Good morning. My name is Jen, and I will be your conference facilitator today. Welcome to Chevron's Fourth Quarter 2021 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ remarks, there will be a question-and-answer session and instructions will be given at that time. As a reminder, this conference call is being recorded. I will now turn the conference call over to the General Manager of Investor Relations of Chevron Corporation, Mr. Roderick Green. Please go ahead.

Thank you, Jen. Welcome to Chevron's fourth quarter 2021 earnings conference call and webcast. I'm Roderick Green, GM of Investor Relations. Our Chairman and CEO, Mike Wirth; and CFO, Pierre Breber, are on the call with me. We will refer to the slides and prepared remarks that are available on Chevron's website. Before we begin, please be reminded that this presentation contains estimates, projections and other forward-looking statements. Please review the cautionary statement on Slide 2. Now I will turn it over to Mike.

Thanks, Roderick. After the challenges of 2020, we began last year clear-eyed about the economic realities we faced, and at the same time, optimistic about an eventual recovery. By the end of 2021, we had one of our most successful years ever, with return on capital employed approaching 10%, our highest since 2014; the successful integration of Noble Energy, while more than doubling initial synergy estimates; and record free cash flow, 25% greater than our previous high. 2021 was also the year when Chevron accelerated our efforts to advance a lower-carbon future by forming Chevron New Energies, an organization that aims to grow businesses in hydrogen, carbon capture and offsets, introducing a 2050 net-zero aspiration for upstream Scope 1 and 2 emissions and establishing a portfolio carbon intensity target that includes Scope 3 emissions and more than tripling our planned lower carbon investments. Chevron is an even better company today than we were just a few years ago. We're showing it through our actions and our performance, which we expect to drive higher returns and lower carbon. And we intend to keep getting better. Our record free cash flow enabled us to strongly address all four of our financial priorities in 2021: a higher dividend for the 34th consecutive year, a disciplined capital program, well below budget, significant debt paydown with a year-end net debt ratio comfortably below 20% and another year of share buybacks, our 14th out of the past 18 years. I expect 2022 will be even better for cash returns to shareholders with another dividend increase announced this week and first quarter buybacks projected at the top of our guidance range. We're optimistic about the future, focused on continuing to reward our shareholders while investing to grow our businesses and maintaining a strong balance sheet. We made the most of this challenging period, transforming Chevron through a well-timed acquisition and an enterprise-wide restructuring into a leaner and more productive company. In just two years, CapEx was reduced by almost half from Chevron and Noble's pre-COVID total. And operating expenses for the combined company in 2021 were lower than for Chevron on a standalone basis in 2019. The Noble acquisition and increasing capital efficiency enabled us to maintain a five-year reserve replacement ratio above 100%. And 2021 was very consistent with that longer-term performance, driven primarily by additions in the Permian, Gulf of Mexico and Australia and partly offset by lower reserves in Kazakhstan, mostly due to higher prices and their negative effect on our share of reserves. For more on our strong financial performance, over to Pierre.

Thanks, Mike. We reported fourth quarter earnings of $5.1 billion or $2.63 per share. Adjusted earnings were $4.9 billion or $2.56 per share. The quarter's results included three special items: asset sale gains of $520 million, primarily on sales of mature conventional assets in the U.S.; losses on the early retirement of debt of $260 million, which will result in significant future interest cost savings; and pension settlement costs of $82 million. A reconciliation of non-GAAP measures can be found in the appendix of this presentation. Full year earnings were over $15 billion, the highest since 2014. Compared with third quarter, adjusted fourth quarter earnings were down $770 million. Adjusted upstream earnings were flat, with higher realizations offset primarily by negative LNG trading timing effects and higher DD&A. DD&A increased on catch-up depreciation for our interest in North West Shelf, which no longer meets asset held-for-sale criteria and impairments of certain late-life assets triggered by updated abandonment estimates. Other items include additional taxes and royalties related to higher prices under certain international contracts. Adjusted downstream earnings were down with lower chemicals margins and volumes at CPChem and GS Caltex, in addition to year-end inventory charges. The All Other segment declined due to tax charges. Across all segments, operating expenses increased in part due to higher accruals for employee bonuses and stock-based compensation. Adjusted earnings increased over $15 billion compared to the prior year, primarily due to increased realizations in upstream as well as improved refining and chemicals margins. Costs were up primarily on the acquisition of Noble Energy that closed in the fourth quarter of 2020, higher fuel costs and an unfavorable swing in accruals for employee benefits. 2022 production is expected to be flat to down 3% due to expiration of contracts in Indonesia and Thailand. These contracts are not being extended as we were unable to do so on terms competitive with our alternatives. Excluding contract expirations and 2022 asset sales, we expect a 2% to 5% increase in production led by the Permian and lower turnaround activity in TCO in Australia. We reaffirm our prior long-term guidance of a 3% production CAGR through 2025, and we'll share more about our long-term outlook at our upcoming Investor Day. I'll call out a few items on Slide 11. Full year guidance for the All Other segment excludes special items such as pension settlement costs. The All Other segment can vary quarter-to-quarter and year-to-year. Affiliate dividends are expected to be between $2 billion and $3 billion, depending primarily on commodity prices and margins. We do not expect any additional lending or loan repayments this year at TCO. Finally, asset sale proceeds are expected to be in line with historical averages. We've updated our price sensitivities to include natural gas. Also, our guidance for both earnings and cash flow sensitivities is now the same as we're likely to consume the remainder of our NOLs and other favorable tax attributes if prices remain higher. Finally, we did not receive our federal income tax refund last quarter and expect it later this year. Back to Mike.

