Good morning. My name is Jonathan and I will be your conference facilitator today. Welcome to Chevron's Second Quarter 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers' remarks, there will be a question-and-answer session and instructions will be given at that time. As a reminder this conference call is being recorded. I will now turn the conference over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead. Patricia E. Yarrington: All right. Good morning and 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 Frank Mount, General Manager of Investor Relations. 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. We ask that you review the cautionary statement shown here on slide two. I'll begin with a discussion of our second quarter 2017 financial results and Jay will then provide an update on our Upstream business prior to my concluding remarks. Turning now to slide three, an overview of our financial performance. The company's second quarter earnings were $1.5 billion or $0.77 per diluted share. Included in the quarter were impairments and other charges of $430 million as well as asset sale gains of $160 million. Excluding these special items and foreign exchange gains of $3 million, earnings for the quarter totaled $1.7 billion or $0.91 per share. A detailed reconciliation of special items and foreign exchange is included in the appendix to this presentation. Cash from operations for the quarter was $5 billion, reflecting high margin production growth and strong Downstream performance. Excluding working capital, cash flow from operations was $5.3 billion. At quarter-end, debt balances stood at approximately $43 billion, more than $3 billion lower than where we began the year. Our debt ratio is currently 22.7%. During the second quarter, we paid $2 billion in dividends. Earlier in the week we announced a dividend of $1.08 per share payable to stockholders of record as of August 2017. We currently yield 4.1%. Turning to slide four. Year-to-date, net cash generation after dividends was $1 billion including $200 million generated in the second quarter. This result is a solid down payment on our full year objective of being cash balanced at $50 Brent including asset sales. Cash flow from operations was $5 billion in the quarter, up $2.5 billion from the second quarter of 2016. Year-to-date, cash from operations has totaled $8.9 billion despite working capital consumption and adverse deferred tax impacts, each sized at approximately $1.2 billion, as well as affiliate earnings exceeding dividends by $1.4 billion. Cash capital spend for the quarter was $3.2 billion, approximately $1.3 billion less than the second quarter of 2016. We continued to reduce our spend by finishing our major capital projects under construction and driving capital efficiency gains throughout our investment queue. Second quarter asset sale proceeds were approximately $430 million primarily from the sale of proxies in the San Juan Basin in New Mexico and Colorado and some on the Gulf of Mexico shelf. Looking ahead to the second half of the year, we expect our cash outcomes to favorably reflect growing production and additional proceeds from asset sales. Despite some anticipated unevenness between third quarter and fourth quarter, for example related to the precise timing of sales transactions, pension contributions and affiliate dividends, we do fully expect to end the year in a cash balance position at current prices. Slide five compares current-quarter earnings with the same period last year. Second quarter 2017 results were $2.9 billion higher than second quarter 2016. Special items, primarily the absence of $2.4 billion in second quarter's 2016 net charges, partially offset by current period net charges of $270 million improved earnings by $2.1 billion between periods. An unfavorable movement in foreign exchange negatively impacted the earnings comparison by $276 million between periods. Upstream earnings, excluding special items and foreign exchange, increased nearly $950 million between periods. Increased volumes and higher realization as well as lower operating expenses were partially offset by increased DD&A associated with increased production. Downstream earnings excluding special items and foreign exchange increased nearly $380 million primarily driven by higher margins and a swing in timing effects. The variance in the Other segment was primarily due to unfavorable corporate tax items. As we've indicated previously, quarterly results in the Other segment are likely to be non-ratable and we continued to guide to $1.6 billion in annual net charges for this segment. I'll now pass it over to Jay.

