Michael Wirth: Thanks, Jake, and thank you, everyone, for joining us today. Chevron continues to deliver strong operational performance, maintain cost and capital discipline and consistently return cash to shareholders. First quarter marked 9 consecutive quarters with adjusted earnings over $5 billion and adjusted ROCE above 12%. During the quarter, we also returned $6 billion in cash to shareholders, the eighth straight quarter over $5 billion. We also grew production more than 10% from the same quarter last year and announced final investment decisions to grow our renewable fuels and hydrogen businesses. Earlier this month, we announced our third Future Energy Fund focused on venture investments in lower-carbon technologies. The merger with Hess is advancing, and we intend to certify substantial compliance with the FTC second request in the coming weeks. We believe that a preemption right does not apply to this transaction and are confident this will be affirmed in arbitration. We expect the proxy for the Hess shareholder vote to be mailed in April with a special meeting date in late May. This strategic combination creates a premier energy company with world-class capabilities and assets to deliver superior shareholder value, and we look forward to bringing the 2 companies together. At TCO, we had achieved start-up of WPMP this month with the first inlet separator and pressure boost compressor in service and conversion of the first metering station to low pressure now complete. Later this quarter, we expect a second pressure boost compressor online and a third gas turbine generator to provide power to the Tengiz grid. Metering station conversions are planned through the remainder of the year as additional pressure boost compressors start up, keeping the existing plants full around planned SGI and KTL turnarounds.

adjusted earnings 9 consecutive quarters


We continue to make significant progress on FGP and expect to have additional major equipment ready for operations in the third quarter. Costs and scheduled guidance remain unchanged with FGP expected to start up in the first half of 2025. Now over to Eimear to discuss the financials. Eimear Bonner: Thanks, Mike. We delivered another quarter of strong earnings, ROCE and cash returns to shareholders. We reported first quarter earnings of $5.5 billion or $2.97 per share. Adjusted earnings were $5.4 billion or $2.93 per share. Cash flow from operations was impacted by an approximate $300 million international upstream ARO settlement payment and $200 million for the expansion of the retail marketing network. We also had a working capital build during the quarter consistent with historical trends. Chevron delivered on all of its financial priorities during the quarter, an 8% increase in dividend per share; organic CapEx aligned with ratable budget inclusive of progress payments for new LNG ships; sustained net debt in the single digits while issuing commercial paper to manage timing of affiliate dividends and working capital; and share repurchases of $3 billion. Adjusted earnings were lower by $1 billion versus last quarter. Adjusted upstream earnings were down due to lower realization and liquids liftings. Partly offsetting were favorable tax impacts. Adjusted downstream earnings were lower mainly due to timing effects associated with the rising commodity price environment. All other decreased on higher employee costs and an unfavorable swing in tax items. Adjusted first quarter earnings were down $1.3 billion versus last year. Adjusted upstream earnings were down modestly. Higher liftings were more than offset by lower natural gas realizations. DD&A was higher due to the PDC acquisition and Permian growth. Adjusted downstream earnings were lower mainly due to lower refining margins and timing effects. Worldwide oil equivalent production was the highest first quarter in our company's history. Production was up over 12% from last year, including an increase of 35% in the United States largely due to the PDC Energy acquisition and organic growth in the Permian Basin. Looking ahead to the second quarter, we have planned turnarounds at TCO and several Gulf of Mexico assets. Following another strong quarter in the Permian, production is trending better than our previous guidance, and we now expect first half production to be down less than 2% from the fourth quarter. Impacts from refinery turnarounds are mostly driven by El Segundo and Richmond. We anticipate higher affiliate dividends in the second quarter largely from TCO. With the start-up of WPMP, we expect TCO's DD&A to increase by approximately $400 million over the remainder of the year. Share repurchases are restricted under SEC regulations through the Hess shareholder vote, after which we intend to resume buybacks at the $17.5 billion annual rate. We've published a new document with our consolidated guidance and sensitivities that will be updated quarterly and posted to our website the month prior to our earnings call. Back to you, Jake.

adjusted earnings $5.4 billion or $2.93 per share


Eimear P. Bonner: Thanks, Mike. We reported second quarter earnings of $4.4 billion, or $2.43 per share. Adjusted earnings were $4.7 billion, or $2.55 per share. Results in the quarter were impacted by downtime in Upstream that weighed on realizations, higher exploration expense and Downstream turnaround timing. Organic CapEx was $3.9 billion, in-line with budget. Our balance sheet remains one of the strongest in the industry, ending the quarter with a net debt ratio of 10.7%. Chevron generated solid cash flow of nearly $9 billion excluding working capital. Working capital lowered cash flow due to tax true-up payments outside the U.S. and a build in inventories. We expect about half of the working capital to unwind in the second half of this year, primarily in the fourth quarter. We again demonstrated our consistent approach to returning cash to shareholders with $6 billion of dividends and share repurchases. Adjusted earnings were lower by $700 million versus last quarter. Adjusted Upstream earnings were down mainly due to lower liftings, higher exploration expense and absence of favorable tax impacts from the prior quarter. Partly offsetting were higher realizations. Adjusted Downstream earnings were down due to lower margins and reduced capture rates, this was partially offset by timing effects. All Other decreased mainly due to a tax true-up. Versus last year, adjusted second quarter earnings were down $1.1 billion. Adjusted Upstream earnings were flat, higher realizations and liftings were mostly offset with higher DD&A due to the PDC acquisition and the absence of prior year favorable tax items. Adjusted Downstream earnings decreased mainly due to lower refining margins and higher turnaround and transportation OpEx. The Other segment was down primarily due to state tax adjustments. Worldwide oil equivalent production was up over 11% from last year due to the acquisition of PDC Energy and significant growth in the Permian Basin. Now, looking ahead. The third quarter will have heavier than usual maintenance with several turnarounds at Upstream assets, including TCO and Gorgon. Impacts from refinery turnarounds are mostly driven by El Segundo. There will be a one-time payment related to discontinued operations of around $600 million. We anticipate affiliate dividends to be around $1 billion this quarter. With the project in Kazakhstan nearing completion, we expect quarterly dividends from TCO moving forward. As a reminder, Chevron pays a 15% withholding tax on dividends from TCO which lowers both earnings and cash flow. Share repurchases are targeting the $17.5 billion annual guidance rate. Asset sales in the second half of the year are expected to be aligned with full-year guidance. Back to you, Mike.


Eimear Bonner: Thanks, Mike. We reported third-quarter earnings of $4.5 billion or $2.48 per share. Adjusted earnings were $4.5 billion or $2.51 per share. Organic CapEx was $4 billion for the quarter, in line with our budget. Our balance sheet remains one of the strongest in the industry, ending the quarter with a net debt ratio under 12%. Cash flow in the third quarter was the highest for the year despite lower oil prices. Working capital decreased by $1.4 billion on lower inventory levels. Share repurchases were a record $4.7 billion at the top end of our quarterly guidance range. Our financial priorities are unchanged, and we plan to use our strong balance sheet towards shareholders consistently through commodity cycles. Compared with last quarter, adjusted earnings were down about $150 million. Adjusted upstream earnings were down mainly due to lower realization and high dividend at TCO, partly offset by higher lifting. Adjusted downstream earnings increased primarily due to favorable timing effects and higher US volumes. This was partially offset by lower US refining margins. Adjusted third-quarter earnings were down $1.2 billion versus the same quarter last year. Adjusted upstream earnings were flat. Lower liquids realizations and higher DD&A were mostly offset by higher liftings and timing effects. Adjusted downstream earnings decreased mainly due to lower refining margins. All other was down primarily due to interest expense. Third-quarter oil equivalent production was up around 75,000 barrels per day from last quarter. Strong production in the Permian, primarily in our company-operated New Mexico assets, was the main driver. We expect full-year average production growth to finish at the top end of our guidance range of 4% to 7%. Costs always matter in a commodity business. We have a track record of managing unit costs well below inflation while successfully integrating several acquisitions. Higher returns require competitive costs and safe and reliable operations. Executing turnarounds on budget and on schedule is a key performance driver, and we have delivered outstanding performance in 2024. Our teams have collaborated across upstream and downstream to standardize the approach to these complex maintenance events, increasing the days our facilities are online and lowering unit costs. While we anticipate significant volume growth in the years ahead, we also expect to deliver $2 to $3 billion in structural cost reductions by the end of 2026. These cost savings will largely come from optimizing the portfolio, leveraging technology to enhance productivity, and changing how and where work is performed, including the expanded use of global capability centers. Now looking ahead, in the fourth quarter, Upstream will have downtime, which is expected to be split between US and international operations. Impacts to production from divestments are expected to be around 45,000 barrels of oil equivalent per day for the quarter. Downstream, we will have higher planned maintenance primarily at El Segundo and Pasadena. We will also have a shutdown at the Pasadena refinery, enabling the light tight oil expansion to come online. We anticipate affiliate dividends to be around $1 billion this quarter. Share repurchases are expected to be between $4 and $4.75 billion in the fourth quarter, unchanged from prior guidance. Proceeds from asset sales are expected to be about $8 billion before taxes. Back to you, Jake.


