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spk01: Good day, ladies and gentlemen, and welcome to the second quarter 2021 Hess Corporation conference call. My name is Liz, and I will be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question and answer session. If at any time you require operator assistance, please press star followed by zero, and we will be happy to assist you. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.
spk13: Thank you, Liz. Good morning, everyone, and thank you for participating in our second 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 and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the risk factor section of HESA's annual and quarterly reports filed with the SEC. Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John Hess, Chief Executive Officer, Greg Hill, Chief Operating Officer, and John Riley, Chief Financial Officer. In case there are any audio issues, we will be posting transcripts of each speaker's prepared remarks on www.hess.com following the presentation. I'll now turn the call over to John Hess.
spk10: Thank you, Jay. Good morning, everyone. Welcome to our second quarter conference call. Today I will review our continued progress in executing our strategy and our long-standing commitment to sustainability. Greg Hill will then discuss our operations, and John Riley will cover our financial results. Our strategy is to grow our resource base, have a low cost to supply, and sustained cash flow growth. Executing this strategy has positioned our company to deliver industry-leading cash flow growth over the next decade and has made our portfolio increasingly resilient in a low oil price environment. Our strategy aligns with the world's growing need for affordable, reliable, and cleaner energy that is necessary for human prosperity and global economic development. We recognize that climate change is the greatest scientific challenge of the 21st century and support the aim of the Paris Agreement and a global ambition to achieve net zero emissions by 2050. The world faces the dual challenge of needing 20% more energy by 2040 and reaching net zero carbon emissions by 2050. In the International Energy Agency's rigorous sustainable development scenario, which assumes that all pledges of the Paris Agreement are met, oil and gas will be 46% of the energy mix in 2040, compared with approximately 53% today. In the IEA's newest net-zero scenario, oil and gas will still be 29% of the energy mix in 2040. In either scenario, Oil and gas will be needed for decades to come and will require significantly more global investment over the next 10 years on an annual basis than the $300 billion spent last year. The key for our company is to have a low cost of supply. By investing only in high return, low cost opportunities, the best rocks for the best returns, we have built a differentiated and focused portfolio that is balanced between short-cycle and long-cycle assets. Guyana is our growth engine, and the Bakken, Gulf of Mexico, and Southeast Asia are our cash engines. Guyana is positioned to become a significant cash engine in the coming years 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. Based on the most recent third-party estimates, our cash flow is estimated to grow at a compound annual growth rate of 42% between 2020 and 2023, which is 75% above our peers and puts us in the top 5% of the S&P 500. With a line of sight for up to 10 FPSOs to develop the discovered resources in Guyana, this industry-leading cash flow growth rate is expected to continue through the end of the decade. Investors want durability and growth in cash flow. We have both. We are pleased to announce today that in July, we paid down $500 million of our $1 billion term loan maturing in March 2023. Depending upon market conditions, we plan to repay the remaining $500 million in 2022. This debt reduction combined with a startup of lease of phase two early next year is expected to drive our debt to EBITDAX ratio under two next year. Once this debt is paid off and our portfolio generates increasing free cash flow, we plan to return the majority to our shareholders, first through dividend increases and then opportunistic share repurchases. In addition, we announced this morning that Hess Midstream will buy back $750 million of its Class B units from its sponsors, Hess Corporation and Global Infrastructure Partners, to be completed in the third quarter. We expect to receive approximately $375 million in proceeds, and our ownership in Hess Midstream on a consolidated basis will be approximately 45% compared with 46% prior to the transactions. On April 30th, we completed the sale of our Little Knife and Murphy Creek non-strategic acreage interest in the Bakken for a total consideration of $312 million, effective March 1st, 2021. This acreage, most of which we were not planning to drill before 2026, was located in the southernmost portion of our Bakken position and was not connected as midstream infrastructure. The midstream transaction and the sale of the Little Knife and Murphy Creek acreage bring material value forward and further strengthen our cash and liquidity position. The Bakken remains a core part of our portfolio and our largest operated asset. We have a large inventory of future drilling locations that generate attractive financial returns at $50 per barrel WTI. In February, when WTO oil prices moved above $50 per barrel, we added a second rig. Given the continued strength in oil prices, we are now planning to add a third rig in the Bakken in September, which is expected to strengthen free cash flow generation in the years ahead. Key to our long-term strategy is Guyana, with its low cost of supply and industry-leading financial returns. We have an active exploration and appraisal program this year on the Staybrook block, where Hess has a 30% interest and ExxonMobil is the operator. We see the potential for at least six FBSOs on the block by 2027, and up to 10 FBSOs to develop the discovered resources on the block. And we continue to see multi-billion barrels of future exploration potential remaining. Earlier today, we announced a significant new oil discovery at Whiptail. The Whiptail No. 1 well encountered 246 feet of net pay, and the Whiptail No. 2 well, which is located 3 miles northeast of Whiptail 1, encountered 167 feet of net pay in high-quality oil-bearing sandstone reservoirs. Drilling continues at both wells to test deeper targets. The Whiptail discovery could form the basis for our future oil development in the southeast area of the Stabrook Block and will add to the previous recoverable resource estimate of approximately 9 billion barrels of oil equivalent. In June, we also announced the discovery at the Longtail 3 well, which encountered approximately 230 feet of net pay, including newly identified high-quality hydrocarbon-bearing reservoirs below the original Long Tail 1 discovery intervals. In addition, the successful Mako II well, together with the Waru II well, which encountered approximately 120 feet of high-quality oil-bearing sandstone reservoir, will potentially underpin a fifth oil development in the area east of the ELISA complex. In terms of Guyana developments, the Lisa Unity FPSO, with a gross capacity of 220,000 barrels of oil per day, is expected to sail from Singapore to Guyana in late August, and the Lisa 2 development is on track to achieve first oil in early 2022. Our third oil development on the Staybrook Block at the Piara Field is expected to achieve first oil in 2024, also with a gross capacity of 220,000 barrels of oil per day. Engineering work for our fourth development. on the Staybrook Block at Yellowtail, is underway with preliminary plans for a gross capacity in the range of 220,000 to 250,000 barrels of oil per day and anticipated startup in 2025, pending government approvals and project sanctioning. Our three sanctioned oil developments have a break-even Brent oil price of between $25 and $35 per barrel. And, according to a recent data from Wood Mackenzie, our Guyana developments are the highest margin, lowest carbon intensity oil and gas assets globally. Last week, we announced publication of our 24th Annual Sustainability Report, which details our environmental, social, and governance, or ESG, strategy and performance. In 2020, we significantly surpassed our five-year emission reduction targets, reducing Scope 1 and 2 operated greenhouse gas emissions intensity by 46% and flaring intensity by 59% compared to 2014 levels. Our five-year operated emission reduction targets for 2025, which are detailed in the sustainability report, exceed the 22% reduction in carbon intensity by 2030 in the International Energy Agency's sustainable development scenario, which is consistent with the Paris Agreement's ambition to hold the rise in global average temperature to well below 2 degrees centigrade. We are also contributing to groundbreaking research being done by the Salk Institute to develop plants with larger root systems that are capable of absorbing and storing potentially billions of tons of carbon per year from the atmosphere. We continue to be recognized as an industry leader for the quality of our ESG performance and disclosure. In May, Hess was named to the 100 Best Corporate Citizens list for the 14th consecutive year based upon an independent assessment by ISS ESG. And we were the only oil and gas company to earn a place on the 2021 list. In summary, oil and gas are going to be needed for decades to come. By continuing to successfully execute our strategy and achieve strong operational performance, our company is uniquely positioned to deliver industry-leading cash flow growth over the next decade. As our term loan is paid off and our portfolio generates increasing free cash flow, the majority will be returned to our shareholders, first through dividend increases and then opportunistic share repurchases. I will now turn the call over to Greg Hill for an operational update.
