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Chevron Corporation (CVX 2.59%)
Q3 2019 Earnings Call
Nov 1, 2019, 11:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's Third Quarter 2019 Earnings Conference Call. [Operator Instructions]
I will now turn the conference call over to the General Manager of Investor Relations of Chevron Corporation, Mr. Wayne Borduin. Please go ahead.
Wayne Borduin -- General Manager, Investor Relations
Thank you, Jonathan. Welcome to Chevron's third quarter earnings call and webcast. On the call with me today are James 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 two. Turning to Slide three and Pierre.
Pierre R. Breber -- Vice President and Chief Financial Officer
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 four, third quarter cash flow was strong, down from the prior quarter, due to lower Brent prices in 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 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, 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 UK North Sea assets, we will be near the low end of our $5 billion 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.
James W. Johnson -- Executive Vice President, Upstream
Thanks, Pierre. On Slide seven, 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 eight. 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 47% 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 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 start up of FGP has shifted to mid-2023 and will now follow WPMP, which remains on schedule for start-up 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 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 owners 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 logistic system is working well and the 2019 sealift 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 start-up 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 estimate.
Importantly, we're not changing Chevron's capital guidance. Our 2020 capital to be announced in December, we'll be in the range of $18 billion to $20 billion, and we are reaffirming our capital guidance of $19 billion 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 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 will turn it back to Pierre.
Pierre R. Breber -- Vice President and Chief Financial Officer
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 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 produce Gorgon's greenhouse gas emissions by about 40% over the life of the project. Lastly, construction is under way 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 refinerywide 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.
Wayne Borduin -- General Manager, Investor Relations
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.
Questions and Answers:
Operator
Thank you. [Operator Instructions] Our first question comes from the line of Jason Gammel from Jefferies. Your question please.
Jason Gammel -- Jefferies -- Analyst
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 US downstream earnings were pretty robust this quarter relative to what I would have expected just given a heavy turnaround schedule. It is just the margin environment that was helping out? Or is there anything else that's happening in Downstream, that is maybe more ratable.
Pierre R. Breber -- Vice President and Chief Financial Officer
All right. Thanks, Jason, this is Pierre. So on co-lending, we 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 is over -- 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 will help offset that higher co-lending.
If we go to downstream in the quarter, we don't -- there is nothing that's -- that isn't inherent in the underlying margins. So that I can really point out to. We've had distillate margins have popped up a little bit and we tend to have some more production in that space, you'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 the third quarter performance largely to how we operated in the underlying margin environment.
Jason Gammel -- Jefferies -- Analyst
Very clear. Thanks, Pierre.
Pierre R. Breber -- Vice President and Chief Financial Officer
Thanks, Jason.
Operator
Thank you. Our next question comes from the line of Phil Gresh from JPMorgan. Your question please.
Phil Gresh -- JPMorgan -- Analyst
Yes. Hi, good morning. First question, just coming back to the idea that the Tengiz capex increase will not affect the overall capital spending plan. Is this -- are we just talking here about the fact that perhaps you're at low end of capex ranges. And now you moved to high-end of the capex ranges or how do you calibrate being able to offset $4 billion to $5 billion of incremental spending make the Chevron within the budget? Is it activity elsewhere or is it just within ranges here we're talking about. Thanks.
James W. Johnson -- Executive Vice President, Upstream
Phil, there is a couple of different places that we look to; first, TCO itself in its base capital spend has offset and we'll 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 there's a lot of short cycle activity and we're able to pace and adjust that program to fit within the investment levels that we set. And particularly as it relates to gas-related investments or 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 then 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 our -- 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 was in 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 -- if these types of spending that we constantly are working through as we allocate our capital each year, we're going to remain capital discipline, we're going to stay within the ranges that we've given you and we're going to -- look to do while we stay focused on delivering the value and returns that are really what's driving our decisions.
Pierre R. Breber -- Vice President and Chief Financial Officer
And if I can just fill it 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, but -- 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 increased elsewhere.
Phil Gresh -- JPMorgan -- Analyst
Okay, all right. Thank you for the color. And then I guess just a follow-up would be for Jay, I'm just trying to kind of rewind here your back to a year or so ago, there were some fears that things are getting a bit behind in Tengiz and then back at the Analyst Day, the tone sounded much better that things are 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.
