Chevron Corporation

Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's third quarter 2019 earnings conference call. At this time, all participants are in listen-only mode. After the speaker's remarks, there will be a question-and-answer session, and instructions will be given at that time. If anyone should require assistance during the conference call, please press star then zero on your touchtone 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. Wayne Bourdune. Please go ahead.

Thank you, Jonathan. Welcome to Chevron's third quarter earnings call and webcast. On the call with me today are Jay Johnson, EVP of Upstream, and Pierre Brever, CFO. We'll refer to the slides 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. Turning to slide three, and Pierre.

Thanks, Wayne. We had another quarter of strong operational and financial performance. First, an overview of our financial results. Earnings are $2.6 billion, or $1.36 per share. The quarter's results included a $430 million special item tax accrual associated with a cash repatriation in the fourth quarter. Foreign exchange gains for the quarter were $74 million. Excluding special items and FX gains, earnings were $2.9 billion, or $1.55 per share. A reconciliation of non-GAAP measures can be found in the appendix to this presentation. Cash flow from operations was $7.8 billion. We also maintained a strong balance sheet with a low debt ratio. Importantly, our strong cash flow allowed us to continue to deliver significant cash to our shareholders. During the quarter, we paid over $2 billion in dividends and repurchased $1.25 billion of shares. in line with our annual share repurchase run rate guidance of $5 billion. Year-to-date, we've returned approximately $9.5 billion in dividends and share repurchases. Year-to-date organic CapEx was $14.5 billion, slightly below our ratable budget of $15 billion. Total CapEx, which includes inorganic transactions that are unbudgeted, totaled $15 billion. We are maintaining a firm commitment to capital discipline to improve returns on capital. Turning to slide four, third quarter cash flow was strong, down from the prior quarter due to lower Brent prices and the absence of the termination fee received from Anadarko. On a year-to-date basis, cash flow from operations of nearly $22 billion funded all four of our financial priorities. With nearly $12 billion in free cash flow, we currently have an annualized yield of about 7%, highlighting our ability to generate strong free cash flow in a lower oil price environment. Through three quarters, the company's cash flow dividend break-even price, excluding working capital, is in the low 50s Brent. Asset sales proceeds add to our positive cash flow and further lower the break-even while high-grading our portfolio. Since the beginning of 2018, asset sale proceeds have totaled $3 billion, and by year-end, after the expected closing of the sale of our UK North Sea assets, we will be near the low end of our $5 to $10 billion guidance range with one year to go. Turning to slide five, third quarter 2019 earnings of $2.6 billion decreased about $1.5 billion versus prior year. Excluding special items and FX, upstream earnings declined primarily due to lower crude and natural gas prices partially offset by higher liftings. Downstream earnings also were down primarily due to higher turnaround and maintenance costs lower volumes driven by the Southern Africa divestment, and lower chemicals margins. The variance in the other segment primarily reflects lower corporate charges versus last year. Turning to slide six, compared to the second quarter, third quarter earnings decreased by about $1.7 billion. Excluding special items and FX, upstream results were lower, primarily due to a 10% decrease in Brent prices since the second quarter. Downstream earnings, excluding FX, improved due to stronger refining and marketing margins, partly offset by lower chemical margins and the impacts of planned turnarounds. The variance in the other segment primarily reflects lower corporate charges and tax items. I'll now pass it to Jay.

Thanks, Peter. On slide 7, third quarter oil equivalent production increased 3% compared to a year ago, with higher shale and type production in the Permian, as well as higher production from major capital projects following the ramp-ups at Bigfoot and Hebron. This growth was partly offset by unplanned downtime at Hibernia, asset sales, and the impact of Hurricane Barry in the Gulf of Mexico. Turning to slide 8. Third quarter production was strong at more than 3 million barrels a day for the fourth consecutive quarter despite the impact of planned turnarounds and asset sales. Year-to-date production, excluding asset sales, is about 5% higher than 2018, which is consistent with our earlier guidance of 4% to 7% as shown by the middle bar. Looking forward to the fourth quarter, we expect production growth to be primarily driven by our shale and tide assets as well as the continued ramp-up of Hebron. Turning to slide nine, I'll provide an update on the TCO project. In the third quarter, we completed a detailed cost and schedule review of the future growth and wellhead pressure management project in Kazakhstan. As a result, the cost estimate for the project has been updated to $45.2 billion, with an additional $1.3 billion in contingency. The expected startup of FGP has shifted to mid-2023 and will now follow WPMP, which remains on schedule for startup in late 2022. The updated estimate has been submitted by TCO for shareholder approval. Overall, the increase in total cost, including contingency, is about 25%. The waterfall shows the key drivers of the updated estimate. As discussed previously, higher engineering costs and engineering's impact on fabrication consumed about two-thirds of the original contingency. Additional construction costs represent the largest category of the revised estimate. More than half of the increase in construction cost is due to higher quantities than originally estimated, including significant increases for electrical and instrumentation which was one of the last scopes of the engineering work to be completed. The balance is primarily driven by higher unit construction rates due to higher market rates and more complex work than originally anticipated. Finally, the schedule and other category is primarily driven by the FGP schedule delay and increased costs for operational readiness and the owner's team. Despite the increased project costs, TCO remains a world-class asset that's expected to generate strong cash flow for many years. Turning to slide 10, beginning in 2020, we expect spending to ramp down as we complete the project. The project is approximately 70% complete. Detailed engineering and procurement are essentially complete, mitigating the risk of further impact on fabrication or construction. Work at three of the four fabrication yards is complete. The logistics system is working well, and the 2019 C-LIFT has successfully concluded. Modules are being delivered, restacked, and set on foundations as planned. Drilling is ahead of schedule with 40 of the 55 wells drilled and completed. The lower chart on the slide shows the completed and remaining capital spend. Most of the remaining scope now resides with construction and startup activities. Given the work completed, including two full years of on-site construction experience, we believe we're on track to deliver the project in line with the updated estimates. Importantly, we're not changing Chevron's capital guidance. Our 2020 capital to be announced in December will be in the range of $18 to $20 billion. And we're reaffirming our capital guidance of $19 to $22 billion for 2021 through 2023. We remain committed to capital discipline and delivering leading returns for our shareholders. Slide 11 highlights some recent commercial developments in our upstream business. First, we recently announced a farm-in agreement to take a 40% working interest in three Mexican blocks in the deepwater Gulf of Mexico. We also recently participated in Brazil's 16th bid round and were awarded a 35% to 40% working interest in two operated and three non-operated blocks. We're excited about these additions to our exploration portfolio. Last week, we signed an agreement to sell the company which holds our interest in the Malampaya gas fields in the Philippines. We're expecting the transaction to close in the first half of 2020. Now I'll turn it back to Pierre.

