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Edited Transcript of CVX earnings conference call or presentation 2-Aug-19 3:00pm GMT

Q2 2019 Chevron Corp Earnings Call

SAN RAMON Aug 8, 2019 (Thomson StreetEvents) -- Edited Transcript of Chevron Corp earnings conference call or presentation Friday, August 2, 2019 at 3:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* James William Johnson

Chevron Corporation - EVP of Upstream

* Pierre R. Breber

Chevron Corporation - VP & CFO

* Wayne Borduin

Chevron Corporation - General Manager of IR

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Conference Call Participants

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* Alastair R Syme

Citigroup Inc, Research Division - MD and Global Head of Oil and Gas Research

* Biraj Borkhataria

RBC Capital Markets, LLC, Research Division - Analyst

* Douglas George Blyth Leggate

BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research

* Jason Gammel

Jefferies LLC, Research Division - Equity Analyst

* Jonathon Rigby

UBS Investment Bank, Research Division - MD, Head of Oil Research and Lead Analyst

* Neil Singhvi Mehta

Goldman Sachs Group Inc., Research Division - VP and Integrated Oil & Refining Analyst

* Paul Cheng

Scotia Howard Weil, Research Division - Research Analyst

* Pavel S. Molchanov

Raymond James & Associates, Inc., Research Division - Energy Analyst

* Philip Mulkey Gresh

JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst

* Roger David Read

Wells Fargo Securities, LLC, Research Division - MD & Senior Equity Research Analyst

* Sam Jeffrey Margolin

Wolfe Research, LLC - MD of Equity Research & Senior Analyst

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Presentation

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Operator [1]

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Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's Second Quarter 2019 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded. I would now turn the conference call over to the General Manager of Investor Relations of Chevron Corporation, Mr. Wayne Borduin. Please go ahead.

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Wayne Borduin, Chevron Corporation - General Manager of IR [2]

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Thank you, Jonathan, and welcome to Chevron's Second Quarter Earnings Call and Webcast. On the call with me today are Jay Johnson, EVP of Upstream; and Pierre Breber, CFO. We'll refer to the slides that are available on Chevron's website.

Before we get started, please be reminded that this presentation contains estimates, projections and other forward-looking statements. Please review the cautionary statement and important information for investors and stockholders on Slide 2.

Turning to Slide 3. And Pierre?

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Pierre R. Breber, Chevron Corporation - VP & CFO [3]

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Thanks, Wayne. We had another solid quarter. The company delivered record production led by continued strength in the Permian Basin and at Wheatstone in Australia. Jay will provide more detail shortly.

First, an overview of our financial results. Earnings were $4.3 billion or $2.27 per share. This is the highest reported quarterly result since the third quarter 2014 when Brent was over $100 a barrel. The quarter's results include special item gains totaling $920 million from the Anadarko termination fee and a tax rate change in Alberta. Foreign exchange gains for the quarter were $15 million. Excluding special items and FX gains, earnings were $3.4 billion or $1.77 per share.

A reconciliation of non-GAAP measures can be found in the appendix to this presentation.

Cash flow from operations was almost $8 billion, excluding working capital changes. We also maintained a strong balance sheet with a low debt ratio. Importantly, our continued strong cash flow allowed us to deliver on our commitment to return significant cash to our shareholders.

During the quarter, we paid over $2 billion in dividends. And after terminating our agreement with Anadarko, we resumed buybacks and repurchased $1 billion of shares during the quarter. Going forward, we expect share buybacks at the $5 billion annual run rate or $1.25 billion per quarter in line with our updated guidance stated in May.

We also continued to maintain capital discipline with a focus on increasing returns. Year-to-date organic CapEx was $9.6 billion, a little less than half of our $20 billion budget. Total CapEx, which includes acquisition costs that are unbudgeted such as the purchase of the Pasadena refinery, totaled $10 billion.

Turning to Slide 4. Cash flow was strong and the trend is in line with full year guidance. Cash flow from operations, excluding working capital increased this quarter due to growing production volumes and higher liquids realizations as well as the termination fee received from Anadarko. Free cash flow excluding working capital increased to $4.3 billion and supported the dividend, debt reduction and share buybacks. The company's cash flow breakeven remains in the low 50s on a Brent basis year-to-date.

Asset sales proceeds added to our positive cash flow and further lowered the breakeven while high grading our portfolio. Since the beginning of 2018, asset sale proceeds have totaled $2.9 billion, and we remain on track to divest $5 billion to $10 billion of assets by 2020.

Turning to Slide 5. Second quarter 2019 earnings of $4.3 billion increased about $900 million versus the prior year. Excluding special items and FX, upstream earnings were relatively flat as higher production was offset by lower realizations. Downstream earnings also were relatively flat as timing effects were offset by lower margins. The variance in the Other segment was primarily the result of lower corporate charges.

Turning to Slide 6. Compared to the first quarter, second quarter earnings increased by about $1.7 billion. Excluding special items and FX, upstream results were roughly flat as higher liftings in crude realizations were offset by lower gas realizations, higher DD&A and other expenses. Australia gas realizations were lower primarily due to lower LNG spot prices and a higher ratio of spot LNG sales while U.S. gas realizations reflected weaker Henry Hub and Waha pricing. Downstream earnings excluding FX improved by about $520 million due to stronger U.S. West Coast refining and marketing margins and timing effects, partly offset by the impacts of planned downtime. The variance in the Other segment largely reflects lower corporate charges.

I'll now pass it to Jay.

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James William Johnson, Chevron Corporation - EVP of Upstream [4]

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Thanks, Pierre.

