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Operator: Good day, ladies and gentlemen and welcome to the Second Quarter 2023 Hess Corporation Conference Call. My name is Kevin and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.
Jay Wilson: Thank you, Kevin. 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 unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the Risk Factors section of Hess's annual and quarterly reports filed with the SEC. Also, on today's conference call, we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. On the line with me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. I'll now turn the call over to John Hess.
John Hess: Thank you, Jay. Welcome, everyone, to our second quarter conference call. Today, I will share some thoughts on the energy transition and then discuss our continued progress in executing our strategy. Then Greg Hill will cover our operations and John Rielly will review our financial results. First, in terms of the energy transition, it is important to realize that progress has been made towards the goal of the Paris Agreement. According to the International Energy Agency, or the IEA, the global median temperature increase prior to the Paris Agreement was 3.5 degrees Celsius. Today, according to the IEA's stated policy scenario, the world is on a trajectory to a median temperature increase of 2.5 degrees. However, much more progress is required and we currently are not on a path to meeting the Paris Agreement's goal of 1.5 degrees. There are 3 important gaps affecting the pace of progress. First, the world is facing a structural deficit in energy supply and the key challenge is investment. To meet growing energy demand, the world needs to invest $4 trillion each year for the next 10 years in clean energies, significantly more than last year's investment of $1.4 trillion. The world also needs to invest $500 billion each year for the next 10 years in oil and gas, as compared with $300 billion to $400 billion invested annually in the last 5 years. Second, developed countries have a gap between their current pledges and the investments they are making to reach their emission reduction commitments. For example, the United States has pledged a 50% reduction in emissions by 2030. And even with the incentives in the Inflation Reduction Act, our nation will likely fall far short of that pledge. Finally, developing countries are also facing large gaps in their aspirations for emission reductions. I recently had the honor of speaking at the Energy Asia Conference in Kuala Lumpur. Asia represents 50% of the world's population, 50% of global energy use and 50% of global emissions and will, therefore, play a key role in the energy transition. The conference speakers, both government officials and business leaders, made it clear that Asia will need to find the right balance between energy affordability and emission reduction commitments. At COP28 in December of this year, developing countries' voices must be heard to address their rights to economic prosperity and a higher standard of living. The reality is that the energy transition will take a long time, cost a lot of money and require many technologies that do not exist today. We must recognize that oil and gas will be needed for decades to come and are fundamental to an orderly, just and secure energy transition. Policymakers need to have climate literacy, energy literacy and economic literacy to enable a net zero future. In a world that will require reliable, low-cost oil and gas resources for decades ahead, we believe that Hess offers a unique value proposition for investors. We continue to execute our strategy to deliver high-return resource growth, a low cost of supply and industry-leading cash flow growth and, at the same time, maintain our industry leadership in environmental, social and governance performance and disclosure. In terms of resource growth with multiple phases of Guyana developments coming online and our robust inventory of high-return drilling locations in the Bakken, we can deliver highly profitable production growth of more than 10% annually through 2027. In terms of low cost of supply, as our resource base continues to expand, particularly in Guyana, where our first 5 developments have breakevens in the range of $25 to $35 per barrel Brent, we will steadily move down the cost curve. By 2027, we forecast that our cash unit costs will decline by 25% to approximately $10 per BOE. In terms of cash flow growth, we have an industry-leading rate of chain story and an industry-leading duration story, providing a highly differentiated value proposition. Based upon a flat Brent oil price of $75 per barrel, our cash flow is forecast to increase by approximately 25% annually between 2022 and 2027, more than twice as fast as our top line growth. And our balance sheet will also continue to strengthen, with our most recent debt-to-EBITDAX ratio at approximately 1x. Successful execution of our strategy has uniquely positioned our company to deliver significant value to shareholders for years to come, both by growing intrinsic value and by growing cash returns. We plan to continue increasing our regular dividend to a level that is attractive to income-oriented investors but sustainable in a low oil price environment. As our free cash flow generation steadily increases in future years, share repurchases are expected to represent a growing proportion of our return of capital. By investing only in high-return low-cost opportunities, we have built a differentiated and balanced portfolio focused on Guyana, the Bakken, Deepwater Gulf of Mexico and Southeast Asia. Key to our strategy is Guyana, the