Thanks, Jay. And turning to slide 12, this quarter, there were a number of highlights related to lowering the carbon intensity of our operations. Earlier this month, earlier this month, we announced two new greenhouse gas reduction goals. The new goals are aimed at reducing our oil emission intensity by 5 to 10% and our gas emission intensity by 2 to 5% in between the years of 2016 and 2023. These are in addition to the targets we set at the beginning of the year to reduce our flaring intensity and methane emissions over the same time period. In Australia, we started up the Gorgon CO2 Injection Project in early August and are in the process of ramping it up to full capacity. Once fully operational, this will be one of the world's largest carbon sequestration projects and is expected to reduce Gorgon's greenhouse gas emissions by about 40% over the life of the project. Lastly, construction is underway on a new 29-megawatt solar farm which will supply electricity to Chevron's Lost Hills field in California. Now, looking ahead. In upstream, we expect full-year 2019 production growth to be in the middle of the 4% to 7% range, excluding 2019 asset sales. Asset sales, primarily in Denmark and Brazil, are forecasted to have a full-year impact near 30,000 barrels per day. Planned turnarounds. primarily in Gorgon and Nigeria, will be lower than the third quarter, but are expected to impact production in the fourth quarter by more than 70,000 barrels per day. As Jay mentioned earlier, we have acquired new exploration acreage in Brazil that is expected to add about $120 million in inorganic capital, which is unbudgeted. Full-year TCO co-lending is expected to be below the full year guidance of $2 billion, dependent primarily on the fourth quarter distribution decision. In downstream, we expect high refinery turnaround activity. This includes a refinery-wide turnaround at SPRC in Thailand, which occurs once every five years. In the fourth quarter, We expect to make the $430 million tax payment related to the cash repatriation and to repurchase shares of $1.25 billion. With that, I'll hand the call back over to Wayne.

Thanks, Pierre. That concludes our prepared remarks. We're now ready to take your questions. Keep in mind that we do have a full queue, so please limit yourself to one question and one follow-up. We'll do our best to get all of your questions answered. Jonathan, please open the lines.

Thank you. Ladies and gentlemen, if you have a question at this time, please press star then 1 on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. If you're listening on a speakerphone, we ask that you please first lift your handset before asking your question to provide optimum sound quality. Again, if you have a question, please press star then 1. Our first question comes to the line of Jason Gamble from Jefferies. Your question, please.

Thanks very much, guys. I guess the first question related to the updated 10 GEEs budget, given that a lot of the spending is already behind you, do you anticipate that this is going to have any significant effects on the co-lending that you'll be making to the venture in the coming years? And then maybe I'll just ask my second question now. The U.S. downstream earnings were pretty robust this quarter relative to what I would have expected, just given a heavy turnaround schedule. Is it just the margin environment that was helping out, or is there anything else that's happening in downstream that is maybe more rateable?

All right. Thanks, Jason. This is Pierre. So on co-lending, will provide guidance for 2020 next quarter as we have in prior years. As you know, co-lending depends on three primary factors, the level of the capital spend, oil prices, the macro environment, and any dividends. And I guided in the fourth quarter that we expect the full year for 2019 to be lower than our $2 billion, but it will vary depending on the fourth quarter dividend decision that TCO makes, So if the dividend is higher, the co-lending would be higher. If it's lower, the co-lending would be lower. So if you go back to how this cost increase impacts co-lending, you really have to look at it as overall cash flow. So clearly, if you hold prices and dividends constant, higher capital costs will result in higher co-lending. But that does not translate to lower Chevron cash because we're going to offset the increases in TCO elsewhere in our capital program. And so if you remember, TCO capital spend is non-cash, and co-lending turns part of it into cash because we think it's the most economic way to finance our share of the TCO spending. But again, we're going to have offsets elsewhere in our capital program, which will be cash capex, and that'll help offset that higher co-lending. If we go to downstream in the corridor, you know, we don't there's nothing that's, you know, that isn't inherent in the underlying margin, so that I can really point out to. You know, we've had, you know, distillate margins have popped up a little bit, and we tend to have some, you know, more production in that space. We're seeing some of the effects of IMO are rolling through the system. I mean, West Coast margins had some strength at times in the quarter, but I would attribute some the third quarter performance largely to how we operated in the underlying margin environment.