James W. Johnson -- Executive Vice President, Upstream
Yes, I think what's changed fundamentally as 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 and how we're going to do the backfill in quantities associated with it. Those drove a much higher construction costs than we had anticipated and then if you look at the third bar, you see that represented.
The other big surprise was having to delay the start-up of FGP by the year. This is really driven fundamentally by an assumption change we had planned to integrate modules, that 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 is fully integrated. While we're seeing very complete modules coming from the fabrication yard, just as we've gotten a year of ME&I experienced this year. Our view has changed that we're using 14 months as our planning basis and that's push that schedule time out. So the growth in quantities and these longer schedule have really been the surprises that we didn't anticipate previously. So that's really where we are at this point in time.
Phil Gresh -- JPMorgan -- Analyst
Okay, thanks a lot.
James W. Johnson -- Executive Vice President, Upstream
Thanks, Phil.
Operator
Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question please.
Neil Mehta -- Goldman Sachs -- Analyst
Yes. Thank you. So the first question on -- 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 US election? And any impacts the way you think about prosecuting your bridge?
James W. Johnson -- Executive Vice President, Upstream
Well, I'll start with just the performance in the Permian. Our view as you know, has been to be very disciplined and focused on returns and efficiency. 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 checker boards 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 US, but around the world. It's done safely, it's done effectively, we learned more about it all the time, and it's really unlocked an economic -- 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 US.
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, well we would not like to see any kind of restrictions on hydraulic fracturing it's -- that's the context for our company.
Neil Mehta -- Goldman Sachs -- Analyst
No, that's great. Appreciate it. And that the follow-up here is, is related to Brazil there is the upcoming transfer of rights auction then you've 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 seems it's not being there over the next couple of years?
James W. Johnson -- Executive Vice President, Upstream
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 will 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.
Neil Mehta -- Goldman Sachs -- Analyst
Thanks guys.
James W. Johnson -- Executive Vice President, Upstream
Thanks, Neil.
Operator
Thank you. Our next question comes from the line of Paul Chang from Scotiabank. Your question please.
Paul Chang -- Scotiabank -- Analyst
Hey guys, good morning.
James W. Johnson -- Executive Vice President, Upstream
Good morning.
Paul Chang -- Scotiabank -- Analyst
Jay, the one, two, you 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 that something was not working in order for us that to have them at this stage to have the delay for a year, and also that for 25% increase. So what have we learned?
James W. Johnson -- Executive Vice President, Upstream
Well, Paul. It's a good question. We ask ourselves all this time -- all the time, how can we be 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 wells -- there have been a lot of dimensions to this particularly the execution work is going very well. Happy with the way the fabrication work has gone and 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, the 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 sealift 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 cost 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 built 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 system -- production 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 start-up.
Pierre R. Breber -- Vice President and Chief Financial Officer
Yes. And if I can -- 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.
Paul Chang -- Scotiabank -- Analyst
Sure, understand, but I think Jay when you're saying that you're unhappy about the engineering on this. So you said not to point the finger, but is it an internal issue or its an external, the contract that you guys have issue?
James W. Johnson -- Executive Vice President, Upstream
You're asking me [Speech Overlap]
Paul Chang -- Scotiabank -- Analyst
I think, really going to be able to mitigate it in the future, I mean that what -- I mean, you said you learned from that, but exactly what have we learned and what is the change will be?
James W. Johnson -- Executive Vice President, Upstream
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 teams 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 build 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 is work to be done as we really understand how to better define and prosecute the engineering programs that are necessary for these projects.
Pierre R. Breber -- Vice President and Chief Financial Officer
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 our deepwater projects and they're very different than these. A lot of the spending is in drilling and completion we're very good. On the facility side, it tends to be standard designs, in fabrication yards, as Jay said is not land-based projects in remote locations and we have a better track record in those [Technical Issues]. Again, we need to do better we're learning from it from an enterprise perspective at the portfolio, the investments that are at least in front of us are hitting a different place and where this project has been.
