Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's Second Quarter 2018 Earnings Conference Call. At this time, all participants are in a listen only mode. After the speakers' remarks, there will be a question and answer session and instructions will be given at that time.
As a reminder, this conference call is being recorded. I will now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.
All right. Thank you, Jonathan. Welcome to Chevron's 2nd quarter earnings conference call and webcast. On the call with me today are Jay Johnson, Executive Vice President of Upstream and Wayne Bourdoun, General Manager of Investor Relations. We will 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. We ask that you review the cautionary statement on Slide 2. Turning to Slide 3, an overview of our financial performance. The company's 2nd quarter earnings were $3,400,000,000 or $1.78 per diluted share. This was nearly $2,000,000,000 or roughly $1 per share higher than the same period a year ago.
The quarter included the impact of a non recurring receivable write down, which was offset by foreign exchange gains. A reconciliation of special items, foreign exchange and other non GAAP measures can be found in the appendix to this presentation. Cash flow from operations for the quarter was $6,900,000,000 Excluding working capital effects, cash flow from operations was 7,000,000,000 The working capital penalty in the current quarter was understated by the $270,000,000 receivable write down just mentioned as this was a non cash item. Year to date cash flow from operations has totaled $11,900,000,000 about $3,000,000,000 more than a year ago. At quarter end, debt balances stood at approximately $39,000,000,000 giving us a headline debt ratio of 20% and a net debt ratio of 17%.
During the Q2, we paid $2,100,000,000 in dividends and we currently yield 3.6%. Turning to Slide 4. In addition to the non cash receivable write down impact, our 2nd quarter cash from operations position also reflected a discretionary U. S. Pension contribution of $300,000,000 When these two elements are taken into account to allow for an apples to apples comparison, underlying cash generation improved between the 1st and second quarter by about $500,000,000 This improvement reflected higher Brent prices of about $7.50 per barrel and higher WTI prices of about $5 per barrel.
Our upstream realizations did not fully capture the quarterly increase in global oil prices, largely due to portfolio mix effects surrounding the Brent WTI differential. We also saw lower Asia LNG spot prices during the quarter. Year to date, affiliate dividends were $1,800,000,000 less than earnings. Cash capital expenditures for the quarter were $3,200,000,000 $6,200,000,000 year to date, in line with our 2018 budget. We had a 50% year on year improvement in operating cash flow from 2016 to 2017.
We expect a similar improvement to trajectory from 2017 to 2018. We anticipate second half cash generation will reflect higher production, strong upstream cash margins, additional proceeds from asset sales, and some reversals of working capital requirements. These positives are expected to be offset only modestly by another discretionary U. S. Pension contribution.
Turning to Slide 5, this favorable outlook on cash flow combined with our ongoing commitment to capital discipline enables us to initiate share repurchases targeted at $3,000,000,000 per year. Our financial priorities are unchanged. We are generating cash surplus to what we need to meet the first three of these. We increased our annual dividend by 4% earlier in the year. We continue to be very selective and disciplined in our investments, and we have an advantaged portfolio and a large captured resource base.
We plan to ratably develop these resources within the $18,000,000,000 to $20,000,000,000 capital range we previously indicated through 2020. Our balance sheet is strong and getting stronger. We will take advantage of higher price periods like we're seeing now to modestly reduce our debt level over time. We'll start repurchases in the Q3. Going forward, we will provide an update at the end of every quarter on our progress.
We believe annual share repurchases of $3,000,000,000 can be sustained over most reasonable price scenarios. Turning to Slide 6, just a quick update on our portfolio optimization efforts. We have previously indicated our intent to generate between $5,000,000,000 $10,000,000,000 in targeted asset sale proceeds over the 3 year period 2018 to 2020. We remain confident in this range. On a year to date basis, we have had sales proceeds of approximately $700,000,000 primarily from the sale of our upstream non operated joint venture interest in the Elk Hills field in California and the Democratic Republic of the Congo.
Later this year, we expect to close the Southern Africa Downstream transaction. When that happens, 2018 will be right on pace with our 3 year target. A few weeks ago, we announced our decision to market our U. K. Central North Sea assets.