Thank you, Pat. Slide six compares the change in Chevron's worldwide net oil equivalent production between the second quarter of 2017 and the second quarter of 2016. Second quarter 2017 production was 2.78 million barrels a day, an increase of 252,000 barrels a day or 10% over the second quarter of 2016. Major capital projects increased production by 265,000 barrels per day as we started and ramped up multiple projects including Gorgon, Angola LNG, Jack/St. Malo, Alder, Moho Nord, Mafumeira Sul and Bangka. Shale and tight production increased by 41,000 barrels a day primarily due to growth in the Midland and Delaware Basins in the Permian. The increases were partially offset by normal field declines and PFE effects. The other bar includes the loss of 38,000 barrels a day due to 2016 asset sales. Turning to slide seven. Year-to-date 2017 production is 2.73 million barrels a day. Up 5% from 2016 and within our guidance range of 4% to 9% growth excluding asset sales. Our expectation is that full year production will be well within our original guidance range. The ramp-up of production in the second quarter was strong, with June's monthly production at 2.85 million barrels per day. Looking ahead to the second half of the year, we expect to see reliable production from the assets that are currently onstream, further growth in the Permian and Wheatstone coming online. Some of these increases will be offset in the third quarter due to normal turnaround activity. Year-to-date there's been no impact on production from 2017 asset sales since the first transactions involving producing assets closed on June 30. Assets sold year-to-date and assets expected to be sold later this year have a combined daily production of around 175,000 barrels per day. The impact on full year 2017 production from asset sales is expected to be 25,000 to 75,000 barrels a day given the late in year timing for the sales. Turning to slide eight. We're seeing strong performance at Gorgon. All three trains have achieved or exceeded nameplate capacity and are operating smoothly. On a 100% basis, second quarter Gorgon production was 333,000 barrels of oil equivalent per day and is currently averaging around 430,000 barrels a day. We are currently producing around 3 billion cubic feet of gas a day from 14 wells. In the second quarter, domestic gas sales were approximately 125 million cubic feet per day and condensate production was around 14,000 barrels a day. We shipped 88 LNG cargoes so far this year. Looking forward, we're focused on achieving sustained operations and are analyzing plant performance to find opportunities to increase reliability and production. Additional fine tuning of the plant will maximize efficiency and we expect further debottlenecking opportunities to increase plant capacity. Turning to slide nine. We're on track at Wheatstone. The Wheatstone platform and pipeline are operational and supplying natural gas to the inlet of the onshore LNG plant. Early well performance is encouraging. We're in the process of starting up the plant and expect to commence cool-down shortly. LNG production is expected to follow next month. Train 2 construction is progressing well and we're on track to start up six to eight months after Train 1. Turning to slide 10. The future growth project, or FGP, is progressing well, and I'll highlight some milestones. Module fabrication is in progress in Korea and Kazakhstan, as is the fabrication of gas turbine generators in Italy. Dredging is essentially complete, and other activities required for the initiation of port operations are on track. Infrastructure work and site construction are progressing, and we're 75% complete with our piloting program. We have two drilling rigs in operation on multi-well pads, with a third rig expected in August. We're on track for first production in 2022. In addition to FGP, we're also making progress on a number of other major capital projects. At Hebron, offshore Canada, the platform's been installed on location and we expect first oil before year-end 2017. Projects expected to come online in 2018 include Clair Ridge in the North Sea, where offshore hookup and commissioning is well underway; the Stampede platform in the Gulf of Mexico, which was recently installed on location; the Big Foot platform, which is preparing for sail away around the end of this year; and Tahiti, where we're progressing the Vertical Expansion project. These projects are expected to add approximately 20,000 net barrels of new production in 2018 and 65,000 net barrels in 2019. Let's turn to slide 11. This is an updated map of the Permian Basin including Southeast New Mexico and West Texas. Our two million acres, 1.5 million of which are Midland and Delaware Basins, are depicted in blue. Outlined on the map are our Chevron-operated and non-operated development areas. Additionally, on the right side of the chart, we've included an updated version of our assessment of acreage valuation. Currently, we estimate that approximately 650,000 of our acres have a net value in excess of $50,000 an acre, and an additional 450,000 acres have a net value between $20,000 and $50,000 per acre. The balance of our acreage is a mix. Some is of lower quality, some is still under evaluation. Some lacks nearby infrastructure, and other requires further appraisal. As a reminder, these estimates are a snapshot that assumes simultaneous development at a $50 WTI price, burdened with all the development and production costs as we see them today. Let's turn to slide 12. This slide illustrates our returns-focused Permian development strategy. We're investing for value. We're applying technology and learning from others to drive capital efficiency. Let me provide a few examples of how we're using technology as a competitive advantage. We're using seismic data to detect variations in the properties of reservoirs to identify the optimal areas. We're then applying petrophysical modeling to evaluate the physical and chemical properties of rocks and their contained fluids, and we integrate geophysical information with production data to identify the most productive intervals, and to select well locations that offer the highest returns. We perform focused data analytic studies to optimize horizontal well placement and well spacing decisions. To do this, we have a comprehensive database of industry wells with production, completion, reservoir, and operational data. We also use this data to optimize our completions for proppant loading, cluster spacing, and liquid loading. During drilling operations, we use well and model data to make precise wellbore placement decisions to keep the well path within the most productive depth, often within a 10-foot interval. Our Integrated Operations Center provides support to our field personnel, who have access to real-time, operational data on mobile devices. As an example, real-time equipment information, such as excessive compressive vibration, can provide an early indication of a potential problem, allowing us to react before downtime occurs. But the real key in all this is effectively applying the technology to deliver better outcomes. We also learn by watching others. The graphs on the right side are one example of how we successfully combine our application of technology with our learning from others. The initial six months' recoveries per lateral foot are highlighted on the charts for wells in two different benches. In red are the actual results of Competitor A, who's a strong growth player in the basin, employing a strategy of speed to the development of the second Bone Spring and Avalon horizons in the Delaware Basin. They got there first, they drilled aggressively in each horizon, and they demonstrated production growth. However, their strategy of trial and error required them to spend significant capital. We've learned from their experience. The blue on the chart shows our actual results in the same horizons. For a similar number of wells, we're recovering more production per foot, and our cost per foot is lower than our competitor. Our strategy is working. We believe real value is created through capital efficiency and discipline, as well as strong, consistent execution. Let's go to slide 13. This chart illustrates three elements of financial performance. Our current financial metrics, the competitiveness of our current spend, and the attractiveness of returns for future investments. First, our unconventional Permian business, fully loaded with overhead cost, has positive after-tax earnings for the first half of 2017. We forecast earnings growth, even at flat prices in future periods, as a result of lower unit operating costs and depreciation rates. Our depreciation rates are expected to further decline as we cycle through prior invested capital and replace it with today's more efficient development costs. At actual 2017 oil, gas, and NGL prices, our year-to-date operating cash flow per barrel is approximately $20 and is accretive to Chevron's overall portfolio. Second, our unit development and operating costs are competitive and declining. The chart on the right compares our company operated with our non-operated JV costs. As you can see, cost reduction progress has been encouraging, and we are increasingly competitive. And third, the Permian is an attractive place to make future investments. We estimate, as noted in the box at the bottom, that our 2017 investments in the Permian, fully loaded with overhead, will generate greater than 30% returns at a $50 a barrel WTI price. Turning to slide 14. We're actively managing our Permian portfolio through acreage swaps, joint ventures, farm-outs and sales. This chart shows our historical and forecasted transaction activity in the Midland and Delaware Basins. We've identified between 150,000 and 200,000 acres in the Midland and Delaware Basins that we plan to transact to generate more immediate value. A recent transaction effectively more than tripled the value of our acreage simply by enabling longer laterals. Generally, the highest value transactions are swaps to core up acreage and enhance value through long laterals and other infrastructure efficiencies. In 2017, we've already closed seven deals and have grouped the remaining acreage into a number of packages that are actively being marketed. Slide 15. Production continues to track ahead of expectations as we continue to see efficiency gains and improved well performance. The chart on the left shows our second quarter, 2017 production of approximately 178,000 barrels a day, up about 44,000 barrels a day from the second quarter of 2016. In March, we gave you our forecasted Permian compounded annual growth rate of 20% to 35%. And we're currently near the top of that range. Today, we're operating 13 rigs and our plan is to continue to add rigs approximately every eight to ten weeks achieving 20 operated rigs by the end of 2018. In addition to our operated fleet, we expect to see our share of production from non-operated rigs. Our objective in the Permian is to generate value through capital and execution efficiency. We intend to be fully competitive on our unit development and production costs and realizations and use our superior royalty position to generate leading financial performance. With that, I'll turn it back over to Pat. Patricia E. Yarrington: All right. Turning now to slide 16. We continue to see lower capital spending as well as lower operating expense outlays despite significant production increases. C&E outlays have averaged $4.5 billion per quarter this year. That's over $1 billion lower than the average quarter in 2016 and over 50% lower than the average quarter in 2014. 2017 year-to-date total C&E is $8.9 billion. We are trending below our full year guidance and conservatively would expect full year C&E to come in around $19 billion. A positive pattern is also evidenced with operating expenses. The average quarter this year is $5.6 billion, $650 million lower than the average quarter in 2016 and 25% lower than the average quarter back in 2014. We expect to close out 2017 with operating expenses $1.5 billion to $2 billion lower than 2016. Second half costs will reflect growing production, the impact of asset sales and continued cost containment efforts throughout the enterprise. Now on slide 17, we're on target with our asset sales program. In fact, we're already in the $5 billion to $10 billion proceeds range that we established for the 2016 and 2017 years. With six of the eight quarters behind us, cumulative asset sale proceeds now total $5.3 billion; $2.5 billion so far this year and $2.8 billion last year. During the remainder of 2017, we have a number of transactions that are listed on the slide, where sales and purchase agreements are signed. We currently anticipate having at least $1 billion closing in the third quarter. Many of the remaining transactions are international in nature. These are often complex and subject to multiple regulatory agency oversight making timing uncertain. When all is said and done, we expect 2016 to 2017 sales proceeds to be solidly within the established guidance range. Now turning to slide 18. I'd like to close out my comments this morning on cash flow. We have an improvement trend underway with the first half of the year net cash positive after dividends by $1 billion. Production is up, in particular, high cash margin production is up and capital spend is down. We're getting more efficient and our cost structure is coming down. We're executing well on our asset sales and we're realizing good value in those transactions. We're also focused on improving returns. We expect this to happen as projects are completed and revenue is realized from growing production volumes. It'll happen as we pivot to shorter cycle time, high return investments. We showed you the opportunity we have in the Permian for high return investments. And returns will be aided by ongoing reductions in operating expenses and improvements in how we manage our capital projects. We're competitively positioned with a very strong portfolio. We're confident we're taking all the steps within our control to enhance our competitiveness longer term. So that concludes our prepared remarks. We're now ready to take your questions. Please keep in mind that we do have a full queue and so try to limit yourself to one question and one follow-up if necessary, and we'll certainly do our best to get all of your questions answered. So Jonathan, please open up the lines.

