Good morning. My name is Jonathan and I will be your conference facilitator today. Welcome to Chevron's Third 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 would now like to turn the call over to Chairman and Chief Executive Officer of Chevron Corporation, Mr. John Watson. Please go ahead.

Okay. Thanks, Jonathan. Welcome to Chevron's third quarter earnings conference call and webcast. On the call with me today are Pat Yarrington, our Vice President and CFO, who you know very well, and Frank Mount, our General Manager of Investor Relations. We will refer to the slides that are available on our website. Before we get started, please be reminded that this presentation contains estimates, projections and other forward-looking statements. We ask that you read that cautionary statement that is on slide 2. I will now turn the call over to Pat, who will take you through our financials, briefly. Pat.

All right. Thanks, John. I'll be presenting four slides on third quarter results. Our normal earnings and production variance slides are available in the appendix section of the presentation, which is available on our website. Starting now with slide 3, an overview of our financial performance. Third quarter earnings were $2 billion, or $1.09 per diluted share. Excluding foreign exchange and impairments, earnings totaled $1.9 billion, or $1.01 per share. On this basis, third quarter results were modestly better than second quarter, despite a much weaker oil market. This reconciliation is also available in the appendix. Cash from operations for the quarter was $5.4 billion. Our debt ratio at quarter end was just under 19%. During the third quarter, we paid $2 billion in dividends. Earlier in the week, we declared a $1.07 per share dividend, payable in the fourth quarter. This takes our 2015 annual dividend to $4.28 per share and makes 2015 the 28th consecutive year where we have increased annual per-share dividend payments. Turning to slide 4, cash generated from operations was $5.4 billion during the third quarter and nearly $15 billion year-to-date. Downstream cash generation strength was sustained in the third quarter, while upstream cash flow fell, commensurate with an approximate 20% drop in global oil prices between quarters. As of September 30th, working capital effects reduced 2015 operating cash flow by $2.3 billion. Year-to-date proceeds from asset sales were $5.4 billion, bringing our total over the last seven quarters to more than $11 billion. We are tracking very well against our four-year asset divestment target of $15 billion. Cash capital expenditures were $6.8 billion for the quarter, $800 million lower than second quarter. Year-to-date cash capital expenditures were $22 billion, down $3.6 billion or 14% compared to the same period in 2014. At quarter end,…

Okay. Thanks, Pat. Turning to slide 7, I would like to start by reinforcing that our priorities – financial priorities are unchanged. Our first priority is to maintain the dividend and grow it as the pattern of earnings and cash flow permit. As Pat mentioned, we announced our quarterly dividend earlier this week and are very proud of the fact that we've increased the annual per-share payout for 28 consecutive years. Back in March, we committed to delivering free cash flow to cover the dividend in 2017. At that time, the futures market was envisioning $70 prices in 2017. Today, the futures market is lower, but our intent remains the same. Our goal is to balance our cash equation by completing projects under construction and reducing capital spend and operating expenses to levels consistent with the current market conditions. We will also continue to divest assets where we can obtain good value. We will achieve this while operating all businesses safely and reliably. I'll address each topic on this slide on the slides that follow. First, a little bit of an overview on the market. It's clear that low prices have reduced upstream earnings for the sector, and, for Chevron, we're no exception. Prices are low because the market is producing more than consumers want, but the markets are showing signs of rebalancing. Using Wood Mac data, this chart depicts worldwide liquid supply with the black line and demand in red. The blue represents the shortfall from or surplus to inventory. In the early part of the decade, the pattern was clear. Supply could not keep up with demand, in part because of supply disruptions in the Middle East and North Africa. The success of shale in the U.S. and some growing production from Iraq allowed the market to rebalance…

Thank you. Our first question come from the line of Phil Gresh from JPMorgan.

Hi. Good morning.

Good morning, Phil.

John, thanks for the full update here. My first question is that one of the criticisms I continue to hear from investors about big oil is that most of the companies in the industry are just trying to manage two dividend coverage at a point in the cycle rather than through the cycle. And I fully appreciate Chevron has a full stable of capital projects over these past few years, so the spending flexibility is very high. But I was hoping you could just help us tie this new capital spending guidance to what kind of underlying capital spending would be required to keep production flat or what kind of long-term growth rate you think Chevron could achieve using this lower capital base?