On Slide 7, second quarter oil equivalent production increased 9% compared to a year ago with shale and tight production increasing in the Delaware and Midland basins and production for major capital projects increasing with ramp-ups at Wheatstone, Hebron and Big Foot. Our base business production increased as Gulf of Mexico and other deepwater brownfield developments more than offset natural declines across the portfolio.

Turning to Slide 8. Second quarter production was strong at more than 3 million barrels a day for the third straight quarter. Year-to-date production excluding asset sales is about 5% higher than 2018, consistent with our guidance of 4% to 7% growth as shown by the middle bar. Second quarter production was impacted by planned turnarounds and asset sales, which together had an impact of almost 70,000 barrels a day.

Looking forward to the second half of the year, we expect production growth to be primarily driven by our shale and tight assets as well as a continued ramp-up of Big Foot and Hebron. This growth will be partially offset by higher turnaround activity in the third quarter. Our full year outlook is expected to be in line with its guidance even before adjusting for the entitlement impacts of higher prices.

Let's turn to the Permian. In the next 3 slides, I'll provide some additional information regarding the attractive performance and the potential of this asset. Permian shale and tight production continues to track the guidance we provided at our 2019 Security Analyst Meeting. In the second quarter, production was 421,000 barrels of oil-equivalent per day, an increase of over 150,000 barrels a day or about 55% relative to the same quarter last year. This strong performance demonstrates our track record of consistent execution, and we expect to deliver 900,000 barrels per day in 2023 with a relatively steady rig count.

Moving to the mix of crude oil, NGLs and natural gas. About 3/4 of our Permian production is liquids, and 1/2 of our production is crude oil. We expect these proportions to continue throughout the forecasted period.

As discussed in the past, we have an advantaged royalty position across the Permian, and it's comprised of 2 distinct components. First, we have a royalty benefit shown in the dotted blue wedge as our actual royalty rate is lower than the standard royalty rate. The second component comes from the royalty barrels shown by the hashed blue wedge, which are the barrels we receive from the acreage that we've leased to other producers. And of course, these barrels require no Chevron capital. In total, these royalty contributions make up about 20% of our production throughout the 5-year period and contribute to delivering our expected production profile.

Let's turn to Slide 10. Our work to reduce unit cost and increase productivity continues. We're optimizing our Permian factory and maintaining our focus on delivering industry-leading returns. This slide shows the progress we've made since 2016. As shown on the left, we continue to drive higher EURs by optimizing well spacing, landing zones and completions. The average lateral length of our wells continues to increase and is expected to approach 10,000 feet next year as we execute our core-up strategy for our development areas.

As illustrated in the upper right, these efforts translate into a sustained reduction in unit development and production costs. The chart on the lower right shows that the royalty benefit alone leads to returns that are about 10 percentage points higher than a comparable well subject to the standard royalty burden. As we've said before, our strategy in the Permian is to be highly competitive in our execution, leverage our midstream capability and use our advantaged royalty position to make us the clear leader in financial returns.

Slide 11 shows that we're well on our way. As stated in March, we expect to be free cash flow positive next year, and we expect to grow free cash flow each year thereafter. Earnings are expected to strengthen, exceeding $4 billion in 2023. All of this assumes the same reference prices communicated at our 2019 Security Analyst Meeting.

As the Permian production increases, we expect to see operational cash flow nearly twice the level of C&E by 2023 and a return on capital employed of about 30%, all delivered by an optimized, ratable factory with relatively low execution risk. To more than double production while being free cash flow positive every year starting next year and generate returns on capital in excess of 20% along the way shows why this is an attractive investment opportunity for our company and its shareholders. We're focused on value, not volume, and our true measure of success is building a sustainable business with strong free cash flow and growing returns.

Let's turn to Slide 12. In the Gulf of Mexico, we have a robust portfolio that's performing well, generates good value and has attractive investment opportunities at each stage of development. We have a strong queue of exploration prospects that we're actively evaluating and maturing.

Earlier this year, we participated in the Blacktip exploration well, which resulted in a discovery near Perdido and Whale. The well encountered more than 400 feet of net pay and is within tieback distance. Whale and Ballymore are progressing through the appraisal phase to further assess the size of the resource. As mentioned in March, we're targeting unit development cost of $16 to $20 a barrel for new developments in the Gulf of Mexico.

Anchor continues to progress towards FID, which is expected by early next year. The technology we're developing to exploit these higher-pressure reservoirs will allow us to target other resource opportunities in the Gulf of Mexico.

At Mad Dog 2, drilling and fabrication is progressing as planned, and the project is expected to deliver first oil in 2021. And we expect Big Foot and Stampede to increase production as we bring on additional wells.

We're also pursuing highly economic brownfield developments at existing assets such as Jack/St. Malo and Perdido. With our leading technology, experienced workforce and broad portfolio, we're continuing to add value in the Gulf of Mexico.

Turning to Slide 13. I had the opportunity to visit Kazakhstan again in June, and we continue to make good progress with the future growth wellhead pressure management project at Tengiz. The project is now 65% complete and remains on track for first oil in 2022. As we discussed at the March analyst meeting, this is another critical year for the project as we're fully engaged with module fabrication, transportation and installation, and that's our first full year of mechanical, electrical and instrumentation work at site. Detailed engineering and procurement are almost complete, reducing the risk of further impact on fabrication and construction activities. We're on schedule to close out work at 3 of the 4 fabrication yards this year. The logistics system is working well, and modules are being delivered, restacked and set on foundations.

