Chevron Corp

NYSE:CVX

Earnings Call Transcript 2018-Q2

[Operator]

Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron 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 [Operator Instructions]. 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.

[Pat Yarrington, Vice President and Chief Financial Officer]

Thank you, Jonathan. Welcome to Chevron's second quarter earnings conference call and webcast. On the call with me today are, Jay Johnson, Executive Vice President, Upstream and Wayne Borduin, General Manager of Investor Relations. We will refer to the slides that are available on Chevron's Web site. 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 second quarter earnings were $3.4 billion or $1.78 per diluted share. This is nearly $2 billion or roughly a $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 $6.9 billion. Excluding working capital effect, cash flow from operations was $7 billion. The working capital penalty in the current quarter was understated by the $270 million receivable write-down as just mentioned as this was a non-cash item. Year-to-date, cash flow from operations has totaled $11.9 billion, about $3 billion more than a year ago. At quarter end, debt balances stood at approximately $39 billion, giving us a headline debt ratio of 20% and a net debt ratio of 17%. During the second quarter, we paid $2.1 billion in dividends and we currently yield 3.6%.

Turning to Slide 4. In addition to the non-cash receivable write-down impact, our second quarter cash from operations position also requested a discretionary U.S. pension contribution of $300 million. When these two elements are taken into account to allow for an apples-to-apples comparison underlying cash generation improved between the first and second quarter by about $500 million. 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 $1.8 billion less than earnings. Cash capital expenditures for the quarter were $3.2 billion and $6.2 billion year-to-date, in line with our 2018 budget. We had 50% year-on-year improvement in operating cash flow from 2016 to 2017. We expect a similar improvement 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 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 billion 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 billion to $20 billion capital range we previously indicated through 2020. Our balance sheet is strong and getting stronger. We will take advantage of higher price period like we’re seeing now to modestly reduce our debt level overtime. We’ll start repurchases in the third quarter. Going forward, we will provide an update at the end of every quarter on our progress. We believe annual share repurchases of $3 billion 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 billion and $10 billion in targeted asset sale proceeds over the three 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 million, 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 African downstream transaction. When that happens, 2018 will be right on pace with our three year target. A few weeks ago, we announced our decision to market our UK Central North Sea assets. As with any transaction, we will only execute if we believe it is aligned with our strategic objective and we receive good value.

Turning to Slide 7. Second quarter 2018 after tax earnings were $2 billion higher than second 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 million. Upstream earnings, excluding special items and foreign exchange, increased by approximately $2.3 billion between periods, mainly on improved realizations and higher lifting.

Downstream earnings, excluding foreign exchange, decreased by about $400 million mostly due to an unfavorable swing and timing effect, 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 second quarter 2018 with first quarter 2018. Second quarter results were approximately $230 million lower than the first quarter. For special items, the second quarter included the $270 million non-recurring receivables write-down, while the first quarter included $120 million asset impairment. Foreign exchange impacts were a positive variance of $136 million 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&A. Downstream earnings, excluding foreign exchange, improved by about $80 million, reflecting higher volume 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 $2.4 billion in annual net charges and the quarterly results are not ratable with year-to-date charges of nearly $1.2 billion, we are trending in line with our earlier guidance.

I'll now pass it on to Jay.

[Jay Johnson, Executive Vice President, Upstream]

Thanks, Pat. On Slide 9, second quarter 2018 production was an increase of 46,000 barrels per day from the second quarter 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 tight 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 in the U.S. Gulf of Mexico and Nigeria, were 51,000 barrels a day.

The impact for 2017 and 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 of 2018 production is up 4% relative to the first half of 2017.

Turning to Slide 10. Second quarter production was 2.83 million barrels per day, taking our year-to-date production to 2.84 million barrels per day. Excluding the impact of 2018 asset sales, which is the middle bar, our year-to-date production growth was 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 second quarter. The production impact from turnarounds in the second quarter was 67,000 barrels a day.

We expect heavier planned turnaround activity in the third quarter. The production impact from 2018 asset sales was 15,000 barrels a day in the second quarter with a year-to-date impact of 8,000 barrels a day. With the successful startup for Wheatstone Train 2, continued growth in the Permian and ramp-ups at Hebron, Stamped 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 five LNG trains with a total installed liquefaction capacity of 24.5 million 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 first production in mid-June. The ramp-up has exceeded expectations as Train 2 reach nameplate capacity within weeks of startup. We've already exported the equivalent of six cargoes of Train 2 production, and we’re planning to take a pit stop in the third quarter to remove the start up strainers.

