Chevron Corp (CVX) — Q3 2019 Earnings Call Transcript

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 Breber, 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 2. Turning to slide 3. And Pierre?

Thanks, Wayne. We had another quarter of strong operational and financial performance. First, an overview of our financial results: Earnings were $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 4. 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 the three quarters, the company's cash flow dividend breakeven price, excluding working capital is in the low 50s Brent. Asset sales proceeds add to our positive cash flow and further lower the breakeven 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 U.K. North Sea assets, we will be near the low end of our $5 billion to $10 billion guidance range with one year to go.

Thanks, Pierre. On slide 7, third quarter oil equivalent production increased 3% compared to a year ago with higher shale and tight production in the Permian as well as higher production from major capital projects following the ramp-ups at Big Foot 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 tight assets as well as the continued ramp-up of Hebron. Turning to slide 9. 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 start-up 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.

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, 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 the years between 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.

Thanks very much, guys. I guess the first question related to the updated Tengiz 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 you out or is there anything else that's happening in downstream that is maybe more ratable?

Thank you, Jason. This is Pierre. Regarding co-lending, we will provide guidance for 2020 next quarter, as we have in previous years. Co-lending depends on three main factors: the level of capital spending, oil prices, and the macro environment, along with any dividends. I mentioned in the fourth quarter that we expect the full year for 2019 to be below our $2 billion forecast, but this will depend on TCO's fourth quarter dividend decision. If the dividend is higher, co-lending will increase, and if it's lower, co-lending will decrease. To assess how this cost increase affects co-lending, you need to consider the overall cash flow. Holding prices and dividends steady, higher capital costs will lead to higher co-lending, but this doesn’t mean lower cash for Chevron since we will offset the increases in TCO elsewhere in our capital program. Remember, TCO's capital spend is non-cash, and co-lending converts some of that into cash because we believe it's the most efficient way to finance our portion of TCO spending. However, we will have offsets in other cash capital expenditures, which will help mitigate the higher co-lending. Moving to Downstream for the quarter, there isn't anything outside the underlying margins that I can highlight. Distillate margins have increased somewhat, and we expect more production in that area. We are seeing some effects from IMO rolling through the system. While West Coast margins showed some strength at times this quarter, I believe the overall performance in the third quarter was mainly due to our operations within the existing margin environment.

Very clear. Thanks, Pierre.

Good morning. My first question is regarding the increase in Tengiz capital expenditure and its impact on the overall capital spending plan. Are we discussing the possibility that you might be shifting from the low end to the high end of capital expenditure ranges? How do you plan to offset the additional $4 billion to $5 billion in spending within Chevron's budget? Is this adjustment due to activity in other areas, or is it simply a matter of moving within established ranges? Thank you.

Phil, we have several avenues to manage this. First, TCO's base capital expenditures have helped balance and will continue to balance some of the increases in the FGP spending. Additionally, as Pierre mentioned, our capital program is now more flexible, allowing us to pace and adjust our spending to align with the investment levels we've established. In particular, regarding gas-related investments, we have the opportunity to reduce some expenditures in this current environment, which we might have done regardless. Lastly, we're focusing on capital efficiency across the business. Our core operations are performing very well, and we are initiating digital projects to enhance the effectiveness of our capital spending. Overall, our teams are finding ways to achieve more with less. For instance, in Bangladesh, instead of initiating a large capital project for additional compression, the team successfully looked at recompleting some wells, adding perforations, and optimizing existing facilities, which extended our production plateau and reduced the need for additional capital on a new project. These are the types of expenditures we continuously evaluate as we allocate our capital yearly. We will maintain discipline in our capital spending, stay within the ranges we have communicated, and remain focused on delivering value and returns which drive 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 color. And then, I guess, just a follow-up would be for Jay. I'm just trying to kind of rewind here back to a year or so ago, there were some fears that things were getting a bit behind in Tengiz and then back at the Analyst Day, the tone sounded much better that things were back on track. And now that we have a 25% increase, which is fairly sizable. So I'm just hoping you could provide a little bit more color about how these things have progressed to the point that we have this kind of increase? Thank you.