It's a fair question. We do try to invest through the cycle. We got into a period at the early part of this decade where we had some good projects that were frankly stacked up on top of one another. We thought it was the right time to take Gorgon forward. We had good contracts in place. And, frankly, it was somewhat countercyclical when we started in 2009, very late in 2009. Wheatstone, very similar. We thought it was a good market and we needed to move that one as well. We also had Gulf of Mexico projects that following the moratorium in the Gulf of Mexico, came on – we started it at the same time. So we went through a period of capital spend that was pretty high. We thought these were very good projects, but there's no doubt that we were going through a period of heavy capital spend. And we kept our balance sheet pretty strong to enable us to withstand the ups and downs that we see in the market. Now, we saw prices rise dramatically, and then we've seen them come back down a little harder than we thought, so we do have to manage through this cycle. But I think we've been able to weather that pretty well. We are completing the projects that we've got. We're working to preserve the options that we have on some of the nice opportunities we have going forward. But we do have to live within our means here, and if you look at the – as you know very well, when we look at the pattern of dividends, it's a nice, smooth pattern with increases over 28 years. The pattern of earnings is a lot more volatile during that period, depending upon commodity prices. So we do invest through the cycle with some of these long projects, we have to be able to do that. But we have had a period of heavy spend for – that we've had to go through. So there is an adjustment when prices go from 100 to 50, and we're just having to deal with that. But, certainly, we're investing through the cycle, but making some adjustments to deal with the low prices we've got.

And is there a specific growth rate you think you can achieve with this new spending base?

Well – certainly, we're going to see disproportionately strong growth through 2017, frankly, into 2018 that, we think, will be very good. Long-term, overall, hydrocarbons are growing in the 1% to 1.5% range. And so that's probably a more reasonable expectation going forward, but frankly we make our investment decisions based on what we can do that is economic. If you look at the history for companies our size, growing at something significantly greater than where aggregate demand for oil and gas is growing is pretty hard to do. And, frankly, we'll be guided by what we think we can do economically. We'll give you a little bit more information on what we think post-2017 as we finalize our business plan. We're still grinding – the reason we gave you a range on some of these capital numbers is we're still grinding through that business plan right now to be sure we strike the right balance, and that level of spending will dictate what the growth will be in some of the out years. Just so you have some confidence, though, I made specific comments on the future growth project, the Wellhead Pressure Management project in Tengiz, as one example of investing through the cycle. And that's a significant project, which we're working through final details with government and partner. But we're doing a lot of early work on that project, and that's one that, as we take final investment decision, we won't see the production from that until the next decade. And so that and other investments will provide growth going forward.

Thanks, Phil.

Sure, Okay. Thank you.

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

Thank you. Hey, guys. Good morning.

Good morning, Paul.

How are you doing, Paul?

Very good. Thank you. John, two questions. One is really short, and let me go for that first. With the – the CapEx is saying that the base operation decline rate will be higher. I think, for the last five years you guys have been about 3% to 4%. Do you have a new number for us?

Yeah. Actually, we've been better than that. Our base business has been more like 1%. It's been less than 2%, certainly, during that period, and we see it being more like 3%. And so, frankly, if you take just the difference between about 1% and 3% and apply it to our base level of production, you get a little bit lower production than you might have seen otherwise.

Okay. Excellent. Second one is a little bit more strategic, I think. If we look at hallmark for Chevron, it has always been on the LNG deepwater macro (00:23:47) project development. But I think the market is concerned, this type of development, there's a high-cost curve, has increasingly choose the last several years at the high end of the industry. And that also that the recent cost deflation that they have not seen as much comparing to the short cycle. So the question is that, do you agree with that view, and is concerned that the hallmark of the company what you're good at and of that to be at the high end of the supply cost curve? If you sort of agree with that, what initiative that Chevron is thinking to try to improve your cost curve position so that they will become, say, at the top quartile or top half at least.

