Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's Second Quarter 2015 Earnings Conference Call. At this time all participants are in a listen-only mode. After the speakers' remarks, there will be a question-and-answer session and instructions will be given at that time. As a reminder, this conference call is being recorded. I will now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead. Patricia E. Yarrington: All right. 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 on slide two. Slide three provides an overview of our financial performance. The company's second quarter earnings were $571 million, or $0.30 per diluted share. Included in the quarter were impairments of $1.96 billion and other charges of approximately $670 million relating to project suspensions and adverse tax effects, all of which were non-cash charges stemming from a downward revision in the company's longer-term crude oil price outlook. Excluding these special items, as well as asset-sale gains and foreign-exchange effects, earnings were $1.8 billion, or $0.97 per diluted share, approximately $400 million higher than first quarter on that same basis. A detailed reconciliation of the special items is included in the appendix to this presentation. Cash from operations was $7.2 billion, an improvement of $4.9 billion from the prior quarter. Our debt ratio at quarter end was 17%. During the second quarter, we paid $2 billion in dividends. Earlier in the week, we announced a dividend of $1.07 per share payable to shareholders of record as of August 19. We're currently yielding 4.6%. Turning to slide four, cash generated from operations was $7.2 billion during the second quarter and $9.5 billion year-to-date. Upstream cash generation was stronger than in the first quarter, the result of higher crude prices. We also benefited from strong cash generation from our downstream and chemicals business. Temporary working capital effects reduced year-to-date cash flow by approximately $2 billion. We expect this impact to reverse in future quarters. Proceeds from asset sales for the quarter totaled approximately $3.9 billion, the vast majority of which related to our sale in the interest in Caltex, Australia. We are well ahead of pace on our four-year asset divestment program. In the past 18 months, we have recognized asset sale proceeds of nearly $11 billion, compared to our stated $15 billion goal over the 2014 to 2017 time period. Cash capital expenditures were $7.6 million for the quarter, essentially flat with the first quarter. Year-to-date cash capital expenditures were $15.2 billion, down $2.2 billion or 13% compared with the same period in 2014. At quarter end, our cash and cash equivalents were approximately $12.2 billion and our net debt position was $19.4 billion. Slide five compares current quarter earnings with the same period last year. Second quarter 2015 earnings were $5.1 billion lower than second quarter 2014 results. Upstream earnings decreased to $7.5 billion between quarters. The impairments and other charges I noted previously accounted for $2.6 billion of this decline. Significantly lower crude realizations and the absence of second quarter 2014 asset sale gains make up the remaining variance between periods. Downstream results increased by $2.2 billion, primarily driven by higher worldwide margins and gains from asset sales, principally the sale of our interest in Caltex Australia. Operationally, the second quarter continued a positive quarterly pattern of high reliability, strong margins and good cost management. The variance in the other segment was primarily favorable corporate tax items. Turning now to slide six, I'll compare results for the second quarter 2015 with the first quarter of 2015. Second quarter earnings were $2 billion lower than first quarter results. Upstream earnings decreased by $3.8 billion, primarily reflecting the charges I previously discussed. Unfavorable foreign exchange effects and the absence of first quarter asset sale gains and the positive UK tax adjustment were also large variances between periods. Downstream earnings increased $1.5 billion as gains on asset sales were partially offset by an unfavorable foreign exchange swing between the quarters. Operationally, the quarters were fairly comparable. The variance in the other segment was primarily favorable corporate tax items, partially offset by higher corporate charges, including severance accruals. Frank will now take us through the comparisons by segment.

Thanks, Pat. Turning to slide seven, our U.S. upstream earnings for the second quarter were $578 million lower than the first quarter's results. Asset impairments and project suspensions across multiple assets, primarily as Pat indicated, from a reduced price outlook, decreased earnings by $630 million. Higher realizations, consistent with an increase in domestic crude prices, increased earnings by $190 million. Exploration expenses, mainly associated with the deepwater Gulf of Mexico, decreased earnings by $70 million. The other bar reflects higher production, which was more than offset by higher DD&A rates. Turning to slide eight, international upstream earnings were $3.2 billion lower than last quarter's results. Asset impairments, primarily at Papa Terra in Brazil, project suspensions and adverse tax effects from price changes previously discussed reduced earnings by about $1.9 billion. An unfavorable swing in foreign currency effects decreased earnings between periods by approximately $670 million. The absence of last quarter's gains on asset sales and the deferred tax benefit from the UK tax change decreased earnings by $660 million. Increased exploration expenses resulted in lower earnings of $170 million. Higher realizations increased earnings by $395 million, consistent with the increase in Brent prices between the quarters. The other bar primarily consists of an unfavorable ruling on a decade-old tax issue and severance accruals booked in the second quarter. Slide nine summarizes the change in Chevron's worldwide net oil equivalent production between the second quarter of 2015 and the first quarter of 2015. Net production decreased by 85,000 barrels per day between quarters. Major capital project ramp ups, primarily at Jack/St. Malo in the Gulf of Mexico and from the expansion of the Bibiyana field in Bangladesh increased production by 22,000 barrels per day. Growth from our shale and tight assets, primarily in the Permian, contributed 11,000 barrels per day. As we foreshadowed in our first quarter earnings call, production in the Partitioned Zone was shut down at the end of May based on the inability to secure work and equipment permits. The shutdown decreased production in the second quarter by 38,000 barrels per day. We're still not producing in the Partitioned Zone, and we have no updated guidance as to when production is likely to restart. Planned and unplanned downtime reduced production by 34,000 barrels per day between periods, primarily in Canada and in Australia. Price and cost recovery effects decreased production by 23,000 barrels per day between quarters as high crude prices and reduced spending decreased volumes associated with production share and variable royalty contracts. The remaining variance in the base business and other bar primarily reflects natural field declines and weather-related production limitations at Tengiz. Slide 10 compares the change in Chevron's worldwide net oil equivalent production between the second quarter of 2015 and the second quarter of 2014. Net production increased by 51,000 barrels per day between quarters. Major capital projects increased production by 71,000 barrels per day due to production ramp-ups, primarily in the deepwater Gulf of Mexico and Bangladesh. Shale and tight production increased by 46,000 barrels per day due to the growth in the Midland and Delaware Basins in the Permian, the Marcellus and the Vaca Muerta shale in Argentina. Price and cost recovery effects increased production by 61,000 barrels per day due to the roughly 45% drop in crude prices between periods. The shutting of operations in the Partitioned Zone decreased production by 45,000 barrels per day. Asset sales resulted in lost production of 33,000 barrels per day, principally driven by the divestment of our assets in Chad and the Netherlands. The decrease of 49,000 barrels per day in the base business and other bar primarily reflects normal field declines and the impact of higher external constraints, partially offset by a favorable variance from less planned turnaround activity. Our base business continues to perform well with a managed decline rate within our existing guidance range. Year-to-date net oil equivalent production was 2.638 million barrels per day and within our 0% to 3% guidance for 2015 growth. Looking forward to the remainder of the year, the third quarter is expected to be a comparatively heavy turnaround period, and we believe the full year production guidance remains appropriate. Turning to slide 11, U.S. downstream results increased $25 million between quarters. Tight product supply, primarily on the West Coast, boosted refining and marketing margins and increased earnings by $165 million between quarters. Higher operating expenses decreased earnings by $185 million, reflecting planned maintenance and turnaround activities at the El Segundo Refinery and commitments related to the Richmond Refinery modernization project. The variance in the other segment primarily reflects stronger results in our chemicals business. Turning to slide 12, international downstream earnings improved by $1.5 billion between quarters. Gains on asset sales, primarily related to the sale of the company's interest in Caltex Australia, increased earnings by $1.7 billion. Lower refining and marketing margins decreased earnings by $120 million between quarters as product price increases, including the negative price lag effects on naphtha and jet fuel failed to keep pace with rising crude costs. An unfavorable swing in the foreign currency effects lowered earnings by approximately $155 million. The variance in the other bar reflects multiple unrelated items. Jay will now provide an update on our upstream operations. Jay?