Very clear. Thanks, Peter. Thanks, Jason.

Thank you. Our next question comes from the line of Bill Gresh from J.P. Morgan. Your question, please.

Yes. Hi. Good morning. First question, just coming back to the idea that the 10 Gs capex increase will not affect the overall capital spending plan. Is this, you know, are we just talking here about the fact that perhaps you're at low end of CapEx ranges and now you move to high end of CapEx ranges or how do you calibrate being able to offset, you know, four to five billion of incremental spending next to Chevron, you know, within the budget? Is it activity elsewhere or is it just, you know, within ranges here we're talking about? Thanks.

Phil, there's a couple different places that we look to. First, TCO itself in its base capital spend has offset and will continue to offset some of the increase in the FGP spend. Beyond that, though, as Pierre was talking about, we have a much more flexible capital program now with a lot of short cycle activity, and we're able to pace and adjust that program to fit within the investment levels that we've set. and particularly as it relates to gas-related investments, are opportunities for us in this current environment to scale back some of that as appropriate. And those are things we may have done anyway. And the final thing is just the capital efficiency that we're driving throughout the business. Our base business performance has been very strong. We have digital initiatives trying to reduce and make our capital spend more effective. And so right across the board, people are figuring out ways to do more with less. I'll give you a good example within Bangladesh recently where instead of making a major capital project to add some additional compression, the team was able to look at recompleting some wells, adding some perforations, and doing some debottlenecking on existing facilities, which extended the production plateau and alleviated the need for incremental capital spend on another project. So it's these types of spending that we constantly are working through as we allocate our capital each year. We're going to remain capital disciplined. We're going to stay within the ranges that we've given you, and we're going to look to do it while we stay focused on delivering the value and returns that are really what's driving our decisions.

And if I can just build off of Jay's answer there, and just to be very specific, no, we do not intend to go from the low end to the high end of the range. We intend to find offsets through the way that Jay has talked about. We have a range because we're giving guidance out to 2023 It is a cyclical business. Oil prices can change. COGS can change. We have short cycle capital that we can flex up or down, as Jay mentioned. So the intent of the range, we still want to keep the range for what it's there for, and our intent is to offset increase elsewhere.

Okay. All right. Thank you for that, caller. And then I guess just a follow-up would be for Jay. I'm just trying to kind of rewind here back to you. A year or so ago, you know, there were some fears that things were getting a bit behind in 10 geese. And then back at the analyst day, the tone sounded, you know, much better that things were back on track. And now we have a 25% increase, which is fairly sizable. So I'm just hoping you can provide a little bit more color about how these things have progressed to the point that we have this kind of increase. Thank you.

Yeah, I think what's changed fundamentally is we completed a very detailed cost and schedule review in the third quarter. So that's just been completed. And as we looked at it, there were a couple of key elements. We've talked in the past about the overall engineering program, the cost of that program, and the impact the engineering has had on fabrication and construction. And you can see those in the first two bars of page nine, slide nine. And that really reflects that accelerated consumption of contingency that we've talked about in the past. What was frankly a surprise was the increase in quantities that we're seeing coming out of the late stages of engineering, particularly related to things like the electrical and instrumentation controls, fire and gas, some of the late changes in how we're going to do the backfill and quantities associated with it. Those drove a much higher construction cost than we had anticipated. And if you look at the third bar, you see that represented. The other big surprise was having to delay the startup of FGP by a year. This is really driven fundamentally by an assumption change. We had planned to integrate modules. Our estimate was based on the integration of the modules in FGP each one taking about 12 months from the time it was placed on its foundation until it was fully integrated. While we're seeing very complete modules come from the fabrication yard, just as we've gotten a year of ME&I experience this year, our view has changed that we're using 14 months as our planning basis, and that's pushed that schedule time out. So the growth in quantities and the longer schedule have really been the surprises that we didn't anticipate So that's really where we are at this point in time. Okay. Thanks a lot.

Thanks, Bill.

Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question, please.

Yeah, thank you. So the first question, just on the Permian and the glide path here, you continue to trend above your target levels. Can you just talk, Jay, with some detail about how the plan is progressing in the Permian and any comments that you would have on sort of this upcoming U.S. election and any impacts of the way you think about prosecuting your acreage?

Well, I'll start with just the performance in the Permian. Our view, as you know, has been to be very disciplined and focus on returns and efficiencies. And we have seen continued performance improvement in our drilling in particular. Our completions have remained very strong throughout. And so we're watching every segment of the value chain from the actual land acquisition to fill in some of the checkerboards and allow the longer laterals right through the drilling efficiency, the end of the completions, the facilities and on production, and then working with our marketing and transportation group to ensure that we're getting the highest realizations we can for the products that we're producing. So we're on plan. We've actually, as we said, doing very well with our production profile. We're pleased with the performance that we're seeing, but we're always driving for better performance. In terms of the upcoming election, look, hydraulic fracturing has been done for Millions of wells, not only in the U.S., but around the world. It's done safely. It's done effectively. We learn more about it all the time. And it's really unlocked a huge economic benefit for the country as well as for the companies involved. It's also unlocked some environmental benefits in terms of the proliferation of gas, which isn't always to our benefit from a profit standpoint, but it's a great fuel for the U.S., If you look at it from our company's standpoint, we have less than about 10% of our Permian unconventional acreage that is on federal land, and all of that is in New Mexico. So from a relative standpoint, while we would not like to see any kind of restrictions on hydraulic fracturing, that's the context for our company. No, that's great. I appreciate it.