spk08: Thanks, John. In the second quarter, we continued to deliver strong operational performance. Company-wide net production averaged 307,000 barrels of oil equivalent per day, excluding Libya, above our guidance of 290,000 to 295,000 barrels of oil equivalent per day, driven by good performance across the portfolio. In the third quarter, we expect company-wide net production to average approximately 265,000 barrels of oil equivalent per day, excluding Libya, which reflects the Tioga gas plant turnaround in the Bakken and planned maintenance in the Gulf of Mexico and Southeast Asia. For full year 2021, we now forecast net production to average approximately 295,000 barrels of oil equivalent per day, excluding Libya, compared to our previous forecast of between 290,000 and 295,000 barrels of oil equivalent per day. So we're now forecasting to be at the top of the range. Turning to the Bakken, second quarter net production averaged 159,000 barrels of oil equivalent per day. This was above our guidance of approximately 155,000 barrels of oil equivalent per day, primarily reflecting increased gas capture, which has allowed us to drive flaring to under 5%, well below the state's 9% limit. For the third quarter, we expect Bakken net production to average approximately 145,000 barrels of oil equivalent per day, which reflects the planned 45-day maintenance turnaround and expansion tie-in at the Tioga gas plant. For the full year 2021, we maintain our Bakken net production forecast of 155,000 to 160,000 barrels of oil equivalent per day. In the second quarter, we drilled 17 wells and brought nine new wells online. In the third quarter, we expect to drill approximately 15 wells and to bring approximately 20 new wells online. And for the full year 2021, we now expect to drill approximately 65 wells and to bring approximately 50 new wells online. In terms of drilling and completion costs, although we have experienced some cost inflation, we are confident that we can offset the increases through technology and lean manufacturing efficiency gains and are therefore maintaining our full year average forecast of $5.8 million per well in 2021. We've been operating two rigs since February, but given the improvement in oil prices and our robust inventory of high return drilling locations, we plan to add a third rig in September. Moving to a three-rig program will allow us to grow cash flow and production, better optimize our in-basin infrastructure, and drive further reductions in our unit cash costs. Now moving to the offshore. In the deepwater Gulf of Mexico, second quarter net production averaged 52,000 barrels of oil equivalent per day compared to our guidance of approximately 50,000 barrels of oil equivalent per day. In the third quarter, we forecast Gulf of Mexico net production to average between 35,000 and 40,000 barrels of oil equivalent per day, reflecting planned maintenance downtime as well as some hurricane contingency. For the full year 2021, our forecast for Gulf of Mexico net production remains approximately 45,000 barrels of oil equivalent per day. In Southeast Asia, Net production in the second quarter was 66,000 barrels of oil equivalent per day, above our guidance of approximately 60,000 barrels of oil equivalent per day. Third quarter net production is forecast to average between 50,000 and 55,000 barrels of oil equivalent per day, reflecting planned maintenance at North Malay Basin and the JDA, as well as Phase III installation work at North Malay Basin. Full year 2021 net production is forecast to average approximately 60,000 barrels of oil equivalent per day. Now turning to Guyana. In the second quarter, gross production from Leesa Phase 1 averaged 101,000 barrels of oil per day, or 26,000 barrels of oil per day net to HESS. The repaired flash gas compression system has been installed on the Leesa Destiny FPSO and is under test. The operator is evaluating the test data to optimize performance and is safely managing production in the range of 120,000 to 125,000 barrels of oil per day. Replacement of the flash gas compression system with a modified design and production optimization work are planned for the fourth quarter, which will result in higher production capacity and reliability. Net production from LEASA Phase I is forecast to average approximately 30,000 barrels of oil per day in the third quarter and for the full year 2021. The LEASA Phase II development will utilize the 220,000 barrels of oil per day Unity FPSO, which is scheduled to sail away from Singapore at the end of August, and First Oil remains on track for early 2022. Turning to our third development at Piara, the Prosperity FPSO hull is complete and will enter the Keppel Yard in Singapore following the sale away of the Leesa Unity. Topside's fabrication is commenced at Dynamax, and development drilling began in June. The overall project is approximately 45 percent completed. The Prosperity will have a gross production capacity of 220,000 barrels of oil per day, and is on track to achieve first oil in 2024. As for our fourth development at Yellowtail, the joint venture anticipates submitting the plan of development to the government of Guyana in the fourth quarter, with first oil targeted for 2025, pending government approvals and project sanctioning. During the second quarter, the MACO2 appraisal well on the Staybrook Block confirmed the quality, thickness, and aerial extent of the reservoir. When integrated with the previously announced discovery at Wallaroo 2, the data supports a potential fifth development in the area east of the Leesa Complex. As John mentioned, this morning we announced a discovery at Whiptail, located approximately four miles southeast of Wallaroo 1. Drilling continues of both wells to test deeper targets. In terms of other drilling activity in the second half of 2021, after Whiptail 2, the Noble Don Taylor will drill the Pinktail 1 exploration well, which is located five miles southeast of Yellowtail 1, followed by the Triple Tail 2 appraisal well, located five miles south of Triple Tail 1. The Noble Tom Madden will spud the Catabac I Expiration Well, located 4.5 miles southeast of the Turbot I discovery in early August. Then in the fourth quarter, we will drill our first dedicated test of the deep potential at the Fangtooth Prospect, located 9 miles northwest of Leesa I. In the third quarter, the Noble Sam Croft will drill the Turbot II Appraisal Well then transition to development drilling operations for the remainder of the year. The Stena Caron will conduct a series of appraisal drill stem tests at Wallbrew 1, then Mako 2, and then Longtail 2. In closing, we continue to deliver strong operational performance across our portfolio. Our offshore assets are generating strong free cash flow, the Bakken is on a capital-efficient growth trajectory, and Guyana keeps getting bigger and better. all of which positions us to deliver industry-leading returns, material cash flow generation, and significant shareholder value. I will now turn the call over to John Reilly.