Thanks, Frank. Turning to slide 13, I'm going to discuss our Upstream business, where we continue to make good progress in delivering the projects that are driving our growth in volume, in value and in cash. Gorgon is a critical part of that growth, and we continue to work towards the first LNG cargo. As you can see from the photo, plant construction has advanced. We're nearing mechanical completion of the first train with over 60% of critical subsystems handed over to commissioning. We've posted new pictures today and I encourage you to look at them on our investor website and chevron.com. Turning to slide 14, the upstream work scope for initial production from the Jansz field is largely complete with the control systems now active. We've established communications from the central control room on Barrow Island to the subsea wells, which enables us to conduct commissioning activity on the upstream and pipeline systems. Final testing is underway for the subsea infrastructure and controls. At the plant, all LNG and condensate tanks required for first LNG are ready and commissioning of completed process systems is underway. Currently the critical path is through the refrigerant compressors and the hydrate prevention system for the subsea wells. We expect to perform the first commissioning run of the compressors and testing of the hydrate prevention system in late September. Once we're satisfied with the operation of these systems we'll be ready to introduce gas from the Jansz wells into the upstream pipeline and begin the startup of Train 1, which we currently expect late this year. The schedule is dependent on managing commissioning and startup risks, including equipment malfunctions, possible labor and weather disruptions, as well as other unforeseen issues. Our focus is on a safe and incident-free startup that leads to reliable long-term operations. We're working to achieve the first LNG cargo by year-end. However, given these risks, it's likely to occur in early 2016. Now let's talk about Wheatstone, moving to slide 15. Wheatstone is now over 65% complete. On the upstream side of the project, we successfully completed the float-over and installation of the offshore platform in April. Hook up and commissioning is on plan with all subsea structures now installed. The flow line installation is underway and the development drilling program ongoing. All nine wells were previously drilled to the top of the reservoir and we're now drilling the reservoir sections of each well and running the completions. At the plant site, 11 of 24 major process modules for Train 1 have been delivered. All refrigeration compressors and gas turbine generators have been installed and the domestic gas pipeline has been completed. The focus of activity at the plant has shifted from civil works to mechanical, electrical and instrumentation systems. The work on site is going very well. Our biggest challenge has been the delays in module delivery from a fabrication yard, which is putting pressure on the schedule. To address the delays, we've expanded to an additional yard and provided increased oversight in the yards. We've seen positive results from these actions and are not anticipating any further delays in the module delivery schedule. Additionally, we've increased bed capacity at the plant site and are updating our work plans to mitigate the impact to schedule. Our objective remains first LNG by year-end 2016, and we'll continue to provide updates on our progress over the next 18 months. Turning to slide 16. Performance at the Jack/St. Malo lower tertiary development continues to exceed our plan. The sixth well was brought online ahead of schedule and total production has ramped up to around 80,000 barrels per day. The development drilling program continues and we're seeing some get improvements in cycle time, costs, and stimulation effectiveness with the most recent completion 20% better on cost and schedule than previous wells. Work to install the Big Foot Tension Leg Platform was suspended in early June when nine of the 16 tendons lost buoyancy. There were no environmental impacts or injuries, and we are investigating the root cause of the incident. We have secured the site, including successful recovery of the seven remaining tendons. The tension leg platform was undamaged and is being moved to a safe harbor location. Site surveys and equipment inspections are in progress to determine whether the installed piles and recovered tendons can be reused and what equipment will require replacement in order to complete the project. At this point, we are not expecting any Big Foot production in 2016 or 2017, which is a reduction from our original plan of 10,000 net barrels per day in 2016 and 22,000 net barrels per day in 2017. As we complete the investigation and update our plan, we will advise you accordingly. Appraisal drilling is ongoing at the Anchor discovery and in the Northwest Keathley Canyon area, now named Tigris. Tigris has the potential to offer a multi-field, hub development of the Guadalupe, Gila and Tiber discoveries with the potential addition of the Gibson exploration prospect, which we plan to drill around the end of this year. Appraisal drilling is underway at Guadalupe and recent results from deepening the Gila discovery well are encouraging with further appraisal planned. We continue to progress our opportunity cue in the deepwater and in the second quarter made another lower tertiary discovery at the Sicily prospect in Keathley Canyon Block 814. We're encouraged by the results of the discovery well and follow-up appraisal work is planned. Turning to slide 17. As we communicated in March, our Permian position is strong. We have a large, high-quality acreage position with advantage royalty, which we are cost-effectively developing. We remain on track to drill 325 wells this year and have expanded to multiple factory mode, horizontal well development programs across the Midland and Delaware basins. We remain committed to our pace development approach, but the short cycle nature of these investments allows us to adjust this pace relatively quickly. In the current market, we've been active in negotiating cost reductions with our suppliers, achieving rate reductions of 20% to 50% across our major drilling and completion spend categories. At the same time, we continue to improve our drilling and completion efficiency. Since last year, we achieved roughly a 15% increase in drilling footage and a 20% increase in frac stages per day. The initial production rates for these wells are also very encouraging with our Bradford Ranch laterals averaging 1,100 barrels a day and comprising around 90% liquids. In addition, current estimated well recoveries have increased by 30%. So in summary, cost reductions, improved efficiency, and increased recoveries have improved our development cost per barrel by around 35% relative to 2014 and make more than 3,000 well prospects economic at $50 per barrel WTI. Let's move to slide 18. The major capital projects driving our growth are nearing completion, and are underpinned by our strong base business. The volumes associated with this growth are accretive to our cash margins and will contribute to long-term cash flow. We've reduced our current year capital spending by $5 billion relative to 2014. In the current environment, we are planning to reduce our 2016 and 2017 capital programs and our flexibility in capital spending significantly increases as our projects already in execution are completed. We are pacing projects not yet in execution to ensure we capture the cost advantages presented by the current environment and are prioritizing them to manage our capital program. We continue to drive cost reduction and efficiency to strengthen our cash flow by systematically reviewing our organizational structures and activity levels in our business units and by working with our suppliers. Pat will now conclude by sharing the enterprise impacts of these efforts. Patricia E. Yarrington: All right. Turning to slide 19, I'd like to now provide an update on the self-help efforts that we have underway to lower our costs and improve our efficiency. To-date, we've identified more than $3 billion of spend reductions with about half coming through organizational reviews and half working through the supply chain. On the organizational side, efficiency reviews have recently concluded that covered our corporate gas and midstream and service company group. Similar reviews are occurring on a rolling basis within our upstream business units. Work activities in these identified groups have been prioritized, streamlined, and right-sized to the current environment. Savings totaled approximately $1.4 billion on a full run rate basis and represent both dollar and workforce reductions off the relevant base of about 20%. These benefits to our cost structure should become increasingly evident as we move through the next several quarters. In future periods, we expect to see additional savings identified as our remaining upstream units complete their reviews. We're also aggressively pursuing savings through the supply chain, particularly in the U.S., where our supplier responsiveness has been high. We have negotiated an excess of $1 billion in immediate savings, achieving product category reductions of typically 15% to 30%. We are also changing the way we work through greater standardization, project re-scoping, refinement of fit-for-purpose designs, and timing optimizations. In combination, we estimate negotiated savings and work changes will lower our future supply chain spend $1.6 billion. These savings will appear in multiple ways as we move through 2015 into 2016. Impacts will come in the form of lower operating expenses, lower capital and lower cost of goods sold. And we're not done. We expect more supply chain savings to be identified in future months, particularly as activity continues to flow and as additional spare capacity emerges. We are being aggressive in pursuing these self-help measures in response to a very challenging industry environment. Moving to slide 20, I'd like to close with a few thoughts. We made a commitment to our investors in March. We said we would cover the dividend from free cash flow in 2017. We stand by that commitment. We are taking the steps necessary to ensure we are a resilient competitor regardless of the ensuing price environment. Our focus areas are shown on the slide, get our capital projects currently under construction online, rebase and reprioritize our capital outflows, maintain reliability and drive our cost structure lower, and conclude our planned divestment program. If a lower price environment persists for longer, you'll see even more significant cost savings and even greater cuts in capital. As we showed you in March, we have tremendous flexibility in our 2017 C&E spend. We are confident that we can and are committed to scaling our C&E outflows in a manner that will allow us to continue our 27-year record of annual dividend payment increases. So that concludes our prepared remarks. I appreciate you listening in. We're now ready to take your questions. Please keep in mind that we do have a full queue so try to limit yourself to one question and one follow up if necessary. And we'll do our best to get all of your questions answered. Jonathan, please open the lines for questions.