Eimear Bonner : Thanks, Mike. Chevron reported fourth quarter earnings of $3.2 billion, or $1.84 per share. Adjusted earnings were $3.6 billion, or $2.06 per share. Included in the quarter were special items totaling $1.1 billion related to restructuring and impairment charges. Foreign currency gains were $720 million. Full-year organic CapEx was aligned with our announced $16 billion budget. Inorganic CapEx of $530 million related mostly to lease acquisitions and new energies investments. We maintained double digit returns with adjusted ROCE of 10.5% for the year. Compared with last quarter, adjusted earnings were $900 million lower. Adjusted upstream earnings were impacted by revisions to asset retirement obligations and timing effects, including year-end inventory valuation. Adjusted Downstream earnings were lower due to softer refining and chemicals margins and timing effects. Chevron’s cash generation continued to position the company for long-term success while rewarding shareholders. In 2024, we Invested capital efficiently, growing production by 7%; Generated nearly $8 billion in proceeds from asset sales; sustained our long track record of dividend increases and repurchased 5% of shares outstanding; and maintained a strong balance sheet, ending the year with a net debt ratio of 10%. Chevron’s long-standing financial priorities have created value for shareholders. They have guided our actions through multiple commodity and investment cycles and will continue to govern how we allocate capital. Over the past five years we have grown our dividend faster than the S&P 500 and nearly double the rate of our closest peer. Today, we announced a 5% increase in the dividend, marking the 38th consecutive year with an annual increase to dividend payment per share. We’re committed to capital discipline. Only the most competitive projects in our portfolio will get funded. Where assets don’t compete for capital, we have a history of generating value commercially. The balance sheet is in excellent health, with net debt below our historical levels. We’ve repurchased shares 17 of the last 21 years and intend to maintain a buyback range of $10 to $20 billion per year depending on market conditions. Compared to our peers, we’re delivering growth with less capital and returning more cash to shareholders. In the past three years, we’ve returned $75 billion in cash to shareholders via dividends and share buybacks. Now, I’ll hand it back over to Mike to cover our near-term outlook.


Michael Wirth: Yes. So Josh, there's going to be some more capital, we said 3% to 5%. So think about around $1 billion Chevron share over 2024 and 2025, probably a little more weighted to 2024 than 2025. Cash flow from the operations will be lower by about $1.5 billion at $60 Brent in total over the next two years really due to the delay in the project. So it's equivalent to about 50,000 barrels a day in net production in each of those years. So in total, we expect our share of dividends to be lower by about $2.5 billion across 2024 and 2025 from the prior guidance. And so it's a combination of those things. And so we had previously guided to above $5 billion. We're now seeing above $4 billion and a little more of that coming from production and cash flow from ops as opposed to CapEx.


Eimear Bonner: Yes. It's been about 9 months since we closed with PDC Energy. We're really pleased with the progress that we're seeing, the synergies. On the CapEx side, to date, we've captured $500 million, which is $100 million more than what we had initially guided to. We're also seeing capture on the OpEx side as well. So we're nearing $100 million there. The teams are continuing to integrate. We're bringing the best of both companies together and building a development playbook focused on optimizing returns in the basin. We're realizing strong free cash flow from these assets. So we're ahead of pace for the incremental $1 billion in annual free cash flow that we guided to.


Lucas Hermann: Yeah. Thanks very much. And afternoon, Mike and Eimear. A fairly obvious question, I guess. I just wanted to talk to you. I wondered if both of you could talk a little bit more about CapEx going forward, and maybe it is an inappropriate time, and December will be better. But if I look at what is happening with the business, you know, obviously, Tengiz starts up. You have got your assets in the Gulf coming on, you are talking about, you know, driving for free cash or driving for NPV value in the Permian CapEx coming down there. If I think about the current rate of CapEx spend including, you know, associates, it feels as though it is around $18, $18.5 billion if you got at the beginning of the year. If I look at the opportunities for that CapEx to start to fall as projects or as plateau or projects come on, it feels as though, you know, maybe $3, $4 billion of CapEx opportunity sits there or opportunities to support CapEx decline. Yes. It is there. What is really hard, Mike, is to see, you know, where that goes. Particularly given, obviously, everything going on in the Eastern Meds at the moment. So, you know, is it right now to start thinking about CapEx coming down very materially as we move forward over the next two, three years, and you are really starting to benefit more emphatically from a portfolio that, in essence, is, you know, deep in resource but pretty long duration.


Michael Wirth: Yeah. So you have covered a lot of waterfront there, Lucas. Let me try to address some of it, then let Eimear share some of her thoughts. Number one, I think an important point is if you look at the rateability of our CapEx, we used to have a program that had a lot of big long-duration capital projects. There was a pattern where the back half of the year, fourth quarter in particular, tended to be a little bit heavier at first. Quarter a little bit lighter. We are very ratable now. We have been about $4 billion on our organic CapEx, you know, all three quarters this year. So it has become much more ratable and predictable. That is a reflection of the nature of the projects that we are doing. Point two, you talked about CapEx coming down. A decade ago, our CapEx was $40 billion. Today, you bring in affiliates, as you say, it is $18 something, $18.5 or whatever that number is. So it is less than half of where we were. So it has come down substantially even as production has grown, as the company generates more cash. We are doing it in a much more capital-efficient manner than we ever have before. And then point three is, yes, we will continue to seek further ways to optimize and improve the capital efficiency of our company. A larger portfolio does over time require capital to maintain it, and so, there lies the trade-offs that you evaluate as you look at your capital investment opportunities, the readiness of those, to move into execution. And I think in the near term, what is very clear is our affiliate CapEx will come down next year as the project in Kazakhstan concludes. So you will see affiliate CapEx come off. You know, we are in the process right now of finalizing our business plan for 2025. And so it is a bit premature for me to guide you to that number, but we are looking at all the trade-offs and then we will know more about that after we complete our planning process. But our intent is to stay very disciplined, which I think is something we have demonstrated here over, you know, many, many years now. Our guidance range of $14 to $16 billion is unchanged. And I think you should expect us to respect that. And if that does change, by some quantum and you throw out some larger numbers there, you know, we will cover that with everybody and talk about how it has changed, why it has changed, and how you should think about what that means going forward. Do you want to add anything to that?


Pierre Breber: And I'll just add some comments on affiliate dividends. So we've given a guide on fourth quarter affiliate dividends, which falls short of the full-year guide that we did at the start of the year. That shortfall is not from TCO, that's from CPChem, Chevron Phillips Chemical Company, on lower petchem margins. It's also from Angola LNG on lower TTF prices than we had assumed. We've also had some of the Angola LNG cash has come back to us as return to capital. In terms of TCO, we had a $600 million dividend Chevron share in the second quarter. We can't get ahead of the TCO Board on the fourth quarter. But 90% or so of the fourth quarter guide is related TCO. I'll remind you last year that TCO dividend was $1.6 billion Chevron share. All these numbers are before the withholding tax. So we'll see a pretty significant increase in the total year TCO dividend. Now some of that was the – getting some of the excess cash off the balance sheet like we were talking about. But if you go back to the period prior to the start of this construction, so the period into 2015, we're seeing dividends now – or this year's dividend will be similar to what we saw from that time period. So the inflection is happening after five years of either not receiving dividends or, in fact, putting cash out, essentially having negative free cash flow. So we know production is going to be down next year. We showed that. So you'd expect dividends to reflect that a little bit. We have a little bit of increase in CapEx. And then we'll be heading to this more than $4 billion in 2025. And all of that is – that guidance is at $60. So we're seeing some positive news in terms of the cash flow coming out. Clearly disappointing news on the revised schedule, but we're going to work hard to deliver it in the front end of the range. Thanks, Paul.


Josh Silverstein: Thanks. Good morning, guys. Going back to the Permian you're stepping up the CapEx this year to about $5 billion versus $4 billion last year to help you deliver the year-over-year growth. As you continue to ramp towards the million BOE per day target, what's needed from a CapEx standpoint to deliver this growth? Can you stay closer to the $5 billion range or does that step up towards $6 billion in 2025 because you have an accelerating pace to hit that? Thanks.


Pierre Breber: Yes. Consistent with what Mike just said, we're continuing to do cost affiliate accounting, which means we are not – we don't record production or reserves, right? So that's not reflected in our numbers. And we only record earnings when we receive cash. So we're not – we're recording a proportionate share of equity earnings, but only what we actually receive in cash. And that's something that we'll continue to look at. And as Mike said, depending on all those potential triggers down the road, elections and such, we could go back to equity accounting at some point in time. But we have not made that decision yet. In terms of cash flow, it's about 1% of our cash flow. So it's modest, of course. But it's more than it was before. And so as Mike said, operations there are continuing well. And we're getting a little bit of cash. And we'll just see where it goes from here.


Eimear Bonner: Yes. Josh, yes, so we had some commercial paper issued in the first quarter, and it was just to manage short-term liquidity. Timing of affiliate dividends can be a bit lumpy, repatriation of cash can be a bit lumpy. So this was normal business for us in the first quarter. I think in terms of what to expect in terms of cash on the balance sheet, I mean, we target to hold about $5 billion in cash, and that will bounce around as well. But I think $5 billion is a good number. We have access to lots of liquidity and commercial paper, bond investors, credit facilities. So while we've had higher cash in the balance sheet in the past, holding excess cash with low debt and lots of access to liquidity can be a drag in returns. So we're quite comfortable with the $5 billion cash, and that's a good number for you to focus on there.


