2Q22 Earnings Conference Call
Edited Transcript
Friday, July 29, 2022

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATIONFOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIESLITIGATION REFORM ACT OF 1995
This presentation contains forward-looking statements relating to Chevron’s operations and energy transition plans that are based on
management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words orphrases such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “advances,” “commits,” “drives,” “aims,” “forecasts,” “projects,”“believes,” “approaches,” “seeks,” “schedules,” “estimates,” “positions,” “pursues,” “may,” “can,” “could,” “should,” “will,” “budgets,”“outlook,” “trends,” “guidance,” “focus,” “on track,” “goals,” “objectives,” “strategies,” “opportunities,” “poised,” “potential,” “ambitions,”“aspires” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future
performance and are subject to certain risks, uncertainties and other factors, many of which are beyond the company’s control and are difficult topredict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements.
The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Unlesslegally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information,
future events or otherwise.
Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude
oil and natural gas prices and demand for the company’s products, and production curtailments due to market conditions; crude oil production
quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries; technologicaladvancements; changes to government policies in the countries in which the company operates; public health crises, such as pandemics (including
coronavirus (COVID-19)) and epidemics, and any related government policies and actions; disruptions in the company’s global supply chain,including supply chain constraints and escalation of the cost of goods and services; changing economic, regulatory and political environments inthe various countries in which the company operates; general domestic and international economic, market and political conditions, including themilitary conflict between Russia and Ukraine and the global response to such conflict; changing refining, marketing and chemicals margins;actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources
or product substitutes; development of large carbon capture and offset markets; the results of operations and financial condition of the company’s
suppliers, vendors, partners and equity affiliates, particularly during the COVID-19 pandemic; the inability or failure of the company’s jointventure partners to fund their share of operations and development activities; the potential failure to achieve expected net production fromexisting and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned
projects; the potential disruption or interruption of the company’s operations due to war, accidents, political events, civil unrest, severe weather,cyber threats, terrorist acts, or other natural or human causes beyond the company’s control; the potential liability for remedial actions orassessments under existing or future environmental regulations and litigation; significant operational, investment or product changes undertakenor required by existing or future environmental statutes and regulations, including international agreements and national or regional legislation
and regulatory measures to limit or reduce greenhouse gas emissions; the potential liability resulting from pending or future litigation; thecompany’s future acquisitions or dispositions of assets or shares or the delay or failure of such transactions to close based on required closing
conditions; the potential for gains and losses from asset dispositions or impairments; government mandated sales, divestitures, recapitalizations,taxes and tax audits, tariffs, sanctions, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements
compared with the U.S. dollar; material reductions in corporate liquidity and access to debt markets; the receipt of required Board authorizations
to implement capital allocation strategies, including future stock repurchase programs and dividend payments; the effects of changed accounting
rules under generally accepted accounting principles promulgated by rule-setting bodies; the company’s ability to identify and mitigate the risks
and hazards inherent in operating in the global energy industry; and the factors set forth under the heading “Risk Factors” on pages 20 through 25of the company’s 2021 Annual Report on Form 10-K and in subsequent filings with the U.S. Securities and Exchange Commission. Other
unpredictable or unknown factors not discussed in this presentation could also have material adverse effects on forward-looking statements.
As used in this presentation, the term “Chevron” and such terms as “the company,” “the corporation,” “our,” “we,” “us” and “its” may refer to
Chevron Corporation, one or more of its consolidated subsidiaries, or to all of them taken as a whole. All of these terms are used for convenience
only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.
Terms such as “resources” may be used in this presentation to describe certain aspects of Chevron’s portfolio and oil and gas properties beyond
the proved reserves. For definitions of, and further information regarding, this and other terms, see the “Glossary of Energy and Financial Terms”
on pages 24 through 25 of Chevron’s 2021 Supplement to the Annual Report available at chevron.com.
This presentation is meant to be read in conjunction with the Second Quarter 2022 Transcript posted on chevron com under theheadings “Investors,” “Events & Presentations.”

Chevron
July 29, 2022
11:00 AM ET

This transcript has been edited by Chevron Corporation. It is generally consistent with the original conference
call transcript. For a replay of the Investor Conference Call, please listen to the webcast presentation posted on
chevron.com under the headings “Investors,” “Events & Presentations.”
Operator:

Good morning. My name is Katie, and I will be your conference facilitator today.
Welcome to Chevron’s Second Quarter 2022 Earnings Conference Call. At this time, allparticipants are in a listen-only mode. After the speakers’ remarks there will be aquestion and answer session and instructions will be given at that time. If anyone should
require assistance during the conference call, please press star and then zero on yourtouch-tone telephone. 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.

Roderick Green:Thank you, Katie. Welcome to Chevron’s Second Quarter 2022 Earnings Conference
Call and webcast. I’m Roderick Green, GM of Investor Relations. Our CFO, Pierre
Breber, and EVP of Upstream, Jay Johnson, are on the call with me today.
We will refer to the slides and prepared remarks that are available on Chevron’s website.
Before we get started, please be reminded that this presentation contains estimates,
projections, and other forward-looking statements. Please review the cautionary
statement on slide two.
Now, I will turn it over to Pierre.

Pierre Breber:Thank you, Roderick, and thanks, everyone, for joining us today.
We delivered another quarter of strong financial results with ROCE over 25% – thehighest since 2008.
Special items this quarter include asset sales gains of $200 million and a $600 million
charge to terminate early a long-term LNG regas contract at Sabine Pass.
C&E for the quarter was nearly $4 billion – including inorganic spend to form our JV
with Bunge. With the acquisition of REG, our total investment was $6.8 billion – morethan double last year’s quarter.
Strong cash flow enabled us to fund this higher level of investment, pay down debt for
the fifth consecutive quarter, and return more than $5 billion to our shareholders throughdividends and buybacks.
Adjusted second quarter earnings were up more than $8 billion versus last year.
Adjusted Upstream earnings increased mainly on higher realizations, partially offset bylower liftings from the end of concessions in Indonesia and Thailand.
Adjusted Downstream earnings increased primarily on higher refining margins.
Compared with last quarter, adjusted earnings were up nearly $5 billion.