Thank you. Our first question comes from the line of Phil Gresh from JPMorgan. Your question, please. Philip M. Gresh: Hi. Good morning, Pat and Jay. Patricia E. Yarrington: (24:09) Philip M. Gresh: First question – morning. First question is Pat, you made some commentary in the very beginning here about the transitory factors adding up to about $3.8 billion of headwinds in the first half of the year. And if you go back to the Analyst Day, I think the number you gave for the full year at that time was $4 billion of headwinds that you were expecting. So it seems pretty front half, 1H loaded in terms of how that's played out. But just wondering if that's still a good number to be thinking about for the full year. Patricia E. Yarrington: Yeah, so good question. And I would say within our ability to forecast these things I think that is still very reasonable guidance that we gave you back in the SAM, certainly within that range. Philip M. Gresh: Got it. Okay. And the second question is just around the capital spending reduction. You noted $19 billion but conservatively so. As I think about that number, and what's imbedded in there for Gorgon and Wheatstone and CPChem, et cetera, it seems like it's $2 billion if not $3 billion of spend for some projects that'll be rolling off. So as I look ahead to 2018 and beyond, you had that $17 billion to $22 billion range that you had given. And so if we take the roll-off against the conservative $19 billion, it would seem like you're tracking pretty well in a $50 Brent world to be at or even maybe below that range longer term. But I'm sure there's some offset. So maybe you could just talk about how you see the puts and takes around that, and especially in light of your peer today saying they're seeing some upward inflationary pressure. Patricia E. Yarrington: Right. I think the guidance that we've given so far, we stand by. I did say $19 billion conservatively. We do anticipate additional activity in the Permian in the second half of the year. We mentioned about having the rig rates running up and so additional activity there. We do anticipate seeing more spending out of TCO as that FGP project ramps up and we also have additional spending in the Agbami infill drilling program. So there are some elements that we can see adding to outlays in the second half of the year. You're absolutely right. There will be offsets with Gorgon and Wheatstone trailing off certainly. And as I look forward to 2018, I do think that we have – we did say $17 billion to $22 billion, but we would be at the low end of that range if prices are hovering around $50. And I think that is still the best guidance that we can offer at this point. We as we normally do, we're in the middle of putting our business plans together and as we move through the second half of the year here, we will get much greater confirmation of that capital program really looks like.