Its companion plan, 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 Gordon pit stops have been successful and we’re seeing improvements in performance and reliability. As a casing point, Gorgon Train 1, since its pit stop, has run more than 285 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 second quarter. 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 FGP WPMP project is progressing as guided towards first production in 2022. The project is 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. Six pipe rack modules have been successfully delivered to sites, demonstrating the operability of the delivery system and the receiving facilities. Site work continues to focus on foundation, undergrounds and infrastructure in preparation for module installation. Major mechanical, electrical and instrumentation contracts have been awarded.

We also have three drilling rigs operating on multi-well pads, and drilling is ahead of schedule. If you recall back in March that I said 2018 is a critical year for execution. This is the first 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 tight production in the second 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 second quarter. 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.

Turn to Slide 14. We’re currently operating eight 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 the core of 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 increase 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 discuss the value of being an integrated company, and our strategy for maximizing returns in the Permian. Chevron has secured from transport capacity at competitive rates to move the equivalent of nearly all of our forecasted 2018 and 2019 operated and NOJV taking kind oil production to multiple markets, including the U.S. Gulf Coast. As a result of these contractual arrangement 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, they'll be periods of tightness and length. As an example, in June, we had more than 50,000 barrels a day of excess takeaway capacity out of the Midland basin, which we monetize through purchases of third-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 source crews. We have firm contractual arrangements in place to further increase that dock capacity in 2019.

Overall, we've exported more than 8 million 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 the slowdown activity or divert capital. Pat, back to you.

[Pat Yarrington, Vice President and Chief Financial Officer]

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 have 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 backend loaded, giving us confidence that our full year product outlook is trending towards the upper half of the guidance range. In addition, we should we see some relief in working capital and additional asset sales proceeds.

Capital spending is on budget for the first six 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 will certainly do our best to get all of your questions answered.

Jonathan, go ahead and open the line please.

[Operator]

Thank you [Operator Instructions]. Our first question comes from the line of Neil Mehta from Goldman Sachs. Your question please.

[Neil Mehta, Goldman Sachs]

Thank you very much, and congratulations on the buyback. It's great to see you’re making this step. I want to start there and see how you guys were framing the $3 billion number. How did you arrive 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 of this as a base load fixed cost, if you will, on a go-forward basis in any foreseeable price environment? Or is this more of a flywheel dynamic?

[Pat Yarrington, Vice President and Chief Financial Officer]

You hit upon in a way you asked the question some of the keywords 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 -- 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 is a bit of 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 billion level was sustainable.

[Operator]

Our next question comes from the line of Phil Gresh from JPMorgan. Your question please.

[Phil Gresh, JP Morgan]

Yes, good morning. I echo Neil's sentiment. Congratulations on the buyback. I guess it's somewhat of a follow-up question. You gave helpful color around cash from operations. It sounds like it supposed to be up 50% year over year, I think is what you said. And so that would be about $30 billion of CFO. If I look at that on a post-dividend, post-CapEx basis, you'd have about $9 billion of post-dividend free cash flow. And so it sounded like you said in your prepared remarks there is also maybe some desire to pay debt down a little bit. But just wondering how you think about that? Obviously, a third 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 up?

[Pat Yarrington, Vice President and Chief Financial Officer]

I think it’s a great question and you are trying relating on the numbers quite accurately there. All I would like to say just from the start, we’d like to hit the cash in the door and see it before we over commit on it. So there might be a bit of conservatism here in how we started. But if you step back and think about the price environment that we’re in and the price environment that may be expected as that market is telling us over the next couple of years that maybe coming, which would be a lower price environment. We think it's prudent at this point in time to strengthen the balance a bit sheet 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 and showing up the balance sheet 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 little bit and paying down debt 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 dividends 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 commitments, share repurchases are the fourth in our priorities, dividends come first. But obviously, we’d like to have as much readability and predictability around share repurchases as we can.

[Phil Gresh, JP Morgan]

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, is 2% year-over-year impact. So maybe you can just provide some color around what you think is going better than your expectations? Is it all Permian or are there other things as well?

[Jay Johnson, Executive Vice President, Upstream]

So I think the primary thing that gives us some confidence is that we started out Wheatstone Train 2 very late in the second quarter. 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 third quarter, which will be bit of a drag on production. But as we move through that, and as we move into the fourth quarter, overall, with these new projects coming online and our relatively low base decline, we really feel pretty comfortable about where we are in our production profile through the rest of the year, barring unforeseen events.

[Operator]

Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question please.

[Paul Cheng, Barclays]

Jay, did I hear you correctly. You were saying that turnkey, you are seeing some cost pressure or sign of cost pressure. Can you elaborate a little bit more in terms of how big -- is that really going to be a big problem or what [material] we’re talking about and where is the source of the cost pressure?

[Jay Johnson, Executive Vice President, Upstream]

So we are seeing some cost pressure. We are now, as I said, approaching 85% complete on the engineering. We’re about 40% complete on fabrication. We’re having a full-year of construction in the field. Where we are seeing some cost pressures at this point in time, our engineering program has cost more than we would have been 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 is a lot of important milestones. The good things that are happening, the fabrication is really working well.