Eimear Bonner : Hi, Biraj, thanks for the question. You're right. Cash flow, excluding working capital, was impacted by some non-recurring and accounting items this past quarter. So let me step you through the big ones. Maybe the first is we recognized some tax charges and earnings related to our recently completed Canadian asset sale, and that was around $1.5 billion. It's important to note that these tax charges are offset in working capital. But if you exclude the working capital when you're looking at cash flow, you're still going to see that tax charge. So that's a big one. That's the main one. The second one is we also recorded some charges in the quarter that for earnings, we had identified those as special items. We disclosed them back in December and our capital release. However, we don't make the same adjustments for these items and cash flow. So you're seeing some of that flow through to the bottom line, and that's about a $500 million headwind. Beyond those two items, we did have some other impacts, the combination of affiliate distributions, some unique commercial activity, and that's another $500 million. So when you add up the three elements, that's about $2.5 billion to take into consideration for the cash flow this quarter. So if you've got any additional questions on those pieces acknowledging they're a bit unusual this quarter. I mean Jake can follow up with you after the call and sure you how everything flows through. Thanks.


Biraj Borkhataria : Hi, thanks for taking my question. Firstly, congrats on getting FGP online. I know it’s a big project. So I wanted to ask about sort of underlying cash flow, excluding working capital. This quarter, at least versus our model the $5.3 billion was quite a bit with what we expected. So could you just walk me through how I should think about any one-offs in there? And help me understand what the sort of underlying basis should be as we think about ‘25? Thank you.

underlying cash flow excluding working capital this quarter


Joshua Silverstein: Yes. Thanks. Good morning, guys. On the TCO, you had mentioned that in 2025, you expect the cash flow to be about $1 billion lower, around $4 billion versus $5 billion previously. Is that just due to the project delays? Or is there higher cost estimates now in that, so it would be lower distributions from there? Or is there something else that's driving that?


Pierre Breber : Thanks, Mike. We reported first quarter earnings of $6.6 billion, or $3.46 per share. Adjusted earnings were $6.7 billion, or $3.55 per share. We had one special item this quarter related to changes in the energy profits tax in the United Kingdom. The appendix of this presentation contains a reconciliation of non-GAAP measures. Strong operating cash flow enabled Chevron to deliver on its financial priorities during the quarter a 6% per share dividend increase, higher CapEx within budget, net debt ratio under 5%, share repurchases at the top of our prior guidance range. Adjusted first quarter earnings were up over $200 million versus last year despite 20% lower oil prices. Adjusted Upstream earnings were lower mainly due to realizations and adjusted downstream earnings increased primarily due to higher refining margins. Both segments benefitted from a change in timing effects. Higher interest income and lower accruals for stock-based compensation decreased all other charges. Compared with last quarter, adjusted earnings were down $1.1 billion. Adjusted Upstream earnings decreased primarily due to lower realizations. Other items include the absence of last quarter’s dividend withholding tax at TCO and lower exploration and transportation expenses. Adjusted Downstream earnings were essentially flat. Lower margins and volumes were offset with higher chemical earnings and other favorable items including trading results. Lower accruals for incentive-based compensation decreased All Other net charges and also benefitted the operating segments First quarter oil equivalent production was down about 80,000 barrels per day from last year due to the expiration of a contract in Thailand and the sale of our Eagle Ford asset. This was partially offset by growth in the Permian. We expect 2023 production growth in the Permian to be back-end loaded as wells put on production, POPs increase across both operated and non-operated areas. We expect our royalty production to be roughly flat. As discussed during our Investor Day, we’re increasing activity in New Mexico. All four company-operated rigs added this year, one each quarter, will be in New Mexico, leading to more POPs expected in the second half of the year and into 2024. We also continue to be active in Texas. Last year, about half of our company-operated production was in the Delaware Basin in Texas with the remainder split about evenly between the Midland Basin and New Mexico. More than half of our non-operated production is with five major operators in large, contiguous positions in core areas with multiyear development programs, where we have visibility to capex and execution schedules and a royalty benefit compared to the operator. The balance is with dozens of other operators where we have a little less visibility, but similar predictability from greater diversification. More than half of our royalty production comes from the Pecos River area in the heart of the Delaware Basin. The balance of our royalty position is in the remainder of the Delaware and Midland Basins, also with well-known operators. In summary, Chevron has a large, diverse position in the Permian with a unique royalty advantage where we learn from our own operations and from others. Now, looking ahead. In the second quarter, we expect planned turnarounds at Gorgon and in the Gulf of Mexico along with downtime at a FSO in Thailand and a number of planned refinery turnarounds. Also, we expect share buybacks to increase to a $17.5 billion annual rate. In summary, 1Q was another quarter with strong financial results, continued capital discipline, and a steady return of cash to shareholders. We’re confident that consistent and straightforward management, through commodity cycles, will create value for stakeholders. Back to you, Jake.


Biraj Borkhataria: My first one is on portfolio concentration. So at your Analyst Day, you talked about just over $20 billion of free cash flow at $60 a barrel. And looking through today's slides, roughly half of that in the medium term will come from the Permian plus TCO. So I understand that you want every dollar to go to the highest level of return, which is completely sensible. But I was wondering if you can talk about portfolio concentration because it is quite unusual for a super major to have that level of concentration in terms of free cash flow. So how do you think about portfolio diversity? And is this something you're actively trying to address going forward? And I've got a follow-up on a different topic.


Pierre Breber: If I can just build off that and go to the return of capital question that Neil asked and that's what gives us confidence not only on the buyback, but on the track record of dividend growth. So, we guided to 10% annual free cash flow coming from all those businesses. Some are holding cash constant, some are growing cash flow that Mike covered. And that goes to leading dividend growth where we've grown the dividend over the last five years at rates double our closest peer and much higher than others, and where we have a buyback that is nearly 6% of our shares outstanding annually. Our business is built for $50. So part of the confidence in our ability – currently, if you look at our breakeven and adjust for working capital this quarter, if you look at the last four quarters, it's actually probably a little bit lower than that with the strong refining margins that we've been seeing. So we're built for lower prices. Free cash flow is going to grow from this base. That should give investors confidence in our ability to continue to grow the dividend at leading rates and to maintain buybacks at also very high rates.


free cash flow incremental $1 billion annual guided to


Michael K. Wirth: Yes. You could do something else if you wanted to. This is the transaction, that’s the right transaction for us. And so, we’re very focused on it, Alastair, and we’ve made good progress with the shareholder vote, we’re steadily marching along with the FTC, and I’ve already mentioned the timeline on the arbitration. So, it’s sometimes good things you have to work for and this will take a little bit more time than we had anticipated, but we remain confident in the outcome. And, as I tried to cover in our prepared remarks, we’ve got a really strong queue of organic growth opportunities in flight right now. We didn’t mention the Eastern Med, which is another one. So, we’ve got projects in multiple regions of the world that are poised to deliver growth over the next three years, absent it we be at 10% growth in free cash flow, we’ve got projects coming on in numerous basins in the world and in our chemicals business as well. So, we’re really focused on that and creating value there. But, if another opportunity were to present itself that were compelling, we’re certainly in a position to consider it. Thanks for the question.


Michael Wirth: Thank you, Jake. And thank you, everyone, for joining us today. Earlier this week, we announced several senior leadership changes, including Pierre's plans to retire next year, along with second quarter performance highlights. In a few minutes, Pierre will share more details on our financials, which included return on capital employed greater than 12% for the eighth consecutive quarter and another quarterly record in shareholder distributions of more than $7 billion. At TCO, we're making good progress with commissioning and pre-start up activities, including introducing fuel gas to new facilities. In the third quarter, we expect mechanical completion for the Future Growth Project and to complete a major turnaround. Cost and schedule guidance is unchanged. Conversion of the field from high-pressure to low-pressure is expected to begin late this year and FGP is on track to start up by mid-next year. We have unused contingency which gives us confidence that we'll complete the project within the total budget. After completion of these projects, TCO is expected to deliver production greater than 1 million barrels of oil equivalent per day and generate about $5 billion of free cash flow – Chevron share at $60 Brent – in 2025. Chevron's Permian production set another record in the second quarter, about 5% above the previous quarterly high. We expect next quarter's production to be roughly flat before growing again in the fourth quarter, on track with our full-year guidance. Early 2023 well performance in our company-operated assets, in all three areas, is consistent with our plans. In New Mexico, we've put on production at 10 wells. Before year-end, we expect to POP an additional 30 wells with higher expected production rates. As a reminder, about half of Chevron's Permian production is company operated, with the balance non-operated and royalty production. While short-term well performance is one measure, we're focused on maximizing value from our unique, large resource base that is expected to deliver decades of high-return production. Over the next five years, we expect to develop over 2,200 net new wells, growing production while delivering return on capital employed near 30% and free cash flow greater than $5 billion in 2027 at $60 Brent. Longer term, we've identified well over 6,000 economic net well locations that support a plateau greater than 1 million barrels per day through the end of next decade. Our deep resource inventory and advantaged royalty position allow us to optimize our development plans for high returns, incorporating learnings and technology improvements, as we expect to deliver strong free cash flow for years to come. In the deepwater Gulf of Mexico, the floating production unit at Anchor is on location and the project remains on track for first oil next year. We continue to build on our exploration success and were awarded the highest number of blocks in the most recent lease round. In the Eastern Med, our Aphrodite appraisal well in Cyprus met our expectations and we've submitted a development concept to the government. At Leviathan, we're expanding pipeline capacity to nearly 1.4 BCF per day. We expect to close our acquisition of PDC Energy in August after their shareholder vote next week. Our teams are working on integration plans and we look forward to welcoming PDC's talented employees to Chevron. Now, over to Pierre.