Adjusted Upstream earnings increased primarily on higher realizations partially offset by
tax and other items, including higher withholding taxes on TCO dividends and cash
repatriations.
Adjusted Downstream earnings increased primarily on higher refining margins and afavorable swing in timing effects.
The All Other segment was up due in part to a favorable change in the valuation of stockbased compensation.
I’ll now turn it over to Jay.
Jay Johnson:

Thanks, Pierre.
Second quarter oil equivalent production decreased about 7% year-on-year due toexpiration of our contracts in both Indonesia and Thailand, the sale of our Eagle Ford
asset, and CPC curtailments impacting TCO during April. This was partially offset byshale and tight growth, primarily in the Permian.
In the Permian, we’re delivering on our objectives of higher returns and lower carbon.
Our development costs are down about 25% since 2019, and we expect to keep them flat
this year by offsetting inflation with productivity improvements. An example is simulfrac, where we perform completion activities on four wells at a time, reducing cycle timeby a quarter.
We continue to design, construct, and operate facilities to limit methane emissions. Twoof our Midland Basin sites recently earned the highest ratings from Project Canary’s
independent certification program.
Production is at record levels and growing in line with guidance, with our royalty
position providing a distinct financial advantage for our shareholders.
At TCO, the drilling program is complete and the final metering station is online. We
expect to complete construction by year-end with remaining project activities primarily
focused on systems completion, commissioning, and start-up.
Total project cost guidance is unchanged. WPMP start-up is expected in the second halfof next year and FGP expected timing remains first half of 2024.
TCO’s operations continue to generate strong cash flow, enabling a mid-year dividend.
With project spend decreasing, we’re expecting higher dividends going forward.
In Australia, we shipped 87 LNG cargoes from Gorgon and Wheatstone in the first halfof this year – up over 10% from last year. Our reliability benchmarks are in the firstquartile and we intend to stay there with an ongoing focus on operational excellence.
Gorgon Stage 2, the first backfill project, is on track to deliver first gas in September.
Our Gulf of Mexico projects are progressing well, with Ballymore achieving FID as a tieback to Blind Faith, an example of leveraging our existing infrastructure to improve
returns. The Anchor hull is currently sailing from Korea and work on its topsides
continues in Texas.
Lastly, we recently signed agreements to export 4 million tonnes a year of LNG from the
U.S. Gulf Coast, with 1.5 million tonnes a year expected to start in 2026. Theseagreements leverage our growing U.S. natural gas production and expand our value
chains in Atlantic Basin markets.
Now back to you, Pierre.
Pierre Breber:Thanks, Jay.
We closed the REG acquisition last month and integration is going very well. We’repleased to welcome REG’s talented employees to Chevron and CJ Warner to our Board.
Our teams have already identified further commercial opportunities and we quickly acted
to lower insurance and financing costs.
In May, we launched our joint venture with Bunge. The JV is operating two existingcrushers and evaluation work is underway to expand crush capacity and add pretreatment facilities.
In carbon capture and storage, we closed on the expanded JV to develop the Bayou Bend
CCS hub. The lease held by the JV is in Texas state waters near large industrial emittersand we believe it is the first U.S. offshore lease dedicated to CCS. Also, we recently
filed for a conditional use permit in Kern County California to store CO2 emissions fromone of our cogeneration plants.
Now, looking ahead.
In the third quarter, we expect turnarounds and downtime to reduce production in a
number of locations. In Downstream, planned turnarounds are primarily at our California
refineries.
We do not expect significant dividends from TCO or Angola LNG until the fourth
quarter. Our full year guidance for affiliate dividends is unchanged, with upside potential
beyond the top of the range depending on commodity prices.
Also, we increased the top end of our share buyback guidance range to $15 billion peryear and expect to be at that rate during the third quarter.
In closing, we’re executing our plans, increasing investment to grow both traditional andnew energy supplies, and delivering value to our stakeholders. Although commodity
markets may be volatile, our actions are consistent through the cycle and focus on our
objectives to deliver higher returns and lower carbon.
Back to you, Roderick.

Roderick Green:That concludes our prepared remarks. We are now ready to take your questions. Please
limit yourself to one question and one follow-up. We will do our best to get all yourquestions answered.
Katie, please open the lines.

Operator:Thank you. If you have a question at this time, please press star one on your touch-tone
telephone. You may ask one question and follow-up question. If your question has beenanswered or you wish to remove yourself from the queue, please press star two. If you
are listening on a speaker phone, we ask you please lift your handset before asking yourquestion to provide optimum sound quality. Again, if you have a question, please press
star one on your touch-tone telephone.
Our first question comes from Devin McDermott with Morgan Stanley.

Devin McDermott:(Morgan Stanley)

Jay Johnson:

Good morning. Thanks for taking my question. Jay, I wanted to congratulate you on theretirement plans and take advantage of having you here on the call. My first one is on
TCO. It’s great to see the project progress there, and with the WPMP portion of the
project largely complete, I was wondering if you could talk a little bit more about theremaining milestones for that second phase FGP as you progress toward that first half2024 start-up?
Thank you, Devin, for both the retirement wishes and the question. At TCO, we’ve beensteadily making progress here, and we had a very strong period in the first half of thisyear. We had the unrest in January, of course, and then the team responded well afterthat even with some of the [COVID-19] Omicron impacts.
We expect to finish construction on everything this year and be largely into thecommissioning phase. And this is largely putting together, doing the pressure testing,filling the fluids, cleaning systems, and preparing them for eventual start-up. The WPMP
that we expect in the second half of next year will be around enabling us to boost thepressure from the field up to the facilities. We don’t expect to see a material change inour production at that point in time, but it enables us to move into the phase of start-up
for FGP where we will start to see incremental production coming through the plant.
Some of the big milestones we’ve already accomplished. All 40 production wells are
already now produced and completed and actually producing into the plant. That helps
us with the transition from the high-pressure to the low-pressure phase. We’ve got the
injection wells already completed, so we can begin the FGP start-up. Field facilities arewell underway in terms of the new gathering system. All the metering stations have to beconverted from high-pressure to low-pressure. They’ll be done one at a time, so we canmaintain production through that period.
You won’t see a lot of outward signs, other than progress on the commissioning, thenumber of subsystems completed, and that’s really what we’re moving into. We’re 93%
complete overall now. What’s going to be more important are the rundown curves as webring each system to completion.

Devin McDermott:Great. Thank you. Very helpful and great progress there. Sticking with TCO and thatpart of your portfolio, there’s been a lot of headlines around the CPC pipeline in recent
weeks and months. I was just wondering if you could give us a status update on where
things stand there? And then also to the extent that there were to be any further
disruptions to flows on that pipe, can you talk a little bit about the impacts to operations
for your base existing production in that area?