And if the follow-up here is related to Brazil, there's the upcoming transfer of rights option, and you called out some of your increased exploration acres there. Can you provide some context in terms of the way that Chevron thinks about Brazil and how aggressive it sees itself being there over the next couple of years?

Well, we've talked before that we are – very happy actually with our existing resource base. We've been doing a lot of portfolio work, as you know, over the last several years to really clean up our portfolio. And part of that has been a reload of our exploration strategy. But because we're happy with our resource base, we have primarily focused on reloading in the exploration space because we're looking for resource additions out in the future. And we also want to manage our capital over the period of time. So our focus has been on exploration opportunities. That's what you've seen us do in Brazil, and our focus has been that way. We are interested in Brazil because we see the pre-salt as a prolific hydrocarbon basin. It's a good place to be to increase the probability of success on exploration, and we'll stay focused on that. We have a couple of wells coming up next year, which will be good wells for us. We're looking forward to seeing those results. but we'll continue to stay focused primarily on exploration as we look forward.

Thanks, guys. Thanks, Neil.

Thank you. Our next question comes from the line of Paul Chang from Scotiabank. Your question, please.

Hey, guys.

Good morning.

Good morning. Jay, I don't want to beat the dead horse on Tangi, but what have you learned from Tangi in terms of further fine-tuning your development and project execution process, clearly that something was not working in order for us to have that at this stage, to have the delay for a year, and also that for 25% increase. So what have we learned?

Well, Paul, it's a good question. We ask yourself all the time, how can we do better? Clearly, this is a disappointment. I'm very disappointed because we have taken all the lessons learned from the past and try to make sure we're building those into each project as we go forward. When we think about what's gone well, there have been a lot of dimensions to this, particularly the execution work is going very well. I'm happy with the way the fabrication work has gone in the yards. The modules are coming out very complete and dimensionally accurate. When we set them on their foundations, everything is lining up. The logistics system has been flawless. performance is exactly how we had planned. And it's delivering modules to the site very effectively. And we've been able to complete the sea lift for 2019. So we're happy on all those fronts. The scheduled delay is a disappointment. And that has to do a lot with the quantity growth we saw in engineering. And as we've said, we've been unhappy with the overall engineering performance on this project. Not only the engineering costs themselves, but the impact it's had on fabrication and construction. We need to do better in this area, and it's an area that we're going to continue to learn our lessons from this and build it forward. We don't have any other very large mega projects like this that are land-based anywhere in the world at the current time, so we've got time to take these lessons learned and really think about how we approach this differently in the future. Our commitment remains on capital discipline. Our commitment remains to execute this project to the best of our ability. When you look at the improvements taking place on the ground in Tengiz, in 2018, we talked about productivity that we needed to improve, and we saw 40% to 50% improvement in the productivity across the site. In 2019, this year, we've seen another 30% to 40% improvement in productivity. So we're seeing great improvements with the production, the construction management systems, And we're going to continue to stay focused on productivity, on completing work and moving it to mechanical completion and then getting it through systems completion and then to startup.

Yeah. And if I can just build off of Jay's answer, Paul, you know, just to put this in an enterprise perspective, the additional depreciation after tax to Chevron is less than 20 cents per share or less than the cash flow impact of a dollar change in oil prices. So, As Jay said, we own this and we need to do better. And trust me, we're fighting for every dollar. But I did want to put in perspective what this means for a company like Chevron.

Sure, I understand. But I think, Jay, when you're saying that you're unhappy about the engineering on this, so is it not to point the finger, but is it an internal issue or is it an external contract that you guys use? You're asking me to do that. How are you really going to be able to mitigate it in the future? I mean, you say you learn from that, but exactly what have we learned and what is the change will be?

From an engineering standpoint, Paul, I think we have a couple of things. One is we are doing more to bring the early engineering back in-house and do more focused design development with our own capabilities, and we're trying to minimize the amount of variation that we see in terms of each project team's decisions that they make around engineering. I think that's a key part of it, and I think looking at the total project in the context of the environment it's going to be built is also important. I do think there are also opportunities for the industry to improve on engineering. I don't think this is necessarily isolated to our company. So there's work to be done as we really understand how to better define and prosecute the engineering programs that are necessary for these projects.

And if I can just, you know, what Jay said is we don't have projects like this in our queue. If you look at our capital program, a lot of base business capital, shale and tight capital. We are going to have some major capital projects, but the ones that are coming up are deepwater projects and they're very different than these. A lot of the spending is in drilling and completion where we're very good. On the facility side, it tends to be standard designs, you know, in fabrication yards. As Jay said, it's not land-based projects in remote locations. And we have a better track record in those. So, again, we need to do better. We're learning from it. From an enterprise perspective, the portfolio, the investments that are at least, you know, in front of us, you know, are hitting a different place than where this project has been.

My final question, Jay and Peter. I think in 10G, even before the cost increased, the full project return on capital, the full cycle internal way of return is actually pretty low. And with this, of course, it's much lower. But the cash flow will be great once they become on stream. So which is a more important factor when you guys determine whether you want to go with a certain project? Is it the internal way of return or is the cash flow? and the sustainability of that cash flow, say, for how long? So trying to understand that the decision-making process.