Eimear Bonner: Yes. Thanks, Mike. Yes, Sam, well, after years of investing, as the project starts up over the next couple of years, we do expect the CapEx profile to continue to decline, and that will enable free cash flow over the next couple of years to grow. With WPMP, it will keep the plants full. So this will allow IBS business to generate significant cash, and that will be available for distribution. With the second phase of the project then next year in '25, TCOs free cash flow is going to grow even further because with that phase of the project, we get incremental production. So what does this mean for Chevron? Well, we expect $4 billion of free cash flow in 2025 and $5 billion in 2026. This is a $60 Brent. This will flow to us through a combination of dividends, so you'll see this come through cash flow from operations and loan repayments, which will flow through cash for investing. So we do expect dividends this year. We have guidance -- affiliate guidance to dividends for 2024. But we've also included in the deck today the outlook for affiliate dividends for the second quarter, $1 billion to $1.5 billion. And a significant portion of that is an assumption around TCO.


Mike Wirth : Thanks, Eimear. Chevron is in a strong position today, with near-term catalysts that are expected to drive the company to even better performance in 2025 and 2026. Our objective is unchanged, to safely deliver higher returns and lower carbon. In the next two years, we plan to achieve industry leading free cash flow growth; further strengthen our portfolio, including the expected completion of the Hess transaction in the third quarter; advance opportunities in renewable fuels, hydrogen, CCUS and power; while maintaining cost and capital discipline. It's important to note that the guidance provided today exclude tests, we continue to be very confident in assets position in arbitration. We plan to host our next Investor day with the longer term outlook after we close the transaction later this year. Chevron is poised for industry-leading free cash flow growth. We expect to add $10 billion of annual free cash flow in 2026, led by growth and advantaged upstream assets. With additional production from FGP and a further reduction in affiliate CapEx, we expect a sustained increase in distributions from TCO going forward. In the Gulf of America, where we produce some of the highest margin barrels in our portfolio, we'll have additional growth as Anchor and Whale continue to ramp up and we bring Balimore online. And in the Permian, we're focused on operational efficiency and free cash flow, positioning the asset as a core cash generator for the company. We're also executing plans to deliver stronger results across the entire portfolio, including cash savings from our targeted $2 billion to $3 billion reduction in structural costs and improved returns in our Downstream and Chemicals businesses. At TCO, we achieved first oil at FGP last week. This important milestone is the result of consistent, disciplined execution by the project and operations teams. Our focus remains on a safe and reliable ramp-up of the plant. FGP adds 260,000 barrels of oil production capacity to the existing plants. We expect to achieve full production rates 1 million barrels of oil equivalent per day – within the next three months. At $70 Brent, expected free cash flow to Chevron is $5 billion in 2025 and $6 billion in 2026. This includes fixed loan repayments and quarterly dividends. We are proud to bring this large, complex project online for the benefit of our shareholders and the Republic of Kazakhstan and look forward to future collaboration to maximize the long-term value of the Tengiz reservoir. In 2024, execution efficiencies led to strong well and base business performance, helping us achieve another record for Permian production. Over the last five years, we’ve delivered compound annual growth of 16% while continuing to capture efficiencies. Through optimized pad and drilling designs, and completions improvements like triple frac, we’re able to achieve these production levels with 40% fewer company-operated rigs than our plans included just a few years ago. We expect production to reach one million barrels of oil equivalent per day in 2025, and plan to moderate growth and CapEx to drive predictable and durable free cash flow generation. Our Permian portfolio delivers superior returns due to royalty advantaged acreage across all of the sub-basins, which add to both the top and bottom-line. We’re continuing to develop and deploy technologies to enhance efficiencies and recoveries. We’re leveraging our strengths in advanced chemicals and stimulation and scaling them across our shale and tight portfolio. Our world-class upstream assets provide further growth opportunities that are poised to deliver value for decades. In the Gulf of America, where we expect to grow production to 300,000 barrels of oil equivalent a day, we achieved first oil at the Anchor and Whale projects, and Ballymore is expected to come online around the middle of this year. In Western Australia, our discovered resource has the ability to keep our LNG plants full for decades. Last month, we announced an asset swap that will increase our equity in Wheatstone, which enables long-term asset development and monetization. In West Africa, we have a queue of low-cost developments that are expected to sustain production for many years. We recently extended leases in Nigeria and had a shelf discovery that will tie back to existing infrastructure. In Angola, we achieved first gas at the Sanha Lean Gas Connection project, and we plan to bring online our South N’dola development later this year. In the Eastern Mediterranean, we have a significant resource position we’re continuing to unlock. Expansion projects at Leviathan and Tamar are expected to come online through the end of the decade. Turning to our Downstream and Chemicals businesses, we’re focused on operating reliably and efficiently while executing competitive projects that extend our value chains and capture market synergies. The recently completed expansion at our Pasadena refinery enhances our integrated value chain by running more Permian crude, supplying more products to our regional marketing business and expanding synergies with the Pascagoula refinery. Our petrochemical growth projects in the U.S. and Qatar are more than 50% complete and are expected to contribute to further cash flow growth beyond 2026. Both projects are feedstock advantaged, have competitive cost structures and are well-positioned to serve growing demand. We have several projects in our New Energies business that are expected to achieve key milestones in the next two years. In renewable fuels, we’re in final commissioning of the Geismar renewable diesel expansion and at our Bunge joint venture, construction continues at the new oilseed processing plant in Louisiana, increasing our exposure across the renewable fuels value chain. We’re working towards start-up of the ACES green hydrogen project in Utah later this year, which will produce hydrogen from water and excess renewable power and store it underground for dispatchable lower carbon power generation. The project is one of the world’s largest hydrogen storage projects and will have over 200 megawatts of electrolyzer capacity. In carbon capture and storage, Bayou Bend is working towards a FEED decision for the offshore project, and we’re also developing plans to capture and store CO2 from our Pascagoula refinery. Earlier this week we announced plans to jointly develop scalable, reliable power solutions to support growing energy demand from U.S. data centers. Chevron is positioned to participate in this growth and generate competitive returns through integration with our U.S. natural gas business; Experience in building and operating nearly five gigawatts of reliable, behind-themeter power; and Expertise in technologies that can help provide a pathway to reduce GHG emissions. We've secured slot reservations to purchase seven natural gas fired turbines from GE Vernova with deliveries beginning late 2026, and we’re advancing site selection and engineering work while engaging customers. We look forward to sharing more as our plans develop. I’ll hand it back to Eimear to close out our guidance for 2025 and 2026.


Eimear Bonner : Jason, yes, I can talk to that. The free cash flow inflection that's coming with -- which is actually upon us now that the asset has started up. So we shared in the slide, $5 billion for 2025 and $6 billion for 2026. What's contributing there is obviously the production but also the affiliate CapEx is coming down. So with the project completing and the affiliate CapEx is reducing significantly. And so that's resulted in the free cash flow. We also anticipate that as the plant gets [indiscernible] and the safe and reliable start-up completes that they'll be focused as well on operational OpEx and optimizing that, given the new base business of 1 million barrels a day that they will have. So that can move around a little bit during the year. But generally, we have OpEx coming down there, too. So those are two things that are contributing to the free cash flow in addition to the production.


Mike Wirth : Is -- there a maximum -- I mean it's limited by our position there and the entities that we're involved in and what our portion of that production that we're entitled to market is. We're currently seeing about 100,000 barrels a day of production up from about 50 when the license term changed. That actually go up further this year, maybe another 50% if everything goes well. The rude comes to the U.S., and we're finding a market for the crude. And yeah, it's a six-month license from OPEC, and we have to bear that in mind. So that's why we are proceeding, as you said, which is we've got some past receivables that are being paid from some of these proceeds and there's a lot of relatively straightforward workover and other activity that can help bring production up at -- without major capital commitments. And so that's the current model. We'll see how things unfold and hopefully pointed in a good direction, but it's been a bit of an up and down situation, and we have to -- we just have to take this one step at a time.