All right. Thanks, Pierre. I believe 2021 was a pivotal year for Chevron, where we got better in so many ways. And we look forward to 2022 and beyond, confident in our strategy and capabilities that aim to deliver higher returns and lower carbon. We'll share more during our Investor Day on March 1. At this time, we expect to be at the New York Stock Exchange with a limited number of participants. The meeting will be webcast for all to see. With that, I'll turn it back to Roderick.

That concludes our prepared remarks. We are now ready to take your questions. Please try to limit yourself to one question and one follow-up. We will do our best to get all questions answered. Jen, please open the line.

Our first question comes from Neil Mehta with Goldman Sachs.

The first question I had was more of a housekeeping item for you, Pierre, which is, in the quarter, it looked like LNG timing effects had a meaningful drag here. I recognize there was a lot of volatility, particularly towards the end of the month with TPS and JKM, but maybe you can break it down in layman's terms for us. What does that really mean and what happened in the quarter?

Thanks, Neil. About half of the timing effects in the quarter were due to a negative inventory charge. So we had two cargoes on the water at year-end. They get valued into inventory at average annual prices, which were well below the purchase price because as you said, Neil, prices were in a rising price environment and prices rose at the end of the quarter. So that will reverse itself this year when they are sold at the higher prices that they were purchased at. The balance of the timing effects are in paper mark-to-market effects. And as you know, the paper, which is tied to physical cargoes, gets marked to market while the physical cargoes are not. So that creates a timing effect, which unwinds when the physical cargoes are delivered. We ended the year with a positive mark-to-market, but not as positive as what we had at the end of the third quarter. We added some JKM shorts during the quarter to balance our portfolio. We're still net long JKM. So any effects going forward will depend on the direction of future prices. And all this activity is really just geared towards managing our overall price exposure between our sales agreements and our supplies, which are a mix of both Brent and JKM prices. And just to put a fine point on the comment you made, these positions are not very large. But when we have natural gas LNG price movements that have gone from $10 to $20 to $30 per Mcf, it's causing larger timing effects than you would normally see.

That makes a lot of sense, Pierre. And then the follow-up for you is just on cash flow. Again, relative to consensus, it was softer. It does seem like there's some one-timers in there, maybe something around the timing of tax refunds and then where Angola shows up, but there's still a gap in there. So can you just talk about how you bridge to Street numbers in your mind, anything we need to carry forward as we think about next year?

Well, I'll cover the two points you made. We did not receive the IRS tax refund that we expected in the fourth quarter; we expect it sometime this year. We did receive a TCO dividend. There is a 15% withholding tax that comes off of the dividend. And we did receive the Angola LNG return of capital, which actually exceeded our guidance. By the way, the TCO dividend was at the high end of our guidance range. And the return of capital from Angola was above our guidance. But again, it shows up in cash from investing and not cash from operations because it's a return of capital. If you look beyond that, we do have, and as I referred to in our prepared remarks, there are certain contracts internationally that have additional taxes and royalties that kick in essentially when oil and LNG prices are higher, and we don't share specifics on our contracts. But as we talked about, we had extraordinarily high LNG pricing of $30, and we also had oil prices that increased during the year. And the last thing I'd say is we provided guidance on the third quarter call on our expected increase in earnings from LNG spot cargoes. We gave that guidance in part because LNG prices increased significantly. We anticipated to have fewer cargoes because our long-term contract takes were going to be higher during the winter from our primarily Japanese customers. We did not produce as much out of Australia, so we had fewer LNG spot cargoes. That was an opportunity missed and that resulted in lower earnings and cash flow.