Yeah, look, I'll start, and maybe Jay will add some comments. I mean, you've heard Jay and Mike and myself are all talking about increasing returns on capital. So we are focused on the return on investment, and so we are looking at it. Once you have a cost increase, I think it's stating the obvious that that dilutes the returns, and we're taking a lot of actions to offset that, both in Tanguy's and across the rest of the portfolio. I tried to give, again, some financials that kind of characterize what the impact is, again, on a company like Chevron, less than 20 cents per share. But, you know, we are looking fundamentally at returns on capital, but we also know cash is important. It helps pay the dividend and support the share buybacks.

I would just say this particular project, Paul, I know your views on it have been the same for a long time, but this is an important project for 10 geese. It does lower the back pressure on all the wells and addresses the declining reservoir pressure that we see there. It provides excess gas handling, which will unlock oil production in our existing facilities as well as for FGP, and it helps maintain reservoir pressure in the platform, which is an important aspect of the overall performance of Tengiz, not just the incremental performance. There also, as Pierre said, we're looking at ways that this can be offset. And one of the key milestones that was achieved was the decision to de-bottleneck the CPC pipeline. And so that's going to open up some additional export capacity, which will improve realizations and help boost returns and help mitigate and offset some of the increases that we're seeing on project cost.

Thank you, Paul.

Thank you. Our next question comes from one of Devin McDermott from Morgan Stanley. Your question, please.

Good morning. Thanks for taking the question.

Good morning, Devin.

I wanted to follow up on some of the exploration discussion from earlier. You talked a little bit about Brazil, but you also highlighted in the release and slides some additional blocks in the offshore Gulf of Mexico, and I think you've been fairly active in the U.S. Gulf of Mexico leasing as well. As we're going to step back and look at where you're seeing the most opportunity from here, can you talk a little bit more about that and the overall strategy here and the desire, if any, to diversify growth options away from shale and tidal? But I think you mentioned there were some larger capital projects offshore potentially in the pipe. So a little more color on that would be great.

Yeah, thanks for the question. So in addition to Deepwater Brazil, we have been very interested in some of the deep water in the Mexican areas of the Gulf of Mexico. And this plays on a lot of the knowledge we already have in the U.S. sector of the Gulf of Mexico. So we've recently farmed into some additional blocks, and these complement nicely some blocks we'd acquired in an earlier bid round. One of our strategies has been to move out of more of the frontier, highly speculative areas and really focus our exploration initiatives in the areas that we consider to be highly prolific basins, and that really increases our probability of success. At the same time we're doing that, we're trying to balance the amount of capital that goes in early and really use the fact that some of this is only under 2D seismic or lightly explored to open up new opportunities for development. In the U.S. Gulf of Mexico, we've been very active, and one of the key strategies in the U.S. Gulf is to focus a lot of our new blocks around existing infrastructure, and we're looking to push that envelope of how far we can tie back exploration opportunities or discoveries to existing infrastructure and avoid having to build brand-new greenfield A couple of examples of that would be, for example, you recently heard about the Essex discovery with another operator. That'll tie back to tubular bells. It's very close. It brings new production in at very low capital costs and with a very short cycle time. So those are kind of the low-cost, high-return subsea tiebacks that are being enabled and supported by our exploration strategy in the U.S. Gulf of Mexico. We're also talking about Extending that reach, as I said, through some of the new technology, we have used quite successfully the single-phase seafloor pumping at Jack and St. Malo and really proven that technology. And we've now finished the technical certification to move to multi-phase pumping. And this can really extend that radius of which we can pull production back to existing hosts that have ullage. So it's entirely in line with our theme of exploring in prolific basins. but also utilizing existing infrastructure and getting more out of our existing facilities whenever possible.

Got it. Great. And my second is on some of the comments around incremental efficiencies you're realizing across the portfolio is one of the things you mentioned in response to the Tengee's cost pressure. And Pierre, I think you mentioned it also as a an area where you've seen success across the portfolio in your prepared remarks. So I was hoping to get a bit more specifics on where within the portfolio you're seeing those capital efficiency improvements, and then also to the extent you are cutting back capital in more gassy areas in response to the 10 G's pressure, any additional detail on where that is, North America gas elsewhere in the portfolio, additional color would be helpful there as well.

Sure. You know, the increased efficiencies, quite honestly, are happening across the board. All of our units are really focused on how to continue to drive better performance out of the investments we've made in the past. We've seen some great improvements in particular, for example, in Angola, where they have developed some new opportunities by using our existing installed base system. We saw a very strong cash flow coming out of Angola. And there's been a lot of good cooperative work with the government of Angola to unlock many of the marginal reserves that can be tied back to our existing facilities. But it really is happening around the world. In terms of the Gulf of Mexico, we've seen our unit development costs come down to where we're now targeting $16 to $20 a barrel for new facilities. And projects like Anchor and Whale certainly we're targeting in that range. The OPEX in the Gulf of Mexico, in the deep water, has come down to just under $10 a barrel, which is a significant reduction from where we were in 2014. We're taking these lessons learned. We're sharing them across other areas in the company to make sure that it's one thing to share, it's another to adopt these best practices, but we're seeing great cooperation between our business units, and we're going to be really focused on doing that even more as we move forward. All of this isn't just in response to Tengiz, but rather it's the context of Tengiz in this environment that's allowing us to do this, and I think do it quite efficiently. In terms of the specifics on where in our capital program we'll be making changes, that's not something that we'll discuss at this point in time, but we'll give more color on that potentially in December with our capital announcement and, of course, in the SAM, the security analyst meeting that we do early in the year each year.