Jay Johnson:

The CPC [pipeline] continues to be an important export route for us. It handles the
majority of Kazakh crude that’s being exported to Western markets and it represents animportant supply to the world. It’s about 1.4 million barrels of oil a day coming throughthat.
The oil that we put into the line from Kazakhstan carries a certificate of origin from
Kazakhstan. We’ve done a lot of work in Washington D.C. and Brussels to make surepeople understand the importance of the pipeline to world supply. We’ve seen thereliability and the capacity to be able to maintain at the levels we need.
The interruptions that we’ve seen have been managed. We’ve gotten through those. As
we look forward, we just continue to work with the Kazakh government and with theinternational consortium that owns and operates the CPC pipeline to maintain this

important export route for the crude. There are some alternate export routes being
developed, but CPC remains the primary and most important route for us.
Devin McDermott:

Got it. Just to clarify, at the moment, operationally, you are at normal nameplate andflow rates through the pipe?

Jay Johnson:

Yeah. We’re at full capacity, both at TCO and through the CPC pipeline. They actuallywork quite well with us when they do have to take the pipeline down for ongoing
maintenance, which all pipelines have to do from time to time. They coordinate with the
producers. They’re often coordinated with turnarounds that the producing facilities areundergoing. The recent downtime for CPC as they were dealing with some of the resultsof the survey work around the terminal was coordinated with the NCOC turnaround
activities so that it didn’t have any impact at all on TCO’s production.

Devin McDermott:Great. Thanks so much.

Jay Johnson:

Thanks, Devin.

Operator:

We’ll take our next question from Neil Mehta with Goldman Sachs.

Neil Mehta:(Goldman Sachs)

Hey. Good morning team and Jay. Thank you for all the insights over the years and wish
you well in your retirement, sir.

Jay Johnson:

Thank you.

Neil Mehta:

The first question is on capital returns. You guys raised the top end, the buyback
guidance here. So just talk about the math that went into it and how you think about the
optimal return of capital formation, whether it is through buybacks or dividend growth?

Pierre Breber:Thanks, Neil. It’s Pierre. I’ll take that.
I’ll go through our financial priorities. They’ve been consistent for decades, literally.
The first financial priority is to grow the dividend. We’ve done that for 35 consecutive
years, increased it 6% earlier this year. It’s up 20% since right before COVID and it’sdoubled since 2010.
The second is to invest and grow both traditional and new energy, and you saw that our
total investments for the first half of the year were up 80% versus a year ago.
The third is to maintain a strong balance sheet. For the fifth consecutive quarter, we paid
down debt. Our net debt ratio is at 8%. That’s well below our mid-cycle guidance of
20% to 25%.
And when we have cash in excess of those first three priorities, we buy back shares, andwe intend to do it ratably over the cycle. We repurchased shares 15 of the last 19 years.
We bought back almost $60 billion during that time at an average price of around $90 ashare, very close to the weighted average price during that whole time. And as you said,
we just increased the top of the range of our guidance to $15 billion a year. That
represents about 1% of our shares each quarter.
The $15 billion annual rate is based on our current outlook. It was tested against anumber of scenarios. The rate is consistent with our [2022 Chevron] Investor Day upside
leverage case, which was a $75 Brent flat nominal price over five years.

As we’ve said with previous buyback rates, we intend to maintain buybacks at this annual
rate for a number of years across the commodity cycle. As a reminder, our net debt iswell below our mid-cycle guidance range. We’ll continue buybacks even when thecommodity cycle turns down, and we’ll lever back up our balance sheet closer to that 2025% guidance range.
Neil Mehta:

Pierre, the follow-up is just on the Permian. Can you talk about how you’re thinking
about the growth profile there relative to what you guided at the beginning of the year?
Does the upward drift in commodity prices change the way you’re thinking aboutprosecuting that asset?

Jay Johnson:

Neil, I’ll start out with that and then Pierre can finish if he’s got any other thoughts.
Our approach to the Permian, as you know, for many years, has been to be very
disciplined, very focused on generating the returns and the efficiency that allow us to be
profitable regardless of the prices. We’re not responding to short-term price, but we are
increasing our activity levels since the turndown during COVID. And we have seen ourinvestment go up. This year, it’s $1 billion higher than it was last year. We also see thenumber of wells that we’re putting on production going up. We expect to do over 200
POPs this year. We’re looking for about a 15% increase in our Permian production.
We’ve increased two additional rigs in July. We’re running now with a fleet of 10 rigs
across the Permian in the current time, and we expect to maintain that through the second
half. But I’ll remind you also one of our rigs today drills the equivalent of what two rigs
could do in 2018. Using just rig counts you have to be careful because we’re so much
more efficient with our rigs, and each frac crew today is also completing roughly double
the work they were doing back in 2018. We’re much more efficient than we were justfour years ago.
We expect to see our investment continue to grow. We’ve given you guidance ofincreasing our investment rate up to about $4 billion a year by 2024. And then I would
expect to see it relatively flat after that as we just maintain an efficient operation acrossthe Permian. We also have Non-Operated activity, and we currently have about nine net
rigs running on the Non-Op side. That also contributes significantly to our production
profile.
Our guidance remains unchanged. We’d expect to see about 1.2 to 1.5 million barrels a
day of production ultimately at our plateau. As we continue to gain insights andknowledge, as we look at our efficiencies, as we look at our portfolio and world demand,
that can change as we go forward. That’s our guidance as we see it today, and we’ll
continue to update you as we move forward in time.

Pierre Breber:

My only add is it’s also among our most carbon-efficient barrels in the portfolio. And as
Jay has said, it’s a demonstration of delivering on our objectives of higher returns andlower carbon. Thanks, Neil.

Operator:Thank you. We’ll take our next question from Jeanine Wai with Barclays.

Jeanine Wai:
(Barclays)

Hi. Good morning, everyone. Thanks for taking our questions.

Jay Johnson:

Morning.