Neil, it's Mike. One other thing you talked about is what you should bear in mind going forward? As we've been in this fairly depressed commodity price environment, we've built up net operating losses in our business. And as we've returned to profitability, those have now been utilized and offset against taxes payable. As we work our way through those and in a strong price environment that could happen sooner rather than later, we'll be in a net taxable position that's quite different than what we were before. And so I think that's another point that may not be as evident in the quarter. But as you go forward, it's a good news/bad news situation; we're going to be more profitable, but it also means we're going to have higher taxes payable.

Our next question comes from Phil Gresh from JPMorgan.

My first question is about the production outlook for 2022. You had very strong production in the Permian during the fourth quarter, approximately 70,000 to 80,000 barrels per day above the full year average, and you expect an increase of 80,000 barrels per day in new production in 2022 compared to 2021. It seems like you could achieve that from the Permian alone. However, I'm curious if there are other factors to consider regarding the new production aspect of the growth for 2022, or if there's some caution involved. Any insights would be appreciated.

Yes, Phil. Fourth quarter Permian does look strong. One thing we see from time to time is with our non-operated joint venture position; sometimes the way production gets reported in by partners can result in a little bit of lumpiness in those numbers. But broadly speaking, the Permian is healthy and getting better. I think 2022 Permian production will be a little bit better than we showed at our Investor Day last March. Roughly speaking, this could be up around maybe 10% compared to full year average in 2021. That is the largest piece of what we would anticipate in terms of production growth next year. There is some growth in base and other primarily. As Pierre said in his comments, we've got lower planned turnaround activity at TCO, and we expect more uptime at Gorgon. That's offset by a few asset sales that we would anticipate. Those are the significant moving pieces in production for 2022.

Okay. Great. That's very helpful. And Mike, I know you'll get into a lot more detail in March at the Analyst Day and looking forward to that. But just kind of looking back pre-COVID at prior analyst days, your framework was $60 Brent that you're using to balance CapEx and distributions in a fairly evenly balanced framework. Obviously, oil is at $90 now and maybe you don't want to give guidance at those types of levels. But I am curious about what is the right way to look at the cash balancing framework? What price would you think is reasonable these days? As I know you like to manage the business through the cycle, not based on spot prices.

Yes. We will talk about that more in March, Phil. But our longer-term view on the pricing environment hasn't changed a lot. There's a lot of resources out there that can be produced economically at prices lower than what we see today. Our breakeven reflects that. We are in a period of time where cash flow is strong. As we mentioned in our comments, the last two quarters have been the best two quarters the company has ever seen. Last year was 25% higher than the best year in our history. So we increased the dividend. Debt came down significantly, and we've guided to the high end of our share repurchase range. If we continue to see an environment like this, the balance sheet doesn't need to be a lot stronger than it is today. We've already increased the dividend and we're going to be disciplined on capital. That really leaves one lever left: you should expect us to be consistent with our history, which is returning cash through share repurchases. At least in this environment, we've got ample cash to do that and sustain that well into any kind of correction that we eventually will see.

Our next question comes from Jeanine Wai with Barclays.

Our first question is on TCO. I guess now that you're through much of the winter campaign, is there any update on how FGP-WPMP and how those are tracking on cost and schedule maybe given your COVID protocols and efficiencies? And if you have any color on impact related to the recent geopolitical unrest, that would also be very helpful.

Sure, Jeanine. Fourth quarter was really good execution on field productivity. We made terrific progress, and that's carried forward as we began the year. We did have some impact during the unrest that occurred in Kazakhstan, but for about a week, that is the amount of time that it really cost us in the field there. We've remobilized everyone now and are back at full strength in terms of field activity. We have a highly vaccinated workforce, more than 90%. One of the highest rates of vaccination anywhere in our system in the world. Although we have seen Omicron cases appear in the workforce there, at this point, it's at a level that's very well managed, and it's not having any impact on field construction and activity. We are continuing to make good progress. We have not made any change to our cost or schedule guidance and are overall at about 89% project progress and 82% construction progress at this point. So things have been managed really well on the ground by our team during a pretty challenging month of January.