Yes. We've recently completed a comprehensive review of our costs and schedule in the third quarter. During this review, a few key factors emerged. In the past, we've discussed the overall engineering program, its costs, and the effects of engineering on fabrication and construction, which you can see represented on page 9. This highlights the accelerated use of contingency funds we've mentioned before. However, what surprised us was the increased quantities arising from the later stages of engineering, especially concerning electrical and instrumentation, controls, fire and gas systems, and some recent changes in our backfill approach and related quantities. These factors led to significantly higher construction costs than we originally expected, as shown in the third bar. Another unexpected development was the delay in the start-up of FGP by a year. This was mainly due to a change in our assumptions. We initially expected to integrate modules, estimating that each integration would take about 12 months once placed on its foundation. Although we've seen well-prepared modules coming from the fabrication yard, after a year of ME&I experience, we've adjusted our planning to a 14-month timeline, which has extended the schedule. The increase in quantities and the adjusted schedule were both surprises that we did not foresee at the start. This is the current situation we find ourselves in.

Okay, thanks a lot.

Yes, 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 the way you think about prosecuting your acreage?

I will begin by discussing our performance in the Permian. As you know, we have been very disciplined and focused on returns and efficiency. We have seen ongoing improvements in our drilling performance, particularly in our completions, which have remained strong throughout. We monitor every part of the value chain, from land acquisition to optimizing our checkerboard areas and longer laterals, as well as drilling efficiency, completions, facilities, and production. Additionally, we collaborate with our marketing and transportation teams to maximize our product realizations. Everything is on track, and we are pleased with our production profile, although we are always striving for better results. Regarding the upcoming election, hydraulic fracturing has been successfully employed for millions of wells globally and has been done safely and effectively. We continually learn more, and it has provided significant economic advantages for both the country and the companies involved. Furthermore, it has enabled environmental benefits through increased gas availability, which, while not always beneficial from a profit perspective, is a valuable fuel for the U.S. From our company's point of view, less than 10% of our Permian unconventional acreage is on federal land, all of which is in New Mexico. Therefore, even though we oppose any restrictions on hydraulic fracturing, this is our company's context.

No, that's great. Appreciate it. And then, the follow-up here is related to Brazil. There's the upcoming transfer of rights auction and you called out some of your increased exploration acreage 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 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.

Hey, guys. Good morning.

Hi.

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

That's a great question, Paul. We constantly evaluate how we can improve. This situation is certainly disappointing for me, as we have been incorporating lessons learned from past experiences into our ongoing projects. On the positive side, many aspects of our execution have been successful. The fabrication work in the yards has gone well, with modules being completed accurately and fitting perfectly on their foundations. Our logistics system has functioned flawlessly, delivering modules to the site as planned, and we've successfully completed the sealift for 2019. However, the schedule delay is disheartening and is primarily linked to the increased demands in engineering. We've expressed our dissatisfaction with the overall engineering performance on this project, especially regarding the associated costs and their effects on fabrication and construction. We recognize the need to improve in this area and will take the lessons learned to enhance our future approach. Currently, we do not have any other large land-based mega projects, allowing us time to carefully apply these insights. We remain committed to financial discipline and ensuring this project is executed to the best of our ability. In 2018, we identified the need to enhance productivity at Tengiz, and we achieved a 40% to 50% improvement across the site. In 2019, we've seen an additional 30% to 40% increase in productivity. We are making great strides with our production and construction management systems, and we will continue to focus on boosting productivity, finishing work, and advancing toward mechanical completion and startup.

Yeah. And if I could just build off of Jay's answer Paul. Just to put this in an enterprise perspective, the additional depreciation after tax to Chevron is less than $0.20 per share or less than the cash flow impact of a $1 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 upon the finger, but is it an internal issue, or just an external the contract that you guys use?

You're asking…

How are you going to be able to mitigate it in the future? You say you've learned from that, but what exactly have we learned? And what changes will be made?

From an engineering standpoint, Paul I think we have a couple of things. One, we are doing more to bring the early engineering back in-house and doing 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. It's 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.