Thanks, Phil. Philip M. Gresh: Thanks.

Thank you. Our next question comes from the line of Doug Leggate from Bank of America. Your question, please.

Thank you. Good morning, everybody.

Hey, Doug.

Jay, I'm going to take advantage of you being on the call. Clearly the Permian is running well ahead of your guidance. I wonder if you could speak to – I guess there's a number of facets to this. What's driving the beat? How did it impact your guidance? And from a broader portfolio standpoint, you've clearly got an enormous footprint that could really stand on itself in terms of sustaining your or offsetting your decline rate. So how does the (27:33) even think about capital allocation? Think about getting pregnant with a six-year, large scale development versus the flexibility this gives you in the broader portfolio. So strategically what role does this play going forward and what happens to the guidance?

So you're correct. We're seeing very good performance out of the Permian. Our drive on capital efficiency and good execution is really paying off for us. We also have seen good performance from our new basis of design. It's early yet but the results are encouraging. As we look at our overall portfolio and as we finish the period of heavy capital spend that we've been on, we have a pretty youthful portfolio that allows us a lot of opportunity to continue to build now on the infrastructure that's been installed and to capitalize on the Permian as a very large resource base for us. Our current plan that we've given you has the rigs running up to 20 company operated rigs by the end of next year. One thing I really like about the Permian is we're monitoring financial performance and financial returns virtually on a real-time basis. And as we continue to see performance out of Permian, we have the option to continue to expand that rig fleet or to hold the rig fleet depending on the performance that we're seeing. So we have seen a continued set of surprises to the upward over the years as we've shown you what the Permian can do for us and I would expect to see continued performance as we move forward. What's first and foremost, out of all this is that the Permian is one of our primary assets and it will attract the capital that's necessary. We are not holding back capital to the Permian and I don't think we'll need to. As these big capital programs roll off, the amount of discretionary capital allocation that we have has been increasing pretty significantly and that's going to continue over the next several years. So I'm very encouraged.

Thanks for the answer, Jay. My follow-up is for Pat. And, Pat, obviously the slide on Permian asset sales, just to be clear, I'm not entirely sure if you were indicating that those would be outright disposals or swaps because even at the low end of your valuation, the $20,000 an acre, that could be a $3.5 billion type number. Maybe you could just clarify that, and just a broad update on, is the $10 billion still a good number? And maybe just as a quick add-on, CapEx, combined, if we put the two together, it looks like free cash flow could be hitting a fairly substantial inflection point. Is your CapEx going to end coming in light as well? I'll leave it there. Thank you. Patricia E. Yarrington: Right. So just a point of clarification, on the Permian slide where we talked about opportunities for transaction, that is a combination of swaps, leasing and sale. And as another point of clarification, that activity was not anticipated in our $5 billion to $10 billion asset sale proceeds guidance range that we had given. So that would be on top of that. And we haven't really made a distinction. We haven't clarified publicly what the proportionality of swaps versus leases, versus sales is. As we said, the priority really is on the swaps because that's where really you can capture the greatest value by being able to extend the laterals. And we also said there's a number of sales packages that are also out in the marketplace. I do think we are – this is a – 2017 is a transition year. And I think we are very much at a point of inflection as we get through this year in terms of higher cash generation from the assets that are online, higher margin-accretive production, lower operating expenses as well as lower C&E outlays and greater flexibility around the capital program altogether. So I think it is very much a transition year and an inflection year.

Thanks. So just to be clear, Pat. Does the CapEx ramp up in the second half or are you trending well – you're obviously trending well under your guidance. Patricia E. Yarrington: Right. We're just saying we didn't think it was appropriate for people to take the first half of the year and double it and think that that's where we were going to close out the year because we do have certain elements where we see some outlays increasing.

Thanks very much.

Thank you. Our next question comes from the line of Evan Calio from Morgan Stanley. Your question please.

Hey, good morning, everybody and great results.

Hey.

A few questions for Jay if I can. There's a significant high-grading in the Permian inventory in one quarter where you've added additional 50,000 acres at the $50 value – $50 per acre – $50,000 per acre and 100,000 at the $20,000 to $50,000 range. Can you discuss what drove the change? Was that one factor or multiple? And is that inventory review process a quarterly ongoing process? Just trying to understand or get an understanding of the progression or potential future rate of change here.

Thank you, Evan. The actual update isn't a quarterly update. I think the last time we gave you that data was third quarter of last year. So it's over a period of time. But there are a number of factors that drive that increased valuation. Probably first and foremost is just the increasing efficiency we're continuing to see, both in terms of our recoveries and our cost development and operating cost per foot. So those are driving, to a large extent, the increased valuations that we're seeing, because they're based on our well performance. So, we would expect to see – we'll continue to update these periodically. We won't do it probably quarterly, because it's just too much effort focused on keeping track of all the acreage, but the general message is, our acreage position, we continue to work it hard. We continue to look for the next best development areas. We're using technology and the experience of others, and we are seeing continued improvement in those valuations. And then we're delivering those results.

Great. And my second question is on – you had great progressions on both DD&A and LOE in the newer slide indicate DD&A dropping 30% by 2020. I mean is that for incremental wells in 2020, or the entire Permian unconventional business by 2020? And on the LOE side, any color there on what's driving the difference? Whether that's be efficient infrastructure buildout or a shift to multi-well pad development?