As reported in the media on June 29, one of our contractors at the 3GP site experienced an interpersonal conflict that resulted in the suspension of construction activity at the site for several days. Production operations and other FGP sites were not affected by the incident. And overall, the event is expected to have a relatively minor impact on project progress. With respect to construction, we're just under 40% complete. Looking ahead, our focus continues to shift to productivity at site where we're seeing good performance from our workforce and steady improvement in productivity.

With that, I'll turn it back over to Pierre.

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Pierre R. Breber, Chevron Corporation - VP & CFO [5]

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Thanks, Jay.

Slide 14 highlights some recent commercial developments. First, through our joint venture, Chevron Phillips Chemical Company, we announced 2 new petrochemical investments, one in the U.S. Gulf Coast and one in Qatar. Each is in a joint venture with Qatar Petroleum. The long-term fundamentals of chemicals are strong. We believe these projects offer attractive returns underpinned by advantaged feedstock, world-class scale and leading technology.

Also in the quarter, we closed the sale of our interest in Denmark and executed an agreement to sell our U.K. Central North Sea fields, which we expect to close later this year. Additionally, we completed our acquisition of the Pasadena refinery, which will enable us to supply more of our retail market in the region and process more domestic light oil. In the renewable space, we recently agreed to purchase wind power to supply our Permian operations. This is a cost-effective renewable energy alternative to our current electricity supply in the Permian. Also Chevron executed an agreement to be an equity partner in CalBio gas, a joint venture to produce and market dairy biomethane as a vehicle fuel in California. The project will capture methane that otherwise would be vented to the atmosphere and process it into renewable natural gas.

Turning to Slide 15. Our performance this quarter reinforces 4 key messages you've heard from us in the past. First, we have an advantaged portfolio that is delivering today and is positioned to do so over the long term, as Jay highlighted in the Permian, Gulf of Mexico and at Tengiz. Second, with continued positive free cash flow this year, we have the strongest balance sheet in the industry, a low cash breakeven and resilience if prices fall. Third, we are disciplined with capital spending, on track with our budget and committed to increasing returns. And fourth, we have a total cash yield of about 6% with the resumption of our share buybacks.

Bottom line, we are positioned to deliver superior financial performance to our shareholders consistently for many years to come.

Now looking ahead. (inaudible) we continue to expect...

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Operator [6]

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(technical difficulty)

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Wayne Borduin, Chevron Corporation - General Manager of IR [7]

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I believe we were cut off prematurely so actually, we'll begin with Slide 16.

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Operator [8]

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You may resume.

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Pierre R. Breber, Chevron Corporation - VP & CFO [9]

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Okay. Thank you, Jonathan. This is Pierre, and we understand that we cut off at Slide 16, so I'm going to resume there and we're going to look ahead.

In upstream, we continue to expect 2019 production growth to be 4% to 7%, excluding 2019 asset sales. Planned turnarounds in Kazakhstan, Nigeria and the North West Shelf in Australia as well as the early July hurricane in the Gulf of Mexico are expected to impact production in the third quarter. Our full year guidance for TCO co-lending is unchanged at $2 billion, dependent upon price investment profile and its dividends. In downstream, we expect high level of refinery turnaround activity in the third quarter, which guides to an estimated after-tax earnings impact of more than $200 million. For the third quarter, we expect a repurchase -- we expect to repurchase shares at a rate of $1.2 billion per quarter.

With that, I'll hand the call back over to Wayne.

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Wayne Borduin, Chevron Corporation - General Manager of IR [10]

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Thanks, Pierre. That concludes our prepared remarks. We're now ready to take your questions. (Operator Instructions) Jonathan, please open the lines.

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Questions and Answers

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Operator [1]

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(Operator Instructions) Our first question comes from the line of Phil Gresh from JPMorgan.

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Philip Mulkey Gresh, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [2]

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So I guess first question, just looking at this Permian additional disclosure and your cash flow expectations, it seems like what you're implying here is that you can grow earnings and cash flow and the ratio of cash flow to CapEx keeps going up. So it seems to imply a pretty flattish CapEx profile, which I think is fairly consistent with the rig count trajectory you talked about at Analyst Day. So I was wondering if maybe you could just kind of walk through that detail.

And then secondarily with -- related to that, I know you recently had an announcement that you made with Enterprise talking about takeaway out of the Permian. I was just wondering how that all feeds into this ability to ensure you get the best realizations for your production.

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James William Johnson, Chevron Corporation - EVP of Upstream [3]

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Okay. I'll take it and Pierre may want to add in some at the end. From a CapEx standpoint, Phil, we are looking to maintain a relatively flat profile in capital, and that's because essentially, we're looking to have a very steady rig fleet as we go forward. We have 20 company-operated rigs. Those are basically on a 100% basis because we operate our own licenses. And then we look for about 30 roughly gross non-operated rigs, which equates to about 7 to 10 net nonoperated rigs.

So as we move that forward we expect to see capital relatively constant. We're building out infrastructure, of course, and we always have some exploration activity out in front of us, and we also do pilot work to ensure that we're continuing to drive to increase the recovery and efficiency of our developments.

In terms of the takeaway capacity, I'll break it into 3 different streams. I'll start with the crude oil. And basically for 2019, we're well covered on our takeaway capacity for crude oil. In 2020, we are also covered for the year. There may be periods of tightness in length as we move through the year, but we recently executed an agreement with Enterprise, not only for takeaway capacity out of the Permian Basin but also for export capacity that will lengthen our ability to supply crude not only in the domestic U.S. but internationally.