As with any transaction, we will only execute if we believe it is aligned with our strategic objectives and we receive good value. Turning to Slide 7. 2nd quarter 2018 after tax earnings were approximately $2,000,000,000 higher than 2nd quarter 2017. Special item impacts were comparable in the two periods and hence do not show up as a variance bar in the aggregate for the enterprise. Favorable movements in foreign exchange positively impacted earnings between the periods by $262,000,000 Upstream earnings, excluding special items and foreign exchange, increased by approximately $2,300,000,000 between periods, mainly on improved realizations and higher lifting.
Downstream earnings, excluding foreign exchange, decreased by about $400,000,000 mostly due to an unfavorable swing and timing effects, higher operating expenses largely due to planned turnaround activity, lower Asia margins and the absence of our Canadian refining and marketing business. The variance in the other segment excluding special items, was primarily the result of higher interest expense since less interest is being capitalized currently compared to the prior year. Turning to Slide 8. This compares results for Q2 2018 with Q1 2018. 2nd quarter results were approximately $230,000,000 lower than the Q1.
For special items, the Q2 included the $270,000,000 non recurring receivable write down, while the Q1 included $120,000,000 asset impairment. Foreign exchange impacts were a positive variance of $136,000,000 between periods. Upstream results, excluding special items and foreign exchange, were essentially flat between the quarters. Higher realizations were offset by higher operating expense and DD and A. Downstream earnings, excluding foreign exchange, improved by about $80,000,000 reflecting higher volumes and stronger U.
S. West Coast refining and marketing margins. The variance in the other segment largely reflected higher corporate charges and lower capitalized interest. As I indicated last quarter, our guidance for the other segment is $2,400,000,000 in annual net charges and the quarterly results are not ratable. With year to date charges of nearly $1,200,000,000 we are trending in line with our earlier guidance.
I'll now pass it on to Jay.
Thank you, Pat. On Slide 9, Q2 2018 production was an increase of 46,000 barrels a day from the Q2 of 2017. Major capital projects increased production by 180,000 barrels a day as we continue to ramp up multiple projects, most significantly Wheatstone and Gorgon. Shale and type production increased 91,000 barrels a day, primarily due to growth in the Midland and Delaware basins in the Permian. Base declines, net of production from new wells such as those in the U.
S. Gulf of Mexico and Nigeria were 51,000 barrels a day. The impact of 2017 2018 asset sales reduced production by 77,000 barrels a day between the periods. Entitlement effects reduced production by 54,000 barrels a day as both rising prices and lower spend reduced cost recovery barrels. Planned and unplanned downtime, along with the impacts from external events, reduced production by 43,000 barrels a day during the quarter.
Overall, the first half twenty eighteen production is up 4% relative to the first half of twenty seventeen. Turning to slide 10. 2nd quarter production was 2,830,000 barrels per day, taking our year to date production to 2,840,000 barrels per day. Excluding the impact of 2018 asset sales, which is the middle bar, our year to date production growth is 4.5% higher than the daily average production for full year 2017. This is in line with our guidance.
As Pat mentioned last quarter, planned turnaround activity across multiple locations began in earnest in the 2nd quarter. The production impact from turnarounds in the second quarter was 67,000 barrels a day. We expect heavier planned turnaround activity in the Q3. The production impact from 2018 asset sales was 15,000 barrels a day in the 2nd quarter with a year to date impact of 8,000 barrels a day. With the successful startup of Wheatstone Train 2, continued growth in the Permian and ramp ups at Hebron, Stampede and Tahiti vertical expansion project, we expect production to further increase in the second half of this year.
Our outlook for the full year is expected to be in the top half of our guidance range even without normalizing for the impact of price at current levels. Turning to Slide 11. Chevron is now Australia's largest producer of LNG and the proud operator of 5 LNG trains with a total installed liquefaction capacity of 24,500,000 tons per year. Our facilities, along with available capacity and other facilities in Northwest Australia, will enable us to monetize our world class natural gas resource base for decades to come. Wheatstone Train 2 achieved 1st production in mid June.
The ramp up has exceeded expectations as Train 2 reached nameplate capacity within weeks of startup. We've already exported the equivalent of 6 cargoes of Train 2 production and we're planning to take a pit stop in the 3rd quarter to remove the start up strainers. Its companion plant Wheatstone Train 1 has also been running well. The train has demonstrated nameplate capacity and has now run 195 consecutive days without a day of downtime. We also successfully completed the planned pit stop on Gorgon Train 2.