Yeah. That is a philosophical question, and I'll give you a few comments. First, I think it's true that onshore costs have come down more than offshore costs. So I think that's just factually true, particularly in the United States, but also around the world. So rig rates and service costs, things of that sort. So that certainly is true. It's also true that some short cycle base business spend traditionally has lowered cost, once you have infrastructure in place, and it, certainly, is true that some of the shales are low cost. I think what's important, though, is if you step back and look at the market overall, it's a 95 million barrel a day market. The shales are about 5 million barrels a day. And there's a decline curve that's very rapid in the shales, of course, in every other producing asset. And it's going to take contributions from all asset classes to meet demand. And so we're going to need all forms of supply, and what we're doing is trying to take on cost reductions and get better everywhere to take costs down. And we've been able to do that. We've shown you some charts periodically, and – I mean offshore is about 25% of worldwide production and Deepwater production continues to grow and will continue to make contributions to worldwide supply. But if you look at drilling and completions technology, we've talked about things like the single-trip multizone frac pack, which is just a more efficient to get in and out of the hole to do work. If you look at ocean-bottom nodes work that we're doing, that really gives us better seismic imaging on the ocean floor, subsea systems and boosting technology. All these things are bringing cost down. In fact, in our Gulf of Mexico operations, our Deepwater, we've been able to reduce drilling days significantly. Our drilling days for 10,000 feet are down 25% over the last two years. So we've been able to take those costs down. And I think you're also likely to see the work that we did in the Gulf of Mexico to consolidate holdings, to create – for the industry to collaborate to create hub class developments will also help with economies of scale. So I think you'll see bigger hubs, but I think all classes of assets, at the current low prices, will have some spending that will fall out. So it's – some of your points are true, but I think costs – you'll see costs over time come down everywhere, and, of course, these projects are over a long period of time. LNG are 40-year projects, so you have a different lifecycle to these things as well, which can impact – some long-cycle LNG tend to be – because they're long-cycle, tend to be a little bit lower than – in RORs, but they have a very long life and cash flow. So they have a little bit different characteristic to them.

Thank you.

Thanks, Paul. Thanks very much.

Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question please. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Yeah. Good morning. Thanks for all of the color. Just on the opening remarks, I think you said slower ramp-up on projects. So I presume that's going to be LNG, just looking at the cartoon which you put in the presentation in terms of LNG volumes. Maybe just a bit of a color around Gorgon and Wheatstone. Thanks.

Well, we said that the ramp-up would take place over time. The key is getting them started and getting first LNG and then the ramp-up will take place over time. So, I think, all I was trying to say with the ramp-up is that they will take place over the next three years. My comment wasn't so much about the ramp-up as it was that there will be a start date. Just in terms of what we're expecting, I indicated that Gorgon will see first cargo in the first quarter. I had updates yesterday afternoon on both Gorgon and Wheatstone, and I was pleased with the progress that I heard. I gave you some of the kind of key points that – the kind of proof points to where we're headed there. ALNG will start up early next year as well. I mean there's no secret that this has been a challenge, as we work through some of the engineering issues, but once that gets started, I think we've addressed some of the engineering issues that we encountered. There were also some technical bulletins that were issued by the technology owner. We took care of those, as well, during this downtime. So ALNG will start up early next year as well, and my update on Wheatstone, the key issue there has been module delivery. We had some modules out of Malaysia that were late. The team is working very hard to mitigate schedule there, and what I mean by that is, with some delay in modules, we're really now looking at both construction timing and some of the start-up and commissioning work that will need to be done. We've taken a close look at all the other projects that have been done in Australia and elsewhere, on the East Coast…

No. Actually, I think if you look at our cash flow, and the rule of thumb that we gave you for the effective oil prices was roughly $350 million after tax in earnings and cash flow for every dollar per barrel. And you multiply it by the change in barrel, I'd think you'd find that our cash flow is better than what you might expect by that rule of thumb. Now, we're trying to diminish that or reduce that rule of thumb by taking on costs and other things to get better at what we do, but I think you'd find that between those rules of thumb for oil and gas, I think you'd find that it's pretty consistent with that. And in fact, it's better because our downstream has performed so well. So I mean the grim reality is when you have on oil prices in the $40s, as we saw in the third quarter, as you look across the sector, particularly in the United States, it's tough sledding. And if you've got natural gas prices where they are in the U.S., it's a challenge. But we're taking it on by reducing costs. You saw some of the pretty aggressive actions that we're taking around the world to size the organization at the right level, and we think if we get some recovery in prices, you'll see a nice pop from that. But I can't control prices. I can only control my costs and spend. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) So it's just oil sensitivity. I understand. Thanks.