spk06: Thanks, Greg. In my remarks today, I will compare results from the second quarter of 2021 to the first quarter of 2021. Adjusted net income was $74 million in the second quarter of 2021, compared to net income of $252 million in the first quarter of 2021. Turning to E&P, E&P adjusted net income was $122 million in the second quarter of 2021, compared to net income of $308 million in the previous quarter. The changes in the after-tax components of adjusted E&P results between the second quarter and first quarter of 2021 were as follows. Lower sales volumes reduced earnings by $126 million. Higher cash costs reduced earnings by $48 million. Higher expiration expenses reduced earnings by $10 million. All other items reduced earnings by $2 million for an overall decrease in second quarter earnings of $186 million. Second quarter sales volumes were lower primarily due to Guyana having two 1 million barrel liftings of oil compared with three 1 million barrel liftings in the first quarter. And first quarter sales volumes included non-recurring sales of two VLCC cargoes, totaling 4.2 million barrels of Bakken crude oil, which contributed approximately $70 million of net income. In the second quarter, our E&P sales volumes were underlifted compared with production by approximately 785,000 barrels, which reduced our after-tax results by approximately $18 million. Cash costs for the second quarter came in at the lower end of guidance and reflect higher plan maintenance and work-over activity than the first quarter. In June, the U.S. Bankruptcy Court approved a bankruptcy plan for Fieldwood Energy, which includes transferring abandonment obligations of Fieldwood to predecessors in title of certain of its assets, who are jointly and severally liable for the obligations. As a result of the bankruptcy, Hess, as one of the predecessors in title in seven shallow water West Delta 7986 leases held by Fieldwood, is responsible for the abandonment of the facilities on the leases. Second quarter E&P results include an after-tax charge of $147 million, representing the estimated gross abandonment obligation for West Delta 7986 without taking into account potential recoveries from other previous owners. Within the next nine months, we expect to receive an order from the regulator requiring us, along with other predecessors entitled, to decommission the facilities. The timing of these decommissioning activities will be discussed and agreed upon with the regulator, and we anticipate the costs will be incurred over the next several years. Turning to midstream, the midstream segment had net income of $76 million in the second quarter of 2021, compared to $75 million in the prior quarter. Midstream EBITDA, before non-controlling interest, amounted to $229 million in the second quarter of 2021, compared to $225 million in the previous quarter. Now turning to our financial position, at quarter end, excluding midstream, cash and cash equivalents were $2.42 billion, which includes receipt of net proceeds of $297 million from the sale of our Little Knife and Murphy Creek acreage in the Bakken. Total liquidity was $6.1 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 committed through May 2024, and we have no material near-term debt maturities aside from the $1 billion term loan, which matures in March 2023. In July, we were paid $500 million of the term loan. Earlier today, HES Midstream announced an agreement to repurchase approximately 31 million Class B units of HES Midstream held by GIP and us for approximately $750 million. We expect to receive net proceeds of approximately $375 million from the sale in the third quarter. In addition, we expect to receive proceeds in the third quarter from the sale of our interest in Denmark for total consideration of $150 million with an effective date of January 1st, 2021. In the second quarter of 2021, net cash provided by operating activities before changes in working capital was $659 million compared with $815 million in the first quarter, primarily due to lower sales volumes. In the second quarter, Net cash provided by operating activities after changes in working capital was $785 million, compared with $591 million in the first quarter. Changes in operating assets and liabilities during the second quarter of 2021 increased cash flow from operating activities by $126 million, primarily driven by an increase in payables that we expect to reverse in the third quarter. Now turning to guidance. First for E&P, our E&P cash costs were $11.63 per barrel of oil equivalent, including Libya, and $12.16 per barrel of oil equivalent, excluding Libya, in the second quarter of 2021. We project E&P cash costs, excluding Libya, to be in the range of $13 to $14 per barrel of oil equivalent for the third quarter, which reflects the impact of lower production volumes resulting from the Tioga gas plant turnaround. Full-year cash cost guidance of $11 to $12 per barrel of oil equivalent remains unchanged. DD&A expense was $11.55 per barrel of oil equivalent, including Libya, and $12.13 per barrel of oil equivalent, excluding Libya, in the second quarter. DD&A expense, excluding Libya, is forecast to be in the range of $12 to $13 per barrel of oil equivalent for the third quarter, and full year guidance of $12 to $13 per barrel of oil equivalent remains unchanged. This results in projected total E&P unit operating costs excluding Libya to be in the range of $25 to $27 per barrel of oil equivalent for the third 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 third quarter and full-year guidance is expected to be in the range of $160 to $170 million, which is down from previous guidance of $170 to $180 million. The midstream tariff is projected to be in the range of $265 to $275 million for the third quarter. and full-year guidance is projected to be in the range of $1,080,000,000 to $1,100,000,000, which is down from the previous guidance of $1,090,000,000 to $1,115,000,000. E&P income tax expense, excluding Libya, is expected to be in the range of $35 to $40 million for the third quarter, and full-year guidance is expected to be in the range of $125 to $135 million, which is updated from the previous guidance of $105 to $115 million, reflecting higher commodity prices. We expect non-cash option premium amortization will be approximately $65 million for the third quarter, and full-year guidance of approximately $245 million remains unchanged. During the third quarter, we expect to sell three one-million-barrel cargos of oil from Guyana. Our E&P capital and exploratory expenditures are expected to be approximately $575 million in the third quarter. Full-year guidance, which now includes increasing drilling rigs in the Bakken to three from two in September, remains unchanged from prior guidance at approximately $1.9 billion. Turning to midstream. We anticipate net income attributable to HES from the midstream segment to be in the range of $50 to $60 million for the third quarter, and full-year guidance is projected to be in the range of $275 to $285 million, which is down from the previous guidance of $280 to $290 million. Turning to corporate, corporate expenses are estimated to be in the range of $30 to $35 million for the third quarter, and full-year guidance of $130 to $140 million remains unchanged. Interest expense is estimated to be in the range of $95 to $100 million for the third quarter and approximately $380 million for the full year, which is at the lower end of our previous guidance of $380 to $390 million, reflecting the $500 million reduction in the term loan. This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.