industry's largest oil province discovered in the last decade, where Hess has a 30% interest and ExxonMobil is the operator. Since 2015, we have had more than 30 discoveries on the Stabroek Block, underpinning a gross discovered recoverable resource estimate of more than 11 billion barrels of oil equivalent, with multibillion barrels of exploration potential remaining. In June, we were honored to be named E&P Explorer of the Year in the 15th annual Wood Mackenzie exploration industry survey for the second consecutive year. In terms of Guyana developments, we currently have line of sight to 6 floating production, storage and offloading vessels, or FPSOs, in 2027, with a gross production capacity of more than 1.2 million barrels of oil per day and the potential for up to 10 FPSOs to develop the discovered resources on the Stabroek Block. In the Bakken, we have a 15-year inventory of high-return drilling locations to enable us to steadily grow net production to approximately 200,000 barrels of oil equivalent per day in 2025. We plan to continue operating a 4-rig program which will enable us to fully optimize our infrastructure, lower our unit cash costs and generate significant levels of free cash flow. Turning to our operated offshore assets. In the Gulf of Mexico, we had a successful oil discovery during the quarter at the Hess-operated Pickerel-1 well with approximately 90 feet of high-quality net pay which we plan to tie back to our Tubular Bells Production Facility, with first oil expected in mid-2024. In Southeast Asia, we have 2 important long-life natural gas assets, North Malay Basin and the joint development area, or JDA. Our major priorities going forward are to continue to maximize cash flow and production at North Malay Basin and to work with the governments of Malaysia and Thailand to extend our PSC agreement at the JDA. 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. Last week, we announced the publication of our 26th Annual Sustainability Report which provides a comprehensive review of our strategy and performance on environmental, social and governance programs, including our net zero commitment and the significant progress we have made toward our 2025 emissions reduction targets. In summary, we continue to successfully execute our strategy to deliver industry-leading cash flow growth and financial returns to our shareholders, while safely and responsibly producing oil and gas to help meet the world's growing energy needs. As a result, our company is uniquely positioned to deliver significant value to shareholders for years to come, both by growing intrinsic value and by growing cash returns. As our portfolio becomes increasingly free cash flow positive, we will continue to prioritize the return of capital to our shareholders through further dividend increases and share repurchases. I will now turn the call over to Greg Hill for an operational update.
Greg Hill: Thanks, John. In the second quarter, we demonstrated strong operational performance across our portfolio. Company-wide net production averaged 387,000 barrels of oil equivalent per day, well above our guidance of approximately 355,000 to 365,000 barrels of oil equivalent per day. In the third quarter, we expect company-wide net production to average approximately 385,000 barrels of oil equivalent per day, reflecting planned maintenance and hurricane contingency in the Gulf of Mexico. For the full year 2023, we now expect company-wide net production to average between 385,000 and 390,000 barrels of oil equivalent per day, up from our previous guidance of 365,000 to 375,000 barrels of oil equivalent per day, primarily reflecting our strong performance in the first half of 2023 and the expected startup of the Payara development in Guyana early in the fourth quarter. Turning to the Bakken. Second quarter net production of 181,000 barrels of oil equivalent per day was above our guidance of 165,000 to 170,000 barrels of oil equivalent per day, with approximately half of the increase due to strong operational performance and the remainder from higher production entitlements under our percentage of proceeds contracts as a result of lower NGL prices. In the second quarter, we drilled 32 wells and brought 30 new wells online. In the third quarter, we expect to drill approximately 27 new wells and bring online approximately 30 new wells. For the full year 2023, we expect to drill and bring online approximately 110 new wells. Individual well results in terms of IP180s and EURs continue to meet or exceed expectations. For the third quarter, we expect Bakken net production to average approximately 185,000 barrels of oil equivalent per day. And for the full year 2023, we have increased our forecast of net production to between 175,000 and 180,000 barrels of oil equivalent per day, up from our previous guidance of 165,000 to 170,000 barrels of oil equivalent per day. Moving to the offshore. In the deepwater Gulf of Mexico, second quarter net production averaged 32,000 barrels of oil equivalent per day. In the third quarter, we expect net production to average approximately 25,000 barrels of oil equivalent per day, reflecting planned maintenance downtime and hurricane contingency. For the full year 2023, we continue to forecast Gulf of Mexico net production to average approximately 30,000 barrels of oil equivalent per day. We are excited to announce that the first well of our 2023 Gulf of Mexico drilling program has resulted in an oil discovery. The Hess operated Pickerel-1 infrastructure-led exploration well in Mississippi Canyon, encountered approximately 90-feet of net pay and high-quality oil-bearing Miocene-aged reservoir. Long lead