Jeanine Wai:

Jay, we’d also like to wish you well and thank you for all your time over the years, andwe’ll stick to two Upstream questions just so we can get two last in before you leave.
Our first one is on LNG. This week, there was an announcement that Chevron, alongwith a couple of other partners, that you guys reached FID on development that’ll help
boost Angola LNG plant volumes. Can you talk about how you’re viewing expansion
opportunities in Angola, and also hit on Equatorial Guinea where you also have kind ofan equity position that feeds an LNG plant there? And is there a preference on how yourinvolvement evolves with LNG plants because you have some equity ownership, but wealso know that you had a Cheniere agreement that you announced recently that was morejust on the marketing front. So just wondering how you’re seeing your role there on newopportunities?
Jay Johnson:

That was pretty good, Jeanine. I think you got three questions in there, and I’m going to
try and move right through those.

Jeanine Wai:Oh, no. That was just one.

Jay Johnson:

I know. Teasing you. I’m allowed to do that. I’m the Upstream guy.
On the LNG in Angola, you’re right, we just took FID in the new gas consortium. There
are two primary sources of gas for Angola LNG. Traditionally, it was built for the
associated gas that’s produced along with the oil resources in Angola. That’s been themain source of gas for Angola LNG up to this point. We continue to develop new oil
resources with our 20-year extension. We just secured really good terms on both the oiland the gas. It encourages investment in that country. There’s a lot of oil still in Block 0.
That continues unabated. Actually, the investment will move forward.
The non-associated gas, in other words, drilling and developing reservoirs that are gas
only, is a new investment mode. We’re doing that through the consortium you
mentioned. That’s designed to be supplemental gas so that we can keep the Angola LNG
facilities full. And the ongoing effort to keep that plant running is really economic,
because it builds on existing infrastructure that’s already been built and the investments
have already been made. Importantly, it’s supplying needed LNG into the European
market and also gives us exposure to that Atlantic Basin. That’s been a good project forus, and we’re pleased to take that FID.
In EG, again, we have exposure now to the Atlantic Basin through that project. We
continue to produce there. There’s not much more I can say other than that’s also been a
profitable area for us and it came to us through the Noble acquisition. It was kind of oneof those more hidden jewels. We talk about Eastern Med, we talk about the DJ Basin inparticular, but EG is supplying a very good return to us through those gas and LNG
facilities.
In terms of our focus on ownership versus commercial, we’re really pretty agnostic.
We’re looking for the returns and the scale that we can build out of the business. We’relooking for multiple points of supply so that we can maintain an active and profitableportfolio. And where we can do commercial deals and not have to use capital to really beable to leverage other facilities, that’s always a nice way for us to go. I’m pleased to getthat exposure out of the Gulf Coast into both European and potentially Asian markets. It
gives us an access for a lot of our produced gas in North America to access those markets
rather than just U.S. Where it makes sense, we’ll also make investments as we have inother places and own the facilities or run them through joint venture or non-operated
facilities. We really look at what gives us the best opportunity to generate the returns
we’re looking for.

Jeanine Wai:

All right, thank you. We won’t sneak in our unrelated follow-up since that was a very
fulsome response. Thank you.

Jay Johnson:

Okay. Thanks, Jeanine.

Pierre Breber:Thanks, Jeanine.

Operator:

We’ll take our next question from Doug Leggate with Bank of America.

Doug Leggate:(Bank of America)

Thank you. 41 years in one place. Jay, that’s pretty impressive. Congratulations, sir.

Jay Johnson:

Thank you.

Doug Leggate:

I wonder if I could take maybe two questions for you, actually. Maybe Pierre might
prefer the second one. I want to go to the Permian first. You have about half yourproduction Operated and half Non-Operated. Can you parse between the inflationarypressures between your Operated and Non-Operated from what you’re seeing currently?

Jay Johnson:

It’s difficult for me to really do that definitively. What I can say, though, is I think wehave a competitive advantage in the Permian. We have a couple of things working in ourfavor. We maintain a global supply chain, and we’re able to tap suppliers of both
equipment and materials, goods, and services over a much broader range than maybe
some of our competitors.
We also do multi-year contracts and other mechanisms commercially that allow us tomitigate some of the inflationary pressures that we see today. And then, of course, ourfocus on driving for improved productivity, improved efficiency, has really helped uscontinue to counter the inflationary pressures.
I think the other area that we have a distinct advantage is that we’ve been building out
our infrastructure in the Permian. Just as a proof point, the last 800 wells over the last
five years, to produce those 800 wells, we had to build 40 central tank batteries. As welook forward, the next 800 wells, we only need to build an additional four central tankbatteries. While others are having to invest in this high inflationary period, we’re largely
using infrastructure that was built over the past five years with very small incremental
surface facilities required. I think that’s going to be hard for others to match.

Doug Leggate:That’s a very clear answer. Thank you.
Pierre, I don’t know quite how to ask this question. I’m going to try and get a part A anda part B perhaps, I’ll be respectful. Mike was interviewed recently talking about thetightness in the global oil market. I think he said something like, I don’t want to put
words in his mouth, but any weakness in oil prices is going to be fleeting because of theunderinvestment. And you guys obviously have stepped up your spending from COVID
levels, but you’re still well below pre-COVID levels ‘16 through ‘19, let’s say. With
your balance sheet where it is and the depth of opportunities that you obviously have thatyou’re not funding, how should we think about your continued commitment to the current
CapEx level? Or do we see Chevron re-engage in organic growth at some point?

Pierre Breber:

You should think that there’s no change in our guidance. Our 2022 capital is on track.
It’s likely to end up below our $15 billion budget. We’ve been ramping up during thecourse of the first half of the year, and I think you’ll see us higher in the second half ofthe year, but likely end the year below our $15 billion budget.
Our guidance that we shared at our March [2022 Chevron] Investor Day is $15 to $17
billion of organic capital investments through 2026. Our budget this year is around $15
billion. We have $2 billion of room to increase activity and investment within theguidance. And then as Jay just described, our major capital project in Kazakhstan iswinding down, it’ll decrease spending by about a billion and that opens up anotherbillion.
We will increase investment in activity next year. I expect that. We’re doing that work
right now. We’ll share the details in December when it’s finalized and approved by the
Board. We’ll increase it within the guidance. And that guidance enables us to: sustain
and grow the Upstream business as we’ve talked about – 3% compounded annual growthrate between now and 2026; add to our refinery capacity – we bought a refinery inPasadena, Texas in 2019, kept all of our U.S. refineries through COVID, and are making
investments in that Pasadena refinery that was just recently FID-ed; and of course, all theactivities we’re doing to grow new energies. We can do all of that within the guidance.
And as we recognize Jay, one of the things he deserves a lot of credit for is our Upstream
business is much more capital efficient than it’s ever been. And has a mindset of how do
we deliver business results with less capital. And if we do that, there’s more free cash
flow for shareholders.
Operator:
John Royall:(J.P. Morgan)

Jay Johnson:

Thank you. We’ll take our next question from John Royall with J.P. Morgan.