Thank you ladies and gentlemen. And once again, we ask that you please limit yourself to one question and one follow up. Our first question comes from the line of Jason Gammel from Jefferies. Your question, please? Jason D. Gammel: Yes. Thanks very much. First of all, if I could just ask on Gorgon. Jay, you mentioned the key risks still to getting to the first commercial cargo included labor risks, and there has been a lot of media attention to the – one of the unions that is employed by one of your primary contractors. Do you have any update on any industrial actions that could prevent getting that first commercial cargo in early 2016?

Thanks for the question. At this point, the work with the contractors and the unions to agree a new contract is ongoing. The discussions continue. There was a fourth vote that was unsuccessful recently, and so the unions have requested and received permission to seek a strike vote, but there is warning time that has to occur before that happens. At this point in time, any action that would occur would be relatively short in duration, 24 hours or less, and we would have ample warning time before that would occur. But I think it's important to recognize that a strike at this point is really not going to be in anyone's benefit and so the negotiations continue between our contractors and the unions, and I'm optimistic that they will be able to find a solution and a way forward. I think the issues have largely been addressed. The primary one appears to be just around work schedules, and so that's an area that's receiving quite a bit of focus as we move forward. Jason D. Gammel: Okay. Appreciate that. If I could, just as a follow up, ask a question about the charges that were recorded in the quarter for project suspension. Would you be able to give us any examples of projects that are being deferred and the level of CapEx savings that's being associated with these deferrals?