When we look at natural gas liquids, we have full takeaway capacity for this year and next year. And as we turn to gas, we really think of gas in 2 ways. The first is just basic flow assurance. We need to be able to move the gas without having to flare or have any threat of mitigating production in our avoidance of flaring. So we have 100% flow assurance set up for the balance of this year and next year. In terms of takeaway of gas from the basin outward for export, what we look at is, this year, we're at about 20% of our gas can be exported from the basin. And by the end of this year, we expect to be about 25%. By the end of next year, we should be more like 60% of our gas being exported from the basin gives us more exposure to other price structures rather than just the Waha.

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Philip Mulkey Gresh, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [4]

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Okay. Great. Just my follow-up question then for Pierre would just be some of your balance sheet commentary. Your net debt to cap, I believe, is at lowest since it has been since mid-2015. I know you increased the buyback a bit. There was the situation where you had an M&A consideration there that you walked away from, but I guess how do you think about that level of financial leverage? And where you want to keep that balance sheet for opportunities that might present themselves?

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Pierre R. Breber, Chevron Corporation - VP & CFO [5]

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Look, our cash generation has been strong, and we've been returning cash to shareholders, and we increased our dividend 6% early this year. As you mentioned, we raised our guidance on the share buyback rate in May to $5 billion per year. We're being very disciplined with capital managing to our $20 billion organic budget in 2019. So the way the math works, no doubt in the short term, our strong balance sheet gets even stronger. That's okay. Over time, this strong cash generation will be returned to shareholders in the form of higher dividends and a sustained share buyback program. That's the way I would think about it. I won't comment on M&A. We obviously have -- we're in a very financially strong position, at the same time we've got a great value proposition for our shareholders that we've communicated at our March Analyst Day, and then Jay provided more insight into some key elements today, and that's what we're focused on delivering.

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Operator [6]

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Our next question comes from the line of Neil Mehta from Goldman Sachs.

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Neil Singhvi Mehta, Goldman Sachs Group Inc., Research Division - VP and Integrated Oil & Refining Analyst [7]

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I guess the first question I have, Jay, you just came back from Kazakhstan, sounds like. There are some questions around labor productivity as it relates to Tengiz. Can you just confirm everything is on track and then just in terms of the capital budget as well your confidence level in achieving the targets that you set out?

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James William Johnson, Chevron Corporation - EVP of Upstream [8]

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Yes. So we just did come back. We were there in June. And we talked about this at the Security Analyst Meeting and in previous calls. A big focus at site now is on labor productivity. We've got a lot of work to do as the modules come in are set on foundations. Last year, we were primarily focused on civils and undergrounds. This year, we're making the transition to mechanical, electrical and instrumentation. As we look forward, we have to get through commissioning and then all the start-up activities. So we've put in place specific tools that can really help us not only drive the productivity but understand what the drivers are, where we have gaps from where our expectations are and what we need to do to close those. Those tools are now widespread across the site and are proving to be very effective so we've seen steadily improving productivity across the workforce and are actually feeling pretty good about where the execution is headed at this point. But it's early days. We're 40% roughly complete on construction, and we've got a lot of man-hours to go over the next couple of years.

In terms of the overall capital program, you've seen we continue to be right in the middle, right on our guidance. We're about 50% expended on our Chevron C&E through mid-year, and we still expect to maintain our guidance of $18 billion to $20 billion for next year, so that should give you a pretty good idea of where things sit.

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Neil Singhvi Mehta, Goldman Sachs Group Inc., Research Division - VP and Integrated Oil & Refining Analyst [9]

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Appreciate this. A follow-up question, this might be for you, Pierre. You've gotten a lot of credit from investors for stepping away from the Anadarko potential transaction and showing the capital discipline. Now since the deal closed, the stock has materially outperformed other constituents of the XLE or XOP, the others, independent E&Ps and that multiple arbitrage or share price ratio arbitrage seems to be opening up again. Just want to get your thoughts on M&A. Again, it felt opportunistic but is another opportunity potentially opening up here?

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Pierre R. Breber, Chevron Corporation - VP & CFO [10]

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Yes. Thanks, Neil. Look I obviously can't speculate on M&A. What I can restate is we have a very strong value proposition for our shareholders. And if I can just -- some of the key elements that we communicated in March is 3% to 4% production growth guidance through 2023, a very disciplined capital program. Jay provided the 2020 guidance of $18 billion to $20 billion and longer-term guidance of $19 billion to $22 billion from 2021 to 2023. We have leading upstream cash flow margins, leading earnings margins, and we're improving cash return on capital employed by more than 3%. So we clearly do not need to do a deal. That said, as you said, we have been opportunistic in the past if we see a good strategic fit at a good price, at a good value. And 2 recent examples would be the Pasadena refinery and Anadarko, but we've moved on and we're focused on delivering -- growing earnings and cash flows for our shareholders.

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Operator [11]

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Our next question comes from the line of Alastair Syme from Citi.

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Alastair R Syme, Citigroup Inc, Research Division - MD and Global Head of Oil and Gas Research [12]

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I just had a couple of questions. One, can you talk a little bit about Anchor, which you're hoping to FID next year? What do you think has to happen to move that forward? Because my understanding is there's still quite significant technological challenges. And the follow-up if you can just talk a little bit -- it's just sort of a question just on the asset sales that you announced, the U.K. asset sales in the quarter. Can you talk about what happens on the decommissioning liabilities associated with those assets, please?

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James William Johnson, Chevron Corporation - EVP of Upstream [13]

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Yes. So with Anchor, we are in the FID process so this is doing all the preliminary engineering work prior to the detailed engineering. I would say there are 2 primary technologies to be developed to support Anchor. And in developing for Anchor, we'll also have these available for other opportunities that we foresee. The first is just the high-pressure technology getting to the 20,000 psi. That's well along, and we really -- it really comes down to just thicker steel. We're in the qualification stages and we really don't see that as a major technology shift. It's just a matter of working through the process, and the second is the higher hook loads for deeper wells, and this will also support potential developments like Ballymore. So neither of those do we regard as a particularly challenging technological advance but an important one to get finished. So we do expect to be on path with Anchor for FID early in the next year. In terms of the North Sea deal, we really don't get into the details of any of our commercial transactions, so I can't really comment too much on that other than to say, as an overall package, we're very comfortable with the transaction as it's been constructed and are working with the buyer to move it forward to close.