construction activities are underway to tie the well back to the Tubular Bells production facility, with production expected to commence in mid-2024. Following Pickerel, we plan to drill the Black Pearl development well in which Hess is the operator and has a 25% working interest and Chevron, CNOC and Equinor each have 25%. This well is planned as a tieback to the Stampede Production Facility. Following Black Pearl, we plan to drill the Vancouver prospect located in Green Canyon Block 287. Vancouver is a large hub class exploration prospect, targeting subsalt Miocene-age reservoir. Hess is the operator and has 40% working interest and Shell and Chevron each have 30%. In Southeast Asia, second quarter net production averaged 64,000 barrels of oil equivalent per day. For the third quarter and full year of 2023, we forecast net production to average approximately 65,000 barrels of oil equivalent per day. In Guyana, where Hess has a 30% interest in the Stabroek Block, second quarter net production averaged 110,000 barrels of oil per day at the high end of our guidance range of 105,000 to 110,000 barrels of oil per day, driven by strong facility uptime and well performance. For the third quarter, net production from Guyana is expected to also average approximately 110,000 barrels of oil per day. We now expect full year 2023 net production to average approximately 115,000 barrels of oil per day compared to our previous guidance range of 105,000 to 110,000 barrels of oil per day, reflecting the expected early fourth quarter start-up of Payara, with a gross production capacity of approximately 220,000 barrels of oil per day. We forecast Payara to contribute approximately 15,000 net barrels of oil per day in the fourth quarter. Turning to our fourth development, Yellowtail. The overall project is approximately 60% complete and remains on track for first oil in 2025, with a gross production capacity of approximately 250,000 barrels of oil per day. The fifth development, Uaru, was sanctioned in April. Uaru will develop more than 800 million barrels of oil from the Uaru, Mako and Snook fields. The FPSO will have a gross production capacity of approximately 250,000 barrels of oil per day and is on track to achieve first oil in 2026. With regard to our sixth development, Whiptail, the partnership anticipates submitting a plan of development to the government of Guyana in the fourth quarter, with first oil targeted for 2027. Now turning to exploration. In Guyana, the Stabroek Block exploration license was formally extended by 1 year to October 2027 due to the COVID-19 pandemic. The extension also pushes out the contractual acreage relinquishment by 1 year to October 2024. In the Fangtooth area, drill stem tests and core analysis are ongoing. Moving forward, we plan to drill the Bacher-1 well which is a deep prospect located approximately 7 miles west of Fangtooth-1 and the Lancetfish-1 well, located approximately 2 miles southwest of Fangtooth-1. We also plan to drill the Lancetfish-2 appraisal well also in the Fangtooth area. Exploration and appraisal activities are also planned in the southeastern portion of the block to better understand the longer-term potential of this area. Activities will include drilling and exploration prospect called Blue Fin, located approximately 6 miles southwest of Himara-1. In closing, we achieved strong operational performance in the quarter. The Bakken is on a steady growth trajectory. We had exploration success in the Gulf of Mexico with more drilling planned. Our Southeast Asia assets continued to deliver steady production through high reliability and successful ongoing drilling programs. And Guyana keeps getting bigger and better, all of which position us to deliver significant shareholder value for years to come. I will now turn the call over to John Reilly.
John Rielly: Thanks, Greg. In my remarks today, I will compare results from the second quarter of 2023 to the first quarter of 2023. We had net income of $119 million in the second quarter of 2023 compared with $346 million in the first quarter of 2023. On an adjusted basis which excludes items affecting comparability of earnings, we had net income of $201 million in the second quarter of 2023. Turning to E&P. E&P adjusted net income was $237 million in the second quarter of 2023 compared with $405 million in the previous quarter. The changes in the after-tax components of adjusted E&P earnings between the second quarter and first quarter of 2023 were as follows: higher sales volumes increased earnings by $66 million, lower realized selling prices decreased earnings by $118 million, higher cash costs and Midstream tariffs decreased earnings by $71 million, higher exploration expenses decreased earnings by $34 million. All other items decreased earnings by $11 million, for an overall decrease in second quarter earnings of $168 million. For the second quarter, our E&P oil sale volumes were overlifted compared with production by approximately 100,000 barrels which had an insignificant impact on our after-tax results for the quarter. Turning to Midstream. The Midstream segment had net income of $62 million in the second quarter of 2023 compared with $61 million in the previous quarter. Midstream EBITDA before noncontrolling interest amounted to $247 million in the second quarter compared to $238 million in the previous quarter. Turning to our financial position. At June 30, excluding the Midstream segment, cash and cash equivalents were $2.2 billion. Total liquidity was $5.6 billion, including available committed credit facilities and debt and finance lease obligations totaled $5.6 billion. During the second quarter, we received net