We are seeing high quality come out of the modules and sales as they are being completed and shipped to Tengiz. We successfully tested the logistics system and we have delivered modules all the way to sites. So those things are all working quite well. But what we need to do is we are 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've expected. So that tells us we have cost pressure on this project. We will continue to access it and we will update you accordingly as we need to.

[Paul Cheng, Barclays]

And at what point that you will be more certain whether you have to raise your overall budget? Is it six months from now? Where is 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 it's going to be higher?

[Jay Johnson, Executive Vice President, Upstream]

We continue to assess our performance Paul, as we move through the project. This is a 5, 6 year project overall duration. So, we are 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 are very focused on the timely delivery of engineering and engineer 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 sufficient 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 billion to 20 billion. And we will keep you updated as we gain more information.

[Paul Cheng, Barclays]

My 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?

[Jay Johnson, Executive Vice President, Upstream]

The real price of oil do you mean?

[Paul Cheng, Barclays]

Yes.

[Jay Johnson, Executive Vice President, Upstream]

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 price 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 to plan that really is able to respond and adjust accordingly with options for whatever the price turns out to be.

[Paul Cheng, Barclays]

I'm sorry that I probably didn't make myself clear. When I say real price, means that the price adjusted for inflation. Do you build in an inflation factor, whatever is the price deck that you use? Or you just use a nominal flat price in your assumptions? So when you guys previously saying that Tengiz would be a $60 or low $60 Brent price would be generating a 10% return or 15% return, is that the price is based on inflation adjusted or nominal?

[Pat Yarrington, Vice President and Chief Financial Officer]

It's based on inflation adjusted. I mean we look at what we expect price is to be because the costs out estimates that we are putting together have those kind of components built in. But when we are taking the project to evaluation when we are 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 it in a real sense? So, we look at the economics and judge the value of the project based on multiple price scenarios. But when we are actually putting out an FID kind of number, it is our best estimate of what that cost at that point in time will be.

[Operator]

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]

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, Pat, what you said about the buyback being sustainable, it seems at least on our numbers in the current oil price environment you have got a lot more headroom in terms of surplus cash. But 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.

[Pat Yarrington, Vice President and Chief Financial Officer]

Dough, I think I'll just start and say, we feel good about the $18 billion to $20 billion 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 unconventional. Our ability to take what is relatively a less mature asset base like LNG and debottlenecking and see continued value growth there, we have a whole series of investments that we can see lined out that our current portfolio gives us opportunity to develop economically and that's why we feel comfortable about the $18 billion to $20 billion range.

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 investment. 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 are looking at our 2019 to 2021 plan, and as 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 2019.

But for now, I think the key message is $18 billion to $20 million that's the capital program that's the capital discipline that were living within.

[Doug Leggate, Bank of America Merrill Lynch]

Jay maybe I can follow-up with you specifically than on another potential source of cash because you guys have obviously got tremendous flexibility with the Permian, but it is also very early and your 5 billion to $10 billion disposal plan and since you laid that out the oil prices obviously recovered quite a bit so, so I guess what I'm asking Jay is it that upside to your disposal target, how is the change in oil price changed your view of what's covered in the portfolio and I'll leave it there.

[Jay Johnson, Executive Vice President, Upstream]

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 maybe economic, quite of economics, but they don't compete for capital and or trying to be very disciplined about what projects we invest 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 that 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. It's a pretty normal part of our operation to continue to look at properties as they move through their lifecycle and decide when do they need to exit the portfolio. Our overall focus on all of this, we are not driving your production target we are driving to improve our returns and lead the industry and our returns on the upstream assets.

[Operator]

Our next question comes from the line of Jason Gammel from Jefferies. Your question please.

[Jason Gammel, Jefferies]

Jay, it's 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?

[Jay Johnson, Executive Vice President, Upstream]

Yes, we have not issued any formal guidance around this yet. We are going through the business plan now when we really develop that. But I would say that we took all the knowledge from the Gordon Train 1 and apply that to 2 and 3. We have gone through the pit stops now. So, we are 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 utilize and so that's our primary focus at the moment. Wheatstone is 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 said before, you know some of the small pit stops if we see economically driven opportunities to enhance performance as we have done, but overall I think a lot of the other than routine maintenance a lot of the unknown 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 our three or four-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.

[Jason Gammel, Jefferies]

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 PZ?