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Pierre R. Breber, Chevron Corporation - VP & CFO [14]

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Yes. And I think I can add to Jay's comments that we're fully in tune with the importance of abandonment obligations, and that's carefully considered in terms of the financial strength of the partners or the parties that we transact with. And again, we won't be specific as it's commercially sensitive, but as you can imagine, the point of negotiation and something that we don't intend to be exposed to over time.

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Operator [15]

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Our next question comes from the line of Biraj Borkhataria from RBC Capital Markets.

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Biraj Borkhataria, RBC Capital Markets, LLC, Research Division - Analyst [16]

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Apologies if I missed this, I was cut off the call, but I have a question on LNG. You mentioned a higher ratio of spot details in the quarter. Could you just talk through what was driving that? One of your peers has talked about buyers for their contracts not taking their full nominations. So I was wondering if that was the issue or there's something else there.

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James William Johnson, Chevron Corporation - EVP of Upstream [17]

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I'll talk first in general because there's an element of -- as we gain in our performance, the facilities are performing very well, reliability is coming up, we have extra production over and above what we had planned, and so all that production is going to be exposed to spot prices. And so that's going to be an ongoing thing. In the second quarter specifically, we certainly had excellent performance at both Gorgon and Wheatstone, and so we had extra production coming from that. But at the same time, we also deferred a turnaround so we had a turnaround scheduled in the second quarter that's been moved to the fourth, so we had extra cargoes there that were exposed to spot. We do have some downward flex that was exercised by some of our purchasers in the shoulder months, and that occurred in the second quarter. And then finally, there's also an element even in our fixed-term contracts where we had about a 3- to 6-month delay in the oil pricing that they're linked to, and so we saw some downward movement in that element. So together, those all really drive the realizations in the second quarter for our LNG. But as I say, going forward, we do expect to see increased production as our reliability's been higher, and our overall goal would be to term that up and get closer to what our expected production is as we gain continued confidence in the reliability of the facilities.

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Biraj Borkhataria, RBC Capital Markets, LLC, Research Division - Analyst [18]

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That's great color. Just a quick follow-up. At Gorgon, in particular, I think in the past you may have talked about debottlenecking the project increased capacity by maybe 10% or 15%. Can you just update us on where we are now relative to the original nameplate?

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James William Johnson, Chevron Corporation - EVP of Upstream [19]

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Yes. I don't recall us giving out specific guidance on percentages of increase. Our focus right now is on doing a couple of things. That's -- first is just getting the reliability increasingly high, and we've seen very good reliability. We're still learning these facilities as they continue to operate, and we build learnings from some of the shutdowns and turnarounds that we've already accomplished into future ones. As we look forward, what we are looking at is we're collecting the data literally daily as we move through an annual cycle of the ambient conditions as well as the performance of the plant. We look for where the restrictions that keep us from going to that next level of production. At this point in time, I'd say we're probably 2% above where we expected to be on Gorgon production, around 6% above on Wheatstone, but it's an ongoing effort as we move forward to get more out of our existing investments and infrastructure.

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Operator [20]

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Our next question comes from the line of Jon Rigby from UBS.

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Jonathon Rigby, UBS Investment Bank, Research Division - MD, Head of Oil Research and Lead Analyst [21]

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Two, please. The first is the Anadarko transaction during that process, I felt that you sort of indicated that you had capacity and the willingness to sort of deepen your deepwater participation globally, and you spoke quite enthusiastically about adding extra LNG to your portfolio, creating a global position, et cetera. So as you move forward with new opportunities as and when they arise, thematically outside of the U.S., is that where we should expect you to be appearing or looking? And then the second, just very specifically with the new refinery asset, what are the plans for that now you've got ownership of it?

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Pierre R. Breber, Chevron Corporation - VP & CFO [22]

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Thanks, Jon. This is Pierre, and I'll start. I said earlier we moved on, but it looks like we'll go back to Anadarko a little bit here. Look, there were several elements of it, the transaction. There was the FID in the Permian, there was the FID in the Gulf of Mexico, and there was the LNG. And there was the ability to get synergies out of the transaction and do it at an attractive price that we thought was good for their shareholders and good for our shareholders. So that -- if you want to get into our thinking, we -- adding LNG is something that absolutely we are interested in doing. We've got a great position in Australia that Jay just talked about that's generating a lot of cash where we have opportunities to debottleneck and potentially add to that over time. And you'd expect that we are -- we're always working the portfolio, and LNG is one of the asset classes that we're interested in, and we'll pursue opportunities in that space. That makes sense for the company and our shareholders.

In terms of Pasadena, we've had 3 very clear strategic objectives on it. One was to provide some equity product into our retail network in Texas. The second was to coordinate and optimize feedstocks and other flows between Texas and our refinery in Pascagoula, Mississippi. And the third was to process more domestic light oil and increasingly, try to position and retool the refinery a little bit to take more and more Permian oil. So really, I mean, it's very early days, but I'd say everything is on track and aligned with the strategic rationale. So there's been no surprises in terms of those 3 objectives. We feel we can meet them with the acquisition. We've had some early wins. In fact, over the next few months, we expect to run up to 30,000 barrels a day of Permian crude oil. That's a little more than we actually had thought at this point in time. Also we know there's work to do as expected on maintenance and reliability of the facility. So everything is on track, and we feel good about it, but it's early days.