proceeds of $217 million from the public offering of approximately 6.4 million Hess-owned Class A shares of Hess Midstream and the sale of approximately 1.7 million Hess-owned Class B units to Hess Midstream. Net cash provided by operating activities before changes in working capital was $974 million in the second quarter compared with $1.03 billion in the first quarter. E&P capital and exploratory expenditures were $933 million in the second quarter of 2023 compared to $765 million in the previous quarter. Now turning to guidance. Our E&P cash costs were $13.97 per barrel of oil equivalent in the second quarter of 2023 which was lower than our guidance of $15.50 to $16 per barrel of oil equivalent, primarily due to higher production. We project E&P cash costs to be in the range of $14 to $14.50 per barrel of oil equivalent for the third quarter and in the range of $13.50 to $14 per barrel of oil equivalent for the full year which is at the lower end of our previous guidance of $13.50 to $14.50 per barrel of oil equivalent. DD&A expense was $12.79 per barrel of oil equivalent in the second quarter of 2023. DD&A expense is forecast to be in the range of $12.50 to $13 per barrel of oil equivalent for the third quarter and in the range of $13 to $13.50 per barrel of oil equivalent for the full year which is at the lower end of our previous guidance of $13 to $14 per barrel of oil equivalent. This results in projected total E&P unit operating cost to be in the range of $26.50 to $27.50 per barrel of oil equivalent for both the third quarter and full year 2023. Exploration expenses, excluding dry haul costs, are expected to be approximately $60 million in the third quarter and approximately $170 million for the full year which is updated from the previous guidance of $160 million to $170 million. The Midstream tariff is projected to be in the range of $320 million to $330 million for the third quarter and full year guidance of $1.230 billion to $1.250 billion remains unchanged. E&P income tax expense is expected to be in the range of $170 million to $180 million for the third quarter and full year guidance of $670 million to $680 million remains unchanged. We expect noncash option premium amortization which will be reflected in our realized selling prices, will be $52 million for the third quarter and full year guidance of $190 million remains unchanged. Our E&P capital and exploratory expenditures are expected to be approximately $1.025 billion in the third quarter and full year guidance of approximately $3.7 billion remains unchanged. Turning to Midstream. We anticipate net income attributable to Hess from the Midstream segment to be in the range of $55 million to $60 million for the third quarter and $240 million to $250 million for the full year which is down from the previous guidance of $255 million to $265 million, reflecting the impact of the Midstream capital market transactions completed in the second quarter. Turning to Corporate. Corporate expenses are estimated to be approximately $25 million for the third quarter and $110 million to $120 million for the full year which is lower than the previous guidance of $120 million to $130 million due to higher interest income. Interest expense is estimated to be in the range of $75 million to $80 million for the third quarter and $300 million to $310 million for the full year which is updated from the previous guidance of $305 million to $315 million. This concludes my remarks. We'll be happy to answer any questions. I will now turn the call over to the operator.
Operator: [Operator Instructions] Our first question comes from Doug Leggate with Bank of America.
Doug Leggate: Greg, I wonder if I could just ask a couple on Guyana. First of all, with Payara, you gave the guidance of the expected production for the fourth quarter but can you give us some idea of the ramp up? When would you expect to see full facility production at Payara?
Greg Hill: Yes. So thanks for that question, Doug. Yes, as we mentioned it's coming on early in the fourth quarter and I would expect the ramp-up to be like Liza Phase 2 kind of on the order of 5 months or so in terms of ramp Payara is a little bit bigger, so it might take marginally a little bit longer but I would say 5 months, yes.
Doug Leggate: Okay. Is there a debottlenecking strategy around Payara like you've done in Liza 1 and 2?
Greg Hill: Yes, I think there will be because there is a lot of discovered resource in and around Payara. So there will definitely be a debottlenecking strategy as well.
Doug Leggate: My follow-up is really on exploration. It seems Exxon -- I guess yourselves and Exxon submitted a 35-well program that's been approved by the government now. So I guess that fits into that timeline you were talking about with the extension. But I'm really trying to understand what this means for the risked resource view. You haven't updated the 11 billion barrels for about 1.5 years and our understanding from our field trip down there was that Fangtooth Southeast was a success. So can you give us some update as to when you would expect to see the resource numbers revised?
John Hess: Sure. Doug. It's John and thanks for the question. Look, we have a very active exploration appraisal program this year on the Stabroek Block. A lot of it in terms of appraisal, especially in the Fangtooth area. Greg addressed that in his remarks. And other appraisal on the block, some exploration on the block. And I think the real takeaway, Doug, is that we still see multibillion barrels of oil equivalent. And at the appropriate time, we'll consider increasing the resource estimate of greater than 11 billion barrels of oil equivalent.