Great. Thanks, Ed. Sure.

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

Yes, thanks very much. Hi, everyone. You've already touched on a lot of drivers here, John. But I was just trying to reconcile the new production range of 2.9 to 3.0 relative to the 3.1 million barrels a day that was presented at the analyst meeting. And I wasn't really clear rather the Partitioned Zone was included in the 2.9 to 3.0 or rather it's out, because that's obviously a big reconciling factor. And then how much of it would essentially just be production being pushed into 2018 versus an actual lower production figure from declines?

Yeah, there are lots of effects that are in there. First off, the biggest effect in the change versus what we've talked about previously was my comment on declines. You can't take – depending on which numbers in the range you want to use, we've taken $15 billion of capital out of the business in the go-forward projections from 2016 and 2017 in total. And that impacts, as I said, base decline. So if you add 2% to the decline, that's 100,000 barrels a day over a couple of years. So that's number one. But to answer your question about the Partitioned Zone, that production a year ago was roughly 80,000 barrels a day. And if you look at where we expect it to be in 2017, it was somewhere under 70,000 barrels a day. And that is included in both estimates. We expect to be back online by that time. I just returned from the Middle East, and I'll tell you, this has been pretty perplexing to me why we remain shut-in. You have two great allies in Saudi Arabia and Kuwait who are having a disagreement over administrative matters in the Partitioned Zone between Saudi Arabia and Kuwait. It's in the Kuwaiti portion of the zone. And so, they administer work visas, equipment permits and things like that, and they stopped issuing them. And so we ended up shutting in May, and so we've lost the better part of 80,000 barrels a day net to our production. The reason I think production will come back is because the Kuwaitis themselves are actually being hurt by shutting in a gross amount of 200,000 barrels a day, half of which is theirs. They are hurt; Chevron is hurt, but Saudi Arabia is able to increase production elsewhere. So I think there's motivation for the Kuwaitis to begin issuing work permits and allowing work to continue while whatever disputes are resolved. And our plan is for that production to come back by 2017. In terms of other factors that are out there, we are high-grading some of the investment that we're doing in the shales, so while the growth profile will be nice, it'll be a little lower. Certainly, in the gas area, we've curtailed spending. We have really gotten our costs down very well in the Marcellus. We can compete with anybody there now. But nobody makes money, that I'm aware of, at $1.50 gas, which is where we are now. And futures prices remain low. So we can compete with anybody, but for the time being, we're scaling back investment there. So these are the kinds of effects that we've rolled in as well as schedule and timing of projects. A notable change from where we had been previously, of course, is Bigfoot, which we show no production in 2017 for.

Okay. That's obviously a big factor, then. Great. And John, just as a follow up. I think you kind of answered this in your response here, but if I'm looking at the capital spend slide in the analysts meeting, I was looking at $32 billion or so of capital spend in 2016 with some flexibility around that. Is the incremental flexibility that you've identified in the numbers you put forward today mostly coming out of that base investment, which is why you're seeing the higher decline curves?

It's a little bit of both. At $70, when we presented the information that we did to you earlier, that was with the expectation that we would be able to take costs out and that certain projects would continue. So we had funding in the out years. I mean, again, some of it was ultimately discretionary around certain projects. Some of that has been removed or deferred in some cases. And that's just reflecting the realities that we're seeing lower prices. So there's some in large projects, but there is also a good chunk of it that's coming in the base investment area.

Thanks, Jason.

Thank you.

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

Thanks. Good morning everyone. Good morning, John.

Good morning, Doug.