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Operator [23]

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

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Jason Gammel, Jefferies LLC, Research Division - Equity Analyst [24]

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I had a couple on the Permian Slide #10. I guess the first one would be obviously some fairly impressive, absolute performance in increasing EUR and decreasing development production cost on an absolute basis. I know you did a lot of benchmarking. How would you say you stack up against industry in those areas now?

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James William Johnson, Chevron Corporation - EVP of Upstream [25]

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Yes, that's a good question, Jason. I think the -- we do, do a lot of benchmarking, and this continues to be an evolving story. So I would say we're competitive on these areas. We have a very good understanding, particularly in terms of the type curves across the entire basin. We have the capability and actually run decline curves across not only our own but competitors' wells so that we understand how our wells are performing, and we're actually very comfortable with the overall performance not only in terms of the recoveries but the economics that we're generating from the execution work. And then when that's coupled up with our ability to use our midstream capability and our royalty position, it's really giving us, I would say, leading financial performance overall.

So if you went back and looked at our Security Analyst Meeting slides, we showed you some of the competitor data. We also showed you how our actual type curves are performing relative to our expectations, and they're very tightly coupled. So I think we have a good understanding, but we're seeing that continued improvement as we move forward.

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Pierre R. Breber, Chevron Corporation - VP & CFO [26]

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Yes. The only thing I would add to Jay's comments -- this is, Pierre. Look, I mean, you can cherry pick a lot of data out there to position how you look. We've been pretty consistent with what we've shown. And also we've done a lot, not just general benchmarking by comparisons to our non-op partners or the operators on our behalf where we know we have very good apples-to-apples data. So it is an area of, focus and we feel we compete very well.

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Jason Gammel, Jefferies LLC, Research Division - Equity Analyst [27]

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That's great. And maybe just a quick follow-up, I noticed that the average lateral length that's planned for 2020 is starting to approach 10,000 feet. In the past, you've had fairly frequently slides about swapping another positioning to kind of block up your acreage. And if you're moving towards 10,000 feet, I'm suspecting you're getting a long ways towards doing that, but can you just kind of talk about whether there's further opportunity there?

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James William Johnson, Chevron Corporation - EVP of Upstream [28]

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Well, as we continue -- in the existing development areas, we are getting higher and higher on our average lateral length and approaching that 10,000-foot mark. In the areas that we've transacted, we had about 60,000 acres that we transacted in 2017 and 95,000 acres in 2018. Those enabled are about 1,900 longer laterals, so it's really helped us in our core-up development areas. As we continue though to open up new development areas, we're going to continue to have this land activity as we optimize our land positions. So about half of our acreage overall we consider to be in very highly productive areas. And what we'll want to do is continue to use swap-outs or swaps and farm-out sales acquisitions to continue to core up our development areas. We try and do that in a timely manner. We don't want to get too far ahead of ourselves, but we do want to make sure that we're drilling efficiently as we start each area. As we've said many times, our focus is on delivering returns, not just chasing production or chasing a certain activity level.

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Operator [29]

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Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [30]

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I was wondering if, Jay, I could take advantage of you being on the call just a little bit in terms of the assumptions you made in the Permian on the cash margins, things have obviously deteriorated, no fault of your own, in terms of NGLs and gas. So if -- how do you see the prognosis there? What assumptions were you making when you were talking about CapEx versus cash flow? And I guess kind of the last piece of that question is 900,000 barrels a day out of 3.3, 3.4 in 2023 suggests that your cash margin across the portfolio could move away from this sort of sector leaving (inaudible) what you've had in the past. I'm just curious if you can offer any thoughts on that. I've got a follow-up, please.

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James William Johnson, Chevron Corporation - EVP of Upstream [31]

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Well, the cash -- the assumptions that we provided are all given in our Security Analyst Meeting deck so you can go back and reference those. And what we're trying to do is continue to make sure we have the flow assurance, as I mentioned earlier in the call, to move gas out to other markets and not have it captured in the immediate basin. Crude oil, we're already well ahead of that. We move our crude outside the basin, and we can access and optimize the markets that we're reaching.

In terms of the cash margin overall, again, we've given you that information. We see that as very strong. There's always going to be fluctuations in the market as there's tightness and length in different locations, but overall, we feel pretty strong about where we're heading with this as a production base but also the other production we have around the world.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [32]

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Okay. I understand. There's a lot of moving parts in that. My follow-up is kind of related, and it's -- historically, when oil prices we're a lot weaker, you guys talked routinely about what your sustaining capital was in the portfolio. And obviously, that has been reset favorably by the very large LNG projects and now it's kind of dominating the base decline and the lack thereof. As you move towards again this level of having a significantly larger proportion of your production and a high decline underlying unconventional asset base, what does that do to the sustaining capital versus, I think, you used to talk about like a $13 billion number. How does that evolve as we move towards the 5-year plan?

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Pierre R. Breber, Chevron Corporation - VP & CFO [33]

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This is Pierre, and I'll start and ask Jay to add some comment. We've never really talked about sustaining capital. We've given -- we have a $20 billion capital budget this year that we talked about, $18 billion to $20 billion guidance next year and then $19 billion to $22 billion, 2021 to 2023. So the guidance is pretty clear. It's pretty tight. That results in an enterprise that's growing 3% to 4% of production growth through 2023 with leading cash margins.