Understood. Thank you. Thank you. Our next question comes to the line. B. Ridge from RBC. Your question, please.

Hey, thanks for taking my question. Sorry, I have another one on Tengiz. Jay mentioned the significant productivity improvements in 2018-2019, but taking that on board, that would suggest the capex increase was coming quite a long time ago. So I guess Just want to square that comment with the cap has increased today and the timing of that. But taking a step back, you know, you look at the last few years and you've had your fair share of issues at some of these major projects. Pierre, you know, you're signing up on these. I just wonder if these experiences make you think twice about embarking on these types of projects of this scale in the future. That would be my first question. I've got another follow-up. Thanks.

So on the productivity, the contracts at site at Tenge's in the construction are largely unit rates. So we pay based on the quantities that are being installed. But the productivity is important because it relates to the underlying schedule and the ability to finish the work and execute the work in the timeframe that we've got and with the numbers of people we plan because there's a lot of indirects that come with having to add additional direct labor. So while the unit rates have been in place, It's really the complexity that has increased on some of the man-hours. We've talked in the past about the unit rate costs that were in our bids for the mechanical, electrical, and instrumentation work, but really the surprise has been the increase in quantities, because when you multiply the quantities times those rates, that's what's resulting in the higher cost, and as I said, the shift in schedule. So that's how I square that with what we've given you in the past and really what came out of the detailed cost and schedule review that we just completed.

Yeah, and, Viraj, in terms of – I think I addressed this. I mean, we don't have other projects like FGPW, PNP, NRQ. You know, Kitimat is being worked, but it's not ready. What we have is a lot of base business capital, a lot of shale and tight, and hopefully some deep water projects here over time. I understand your question. It's theoretical. I'm not going to speculate about it, but as I look at our portfolio right now, we don't have that choice. That said, we're going to be in the business a long time. We're going to learn from it. We have to do better, but we don't have any immediate capital decisions that are in this kind of a large-scale, land-based construction project.

Okay. Understood. Just to follow up, hopefully an easier question, but the tax on repatriated cash – Are you expecting that to be a one-off, or should we expect more of these in the future? And can you confirm whether that was cash tax or just a P&L charge? Thank you.

Yeah, so thanks for that question. So, no, we completed a global cash management review in the third quarter and decided to repatriate this cash, which was previously unremitted. So prior to completing this review, these earnings were expected to be invested in outside the U.S., and that's why we didn't accrue for the state and forward withholding taxes. So when we made the decision to repatriate it, that's when we accrued the tax. So it is a cash tax, but the tax payment will be in the fourth quarter. We accrued the P&L was in the third quarter. And the actual cash movements, so this will bring non-U.S. cash into the U.S., It will allow us to lower our cash balances. It will lower our debt balances. We're doing it because it's the right economic decision. And this is for prior earnings. You know, we do not expect other types of repatriations of prior earnings like this. At the same time, there could be some current earnings that, of course, are repatriated, and that's in the normal course of business. So, no, this is a one-off. It's over $8 billion of non-U.S. cash being brought to the U.S. You won't see our U.S. cash balances go down by that full amount because some of it had been lent into the U.S., but we expect our year-end cash balances to be $3 to $4 billion lower than where we ended the third quarter. We ended the third quarter a little bit high because we were preparing for some of these moves to repatriate the cash.

Got it. Thank you, Dennis.

Thank you. Our next question comes in line of Doug Leggett from Bank of America, Maryland. Your question, please.

Thanks, everybody. Good morning. Jay, I know you don't, or maybe Pierre, I know you guys don't normally want to talk about fiscal terms, but in light of the Tenge's cost increases, I just wondered if you could just remind us or walk us through what the implications are for cost recovery, because I'm guessing that With existing production and, you know, lack of ring fencing and so on, the net impact of this may not be as severe as obviously the headline cost overrun suggests. I just wonder if you could walk us through what the cost recovery ramifications are, please, and I've got a follow-up.

Well, this is a tax and royalty contract in Tengees, and so it's really going to be through the DDNA and the the way that flows through the books in terms of the recovery. So it's impacting returns more than it will the actual cash flow once we get past the startup of the facility.

I was under the impression it was an accelerated DD&A. Is that not the case?

As I said, we're not going to discuss the terms of the contract, but it's a tax and royalty contract. Okay. Okay.

And just to be clear, when I refer to the less than 20 cents, I'm talking about book depreciation, not tax depreciation, which obviously is different.

Okay. Sorry, I thought there was an accelerated piece to that. Thanks. My follow-up is really more going back to the Permian. Obviously, the plan you've laid out is continuing to outperform against at least the production profile. But when you laid out the plan, you talked about – when you would expect the Permian to be cash break-even in terms of capital and cash flow and obviously royalty contribution and so on. Obviously, NGL and gas prices have deteriorated quite materially. So I'm wondering if you could just update your thoughts on that and specifically on the takeaway solutions that you've announced over the last several months. What does that do to your ability to improved gas and NGO realizations. Are those leased line or are they going to uplift your realizations with more of a kind of Gulf Coast type metric? I'll leave it there. Thanks.