Our follow-up question relates to Phil's inquiry about the Permian. You had a robust quarter, surpassing our expectations. You mentioned that 2022 production is slightly better than anticipated from your March Analyst Day forecast. Could you please clarify whether you've increased activity in the region, or is it mainly a result of improved efficiencies? Also, considering its significance to corporate growth in the medium term, are you taking any measures regarding supplies, labor, or equipment in anticipation of potential tightening in the service markets over the next few years?

Yes. Let me speak first to activity. Then I'm going to allow Pierre, who's now in charge of our supply chain organization, to speak to any signs of inflation and how we're managing that. Activity in the Permian is really increasing aligned with the guidance that we've issued previously, and spending this year up from $2 billion to $3 billion. Wells put on production, a little bit over 200 we anticipate this year, which is up about 50% versus 2021. We'll share an update on all of these things when we see you in March. This is really well aligned with what we've already guided to and indicates the ongoing efficiencies that we continue to see in the field and the quality of this asset, which endures as we go through cycles like the one we just went through. It’s quite pleasing to have an asset of this caliber in your portfolio that's large and flexible when it comes to capital, and that we can demobilize, remobilize when conditions call for it. Progress is strong there. I'll let Pierre comment on input costs.

Jeanine, we continue to manage our costs, we think, very well in the Permian and across our portfolio. Our capital budget, which we announced in December, expected some COGS increase — modest in the low single digits. What we might be seeing a little bit more than that in the Permian is very manageable, and we think we can offset it with efficiencies. Although rates are up, they're still below where they were pre-COVID. Rigs capacity in the industry for specific oil and gas equipment and services is still below pre-COVID levels. While we are exposed to labor and steel and certain other elements tied to the broad-based economy, oil and gas-specific equipment services remain well under control. Our ability to contract well and be a very good partner to work with gives us confidence that the little bit of cost pressure we're seeing is manageable within the range of what we expected, and we intend to deliver our capital program in line with our budget.

Our next question comes from Doug Leggate from Bank of America.

So Pierre, I think your explanation about the dividend from TCO being a return of capital probably explains why the cash flow numbers were too high. But my question is really about the go-forward portfolio leverage. You obviously lose Indonesia, you lose Thailand, which I guess was gas. But you've got the Permian driving growth on a lighter recent history of PSC capital for the cost standpoint. So my question is when I think about portfolio oil leverage for the go-forward outlook, how does that compare to the legacy portfolio given all those changes?

Our guidance on — let me start by saying we've always been the most levered among the integrated energy companies. That's a function of the portfolio we've created over a long time, which tends to be upstream-weighted. Within upstream, we tend to be oil-weighted. Again, a big portion of our LNG is sold under oil prices. So while we were viewed as a defensive stock during some of the challenging times in 2020 and last year because of how we manage the balance sheet and how we're able to flex our capital program and manage our costs, we really are more of an oil play and we're much more levered on the upside. We've shown that in the last Investor Day, and we'll show that again in the upcoming Investor Day. In terms of our sensitivity, it’s still around the same when you factor it all in. Indonesia was working its way to be a fairly modest portion of the portfolio. You are right over time that both Tengiz and the Permian that increases our weighting in some ways. However, the guidance that we provided of $400 million of earnings and cash flow benefit from a dollar change in prices still holds.

My follow-up, if I may, is to go back to your one-off comments, the DD&A and the timing effects. I'm curious how much was that because you didn't strip it out? I'm curious why you didn't strip it out. And then just real quick on the LNG, was there a shift in contract versus spot volume exposure that also impacted the quarter? And then that's it for me.