So the prior times we talked about the base decline. We are investing in the unconventional, as you saw on the Permian, that it's -- the production is more than doubling while it's being free cash flow every year starting next year at returns that are going from 20% to 30%. So we feel really good about our position. We're not focused on keeping a base flat capital. We're focused on increasing returns. It's resulting in an outcome of higher production that's translating to higher earnings and cash flow. But the high decline that you referred to is that it's a nature of the business, but when you're investing in it, you can see that we're more than offsetting that decline, and we're doing it in a very economic manner. And as we continue to fill out facilities and keep facilities filled over time, the reinvestment is a very attractive use of capital for the shareholders.

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James William Johnson, Chevron Corporation - EVP of Upstream [34]

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I might just build on what Pierre said because he's absolutely right. As we have a larger percentage of our overall production constrained by facilities. It means we have the ability to be very stable in our production. And the same in some respects actually applies in the Permian. While any individual well may have a relatively high decline rate, it does approach an asymptotic curve, but the facilities we install for each of the development areas, our goal is to keep those full. And one of the advantages of the Permian is that in the initial drilling, we fill the facilities up, but then we can go back to infill drilling programs and by going after the subsequent benches in a given development area and just continue to keep those facilities full. And the amount of rig activity it takes is much less for those subsequent drilling campaigns to maintain that production in a given development area. So I actually feel pretty good about where the whole portfolio has moved and really, I'm not too worried about what some people see as a problem with these individual Permian wells.

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Operator [35]

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

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Roger David Read, Wells Fargo Securities, LLC, Research Division - MD & Senior Equity Research Analyst [36]

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Maybe just to dive in here, kind of following up on some of the Permian questions. With your royalty position and others' developments and with some of the problems we're seeing from some of those E&Ps, any risk to your outlook from those who might have overstepped their bounds in terms of the way they were developing the Permian?

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Pierre R. Breber, Chevron Corporation - VP & CFO [37]

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Well, Roger, this is Pierre. I mean, you're right. I mean, we don't control the royalty barrels because that's being operated by others who own the working interest. We're a landowner. And as Jay said, we receive those barrels with no capital, no operating cost, but the flip side is that we don't control the development. So we're doing it based on an outlook and an expectation. Certainly, we know what the actuals have been, but you're right that there is some risk of that. It could go either way. It could go bigger or lower than what we're showing dependent on what those operators activity levels are.

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Roger David Read, Wells Fargo Securities, LLC, Research Division - MD & Senior Equity Research Analyst [38]

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Okay. Great. And then from a guidance standpoint on the downstream, the high refinery turnaround activity for the third quarter. I was under the impression you'd had fairly high turnaround activity earlier in the first half of this year. So I was just curious was that the right interpretation and maybe if there's any geographic specific exposure on the high TARs this quarter.

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James William Johnson, Chevron Corporation - EVP of Upstream [39]

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Yes, Roger, so we have now adopted a practice of giving pretty clear guidance on planned turnaround activity in the downstream, and we characterized it as either a low, medium or high. So you're right, second quarter was high, and that's related to $200 million of after-tax earnings impacts both from higher costs and from lost profit opportunity beyond volumes not produced. First quarter was actually low, which is up to $100 million of FX. So in the third quarter, it's another high quarter. That's not unusual. It just depends on how the planned turnarounds are set up. We won't provide specifics on the locations. It's commercially sensitive and so it's just something that we won't do ahead of time. We're happy to talk about it looking back. So in the second quarter, we had some planned turnaround activity in Pascagoula and in Asia. So we can explain afterwards but we think we're giving pretty clear guidance. So you're right that you should view the earnings -- after-tax earnings impact of planned turnarounds in 3Q to be the same or similar to 2Q.

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Operator [40]

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Our next question comes from the line of Paul Cheng from Howard Weil.

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Paul Cheng, Scotia Howard Weil, Research Division - Research Analyst [41]

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Jay, since you are here, and I think you mentioned in your prepared remarks about the incident in Tengiz with your contractor, at least in the media it seems like they make it as may have been more serious talking about between the foreign contractor and the local people and may even be different gender. Can you give us a little bit more update on that and whether there's any initiatives have been taken trying to resolve the problem there?

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James William Johnson, Chevron Corporation - EVP of Upstream [42]

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Yes, Paul. I can give you a little bit more. This is really centered around one particular contractor that was at the 3GP site, and there were obviously some disagreements between some of their workers and the management of that company. When the issue happened, we shut down the entire site, the 3GP site, not the other site that didn't have any impact on production operations. But we wanted to make sure that the problem was mitigated and contained, and we understood what was at the root of it. We've worked with that contractor. They're putting in place corrective action to make sure that they deal with some of the concerns that were there. That is the only contractor that's had an extended ramp-up so they are working back to their normal strength, and we expect to see then that normal strength by the end of August. So at this point in time, we don't see it as having a material impact on the overall progress of the work. That contractor was about 1 month ahead of where we expected them to be on the workflow. So unfortunately, we've used up some of that float that they'd built up, but we believe we're going to be able to mitigate the impact to this. The worker and the workforce relations are always important to us, and this is one that we continue to stay focused on. It's very important as now our focus continues to shift to site, and I can assure you we'll stay focused with our workforce to make sure that we're trying to anticipate and deal with any other concerns.

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Paul Cheng, Scotia Howard Weil, Research Division - Research Analyst [43]

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And the second question, Jay. I think in Angola, Block 14, I think that the expiration is 2023. And in Nigeria, in Agbami, I think, is 2024. When you guys will start the process for renegotiation on those?

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James William Johnson, Chevron Corporation - EVP of Upstream [44]

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Well, that's not something we normally are going to talk much about publicly, Paul. That's between us and our partners and the government. So I can tell you that those discussions and the planning for that is well in hand, but I really won't be able to go into much detail on those at this time.