Michael Wirth: Yes. And I might give you some kind of broader commentary on Permian performance as well. Overall, production was down just a little bit, about 2% in the quarter. That was entirely driven by non-operated joint ventures. And primarily, a couple of the operators had delays in putting wells online due to frac hits and some other factors. There was also some takeaway capacity on the Permian highway that – constraints that resulted in some unplanned downtime. So co-op production in the third quarter was essentially flat from the prior quarter, which is what we had guided to. And that's despite having some wells that were choked back due to some surface constraints. In one development area, we're seeing higher-than-expected CO2 content in the gas and others in the area are as well. So we've got third-party handling and process facilities that are constrained by that and can't handle all the CO2. So we're choking wells back. There's a new federal regulation that I won't get into the details. But it affects how we meter production. And it prevents co-mingling. And so we've got wells choked back until we can get some new meters in place. And then we've got some produced water limits that have come into effect in some areas. So there's a number of things that are not indicative of well performance, but other surface realities that we're working on our way through that are impacting co-op production a little bit. In New Mexico, you're right. We got more POPs in the second half of the year. We've POP-ed about 60% of the planned wells in New Mexico. So the balance, almost half, come on in the fourth quarter. POP performance has generally been strong. Some of those wells are hit by the facility constraints that I've talked about. But overall, well performance is aligned with our type curve expectations. I think when we get to the fourth quarter call, Biraj, we'll come back with some more detail on type curves. We'll have enough of them online. We'll have enough months that we can start to give you some of the same kind of evidence that we did last quarter to show you the performance.


Michael Wirth: Thanks, Jake, and thank you, everyone, for joining us today. Chevron continues to deliver strong operational performance, maintain cost and capital discipline and consistently return cash to shareholders. First quarter marked 9 consecutive quarters with adjusted earnings over $5 billion and adjusted ROCE above 12%. During the quarter, we also returned $6 billion in cash to shareholders, the eighth straight quarter over $5 billion. We also grew production more than 10% from the same quarter last year and announced final investment decisions to grow our renewable fuels and hydrogen businesses. Earlier this month, we announced our third Future Energy Fund focused on venture investments in lower-carbon technologies. The merger with Hess is advancing, and we intend to certify substantial compliance with the FTC second request in the coming weeks. We believe that a preemption right does not apply to this transaction and are confident this will be affirmed in arbitration. We expect the proxy for the Hess shareholder vote to be mailed in April with a special meeting date in late May. This strategic combination creates a premier energy company with world-class capabilities and assets to deliver superior shareholder value, and we look forward to bringing the 2 companies together. At TCO, we had achieved start-up of WPMP this month with the first inlet separator and pressure boost compressor in service and conversion of the first metering station to low pressure now complete. Later this quarter, we expect a second pressure boost compressor online and a third gas turbine generator to provide power to the Tengiz grid. Metering station conversions are planned through the remainder of the year as additional pressure boost compressors start up, keeping the existing plants full around planned SGI and KTL turnarounds.


Michael Wirth: Alright. Thanks, Jake. This quarter, Chevron delivered strong financial and operational results, returned record cash to shareholders, and achieved project milestones that are expected to deliver production and cash flow growth over the coming years. We continue to see strong performance in the Permian, executed major turnarounds at TCO and Gorgon ahead of schedule. Worldwide production increased by 7% from the prior year and set a third-quarter record. We started up the high-pressure anchor project and began water injection to boost production at the Jack Saint Melo and Tahedi fields. These projects, combined with additional project startups through 2025, are expected to grow Gulf of Mexico production to 300,000 barrels per day by 2026. We have expanded our CO2 storage portfolio, adding over two million acres offshore Western Australia. In September, the FTC completed its review of the company's merger with Hess. We also recently announced several asset sales as part of our ongoing portfolio optimization efforts. This quarter marked the one-year anniversary of the PDC Energia Position. We have successfully combined the two companies, taking best practices from both and applying them across our shale and tight portfolio. We have exceeded our guidance of $500 million in combined capital and cost synergies by more than 30% and have delivered more than $1 billion in incremental free cash flow since acquiring PDC. Jurn's well performance is 40% better than the DJ Basin average, and we continue to optimize development plans. We have advantaged inventory, with around 75% of locations at a breakeven below $50 per barrel. We expect to hold production at a plateau around 400,000 barrels of oil equivalent per day through the end of the decade. Our operations in Colorado are among the lowest carbon intensity in the industry, benefiting from tankless production facilities that lower greenhouse gas emissions by 90% compared to older designs. Where possible, we utilize grid-powered rigs that reduce more than 60% of our on-site greenhouse gas emissions from drilling. At TCO, the team continues to deliver consistent progress on project milestones. All four Pressure Boost facilities are now online and operating with high reliability. All production is flowing through these facilities, which allows optimization of existing plants and enabled the highest daily production in the field's 31 years of service. Remaining metering stations are all under conversion, and we are confident in the incremental well capacity that will feed FGP. We have initiated final leak testing for the wet sour gas compressors and are preparing the crude processing systems for operation. Complex commissioning activities will continue over the coming months, leading into initial startup activities in the first quarter of 2025. We continue to divest non-core positions at significant value. We have announced asset sales in Canada, Alaska, and Congo, which will contribute before-tax proceeds of approximately $8 billion pending regulatory approvals. We expect to close these transactions in the fourth quarter. In Canada, we received a compelling offer for our Kaybob Duvernay shale position and non-operated interest in the Athabasca Oil Sands project. Both are good assets, and we have a long history there, but they are a better fit for a reputable counterparty and an attractive deal value for Chevron. Now, I will turn it over to Eimear to discuss the financials.


Mike Wirth : Yeah. So first of all, we're really pleased to see tensions diminishing in the region and hopefully a lasting piece for the people there. The headline is there's no real change to our plans, John. We expect projects that are in execution at both Tamar and Leviathan to come online by the end of the year or into early 2026. There was a pipelay vessel that was demobilized during kind of the height of the conflict. That vessel will be remobilized here during the first half of this year to complete the work that it had underway. So the next leg of growth after those two projects would be a Leviathan expansion. We're currently in feed for that. It would be a significant growth in production for Leviathan. Still work to be done but that's a project that would come online towards the end of this decade and continue to step up the production on that asset significantly. So despite all the activity we've seen in that region, we'll see production up by 25% over the next two years and something closer to 50% by 2030.


Eimear Bonner : Thanks, Mike. In a cyclical commodity business, capital and cost discipline always matter. Chevron’s CapEx and affiliate capex budgets reflect our commitment to capital efficiency while funding a balanced portfolio of short and long-cycle investments. Organic CapEx is expected to remain within our $14-16 billion guidance range. As spend in the Permian and Gulf of America comes down, capital will flow elsewhere within the portfolio to support continued growth. Affiliate c is expected to trend down further as investments at TCO and CPChem come online. We’re targeting $2 billion to $3 billion in structural cost reductions by the end of 2026. Work is underway to deliver these savings through asset sales; scaling technology solutions, such as expanding the use of robotics; and changing how we work to improve efficiencies. We’re executing our plans to lower absolute costs while delivering growth. Last year, worldwide oil equivalent production was the highest in our history, benefitting from a larger position in the DJ Basin following our acquisition of PDC Energy and nearly 18% growth in the Permian. Excluding asset sales, we expect production to grow around 6% annually through 2026. In 2025, we expect growth to be weighted towards the second half of the year as key projects in Tengiz and the Gulf of America come online and ramp throughout the year. We’re excited about the year ahead. We’re focused on delivering growth across advantaged assets and value chains while reducing absolute costs; starting up profitable New Energies projects and advancing new behind-the-meter power solutions; and continuing to reward our shareholders with higher returns and a differentiated value proposition. I’ll now hand it off to Jake.


Michael K. Wirth: Thanks, Jake. This quarter, Chevron delivered strong production and extended our track record of consistent shareholder returns. Production increased by more than 11% from the prior year and included a new quarterly record in the Permian. Over the past two years we’ve returned over $50 billion to shareholders, approximately 18% of our market cap. We continued to advance growth opportunities in our traditional and new energies businesses through adding new exploration plays in West Africa and South America, achieving key milestones on the ACES green hydrogen project and commissioning of the Geismar renewable diesel plant expansion, which is expected to come online by the end of the year. The merger with Hess achieved a successful shareholder vote, and we now expect the FTC review process to conclude in the third quarter. The arbitration panel addressing the Stabroek JOA has set a hearing for next year. Hess had requested an earlier hearing, but the panel ultimately sets the schedule. We remain confident this is a straightforward matter and the outcome will affirm a preemption right does not apply. We’re committed to the merger and look forward to combining the two companies. In the Gulf of Mexico, we’re leveraging our deepwater expertise with plans to deliver high cash-margin, low carbon intensity production growth. First oil at Anchor is imminent, delivering the industry’s first deepwater 20,000 pound development. The project is on-track to come in under budget while deploying multiple breakthrough technologies. After Anchor, three more projects are scheduled to come online and we expect production to grow to 300,000 barrels a day by 2026. Our developments have become more capital-efficient, unit drilling costs have come down and facility designs are optimized for high returns. As one of the largest leaseholders in the basin, we’re well-positioned for the future with leading technology capability and attractive exploration opportunities near existing infrastructure and in frontier areas. In the Permian, base business performance continues to improve, with higher reliability and lower decline rates. Development activity continues to get more efficient. We’re one of the first operators to deploy triple-frac, delivering cost reductions of more than 10% and shortening completion times by 25% where applied. In the Delaware Basin, company-operated well performance continues to improve as we optimize development strategies. In the Midland Basin, early well results are lower versus last year, our program in the second half of the year is more heavily weighted to development targets that we expect to perform better. With strong momentum in our operated portfolio and predictable results from our non-operated and royalty acreage, we now expect full-year production growth of about 15% and fourth quarter production to average around 940,000 barrels per day. At TCO, cost and schedule guidance is unchanged, with FGP expected to start up in the first half of 2025. We continue to bring major equipment online and complete key project milestones. Eight out of 21 metering stations have been converted to low pressure. Three Pressure Boost Facility compressors are in operation. A third gas turbine generator is in service. The first 3GP process system is ready for operation, and we completed the SGI turnaround on time and under budget. The wells converted to low pressure are meeting expectations and the Pressure Boost Facilities are operating with high reliability. Over the next two quarters, we’ll continue converting the field to low pressure while further commissioning key equipment for FGP. The project team remains focused on completing the project safely and starting up reliably to deliver value to Kazakhstan, TCO and shareholders. This quarter was a little light due to some operational and other discrete items that impacted results, but I remain confident we’re well-positioned to deliver on long-term earnings and cash flow growth. Now, I’ll turn it over to Eimear to cover the details.