The Gorgon pit stops have been successful, and we're seeing improvements in performance and reliability. As a case in point, Gorgon Train 1, since its pit stop, has run more than 2 85 days without a day of downtime. Combined net production from our operated LNG trains was 282,000 barrels of oil equivalent per day in the Q2. With Wheatstone Train 2 ramping up and Gorgon Train 2 back online, we're already seeing net production approaching 400,000 barrels per day. Let's turn to Slide 12.
I recently returned from a trip to Kazakhstan. Our base business at TCO is running well and the FGP WPMP project is progressing as guided towards first production in 2022. The project estimated to be 40% complete with preassembled pipe racks, process modules and a gas turbine generator all in transit from yards in Kazakhstan, Korea and Italy. 6 pipe rack modules have been successfully delivered to site, demonstrating the operability of the delivery system and the receiving facilities. Site work continues to focus on foundations, undergrounds and infrastructure in preparation for module installation.
Major mechanical, electrical and instrumentation contracts have been awarded. We also have 3 drilling rigs operating on multi well pads and drilling is ahead of schedule. You'll recall back in March that I said 2018 is a critical year for execution. This is the 1st year of module fabrication and site construction as well as initiation of the module transportation system. With engineering approaching 85% complete and fabrication of 40% complete, we are seeing cost pressure on the project.
Site productivity remains a key driver of success for the project and is a major focus for our team. Turning to the Permian on Slide 13. Permian shale and pipe production in the 2nd quarter was 270,000 barrels of oil equivalent per day, representing an increase of about 92,000 barrels a day, up 50% relative to the same quarter last year. Our development strategy continues to center around disciplined execution and capital efficiency. We're currently running 19 rigs and our development program is progressing as planned.
While activity levels are high in the Permian, Chevron has not experienced supply shortages in the Q2 and we're securing the dedicated crews and materials needed to execute the plan we've previously described. We continue to focus on well performance and the optimization of our well factory. This requires coordination and planning starting with our land position, running through the drilling and completion strategy, as well as the design and construction of facilities. And it ends with the midstream arrangements to ensure that we bring produced oil, gas and NGLs to market at competitive realizations. Let's turn to Slide 14.
We're currently operating 8 development areas and participating in approximately 30 joint venture developments operated by others. We continue to proactively manage and strengthen our land position. Year to date, we've transacted 31,000 acres through swaps, joint ventures, farm outs and sales. We've previously mentioned that some of the highest value transactions are swaps that allow us to core up acreage and enable long length laterals. As the land transaction example on the right depicts, coring up acreage provides an opportunity to double the lateral length of each well and optimize facilities, which in turn lowers our unit development cost.
In this case, the acreage swap increased the number of long length lateral wells we can drill by approximately 600 and improve the forecasted internal rate of return for each well by more than 30%. Since 2016, we've increased our average lateral length per well in the Permian by approximately 35%. We'll continue to look for opportunities to core up acreage and improve the capital efficiency of our Permian program. Let's turn to slide 15. Last quarter, Mark discussed the value of being an integrated company and our strategy for maximizing returns in the Permian.
Chevron has secured firm transport capacity at competitive rates to move the equivalent of nearly all of our forecasted 2018 2019 operated and NOJV taking kind oil production to multiple markets, including the U. S. Gulf Coast. As a result of these contractual arrangements and long term planning, this equivalent production is not materially exposed to the Midland basis differential. Our share of NOJV oil production not taken in kind is approximately 20% of our Permian crude volumes.
We previously mentioned that the pipeline takeaway capacity and production don't always move in perfect lockstep. There'll be periods of tightness and length. As an example, in June, we had more than 50,000 barrels a day excess takeaway capacity out of the Midland Basin, which we monetized through purchases of 3rd party volumes. We expect that excess capacity to attenuate through the rest of the year as our production continues to grow. Agreements are in place to access additional pipeline capacity in early 2019 in line with our production growth forecast.
In July, we utilized firm dock capacity in the Houston Ship Channel to gain access to world markets for Permian sourced crudes. We have firm contractual arrangements in place to further increase that dock capacity in 2019. Overall, we've exported more than 8,000,000 barrels of liquids from the Gulf Coast in 2018, further demonstrating our midstream's ability to batch, blend, trade and export to secure the highest value for our products. We're developing processing arrangements for NGLs and we have flow assurance for natural gas to ensure the production will not be impacted. We are moving forward with our development plans in the Permian and we do not intend to slow down activity or divert capital.
Pat, back to you.