Yes, Doug. The return of capital was from Angola LNG. TCO was a dividend withholding tax. You're right; that part does not show up in cash from ops. In terms of DD&A, about half is due to the catch-up at North West Shelf. We designated that asset as held for sale about 18 months ago. So you're capturing 18 months of depreciation all in the fourth quarter. We don't call it a special item because obviously, it would have been in our underlying results if it had been held for use during that time. The other half are impairments tied to increases in abandonment estimates for late-in-life assets. These estimates are part of our regular updating process because these assets are very late in life; they don't have the production or remaining production life to recover those additional abandonment estimates, and therefore, that results in an impairment. About half is the catch-up, and half are onetime in nature. In terms of the LNG, yes, there was a shift in the fourth quarter to more contractless spot. We guided to that on the third quarter. As I mentioned earlier, it was even more so. During the winter months, our Northern Hemisphere customers tend to increase their takes under the long-term contracts. We didn't produce as reliably in the fourth quarter, so we had fewer spot cargoes. What you're seeing is that we did not benefit as much with the run-up in spot prices as we had guided to in the third quarter; our weighting was more oil contract-related. Now these contracts are doing very well. Spot markets go up and down. But you'll see more exposure as we go forward. Yes, Doug. The return of capital was from Angola LNG. TCO was a dividend withholding tax. You're right; that part does not show up in cash from ops. In terms of DD&A, about half is due to the catch-up at North West Shelf. We designated that asset as held for sale about 18 months ago. So you're capturing 18 months of depreciation all in the fourth quarter. We don't call it a special item because obviously, it would have been in our underlying results if it had been held for use during that time. The other half are impairments tied to increases in abandonment estimates for late-in-life assets. These estimates are part of our regular updating process because these assets are very late in life; they don't have the production or remaining production life to recover those additional abandonment estimates, and therefore, that results in an impairment. About half is the catch-up, and half are onetime in nature. In terms of the LNG, yes, there was a shift in the fourth quarter to more contractless spot. We guided to that on the third quarter. As I mentioned earlier, it was even more so. During the winter months, our Northern Hemisphere customers tend to increase their takes under the long-term contracts. We didn't produce as reliably in the fourth quarter, so we had fewer spot cargoes. What you're seeing is that we did not benefit as much with the run-up in spot prices as we had guided to in the third quarter; our weighting was more oil contract-related. Now these contracts are doing very well. Spot markets go up and down. But you'll see more exposure as we go forward.

Yes, Doug. The one other thing to bear in mind is that as we've been in this fairly depressed commodity price environment, we've built up net operating losses in our business. As we returned to profitability, those have now been utilized and offset against taxes payable. Moving forward, we'll be in a net taxable position that’s quite different than what we were before. So that may not be as evident in the quarter, but is important for future considerations. The good news is we will be more profitable, but it will also mean that we have higher taxes payable.

Our next question comes from Devin McDermott from Morgan Stanley.

The first one I wanted to ask on is just CapEx. I think it's notable that you all came in for last year below the bottom end of your CapEx guide. I was wondering if you could just talk a little bit more about some of the drivers of that CapEx beat. And then, Pierre, you mentioned before, I think, that you're seeing or assumed a few percentage points of inflation in the Permian. I was wondering if you could just broaden that out and talk about the inflationary trends you're seeing across the global portfolio and opportunities to potentially offset that as you think about 2022 spending levels?

Yes, sorry, the low single digits was really meant to be across the portfolio. That's factored into our $15.3 billion capital program. If you look offshore, those rig rates have stayed flat to down. We do contract where we lock in rates for some services, and we have price caps on some services. There are lots of ways that we work to mitigate our exposure to COGS. I would view it as low single-digits overall. Permian might be slightly higher, but not nearly as high as numbers I'm hearing from some others. We don't see anything in our cost that would be double digits at all. So a little bit very modest, presented to be higher than what we planned for and again, manageable by offsetting with efficiencies.

And on 2021, Devin, there's nothing noteworthy in the profile of CapEx that drove the ultimate outcome, which was a little below what we had guided to. There's inertia in some of these things, and as we pulled the handbrake pretty hard in 2020, we throttled a lot of things down. As we start to bottom out and turn that back around a little bit, the system just needs to adjust. I wouldn't call it anything that's unique or noteworthy. We've had about half of the underspend attributable to project deferrals like at Tengiz due to COVID and half to greater capital efficiency and other cost savings.

Okay. That's helpful. And then separately, I wanted to ask on Australia LNG and Gorgon specifically. I was wondering if you could talk in a bit more detail around some of the recent downtime there. What happened, and then what steps are being taken to ensure better uptime here in 2022?