Doug Leggate: Just to be clear, John, the 11 billion relates to how many discoveries?
John Hess: Doug, that line continues to get upgraded. And I would say, it's the overall program and there's still more to be recognized from some of the outstanding wells we drilled. As you know, a lot of evaluation work is underway in an area like Fangtooth. And until we get that evaluation work done, including the drill stem test, production tests, it's a little premature to jump that number until we're ready to give more clarity on it.
Operator: Our next question comes from Arun Jayaram with JPMorgan Securities.
Arun Jayaram: Greg, I was wondering if you could give us maybe an update on how the debottlenecking efforts are going at Liza 1 and Liza 2. Are there any other projects scheduled for the back half of the year? And give us a sense of where you think the new plateau level of production is for both facilities in the post debottlenecking?
Greg Hill: Sure. So Arun, as you know, Liza Phase 1 has already been debottlenecked. It's comfortably operating in the 145 to 150 range on a regular basis, so I think that's about what you can expect out of that one. If we look at Liza Phase 2, so that's Unity, it's producing above its nameplate of 220. It's sometimes as high as 240. The operator has a plan to further debottleneck that facility between now and the end of the year. So I think we'll be approaching the 250 number as we get sort of towards the end of the year. And then there's another kind of an engineering project next year to look at the possibility of further debottlenecking Phase 2. I think the operator is quite comfortable with a number around 400,000 barrels a day from both of those facilities and I would add that's 20% above the sanction case. So ExxonMobil is just doing an extraordinary job of debottlenecking, higher reliability. I can't say enough about the outstanding job they're doing as an operator.
Arun Jayaram: Great, that's helpful. And maybe one for John Rielly. John, I was wondering if you could maybe offer some soft CapEx guidance for 2024, including kind of an expectation that you do kind of purchase the FPSO and you obviously announced the discovery now at Pickerel.
John Rielly: Thanks, Arun. As you know, it's a little early for 2024 capital. We do -- there is a plan to purchase the Unity FPSO in 2024. But look, we're still working on Whiptail, getting the final cost estimates in on that. So I think what we'll do is provide our typical 2024 guidance in January.
Operator: Our next question comes from Paul Cheng with Scotiabank.
Paul Cheng: John, I know you reiterated full year budget at $3.7 billion. But the first half year is a bit low and so where the ramp-up is going to be in the second half?
John Rielly: Yes. So we have Guyana, obviously, the ramp going there, getting Payara online. And look, we managed just the progression of the developments there. So we'll be working on Yellowtail. There's obviously working on Uaru. So you just got -- the back half of the year, you've got more spend coming in Guyana. Then also, what we have is the Gulf of Mexico rig. So as Greg mentioned, we have -- that rig came in right at the tail end of Q2 and so it drilled Pickerel. We had the success there. And as Greg mentioned, it's going to be doing Black Pearl and then Vancouver. So again, that's tilted towards the second half of the year. And the only other thing I would add on that and this was expected, is that the weather window up in North Dakota, this is the best time for some of the facilities to work up there. So that's why we get a little bit more in the back half in the Bakken as well.
Paul Cheng: And I mean -- do you think there's any reasonable probability the full year spending end up going to be below the budget, given the run rate that we see?
John Rielly: Paul, I think we are just going to keep reiterating the $3.7 billion. The execution has been terrific so far, as you can see on the production side and we've been very efficient on the capital side. But we do have plans to spend that full $3.7 billion. So I would look just to keep the capital at that level in your model.
Paul Cheng: Okay. On Guyana, I think that you probably have a $45 million, $50 million of deferred tax in the quarter. Any kind of rough estimate you can provide for the third and fourth quarter may look like. And also that whether the expansion of exploration period by 1 year, you're saying more in the onetime payment from the consortium to the government at all?
John Rielly: Let me start with that 1-year payment. No, there was no payment. That was really, as Greg had mentioned earlier, due to COVID-19 and the force majeure us not being able to explore during that period. So that just is extended to one year. As far as the deferred taxes which are always a bit difficult to actually the forecast, you are right, it was approximately $45 million in Q2. It was about $36 million in Q1. I would say, from our forecast and what we're looking and you've got the Payara start-up which makes it even harder to forecast, that it will be a little bit higher than that $45million number you mentioned in Q3 and Q4 on the deferred taxes.
Operator: Our next question comes from Ryan Todd with Piper Sandler.
Ryan Todd: Maybe just one follow-up on the extensions there in Guyana. And congrats on getting the extension for both the acreage relinquishment and the exploration license. I know you had always said that this was going to be easily managed and now have a huge impact. But does the extension have any impact on how you may allocate resource there over the next few years or, in general, on your approach or what you're able to do there in the basin?
