will have santonian tails on them. And then there will be other ones in the second half of the year. We're still trying to define the exact drilling order in the second half of the year, but those would be the next two.

And I think you said that there will be specific desantonian tests, is that correct?

There will be, yes, at least one that will be aimed at the desantonian itself.

My second question is, Exxon says that there's double the reserves for the exploration program. Does that include the desantonian?

Yes.

Okay. Thank you very much.

Thank you. Thank you.

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