Hey, good morning. Thanks for taking my question. Can you talk about your growth in
the Gulf of Mexico in the Upstream? You’re leaning in there with number of Brownfieldprojects. Can you just speak broadly on how you view GOM within your portfolio? And
how the returns look on those bolt-ons relative to your other options globally in the
Upstream? And then what does the service inflation picture look like in that part of yoursystem relative to, say, the Permian?
Thank you, John. I’ll start this and let Pierre add in.
We’re really quite pleased with the portfolio we maintain in the Gulf of Mexico. It’s agood area of exploration for us. And it has some of the lowest carbon intensity in theworld. It’s about 6 kg CO2e per BOE produced. On a world scale, on even our company
scale, which is already top quartile, it’s right at the bottom end of that range. This is agreat area to develop for future production and carbon efficiency.
When we look at the queue of projects we have, we’ve got the Anchor project that is
expecting to have first oil in 2024. We’ve got Whale coming through, we expect in 2024.
We’ve been expanding our existing facilities. We’re starting up the waterflood at St.
Malo, which is part of the Jack/St. Malo complex. We’ve installed our multiphase pumps
and are commissioning those – that’s going to be an important milestone technologicallyin our ability to step out further and further.
We just took FID at Ballymore. Ballymore is an interesting one because it was a nicesized discovery, but we could really capitalize and get a much higher return by taking
three wells back to a host facility at Blind Faith and be able to develop that. We’repleased to be able to see that higher return coming from Blind Faith, and it also helps ourexisting production at Blind Faith.
As we continue to work forward, I think we’re going to see growth in our Gulf of Mexico
production, but it’s going to be important that we continue to be able to lease and acquire
additional acreage in that basin, along with others, because there’s still, I think, room forcontinual exploration and tieback to this great chain of infrastructure that we have to beable to produce this lower carbon fuel.

Pierre Breber:

Only add is our rigs were largely contracted when rates were lower. So clearly offshore
rigs have increased, but we’re largely contracted at prior rates. Thanks, John.

John Royall:

Thank you. Yes. So on the Downstream, I just had a question on particularly California,
just kind of your go-forward views there. Product balance is not quite as tight as they arein other parts of the country, but then we’re seeing some capacity come out due to RD
conversions there. And so just looking for maybe your medium-term view on refining in
California, specifically?

Pierre Breber:On the Downstream side, we had a strong quarter. Good execution, reliable operations,high refinery utilization, I’m talking generally now, U.S. West Coast and Gulf Coast.
Good cost control and we were able to capture the margins in the marketplace. We had aslight benefit in the second quarter because the Richmond turnaround was deferred. It
was a little bit less of an impact than what we had guided to on the first quarter call. And
timing effects really weren’t a driver, timing is more of the absence of timing effects thatyou saw. In terms of these markets, they’re volatile right now. We’ve seen margins
come off from where they were before.
In the second quarter, we saw a demand response on gasoline, probably around the midsingle digits across the U.S., a little bit higher on the West Coast, a little bit lower in the
Gulf Coast. Didn’t really see much on the diesel side. And jet is really tied to therecovery of travel. We’ll just see where the market takes us, whether it’s West Coast or
Gulf Coast, we’re focused on safe, reliable operations, continuing to have good cost
control, and delivering products that our customers are demanding. Thanks, John.

Operator:
Jason Gabelman:(Cowen)Jay Johnson:

Thank you. We’ll take our next question from Jason Gabelman with Cowen.

Hey, thanks for taking my questions. I have one on the Upstream portfolio and then one
on the financials. On the Upstream, can you just talk about your other gas opportunities
that you have available in the queue? Specifically, I’m thinking about the Eastern Med. I
know you’re delineating some acreage there, and it seems like there’s a lot of gas
available to exploit. And then also, I believe you have a Haynesville position. I’m notsure if that’s in the money or not that you’re looking at. And then I’ll ask my follow-up
after. Thanks.
Thank you. We have a lot of gas opportunities, and we’ve got a lot of infrastructure tobuild those opportunities on, which is really important because it gives us an advantage
from a return standpoint.
In the Eastern Med, which I’ll add is one of the lowest carbon intensity areas from Scope
1 and Scope 2, we’re at 2 kg CO2e per BOE produced. We have, of course, supplied alot of gas into the Israeli market and that opportunity continues to grow as coal isdisplaced. We also take that gas into Jordan for conversion to electric power. And now
we’re taking it into Egypt, where it can supply both domestic needs in Egypt, but also
potentially access some of the ullage that exists in the LNG facilities that are alreadyexisting in Egypt. We’re considering floating LNG as well. As you know, there are very
benign conditions, Med Ocean conditions, in the Mediterranean that lend themselves tofloating LNG, so it represents a viable option for us.
Developing additional gas capacity at Leviathan and Tamar is well within the scope of
those projects and would allow us to access these additional marketing opportunities
through the LNG and the flexibility that it provides.
We continue to have some upside potential in additional fields through EG. And thenwe’ve got access, as you pointed out, in the United States. We are ramping up our
drilling activity in the Haynesville, and we expect to see rigs there starting later this year
– they’ll be working that area. It was very profitable even at the low prices and it’s
profitable now. Again, our focus is going to be on discipline, on continuing to drive forthose efficiencies, but we really are excited to get Haynesville underway and add that toour portfolio in that part of the country. Thank you.
Jason Gabelman:

Great. Thanks. And my follow-up is just on the share count. I believe it went up again
this quarter despite the buyback, and it’s gone up since the buyback started. I think if you
back out the shares issued for Noble, it’s been flattish. So can you just discuss exactly
what’s going on there and your expectations for their share count moving forward withthe higher buyback but also at a higher share price? Thanks.