We really aren't going to go into any specific projects that have been deferred, but as we look at our pre-FID capital, the projects that have not moved to sanction, we're really looking to do either deferments as we slow them down to take advantage of the current market environment, build lower cost structure into this projects. We're also looking to pace those projects as we build our capital programs looking ahead to 2016 and 2017. But some projects that we feel are not going to be competitive rather than keep them moving we've just elected to go ahead and suspend those and those costs reflect some of those projects that we've suspended. Jason D. Gammel: Okay. Thanks for your thoughts, Jay.

Thank you. Our next question comes from the line of Phil Gresh from JPMorgan. Your question, please? Phil M. Gresh: Hey. Good morning, everyone.

Good morning. Phil M. Gresh: First question, I appreciate the additional color on the operating cost reduction potential and if we think about the capital cost side, looking at your Analyst Day deck, you had a grey bar with respect to capital costs of about $20 billion in 2016, so I guess I'm just wondering like how much reduction potential is there from a deflation standpoint, a deferral standpoint, and really if you kind of wrap it all together with the operating costs, your guidance at the Analyst Day suggested that you could cover your dividend at $70. So how low do you think that could go given where we are in this current oil price environment? Patricia E. Yarrington: So I think there's two elements there. Let me just start with the last component here. Really, we did say we would cover our dividend from free cash flow at the $70 price. What I was trying to indicate in my earlier words is we intend to cover the dividend from free cash flow at whatever the ensuing price is. That is a firm commitment on the part of the company, and we have tremendous flexibility, really, in our 2017 C&E to flex that down. We are being very successful in driving our operating costs lower and working through the supply chain to accomplish not only operating expense but capital reductions as well. And that really is an affordability component for us. It's a cash flow management element for us, and after we get these projects that are currently under construction online, that flexibility in C&E becomes quite significant in 2017. So I'll let Jay talk to his prioritization process in terms of looking at the capital program in 2017.

So as we're building – we're in the process of building our plan right now for 2016, 2017, and 2018. And as we go through, as we've said before, our primary focus first and foremost is on putting the investment back into our base business around asset integrity and maintaining good, reliable operations. And then we also fund the major capital projects that are in execution and as you have seen in our slides, that will decrease significantly as these projects come online. Just for example, in our LNG projects, this year we expect to spend around $8 billion in LNG, C&E, but by 2017, that's down to $1 billion. So we'll see tremendous flexibility coming in just from that. At the same time, we're looking at our base business, and as I mentioned, we are bringing our costs down, our efficiencies up, so we're seeing very good performance out of our base business and able to compete even in this environment. So we're evaluating how much money to put back into the base to maintain and continue to grow, particularly the short cycle, high value returns. And then finally, we're looking at the projects that are pre-FID, and as I said, we want to build in the lower cost structures, and we want to be able to preserve the option so that as prices recover, we can decide at what pace and how to ratably bring these projects back into the program. Moving engineering forward so that we have better definition, better understanding of these projects is a very low-cost way to build more confidence into our program for the future. And the last area is our exploration. We've been very successful in the last several years, so we've built up a bit of an inventory on the resource side, and so we can pull back on exploration over the next couple of years as we consolidate and wait for prices to recover. So I would see a dramatic and significant reduction in capital as we move forward. We're building that into our plans but the exact amount is yet to be determined. Phil M. Gresh: Okay. That's helpful. And then the second question in just in light of the commentary about Big Foot, some of the risks around Gorgon and Wheatstone, maybe you could just discuss your degree of confidence with the 3.1 million barrels a day production target for 2017 at this point, and to what degree you might be able to quantify what you see as the downside risk, because I know there was some cushion in that at one point, but maybe just kind of update us with your latest thoughts on that? Thanks.

We still feel very confident about the growth we're going to deliver, and that's primarily because the growth is captured and driven by these major capital projects that are currently in execution. And as I said, we'll continue to fund those and bring those to completion. So that growth is there, it's real, and it's based on our underlying base business performance, which has been very strong, and we've done a good job of being able to maintain our underlying decline rates. But we're in a different world, and so we're seeing costs change, obviously as the cost – or prices structures have come down, costs are moving, and so just as we did with North American gas, there's still opportunity to make adjustments in how we continue to invest in some of the shorter cycle opportunities. So I see us as having a very strong base. The growth, we're very confident with that. The level of the divestment, the level of base business, those can be some factors that go into it, but on balance, we are very strong on the growth prospect and the growth story that we presented to you. Phil M. Gresh: Okay. Thanks.

Thanks, Phil.

Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question, please?

Yes. Good morning. So maybe a small question to begin with. Just obviously Big Foot delay and then you're talking about extra fab space for Wheatstone and extra beds, I presume that the CapEx impact that you might be able to speak to or not and then obviously would you be able to offset that with the cost reduction efforts that the industry is going through?

Thanks. That's a good question. With Wheatstone, when you put extra beds in, there are some costs associated with that. At the same time, because the modules were delayed, we didn't build up the manpower initially as we had originally planned, so there were some savings early on. But in general, we're facing cost pressure on the projects just as we are around the world. At the same time, we're seeing very favorable exchange rates in Australia that are a countervailing force to that. So we're still working under the cost forecast that we've already provided to you. We'll continue to monitor that and see how we progress through the next 18 months, and we'll update you if we feel costs have changed significantly.

Right. And then this is a broader question. There was a period where Chevron had very good project execution, and then there have been, obviously, some well publicized setbacks more recently. If there was one change or one message that you were trying to get to investors and to the organization about how to hold on to better project execution, what would that message be, and is there any anecdotes or data to illustrate that that is changing?