John, I'm wondering how the – first of all, you've given a lot of information this morning. We really appreciate that, so thank you for all the disclosure. But when we get to 2017, let's assume your prognosis on oil prices or at least the supplied line balance is a little bit more optimistic. How does Chevron's sort of strategic go-forward view change in terms of, perhaps, reupping into another round of large scale projects of which you clearly have plenty of options versus being with the short cycle, I guess, flexibility until it sorts itself out? And what was really at the back of mind is I'm curious if you feel that you've got a big enough footprint to offer you that kind of flexibility. And I've got a quick follow-up, please.

Yeah, it's a very fair question. I commented a little bit earlier, as you know well, Doug. We went through this period with a number of projects stacked on top of one another. I don't think you'll ever see something like that in our – it was a series of circumstances that got us in that position. I don't think you're likely to see that. We do have a good queue of projects. I talked about the Anchor discovery which could mature into a project, and we've got others. So we'll take the best of those projects and move them forward. But I think on balance you'll see a higher proportion of shorter cycle spend. Five to seven years ago, we didn't really have a good understanding of our Permian basin position, for example. So you will see, over time, additional monies that will go to the shale developments. I mentioned that I had some reviews in my business units yesterday. I also had reviews with my four shale organizations, which are nicely sharing their successes. And the Permian is doing well. I mentioned the Marcellus is doing very well. The Duvernay in Canada, they've taken the practices and implemented them very quickly to get down the cost curve, and we're working closely with YPF and trying to put those same practice in place. We've delineated, we know where the sweet spots are down there. Now we're starting a horizontal drilling program, and we expect to get better. But I think you'll see a more balanced portfolio, and I think you'll see projects that will have good economics at moderate prices, as we work to standardize and take costs down. So we'll have some optionality in the portfolio. And I just – I can't envision having two big LNG projects at the same time. The Tengiz project is a significant capital project, but I don't see anything like having two Gorgon and Wheatstones plus several Deepwater developments stacked on top of one another.

I appreciate the answer, John. My follow-up is, really, it's kind of on the head count reduction and the fact that you are now getting to the point where these major developments are coming onstream. Are there any portfolio consequences of having to amortize or rationalize a smaller head count across a much larger portfolio? And, of course, the tail changes when Gorgon and Wheatstone come on. So I'm just wondering if outside of the disposals you've given us so far, is there another round of portfolio restructuring that we should maybe look for at some point in Chevron's future? And I'll leave it there. Thanks.

Yeah, there are some changes that will happen in the portfolio. First, just a general comment on the people reductions. One of the large areas for reductions is in Australia. As we ramp down these projects, obviously, you need fewer people. That was known, and in most cases, we had – Australia has a provision for fixed-term employees, and so those – some of those people will be coming down off – will be coming off the payroll. We've got a significant reorganization that's taking place in Angola. And frankly, as we've gone through our business units and gone through our portfolio, we have found ways to make our organization simpler. I don't know any other way to say it. And so we'll be seeing reductions in a lot of different places. Some of them have already happened, in the Marcellus in the North Sea and in our home offices. So we've season those kinds of reductions. There is some portfolio work that I would – some of it I would classify as normal as assets mature. You saw the – for example, we sold our Netherland operations. Our view was that the Chad business was sort of on that – a lot of the value had already been extracted, so we sold out of that business. So there are assets that get mature where another operator – as you know well, there are smaller companies or others that want to grind out that last little bit of value that may take on opportunities that won't fit in our portfolio. And so sometimes there's a good match for them, and we'll sell those. Those can result in reduced employees, and I expect it will. But I would classify that as a normal part of our business. These reductions don't include any huge – the reductions that were forecasted don't include a major portion of the divestitures. The divestiture portion, at this point, is looked at as maybe 10% of that employee reduction, and I would classify it as more routine activity.

Thank you, John.

Thanks very much, Doug.

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

Hey. Good morning, everybody. We've covered a lot of ground today, so thank you. John, I know other than matching the cash flows, improving upon project execution is a key focus for you and Chevron. Positive advances in the quarter. Can you discuss the changes you have made here and your confidence that execution will improve as you move through this key execution phase?