It's a combination of things. On the capital side, the DD&A is really a mix of what we've already got in the portfolio, plus the new wells being added on a continuing basis. But because of the profile of production on these wells, we have a pretty rapid turnover of the capital employed through the depreciation schedule. And so, as we move forward in time, the wells that we're drilling today are more efficient than the wells we drilled last year and the year before, and we're just seeing this progression and decrease of DD&A consistent with the decrease in our unit development costs. From a lease-operating standpoint, we have looked at our actual organization structures. We looked at how we're organized. We look at the efficiency of our factory model. We're using the Integrated Operation Center to keep our production reliability as high as possible. And, as we build scale, we don't have to increase the organization in direct proportion to the scale, so we start getting more and more economies of scale in our operations. So all those together, with the advances in the technology that we're really applying on a very real-time basis, we see this drive to continue to become more efficient.

Thank you, Evan.

Maybe just a follow-up to that, on the multi-well pad development, just where are you today versus where you'll be in 2020, maybe in terms of percentage of activity? Is there a big change or improvement there?

Virtually all of our development activity now, all 13 rigs, are running in multi-well pad mode and factory mode. The only wells you'll see in the future in the Permian that won't be that basis might be some expiration wells that we do to stay ahead of our development drilling. But that would be a very small percentage of the wells.

Okay. Thank you. Impressive.

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

Good morning, guys.

Morning. Patricia E. Yarrington: Morning.

Jay, just, this may be a little bit theoretical, but let's assume that by year 2020, you are running at 20 rigs and that by then, that you probably already reach at the 450,000 barrel per day or so. At that point, what kind of oil price and gas price you need in order for that to be as a self-sustained cash flow breakeven? Any kind of rough number? And also then, as you're looking at Permian, clearly the resource is impressive, but I got to believe that still have a sweet spot in terms of the resource and the peak production ratio. Any kind of help you can give us, that – I know that your result will ultimately be multiple over time of the $9.3 billion (37:22) that you are citing. But if we're looking at a result at a certain level, what will be a reasonable RP ratio to achieve the optimum capital efficiency from you guys' standpoint in the Permian?

Okay, so from the Permian in terms of breakeven position, we gave you guidance in the SAM meeting back in March that if we – we're growing our rig fleet to 20 rigs, is our intention by the end of 2018, and then we have options at that point. But if we should decide to hold at 20 rigs and just continue to run those 20 rigs, under the current conditions with the current performance, we would expect to be cash-flow positive overall. But what's really important here is, we're looking at the returns each and every well and development area give us as we're drilling those areas and as we make the decision on the next area, and those are all very positive. How much we choose to invest into the Permian on an ongoing basis, or on an expansion basis, is really part of our portfolio allocation of, where do we get the best returns. So we're not really worried about whether the Permian in and of itself is returning positive net cash flow, as long as the underlying wells in development are all strongly positive on their financial performance. So, our view is that we're going to get to 20 rigs. We're going to understand our performance and the conditions in the Permian, and we have the option to continue to increase rigs beyond that point should we choose, and should that be an optimal place for us to continue to invest. Terms of the sweet spot, it's really – we're working on the best spots today. But what's important is, as we continue to drive more efficiencies into the business, as we continue to advance the technologies that I talked about and the application of those, what we're finding is that we're continuing to drive down our unit development cost such that we can move into areas that might not have been so attractive before are becoming more and more attractive today. And also, as the infrastructure buildout continues, we are able then to bring in some of these lower value areas now become more and more attractive, because they don't have to underpin infrastructure. We can just use what's already been built out in the past. So overall, we see a very good resource picture. We'll use exploration to stay ahead of the game, and that's really our focus.

So you guys not really looking at, say, an RP pressure ratio, say, 30 or 40 or 25 will be the optimum. So that's not a consideration. Or that's at least not the way how you look at – how much is the overall typical program that you may end up to be.

No. We're really looking at the financial performance of the developments that are in front of us and the results that we're achieving out of the investments we've made and comparing that with the opportunities that we have across our portfolio.

Thank you.

Thanks, Paul.

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

Yes. Thanks very much and hi, everyone. Wanted to ask couple of questions about Gorgon if I could please. First of all, you're currently running essentially at or above nameplate capacity, but you did mention specific items like building reliability and fine tuning the process on the slide. Just wondering if this running at nameplate capacity is something that we can look forward to for the rest of the year or if you will still have some shake-out maintenance as we look towards year-end.

Thank you. Gorgon's running really well. And particularly as we saw Train 2 and then Train 3 start up, Train 3 start-up was a beautiful thing. We're really pleased with it; it looked great. And so now all three trains are stable at or above nameplate. And that was our goal. When we look at the reliability, it's how many trips or how many times does the plant go offline, and obviously we want to eliminate those so that the plants run reliably day in and day out. And then on top of that, we start getting the plant performance data so we can look at what are the bottlenecks that we can correct that'll allow us to then increase the ultimate capacity of the plant. There may be some short pit stops that we'll take from time to time that are going to be economically driven and planned, if we find that some of those opportunities require us to take the plan offline to make that adjustment. There are other things that we'll continue to make adjustments while they're online and running. So on balance, I expect to see us running at these levels throughout the year. There may be times we'll take short pit stops but those would be planned in advance and they'll be driven by economics.