That's also a good question. I think what we have seen, some degradation in terms of performance, and it's driven by a couple of things. One, the projects have been very large and complex. In and of itself, that's not just something that should be difficult to manage, but because of the number of projects being simultaneously managed I think both the industry's resources were stretched thin as well as our own resources to manage these projects was stretched thin. As we now consolidate and finish this big wave of projects that drives the growth that we have, roughly 20% from 2014 to 2017, we won't see that kind of sustained effort to maintain that growth going forward. It'll be at a much more moderate pace. So I think we'll have the more ratable queue of projects back into the range that's more straightforward to manage. At the same time, we're also working to lower the cost structures and increase the predictability of these projects by advancing engineering before we move them to FID. So as I mentioned on many of our pre-FID projects such as FGP, we talked in March about advancing the engineering past 50%, that 40% to 50% range by the time we take FID. Just as an example, you're looking for a proof point, when we took Gorgon to FID, we had modeled 12-inch pipe and larger in our 3D CAD models at the time of FID. FGP will have 3-inch and larger pipe in our system and sketches done for everything below that. So there's a great deal more definition in the design before we're moving these projects forward. So I think the combination of having a more ratable program along with better engineering, more advanced, higher-quality engineering will pay dividends for us.

Thanks, Jay.

Thanks, Ed.

Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question, please? Paul Y. Cheng: Hey, guys. Good morning. Patricia E. Yarrington: Good morning. Paul Y. Cheng: Jay, if I could, two questions. If you're looking at a company the scope and size of Chevron on a going-forward basis – historically that you spend most of your capital in the long cycle macro development, how is that going to change, and is there – may be a sweet spot how that's going to shift between the short cycle and long cycle development effort going forward?

Yes. I think as you look at projects like the Wheatstones, the Gorgons, the FGPs and TCO, these are projects that will add very large base and very long term assets to our portfolio. As we execute our small capital projects, which are often infill drilling programs, work-over programs and de-bottlenecking, we typically see rates of return above 50%, and they're built on these assets, we've already made the investments. So I think we're really doing a good job of rejuvenating our base and putting some new life into the base that we can continue to exploit over a long period of time, but at the same time we're building our capability day by day in our ability to go after the shale and tight largely in North America and in Argentina. So as you've seen our performance numbers continue to increase, we're coming down that learning curve and we're becoming more and more competitive, and it's going to give us a very good balance between deepwater projects, large base projects in the LNG and sour gas as well as access to the shorter cycle of shale and tight unconventional projects. So I see a very good balance and a very good diverse portfolio (39:21). Paul Y. Cheng: Is there a percentage that you can share that on the going forward basis there was that capital spend between the long and the short cycle going to look like?

At this point in time, I don't have a ratio or a percentage to share with you. Our resource base has increased about 15%. Our portfolio has increased in the unconventional side by about 15% over the last five years in particular. So we're seeing more of our resource base being the unconventionals but the unconventionals have very high, very fast decline rates, and that is always going to be something we balance against the longer-term projects with their stable production. So that's something we'll work through as we react to market conditions, our view of forward pricing and the capital that we want to invest across the portfolio. Paul Y. Cheng: The second question is that, Jay, going back to your early comment, not just Chevron, it looked like the whole industry the last maybe 10 years has got openly optimistic about their capability to deliver and execute. And so, it seems like everyone is stretching themselves to the limit and we start seeing all these execution issues. For Chevron, learning from the mistake of the last several years, have you changed the way – I mean you are talking a little bit about more definition. But at the top how have you changed the investment decision process on the FID? Will you be – I mean in the future – in the past the industry tends to just looking at the financial capability and whether that you can afford the project and whether it is a good project. How that is going to change in the future particularly for Chevron ?

For Chevron, we have traditionally looked at individual products and the economic opportunity each project presents in making an investment decision. I would say now in the current environment and looking forward, there'll be two additional lenses that will be added to that decision. First and foremost, the project and the economic proposition it presents, but then we'll be looking at what is the overall level of investment we want to be making and also what is the level of human capacity we have to manage the projects? And those will certainly be factors that we will build into the process, and we are building into the process now so that we can keep that as we move forward. We've also done a lot of work to put in what we call readiness reviews, and these are to make sure that both from a design and a design assurance standpoint before the project moves to execution but also before we start up these projects, we're going to readiness review that are much more rigorous and help us make sure we have the resources and the capabilities in place to execute these projects as expected. Paul Y. Cheng: Thank you.

Thanks.

Thanks, Paul.

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

Great. Thanks. Good morning, everybody. Maybe if I could do one follow-up on the costs, on the slide you have there, on slide 19, there is the $3 billion and spend reduction targeted. I'm not sure if I miss it when you said it, but is this all, is the CapEx and OpEx, is that all in the OpEx side? Can you estimate how much you've captured to date, how far along you are at this point? Patricia E. Yarrington: Yeah, so the combination of the $3 billion is for both operating expense and capital. The $1.4 billion is predominantly going to be operating expense, and the $1.6 billion is going to be a mixture of both and probably leaning a little bit more towards the capital side of things. And from a – and these are elements that should begin to show in an accelerated basis as we move through the third and the fourth quarter. I would say captured to-date actually has been some but not a high proportion of the $3 billion total.

Okay. And is there a timing on when you hope that this – something you hope to capture over the next year or two years or...? Patricia E. Yarrington: Oh, I think it will be more immediate than that. I mean think it will be into the third quarter and fourth quarter of 2015 with some carryover into 2016 as well. I mean, a large portion of the supplier engagement element there, a billion dollars of that are negotiated price reductions off of planned 2015 activity. So those negotiations began, as you know, back in the January, February timeframe, we're sort of concluded in the May, June timeframe and so those rate reductions we should begin to see coming forward in the next half of the year.

Great. Thank you. Very helpful. And then maybe if, I appreciate the color that you gave earlier on Big Foot and the contribution of Big Foot to the 2016 and 2017 plans. Could you maybe give the same numbers for what – in the 2017 plan, let's assume for the Partitioned Zone, and Angola LNG and maybe any updates you have on both of those projects?