production growth 300,000 barrels a day by 2026


Pierre Breber: Thanks, Mike. We delivered another quarter with strong earnings, cash flow and ROCE. This quarter's results included two special items: a one-time tax benefit of $560 million in Nigeria and pension settlement costs of $40 million. Foreign currency benefits were $285 million. The appendix of this presentation contains a reconciliation of non-GAAP measures. Organic CapEx this quarter included about $200 million for PDC legacy operations after closing in August. Our balance sheet remains strong, ending the quarter with a net debt ratio in the single digits. Another quarter of solid cash flow enabled us to deliver on all of our financial priorities. Despite restrictions during the PDC transaction, we were able to repurchase well over $3 billion in Chevron shares. Cash used to reduce debt was primarily related to PDC's higher cost borrowing. Cash balances ended the quarter near $6 billion, a little above what's needed to run our businesses. Adjusted third quarter earnings were down $5.1 billion versus the same quarter last year. Adjusted upstream earnings were lower mainly due to realizations and negative timing effects. Higher unfavorable discrete tax charges and exploration expenses were partly offset by lower DD&A, Venezuela cash recoveries and other favorable items. Adjusted downstream earnings decreased primarily due to a negative swing in timing effects and lower marketing margins. Compared with last quarter, adjusted earnings were down just over $50 million. Adjusted upstream earnings were roughly flat as higher prices and volumes were offset by unfavorable discrete tax charges and negative timing effects due to the rise in prices. DD&A and OpEx were both higher in part due to the addition of PDC legacy assets for two months in the quarter. Adjusted downstream earnings increased primarily due to higher refining margins, partially offset by unfavorable timing effects. All other was down on unfavorable tax items and decreased interest income in line with lower cash balances. Third quarter oil equivalent production was up 6% over last quarter primarily due to two months of legacy PDC production. This was partly offset by a planned turnaround at TCO and pitstop at Gorgon. The Permian, excluding legacy PDC, was down 2% due to lower non-operated production; company-operated production was flat with the second quarter. Now, looking ahead. Our fourth quarter estimate for turnarounds and downtime includes approximately 30,000 barrels of oil equivalent per day for Tamar. We anticipate affiliate dividends in the fourth quarter to be largely from TCO. As a reminder, we record a 15% withholding tax on TCO dividends. Due to the pending transaction with Hess, share repurchases will be restricted pursuant to SEC regulations. Chevron expects share repurchases in the fourth quarter to be around $3 billion plus or minus 20%, depending primarily on the timing of the Hess definitive proxy statement mailing. In summary, our actions and performance show that Chevron keeps delivering strong results. With a strategy that remains clear and consistent, we are well positioned to deliver value to our shareholders in any environment. With that, I'll turn it back to Jake.


Michael Wirth: Yes. We've had a very consistent set of financial priorities for many, many years. The first of which is to sustain and grow the dividend, 36 consecutive years now of per share dividend payouts for the last five years has been a 6% CAGR. Actually, I think the last 15 years have been a 6% CAGR and an announcement of 8% early next year, subject to Board approval. I think there's a strong track record there you can expect to continue. Second is to be disciplined in organic reinvestment into the business to grow those cash flows. You can be confident that we will continue to be disciplined in that reinvestment to drive returns and value. Number three is a strong balance sheet. Pierre mentioned we're single-digit net debt ratio today. That's lower than we have guided to over time. And so over time, you can expect the balance sheet to move back towards the 20% to 25% gearing range that we've identified as where we're comfortable through the cycle. And then the fourth are the share repurchases. And we've got a range now of $10 billion to $20 billion. We're at the high end of that range when we close the transaction with Hess with $17.5 billion annually. Today, that's 5% to 6% of our float each and every year. And we've – I won't go through the details, but we've indicated we can sustain that in a lower price environment. And that's where the lower end of that range would apply. And certainly in a higher price environment, which is where we find ourselves today, we're at the high end of that range. And so we would expect to be consistent, predictable and to sustain that. I mean, consistent and durable being the keywords here. So I think the broad framework is likely to remain unchanged. And I think our behavior will be very consistent with what you've come to see from us historically.

share repurchases $10 billion $20 billion

share repurchases $10 billion to $20 billion


We continue to make significant progress on FGP and expect to have additional major equipment ready for operations in the third quarter. Costs and scheduled guidance remain unchanged with FGP expected to start up in the first half of 2025. Now over to Eimear to discuss the financials. Eimear Bonner: Thanks, Mike. We delivered another quarter of strong earnings, ROCE and cash returns to shareholders. We reported first quarter earnings of $5.5 billion or $2.97 per share. Adjusted earnings were $5.4 billion or $2.93 per share. Cash flow from operations was impacted by an approximate $300 million international upstream ARO settlement payment and $200 million for the expansion of the retail marketing network. We also had a working capital build during the quarter consistent with historical trends. Chevron delivered on all of its financial priorities during the quarter, an 8% increase in dividend per share; organic CapEx aligned with ratable budget inclusive of progress payments for new LNG ships; sustained net debt in the single digits while issuing commercial paper to manage timing of affiliate dividends and working capital; and share repurchases of $3 billion. Adjusted earnings were lower by $1 billion versus last quarter. Adjusted upstream earnings were down due to lower realization and liquids liftings. Partly offsetting were favorable tax impacts. Adjusted downstream earnings were lower mainly due to timing effects associated with the rising commodity price environment. All other decreased on higher employee costs and an unfavorable swing in tax items. Adjusted first quarter earnings were down $1.3 billion versus last year. Adjusted upstream earnings were down modestly. Higher liftings were more than offset by lower natural gas realizations. DD&A was higher due to the PDC acquisition and Permian growth. Adjusted downstream earnings were lower mainly due to lower refining margins and timing effects. Worldwide oil equivalent production was the highest first quarter in our company's history. Production was up over 12% from last year, including an increase of 35% in the United States largely due to the PDC Energy acquisition and organic growth in the Permian Basin. Looking ahead to the second quarter, we have planned turnarounds at TCO and several Gulf of Mexico assets. Following another strong quarter in the Permian, production is trending better than our previous guidance, and we now expect first half production to be down less than 2% from the fourth quarter. Impacts from refinery turnarounds are mostly driven by El Segundo and Richmond. We anticipate higher affiliate dividends in the second quarter largely from TCO. With the start-up of WPMP, we expect TCO's DD&A to increase by approximately $400 million over the remainder of the year. Share repurchases are restricted under SEC regulations through the Hess shareholder vote, after which we intend to resume buybacks at the $17.5 billion annual rate. We've published a new document with our consolidated guidance and sensitivities that will be updated quarterly and posted to our website the month prior to our earnings call. Back to you, Jake.


Eimear P. Bonner: Thanks, Mike. We reported second quarter earnings of $4.4 billion, or $2.43 per share. Adjusted earnings were $4.7 billion, or $2.55 per share. Results in the quarter were impacted by downtime in Upstream that weighed on realizations, higher exploration expense and Downstream turnaround timing. Organic CapEx was $3.9 billion, in-line with budget. Our balance sheet remains one of the strongest in the industry, ending the quarter with a net debt ratio of 10.7%. Chevron generated solid cash flow of nearly $9 billion excluding working capital. Working capital lowered cash flow due to tax true-up payments outside the U.S. and a build in inventories. We expect about half of the working capital to unwind in the second half of this year, primarily in the fourth quarter. We again demonstrated our consistent approach to returning cash to shareholders with $6 billion of dividends and share repurchases. Adjusted earnings were lower by $700 million versus last quarter. Adjusted Upstream earnings were down mainly due to lower liftings, higher exploration expense and absence of favorable tax impacts from the prior quarter. Partly offsetting were higher realizations. Adjusted Downstream earnings were down due to lower margins and reduced capture rates, this was partially offset by timing effects. All Other decreased mainly due to a tax true-up. Versus last year, adjusted second quarter earnings were down $1.1 billion. Adjusted Upstream earnings were flat, higher realizations and liftings were mostly offset with higher DD&A due to the PDC acquisition and the absence of prior year favorable tax items. Adjusted Downstream earnings decreased mainly due to lower refining margins and higher turnaround and transportation OpEx. The Other segment was down primarily due to state tax adjustments. Worldwide oil equivalent production was up over 11% from last year due to the acquisition of PDC Energy and significant growth in the Permian Basin. Now, looking ahead. The third quarter will have heavier than usual maintenance with several turnarounds at Upstream assets, including TCO and Gorgon. Impacts from refinery turnarounds are mostly driven by El Segundo. There will be a one-time payment related to discontinued operations of around $600 million. We anticipate affiliate dividends to be around $1 billion this quarter. With the project in Kazakhstan nearing completion, we expect quarterly dividends from TCO moving forward. As a reminder, Chevron pays a 15% withholding tax on dividends from TCO which lowers both earnings and cash flow. Share repurchases are targeting the $17.5 billion annual guidance rate. Asset sales in the second half of the year are expected to be aligned with full-year guidance. Back to you, Mike.