Pierre Breber:Yes. The share count is going down and will go down. What you see in the earnings
press release is a weighted average during the course of the quarter, not necessarily theend of the quarter. You’ll see in our 10-Q that the share count at the end of second
quarter is, in fact, lower than the first quarter, which you’d expect as we bought back 2.5
billion of shares and issued 0.8 [billion worth of shares for stock option exercises].
The first quarter, we had this very large issuance for our employees and retirees
exercising stock options. We started the year with a lower share count, issued those forour employee and retiree stock options, therefore, started second quarter at a higher rate
and then worked our way down. The math does work. It is going down. You have tolook end of quarter to end of quarter. But what you see in terms of earnings per share,
it’s an average over the quarter, and it’s kind of a quirk that second quarter average washigher than the first quarter, which is the nature of the pattern during the quarter. Sharecounts are going down. Thanks, Jason.

Operator:
Manav Gupta:(Credit Suisse)

Jay Johnson:

Thank you. We’ll take our next question from Manav Gupta with Credit Suisse.
Thank you, guys. My first question here is – I wanted to take expertise from Jay again –this was a heavy turnaround quarter for you. But even then, some of the things where
you were turning around were very high-margin barrels for you, so whether it was TCO,
Angola or Wheatstone. Help us understand, in terms of opportunity cost, if this volume
was somewhere in the lower-margin business versus some of your higher-margin
business? You’re saying Upstream results were good, but they could have been evenbetter, because some of the higher margin barrels were actually in a turnaround.
I appreciate the question. Manav, one of the things that’s really important to us is that we
operate safely and reliably. We look and we schedule our turnarounds and they’re
predominantly to ensure asset integrity and ongoing reliable performance. When weschedule those, we don’t like to shift those because of market conditions. We tend towant to execute those on time. What’s important is that we execute them within thetimeframes that we expected so that our production is in accordance with our planning.
Both Wheatstone and Angola LNG were done really, really well. I was proud of ourteams, they went in, they did the turnaround. This means now in Australia, all five trains
have been through the first round of turnarounds. That’s an important milestone and an
important accomplishment.
This work that we do, while it may seem like we’re giving up some opportunities in thenear-term, it allows us to continue to drive higher and higher reliability, which means ouroverall production will be higher and our costs will be lower and our safety will behigher. That’s really how we think about this.

Manav Gupta:

Thank you. And I have a quick policy question. About a month and a half ago, things
got a little heated between the oil companies and the White House. But as weunderstand, when the actual executive meetings happen between you guys and all theothers and the Secretary of Energy, those are pretty cordial and you guys were looking

for solutions out there. Help us understand what happened in the meeting with Energy
Secretary and how did those go?
Pierre Breber:Manav, we won’t comment on the specifics of our engagements. I think you’re right thatit’s constructive and productive. I’ll point out our U.S. oil and gas production in the firsthalf of the year was up 7% versus last year. Our U.S. refined product sales up 10%
versus last year. The administration wants energy supplies to increase, we’re doing that.
Our investment globally, up 80% first half of the year. If you look at the U.S., more thandouble when you include REG. Chevron is growing energy supply, increasing
investment, and we’re engaging constructively with Congress and this administration.
Thanks, Manav.

Operator:Thank you. We’ll take our next question from Biraj Borkhataria with RBC.

Biraj Borkhataria:(RBC Capital Markets)

Jay Johnson:

Hi. Thanks for taking my questions. Just one for me on Australia. I mean there’s gas
shortages in many geographies in Europe, in particular, but there’s been some talk aboutor noise around that in Australia. I wanted to understand whether we should expect any
export issues at Gorgon and Wheatstone? Are you in discussions with the government
around a proportion of gas going to domestic market versus what’s being exported oranything like that? Any color would be great. Thank you.
Thanks, Biraj. The shortages that you’ve heard about in Australia are all on the East
Coast, and there are no pipelines connecting the West Coast and the East Coast. So
actually, the only way that we could supply any gas to the East Coast of Australia is in
the form of LNG.
We are under long-term contract with customers throughout Asia. We also sell into thespot markets with those facilities. We have interest in North West Shelf as well as, ofcourse, Wheatstone and Gorgon. The Western Australian market is well supplied. It’s apart of our agreements for that supply. There really are no issues. I don’t see any impact
to our export capabilities in Australia.

Biraj Borkhataria:

Okay. Understood. And just a follow-up on the same topic. A couple of years ago, I
think I had a conversation with Pierre around the potential for increasing nameplate
capacity at Gorgon and Wheatstone over time. And as you go through the various
debottlenecking exercises, are you able to provide an update on whether that’s still in theworks, where you are, and what kind of timeline that would be on, if that‘s possible?

Jay Johnson:

Yes. We continue to focus on incremental capacity increases at both Gorgon and
Wheatstone, and that can happen through expansion of debottlenecking where weactually expand the capacity of the facilities. But importantly, it also happens as we
increase the reliability of facilities and their utilization is higher. If you just look at thisyear, we‘ve supplied 87 cargoes. As I said, that‘s up 10% on production from last year
even with the turnaround that we had. You can see the improvement happening there.
We have seen capacity increases at both Wheatstone and Gorgon, and I would expect
those to continue as we move forward.

Operator:Thank you. We’ll take our next question from Sam Margolin with Wolfe Research.

Sam Margolin:(Wolfe Research)

Hi. Good morning.

Jay Johnson:

Good morning, Sam.

Sam Margolin:

I wanted to revisit the LNG topic and maybe specifically tie it to the Permian because
there’s just a lot of resource in the Permian that’s not commercial, and that includes
different zones of what you’re already developing, plus areas that are not on yourdevelopment calendar in the near-term. LNG didn’t historically help with that because
it’s expensive, but obviously, things have changed now. And I would just love yourperspective on what happens to your Permian resource or your overall opportunity thereor the duration of it in an environment where you can add some extra capital or evencommit to a spread, but monetize gas for a double-digit price.
Jay Johnson:

I would characterize it as what determines our pace of activity in the Permian is a balanceon what we can accomplish efficiently. We have a factory model all the way from landacquisition. We do deals all the time to fill in the checkerboards and ensure an efficientdevelopment plan. As an example, just since 2017, we’ve executed over 260 transactions
that have added 3,500 [foot] long laterals. That’s allowed us to drive for this efficiency
and the higher returns.
Our activity levels really aren’t determined by how much we can export from the UnitedStates. All these projects that we have would be economic at much lower prices. It’s
really not the price that’s unlocking the Permian, it’s developing the infrastructure forexport from the basin into the markets that we supply, both domestic and international.
It’s all done in a coordinated fashion. We do it so we stay within the capability of theorganization to execute efficiently and safely, and that’s really what drives the Permian.
It’s nice to have access to these additional markets and the optionality they provide. We
have an advantage in working closely with our Midstream group who has great
capability, both again for the domestic offtake and setting up potential for international
export, but it’s really not what I would view as the limiting factor on our pace. We
determine that based on our overall balance of free cash flow, the returns, and ourresource and reserve replenishment.