spk01: Ladies and gentlemen, if you have a question, please press star followed by 1 on your phone. If your question has been answered or you would like to withdraw your question, press pound. Questions will be taken in the order received. Please press star 1 to begin. Your first question comes from the line of Ryan Todd with Piper Sandler.
spk11: Good morning. Maybe starting off on WPTEL, congratulations on the great results of both WPTEL 1 and 2. Thank you. How do you think, maybe it's a little early to say, but how do you think about ultimate potential resource size, reservoir, and oil quality, and how it maybe stacks up against other future resources to be developed and where it could land in the queue?
spk10: Yeah, great question, Ryan, and thank you. You know, look, Whiptail drilling activities are still underway. We're going to be drilling in both wells to some deeper targets. Whiptail adds to our queue of high-value potential oil developments in Guyana. Waru and Mako, as Greg talked about, have the potential to be our fifth FPSO. Whiptail has the potential to be another oil development, and since evaluations Work is still going underway. It's a little premature to talk about resource size, but definitely what we're seeing is a foundation for potentially another oil development with Whiptail. And then, you know, to remind everybody, we still have a very active exploration and appraisal program on the Statebrook block the remainder of this year, which should provide even more definition for future development investment opportunities. The queue of high-value potential oil developments is growing, and we're going to optimize it as we continue to get more data and well results to further get clarity on what the queue will be.
spk08: And, Ryan, the quality of the reservoirs in Whiptail are outstanding. All right.
spk11: Thanks, John and Greg. Maybe a follow-up on CapEx. Your prior guidance for 2021 Bakken CapEx was $450 million. Is that still the same with the addition of the third rig in September, or was the possibility of a third rig already built in there? And you've been running low on CapEx, obviously, in the first half of the year, but activity is accelerating in the second half. Is there a potential for maybe downward pressure on CapEx on a full-year basis, or – is kind of the trend upward in the second half likely to – I guess are things trending in line with where you would have expected?
spk06: Yes, so from the Bakken standpoint, no, we did not have third rig in our initial guidance of the $450 million for the year. So that third rig is adding to the Bakken capital, so we'll go up from that $450 million. But like you've been saying, we have been running under for the first half, and where it is primarily right now, we're underspending in Guyana. So that pretty much the add, you know, from September to December for the one rig in the Bakken is being offset by a little lower spend in Guyana. As for the $1.9 billion, we do, as you said, expect a ramp-up. It's normal for us in the Bakken, you know, when you get into the summer season, building infrastructure, pads, things like that. So we do get a pickup on capital there. Same thing for our work in Southeast Asia is more ramping up. Greg had mentioned the Phase III installation that's going on. So, you know, I do expect to be spending right around that $1.9 billion, and we'll get that pickup. But, again, we have been a little bit lower, and that's why we can add that Bakken rig and stay at $1.9 billion.
spk12: Great. Thank you.
spk06: Thank you.
spk01: Our next question comes from Arun Jayaram with J.P. Morgan.
spk03: Yeah, good morning. My first question is on LESA Phase II. I know the design is a 220 KBD, but I was wondering if the HESS Exxon consortium is applying some of the learnings from the LESA phase one debottle necking project on this ship, and where could initial predictive capacity be, as well as I wanted to get your timeline to maybe first oil if the boat is sailing from Singapore at the end of August.
spk10: Thanks, Arun. Greg?
spk08: Yeah, sure, Arun. So, we are on track for first oil in early 2022. So, no change to that first oil date that we talked about before. In regards to debodimenting, look, my experience with these FPSOs is, yes, there will be some additional capacity that can be, you know, wrung out of the vessel, but The sequence is important though, so the first thing you do is you get it out there, spin it up, run it at full operating conditions, then and only then after you get that dynamic data can you understand where your potential pinpoints or bottlenecks are. And so that's why typically these optimization projects don't come until I'll say the first year of operation. But I think, you know, 15% to 20% is not atypical. It will vary boat by boat depending on the dynamic conditions, but I would think that you could get some additional upside from phase two and phase three, you know, and beyond.
spk03: Great. My follow-up is for John Hess. John, I wanted to see if you could help us think about the order of operations here regarding, you know, additional cash return to shareholders and and maybe outline paying off the term loan, maybe the timing of step two if the strip holds, and when we could see HEST and the board kind of move on the dividend.
spk10: Yeah, look, once we pay the $500 million off, which we're intending to do next year from the term loan, thereafter, as a function of oil price, and we get visibility on free cash flow generation, the next priority is going to be returning the majority of that free cash flow to our shareholders. And the first priority in that will be to increase our base dividend. So, you know, this is something we've talked about with our board. We're very watchful about it, but we've got to take it a step at a time. But that will be the sequence of events. Pay the other $500 million off. We're estimating to do that next year, depending upon market conditions. And then once after that, once we start to have visibility on free cash flow and market conditions for oil and the financial markets are supportive, the next step will be strengthening our base dividend.
spk03: All right. Thanks, John. Okay.
spk01: Your next question comes from David Degelbaum with Cowen.
spk05: Morning, guys, and thanks for taking the questions today.
spk07: Thank you.
spk05: I just wanted to just touch on the Bakken again. With the addition of the third rig, could you perhaps revisit guidance for where an exit rate should be at the end of this year? And then should we be thinking about the addition of a fourth rig? I just wanted that in the context of what the current in-house view is of the truly optimized program there in terms of activity.
spk10: John, you wanted to take the exit rate, and then Greg, any color you'd like to provide as well.
spk06: Sure. So from the Bakken exit rate standpoint, the addition of the third rig when we're starting in September really is not going to add any wells in for production this year. And what we had said in the prior quarter was that we were exiting somewhere at the 170 to 175 type level as we ended the year. Now, what we are seeing is higher propane prices than we saw back in April, which we like, right? What we see from the NGL price is actually to increase our cash flow in the third quarter, maybe $35 to $40 million based on these higher propane prices. But with those higher propane prices, if you remember, that means we get less volumes under our percentage of proceeds contracts or our POP contracts. So right now, based on what we're seeing on the propane prices, I'd say the exit rate overall will be in the $165 to $170 range. And then, Greg, I'll hand it over to you for the fourth rate.