share repurchases second half of the year


Eimear Bonner: Thanks, Mike. We reported third-quarter earnings of $4.5 billion or $2.48 per share. Adjusted earnings were $4.5 billion or $2.51 per share. Organic CapEx was $4 billion for the quarter, in line with our budget. Our balance sheet remains one of the strongest in the industry, ending the quarter with a net debt ratio under 12%. Cash flow in the third quarter was the highest for the year despite lower oil prices. Working capital decreased by $1.4 billion on lower inventory levels. Share repurchases were a record $4.7 billion at the top end of our quarterly guidance range. Our financial priorities are unchanged, and we plan to use our strong balance sheet towards shareholders consistently through commodity cycles. Compared with last quarter, adjusted earnings were down about $150 million. Adjusted upstream earnings were down mainly due to lower realization and high dividend at TCO, partly offset by higher lifting. Adjusted downstream earnings increased primarily due to favorable timing effects and higher US volumes. This was partially offset by lower US refining margins. Adjusted third-quarter earnings were down $1.2 billion versus the same quarter last year. Adjusted upstream earnings were flat. Lower liquids realizations and higher DD&A were mostly offset by higher liftings and timing effects. Adjusted downstream earnings decreased mainly due to lower refining margins. All other was down primarily due to interest expense. Third-quarter oil equivalent production was up around 75,000 barrels per day from last quarter. Strong production in the Permian, primarily in our company-operated New Mexico assets, was the main driver. We expect full-year average production growth to finish at the top end of our guidance range of 4% to 7%. Costs always matter in a commodity business. We have a track record of managing unit costs well below inflation while successfully integrating several acquisitions. Higher returns require competitive costs and safe and reliable operations. Executing turnarounds on budget and on schedule is a key performance driver, and we have delivered outstanding performance in 2024. Our teams have collaborated across upstream and downstream to standardize the approach to these complex maintenance events, increasing the days our facilities are online and lowering unit costs. While we anticipate significant volume growth in the years ahead, we also expect to deliver $2 to $3 billion in structural cost reductions by the end of 2026. These cost savings will largely come from optimizing the portfolio, leveraging technology to enhance productivity, and changing how and where work is performed, including the expanded use of global capability centers. Now looking ahead, in the fourth quarter, Upstream will have downtime, which is expected to be split between US and international operations. Impacts to production from divestments are expected to be around 45,000 barrels of oil equivalent per day for the quarter. Downstream, we will have higher planned maintenance primarily at El Segundo and Pasadena. We will also have a shutdown at the Pasadena refinery, enabling the light tight oil expansion to come online. We anticipate affiliate dividends to be around $1 billion this quarter. Share repurchases are expected to be between $4 and $4.75 billion in the fourth quarter, unchanged from prior guidance. Proceeds from asset sales are expected to be about $8 billion before taxes. Back to you, Jake.


Howard Ungerleider: Thank you, Jim. We expect the challenging macroeconomic dynamics to continue through the fourth quarter, including sluggish industrial activity. Global Manufacturing PMI has declined for the 13 consecutive month in September. It also includes weak demand in Europe and a slower-than-expected recovery in China. While inflation continues to moderate, it remains at elevated levels, resulting in a continuation of a tighter monetary policy. In the U.S., we're seeing some mixed indicators as September manufacturing PMI improved to 49.8. Retail sales growth remains positive, while consumer confidence has declined for the last two months. In Europe, industrial and consumer demand remains weak despite sharply lower inflation. PMI has contracted for 15 consecutive months through September, and consumer confidence remains low. With that said, automotive demand is showing signs of resilience. In China, while manufacturing PMI remained in expansionary territory in September, China exports fell for the fifth straight month. Automotive sales and production are a bright spot, rising in August, both sequentially and over the prior year in September. Around the rest of the world, India's manufacturing PMI remains expansionary, while in Mexico, industrial production rose for more than 20 months in August. However, ASEAN manufacturing PMI contracted for the first time in two years in September. Against this macroeconomic backdrop, we will continue to take a disciplined approach to managing our operations while leveraging our diverse global portfolio and our cost-advantaged assets. Turning to Slide 6. Our commitment to financial and operational discipline continues to be reflected in the proactive actions we are implementing to lower our costs and maximize cash flow. We achieved $700 million in cost savings year-to-date and remain on track to deliver our $1 billion commitment in 2023. In addition, we are further enhancing our financial flexibility as we execute on our capital allocation priorities across the economic cycle. For example, we're implementing continued actions to improve our working capital to maximize cash flow. As a result, our cash conversion cycle has improved by approximately eight days from pre-COVID levels and we have unlocked approximately $600 million of cash from working capital in the third quarter. Since Spin, we have taken actions to strengthen our balance sheet, ensuring ample liquidity while reducing net debt and pension liabilities, and we are continuing to take actions to further derisk our pension plans. Now pension-funded status has greatly improved, driven primarily by changes in the discount rate and the $1 billion voluntary contribution we made in 2021. Our decision to freeze the U.S. deferred benefit plans at year-end '23 further reduced the pension liability. We expect to pursue additional derisking opportunities for our pension plans in the fourth quarter, including annuitization and risk transfer of some pension liabilities. If these transactions are executed, we expect to record a onetime noncash and nonoperating settlement charge in the range of $500 million to $1 billion in the fourth quarter of 2023. All in, our targeted actions have given us the ability to continue investing in growth while delivering more than 80% of operating income back to our shareholders, well above our 65% target. Turning to our outlook for the fourth quarter on Slide 7. In the Packaging & Specialty Plastics segment, industry data shows a continued decline in U.S. Gulf Coast inventory levels driven by resilient domestic demand and export market strength. Higher polyethylene prices and elevated oil to gas spreads continue to favor our cost advantaged footprint and are expected to generate $100 million tailwind in the quarter. Additionally, we expect a $25 million tailwind as we complete planned maintenance activity at our cracker in St. Charles, Louisiana. We also expect a $50 million headwind to equity earnings due to a planned turnaround at our joint venture in Thailand. In the Industrial Intermediates & Infrastructure segment, we expect seasonal demand increases in deicing fluid to offset seasonal volume declines in building and construction end markets. Additionally, we expect a headwind of $25 million due to elevated energy and feedstock costs, particularly in Europe impacting our polyurethanes and our construction chemicals businesses. In the Performance Materials & Coatings segment, we expect the current macroeconomic conditions to limit consumer discretionary spending in nonservice areas. We also expect margin pressure to continue in upstream siloxanes from competitive supply additions, which will result in a $25 million headwind. Additionally, the seasonal decline in building and construction demand is expected to contribute an approximately $50 million headwind in the quarter. All in, we expect fourth quarter earnings to be in line with the third quarter. Next, I'll turn it back to Jim.


Jim Fitterling: Thank you, Pankaj. Beginning on Slide 3, we continued to navigate a challenging macroeconomic environment with slow global growth in the second quarter. Despite lower year-over-year sales and earnings, Team Dow delivered sequential earnings improvement by executing on our financial and operational playbook. We leveraged our diverse portfolio to capitalize on gains in packaging and modestly higher seasonal demand in building and construction. This resulted in a sequential improvement in volume. In addition, we continue to implement our $1 billion of proactive and targeted cost savings actions delivering $250 million of savings in the quarter and $350 year to date. Net sales were $11.4 billion, down 27% versus the year ago period, reflecting lower demand and prices due to slower macroeconomic activity. Sales were down 4% sequentially, as volume gains were more than offset by lower local prices. Volume decreased 8% year-over-year, led by a 14% decline in Europe, the Middle East, Africa, and India, or EMEA. Volume was up 1% sequentially, driven by gains in Asia Pacific and Latin America, as well as in industrial intermediates and infrastructure and performance materials and coatings. Local price decreased 18% year-over-year and 5% sequentially due to lower demand on weak macroeconomic activity, as well as lower global raw material costs. Operating EBIT for the quarter was $885 million, down from $2.4 billion in the year ago period, primarily driven by lower local prices. Operating EBIT increased $177 million sequentially, driven by gains in packaging and specialty plastics. We generated cash flow from operations of more than $1.3 billion, up more than $800 million versus the prior quarter, driven by improved working capital. On a trailing 12 month basis, our cash flow conversion is 98%. Our strong financial position gives us the flexibility to continue to advance our long term strategic priorities, supported by our disciplined and balanced capital allocation strategy. In the quarter, we returned $743 million to shareholders through dividends and share repurchases. Year to date, we've returned nearly $1.4 billion. And our balance sheet remains healthy, supported by strong investment grade credit ratings. We also published our 2022 INtersections Report in June. The report once again received limited assurance by our external audit firm and showcases Dow's continued progress on our ambition to be the most innovative customer centric, inclusive and sustainable material science company in the world. Now turning to our operating segment performance on Slide 4. In the Packaging and Specialty Plastics segment, operating EBIT was $918 million compared to $1.4 billion in the year ago period. Local price declines were driven by lower global energy and feedstock costs, which in turn impacted polyethylene prices across all regions. Volume declines, primarily in EMEA, were driven by lower demand for olefins and aromatics. Sequentially operating EBIT improved by $276 million, driven by lower energy and feedstock costs. Moving to the Industrial Intermediates and Infrastructure segment, operating EBIT was a loss of $35 million, compared to earnings of 426 million in the year ago period. Results were driven by lower local prices and demand in both businesses. Volume declines were primarily driven by lower demand for consumer durables, building and construction, and industrial applications. Sequentially, operating EBIT was down $158 million due to lower local prices and increased planned maintenance turnaround activity. And in the Performance Materials and Coatings segment, operating EBIT was $66 million compared to $561 million in the year ago period. Local price decreases were driven primarily by declines for siloxanes and acrylic monomers. Volume was down on lower global demand for silicones and coatings applications. Sequentially, operating EBIT increased $31 million, driven primarily by seasonally higher volumes. Next, I'll turn it over to Howard to review our outlook and actions on Slide 5.