Okay. Just a couple of closing comments about the first half and expectations for the remainder of the year. Cash from operations, excluding working capital, is materializing as expected, given the market conditions, production levels and asset reliability that we've achieved. The picture for total cash flow in the second half looks promising as well. We expect second half upstream cash margins to improve and our 2018 projected volume increases are back end loaded, giving us confidence that our full year production outlook is trending towards the upper half of the guidance range.
In addition, we should see some release of working capital and additional asset sales proceeds. Capital spending is on budget for the 1st 6 months. And so in total, we have a very attractive offering for investors, a growing dividend, assets that are strong cash generators, a healthy balance sheet, and finally, sufficient free cash flow to enable a share repurchase program. In short, we are delivering on all of our commitments. So that concludes our prepared remarks, and we're now ready to take your questions.
Please keep in mind that we have a lot of folks on the queue, and so try to limit yourself to one question and one follow-up, if necessary, and we'll certainly do our best to get all of your questions answered. Jonathan, go ahead and open the lines, please.
Thank
Our first question comes from the line of Neil Mehta from Goldman Sachs. Your question please.
Hey, thank you very much and congratulations on the buyback. It's great to see you making this step. I want to start there and see how you guys were framing the $3,000,000,000 number. How did you arrive that was at that being the right level? And to your point about this being an every year number, how should we think about this?
Should we think this as a base load, fixed cost, if you will, on a go forward basis in any foreseeable price environment? Or is there is this more of a flywheel dynamic?
Okay, Neil. Yes, thank you very much. I appreciate the question. You hit upon in your in the way you asked the question some of the key words for us, which really are we do want this to be a sustainable element here. So we obviously took a look at multiple price scenarios and we felt that this level of sustainability was we could handle this almost through any reasonable price environment there.
We pay attention to what expectations are in the market. And you can see, if you look at the futures market, there's a bit of a peak this year, next year and then maybe some downward trend. So obviously, that's a scenario that we took into account. And with that, we felt that the $3,000,000,000 level was sustainable.
Thank you. Our next question comes from the line of Phil Gresh from JPMorgan. Your question please.
Yes. Good morning. I echo Neil's sentiment. Congratulations on the buyback. I guess it's somewhat of a follow-up question.
I mean, you gave helpful color around cash from operations. It sounds like it's supposed to be up 50% year over year, I think is what you said. And so that'd be about $30,000,000,000 of CFO. If I look at that on a post dividend, post CapEx basis, you still you'd have about $9,000,000,000 of post dividend free cash flow. And so it sounded like you said in your prepared remarks, there's also maybe some desire to pay debt down a little bit.
But just wondering how you think about that. Obviously, onethree of this incremental is going back to the shareholder. But are you trying to save money for a rainy day? Or how do you think about that considering you also have asset sale proceeds coming in?
Right. I think it's a great question and you're triangulating on the numbers quite accurately there. All I would like to say, just from the start, we'd like to get the cash in the door and see it before we do we overcommit on it. So there might be a bit of, conservatism here in how we've started. But if you step back and think about the price environment that we're in and the price environment that may be expected that market is telling us over the next couple of years that may be coming, which would be a lower price environment.
We think it's prudent at this point in time to strengthen the balance sheet a bit when commodity prices are high. And so we do anticipate a little bit of debt pay down over the next period of time. We're certainly in a comfortable position from a leverage standpoint, but paying it down a little bit, shoring up the balance sheet a little bit, we think would be an improvement or we'd have willingness to go there to a small degree. Obviously, if you're building up cash a little bit and paying down debt a little bit, it gives you a bit of an insurance policy when times get tougher to meet the commitments that you've already laid out there. And by that, I mean the commitments that you put out there in terms of dividend and also now the commitment we have around share repurchases and the sustainability we hope to have around share repurchases.
I don't they don't have the same level of commitment. Share repurchases are the 4th in our priorities. Dividends comes first. But obviously, we'd like to have as much ratability and predictability around share repurchases as we can.
Yes, that makes sense. If I could ask a quick follow-up, just on the production guidance, You're comfortable with the high end of the range, despite, I think Jay said, despite the entitlement effects, which I think in the second quarter was like a 2% year over year impact. So maybe you could just provide some color around what do you think is going better than your expectations? Is it all Permian or are there other things as well?