spk08: Yeah, so I think just one couple more comments on the third rig. So with that third rig, you know, we'll drill 10 more wells. So that's why we increased our drilling well count from 55 to 65. And then we'll also bring five more wells online with that third rig. So that's why we raised the wells online count from 45 to 50. But as John said, those wells come on right at the end of the year. So the impact of that will be seen in 2022's volumes. The fourth rig, you know, as we've always talked about, you know, the primary role of the Bakken in our portfolio is to be a cash engine. So that's its number one role. So any decision to add any rigs in the Bakken is going to be driven by returns and corporate cash flow needs. Now, having said that, assuming oil prices stay high, you know, into next year, then we'd consider adding a fourth rig to at the end of next year. Why is it at the end? Because you build all your locations in the summertime. And then by doing so, that would allow us to take Bakken production up to around 200,000 barrels a day. And that level really optimizes our in-basin infrastructure. But again, that's going to be a function of oil price, a function of corporate cash flow needs. You know, how much cash do we need the Bakken to deliver for the corporation? That's going to be the primary driver of whether or not we add that fourth rig or not. I will say the fourth rig would be the last rig, so the highest we would go is four rigs, and we could maintain that 200,000 barrels a day with four rigs for nearly a decade, given the extensive inventory of high-return wells that we have.
spk05: Thank you guys. You seem well prepared for that question. Um, appreciate the color. Um, my followup is just on quickly on, on Lydia. Um, you know, you've seen obviously, you know, the end of the forest majority, you've seen production kind of pick up there. I know you guys guide ex Libya, but can you kind of revisit the productive capacity of that asset and your, your view kind of the rest of the year and then just broadly speaking where that sits in your portfolio?
spk10: Yeah. Libya, obviously, it generates some cash for us. You know, it has been running at fairly stable levels, and we would estimate those levels would continue at the current rate. And, you know, it really is a function of political security stability in the country, which has increased. And so we would intend that Libya would continue at the pace of cash generation that it's at now in the future.
spk05: Thank you, guys.
spk01: Your next question comes from Roger Reed with Wells Fargo.
spk09: Thanks. Good morning.
spk10: Good morning, Roger.
spk09: Just one question to follow up on just from the comments earlier about, you know, well-cost staying flat in the Bakken. But as you step back and look at cost inflation almost anywhere, I know you're relatively familiar silent in the Gulf of Mexico today, but there'll be expectations for next year. And then as we think about building the FPSOs or any sort of, I guess, supply chain issues that may be affecting anything as we think about the next FPSO2 and FPSO3 as we think about the timing in Guyana.
spk10: Yeah, Greg, why don't you please handle the cost inflation question that he's asking. One, maybe we cover the onshore focusing on the Bakken, and two, the offshore.
spk08: Yeah, sure. So, you know, let's talk about the onshore first because it's the easiest. Yes, as I said in my opening remarks, we are seeing some minor inflation in the Bakken. You know, the first half of the year was all tubulars. However, recall, we pre-bought. all of our tubulars for the program this year, so we're covered on that. Commodity-based chemicals obviously have gone up, but it really doesn't matter because we're able to cover that through technology and lean manufacturing gains, and that's why we held our well-cost forecast for the year still at 5.8, even though we're feeling some, you know, single-digit kind of levels of inflation. Now, if I turn to the offshore, You know, yes, industry's seeing cost increases there as well. You know, day rates on deepwater rigs are up modestly. They're nowhere near what they were in the halcyon days of, say, five years ago. But remember, almost all of our offshore investment is in Guyana. And we operate under EPC contracts there, so that largely insulates us from cost increases after the contract's signed. And then I've got to say, ExxonMobil is doing an extraordinary job of utilizing this design one, build many strategy to deliver a large amount of efficiencies from that project. So certainly now and in the very near term, I wouldn't expect any cost issues there. And, of course, because of the PSC, if your costs do creep up, that's all covered under cost recovery.
spk09: That's helpful. Thanks. Thanks. And then congratulations on the discoveries certainly that have been announced today and recently. I was just curious, some of the other exploration opportunities you have out there as we think about other blocks inside of Guyana but also over in Suriname. Any updates there?
spk10: Well, the majority of our drilling is going to be on the Staybrook block, and I think Greg gave a pretty good roadmap for what our drilling the rest of the year is going to be. It's going to be a comment of expiration and appraisal. I think, Greg, the only other thing to talk about is CERNAM, probably Block 42, because we do have some drilling planned there next year.
spk08: Yes, we do. So planning is underway on Block 42. for a second exploration well in the first half of 2022. You know, obviously the Apache wells are encouraging for our acreage there that's adjacent in 42. And we see the acreage as a potential play extension also from the Staybrook block. So, you know, we're the ones that have access to not only the Staybrook data, but also the data in Suriname. So we can couple those two together and really understand how the geology lays out there. And that's what makes us excited about Block 42. We also have an interest in Block 59, as you know, just outboard of 42. ExxonMobil has completed the 2D seismic survey on the block there. The data has been analyzed and assessed. And so the joint venture is now planning a very targeted 3D survey over some interesting prospects we see on that as well. But drilling there would not begin to occur until probably 23 at the earliest. Thank you.
spk01: Your next question comes from Paul Chang with Scotiabank.
spk15: Hey, guys. Good morning. Morning, Paul. Morning, Bob. John, you guys are going to generate a fair amount of the free cash, and you're going to pay down the term debt next year. But longer term, do you have a net debt target how much debt do you really want to be sitting on your bond sheet at all?
spk06: Thanks, Paul. So our target, and what I always say it's a maximum target, is a two-times debt-to-EBITDAX target. So as you said, when we pay off this term loan next year and we have Phase 2 coming online, we're going to drive under that two times. So there's And what I expect here, because I think it was we mentioned earlier, we really don't have any material near-term debt maturity. So what we'll do is we'll pay off that term loan. We have small amounts in 2024, and it's not until 2027 that we have our next big maturity. So we'll just pay off the small maturities as we have, and we'll continue to let our EBITDAX grow. Basically, you know, you're going to get Phase 2, then Piara, then Yellowtail, then Waro2. So we're going to have significant growth in EBITDA, and our balance sheet is just going to get stronger and stronger from that standpoint. What I would say is we'd hold that absolute debt level, you know, flat and decrease it for the maturities that come about. And then, as John mentioned, we're going to start driving, you know, significant free cash flow generation. And once that term loan is paid off, we'll start with dividend increases, and then we'll move on to the opportunistic share purchases.
