Chevron Corp (CVX) — Q2 2018 Earnings Call Transcript

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 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 second-quarter earnings were $3.4 billion or $1.78 per diluted share. This is nearly $2 billion 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 $6.9 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 a 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 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 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 periods like we’re seeing now to modestly reduce our debt level over time. 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.

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 as in the U.S. Gulf of Mexico and Nigeria, were 51,000 barrels a day. The impact from 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 the 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 reached 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 startup 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 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 the 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 increased the number of long-length lateral wells we can drill by approximately 600 and improved 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 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 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 will 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 sourced 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 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 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 back-end loaded, giving us confidence that our full-year product outlook is trending towards the upper half of the guidance range. In addition, we should 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 in the queue, 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.

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?

We want this to be a sustainable element, so we evaluated several price scenarios and concluded that this level of sustainability is manageable in various reasonable price environments. We monitor market expectations, and the futures market indicates a peak this year followed by a potential downward trend next year, which we considered. Based on this analysis, we determined that the $3 billion level is sustainable.

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 is 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?

It's a good question, and you are correctly tracking the numbers. From the outset, I want to emphasize that we prefer to see cash flow in before making any large commitments. So, we might be starting off with a conservative approach. If you consider the current price environment and the projections for the coming years, which suggest a potential decrease in prices, we believe it's wise to strengthen our balance sheet while commodity prices are still high. We do plan to reduce some debt over the next period. We feel comfortable with our leverage situation but believe that paying down debt slightly and enhancing the balance sheet would be beneficial. Building cash reserves while reducing debt provides us with a safety net for tougher times, ensuring we can meet our established commitments, including dividends and our share repurchase program. Dividends are our top priority, but we aim for as much predictability and clarity in our share repurchase strategy as possible.

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 a 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?

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 a 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.

Jay, did I hear you correctly? You mentioned that with turnkey, you are experiencing some cost pressure or signs of it. Could you explain a bit more about how significant this might be? Specifically, what materials are involved and what is the source of the cost pressure?

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 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 are 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 assess it and we will update you accordingly as we need to.

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?

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 engineering 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.

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?

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 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 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 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 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?

It's based on inflation adjusted. I mean we look at what we expect prices to be because the cost 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.

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've 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.

Doug, 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 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 billion, that's the capital program; that's the capital discipline that we're living within.

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 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 has the change in oil price changed your view of what's covered in the portfolio and I'll leave it there.

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 a bit of economics, but they don't compete for capital and or 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 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 our production target we are driving to improve our returns and lead the industry in our returns on the upstream assets.

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?

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 Gorgon Train 1 and applied 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 utilized 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, 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.

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?

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 bringing 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 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 of the opportunities of low-hanging fruit to optimize the flow once we get the facilities back online. So, I think there are a lot of good opportunities for us when it restarts. We remain ready to go and of course we will support the governments as they work towards resolution.

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 sides, 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.

I will address the first part of your question. The increase in production from our operations is being closely monitored. Our midstream team and business unit are in constant communication about our current status and updated forecasts to avoid surprises. The midstream team has excelled in collaborating with various suppliers and services to enhance our takeaway capacity. We have implemented strategies that focus on maximizing returns from the Permian Basin, which drives our efforts. Whenever we have opportunities to contract services for pipelines and takeaway capacity instead of investing capital, we opt for that approach. This requires careful coordination with our suppliers to ensure that the necessary capacities align with our growth plans. As it stands, we are looking strong through 2018 and 2019, and we will continue to monitor the situation since there are times of tightness and times of excess capacity. We aim to seize opportunities to transport additional crudes through these lines when differentials exceed tariffs. Regarding the NOJV, we should consider the upstream producers in the Midland Basin. Our midstream team takes crude from the Midland area and transports it to different markets. It's a complex system, making it difficult to identify the movement of a specific barrel. It is more about commercial agreements and volume flow. Our objective is to maximize returns for all barrels produced, whether operated or non-operated, as they are sent to various markets. Additionally, our midstream team has effectively secured pipeline capacity to transport out of the basin and arranged for shipping to access global markets. This approach allows us to anticipate market conditions and adjust our off-take to enhance realizations.

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 quite some time. And all of these precursors have been lined out.

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.

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 billion and $3.5 billion. Actually, I think that is still good guidance maybe 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 deferred 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 billion to $3.5 billion but probably closer to the bottom end of that range.

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 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 of years. So, we are now moving back into 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 costs. 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 actual 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 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 as quite a powerful and valuable force for us.

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?

We would love to sell them LNG to start with, but what's really important for Australia as a country is energy security. You always want to make sure your country has an efficient supply of clean, affordable, reliable energy source. And so in Western 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 Western 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 it. So, at this point, I don't see the East Coast problems having any impact on either the expansion or the delivery from Western Australia.

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?

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 highest value and highest returns and are takeaway capacity in the midstream processing like gas plants and NGLs is provided by third parties.

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