Great. And then if I could just do a follow-up on Wheatstone actually. Sounds like start-up is pretty imminent so I assume there's really nothing on a critical path for Train 1 and that you're just in commissioning process. Just wondering if there's anything still on the critical path for Train 2 to achieve that six- to eight-month start-up or if it's very similar to Train 1 where you just really are now into more of a commissioning phase.

So on Wheatstone Train 1, you're correct, we are in the final stages of commissioning, and in fact, we are now into the true start-up phase. So we expect to see cool-down occurring here shortly. There's really no construction going on at all in Train 1 and commissioning is largely complete. In Train 2, we still are in bulk construction mode. But we expect to see that winding down in the fourth quarter and at this point in time, really don't see any particular on obstacles or challenges in our path to getting Train 2 complete and getting into the commissioning and start-up. There's always the issues of moving from bulk construction into the sequence of commissioning but we've got teams all over that. And just as we saw at Gorgon as we move from Trains 1, 2 and 3, we expect to see continuing efficiency both in the final construction and in that transition to commissioning building on the experience of the first train.

Thanks Jason.

Great. Thanks.

Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question, please.

Good morning, team.

Hi, Neil. Patricia E. Yarrington: Morning.

First question I had was just around base decline rates. Can you talk a little bit about what you're seeing in your portfolio on a base decline rate basis and then also any thoughts in terms of how you see that evolving going forward?

Sure. Base declines have actually been quite good. The shift in strategy as we've moved from the heavy new greenfield investments into a focus on leveraging maximum value from our installed infrastructure base on install base business has been paying big dividends. So the infield drilling programs, the focus on reliability, the workover programs have been really sustaining our production, I think better than we would have expected given the amount of capital and costs that we've pulled out of the system. We have the advantage of a portfolio that has a lot of young assets. So as we start installing things like – or start taking advantage of things like Jack/St. Malo and the other projects that I mentioned that are coming online this year and next year as well as Gorgon and Wheatstone, we are seeing a very young portfolio. Lots of continued opportunities for infield drilling and, really, brownfield expansions. And there's a lot of value in that, even at today's prices.

I appreciate the comments, Jay. And the follow-up is just on some of the areas of disrupted production or areas where there's been a lot of focus on geopolitical issues. And just wanted your comments on three areas in particular, recognizing there could be some limitations in terms of the comments here. One would be Partitioned Zone, two would be Venezuela, and three would be Nigeria. Any updates from Chevron's perspective would be helpful.

Sure. In the Partitioned Zone, the stopping of production continues. There's been no restart activity. There are continuing negotiations and dialogue between the two governments. We continue to advocate for a return to the status quo, get the field back in production while the longer-term issues are addressed. But at this point in time, there has not been any movement towards a restart. Somewhat perplexing to us, but we'll continue to play the role of facilitator and see if we can't get the fields restarted. I think it's in everyone's best interest. In terms of Venezuela, we have continued to be operational. We do not have major impacts on our operations at this point in time, and it's just a situation we continue to monitor. Our priority is on just maintaining safe operations, and protecting our people and assets. And in Nigeria, we continue to see good performance coming out of Nigeria. There are disruptions from time to time, but it has not had, I would consider, a material adverse effect.

Thanks, Jay. Congrats on the good quarter.

(46:54).

Thank you. Our next question comes from the line of Blake Fernandez from Scotia Howard Weil. Your question, please.

Folks, good morning. I had two questions. One for Pat and one for Jay, please. Pat, on the CapEx, obviously, it looks like you're lowering the guidance from 19.8 billion down to $19 billion. And I'm just trying to get a sense of how you see that impacting the cash flow breakeven that you've articulated around $50 a barrel. Presumably, there's some downward pressure there, but any color on that? Patricia E. Yarrington: Well, I mean, I think that would be a normal outcome, an intuitive sort of outcome. Obviously, if we have a little bit less spending, that's where you would fall out. I mean, I think the larger flywheel for us here may be exactly the timing of asset sales during the second half of the year. As I mentioned, many of those are international transactions and getting a bead on exactly when they will close, whether they will close in fourth quarter or perhaps move into first quarter, there's still some uncertainty around those.

Okay. Second question on the Permian, Jay. Based on the feedback we're hearing from some of the refiners, it sounds like we're getting relatively close to exhausting the light sweet processing capacity along the Gulf Coast, and we're starting to see some batching, which kind of indicates we're preparing for some oil exports. I didn't know how that would impact your growth rates and is there an opportunity? Are you planning to participate in exports? Or is that really something you're just going let the midstream players kind of handle on their own? Thanks.

Well, look, when we've talked before about how we look at the Permian, we look at the whole value chain. So everything from our development, operating cost on the front end to the realizations we get on the back end. And we've done a lot of good work to open up multiple pathways to get our products to market so that we can take advantage of the different variations in the markets. So we have been working to stay ahead of our build out curve. At this point, we don't see any constrictions on our ability to grow, as we've discussed, in the Permian. And this is an area that we'll continue to stay focused on and seek the best realizations as we move forward. Thank you.

Thanks, Blake.

Okay.

Thank you. Our next question comes from the line of Doug Terreson from Evercore ISI. Your question, please?

Hi, everybody. Patricia E. Yarrington: Hi.

Hello.

Hey, Doug.

Jay, I had just a clarification question for you. A few minutes ago you talked about 30% returns in the Permian. And when you say 30% returns, are you talking about fully-burdened returns? Or conventional return on capital type definition? Or drilling decision returns? Or what are we talking about there?

No, when we're talking about 30% returns, we're basing that on a $50 WTI price, $2.50 (49:45) gas, $25 NGLs. And what we are doing is looking at our all-in costs, so we're not cherry picking just development costs or anything like that. But this is what we really expect to see, full returns, fully burdened.