spk15: Hey, John, some of your peers that when they're talking about, say, two times EBITDA or that one time or less than one time, They also identify with the parameter that under what commodity price they are using, not necessarily using the current price. So do you guys just look at what is the current price, your EBITDA, or you also target at a lower price, the maximum two times?
spk06: No, we look at even lower prices. What I would say is that that target is there for us no matter what the commodity price is. And Look, we always say this, as the additional FPSOs come on, as John said, these very low-cost developments come on. our margins and our cash flow just continues to improve. So even at lower commodity prices, when we start getting Piari, Yellowtail, Waru, Mako online, we're going to have significant free cash flow, and the balance sheet is going to be very strong. So our target doesn't vary based on commodity prices, and we like to say that with these episodes coming on, we can win in any commodity price environment.
spk15: and John I think John has said that the first priority of the excess free cash after the term loan payoff is increasing the dividend is there any kind of parameter you can share in terms of you will set the dividend longer term based on say 10% of a certain cash flow from operation based on certain or any kind of a permit that you can share, a matrix you can share, so we can have some better understanding of what is the trajectory.
spk06: Sure. What we've been saying right now, and look, we'll give guidance as we get into this free cash flow generation, is that we want to have a dividend that's better than the S&P 500 yield. And why? Because obviously the oil and gas business is a little riskier and more volatile due to commodity prices. So we want to set that at a level that gives us a better yield. And we're going to be in that position, again, as I mentioned with these FPSOs coming on, that we can set that, have a better yield, and withstand lower commodity prices. So we'll test it at lower commodity prices. But, again, due to the uniqueness of the Guyana cash flows that will be coming in, we can do that. So that's the initial guidance I would look at is that we're going to have our yield better than that S&P 500.
spk15: Final question. I think this is for Greg. Greg, we look at your full-year production guidance, which implies the second half is about 280, and you say the third quarter is about 265. So that means that the fourth quarter is about 300. Is that a bit conservative on that number?
spk08: Well, you know, first of all, Paul, it's still early in the year, so we've got a lot of activity going on. We've got Tioga Turnaround. maintenance in the Gulf of Mexico, maintenance in Southeast Asia, and also some shutdowns for Phase 3 in North Malay Basin. Plus, we did dial in, you know, a fair amount of hurricane contingency this year in the Gulf, just based upon last year's experience, but also what the weather forecasters are saying this year. So, you know, we'll be able to update that, you know, on the quarterly call next time. I hope you're right. I hope it is conservative, but again, we have a fair amount of contingency in there for the work that we are doing, you know, and the hurricanes that are anticipated in the Gulf. So let's just see how it plays out.
spk15: Maybe let me ask in this way, Greg. In the fourth quarter, do you have any meaningful turnaround or maintenance shutdown activities? Yes.
spk08: We do have some in the fourth quarter, yes, and some of those are in Southeast Asia, and we also have a turnaround in baldpate in the Gulf of Mexico during the fourth quarter as well. But the hurricane contingency really rolls through both quarters.
spk15: All right. Thank you. Thank you.
spk01: Your next question comes from Doug Leggett with Bank of America.
spk14: Thanks. Good morning, everyone. I'll just speak to two questions, if that's okay. But let me see if I can get them both in. Greg, I'm going to have another go at Whiptail. I seem to recall in our prior conversations that you had built up quite a picture of how large this prospect could be. Now you've got two of the thickest sands three miles apart. I'm out of turn saying that this could be more than one development phase on Whiptail.
spk08: Go ahead, Greg. Look, I think it's early days to be saying that, Doug. You know, one of the reasons we drilled the wells concurrently is because we did have good seismic response, as you intimated, on Whiptail. We were well calibrated with that because, of course, it was sandwiched between Yellowtail and Wallaroo. And so by drilling both of these wells concurrently, obviously we accelerated the evaluation and appraisal of this highly prospective area. We've got more appraisal work to do and some deepening to do in and around this area, but we're very pleased with the results. But I think it's just too early to speculate on you know, is this big enough standalone by itself or, you know, or what? So just give us some time to evaluate the well results.
spk10: Yeah, Doug, great question.
spk08: We're very pleased.
spk10: You know, we're still drilling, still evaluating the results, but certainly we're very encouraged that this could underpin on its own a future oil development. The foundation's there. More work needs to be done to get that definition, but it certainly has the potential to provide a foundation for future oil development. You know, you also got to remember on Yellowtail, as we got more evaluation work in, that obviously turned out to be a much bigger resource, which is why the ship for Yellowtail is being sized between 220,000 and 250,000 barrels a day, which is bigger than the two ships that preceded it at 220,000 barrels a day. So, you know, let's get more drilling, let's get more evaluation, but obviously initial results are very encouraging.
spk14: Thank you for that. Greg, maybe I will do a part 1A before I go on to John. When you think about these hub sizes, what are you thinking about the plateau levels of production nowadays? Are we thinking about one on top of the other or early phases declining? How are you thinking about that given the scale of the resource you have right now just so we can calibrate everybody's production expectations over time?
spk08: No, again, Doug, you and I have talked about this before. You know, I think these hubs, all hubs, frankly, you know, will have a long plateau and longer than would be typical, you know, in a deepwater environment. And that's simply because of the resource density of how much is in the Guyanis Bases in and around these existing hubs. So not only is there additional tieback opportunity in the Campanian, i.e. LESA class reservoirs. But as we go deeper in the Santonian, let's say that works out as a technical commercial success, then you could see where you could tie back Santonian into some existing Campanian hubs. So if you step back and look at all the prospectivity in the Campanian, all the prospectivity in the Santonian, it's pretty easy to see that these hubs will be full for a long time.
spk14: Thank you. My follow-up, hopefully, is a quick one. John Riley, I don't want to press too much on this debt issue, but two times even does a different number at 50 than it is at 70. So I just wonder if I could ask you what your thinking is on the absolute level of debt that you want to get to, because if Diana is self-funding from next year, which I believe it is phase two. The potential to generate a ton of free cash flow is obviously there, and I'm giving you unhedged on the upside. So just give us an idea where you want the absolute balance sheet to be, and I'll leave it there. Thanks.
spk06: Really, as John has said earlier, once we pay off the $500 million on the term loan, we have the debt at the level we want it to be. As I said, there's a small maturity out in 2024 and no really big maturities out until 2027. So the debt is at that level, and we wouldn't be looking to reduce it any further at that point. And, again, as we add the EBITDA from each FPSO, we will quickly drive under two times that. and then, you know, quite frankly, go below one as we continue to add these FPSOs.