Paul Chang -- Scotiabank -- Analyst
My final question is that, Jay and Pierre, I think in Tengiz even before the cost increase the full project return on capital there is full cycle internal will return is actually pretty low. And with this, of course, it's much lower, but the cash flow will be great once that they come on stream. So, which is a more important factor when you guys determine whether you want to go with a certain point, actually is it the internal will return or is the cash flow and the sustainability of that cash flow, say for how long? So I'm trying to understand that the decision making process?
Pierre R. Breber -- Vice President and Chief Financial Officer
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. Once you have a cost increase, I think, it's stating the obvious that dilutes the returns and we're taking a lot of our actions to offset that both and Tengiz and across of 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 our returns on capital, but we also know cash is important and helps pay the dividend and support the share buybacks.
James W. Johnson -- Executive Vice President, Upstream
I would just say this particular project, Paul. I know, your views on had 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.
Pierre R. Breber -- Vice President and Chief Financial Officer
Thanks, Paul.
Operator
Thank you. Our next question comes from the line of Devon McDermott from Morgan Stanley. Your question please.
Devon McDermott -- Morgan Stanley -- Analyst
Good morning, thanks for taking the question.
James W. Johnson -- Executive Vice President, Upstream
Good morning, Devon.
Devon McDermott -- Morgan Stanley -- Analyst
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 US, 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 in the overall strategy here and the desire, if any to diversified 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?
James W. Johnson -- Executive Vice President, Upstream
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 US sector of the Gulf of Mexico. So we've recently farmed in 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 we 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 US Gulf of Mexico, we've been very active and one of the key strategies in the US 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've recently heard about the Essex discovery with another operator that will tie back to Tubular Bells, it's very close 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 US 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, sea 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 allage. 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.
Devon McDermott -- Morgan Stanley -- Analyst
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 cost pressure. And Pierre, I think you mentioned, it also is 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 that is capital efficiency improvements. And then also to the extent you are cutting back capital in more gassy areas in response to Tengiz pressure any additional detail on where that is. Is it North America gas elsewhere in the portfolio additional color would be helpful there as well?
James W. Johnson -- Executive Vice President, Upstream
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 cost come down to where we are 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 will be making changes that's not something that will 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.
Devon McDermott -- Morgan Stanley -- Analyst
Understood. Thank you.
James W. Johnson -- Executive Vice President, Upstream
Thanks, Devon.
Operator
Thank you. Our next question comes from the line of Biraj Borkhataria from RBC. Your question please.
Biraj Borkhataria -- RBC Capital Markets -- Analyst
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 the circle -- square that comment with the capex increase today and the timing of that. Taking a step back, you look at the last few years, and you've had your fair share of issues with some of these major projects. Pierre you're signing up on these, I just wonder, if these experience will make you think twice about embarking on these types of projects of this scale in the future. That would be my first question, and I've got another follow-up. Thanks.
James W. Johnson -- Executive Vice President, Upstream
So on the productivity, the contracts at site at Tengiz 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 indirect 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 time 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.
Pierre R. Breber -- Vice President and Chief Financial Officer
Yes, and Biraj in terms of, I think, I addressed this, I mean we don't have other projects like FGP/WPMP in our queue, Kitimat is being work, but it's not ready. What we have is a lot of base business capital, a lot of shale and tight and hopefully, some deepwater projects here over time. So 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 for 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 base construction project.
Biraj Borkhataria -- RBC Capital Markets -- Analyst
Okay, understood. Just a follow-up, hopefully an easier question. But the tax on repatriated cash, are you expecting that to be a one-off or is it -- should we expect more of these in the future. And then can you confirm whether that was cash tax or just a P&L charge? Thank you.
Pierre R. Breber -- Vice President and Chief Financial Officer
Yes. So, thanks for that question. So, you know, 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 outside the US, 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 accrue the tax. So the -- it is a cash tax, but the cash -- 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-US cash into the US, it will allow us to lower our cash balances, will lower our debt balances. We're doing it because it's the right economic decision.
And this is for prior earnings, we do not expect other types of repatriations of prior earnings like this. At the same time there will be -- it could be some current earnings that of course are repatriated and that's in the normal course of business. So I know this is a one -- a one-off, it's over $8 billion of non-US cash being brought to the US, you won't see our US cash balances go down by that full amount, because some of it had been lent into the US, but we expect our year-end cash balances to be $3 billion 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.