Greg Hill: No. I don't think at all. It won't change the pace. I think you can expect certainly next year, probably a 6-rig program. And it won't affect anything. It will just give us that extra year to lock down whatever we can before the expiry which we have every interest in doing, obviously.
John Hess: Yes. To be clear, each year, we plan to drill 10 to 12 exploration appraisal wells. So it just gives us another year to have further evaluation, then it will be in the best interest of the country and also our joint venture itself. So we have, as I said before and Greg did as well, multibillion barrels of exploration potential remaining. And we can orderly have a prosecution of that opportunity.
Ryan Todd: Great. And then maybe as a follow-up. I know you were just talking about the capital budget for the year but what are your latest assumptions in terms of -- or what you're seeing in terms of cost inflation or deflation on the contract side? And how does that compare with what you had earlier been assuming in your capital and OpEx guidance?
Greg Hill: Yes. So let me address both the onshore and the offshore. So in the Bakken, we observed inflation of between 10% to 15% blended in the first half of 2023. And we were able to mitigate about half of that through the application of strategic contracting, lean manufacturing and technology. Now we're starting to see some costs, such as oil country, tubular goods beginning to moderate. We're still maintaining our well cost guidance at $6.9 per well because we're increasing proppant loading in several areas of the field to further maximize the issue NPV. So we're just going to stick with our 6.9%. But again, we are seeing some deflation start to occur in the Bakken. If we go in the offshore, rig utilization remains very high in the offshore, so costs have not moderated there. However, most of our spend is in Guyana were the first 5 FPSOs are contracted. ExxonMobil was doing a great job of mitigating inflationary effects using its Design One, Build Many strategy. And in addition, recall for our 2023 Gulf of Mexico program, most services were contracted in 2022 when costs were lower. So long and short, our overall 2023 capital guidance of $3.7 billion remains unchanged and we'll provide 2024 guidance in our January call, as John Rielly said.
Operator: Our next question comes from Neil Mehta with Goldman Sachs.
Neil Mehta: Yes. It was a strong quarter in the Bakken, recognizing that volume can be noisy with commodity prices. But just curious on your thoughts on getting to that 200,000 barrels a day of plateau. And is there visibility to pull that forward if you continue on this execution track?
Greg Hill: No. I think, Neil, our plan still shows that we'll get to an average of 200,000 barrels a day in 2025. And as we've said before, with our extensive inventory of drilling locations, we expect to hold that plateau for nearly a decade and the Bakken then becomes a significant free cash flow machine.
Neil Mehta: All right. The follow-up is just around -- it's a couple of cash flow items. First is around return of capital. What's the framework for increasing that as you continue to progress through the program in Guyana? And the second, is there any update on hedging strategies as we look into 2024?
John Rielly: For the return of capital program, so we're going to continue to be disciplined in the execution of our return of capital framework. I mean as you know in March of this year, we announced an increase in our dividend by 17%. And as we go through the year, we'll continue to follow the framework. And as a reminder, our financial priorities remain. First, we're going to invest in the high-return opportunities, especially in Guyana and the Bakken. And as was mentioned earlier, we do have -- our capital is a bit back-end loaded this year. So we have more capital coming in the second half of the year. Our second is to maintain a strong balance sheet. And with that, we do have that $300 million debt maturity coming next year which we do intend to pay off. But again, a key to maintain a strong balance sheet and cash position -- and we have a nice cash position now, the $2.2 billion and that's in place so we can continue to fund these great return projects in the Guyana and Bakken. And then what we will do and we'll follow this framework, it's an annual framework. We're going to return up to 75% of our free cash flow to shareholders through the dividend increases, as John has mentioned earlier and share repurchases. And as John has mentioned earlier, as our free cash flow generation steadily increases, share repurchases are expected to represent a growing proportion of our return of capital.
Neil Mehta: Great. And on hedging?
John Rielly: Sorry. Yes, on hedging. For the hedging, you've seen us in the past couple of years. We've been hedging in around 130,000 to 150,000 barrels of oil per day with put options. So we want to make sure we give the upside to investors. And you can think about that we will maintain that type of level. So on a percentage basis of our oil production, because with Guyana coming on and Payara coming on at full ramp, you're getting just that production capacity between 55,000 and 60,000 barrels a day add there. Yellowtail will be even more because it's a bigger boat. So we're going to have higher and higher oil production. So the hedging percentage, as a percentage of our overall oil production, will go down. But we'll maintain around that 130 to 150 level.