Well, we went through a lot of this, Doug, as you know, in the second quarter call and that guidance still stands. In terms of the crude takeaway capacity, you know, we have sufficient capacity not just to produce it into the basin but to take it to Houston and now we have export capacity opening up as well, 35% now and 40% in 2020. So that's the crude side of things. NGLs are sufficient through 2020. And in terms of gas, our primary focus was to make sure we have evacuation capacity in the basin, and we have 100% of that covered. Our view and our practice is that we have no routine flaring of gas to enable production, and we've been able to honor that. In terms of moving gas out of the basin, Right now, we have about 25% capacity, and it's going to vary based on how these different pipelines come on stream. But by the second quarter of 2021, we're expecting to have about 80% of our gas flowing out of the basin. We are still expecting to have free cash flow positive next year.

Jay, just to be clear, is it 60%, 65% gas in NGLs, or can you – I know you talk about liquids, but can you split the oil versus NGL portion, and I'll leave it at that. Thank you.

We see roughly half of our total mix is in crude, about a quarter of it's in gas liquids, and about a quarter of it's in natural gas.

Helpful. Thanks, fellas.

Thanks, Doug. Thanks, Doug.

Thank you. Our next question comes from the line of Dan Boyd from BMO Capital Markets. Your question, please.

Hey, thanks. Morning, guys. Hey, I want to actually follow up again on the TCO spend. And if I recall correctly, last year, you spent about $600 million more than you initially budgeted. So what I'm wondering is how much of the sort of overrun is going to be already spent or in the budget by the end of this year? That's sort of the first question. And then The follow-up is when I look at your total CapEx budget, in order to be below the $20 billion for next year, given that affiliate spending will still stay high, are you implying that your cash CapEx could potentially be down next year? And I'm just wondering if there's a potential production impact of that or if the Permian is running ahead of schedule enough to offset any of that.

So a couple things, Dan. First of all, I'd take you to slide 10, you know, and that kind of shows our production or our spending profile for the FGP project. And we see 18 and 19 as our peak years of spend. And as we look to 2020, we'll start spending at a lower rate as we move and consolidate really the activities largely into site construction work. We have one more year of fabrication to go in one of the four original yards, and that work is currently about 73% complete. In terms of how to allocate the incremental spend over the total project, I would say roughly it's about half of it behind us, about $4 to $5 billion in front of us, But as we look at it, it's really in that increased construction cost where we see the majority of the increase and the surprise. The part that we did in the first engineering and fabrication was more directed around the consumption of contingency. The increases we've really seen have been in construction and schedule.

So, Dan, again, just to build off Jay's comments, I mean, we're coming off of – we affirmed the guidance for next year between $18 to $20 billion. You know, TCO will be coming off, as Jay said, and so we have – you know, we're doing – we're finalizing our plan and our capital program right now, but we have – between the efficiencies that Jay talked about and choices we can make around deferring low-return projects, we absolutely have the capability of landing a capital program in that range.

Okay, and the production outlook more than offset that in other areas?

Yeah, I mean, we haven't given production guidance, you know, year by year. We've given the 3% to 4% production outlook to 2023, so no change to that. Again, some of the examples, some of the offsets do not impact production. Clearly, if we defer some lower return natural gas investment or we decide to flex down some of our short recycle spend, that could have a modest impact on production. But there are other things that are going better, like the Permian and other offsets that we're trying to manage. So we will give our usual one-year outlook on production guidance on the fourth quarter call in late January.

Okay. Thanks, guys. Thanks, Dan.

Thank you. Our next question comes to the line. Roger Reed from Wells Fargo. Your question, please.

Yeah, good morning. Thank you. I guess maybe it's been mentioned a couple different times, the weakness in gas. Maybe as you think about global gas markets, LNG, what you're seeing in terms of any additional risk we should think about on the spot market side or on the contracted side for LNG. And then as a little add-on to that, just kind of an update of how Gorgon and Wheatstone are performing here and planned and unplanned maintenance.

Okay. Gorgon and Wheatstone are actually performing quite well. Gorgon Train 1 is currently under a scheduled turnaround, a planned turnaround. But as you saw, our third quarter production, and there's a slide in the back, was very strong out of both Gorgon and Wheatstone. And we continue to stay focused on enhancing the reliability and the utilization of those facilities, as well as creeping the capacity. We have a turnaround schedule. that is going to be planned for both of those. And it'll be an annual event. Those will be we'll talk about those as we get closer to them. We have another train for Gorgon next year that has been announced. And these will be done to allow us to get into a regular rotation of turnaround so they can be done safely and efficiently just as we do in in our downstream facilities and places like 10 geese. We do see the The potential for spot to be higher as we increase production, as we hit stronger production, we will have more cargoes available for spot. That's a good thing because we actually have more production than we'd planned for. But over time, as the reliability continues to strengthen, we would expect to try and term up some of that anticipated spot cargoes and reduce the amount of spot in any given quarter relative to either long-term or medium-term contracts that we put in place.

Yeah, the only thing to add, and Jay mentioned this in the second quarter, we have seen some customers downward flex on the long-term contracts. This is something that within contractual limits and within the contractual terms, they have to do it almost a year ahead as tied to the annual delivery schedule. But we have seen some of that, and that has resulted in a little bit more in the spot market than we otherwise would have.

any particular weakness in the spot markets that you're seeing at this point, or are we pretty well past that for the summertime?