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Operator [45]

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Our next question comes from the line of Sam Margolin from Wolfe Research.

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Sam Jeffrey Margolin, Wolfe Research, LLC - MD of Equity Research & Senior Analyst [46]

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So in the Permian, one of the things that you talked about contributing to your rig count staying relatively flat is that you're building up a nice stack of vintage wells, and you've got some legacy production that's supporting the outperformance of the new wells. Just really quickly, Jay, can you shed some light on the performance of those older wells, it sounds like you're leading edge wells are meeting your expectations, but how are the vintage wells doing as far as -- how are they holding up and as they get a little longer in the tooth?

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James William Johnson, Chevron Corporation - EVP of Upstream [47]

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Actually, they're doing quite well. Our focus from day 1 has been to maximize the returns that we can get from our investments in the Permian. So there's been a lot of questions why don't we increase our rig fleet, why don't we be more aggressive, but the reality is we continue to learn as everyone in the industry as we move forward, and I think a lot of the moves we've made to stay focused on returns now are paying off. Many people talk about how high their initial production rates are and their first 6-month rates. But what we're really looking at, that can actually damage wells and cause aggravated decline curves. So we're are looking at the total expected recovery. We're looking at the economics of the well over its life. We're very careful in our drawdown rates in those early months to make sure that we don't cause damage in a wellbore or in the formation. When we put all that together, we're seeing our base production. That is the production that's already online continuing to perform such that when we drill these new wells, we can add that on top. And as you saw from the chart, I believe it was on probably Page 9, we've been able to continue to deliver right on our production profile, and we feel very good about how our wells are performing.

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Sam Jeffrey Margolin, Wolfe Research, LLC - MD of Equity Research & Senior Analyst [48]

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And then this one should be relatively quick, just in reference to the strategic partnership between CPChem and Qatar. Qatar has got a portfolio of other things that Chevron is probably a good candidate to participate in. Do you see that relationship deepening as you kind of advance on the chemical side throughout the Chevron organization? Or are you keeping that siloed into Chems?

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Pierre R. Breber, Chevron Corporation - VP & CFO [49]

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No. No. Look, we have a good relationship with Qatar Petroleum for sure and so does CPChem. And when the Qataris look at CPChem, they look at it as 3 companies, right, Chevron Phillips, Phillips 66 and ourselves. And so we have a good relationship with them. I will say that the trend -- the deals stand on their own. I mean the project in Qatar was bid out. U.S. Gulf Coast again, there's other alternatives that are considered. So each transaction stands on its own, but we're very proud that we have this platform with them. And whether that leads to other opportunities or not, I won't speculate, but we certainly have a good base to work off of.

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Operator [50]

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And our final question comes from the line of Pavel Molchanov from Raymond James.

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Pavel S. Molchanov, Raymond James & Associates, Inc., Research Division - Energy Analyst [51]

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You alluded to the gas takeaway issues in the Permian and that you were trying to avoid flaring as much as possible. But of course, your realized gas price was $0.60 in Q2. So I'm curious if it might get to a point where you have no practical choice but to either flare gas or shut in wells. And if that happens, which would you choose?

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James William Johnson, Chevron Corporation - EVP of Upstream [52]

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We don't flare. We are not flaring and we haven't flared. Our policy is that we find flow assurance, as I said, is our first priority so that we can move the gas, and we've been doing that. And we've got that flow assurance covered, so I don't see us being forced into the choices that you just presented. I do -- as I said earlier, we're going to be increasing the amount of export capacity out of the basin to try and achieve better realizations, and that's part of our overall strategy to maximize the returns that we can get from our investments in the Permian.

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Pavel S. Molchanov, Raymond James & Associates, Inc., Research Division - Energy Analyst [53]

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Okay. And then based on what I just asked but taking a much broader perspective, you're talking about reducing carbon emissions. Just about every other U.S. oil and gas producers talking about the same, when we listen to what's being said onstage at the debates, as I'm sure you saw this week, that point seems to be lost on the policy community. And I'm curious what you think the industry has not communicated that is -- or what the dynamic is that has led to this disconnect between what you're saying and what the policymakers seem to be believing.

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Pierre R. Breber, Chevron Corporation - VP & CFO [54]

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Well, Sam, that's a big last question on the call here. Look, I mean, it depends which policymakers, right? We're in the midst of an energy revolution renaissance here in the United States. For sure, wind and solar is a big part of that but what's going on in the Permian basin, what's happened in the Marcellus and Utica and growing natural gas production, growing crude oil production, exports to world markets and all the geopolitical implications and benefits of that, you can see our President talks a lot about that. At the same time, we share the concerns on climate change. We referred on the earnings call to a couple of investments that lower the carbon intensity of our operations. It was wind PPA in the Permian, so we are consumers of electricity, we are using renewable electricity there, it lowers the carbon intensity of our operations and the renewable natural gas, which is in California, which takes methane that otherwise would be vented to the atmosphere, processes it, puts it in the grid. Yet we have offtake agreements with trucking companies. It generates low carbon fuel standards under the California regulatory regime. It's modest capital. It earns an attractive return, so it's something that we believe is good for the environment and good for our shareholders. So we'll look to do more of that. We'll be very balanced but it's a big question and we'll be part of the conversation.

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Wayne Borduin, Chevron Corporation - General Manager of IR [55]

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I'd like to thank everyone for your time today. We do appreciate your interest in Chevron and everyone's participation on today's call. Jonathan, back to you.

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Operator [56]

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Ladies and gentlemen, this concludes Chevron's second quarter 2019 earnings conference call. You may now disconnect.