Vincent Andrews: Thank you. And let me also echo the prior remarks and congratulations to you, Howard. Very exciting for you. If I could ask just looking at Slide 9 on the CapEx. I just want to make sure I understand -- I mean, obviously, we know where '23 is, it looks like '24 is going to go to that D&A line. And then that '25 to '27, it looks like there's quite a -- there's sort of a zone there. Could you speak to a little bit of maybe a range that you could give us to make sure we have that right in our models and sort of what would define it at the lower end or the upper end of the range? Because I see you do have Alberta at about $1 billion a year, but is it maybe going to be a bit chunkier in some of those years? Or just how should we be thinking about the cadence and the range of CapEx during that period of time.


Jim Fitterling: Sure. I'll take the cold snap, and then, Jeff, I'll have you take a look at the costs. Look, on the freeze, Jeff, I just want to go back, two years ago, this is the third consecutive year of freeze on the Gulf Coast. And we've improved plans every year to be able to be ready for that. This year will be the lowest impact we've had of any of the three years. And so, the big impacts that hit us were at Deer Park and at Seadrift, but almost all of that is back up and running now. So, we were able to rebound pretty quickly. You never go completely unscathed, but I think we managed through it pretty well. We haven't had to disrupt any customers because of downtime. And I think we're going to recover pretty strong here and be running hard by the end of this month. So, I feel that we've navigated it pretty well. And we didn't see enough of an impact that we put that into first quarter estimates. I think our biggest delta in first quarter is we've got quite a few turnarounds in the first quarter, and so that's our biggest impact about $200 million of turnarounds in the quarter -- $150 million. And then, we expect some margin and some seasonality in first quarter, say, plus $200 million on margins and minus $150 million on turnarounds in the quarter. So that's the biggest net-net on the first quarter '24 guidance. Jeff, do you want to hit how the $1 billion costs fell across the business?


Jeffrey Tate: Yes, Arun, I think you're right on top of the run rate. So no comments there. I do think mid-cycle -- I mean, our view of mid-cycle is probably closer to $9 billion. And so to get to that mid-cycle run rate, obviously, we have to have another couple of step-ups to get there. Volume is a big part of it. So as I mentioned, all the projects, on the call that some that we've already put in place that equal $800 million of the step-up and the rest that we're in flight right now, that's another $1.2 billion of step-up. So that $2 billion of improved margins is all volume. And most of that CapEx is either been or will be finished this year and beginning of next year. So I feel good about that. Obviously, the Path2Zero in Alberta comes later. So I think you can see that $1 billion more towards as we're getting to the next peak. That's a '27 to '29 time frame where that's coming in, '27 is Phase 1, '29 is Phase 2. And so if we've got our timing right and that's what we intended, was we got that up and running before we get into the next peak. And so I think we've got the line of sight to the volume that's going to come from here to mid-cycle. When we get to Investor Day on May 16, we're going to unpack all that volume and that trajectory. And then we've got the line of sight into the stuff that gets us greater than $3 billion by 2030, which is next peak type economics. And from where we are, that's excellent growth rates for both of them. And so I feel like we've been through the worst of it here on the slowdown in the cycle. And so it should be more upside than downside from here out.


Jeff Tate : Thank you, Jim, and good morning to everyone joining our call today. Moving to Slide 7, we continue to experience muted demand across some end-markets and regions with the greatest pressure in Europe and China. Global manufacturing PMI has been decelerating over the past three months and consumer spending remains pressured by persistent inflation. That said, we're monitoring the impact of rate cuts in the US and Europe, as well as recent stimulus plans in China to boost economic activity, which could provide some positive momentum for 2025. Looking specifically across our four market verticals, in packaging, domestic demand in North America is resilient and exports are robust, despite decelerating last month. Demand in Europe remains soft, consistent with manufacturing PMI at the lowest point year-to-date. In addition, China's manufacturing PMI returned to contractionary levels in September after improving in August. Infrastructure demand primarily in residential construction remains low. In the US, housing starts decelerated to negative 0.7% year-over-year in September. Eurozone construction PMI remained soft and new home prices in China declined year-over-year for the 15th consecutive month. Consumer spending has slowed across the globe, reflecting affordability challenges. We've seen consumer confidence weaken in the United States, remain negative in Europe, and decline in China for the fifth consecutive month. And in mobility, demand has softened globally. In the US, auto sales were slightly up year-over-year in September after decreasing in August. And in the EU, new car registrations declined in September after reaching a three-year low in August. China auto production declined for the fourth consecutive month, reflecting weak domestic demand, as well as exports due to tariffs imposed in Europe. Now turning to our outlook on Slide 8. We expect fourth quarter earnings to be approximately $1.3 billion, up year-over-year and lower quarter-over-quarter, as normal seasonality plays out. Now looking into the sequential drivers by segment. In the packaging and specialty plastic segment, lower integrated margins stemming from higher feedstock costs and lower licensing revenue will be a headwind. Following an unplanned event in July, we restarted our Texas-8 cracker at the end of the third quarter, and we expect to ramp operating rates steadily throughout fourth quarter. This will generate an add-back of approximately $100 million in the fourth quarter. We also expect lower planned maintenance activity across multiple sites along the US Gulf Coast and in Europe to provide a tailwind sequentially. In the industrial, intermediates, and infrastructure segments, conditions remain mixed. Demand in building and construction end-markets, will be seasonally lower, but we expect the ongoing ramp of our plant at Louisiana operations, as well as the seasonal uptick in demand for deicing fluid, to offset this decline. In addition, we anticipate a $50 million tailwind through the lower planned maintenance activity along the US Gulf Coast. And in the Performance Materials and Coatings segment, we see continued growth in downstream silicone applications across most end-markets. However, this is expected to be offset by ongoing weakness in the China property sector. In addition, lower seasonal demand for building and construction end markets is expected to be a headwind of approximately $125 million. Moving to Slide 9. Team Dow has built a very compelling investment opportunity even as our industry has faced volatile market conditions over the past few years. By continuing to execute our playbook, deliver on our financial priorities and advance our strategy, we are positioning Dow for long-term value growth. Importantly, we have built the financial flexibility to continue disciplined investment in areas that will raise our underlying earnings, reduce emissions and advance customer circularity needs to drive growth. As it relates to our financial strength, Dow has ample liquidity and a strong investment grade-credit profile. Nearly all of our long-term debt is at a fixed rate and we have no substantive maturity until 2027. We also expect to enhance our near-term cash flow generation through the execution of unique to Dow cash flow levers And we are making solid progress on the evaluation of strategic options for our non-product producing infrastructure assets. As previously mentioned, we anticipate generating over $1 billion in proceeds from the transaction and we expect to share further progress yet this year. Dow's strong financial flexibility, allows us to advance our long-term growth strategy. Notably in the Q3, the team is making good progress on the construction of our Path2Zero project in Fort Saskatchewan. Major foundation work began and approximately 40% of cracker pilings are complete. Aligned to our capital deployment schedule for the project, we expect to receive more than $1.5 billion in cash and tax incentives with more than 80% received by 2030. Our near-term growth projects remain on track to deliver more than $2 billion of underlying EBITDA. This includes capacity expansions in silicones this year that will deliver approximately $70 million of annual EBITDA at full run rates. In our Transform the Waste strategy is expected to deliver more than $500 million of EBITDA by 2030. In the third quarter, we added new products to our growing circular portfolio. This includes REVOLOOP Recycled Plastic Resins that incorporate post-consumer recycled material into cable jacketing. We also introduced the 1st Bio Circular Engage REN polyolefin elastomers for carpet tile backing. And with that, I will turn the call back over to Jim.