Oh, in terms of calling, look, it looks, you know, the macro on spot LNG looks, you know, sort of structurally oversupplied. Of course, a cold winter can certainly fix a fair amount of that, but storage levels in Europe, you know, are full, and Asia seems to be well-positioned. So, you know, if I look at it right now, again, it looks oversupplied, and there's more LNG coming on. But markets surprise us all the time. I mean, the takeaway for us is we are just not really exposed to the spot market. We are primarily selling under oil-linked long-term contracts. Thanks, Roger.

Thank you. Thank you. Our next question comes along. Sam McLaughlin from Wolf Research. Your question, please.

Hello. Hey, Sam. So... My first question is on the Permian and it's probably for Jay. I think it's well understood that your leading edge wells perform better and better. I'm interested as the base gets bigger and is more important to the overall production targets, how your first generation wells look, if your EURs that you projected look like they're intact or growing or changing in any way. And if there's sort of rigorous activity work, work over stuff that you have to do that you had modeled or maybe it's less than what you modeled, but just any update on kind of your older wells and how that component of the Permian is shaping up today would be great.

That's a good question, Sam. Thank you. When we look at our production performance out of our wells, the early horizontal wells have actually performed as we expected them to perform. And so our EURs have been consistent with expectation for the wells as we've moved through. As we have continued to evolve though, our basis of design and our completion strategies, we've seen higher and higher EURs and the new wells, of course, are meeting those expectations as well. Overall, the program is working as planned. The newer wells, as you point out, are much more productive than some of the older wells, but they're all meeting the expectations that we'd set for them at the time. in the aggregate. Obviously, any individual well may be higher or lower than planned, but as a portfolio, as a program, we've been overall pleased with the performance, and that's really what's underpinning our ability to deliver the production profile you can see on the chart in the appendix.

Okay. Thanks so much. And then just to follow up, Pierre, you get this question all the time about the leverage profile on the balance sheet, but the net debt continues to fall. The ratio of your free cash flow annualized in not a great year, to net debt is like one and a half times. Is there a level of net debt that you think is underlevered or, you know, suboptimal for the business, especially in the context of 10 Gs? If the biggest impact is, you know, a return impairment, you could enhance that to the equity with some leverage deployed somehow. So just your thoughts on how net debt's trending and what optimal leverage is.

Yeah, no, thanks, Sam. And look, yeah, we are generating good cash in a challenging macro environment. I think you know our four financial priorities. I'll go through them quickly. The first is to sustain and grow the dividend, and we increased it 6% earlier this year. The second is to reinvest capital in the business, and you heard Jay reaffirm our capital guidance, so we are not going to add to our capital program. The third is to maintain a strong balance sheet, and that's what you're asking. I'll get to that. And the fourth is our buyback program that we intend to sustain through the cycle, and we have that at a $5 billion annual rate. So what happens in the short term, clearly, if we generate more cash than those three requirements, in particular the dividend, which we increased earlier this year, the capital program, which we're holding flat, and the buyback program, then it goes to the balance sheet. That's where it's going to go in the short term. That's just how the math works. But over time, we expect if those conditions continue without speculating about future dividend increases or share buybacks, over time that cash should be returned to shareholders in the form of higher dividends and a sustained buyback program. Because, as you say, we don't need to be an even stronger credit. We have the leading balance sheet in the industry. We have the strongest balance sheet in the industry. And I've talked about a gross dividend. Debt-to-capital ratio of 20% to 25%. We're well below that. I'm comfortable being below that because that's, again, the outcome of our cash generation profile. Depending on where the macro environment, obviously that can change, but we are very well positioned to grow dividends, sustain the buyback, invest in the business, and maintain a strong balance sheet.

Thanks so much.

Thanks, Sam.

Thank you. And our final question for today comes from the line of Jason Gamel of Cowen. Your question, please.

Yeah, thanks for taking my question. I just want to firstly quickly confirm that 2019 CapEx hasn't changed as a result of the TCO overspend. And then secondly, just wanted to get your thoughts on M&A that hasn't been addressed this call. I think in the past you've discussed M&A. wanting to kind of expand or potentially acquire some company that operates in multiple arenas, not just one that operates in U.S. shale. I'm wondering if that's still the way you're thinking about M&A and how the opportunity set looks right now. Thanks.

Yeah, thanks, Jason. On your first question on capital for this year, our capital budget on an organic basis is $20 billion. Year-to-date, we're at $14.5 billion. So we're basically on track. We've had some modest inorganic capital year-to-date. That's been the Pasadena Refinery primarily, and we guided to a little bit for the Brazil exploration bid round. So again, we're on track for delivering an organic capital program in line with our budget of $20 billion. In terms of M&A, I'm not going to speculate on that. I think you've You've heard us talk about it. Look, we have a very strong value proposition. You know, we have a 4% dividend yield, a 2% share buyback or the buyback equivalent to 2% of the shares, a free cash flow yield of 7%, an advantage portfolio that Jay has been talking about with strong resources and reserves that allow us to grow cash flow and grow production over time. So we don't need to do a deal. You know, all that said, at times in the past, we have been opportunistic. When we think it's in the interest of our shareholders, it is difficult to make M&A work for our shareholders. And right now, we think we have a very good value proposition on our own for our shareholders. Thanks, Jason. Appreciate the question. Thanks.

Okay, Jonathan.

Yes, and I'd like to hand it back to you for any further remarks.

Well, that concludes our prepared remarks. We're now ready. Now that's the end of the call. Thank you very much.

Ladies and gentlemen, this concludes Chevron's third quarter 2019 earnings conference call. You may now disconnect. Everyone have a great day.