spk14: All right. And Guyana is self-funding next year?
spk06: Guyana is self-funding. Once Phase 2 comes on, Guyana is self-funding.
spk14: Excellent. Thank you.
spk06: Thank you.
spk01: Your next question comes from Neil Mehta with Goldman Sachs.
spk04: Hey, good morning, guys. I'll be quick here, but it's two related questions. The first is for you, John, which is, you know, You always have a great perspective on the oil macro, and there's a lot of uncertainty as we go into 2022. Less so maybe on the demand side, although we can debate that, but more on supply in terms of OPEC behavior. And as barrels come back into the market, will the market get oversupplied or will inventory stay in deficit? So I'd love your perspective, especially given that you spend a lot of time with market participants there. And then the related question is just on HESA's hedging strategy for 2022. Does it make sense to cost average in to the forward curve here, or would you like to stay more open to participate in potential upside? So two related questions.
spk10: Good morning. Thanks for the questions. You know, the oil market is definitely rebalancing. It's three factors, demand, supply, inventories. We think demand is running right now at about 98 million barrels a day. Remember, pre-COVID, globally, it was running 100 million barrels a day. I think demand is well supported with people getting back to work, mobility data in the United States, certainly jet fuel is almost at pre-COVID levels of demand. Obviously, international travel is still down. Gasoline in the United States, demand as well as gas oil demand is back at pre-COVID levels. So demand is pretty strong. I think the financial stimulus programs of the U.S. government and other governments across the world, as well as accommodative monetary policies with the central banks, are really turbocharging the consumer, turbocharging the economy, and supporting oil demand. So we see demand growth continuing into next year. We think we will get, by the end of the year, about 100 million barrels a day of global oil demand. We see that being stronger going into next year. So I think that's a key part that you have to get grounded in to answer your question, what's the demand assumption? We take the over that demand is going to continue to be strong going into next year through the year. Supply, you look at shale. Shale is no longer the swing supplier. It's gone from a business that's focused on production growth to one that's focused on return of capital, financial discipline, appropriately so, so if you can grow a little bit. but generate free cash according to the oil environment. That's what the investor discipline wants. That's what the company discipline wants. So we see the recount. Maybe it gets up to 500 in the United States, but shale will not be growing at the level that it was growing at the last five years for what it's going to be growing the next three or four years. I think U.S. production in the range of crude for oil let's say 11 million barrels a day, it's going to be hard to getting to pre-COVID levels of 13 million barrels a day probably for the next three or four years. So, you know, shale will play a role, but it's going to have a backseat in terms of being the swing supplier. The swing supplier going forward and really the Federal Reserve of Oil prices is going to be OPEC led by, or OPEC Plus led by Saudi Arabia, Russia, and the other members. And I think they've been very disciplined, very wise, and being very tempered. about bringing their spare capacity back. They just made, I think, a very historic agreement that says we'll bring on 400,000 barrels a day month by month. We'll look at it. If something happens in the variant, something happens with Iran coming on, we may curtail that. But basically, that 5.8 million barrels a day of excess capacity will be whittled down $400 a day each month as it goes out. They'll meet every month to check on that. But basically, that will be sort of that cushion that you need to keep supply up with demand. But in that scenario, the market's in deficit. So that should keep prices well supported. And the other key point is, you know, I'd say we're at pre-COVID inventory levels now, where the glut of $1.2 billion barrels of oil excess supply a year ago, April, now has been whittled down to where the market's really back in balance at pre-COVID levels. So, you know, looking forward, the macro, I think, is very supportive, demand growing faster than supply, inventory at pre-COVID levels, and the oil price should be well supported in that environment.
spk04: And, Jeff, you just tied that back into, and that might be a question for John or Ali, tied into the hedging strategy.
spk06: Right. So, Neil, you know, our strategy is going to continue to be to use put options, right? We want to get the full insurance on the downside and leave the upside for investors. So, obviously, we've been watching the market, and the front has been, you know, performing very well. And, you know, it is a bit backward-headed as you go into 2022. And so with the put options, you know, we typically put them on, you know, September to December towards the end of the year. Time value, you know, gets the cost of the options a little bit lower. We'll see where volatility is as we move, you know, getting closer to 2022. Now you should expect us to put on a significant hedge position again like we had this year. And, you know, you should expect to see it as we move into the fourth quarter, us begin to add those hedges.
spk10: But to be clear, it will be a put-based strategy.
spk04: Makes a ton of sense. Thanks, guys. Thank you.
spk01: Your next question comes from Paul Sankey with Sankey Research.
spk07: Hi, everybody. Thanks. A lot of my questions have been answered around the balance sheet, but I was just wondering if we could get a sense for the potential for acceleration on any of the moving parts here. The first would be, would debt pay down potentially be accelerated even faster than what you've talked about with the term loans? If not, would we potentially see faster cash return to shareholders, so a quicker decision to raise the dividend? Is that a potential? Or I guess the alternate would be that you just increase cash on the balance sheet. And then operationally, I guess it's a little bit longer term, but could the pace of Guyana development be accelerated, do you think, or is it a fairly set and predictable path here? And what I'm really wondering is, as you mentioned, the ExxonMobil, buy one, build one, design many, design one, build many strategy. I wonder if that has the potential to accelerate if we look forward, you know, two to three to five to seven years. And finally, whether or not you would increase spending in a very strong story that you have here in the Bakken or the deep water Gulf of Mexico or anywhere else, if that was another potential outlet for the success you're enjoying. Thanks.
spk10: Paul, hi. Good to hear your voice. Look, we've laid out our plan. We're going to be very disciplined about executing the plan. There is always potential to accelerate. It's a function of market conditions, obviously. But I think the key thing is we do want to keep a strong cash position as a cushion for downturns in the oil market. It certainly served us well last year, and it's serving us well this year. Obviously, very different markets between last year and this year. And in terms of what our assumptions are going forward... We want to keep that strong cash position, and with current prices where they are, we think it's prudent to go into next year with a strong cash position so we can fund the high-value projects that we have in Guyana, in the Bakken, and obviously in our other two asset areas. So, you know, I think it's a good planning assumption to assume that it will be, given market conditions, we would pay that $500 million off next year. We always have the flexibility to move it forward, but we want to keep the strong cash position, and we just think that's a financial prudent strategy. In terms of Guyana, Exxon is doing, as Greg said, a great job managing a world-class project. both in terms of cost and in terms of timing, and this idea of design one, build many, and pretty much getting in a cadence of one of these major FPSOs being built, one a year, come on one a year, that cadence is probably as aggressive as any ever done in the industry. And, you know, ExxonMobil often talks about leakage, leakage meaning capital inefficiency. This pace of, you know, bringing on one ship a year is probably as accelerated as you want to get, and it's a pretty darn good one.