Okay. So, Jay, it includes facilities and land costs and all the other things that some people leave out. Is that correct?

Yes.

Okay. Just wanted to be sure. And then also had a question for Pat. Pat, the performance in your Downstream business has improved significantly. Your returns are not only above the cost of capital, but they're as close to that of some of your peers as they've been in a decade or so from what I can tell. I mean, they've gotten to be really good. So when you consider this increase in absolute and relative value of that business, I wanted to see if we could get your updated perspective how you think about that business, meaning besides my point about rising relative and absolute value, what are some of the other factors that you consider when you think about whether or not the R&M and chemicals business should be a core part of the portfolio, longer term? Patricia E. Yarrington: Well, we do completely believe the R&M should be a core part of our portfolio long-term. We like our integrated model, not only for the hedge that it makes in terms offsetting commodity price impacts on the Upstream side, but we use it, importantly, in terms of kind of knowledge transfer between Downstream and Upstream for the efficient operations of plants and facilities. So it's a core part of our business. I think we have been very successful over the last decade really.

Yeah. Patricia E. Yarrington: In improving the returns on Downstream, through some of the transactions and the fine tuning of the portfolio, optimizing of the portfolio that we've done. Plus significant effort around cost management and cost containment. It's a growth opportunity for us if you're including the chemical sector in here as well. So I think it's a key part of our portfolio going forward and we would look to expand and evaluate its investment opportunities for future growth projects. Just along the way we would look at other opportunities. It would compete for capital for future investments as well, in the chemical sector in particular.

Okay. No it's been real successful.

Thanks, Doug.

Just real success story for you guys. Thanks a lot. Patricia E. Yarrington: Absolutely.

Yep.

Thanks.

Thank you. Our next question comes from the line of Anish Kapadia from TPH. Your question please?

Hi. First question was going back to your Permian position. So you talked about the – gave a bit more detail about the asset of swaps and sales going forward. But I think one the big stores of value that you have that you could potentially bring forward is the value of your royalty position. If you look at where some of the pure play lifted royalty names are trading in North America. So I'm just wondering, have you thought about maybe selling or monetizing some of your royalty positions in the current, very low interest rate environment? Patricia E. Yarrington: Yeah, Anish, so obviously, this is a topical area there. We're certainly very much aware of the opportunity, and we have evaluated it. But I think the best I can say at this point is, we don't have any plans for anything like this at this point in time.

Okay. Thank you. And then I had a follow-up. We used to (53:26) get a little bit of an update on your North American activity onshore outside of the Permian. And just thinking about your updated plans in terms of the Duvernay in California, what's the outlook there? And also the Marcellus and, combined with that, is there any thoughts of maybe hedging in the gas price to lock in returns, to be able to put rigs back to work?

So as we look at the different assets that we have across North America, one of the things that we are very active on is sharing the information and best practices that are being developed in each area with the other unconventional areas. So we've seen cost, development cost, come down in the Duvernay. We've been largely involved in an appraisal program and a land tenure strategy. But now, with the results that we're seeing, we have a good-sized resource there and we are evaluating, as Pat mentioned earlier, our business plan at the current time on just what we want to do there, but it's very encouraging. We'll give you more details on each of those in the SAM meeting next year. In terms of the Marcellus, we've also seen our cost structure come down significantly, as well as our drilling efficiency improve. So that also has some promise, especially with the recovery in gas price, as to whether or not we hedge. That's something that we'll evaluate as part of putting together our strategy going forward. Another key area for us is the San Joaquin Valley, where we continue to run a very efficient operation in that area. The strategy there has been a drill-to-fill strategy, so we're really utilizing the existing installed infrastructure base, and we see very good returns coming out of our San Joaquin area. Builds on our heavy oil expertise, and provides a very good return us to. So North America overall looks very strong in the onshore areas. Thank you.

Thanks, Anish.

Thank you. Our next question comes from the line of Ryan Todd from Deutsche Bank. Your question please?

Hey, everybody. Maybe a quick follow-up on the Delaware Basin. One of your competitors today talked about drilling laterals up to 15,000 to 20,000 feet in the Delaware. Can you talk about your general thoughts on lateral length, where you're trending right now in terms of where you've been pushing lateral length? And what you think about the ultimate extent of those efforts going forward?

Yeah. Thanks very much. It's a good question. And there are a lot of different things being tried in the Permian on a real-time basis. And, as I mentioned earlier, our strategy, we've been criticized for it maybe a little bit in the past, but it's proving to be a very good strategy, is to let some of the others do some of the experimentation and then we watch and see what performs well, and then build that into our basis of design. Right now, our focus is on 7500 to 10,000-foot laterals. We'll wait and see if those really turn out. But as you get longer and longer laterals, it gets very difficult to get good returns throughout the length of the well bore. So, our focus is on getting the ultimate return for the capital invested. And that's really what's going to drive us more than any other single parameter.

Thanks. That's helpful. And then, maybe a follow-up on some of the earlier comments and questions on free cash flow. It does look like there's – we're already seeing some amount of free cash flow, probably a greater inflection as we look into 2018. You've paid down a decent amount of debt this year. How should we think about your prioritizations for use of free cash as we go forward in terms of incremental capital, debt paydown, resumption of a share buyback, et cetera? Patricia E. Yarrington: Yeah. I mean, Ryan, I'm going to go back and just reiterate our priorities that we've had. Dividend increase would be the first one, as soon as we can see our way clear to having a sustainable increase, meaning supported by cash flow and earnings. After that, it becomes the capital program, and where do we have incremental opportunity for investments there. You've heard about how strong an opportunity queue we've got sitting there in the Permian. We do want to keep a strong balance sheet. I think that's important, and it's particularly important being in the commodity cycle. And we've learned in the past that, when oil prices are high, it's good to shore up a little bit, and when oil prices are low, you use your balance sheet. And so we want to make sure that we're prepared through the thick and thin of the cycle. I do see share repurchases as the last use of cash, and I think those, at this point in time, with the view we have of commodity prices, et cetera, it's fairly remote for us.