We don't have similar projects in our queue. If you review our capital program, it primarily focuses on base business capital, shale, and tight capital. While we will embark on some major capital projects, the upcoming ones are deepwater projects, which are quite different. Most of the spending will be on drilling and completion, where we excel on the facility side, as it usually involves standard designs from fabrication yards. As mentioned, these aren’t land-based projects in remote areas, and our track record is stronger in those scenarios. We recognize the need for improvement and are learning from this experience. From an enterprise perspective, the investments currently in front of us are aimed at a different area than where this particular project has been.

My final question for Jay and Pierre is about the Tengiz project. Even before the cost increase, the full project return on capital, specifically the full cycle internal rate of return, is quite low. With the increase, it's much lower, but the cash flow will be substantial once production begins. When you assess whether to proceed with a project, which factor holds more weight for you? Is it the internal rate of return or the cash flow and its sustainability over time? I'm trying to grasp your decision-making process.

Yes. 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. And 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 at Tengiz 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 $0.20 per share. But 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 Tengiz, 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 debottleneck 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, all.

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 tight, 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.

Yes. Thanks for the question. So in addition to Deepwater Brazil, we have been very interested in some of the deepwater 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 Esox discovery with another operator, that will tie back to Tubular Bells. It's very close. It brings new production in at very low capital cost 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 pit floor 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 Tengiz's cost pressure. And Pierre, I think you mentioned it also as an area where we'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 these capital efficiency improvements. And then also, to the extent you are cutting back capital in more gassy areas in response to the Tengiz's pressure? Any additional detail on where that is, in North America, gas elsewhere in the portfolio. Additional color would be helpful there as well.

Sure. 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. 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 and the deepwater 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.

Thanks, Tim.

Hey, thanks for taking my question. Sorry, I have another one on Tengiz. Jay, you 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 CapEx increase today and the timing of that. But taking a step back, you look at the last few years and you've had your fair share of issues at some of these major projects. Pierre, you're signing off 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. Then I've got another follow-up. Thanks.

So on the productivity, the contracts at site at Tengiz and 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 time frame that we've got. And with the numbers of people we planned, 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 manhours. 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.

I believe I've addressed this already. We don't currently have any other projects like STP WPMP in our pipeline. Kitimat is in progress but not yet ready. Our focus is on substantial base business capital, shale and tight projects, and possibly some deepwater projects in the future. I understand your question is hypothetical, and I'm not going to speculate on it. However, looking at our portfolio, we currently don't have that option available. That said, we plan to remain in this business for a long time and will learn from our experiences. We need to improve, but we don’t have any immediate capital decisions regarding large-scale land-based construction projects.

Okay, understood. Just to follow up with hopefully a simpler question, regarding the tax on repatriated cash, are you anticipating this to be a one-time occurrence, or should we expect more instances like this in the future? Can you clarify whether that was a cash tax or just an accounting charge? Thank you.

Thank you for your question. We conducted a global cash management review in the third quarter and chose to repatriate previously unremitted cash. Before this review, we expected these earnings to be invested outside the U.S., which is why we did not account for the state and forward withholding taxes. When we decided to repatriate the cash, we then accrued the tax. This is a cash tax, and the payment will occur in the fourth quarter, while the accrual for the profit and loss was in the third quarter. This will bring non-U.S. cash into the U.S., reducing both our cash and debt balances. We made this decision because it is the right economic move, and it pertains to prior earnings. We do not anticipate other similar repatriations of prior earnings. However, there may be some current earnings repatriated as part of our normal business operations. This is a one-time event, involving over $8 billion in non-U.S. cash being brought to the U.S. You won't see our U.S. cash balances decrease by the full amount because some was already lent out domestically, but we do expect our year-end cash balances to be $3 billion to $4 billion lower than at the end of the third quarter. The third quarter's cash balance was somewhat elevated as we prepared for these repatriation moves.

Got it. Thank you, guys.

Thanks, everybody. 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 Tengiz'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 like of ring-fencing and so on, the net impact of this may not be as severe as, obviously, the headline cost overrun suggested. 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 Tengiz. And so it's really going to be through the DD&A and 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 start-up of the facility.

I was under the impression it was going to accelerate the 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 and...