Yes, I'll take that, Devin. Look, it's a point of frustration, no doubt. During normal rounds, we had an operator that spotted evidence of the risk of an operating issue at one of the units in the dehydration train. Nothing catastrophic or alarming, but a sharp-eyed operator picked up evidence, and as we investigated further, we felt it was prudent to take a quick pit stop to address this. That's been completed at two of the three trains; they're all the same design, so these things tend to show up across all three trains. The third train is undergoing that pit stop right now and is also addressing a problem with one of the compressors that was identified, which was an opportune time to make some changes to reduce risk going forward. We expect to operate reliably and have made it through our first major turnaround on all three trains, those are behind us at Gorgon. We do not have any planned turnarounds in 2022, and as we complete this last pit stop, our expectation is to see more production out of Gorgon than we did in '21.

Our next question comes from Paul Sankey from Sankey Research.

Guys, on your guidance, the volumes will fall this year. Would you characterize that as you’re using a conservative oil price assumption and being determined not to raise CapEx? Or were there other issues around the concessions, particularly? And could you talk about whether you could accelerate the Permian, if you wanted to? Can you also discuss inflationary pressures that you might be seeing in the Permian with labor, steel, etc.?

Yes. On production guidance, Paul, I would hope this isn't big news to people. We've long been public about the fact that we couldn't extend the concessions in Indonesia and Thailand on terms that would compete with other opportunities within our portfolio. When you pull those out, we're at 2% to 5%, and Pierre reiterated the compound annual growth of 3% through 2025. This is consistent with the guidance and the messaging that we've been communicating. On the question of whether you could accelerate the Permian? In theory, the answer five years ago was yes; the answer today is yes. We've focused on execution, efficiency, and returns. Last March, we laid out that strong production growth profile, and we look to update that again here in the new year. This asset continues to look as good as we've portrayed it to you; we are not going to get ahead of ourselves in an effort to chase anything. We are bringing activity back up from $2 billion last year to $3 billion, 50% increase in capital spend. We are going to see a 50% increase in wells put on production in '22 versus '21, which is a meaningful activity increase, and we want to do that well. I don't think we will be tempted to chase the price of the day and put that at risk. I think Pierre already addressed inflation; I don’t know if there’s anything else you’d like to add.

Our next question comes from Manav Gupta from Credit Suisse.

My quick question is your U.S. downstream results were down about $400 million quarter-over-quarter, and we expected about $200 million of that to be chemicals headwind. But we also saw somewhere, so what peers are doing is that refining was able to jump up and make up for it. In this case, it looks like both went down a little. And if you could help us understand what the maintenance in the refining system was, what went on in U.S. refining that caused this decline quarter-over-quarter?

Manav, there were a number of items we referred to, including year-end inventory effects. The higher employee benefit costs were felt across all segments, including U.S. downstream. We had a very strong year, and we expect higher employee bonuses; we accrued for that. Our stock ran up in the fourth quarter, and it continued actually in the first quarter. We have to do accruals for stock-based compensation tied to both absolute stock price movement and the relative stock price movement because of how some of our incentive programs work. That helps explain part of your question.

A quick follow-up is you have a global footprint. Help us understand within your entire system how you're tracking refined product demand, gasoline, diesel, jet as well, anything you could help us understand, where we are versus before the pandemic started.

Yes, Manav. I think a lot of the data you see in the public domain is pretty good. We've got global gasoline demand up higher than it was pre-pandemic. Diesel is at and perhaps slightly above; jet fuel continues to lag. The specific numbers can vary region by region. Broadly speaking, that's where we are: ground transport fuels are at or above pre-COVID levels. Aviation is not, and we have still seen an economic recovery underway. Many people are still working from home, not traveling for business, and not taking international flights. Even with the strong demand recovery we’ve seen, we have another lag in demand improvement that is likely to occur this year. The demand outlook is solid, and the issues have been more on the supply side than the demand side.

Next question comes from Paul Cheng from Scotiabank.

I have two questions, please. My first question is, if we're looking at your, I think, well-spoken slogans, lower carbon and higher return, here that Permian is definitely going to contribute to the higher return. Outside Permian, can you help us to maybe bridge the gap or indicate what the self-help topics are that you guys will drive so that we could see a better return over the next perhaps one or two years? The second question is regarding the Australian LNG; it seems like every — I mean, the plan has only been on stream since 2015 and so isn't old, but we have all these tiny little problems from different units coming up. So have you guys gone into doing a thorough review on all the units and considering whether that has other potential issues that we need to face?