Thanks, Ryan.

Good. Thanks.

Thank you. Our next question comes from the line of Roger Read from Wells Fargo. Your question, please? Roger D. Read: Yeah. Thanks, good morning.

Morning, Roger.

Morning. Roger D. Read: Follow-up on the Permian. 20 rigs by the end of 2018 from 13 today, it seems, whether it's the Permian or other shales, comments from developers have been that you keep learning more the breakeven number of rigs to keep production flat, or to grow it at a higher rate, keeps declining, as well as breakeven prices. I was wondering, as you think about the 20 rigs, is that based on static knowledge today, or is that incorporating the idea of improving efficiencies, and that's part of how we should think about the range of 20% to 35% on the CAGR?

Yeah. So the 20 is really based on – we want to be bringing rigs in a steady, orderly fashion so that we can continue to increase the organizational capability around those rigs and make sure we're continuing to use each incremental rig very efficiently. So if you think about all the work that has to go on from establishing the land position, coring up, getting ready for the design of the development area, all through the procurement and then into the offtake afterwards, we want to make sure that we're keeping the organization and the factory healthy around each incremental rig. What we are finding is that, in addition to increasing the rigs, the amount of production each rig is generating is higher, and growing as the efficiencies improve. So part of it is increasing the rigs, but part of it is also getting more out of each and every rig that we apply. And the fleet is becoming more productive. So we're balancing all that. And as I say, because we get data on virtually a real-time basis, we're able to make decisions now and look forward and decide, do we want to continue that pathway higher or do we want to go ahead and hold at any number of particular rigs that we feel would deliver the efficiency? Capital's not the issue. It's really making sure that we're delivering the financial performance that we're looking for. Roger D. Read: Okay. I appreciate it. Patricia E. Yarrington: Hey. I think the... Roger D. Read: Could I ask you just one thing, Pat, real quick on the dividend? It's been modest growth the last couple years. And the earlier question about free cash flow allocation, just at what point do you think you'll have the confidence in say a flat $50 oil world to maybe move the dividend a little more aggressively? Patricia E. Yarrington: It's a Board call here and I think it's not just what current prices are but it's the outlook for future prices as well because it gets into a sustainable support level for the dividend that's important. So it's a combination of what's the commodity price outlook that we have, how are we seeing our capital program, how are we seeing cost structure, and as I said, we made tremendous strides over the last couple of years to get into a much more cash balanced position. And we're cognizant of our 29-year history and would love to be able to take it to a 30-year history but we're only going to do that when we have full confidence that it's a sustainable increase. Roger D. Read: Thanks. I'll bet on 30 though. Patricia E. Yarrington: Okay. Okay. All right. I think we've got time for one more question.

Certainly. Our final question comes from the line of Brendan Warn from BMO Capital Markets. Your question, please?

Yeah. Thanks. I'll keep this short considering it's the last one. Just two-part question. I guess relating to Tengiz, you gave a bit of an update. Can you talk about the capital commitment to Tengiz? Obviously, it seems money buys a whole lot more today than it did 12 months ago and you're carrying quite a high contingency on that project. Can you just flag where that we should be seeing the CapEx coming for Tengiz? And then I've got a follow-up question, please.

Look, it's early days in terms of Tengiz. We carry good contingency and we make sure that when we run our economics, we really take into account what we think it could cost, not just what we want it to cost. We're taking all the steps we talked about in previous calls in terms of making sure the design assurance, our contracting strategies, our execution and our quality management are all in place. It's got our full and complete attention. So we're really working hard to manage this project. We're off to a good start. Projects of this nature are so large, there are always going be challenges and our goal is to address those challenges and minimize the use of contingency. But it's too early to give any other guidance than what we've given so far.

Okay. My follow-up to Pat, and I guess it's in regards to the abilities of the Permian to deliver. That $17 billion to $22 billion and more focusing on the $17 billion, that soft floor, and I guess in around $50 a barrel Brent. I mean, how should we think about that $17 billion? Where could it potentially be considering what you're getting out of your short cycle investments now? Patricia E. Yarrington: Yeah, I think the best I can do is just say we're in the midst of our business planning cycle here and we'll come out with our C&E plan for the 2018 year around December. Typically, that's when we would do it after we've had a chance to go through the full business planning cycle. I don't have any different guidance other than to say what we've said. I mean, we are getting, for every dollar spent, Jay just went through it, for every dollar that we're spending we're getting much better response out of the Permian. So the capital efficiency per dollar is really increasing and that will all be taken into account as we're doing our revised planning. It is important for us to be cash balanced, this year with asset sales and next year without asset sales. And so those are primary objectives that we will be trying to balance as we put this next year's plan together. Patricia E. Yarrington: Okay. Thanks very much. I'd like to thank everybody for the time on the call today. We certainly appreciate your interest in Chevron, and we appreciate everybody's questions on the call and participation. Thank you. Jonathan, back to you.

Ladies and gentlemen, this concludes Chevron's second quarter 2017 earnings conference call. You may now disconnect. ,