Biraj Borkhataria -- RBC Capital Markets -- Analyst
Got it. And thanks again.
James W. Johnson -- Executive Vice President, Upstream
Thanks, Biraj.
Operator
Thank you. Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your question please.
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
Thanks. Thanks everybody. Good morning. Jay, I know you don't or maybe Pierre, I don't -- I know you guys don't normally want to talk about fiscal terms, but in light of the Tengiz cost increases, I just wonder 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 on lack of ring-fencing and so on. The net impact of this may not be as severe as they obviously the headline cost overruns suggest. I just wonder, if you could walk us through what the cost recovery ramifications are please. And I've got a follow-up.
James W. Johnson -- Executive Vice President, Upstream
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.
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
I was under the impression and there was an accelerated DD&A's are not the case?
James W. Johnson -- Executive Vice President, Upstream
As I said, we're not going to discuss the terms of the contract, but it's a tax and royalty contract and...
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
Okay.
Pierre R. Breber -- Vice President and Chief Financial Officer
And just to be clear, when I refer to the less than $0.20, I'm talking about book DD&A, book depreciation not tax depreciation, which obviously is...
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
Okay. I'm sorry, I thought it 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 -- you continue 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 breakeven 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 have announced over the last several months. What does that do to your ability to improve gas and NGL realizations? Are those lease line or are they going to uplift you realizations with more to work in the Gulf course type metric to and I'll leave it there. Thanks.
James W. Johnson -- Executive Vice President, Upstream
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 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.
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
Okay, just to be clear, this is -- is that 60%, 65% gas and NGLs, or can you -- I know you talk about liquids, but can you split the oil versus NGLs portion and I'll leave it at that. Thank you.
James W. Johnson -- Executive Vice President, Upstream
We see roughly half of our total mix is in crude, about a quarter of its in gas liquids and about a quarter of it's in natural gas.
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
Helpful. Thanks fellows.
James W. Johnson -- Executive Vice President, Upstream
Thanks, Dough.
Pierre R. Breber -- Vice President and Chief Financial Officer
Thanks, Dough.
Operator
Thank you. Our next question comes from the line of Dan Boyd from BMO Capital Markets. Your question please.
Dan Boyd -- BMO Capital Markets -- Analyst
Hi, thanks, good morning guys. Hey, I just wanted 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 affiliates 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 is a potential production impact of that or if the Permian is running ahead of schedule enough to offset only that?
James W. Johnson -- Executive Vice President, Upstream
So a couple of things, Dan. First of all, I would take you to Slide 10 and that kind of shows our production or our spending profile for the FGP project and we see '18 and '19 is 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 is half of it, about $4 billion 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 in the surprise. The part that we did in the first engineering -- the engineering and fabrication was more directed around the consumption of contingency, the increases we've really seen has been in construction and schedule.
Pierre R. Breber -- Vice President and Chief Financial Officer
So Dan again, just to build off Jay's comments. I mean we're coming off of reaffirmed the guidance for next year between $18 billion to $20 billion. TCO will be coming off, as Jay said, and so we have -- 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.
Dan Boyd -- BMO Capital Markets -- Analyst
Okay. And the production outlook more than offset that in other areas?
Pierre R. Breber -- Vice President and Chief Financial Officer
Yes, 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 reduction, clearly if we defer some lower return natural gas investments or we decided 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.
Dan Boyd -- BMO Capital Markets -- Analyst
Okay. Thanks, guys.
James W. Johnson -- Executive Vice President, Upstream
Thanks, Dan.
Operator
Thank you. Our next question comes from the line of Roger Read from Wells Fargo. Your question please.
Roger Read -- Wells Fargo -- Analyst
Yes, 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 is a little add on to that, just kind of an update of how Gorgon and Wheatstone are performing here and planned and unplanned maintenance?
James W. Johnson -- Executive Vice President, Upstream
Okay. Gorgon and Wheatstone are actually performing quite well. Gorgon train one is currently under a scheduled turnaround or planned turnaround, but as you saw our third quarter production and there is 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 will 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 our downstream facilities and places like Tengiz. We do see 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 had 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.