Sam Margolin:

Okay. And then, maybe just to follow up, are there any ancillary factors that might be aconsideration like an opportunity to fit another CCUS project on a facility or what it
might contribute to like a flaring mitigation effort or anything besides just a price signal?

Jay Johnson:

As Pierre said earlier, the Permian actually has very good carbon intensity on a Scope 1
and 2 basis. We’re at 15 kilograms of CO2e [per BOE produced] across the basin. We’renow benchmarking our facilities and achieved certification of platinum status [at two of
our Midland Basin sites] with Project Canary, which then provides independent thirdparty certification of our methane emissions and the performance that we have beentalking about. We are working with both our Chevron Technology Ventures, which is
our venture capital arm, and our New Energies segment on the carbon capture andsequestration.
Carbon capture, in particular, is critically important for not just us, but the world. We
have three pilots going on at San Joaquin Valley operations to capture the CO 2 that’s
coming off of our cogen units there. And then, of course, we’re gaining experience atGorgon and Quest up in Canada, where we learn more and more about what it takes toeffectively and efficiently sequester CO2 into storage. These are all going on.
The beauty of having a portfolio like we do is we can put these pilot projects anddemonstration projects wherever it makes the most sense, both from a regulatory, fiscal,
and return standpoint, and develop these technologies that we’re all going to need going
forward.

Pierre Breber:Thanks, Sam.

Operator:
Irene Himona:(Société Générale)

Pierre Breber:Thank you. We’ll take our next question from Irene Himona with Société Générale.

Thank you. Good morning and congratulations on the strong quarter. I wanted to ask,
first of all, about what you’re seeing on the ground in terms of any signs of persistent
demand destruction at retail, but also at industrial customer level, please.
Irene, I said it very quickly earlier. We’ve seen, I would call it, demand response tohigher prices, that in the second quarter was about in the mid-single digits in the U.S. on
gasoline. Again, a little higher on the U.S. West Coast, a little lower on the U.S. Gulf
Coast. I think we’ve seen some recovery since because prices have come off, so we’ll
see where our third quarter ends up. On diesel, it’s very hard to see, not as pricesensitive, it’s tied to commercial and industrial activity, maybe a little bit of a response atretail diesel. And then jet is largely tied to the recovery in air travel, and I think people
are wanting to get out and see people and places. Asia, where we also have retail, is alittle more variable because there’s still been COVID restrictions, and so it’s hard to see
the data.
What’s interesting is there’s obviously concerns around the recession. In terms oftailwinds, we still have very low unemployment, and we have a consumer that wants tospend money to go out and do things they haven’t been able to do for a couple of years.
When prices were higher in the second quarter, they made some choices. And if you lookat that demand response on gasoline, that’s in line or even higher than some past
recession, so it’s not clear. I guess what I’d say is demand will be much more recession
resilient going forward just because we’ve seen a little bit of that response in the second
quarter. And again, diesel will be tied to underlying commercial activity. Jet will reallydepend on if the airlines can get all the flights scheduled and have pilots and all the restof the challenges that have been happening over there. That’s a little bit of a sense of thedemand. We saw a response second quarter, seeing some of it come back here early third
quarter, and we’ll just see where it goes from here.

Irene Himona:

Thank you, Pierre. For my follow-up, and as you mentioned, you’re launching some newcarbon capture projects. I wanted to go back to Australia and ask if you can possibly talkaround the recent performance at the Gorgon carbon capture project. Is utilization
improving? And is there any read through perhaps on the technical side from that projectto the ones you’re launching now? Thank you.

Jay Johnson:

Thanks, Irene. At Gorgon, we’ve now stored successfully about 6.6 million tonnes of
CO2 into that reservoir. Ironically, the biggest issue we’re having currently is just theability to remove water at a sufficient rate from the storage reservoir to create the space
for the CO2 to enter. We’ve already demonstrated the capacity and capability to injectfull CO2 rates into that reservoir, but the water that we’re producing has some solids in it
and some other contaminants, ironically, oil and gas because it’s an oil and gas basin.
And we need the surface facilities that can just remove those before that water is injected
into a third reservoir.
These are not new or particularly high technology challenges at all. It’s what we deal
with in everyday life around the world. It’s just that it’s compounded a little bit because
Gordon sequestration is in a Class A nature reserve, so it’s a very cumbersome process toapprove additional facilities and additional wells. But these problems are solvable, andthey do not represent, in my view, any kind of a restriction on the viability of carbon
sequestration as a means of storing CO2 for long periods.
What I would expect is that, and we said this before, as we learn, as we go through this,what it’s teaching us is that there are uncertainty ranges on any reservoir. Whether you’re
producing from it or injecting into it, having sufficient contingencies and mitigationsdepending on where you find yourself in those uncertainty ranges, when you actually put
the facility into operation is important, and we’ll need to keep these in mind as wedevelop sequestration projects around the world. The science is good. The technology
works. It’s just the basic issues that we face on reservoirs around the world that we now
need to overcome.
Operator:
Paul Cheng:(Scotiabank)Thank you. We’ll take our next question from Paul Cheng with Scotiabank.

Hey, guys. Good morning. And Jay may I add my congratulations and thank you for thehelp over the years. We appreciate it.

Jay Johnson:

Thanks, Paul.

Paul Cheng:

Two questions. First, you touched on the inflation in different parts of your business.
But can you give an overview, or given your footprint, can you give us an overall viewon what is Chevron’s expectation on inflation for next year? I know it’s still early foryour budget, but are we talking about 10%, 15%? Some of your largest suppliers seem tosuggest that everything is all used up in terms of manpower and equipment. So I don’tknow whether you agree with that assessment. And if you can tell us where you see,along the supply chain, the biggest pressure point and where you see the least inflationarypressure? So that’s the first question.
The second question is on Mexico and Brazil. You guys entered, I think, a couple ofyears ago and had some blocks over there, but I haven’t heard you guys talk too muchabout those. Where do those rank within your portfolio today? And what is the next stepin those? Thank you.