Yes. Paul, about returns, yes, Permian is highly accretive to returns because we get very strong returns there. We're reducing costs across our business. As I indicated, we're running Chevron and Noble together for costs lower than Chevron was standalone in 2019. That's a significant driver of improved returns. We work across the value chain to capture more margin, both in the downstream and upstream; it's a lot of self-help initiatives. Rather than think about pointing to assets, I'm talking to you about the way we work and finding ways to improve efficiency and productivity across all our operations drives improvement. It's really about rolling up your sleeves and doing it the old-fashioned way, a lot of little things we stay focused on. Pierre, do you want to add anything else on the drivers of return improvement?

We'll share more at the upcoming Investor Day; we've shown that at the last couple of investor days. As Mike discussed, it's margin capture; Noble synergies; transforming the enterprise and reducing costs; working across the value chain and capital efficiency, both where we put new capital and higher returns across the portfolio, as of course, as lower returns prior capital depreciates off. We’ll update you at the next Investor Day; that's the playbook we’ve been using and will continue to use going forward.

Paul, regarding your question about Gorgon, you're correct that it's not an old facility. It has experienced a number of initial challenges in its early years of operation. We've had our team actively involved in addressing these issues. I mentioned earlier that a detail-oriented operator during routine inspections identified a concern that we've resolved to avoid a more significant outage. We remain vigilant in this regard. We don’t have, as you put it, a major problem looming. Our upstream teams have been strong in their efforts. We've also included skilled individuals from our downstream organization with extensive experience in process facilities to enhance reliability, mechanical integrity, and address ongoing design and construction challenges while under pressure. We've emphasized the importance of improving performance on major capital projects going forward.

Our next question comes from Ryan Todd from Piper Sandler.

A question on the Gulf of Mexico. First of all, any updates on the progress of potential deepwater developments in the U.S. Gulf of Mexico, including the Anchor project, which seems like a lifetime ago? The courts just canceled the result of a recent lease wholesale in the Gulf of Mexico. Can you comment on whether you see any potential for incremental headwinds there on the regulatory front that could impact things in the future?

A quick update on Anchor: we expect first oil in 2024, and that holds. The entire assembly is complete, and commissioning is underway in Korea. We've begun drilling the first development well with a ship called the Deepwater Conqueror. It's a project with attractive development costs, even including some costs related to new technologies. Similarly, Whale, where we are not the operator, is targeted for first oil in 2024, and we have good progress there. Finally, Mad Dog 2, where we’re also in a non-op position, is expected to have first oil this year. So we have several projects making good progress that are an important part of our portfolio. Lease sale 257, which was in the news yesterday, we were the apparent high bidder on a large number of blocks there that we found attractive. We are reviewing this judicial decision right now, and I can't comment more about that. We're disappointed because these lease sales have been conducted successfully in the Gulf of Mexico for decades and have allowed us to be one of the largest leaseholders out there with over 240 leases. It's a strong part of our base business, contributing to energy security in the country, producing some of the lowest carbon intensity barrels. We hope this is resolved in a way that enables continued development and investment in the U.S. energy economy.

And maybe just an overall question on refining. It feels like global product markets have tightened quite a bit with the outlook looking pretty encouraging for 2022. Can you provide some thoughts about how you're thinking about the setup for refining this year? What looks encouraging and what are some of the potential risks that you see to the outlook?

I mentioned earlier the demand recovery underway, and it's showing another leg. We've seen margins strengthen across our portfolio as last year wrapped up. These are encouraging signs. Asia still has some risks; the approach taken by some countries, notably China, to the pandemic may lead their economy to risks if variants continue to emerge. Other uncertainties exist in Asia, particularly within China's real estate sector. That said, broadly speaking, I think you're right, Ryan. We're observing improvements in refining; utilization rates are increasing. The chemical sector remains strong, though moderating from highs earlier in the year, still above mid-cycle. Overall, I believe we're setting up for a stronger year in '22 than we had in '21 across that sector.

Our next question comes from Alastair Syme with Citi.

I have a follow-up question regarding returns. I want to point out that the cash flow in 2021, excluding working capital, was nearly the same as in 2018, and the oil price conditions were similar during both periods. However, the payout ratio has increased significantly over the past three years. My question is, what is the Board's rationale for feeling confident enough to raise that payout ratio so significantly?