Sure. And first I'll start with the PZ. The PZ, at this point in time, we have around 60,000 barrels a day to 70,000 barrels a day expected in the 2017 plan but we do not expect that field to still be shut in, in 2017. So my expectation is that we will be able to resume operations. There is an issue that's being discussed between the Kingdom of Saudi Arabia and Kuwait. The impact on us is the difficulty receiving visas and equipment permits. So we were unable to continue operations and we stopped operations there as this issue is addressed. Our goal would be to return to normal operations in the short term as the – any other issues are continued to be worked out between the two governments. And so we work and we're trying to support the activities in that area accordingly. In terms of the ALNG, progress is moving along quite well there. We are completing the work on all the piping modifications, you recall this is as a result of the acoustic-induced vibration analysis that was done, so that work should be finishing up in the month of August, and then that will allow us to start the recommissioning process at the plant. The other work, in terms of the conditioning equipment on the front end of the plant to handle the diversity of the associated gas feeding the plant will be complete as are the technical bulletins. But we would expect to see restart late the year and then sustain production in 2016 and onward. So that's really the status of those two projects.

Great. Thank you very much. I'll leave it.

Thanks, Ryan. Patricia E. Yarrington: Thank you.

Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question, please? Neil S. Mehta: Good morning. Patricia E. Yarrington: Good morning.

Hi, Neil. Neil S. Mehta: So, Pat, I just want to talk philosophically about how you're thinking about the dividend and your strategy there. Didn't raise the dividend in the third quarter, but the way we read the comments was that we'd look for you to raise it here in the fourth quarter even if it's a nominal level, and it's a priority to continue to raise the dividend going forward. I just wanted to confirm that and then get your thoughts on the broader dividend strategy. Patricia E. Yarrington: A good question. So our broader dividend strategy hasn't changed. Our financial priorities haven't changed. Maintaining a competitive and growing dividend is our absolutely number one objective. What has changed, though, is obviously our immediate financial environment, and so the board chose not to raise the dividend in this quarter. I think that's a prudent action at this point because we're not running as strongly, certainly, as we would like on both earnings and cash flow because of where commodity prices sit. And it's not – I would say it's probably we're not in a very stable either revenue or cost environment. We have a lot of fluidity on those two components here. I will say the board is very committed to growing the dividend and seeing our pattern of dividend increases every year materialize, but what's important here is that it's the annual dividend payment that has moved up every year. That doesn't mean you get an increase in the per share every single year, because we typically have moved them in the second quarter. So it's an annual dividend payment history that applies to the 27-year factor. So I think the board is committed to that. We are committed to that. So I would like to be able to say our entire objective is being able to grow the dividend when the time is appropriate. We don't want to get out over our skis. We want to do it in a manner and at a time when we can see that we can hold on to that increase, sort of in perpetuity. We don't want to put ourselves into a position where we're pushing things, where we are having to fund the dividend off the balance sheet for an extended period of time, so we'll do it as soon as the financials really allow us to get there. It is our number one priority, though. Neil S. Mehta: Thank you, Pat. And, Jay, a question for you around Latin America. Two regions in particular. Venezuela output generally seems to be very robust across the country. Curious what you're seeing there and if you can comment on your relationship with – just politically over there, and given some of the potential tensions? And then the outlook for Argentina as well, it looks like a very powerful resource, obviously a dynamic political situation there as well, but comments on both of those plays would be terrific.

The performance in both of those areas has been good, and our relationships with the government in both countries I'd characterize as very strong. We have a long history and we have worked hard to maintain both our performance and our relationships. In terms of the unconventional play in Loma Campana, we are seeing continued progress there. We have linked in that asset team, and they are tied to our North America asset teams, so there's good sharing of the information as we continue to move down the learning curve, as we gain knowledge from the industry and offset partners, we're plowing those back into the business, moving to consistent sets of metrics. So that drive to continue to improve in the unconventional space is being applied in Argentina as well. And so we're quite excited about that potential for that asset. Neil S. Mehta: Thank you, Jay. Thank you, Pat.

Thanks Neil.

Thank you. Neil S. Mehta: Thanks, Frank.

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

Good morning, everybody. I think you mentioned earlier the inability to slow offshore exploration spending in this current environment or in your outlook here. But can you quantify exploration spending in 2015 and 2016 from at least from an Analyst Day timeframe and discuss rate commitments that limit your flexibility into that timeframe.

Yeah, the Deepwater drilling that's going on in the Gulf of Mexico, of course, we have six rigs there, and it moves back and forth between exploration and appraisal. So as we have exploration success, than rigs get taken out of exploration and moved into more appraisal and development work. So for example, right now, we have, of the six rigs, four are working on production and development wells and two are working on appraisal wells, and we'll move some of those back into the exploration area. We currently expect to drill about 12, what we consider to be high-impact exploration wells around the world this year. We continue to see activity in West Africa, Deepwater West Africa and the Gulf of Mexico are two of our primary areas but we also have some other work in the unconventional going on as well.

Right. So it's more of a shifting then maybe a reduction on the rig side.

I think as we move forward, we're going to, on the rig side, we shift those back and forth. Of course, they're under long-term contracts, the large Deepwater rigs. But in terms of some of the unconventional work, those rigs are on shorter cycle, and we can move accordingly with our capital allocation.

Great.

Going forward, my comment was really around how much additional work we're going to put in outside of those committed Deepwater rigs.

Great, Jay. And since I have you while you're on the call, maybe a question on the Permian. Your EUR's are up 30% on the slides. Any color on the driver there, whether it's completion, lateral lengths, different zones? And maybe just generally within your portfolio, given the returns, I mean is this region a net receiver of more capital versus other areas where there may be more capital pressure in this environment?

Yeah, on the first question, I would say it's all of the above. As we're getting more effective in our drilling, we're learning a lot from our offset operators and we're moving, as you know, from vertical wells to horizontal wells, and our preference is to really be able to drill those 7,500 foot laterals. The IP rates are consistent with what we were hoping for. We're seeing high liquids content in Bradford Ranch. So everything's looking pretty positive there and when you combine that with the reductions we're getting from our cost of suppliers and the efficiencies, that's what's driving that 35% reduction and our development costs per barrel. I would say that as we look forward, we certainly see the Permian as a very lucrative area for us to continue to grow, but because so much of that acreage is held by fee, we have the luxury of being able to moderate and decide just how much we want to put in there and really can use that as a flywheel. As we put more infrastructure into the area, it really gives us increasing flexibility and profitability as we move forward.

Great. Thanks for your answers.

Thanks, Evan.

Thank you. Our next question comes from the line of Doug Terreson from Evercore ISI.