Pierre R. Breber -- Vice President and Chief Financial Officer
Yes, the only thing to add, as 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 is tied to the annual delivery schedule. But we have seen some of that and that as a result in a little bit more in the spot market than we otherwise would have.
Roger Read -- Wells Fargo -- Analyst
Any particular weakness in the spot markets that you're seeing at this point or are we pretty well passed that for the summer time?
Pierre R. Breber -- Vice President and Chief Financial Officer
In terms of calling, look -- it looks, the macro on spot LNG looks, 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, Asia seems to be well positioned. So if I look at it right now, again it looks oversupply 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.
James W. Johnson -- Executive Vice President, Upstream
Thanks, Roger.
Roger Read -- Wells Fargo -- Analyst
Thank you.
Operator
Thank you. Our next question comes the line Sam Margolin from Wolfe Research. Your question please.
Sam Margolin -- Wolfe Research -- Analyst
Hello?
Pierre R. Breber -- Vice President and Chief Financial Officer
Hi, Sam.
Sam Margolin -- Wolfe Research -- Analyst
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 performed 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 you're EURs that you projected look like they are intact or growing or changing in any way. And if there is sort of rig less 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?
James W. Johnson -- Executive Vice President, Upstream
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. 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 is 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.
Sam Margolin -- Wolfe Research -- Analyst
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 sub-optimal for the business, especially in the context of Tengiz, if the biggest impact is a return impairment you could enhance that to the equity with some leverage have deployed somehow. So just your thoughts on how net debts trending and what optimal leverage is?
Pierre R. Breber -- Vice President and Chief Financial Officer
Yes, you know, thanks, Sam and look. Yes, we are generating a 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 at 6% earlier this year. The second is to reinvest capital and 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 and the industry have the strongest balance sheet in the industry, and I've talked about our 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.
Sam Margolin -- Wolfe Research -- Analyst
Thanks so much.
Pierre R. Breber -- Vice President and Chief Financial Officer
Thanks, Sam.
Operator
Thank you. And our final question for today comes from the line of Jason Gabelman of Cowen. Your question please.
Jason Gabelman -- Cowen and Company -- Analyst
Yeah, thanks for taking my question. I just wanted 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 wanting to kind of expand or potentially acquire some company that operates in multiple arena is not just one that operates in US 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.
Pierre R. Breber -- Vice President and Chief Financial Officer
Yes. 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 heard us talk about it. Look, we have a very strong value proposition. We have a 4% dividend yield and 2% share buyback or the buyback equivalent to 2% of the shares and free cash flow yield of 7%, and advantaged portfolio that Jay has been talking about with strong a resources and reserves that allow us to grow cash flow and grow production over time. So we don't need to do a deal. 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.
Jason Gabelman -- Cowen and Company -- Analyst
Thanks.
James W. Johnson -- Executive Vice President, Upstream
Okay, Jonathan.
Operator
Yes, and I would like to hand it back to you for any further remarks.
James W. Johnson -- Executive Vice President, Upstream
Well, that concludes our prepared remarks. We're now ready -- excuse me. No that's the end of the call. Thank you very much.
Operator
[Operator Closing Remarks]
Duration: 63 minutes
Call participants:
Wayne Borduin -- General Manager, Investor Relations
Pierre R. Breber -- Vice President and Chief Financial Officer
James W. Johnson -- Executive Vice President, Upstream
Jason Gammel -- Jefferies -- Analyst
Phil Gresh -- JPMorgan -- Analyst
Neil Mehta -- Goldman Sachs -- Analyst
Paul Chang -- Scotiabank -- Analyst
Devon McDermott -- Morgan Stanley -- Analyst
Biraj Borkhataria -- RBC Capital Markets -- Analyst
Doug Leggate -- Bank of America Merrill Lynch -- Analyst
Dan Boyd -- BMO Capital Markets -- Analyst
Roger Read -- Wells Fargo -- Analyst
Sam Margolin -- Wolfe Research -- Analyst
Jason Gabelman -- Cowen and Company -- Analyst