So I think the primary thing that gives us some confidence is that we started up Wheatstone Train 2 very late in the Q2. It has come up very cleanly and is running well. We continue to see growth in the Permian and we have ramp ups going on, as I said, on a number of capital projects. We have some turnaround activity in the Q3, which will be a bit of a drag on production. But as we move through that and as we move into the Q4 overall with these new projects coming online and our relatively low base decline, we really feel pretty comfortable about where we are on our production profile through the rest of the year, barring unforeseen events.
Our next question comes from the line of Paul Cheng from Barclays.
Hey guys. Good morning.
Good morning.
Jay, did I hear you correctly? You're saying that 10 gs, you are seeing some cost pressure or size of cost pressure. Can you elaborate a little bit more in terms of how big is is that really going to be a big problem or what kind of magnitude we're talking about? And where is the source of the cost pressure?
Thanks, Paul. So we are seeing some cost pressure. We are now, as I said, approaching 85% complete on the engineering. We're about 40 percent complete on fabrication. We've had a we're having a full year of construction in the field.
Where we have seen some cost pressure at this point in time, our engineering program has cost more than we would have anticipated. We had some design quality issues, but also our productivity overall has been lower on engineering than expected. We've also seen some of our major contracts come in for field construction a little higher than what we expected. When we put all that together, we are using more of the contingency at this point in time than we would have expected or anticipated, and so that signals that we're seeing cost pressure on the project. We've talked about getting through this season.
We really need to see how the performance goes. There's a lot of important milestones. The good things that are happening, the fabrication is really working well. We're seeing high quality come out of the modules themselves as they're being completed and shipped to Tengiz. We've successfully tested the logistics system and we have delivered modules all the way to site.
So those things are all working quite well. But what we need to do is we're 40% complete on this project. It's large, it's complex, and we've used more of the contingency at this point than we would have expected. So that tells us we have cost pressure on this project. We'll continue to assess it and we'll update you accordingly as we need to.
And at what point that you will be more certain whether that you have to raise your overall budget? Is it 6 months from now, where's the maybe the critical path that you need to pass in order for you to know whether that you will be able to stay within the budget or is going to be higher?
We continue to assess our performance, Paul, as we move through the project. This is a 5, 6 year project overall duration. So we're still relatively early in the project. The site productivity is really going to be important. And as we go through this year and can really assess where we are and look at that site productivity, it is a full court press in the field to really make sure we are making the progress.
But in making that progress, using the number of man hours and the resources that we expected. So we're very focused on the timely delivery of engineering and engineered design and bulk materials. We want to make sure that we've got our crews ready, that the workforce planning is in place and that we have efficient support of our workforce so that we get the most out of that crew. So it's hard to put a definite time on it. We will continue to monitor our performance.
We build these into our business plan. At this point, I do not see it impacting our guidance of $18,000,000,000 to $20,000,000,000 And we will keep you updated as we gain more information.
Okay. Second question, Jay, when you guys do economic analysis, do you primarily use the real price or are you using the nominal price as the base case?
The real price of oil, do you mean?
Yes.
We have a corporate price forecast, which we use as our basis for our economic assumptions. But more importantly, we also test our business plan against both higher and lower priced scenarios to make sure that we have a robust plan that takes into account. The one thing we do know with certainty is that we cannot predict the oil price. So we want a plan that really is able to respond and adjust accordingly with options for whatever the price turns out to be.
I'm sorry that probably they don't make myself here. When I say real price means that the price adjust for inflation. Do you build in an inflation factor, whatever is the price tag that you use or you just use a long, middle, flat price in your assumption. So when you guys previously saying that 10 gs will be a $60 or low 60 brand price will be generating a 10% return or 15% return, is that the price is based on inflation
I mean, it's based on inflation adjusted. I mean, we look at what we expect prices to be because the cost estimates that we're putting together have those kind of components built in. But when we're taking the project to evaluation, when we're doing the final investment decision, we look at a whole host of price scenarios and we look at both nominal and real outcomes. What would you have to believe to have a 10% rate of return in a nominal sense? What would you have to have in a real sense?
So we look at the economics and judge the value of the projects based on multiple price scenarios. But when we're actually putting out an FID kind of number, it is our best estimate of what that cost at that point in time will be.
All right. Thank you.
Thank you. Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your question, please.
Thank you. Good morning everybody and thanks Joe for getting on the call. I've got two questions if I may. I guess the first one is an upstream question. When you laid out the Analyst Day back in March, obviously, you kept your guidance through 2020.