Good morning, everybody.

Good morning.

On the industry deflation theme, I wanted to see if Jay could comment on whether – Jay, whether you think the pace of cost capture that Chevron's experiencing is different between the U.S. and overseas markets, meaning is one of them lagging the other? And also, do you think it's reasonable to believe that the pace of cost productivity captured for larger companies like Chevron might lag that of smaller companies during this part of the cycle?

Good questions. I'll talk first about the U.S. versus International.

Okay.

We have seen a faster response in cost reductions in the U.S. than in the international side. A lot of that's driven by the competitiveness of the U.S. market. There are more contractors out there, there are more service providers, and you can work and make transition from one to another faster if needed. As you get into the international environment, it varies country by country, but the barriers to entry can be much higher. There's often local content issues. Many of these companies may be in joint venture with local companies. So it just makes it more difficult sometimes to drive those costs lower in the short term. But what is happening is we're seeing the activity levels come off substantially, and as activity levels come off, we're seeing that drive the cost structure lower. So I think we will see, and particularly as low prices persist, we will see the international continue to come down. It just hasn't been at the rate that we've seen in North America. I'm sorry, the second part of the question?

Yeah. And also, Jay, do think it's reasonable that larger – that the cost productivity capture for big companies like Chevron might lag that of the smaller companies during this part of the cycle?

Yeah. I think in North America the small companies can also drive costs down just as we do, because as I said, there's enough competition for provision of goods and services that they can make those switches just as we can. And so they can drive very, very rapid reductions in price. In the international area, what we're trying to do is really work as an enterprise so that we are working with our major suppliers and coordinating our efforts to drive those costs down around the globe. That's why I think a big company has some leverage that a small company wouldn't. We can work with these very large companies to drive those efficiencies, to make sure that our global contracts and terms and conditions support a lower cost structure.

Okay. Patricia E. Yarrington: And I'd just add that I think because of our spend and our size, that gives us additional leverage that some of the smaller firms don't have.

It seems like it would over some period. And then also, Jay, you talked about the neutral zone a few minutes ago and it's obviously been shut in for a few quarters. And I know it's hard to know whether the Saudis and the Kuwaitis are close to resolving their issues, but my question is if those fields were able to be brought back on stream, over what period of time do you think this could happen? Meaning is this something that could occur over months or is it quarters or is it a longer term period, given the extended nature of the shut in? So how do you think about that?

Well, the fields were shut in – the Wafra field was shut in, in mid-May. So that kind of gives the beginning of the timeframe. And obviously it depends on how long they remain shut in. If we were able to restart in the next couple of months, I think we'd be looking at probably like about a six-month ramp-up to get back into kind of normal operation. Obviously visas have to be issued, we have to get workers into the country, we have to get the facilities restarted. So we've been doing steadily since the facilities were shut in, preservation work to make sure that the facilities are protected and that we are ready for a restart. There's extensive planning around the restart. So I think as we work to get approval to restart that field it really just depends on how long it's going to take before that restart initiates. But at this point in time, we can restart in a relatively short period of time. Couple of quarters I would say.

Okay. Okay. Thanks a lot.

Thanks, Doug. Yup.

Thank you. Our next question comes from the line of Paul Sankey from Wolfe Research. Your question, please? Paul B. Sankey: Hi, everyone. Patricia E. Yarrington: Good morning. Paul B. Sankey: Hey. A follow-up just from earlier comments, and then I have a separate question. I wasn't quite clear what you're saying about the dividend. Did you say that the 27-year record is not of increases in per-share dividends but is an absolute payout? I think that's what...? Patricia E. Yarrington: It's an annual payment record, yes. Paul B. Sankey: So we're looking at the dollars that you pay out as an amount? Is that – that's the increase... Patricia E. Yarrington: That's correct. Paul B. Sankey: Okay. Patricia E. Yarrington: That's correct. Paul B. Sankey: Okay. So what you're saying is it may not increase on a per-share basis? Patricia E. Yarrington: Each year it may not. But the payment in each year has increased 27 years. Paul B. Sankey: Yeah, given all the moving parts here, if we could just – I'm sorry if I missed it, but are we still reiterating the $3.1 million a day for 2017, and is that changing with the asset sale element here? I'm not clear if you've increased your asset sale target. And I think your net asset sales from the $3.1 million a day, is that correct? And furthermore, is the cash flow neutrality target dependent on asset sales? And I'm again not clear if you've increased the asset sales. And finally, is the cash flow neutrality a number at which you keep volumes flat or you grow? Thanks. Patricia E. Yarrington: Yeah, so let me just go back and talk about the original objectives that we put out in 2017 and $70 oil and the cash flow neutrality. That – the assumption that we had in there was independent of asset sales, at the $70 price. Now depending upon where you go on price, I have indicated that we would continue to work our cost structure. We would continue to work our capital outlays. I think we also need to keep asset sales in the portfolio. It is an arrow in the quiver. It is a lever that we would have. And what we showed you back in March, we were cash flow neutral covering the dividend without asset sales in there. Depending upon where prices end, obviously I think that's a lever that we still need to have in the – available to us.

So when we gave you the SAM information in March, we had about 65,000 decrease from the 2014 to 2017 in asset sales. And that, as Pat said, can certainly change as we determine what the level of asset sales is going to be. But the $3.1 million is really driven by the major capital projects that are under construction that are going to be coming online. I think one of the key points was, as we also said in March, those volumes that are contributed are accretive from a cash margin standpoint. So as those projects come online, we still see that as the main driver of our growth, and then we just have to evaluate both from a divestment standpoint and any moderation in capital into the base, what the impacts of that might be. Paul B. Sankey: Okay. So we're sticking with the $3.1 million. It's not necessarily contingent. You're not adjusting for asset sales but neither are you adjusting for the project issues that you talked about in the call. The cash flow neutrality doesn't or does include asset sales and can you grow from there in 2017 if you are cash flow neutral? Thanks.