The capital efficiency is the big driver, Alastair. You're right: the commodity price environments in those two years are pretty similar as is cash from operations; however, we have capital spending that is significantly down from that time, meaning free cash flow is significantly higher. Our capital guidance for the next five years is $15 billion to $17 billion, down from $19 billion to $22 billion pre-COVID. That's a structural downshift. Our production guidance hasn't changed. We have a portfolio generating free cash flow and future cash flows more capital efficiently, allowing us to return more capital to shareholders. It's a straightforward story.

Our next question comes from Biraj Borkhataria from RBC.

It's a follow-up on North West Shelf and that reclassification there. Could you provide a bit more detail on the rationale for that? Is that a change in your intentions? Obviously, the last couple of years haven't been a great time to sell assets. I'm just wondering if that was a function of you not getting the valuation you desired or something else?

Biraj, regarding North West Shelf, we had an unsolicited offer on that asset some time ago, which led us to some interesting discussions. We're not in a position to sell assets to generate cash, but if an asset works better for someone else and they see a different value equation than we do, that's certainly a valuable conversation to have. Over the last period, we've been in a conversation like that, which ultimately has not led to a transaction, and that's changed the accounting classification for that asset. It's a good asset for generating strong cash flow. LNG demand is high, and there is a lot of gas in Australia still to run through these plants, making it a valuable part of our portfolio.

I view it more as accounting-related than anything else. There are a number of criteria that need to be met for an asset to be held for sale, and one part that no longer has met that criteria. That's why we did the catch-up depreciation.

That's very clear. The second follow-up was on Tengiz. I think you mentioned the potential loan repayments back to the parent. Do you have any guidance for 2022, given the current pricing environment?

Our guidance is no loan repayment, but also no additional loans. The dividend is included in the overall affiliate dividend. I will point out that we changed our guidance from focusing on the cash flow line to concentrate on the true cash part. If you refer back to that line, the difference between income and dividends from our affiliates is still expected to be about $2 billion higher than the dividends. However, there will be no loan nor loan repayment. We did have some repayment last year. The first dividend we received in years was in December. Expectations for strong dividends from Tengiz this year are based on the project's completion and capability for higher dividends to increase further, and we’ll share more on the cash flow generation capability of Tengiz during our Investor Day.

Our last question comes from Jason Gabelman from Cowen.

The first one is just on international gas exposure. Even backing out this timing impact, it looked like the realizations were a bit light. It’d be helpful if you could talk through that international gas exposure, likely separating it into pump-based, LNG-based, fixed-price segments, however you think about commodity exposure within that production bucket. The second question pertains to CapEx guidance. Your message is clear that this year you're planning to stick to around that $15 billion level. But as we look ahead, can you clarify if the $17 billion high end of the range is where we could see any ramp-up in spending in short-cycle basins? If oil prices stay elevated, can you ramp up in your short-cycle basins even more? I'm not thinking strictly about this year, but rather looking further out.

So on our LNG portfolio, you can think of it as about 80% oil-linked and 20% JKM. That includes Australia but also West Africa, so Angola LNG and Equatorial Guinea. For our international gas, we have lots of other contracts worldwide. Some of those are fixed price, some are partially oil-related with a lag, meaning you won't directly see an effect. We also have some contracts tied to domestic markets. But across our LNG, those three countries, Equatorial Guinea, Angola, Australia, the 80-20 mix is pretty accurate. Australia now is a little bit higher due to an additional long-term contract, but the West Africa LNG is largely influenced by spot-related prices like JKM or TTF.

On longer-term CapEx, if I caught your question correctly, we get this $15-$17 billion range we have proposed. We're at the low end of the range this year; that's a 30% step-up from $2 billion last year to $3 billion, translating to a 50% increase in wells produced. You should expect us to focus on execution and efficiency and not get ahead of ourselves in terms of risk management while pushing to keep these plans within the capital budget schedule. We’ll continue to operate from a disciplined stance while retaining flexibility within those limits. This opens up some capacity to allocate capital to other high-return investments.

I would like to thank everyone for your time today. We appreciate your interest in Chevron and everyone's participation in today's call. Please stay safe and healthy. Jen, back to you.

This concludes Chevron's Fourth Quarter 2021 Earnings Conference Call. You may now disconnect.