Yeah, you're right. We are focused on that. You know, Jay Johnson went through some of those in a little bit of detail, and Jay, of course, is really good on projects. And I guess I would say there are a couple of things that I would highlight. I mentioned Angola LNG earlier, and that is symptomatic of something that's hit the industry, I think, overall, and that is engineering and engineering maturity. So we simply have to – in order to have better – a better understanding of what we're going to build, we have to advance engineering further. So understanding pipe diameter and things down to a more granular level so that we know what materials we're going to need and we can do better cost estimates is, I would say, number one. You know, the example we've given is the Tengiz project, which is a big one that we'll move forward with here. But that one – we're over – we're 35% done with the engineering now, and we'll be somewhere close to 50% by the time we take final investment decisions. So that's number one. But once you complete the engineering, you also have to do more reviews of that engineering, and, I would say, at a higher level, taking a look at constructability of facilities so that you don't – so that you're sure what you build really is what you want. I'll give you an example. One of the changes we're making in Angola LNG is designing more flexibility in the front end of the plant. It's an associated gas project, and so there's greater variability in feed quality. And I think if we had done more work at the front end, perhaps, we would have designed that with more flexibility in mind. So those are the kinds of things that we're going to need to do. We also have to be very cognizant of the contracting work that is – the kind of contract that you sign and what incentives are in that contract for the contractor. And that will dictate the level of oversight better. We're likely – for example, we're likely on the Tengiz project to do more in the way of coordinating the activity of subcontractors on that job, ourselves. So all of these things, I think, are going to make us better, not to mention the usual things around quality assurance that the industry have seen and things of that sort. So the answer is, yes, we're working on improving execution.

Great. And my second question Anchor, it looks like great appraisal results. Any comments on reservoir quality, size range or next appraisal steps, and maybe even somewhat related to Doug's question before. I mean, in a down cycle, do you see an advantage in developing these longer cycle assets where you can cement or secure a lower cost structure versus an onshore asset where you benefit faster on cost savings, but you will presumably reflate over time with a higher decline rate? Maybe how do you think about that?

Yeah. We have to – we just finished the second well, and so we're going to drill – we're likely to have another appraisal well that we'll drill, but we're sort of assessing those results. It's likely to be a hub scale type development. You recall, we've said previously that hub scale assets are going to be 400 million to 500 million barrel type developments, and so we feel pretty good about this one. We've got more work to do, but we feel good. As far as doing them off-cycle, this one needs more work to do before we can progress it. So there's a cycle time to that. Costs, I don't want to give you the wrong impression, costs have come down. Deepwater rig rates, you can get deepwater rigs a lot less than previously. They have come down. I think the opportunity, if you talk to some of the equipment providers, they would say the industry can do a better job in standardizing to help them drive costs down. I think the tendency is to think we can continue to extract money out of the supply chain just based on working rates down, but we also have to work with them to help them become more efficient in what they do. And finally, some of the big cost reductions are in drilling efficiency, which I noted – which I noted earlier. So our view – just to be clear, our view is that hub class developments in that 400 million to 500 million barrel range can be developed at moderate prices that wouldn't be out of line with the kinds of prices you all are thinking about, and that tie-backs in the 100 million to 200 million barrel category can also be economic. But we're going through our plans right now doing exactly what you described in trying to decide which of these to move countercyclically and which are just going have to wait.

Makes sense. Thanks.

Thanks, Evan. Thanks

Thank you. Our next question comes from the line of Paul Sankey from Wolfe Research.

Hi, everyone.

Hey, Paul.

John, a year ago you were guiding to $40 billion of spending in 2017; now you're guiding to $20 billion to $24 billion. Can you break down what compromises that $15 billion? And just a very quick follow-up as well. Can you give us the start date for Tengiz? Thank you.

Yeah, but, you're saying a year ago. If you're saying before oil prices dropped, yeah, we were guiding to a higher level of spend because we've got a good queue of projects, and that would be the opportunity set that we would contemplate (50:27).

Yeah, I guess what I wanted to know is what projects, how much of it is cost saving, how much of it is deferred projects? Which projects have been deferred? The specifics of where we got the $15 billion to $20 billion of savings from. Thank you.