Yeah, I think from the standpoint that the $3.1 million is an outcome. It was $3.3 million, and as the North America gas pricing came substantially lower and we saw it staying lower, we pulled back some investment from North America gas and brought our target down accordingly. At this point, we're still at $3.1 million, we still have all these projects that are under construction and driving forward, but obviously, we just have to see if this very low price condition persists. It may have some impact. The $3.1 million is good a number as an outcome that I can drive it to at this point in time. In terms of going forward, we'll actually see our capital programs. We've talked about moderate quite a bit because we're not going to be trying to do the – and accomplish the organic growth that we're underway right now. So as we look forward, we're evaluating that now, we'll see some momentum continue. Projects like Gorgon have two trains that will come on, Trains two and Trains three and then the ramp ups that are associated with those Trains. Wheatstone will have a second Train coming on. We'll have some other projects that are still in the ramp up phase. So I see some momentum carrying past 2017. Those are also going to be strong volumes from a cash margin standpoint. And then as we look out into the next decade, a lot of that is going to depend on the options that we've been able to preserve and the degree to which we've moved to any of the pre-FID projects forward. That's part of the work that's undergoing now in our business plan. Paul B. Sankey: Okay. So I don't want to go on too much with it. But just a final specific, one with the cash neutrality does include asset sales. Patricia E. Yarrington: So in the $70 case, the answer was no, it did not. Depending upon what case you're going forward with here, a $60 case, a $50 case, whatever your case is, I want to preserve that degree of flexibility for us. Our primary levers are going to be getting our cost structure down and getting our capital program down for whatever price environment prevails out there. But depending upon where prices do go, I don't want to take off our available set of options. I don't want to take asset sales off that available set of options. Paul B. Sankey: Okay. I understand. Can I slip in another one? Why was the...?

You see, Paul, we're overtime. We got a couple of guys (01:03:43). Paul B. Sankey: Yeah. I'll let you go. Thank you. Patricia E. Yarrington: All right.

Thank you. Our next question comes from the line of Alastair Syme from Citi. Your question, please? Alastair R. Syme: Hi, everyone. Can I just ask on the impairment exactly what it was that triggered it? Is it just oil price or is it something about assets going up for sale or some geological review? Patricia E. Yarrington: Yeah, so... Alastair R. Syme: And can you can say what oil price it is? Patricia E. Yarrington: I can answer most of those questions here. The trigger really was a lowering of our corporate longer-term price outlook on crude oil. We took that action in May, and as you know, when there's a trigger event like that, we do need to run impairment tests on our assets. Any time there's a significant trigger, whether it be a reduced price outlook or increased costs or some change in the geology in the reserve or production profile, those are elements that when that trigger occurs we need to do the impairment reviews. And we have a process set up where we look at that every quarter. In this particular instance, the vast majority of the impairments related to Papa Terra, and that was a price-induced, crude oil price-induced impairment. We did have a couple of other smaller assets in this category as well where they were assets held for sale where we were writing it down basically to what we felt was the realizable value. Alastair R. Syme: And on the oil price? Is it possible to talk around that? Patricia E. Yarrington: Right. We're not going to give you our proprietary oil price. I can just say the revised outlook was really based on two factors. One had to do with the rate we were expecting of global GDP growth and in particular around China, so we've seen softening in China, and we've taken our view of that down accordingly. And the second major factor that lowered our overall price outlook had to do with the U.S. tight oil shale produceability. We've seen obviously much stronger production coming out of the U.S. and with the ingenuity and cost efficiency of the U.S. industry we've seen costs continue to fall, and economics of those barrels continue to rise, and so that puts more supply onto the market place. And so it's those two factors that's led us to lowering our longer term price outlook. Alastair R. Syme: Right. And finally, is really anything taken on Big Foot other than the impairment or in the suspension, project suspension (01:06:07)? Patricia E. Yarrington: No. Nothing of any material size, no. Alastair R. Syme: Okay. Thank you very much.

Thanks, Alastair.

Thank you. Our final question comes from the line of Doug Leggate from Bank of America Merrill Lynch.

Thank you, and, guys, thanks for letting the call run over. I really appreciate you letting that. I just want to get on with the end here. I guess I wanted to kind of follow up on a couple of things that Paul mentioned. I really had two specifics. But $11 billion out of $15 billion on disposals, what is your thought on raising disposal target at this point given that you've still got two and a half years left in the program? It would seem you've got a lot of upside potentials. So that's my first. Patricia E. Yarrington: All right. And we're not in a position to move that target at this point. We just moved that target back in March. We feel very good about the assets that we've been able to move forward and the value that we have captured for that. So we have a number of assets kind of lined up in our own mind about how we could meet that $15 billion target over the next several months, 18 months or so. But it really will depend on whether or not that value is capturable. And we're not going to just sell the asset for the sake of meeting a target. We want to capture value while we do it. So I'm not in a position to raise that target at this point. We feel good about where we sit. When we get to March of next year, if we have a different view, we'll update it at that time.

Appreciate it. My follow up, and I guess last question of the call is on Gorgon, not so much on the timing of the startup, I think Jay's been pretty clear on that, but the timing of getting to full capacity because obviously the cash flow delta that comes from the slowdown in spending versus the cash flow contribution is quite important. And I guess what I am getting at is if everyone is really starting to think lower for longer, what does the cash contribution look like and how long does it take to get to full capacity? So, I don't know how you want to try and answer that, but if you could help us with the contribution from Gorgon when it does come on, that would be – Gorgon (01:08:18) that would be very helpful.

So our current view on Gorgon is that each Train, the second Train should start up about seven months after the first Train and then followed by four to six months for the third Train. And it should take around eight months on the first Train to get to capacity is our plan, and then six months for Trains 2 and Trains 3. So you can kind of put all that together to get a rough profile of what Gorgon's going to look like coming forward. And even in the lower price environment the cash generation that it has is still substantial, so we're looking forward to getting that cash on stream. Patricia E. Yarrington: Okay. I think that was our last call. I want to thank everybody for your time and attention here this morning, and I'll turn it back to you, Jonathan.

Ladies and gentlemen, this concludes Chevron's Second Quarter 2015 Earnings Conference Call. You may now disconnect.