And if we take part what you said about the buyback being sustainable, it seems at least on our numbers that in the current oil price environment, you've got a lot more headroom in terms of surplus cash. So I'm curious, what are your intentions post 2020? Should we expect the current level of spending to be sustained? Or is that headroom to allow for, let's say, another step up in project visibility as we go beyond, for example, Tengiz, as we go beyond 2020? I've got a quick follow-up, please.
Yes. So, Doug, I think I'd just start and say we feel good about the $18,000,000,000 to $20,000,000,000 range out through 2020 because we can see our way forward that far with the quality of the resource base we have, the production profile that we've got laid out for the Permian and other unconventionals, our ability to take what is a relatively less mature asset base like LNG and debottleneck it and see continued value growth there. We have a whole series of investments When you get beyond 2020, we really will have to have a review of other incremental projects that we would like to bring online. At some point, we believe that there will be the opportunity to add deepwater investments, for example. Those are competing now or they're working to get their cost structure down so that they can compete better in the portfolio.
That time will come. We've said in the past that we want to be ratable in terms of how many we bring on bring those on at what time frame and what sort of pacing we do. So that's all stuff that we will put together as we're looking at our 2019 to 2021 plan, and it's all information that we will try to come out and provide a little bit more guidance for, when we get to our Security Analyst Meeting in March of 2019. But for now, I think the key message is $18,000,000,000 to $20,000,000,000 that's the capital program, that's the capital discipline that we're living within.
Thanks, Pat. Jay, maybe I can follow-up with you specifically then on another potential source of cash because you guys have obviously got tremendous flexibility with the Permian, but you're also very early in your $5,000,000,000 to $10,000,000,000 disposal plan. And since you laid that out, the oil price has obviously recovered quite a bit. So I guess what I'm asking Jay is, is there upside to your disposal target? How has the change in oil price changed your view of what's core within the portfolio?
And I'll leave it there. Thanks.
I would say that as we look at assets that are going to be part of our portfolio work, we tend to look at assets that are approaching end of life or either very early in life. So early in life would be resource opportunities that we have that just don't compete for capital in the portfolio. They may be economic, quite economic, but they don't compete for capital. We're trying to be very disciplined about what projects we invest in and only invest in the top part of our queue. The projects that are very late in life tend to have limited resource potential left for us and those are the ones we are putting out there.
The higher prices certainly help, but I wouldn't change our guidance at this point in time. This is going to be a pretty ratable program, and it's a pretty normal part of our operation to continue to look at properties as they move through their life cycle and decide when do they need to exit the portfolio. Our overall focus on all of this, we're not driving to a production target, we are driving to improve our returns and lead the industry in our returns on the upstream assets.
Appreciate you taking my questions guys. Thanks.
Thank you. Our next question comes from the line of Jason Campbell from Jefferies. Your question please.
Hi, everyone and thanks very much. Jay, very positive comments on the operations in Australia, essentially reaching nameplate capacity already, and obviously very long duration runs on several of the trains. I guess my question is, given this performance, how should we think about utilization rates in 2019 on the LNG facilities, recognizing that obviously some maintenance still needs to be done, but that there are probably some debottlenecking opportunities in the near term that you might be able to take advantage of?
Yes. We have not issued any formal guidance around this yet. We're going through the business plan now when we really develop that. But I would say that we took all the knowledge from the Gorgon Train 1 and applied that to 23. We've gone through the pit stops now.
So we're really pretty comfortable with where these trains are, and we just need to get some run time and do the analysis to see where the opportunities are for further expansion. One of the best ways to extend the capacity of these trains, of course, is just keeping them fully online and fully utilized. And so that's our primary focus at the moment. Wheatstone has a very similar story. Train 1 started up.
We had a pretty clean startup, but taking all those lessons learned, train 2 was started up very cleanly. And at this point in time, we do not have any anticipation of taking those down. So we may have, from time to time, as we've said before, some of these small pit stops if we see economically driven opportunities to enhance performance as we've done. But overall, I think a lot of the other than routine maintenance, a lot of the known shutdowns at this point in time are behind us. We will get into a regular rotation of shutdowns as all major trains do, and that's on a 3 or 4 year cycle as we get these and we want to have them staggered out.
But that's all being sorted out in our business plan. And for now, we would expect to see some pretty good sustained runs on these trains.