[Jay Johnson, Executive Vice President, Upstream]

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 in storm safe, as you know early in the first quarter of this year. The drilling program is underway. We are completing the first 12 and we are moving through and just about 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, of course it's an ongoing issue that the two governments are working to resolve. Our focus is on making sure that we are keeping the facilities and are ready to restart mode. We are very focused on asset integrity and preservation types of activities. We have also done a lot of engineering and use this time of downtime to model, not only a more comprehensive reservoir set of models, but also the surface facilities and really identified all of the opportunities of low hanging fruit to optimize the flow once we get the facilities back online.

So, I think there is a lot of good opportunities for us when it restarts. We remain ready to go and off course we will support the governments as they work towards resolution.

[Operator]

Our next question comes from the line of Roger Read from Wells Fargo. Your question please.

[Roger Read, Wells Fargo]

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 are running ahead of the guidance range. Does that create any risk? And then the second part of my question is as you move non-operated or non-produced barrels that 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 third party, but I was just curious how that works out.

[Jay Johnson, Executive Vice President, Upstream]

So I'll take the first question or first part of the question. The higher production that we're seeing from our operations is taking into account. Our midstream group and our business unit, they are in daily conversation about where we are, what our updated forecast 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 services in areas for our takeaway capacity.

We have adopted the strategies and 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, our gas plants and things where we can tariff through someone else 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 capacities in place, and accommodating our growth plans.

So at this point in time we look very good through 2018 and 2019. We just will continue to monitor this there is 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 the differential exceeding the tariff. I do think in terms of the -- when we think about the NOJV, we almost have to think of the upstream producers 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 are 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 equipment 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 barrel, as we move those to the various markets.

The other thing that our midstream has done it'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 doc into ships and access world markets as well. And so, it really lets us take a forward look at those markets and adjust our off-take as we need to maximize our realizations.

[Pat Yarrington, Vice President and Chief Financial Officer]

And I wanted to add 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 have been under this plan of the 20 rig rate in the Permian for a quite some time. And all of these precursors have been lined out.

[Operator]

Our next question comes from the line of Theepan Jothilingam from Exane BNP Paribas. Your question please.

[Theepan Jothilingam, Exane BNP Paribas]

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 $2.5 billion to $3.5 billion. So I just wanted to know whether that guidance is still valid and how much of 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 uncon 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 the last six months.

[Pat Yarrington, Vice President and Chief Financial Officer]

I’ll take them in order I think. So, yes, good question about the headwinds. So year-to-date, through this first six months we are sitting at combined headwinds of about 3.6 billion. The guidance that I had given back in March was between 2.5 and 3.5. Actually, I think that is still good guidance may in fact come in a little bit lower, I mean a little bit towards the low end of the range.

What we are seeing here with higher prices is that the differed tax headwind 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.

[Jay Johnson, Executive Vice President, Upstream]

And as far as our other unconventional activities, we have continued to see very good progress in all three of the assets. I’ll just walk through them one at a time. The three rigs we've increased from two to three 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 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 that’s in the northern part of that area. And we are planning to do in an eight well pilot for the unconventional potential under El Trapial, and there is a lot of expectation that that may also improve to be a good area for us from an unconventional sense.

We have restarted our drilling campaign in the Marcellus. We took a couple of year holiday just to reduce our capital during the last couple years. So, we are now moving back in the operation there, and the initial results coming out of the Marcellus as we picked up right where we left off and continued our march to lower our unit development and operating cost. So I'm pretty pleased with what we are seeing in the Marcellus and Utica areas.

And then finally, up at Kaybob DuVernay in Canada we are also seeing good performance from our crews up there. We have moved from largely a land tenure and assessment of 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 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 two or three years has been bringing these various teams together they need 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 were 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 force us.

[Operator]

Thank you. Our next question comes from the line of Pavel Molchanov from Raymond James. Your question please.

[Pavel Molchanov, Raymond James]

Thanks for taking the question. As you are 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?

[Jay Johnson, Executive Vice President, Upstream]

We would love to sell them LNG to start with, but what's really important for Australia as with country is energy security. You always want to make sure your country has efficient 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 trillion cubic feet of gas as 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, but we also are really focused on making sure that we move and monetize that gas resource to the various markets that are demanding in. 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.

[Pavel Molchanov, Raymond James]

Okay. A quick follow-up on your monetization plans. You mentioned some of the upstream assets. Given the very hot demand these days for Permian midstream capacity, is that something that you would consider including in your divestment planning?

[Jay Johnson, Executive Vice President, Upstream]

We don't really have midstream assets per say in the Permian area. We have been focusing on the upstream that's where we see highest value and highest returns and are takeaway capacity in the midstream processing like gas plants NGLs is provided by third parties.

[Pat Yarrington, Vice President and Chief Financial Officer]

Okay, thank you very much. I think that concludes the queue here. So, I guess, we're already 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.

[Operator]

Ladies and gentlemen, this concludes Chevron second quarter 2018 earnings conference call. You may now disconnect.