And just to be clear, when I refer to the less than $0.20, I'm talking about booked DD&A, booked depreciation, not tax depreciation, which obviously is different.

Thank you. I initially thought there was an acceleration involved. My follow-up question relates to the Permian. Clearly, the plan you've outlined shows that you are continuing to exceed the production expectations. However, when you presented the plan, you mentioned your expectations for when the Permian would reach cash breakeven in terms of capital and cash flow, including royalty contributions. Given that NGL and gas prices have significantly declined, could you provide an update on your outlook? Additionally, regarding the takeaway solutions announced in recent months, how do these improvements impact your ability to enhance gas and NGL realizations from those lease lines? Will they enhance your realizations in line with Gulf Coast metrics? I'll leave it at that. Thank you.

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, 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, this is – is the 60%, 65% gas in NGLs? Or can you – I know you talk about liquids, but can you split the oil versus NGL portion then I'll leave it at that. Thank you.

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

Helpful. Thanks a lot.

Thanks, Doug.

Thanks, Doug.

Hi. Thanks. Good morning, guys. I just 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.

There are a few key points to discuss, Dan. Firstly, I want to direct you to slide 10, which illustrates our spending profile for the FGP project. We anticipate that our highest spending will occur in 2018 and 2019. Moving into 2020, our spending will decrease as we focus primarily on site construction activities. We have one additional year of fabrication left in one of the original four yards, and that work is currently about 73% finished. Regarding the allocation of the additional spend over the total project, I would estimate that we have approximately half of it already incurred and about $4 billion to $5 billion remaining. The majority of the increase and the unexpected costs are primarily due to higher construction costs. The earlier phases of engineering and fabrication were mainly influenced by the use of contingency funds. Overall, the actual increases we are experiencing are tied to construction and our project schedule.

So, building on Jay's comments, we are reaffirming our guidance for next year, which is between $18 billion to $20 billion. As Jay mentioned, TCO will be coming down. We are in the process of finalizing our plan and capital program right now. With the efficiencies highlighted by Jay and our ability to defer lower return projects, we are definitely capable of landing a capital program within that range.

Okay. And the production outlook more than offset that in other areas?

Yeah, I mean we haven't given production guidance 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 investments or we decide to flex down some of our shorter cycle 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, Jay.

Thanks, Dan.

Good morning. Thank you. I guess, maybe it's been mentioned a couple of 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 there's a little add-on to that, just an update of how Gorgon and Wheatstone are performing here in planned and unplanned maintenance?

Gorgon and Wheatstone are performing well. Gorgon Train 1 is currently undergoing a scheduled turnaround. As indicated in our third quarter production report, we have seen very strong output from both facilities. We are focused on improving their reliability and utilization, as well as increasing capacity. There is a turnaround planned for both facilities, which will happen annually, and we will provide updates as we approach those dates. We believe there is potential for spot prices to rise as production increases, allowing us to offer more cargoes on the spot market. This is favorable since our production has exceeded our initial expectations. However, as reliability improves, we aim to secure some of this expected spot production under longer-term or medium-term contracts, thereby reducing reliance on the spot market in any given quarter.

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 is within contractual limits and within the contractual terms. They have to do it almost a year ahead. It's tied to 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.

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

The macroeconomic outlook for spot LNG appears to show a significant oversupply. While a cold winter could alleviate some of that oversupply, storage levels in Europe and Asia seem to be in a good position. Currently, it does look oversupplied, with additional LNG on the way, but the markets often surprise us. The key takeaway for us is that we are not particularly exposed to the spot market, as we primarily focus on oil-linked, long-term contracts. Thank you, Roger.

Thank you.

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 rigless activity work workover 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 move 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. So 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've 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 a 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 and not a great year to net debt is like 1.5 times. Is there a level of net debt that you think is under-levered or suboptimal for the business, especially in the context of Tengiz? If the biggest impact is a return impairment, you can 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?

Yes. No, thanks, Sam. Look, yes, we are generating good cash in a challenging macro environment. I think you know our four financial priorities. I will go them quickly. The first is to sustain and grow the dividend and we increased it 6% later this year. The second is the 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 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.

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