Okay, thanks. That's very helpful. And then just as a follow-up, Jay, could you comment on timing on first production at Big Foot and whether you are actively engaged in restarting production in the PC?
Yes. So at Big Foot, we still expect to see production started later this year. We have made good progress. We got the platform successfully installed and storm safe, as you know, early in the Q1 of this year. The drilling program is underway.
We're completing the first wells, and we're moving through and just about to bring buyback gas into the facility to start the final commissioning. So later in this year, we will expect to see production at Big Foot. We've already run, in fact, some of the second riser, just to make sure loop currents aren't a factor for us in that program. As we look at the PZ, that, of course, is an ongoing issue that the 2 governments are working to resolve. Our focus is on making sure that we're keeping the facilities in a ready to restart mode.
We're very focused on asset integrity and preservation types of activities. We've also done a lot of engineering and used this time of downtime to model not only a more comprehensive reservoir set of models, but also the surface facilities and really identified all the opportunities of low hanging fruit to optimize the flow once we get the facilities back online. So I think there's a lot of good opportunities for us when it restarts. We remain ready to go and of course we'll support the governments as they work towards resolution.
Thanks very much.
Thank you. Our next question comes from the line of Roger Read from Wells Fargo. Your question please.
Yes, good morning.
Hi, Roger.
If we could, Jay, maybe come back to the Midland Delaware Basin, the takeaway and then you've been over the last several quarters exceeding the guidance range that was laid out at the Analyst Day. So I was just curious as you think about the capacity to take away both on the oil and gas side, the fact you're running ahead of the guidance range, Does that create any risks? And then the second part of my question is, as you move non operated or non produced barrels at 50,000 barrels a day and replace them with your own, how does that flow through in terms of performance? I would assume better cash capture, cash margin capture on your own barrels than 3rd party, but I was just curious how that works out.
Yes. I'll take the first question or first part of the question. The higher production that we're seeing from our operations is taken into account. Our Midstream group and our business unit, they're in daily conversation about where we are, what our updated forecasts look like so that we don't catch anyone by surprise. The Midstream group has done an outstanding job of working with various suppliers and of services in the area for our takeaway capacity.
We have adopted the strategy. Our focus is on maximizing returns from the Permian, and that's what drives all of our efforts. So where we have had opportunities to not invest our capital, but rather contract for service like pipelines and takeaway capacity or gas plants and things where we can tariff through someone else's capital at a better rate, we've chosen to do so. But that means we have to be very coordinated with all these various suppliers to ensure the capacity is in place and accommodating our growth plans. So at this point in time, we look very good through 2018 2019.
We just will continue to monitor this. There's periods of tightness, periods of excess capacity, and we look to take opportunity to acquire other crudes and move them through those lines when the opportunities present themselves in the form of a differential exceeding the tariff. I do think in terms of the when we think about the NOJV, you almost have to think of the upstream produces into the Midland Basin, into the Midland area. And then our Midstream takes crude from the Midland area and moves it to markets, and that's our crude and others' crude. So it's really a big machine, but it's hard to say one specific barrel moves through the system.
It's more of a commercial arrangement and equivalent volumes. Our goal is to make sure that we are getting the maximum returns for the barrels that we produce, whether they're non operated or operated barrels, as we move those to the various markets. The other thing that our midstream has done that's been really helpful is not just get pipeline capacity out of the basin into the various markets, but then they have also made arrangements so that we can move this, as we said, across the dock into ships and access world markets as well. And so it really lets us take a forward look at those markets and adjust our offtake as we need to maximize our realizations.
And I would add, it's one
of the benefits of being an integrated company and it's also one of the benefits of being a company that focuses on a longer term plan. We've been under this plan of a 20 rig rate in the Permian for quite some time, and all of these precursors have been lined out.
Thank you.
Thank you. Our next question comes from the line of Tapan Josephinejad from Exane BNP Paribas. Your question please.
Yes. It's Thipan here. A couple of questions actually. Firstly, I think you gave guidance at the Analyst Day on the headwinds in the cash flow of somewhere between $2,500,000,000 to $3,500,000,000 So I just want to know whether that guidance is still valid and how much of that those headwinds have been consumed in the first half? And then the second question, I think we've been given an update in terms of the Uncom business, particularly for the Permian, but I was just wondering how the rest of the unconventional business, the Duvernay Argentina is looking as one reviews in the last 6 months?