Pierre Breber:Thanks, Paul. I’ll take the first, and then I’ll hand it to Jay on the second. On theonshore U.S., we’ve seen cost inflation this year in the single digits. We’ve been able tomitigate part of that through good planning, smart procurement, and good relationships
with suppliers. And as Jay pointed out, we’ve been able to also get more efficient with
our drilling and completion operations, which also partially offsets it.
Outside of the U.S., we’re seeing much more modest inflation, and we talked about our
Gulf of Mexico offshore rigs, which were contracted at a time when the rig rates werelower. As we’re looking toward 2023, we’re doing that work right now. We’re confident
that we’ll be able to secure all the goods and services that are needed for our program.
Again, our program will be a higher activity program next year, and that includes thePermian. And we’ll share estimates of what we’re seeing in terms of COGS inflation
when we disclose our CapEx budget in December. We’re just in the middle of that work
right now. I feel very good that we’ll have all the goods and services that we need, andwe’re finalizing our plans. Jay?

Jay Johnson:

Yes. Thanks. Paul, in terms of Mexico and Brazil, we have not had significant
exploration discoveries there. We are turning our attention, I would say, towards Egypt
where we have a very nice exploration position. We’re shooting seismic. These are inareas that have been unexplored before because they’ve been in restricted areas and now
available to us. [And] Suriname. As we do in exploration, we’re always going throughand looking for the next opportunities, but I would say our focus primarily is shifting now
toward Egypt and Suriname. Thanks for the question.

Operator:Thank you. We’ll take our last question from Ryan Todd with Piper Sandler.

Ryan Todd:

(Piper Sandler)Thanks. Maybe first one on the biofuel side. You’ve now closed both the REGI and theBunge deals. Within that business, can you talk a little bit more about what you’re seeingin those markets? And whether you can elaborate at all about the broad types ofcommercial opportunities that you see that you mentioned in your prepared remarks?

Pierre Breber:Thanks, Ryan. We’re really excited to welcome REG’s people to Chevron and CJ
Warner to our Board. She’s already participated in our first Board meeting. She isfantastic, has great knowledge of traditional and new energy businesses, and it’s just agreat add to our Board.
As I said, we had some early wins. I won’t get into the details of the commercial
opportunities, but it’s what we saw in the combination. The strength that REG has interms of feedstock acquisition, primarily of waste oils, and then combining that with our
retail and marketing footprint, and just bringing two great teams together. We’re seeing
as you’d expect, one plus one is more than two. We’ve got our renewable fuels businessheadquartered in Ames, Iowa, and we’re very excited about it.
We closed in mid-June. Just a comment on the accounting. There were no results in our
second quarter results because we chose the convenience day of June 30 th. So all you’ll
see or all you saw in our earnings release and you’ll see in the 10-Q was just the purchaseaccounting. Starting in the third quarter then we’ll see REG in our results. REG had agood second quarter. Margins have been bouncing around, but the results are largely inline with expectations and Geismar continues on track.
Same thing with Bunge, operating two crushers, very excited to be part of that. Invested
in CoverCress, jointly, which is a crop that won’t compete with food. So lots of work inthis space as we work to get to our renewable fuels capability up to 100,000 barrels a day[by 2030]. We’re still on-track to convert a diesel hydrotreater at El Segundo to haverenewable fuel capability and work across other parts of Chevron’s system.
The combination of REG, our Bunge joint venture, and our own assets, along with ourcustomer relationships, we’re all putting that together to have what we think will be avery successful, viable renewable fuels business.

Ryan Todd:

Thanks, Pierre.
Maybe the final one for Jay. Congrats on the retirement. I wanted to ask a higher-level
question on Upstream project development and technology. There’s been a pretty
significant shift over the last 5 to 10 years in the way that you’ve approached project
development, more standardization, oftentimes smaller and more capital-efficient styleprojects. Ballymore is a great example of this. It’s lowered the cost of supply a lot,
especially in the deepwater. As you pass the baton and look forward into the next 10
years, are there things that you can see on the horizon either strategically or technologies
that may continue to drive changes in project development and technology that may drive
things forward even further whether it’s a 20K kit in the deepwater, SURF [subsea
umbilicals, risers, and flowlines] and flowline improvements that allow longer tiebacks,
and what could this mean for the future of your resource development portfolio?

Jay Johnson:

Thanks for the question. It’s pretty exciting. I mean the one bad thing about retirement
is you don’t get to be part of the next steps, and I’m excited about them. I would start byjust saying, I think we’ve accomplished a mindset shift in Chevron, and this is throughout
our workforce, being very focused on returns, not chasing a production target, but
continuing to run this as a business and thinking about the returns we can get. Scale isimportant, but it’s an outcome of the opportunity set that we have and the investments
and capital that we choose to invest.

Getting more focused, the factory model has been really important to us. And ironically,
this started where we drilled lots of wells in places like Duri and the San Joaquin Valley.
We’ve now successfully transferred that into our unconventional plays in Permian, in theDJ, in Duvernay, and Argentina. And now we’re actually taking that factory model into
places like the Gulf of Mexico, where we do what we call urban planning, and we try andhave a steady progression of projects, and we’re developing the capability for further andfurther reach.
I mentioned earlier that Jack/St. Malo is now putting into service multiphase pumps.
These multiphase pumps sit on the sea floor, but they allow us to reach 30, 40, and evenmaybe 50 miles out from a host facility which really gives us great capacity to make evensmaller accumulations economic and gives us the returns we’re looking for while
extending the life of these major hubs. I think the Gulf of Mexico will continue to be an
important proving ground for some of these technologies that can then be exported
around the world.
Our focus on standardization, our focus on minimum viable facilities, our focus on
capital efficiency over just scale and NPV, all these together are resulting in and aligningwith [Chevron’s] Technology Center, so that we continue to develop the technologies
that are giving us the returns that we’re going to need going forward. With the resourcebase that we have today, and the team of people that we have in our technology groups
and in our businesses, I’m really excited.
Pierre Breber:Hey, Ryan. Thanks for that question.
We will miss Jay, but his legacy will live on, and you’ll see it in the performance that theUpstream has been delivering and will continue to deliver.

Roderick Green:Thanks, Ryan.
I would like to thank everyone for your time today. We appreciate your interest in
Chevron and everyone‘s participation on today‘s call. Please stay safe and healthy.
Katie, back to you.

Operator:Thank you. This concludes Chevron’s Second Quarter 2022 Earnings Conference Call.
You may now disconnect.