Operator: Our next question comes from Roger Read with Wells Fargo.
Roger Read: Yes. Just, I guess, two questions I had. One, in terms of Guyana, just what you can tell us about how the wells have been performing and how maybe that fits into the rated guidance on production or the overall confidence that allows you to raise production guidance?
Greg Hill: No. The wells are performing better than expected, really across the board. And of course, the capacity is driven by the physical constraints on the vessel. But obviously, with those wells outperforming, we want to increase that capacity view as high as possible through debottlenecking. But the wells are doing fantastic.
Roger Read: That's good to hear. And then my other question, as you look at your Gulf of Mexico exploration program, sort of the relatively lower risk Black Pearl versus the higher risk Vancouver, anything you're doing on the seismic side that's making that, let's say, offsetting the risk to some standpoint?
Greg Hill: Yes, absolutely. I think there's 2 things that really have been the discontinuity, I'll call it, in the last 5 years in exploration in the Gulf of Mexico. And the first one is ocean bottom nodes. So we are shooting ocean bottom node surveys in and around all of our hubs. And that is coupled -- that coupled with the new algorithms, so Full Waveform Inversion, FWI, the combination of those 2 things are allowing us to see new opportunities in subsalt in the Gulf of Mexico. And that's not only true for in and around our hubs but it's also true for hub class opportunities as well; so very exciting. We've got over 80 blocks in the Gulf of Mexico. And with that inventory, our aim is to maintain that cash engine in the Gulf of Mexico at a minimum, hold production broadly flat but then also potentially grow that production with a hub class success. And those seismic improvements that I talked about are leading that charge with the great portfolio that we have.
Operator: Our next question comes from Kevin MacCurdy with Pickering Energy Partners.
Kevin MacCurdy: Just one question on the Bakken production guidance raise. Gas and NGL has obviously outpaced your quarterly guidance but you also had strong oil production above our expectations. Is there any color you can provide on how much of the guidance raise was oil versus gas and NGLs?
John Rielly: So specifically here, as we move through the year, our oil production is going to continue to increase. So as you saw the increase in Q2, you can expect a similar increase in Q3 as we saw from Q1 to Q2. And then we continue to expect to see these increases as we go forward. And then outside of the winter months in there, we'll continue to have oil increases as go through into 2025 and we get up to that 200,000 barrels of oil per day. So in general, from an overall guidance standpoint on what we were doing, it's kind of similar. Some of the half of the guidance increase is due to performance and half was due to those pop, those NGL and gas volumes.
Operator: Our next question comes from Biju Perincheril with Susquehanna Financial Group.
Biju Perincheril: John, I was wondering how you're sort of tidying up the design tolerance on each of the FPSOs. Just trying to understand as you go through the subsequent debottleneck in projects, how we should think about your production uplift?
Greg Hill: Yes. So I think the thing I will say is that every vessel will be bespoke. So the way that we do this debottlenecking is we produce the vessel for a year or so and then get all of the dynamic data. And then from that data, make a decision on how much we think that we can squeeze more out of the vessel, or do an engineering project to further debottleneck that. But I think the bias will be to debottleneck these vessels as much as we can because there is so much additional resource around each one of these hubs. And that, coupled with the multibillion barrels of additional upside says that these vessels are going to be full, at plateau longer than what would be typical for a deepwater development. And -- but again, each one will be bespoke. So -- but certainly, the bias is going to be there to debottleneck as much as possible.
Biju Perincheril: Got it, that's helpful. A follow-up on the Bakken. You -- so that 200,000 barrels equivalent, at their plateau levels, what should be the oil mix we should expect at that point?
Greg Hill: Yes. So longer term, when we're at that 200,000 barrels a day, you can expect about 100,000 barrels a day of oil. So about 50%.
Operator: Our next question comes from Noel Parks with Tuohy Brothers.
Noel Parks: You made a mention in the Guyana discussion about just putting resources into more exploration of the Southwestern part of the block. I wonder if you could just sort of refresh us on sort of what the original view of that geology was. And now with benefit of the incremental drilling of what you hope to discover or discern there.
Greg Hill: Again, the discovery is down in that part of the block. They're all Upper Campanians, so they're Liza-like reservoir, so very high-quality reservoirs. As you move to the southeast of the block, the GOR does increase. So the reason that we want to do some further appraisal and exploration down there is to really understand the higher GOR developments on the block. Still going to be very good projects, I'm sure but we just need a little bit more data to fully understand how we're going to develop those, where we fit in a queue. I think the important thing is, though, our objective is to move oily developments forward. So for example, Fangtooth is a great example that we're trying to move oily developments up in the queue. But at the same time, there's more that we need to understand about the Southeast part of the block. So we will occasionally do some appraisal or exploration drilling down or just to further up our understanding of that part of the block.