spk07: Got it. And then the potential for greater spending, more growth, is that – would it be – I assume you'd be more focused on cash return ultimately because of the –
spk10: can certainly be folded in, and actually that increases our free cash flow generation in the years ahead. So it actually strengthens our free cash flow, even though in the year of the investment you go up a notch. But the Bakken is becoming a major free cash flow generator, and on its way, let's say, to $200,000 a day equivalent and plateauing. So there will obviously be an increase with the rigs. John talks about it in the range of about $200 million per rig. and then you have the different developments that we have. But we're going to stay very focused on keeping a tight string on our capital investments so we can grow the free cash flow wedge and really compound that free cash flow wedge over the next five to six years. Brilliant. Thank you.
spk07: Could I just ask a color question on the midstream? Could you add any strategic color about the moves you've made in the midstream? And I'll leave it there. Thank you.
spk06: Sure. Just at a high-level strategic standpoint, the midstream continues to add differentiated value to our E&P assets. So it allows us to maintain operational and marketing control. It provides the takeaway optionality to multiple high-value markets. And also, it's driving our ability to increase our gas capture and drive down our greenhouse gas intensity. So just starting, Paul, at the high level, both GIP and us remain committed to the long-term value of And so with this transaction, like pro forma for the transaction, you know, Hess Midstream maintains a strong credit position. It's at three times debt to EBITDA. And then it has continuing free cash flow after distributions as it moves forward. So that debt to EBITDA will come back down from three. So it's going to have sustained low leverage and ample balance sheet capacity. So they really did this to optimize its capital structure. And then with this ample balance sheet capacity, it can support future growth or incremental return to shareholders, including Hess. And that can be this type of buyback or increased distribution.
spk10: So in another way of saying it, Hess Midstream becomes a free cash flow engine for Hess as well.
spk14: Understood. Thank you, gentlemen.
spk01: Your next question comes from Bob Brackett with Bernstein Research.
spk12: Good morning, all. I had a question about Fangtooth. If I heard Greg right, he said it was nine miles northwest of Lisa 1. If I look at a seismic section that the Operator X on mobile had in their investor day, they show a very large, deep seismic signature that seems to correspond to where you're drilling Fangtooth. Am I over-reading that, or is this a fairly large structure that you're going to drill?
spk08: Yeah, it is a very large structure that will be dedicated to, you know, the deeper stratigraphy, you know, call it lower Campanian, Santonian. So that will be our first standalone well targeting those deeper intervals. You know, Bob, as you know, the rest have all been deep tails. But this will be a standalone, and, yes, it is a very large structure.
spk12: Great. Thanks for that.
spk08: Thank you.
spk01: Your next question comes from Noel Parks with Tui Brothers.
spk02: Hi, good morning. Morning. Just to sort of continue on from that last question, could you just sort of maybe walk us through where things stand as far as main targets in Guyana versus deeper potential targets sort of just kind of what you pretty much have established beyond the primary targets and sort of what's still to come.
spk08: Go ahead, Greg. You bet. So, you know, when I talk about deeper plays, I'm really talking about the bottom of the Campanian, the lower Campanian, and then down into the San Antonio and then As I said before, these have the potential to be a very large addition to the recoverable resource base in Guyana. If successful, as I mentioned previously, they could be exploited through a combination of tiebacks to existing hubs and or standalone developments if they're big enough. So we've had eight penetrations to date in the deeper plays. And then if you couple that with the success in Suriname, which is we understand the better part over there, again, don't have the data, but this is just what we're hearing from others in industry, appears to be kind of the lower Campanian-San Antonio interval as well. So there's been a number of penetrations, so that's why we're encouraged. Now, we've got a lot more drilling to do to fully understand the potential of this play. So in the second half, We've got several more deep targets that are planned. Three will be what I call deepening, so there'll be deep tails on Campanian targets, two of which John mentioned in his script, which are whiptail, so both whiptail one and whiptail two will be deepened down into the San Antonian. The next one after that is Catabac, and then also Pinktail will have a deep tail on it as well. And then as I just discussed with Mr. Brackett, there will be a deep standalone called Fangtooth. So just on the state block, by the end of the year, we'll have 13 total penetrations in the deeper stratigraphy. So we'll begin to now understand better how it's all put together, where we think the hydrocarbons are, et cetera, et cetera. So, you know, keep watching this space, evolving story. But, you know, very exciting, but, again, need more drilling to figure out where and what we have.
spk02: Great. And just to sort of extend in the other dimension, I seem to remember that the report you had last quarter or three months ago had some implications for aerial extent. And in the wells on the horizon, you know, second half of the year, Are there any of those that will be, you know, particularly informative about the sort of the aerial extent of the deeper zones?
spk08: Well, yeah. You know, it's a mosaic. It's a picture that we're trying to put together, so yes. I mean, you know, we mentioned fangtooth, for example, being a very large structure, stratigraphic feature, I should say. Obviously, if that If the results of that are very positive, then we will probably want to follow up with an appraisal well or a second well in that, given that the structure is quite large, right? Right. But some of these tails will also inform, you know, the size of some of these as well, because, of course, you're going after seismic features that you see on seismic that are of various sizes. Some are big and some are smaller. So by definition, we'll get a better understanding of that.
spk10: And, Greg, that's great perspective on some of the exploration potential, some of the appraisal potential, but you also might point out that we have a pretty active testing program between now and the end of the year to address the aerial extent and productivity of potential developments. You might talk about that.
spk08: Absolutely. So you remember, you know, we'll be doing drill stem tests at Wauru, at MAKO, and then also Long Tails. you know, before the end of the year. So that will give us really key data to, you know, understand the size of those reservoirs in particular.
spk10: And ultimately that helps us define the value of our and upgrade the value of our development queue for projects going forward. So very active program for the rest of the year. New targets. appraising current targets and also testing them so we can upgrade the development queue of future oil projects.
spk08: And I would anticipate on those lines that, you know, eventually we'll do a DST at Whiptail as well.
spk02: Great. Thanks a lot. Just what I was looking for.
spk11: Thank you.
spk01: Thank you very much. This concludes today's conference call. Thank you for your participation. You may now disconnect. Have a great day.
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