Okay. I'll take them in order, I think. So yes, good question about the headwinds. So year to date, so through the 1st 6 months, we're sitting at combined headwinds of about $3,600,000,000 The guidance that I had given back in March was between 2.5% and 3.5%. Actually, I think that is still good guidance.
It may in fact come in a little bit lower, I mean, a little bit towards the low end of the range. What we're seeing here with higher prices is that the deferred tax headwinds that we thought would materialize at lower prices is really almost turning into essentially turning into a tailwind here at higher prices. And that's exactly what you would expect. So bottom line somewhere between 2.5 to 3.5 but probably closer to the bottom end of that range.
And as far as our other unconventional activities, we continue see very good progress in all three of the assets. I'll just walk through them 1 at a time. The 3 rig, we've increased from 2 to 3 rigs down in Argentina, worked very well with our operator, YPF. We are seeing continued improvement in our performance down there. The economic returns are looking very strong.
I think what's really important in Argentina is as they continue to deal with some of their situation, maintaining an open market will be an important watch point for us as we continue to move forward with our operations in the Vaca Muerta. We also have a field called El Trapial, which was a conventional field up in the northern part of that area. And we are planning to do an 8 well pilot for the unconventional potential under El Trapial and there is a lot of expectation that that may also prove to be a good area for us from an unconventional sense. We've restarted our drilling campaign in the Marcellus. We took a couple of year holiday just to reduce our capital during the last couple of years, but we're now moving back into operation there.
And the initial results coming out of the Marcellus as we've picked up right where we left off and continued our march to lower our unit development and operating costs. So pretty pleased with what we're seeing in the Marcellus and Utica areas. And then finally up at Kaybob Duvernay in Canada, we're also seeing good performance from our crews up there. We have moved from largely a land tenure and assessment or appraisal drilling mode into our first factory mode and have our first development area. That's about 55,000 acres that we started on in November of 2017.
So as we shift from moving rigs around and appraisal drilling to actually development drilling, we expect to see that continued improvement in performance there. One of the things that has been really successful for us over the last 2 or 3 years has been bringing these various teams together. They meet on a regular basis, best practices are shared between the different areas. So while they all have different characteristics, there is far more in common than there is different. And the techniques, the best practices, the use of data analytics, just a lot of the experience that we gain on a daily basis instead of just being in one area now, we're deploying that across all four.
And it doesn't just flow from the Permian outward. Things like zipper fracking actually came from the Marcellus into the Permian. And so we see that leveraging of knowledge and experience is quite powerful and very valuable for us.
Thank you. Our next question comes from the line of Pavel Molchanov from Raymond James. Your question please.
As you're working to expand Gorgon, I know that the Australian government is prioritizing more domestic gas supply, particularly for the eastern states in the country. And how do you kind of balance out your higher export demand with the fact that there is a brewing shortage domestically in the market?
Well, we'd love to sell them LNG to start with. But what's really important to Australia as with any country is energy security. You always want to make sure your country has a sufficient supply of clean, affordable, reliable energy source. And so in the West Australia, there is no pipeline, there is no way to transport gas from the West to the East, other than through LNG. We continue to produce LNG.
We have extensive gas resources in the west, 50,000,000,000,000 cubic feet of gas, that's Chevron Equity gas. Our focus is on making sure we have domestic gas plants at both Gorgon and Wheatstone. We have plenty of capacity to supply the West Australia market. But we also are really focused on making sure that we move and monetize that gas resource to the various markets that are demanding it. So at this point, I don't see the East Coast problems having any impact on either the expansion or the delivery from West Australia.
Okay. And a quick follow-up on your monetization plans. You mentioned some of the upstream assets. Given very hot demand these days for Permian midstream capacity, Is that something that you would consider including in your divestment planning?
We don't really have midstream assets per se in the Permian area. We have been focusing on the upstream. That's where we see the highest value, the highest returns. And our takeaway capacity in the midstream processing, like gas plants, NGLs, is provided by 3rd parties.
Okay. Understood.
Okay. Thank you very much. I think that I think that concludes the queue here. So I guess we're ready to the end to end the call. I'd like to thank everybody for your time today.
We certainly appreciate your interest in Chevron and we appreciate the questions that came in. Thank you very much. Jonathan, back to you.
Ladies and gentlemen, this concludes Chevron's 2nd quarter 2018 earnings conference call. You may now disconnect.