Noel Parks: Great. And I appreciate your comments just a minute ago about seismic improvement and the opportunity in the Gulf of Mexico. I was just wondering whether there were any projects that Hess is participating in on a non-operated basis in the Gulf? Whether -- I was wondering if there were any of those sort of under the radar that might be worth mentioning?
Greg Hill: No. I think there's, again, in the Shell assets, in particular, around some of their hubs, where we have an interest -- a non-operated interest, they're doing the same things. We are OBN and finding new opportunities around those hubs as well. So you'll see some of those feature in the future as well.
Noel Parks: Are those sort of near term or more sort of on the horizon?
Greg Hill: No, that was in near term. It will be part of the mix as we kind of execute over the next 2 to 3 years.
Operator: Our next question comes from Paul Cheng with Scotiabank.
Paul Cheng: And just a quick follow-up on the Pickerel, to be on stream mid-2024. What is the net to Hess going to look like? And what's the development cost?
Greg Hill: Sure, Paul. So that we're still evaluating the well results. But we anticipate peak gross production rates to be in the range of 8,000 to 10,000 barrels a day.
John Hess: And we have 100% interest in that well, to be clear.
Greg Hill: Yes. And that -- as we said, that will be tied back to the Tubular Bells facility kind of midyear next year.
Paul Cheng: Great. John, any what estimate -- what's the development cost on this pipeline?
John Rielly: Again, we are still overall coming -- evaluating the results of the well. One, I can tell you, it's a very high-return project, obviously, with it being a tieback to Tubular Bells. And typically, these type of tieback wells are going to have like a $10 per barrel kind of costs or lower. That's what we'll typically see in those -- in these tieback wells.
Greg Hill: Find and develop.
Paul Cheng: Right. And Greg, what's the resource -- recoverable resource that we estimate for this? And is it all oil or that is the mix between oil and gas?
Greg Hill: No, it's a mix of oil and gas, 80% oil, 20% gas. So it's mainly oil. And as John mentioned, we're still evaluating the well, so I don't want to give a resource estimate yet. But again, it's going to be extremely profitable. ILX tieback, very low find and development costs. So nothing to worry about here, Paul at all.
Paul Cheng: Okay. And final one from me. Yellowtail and Uaru, you're talking about 2025, 2026, should we assume you're somewhat like similar to the Payara, is going to be in the early fourth quarter?
John Hess: I think what we're saying is that each of these will come on in the year quoted. I think it's too early to say exactly when in that year for these later projects. So we're just quoting in the year itself. And as we get closer, obviously, the Yellowtail is 60% complete, so that should tell you something about where it is in the queue.
Paul Cheng: Okay. And on the Gulf of Mexico, second quarter production is better. Is it because that some of the maintenance downtime has been able to perform at a shorter period? Or that something is actually being pushed to the third quarter?
John Hess: No, it's really reliability -- no, it's really just higher reliability across the board.
Operator: Our next question comes from Phillips Johnston with Capital One Securities.
Phillips Johnston: Just a quick one for John Rielly. On the first quarter call, you were asked about your investment in Hess Midstream and it was pretty clear that it's going to remain a key strategic asset for the company going forward for a few different reasons. With the unit sale in Q2 for a little over $200 million, you've cut your stake down about 38% [ph]. I'm sure you can't comment on potential future sell-downs but can you maybe just remind us of the threshold to where you would no longer have operational and marketing control?
John Rielly: So let me just start high level that we remain committed to maximizing the long-term value of Hess Midstream. It's adding differentiated value to our Bakken E&P assets. And part of it is allowing Hess to maintain operational control which we can for -- even with a much lower ownership percentage. So nothing to worry about there from that, Phil. Then what it also does, it provides takeaway optionality to high-value markets. And also, it's that ability to increase our gas capture to drive down flaring in our GHG emissions intensity. So -- and as you know, we've set a zero routine flaring goal by 2025. So the one other thing about it, to your point but with a strong credit position and its continuing free cash flow growth, Hess Midstream has said they continue to have greater than $1 billion of financial flexibility through 2025 to support potential incremental share repurchases. Similar to the ones that we've done this year, we had 2 $100 million gross transactions executed in March and June. So you should expect some more of those with that financial flexibility.
Operator: Ladies and gentlemen, that does conclude the Q&A portion of today's conference call. We'd like to thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect and have a wonderful day.