Oh, it's across the board. I mean, there are some specific projects. An example, yeah, we've talked about the Rosebank project. We've talked about the Indonesia Deepwater development project. Both of those are not in these forecasts in terms of significant spend during the planned period. I think both projects will ultimately go. Kitimat was on our list. We're pacing that project as well. Multiple Angola projects were in pre-feed, so there were a lot of projects. Bear in mind, some of these projects we think will go, and it could be that they start in the third year of the plan. But for now, a lot of these have come out, and we're going to pace them.

But I guesstimate that about half of it is cost savings from lower prices, and half is deferred projects. Is that an – I'm guesstimating. I just wonder.

Yeah, Paul. Look, I don't have a precise number for it. Certainly our view of development costs for the shales have come down significantly during that period, but I don't have a good breakdown for you on that. Sorry.

Okay, and just the start-up for Tengiz?

Well, it's a function of when we take FID, but we'll give you more details on it. But you can think of it as being into the next decade.

But just to be clear, I think that you said that the spending in the 2017 number does include some Tengiz spending?

It does. It does.

Got it.

I mean, we've been doing work to get the port ready. We've been doing work on site infrastructure. I mean, one of the lessons learned on these big capital projects is that you need to take care of some of these certainly long leads in certain cases and site infrastructure and preparation work. So we're spending some money as part of the feed work that we're doing to get greater certainty on costs. But this is a five-plus year kind of construction project, so you can think of it as being into the next decade. And we'll give you more detail after we take FID.

Thank you, sir.

Sure, thank you.

Thank, Paul.

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

Folks, good morning. Just two quick points of clarity, if I could. For one, I presume that the CapEx numbers you're providing here include equity affiliate spend. I think historically that's trended around $4 billion and has been self-funding. I'm just trying to see if, for one, making sure that, that is in there, and is that a fair estimate in those numbers? And then, secondly, U.S. natural gas has been ramping up pretty healthy as far as production is concerned. John, you mentioned a low breakeven on Marcellus. I just wanted to confirm, is that the main driver of that? Thanks a bunch.

Yeah. The answer is yes. It's $4 billion to $5 billion in equity and affiliate spend. Remember, as we ramp up the Tengiz project, we've got the CPChem project. We've got some significant spending that's taking place in affiliates. And your second question on Marcellus, we're not shutting down activity completely there. Don't get me wrong. But we're not going to be running six to eight rigs or anything like that in these kinds of conditions. Right now we've just a couple of rigs that are running there.

Okay. And John, if I could confirm this. Equity affiliates, that should remain self-funding, is that correct?

Not necessarily. I mean, in general the answer is yes. It's depending on where prices are. I mean, it depends on circumstances. Because as the Tengiz project ramps up, there is significant spend. And there are loan provisions that are being worked as a part of that project, some of which will be equity partners' loans.

Okay. Okay. Fair enough. Thank you.

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

Great. Thanks. Good morning, gentlemen. Maybe if I could follow up a little bit on some of your commentary around the longer cycle project spend. The deferrals that we've seen, I mean, I guess it comes from a combination of things, which is either lower levels of operating cash flow as well as kind of an effort to drive down project costs and improve economics. As you think going forward of where you are right now, I mean, your effort to continue to defer at this point, is it driven primarily by this point by your outlook on cash flows, or do you think that there's still a meaningful amount of either cost deflation on the projects, or, I guess, strategic engineering improvements on your end that have to happen? If cash flow is sure to improve, do you feel like you're at a point where the industry will be able to start to re-invest in those, or is there still gains to be made?

It's a fair question. I would say a lot of it is cash flow driven right now. We're still in the final throes of our revisions to the Tengiz project cost estimates, but we have a pretty good idea where that's going to land. And we have a pretty good idea of the sort of the glide path on technology and where costs are going to go for deepwater projects. But there is some uncertainty on price, and, look, I know my shareholders value our dividend. I know our shareholders value increases in the dividend. And I know they value us investing in high-return projects, and so there is some uncertainty on price. And we want to be sure that – we've kept our balance sheet in good condition, and we want to be sure we just strike that right balance to continue to pay and grow the dividend and invest in good projects. So we're just working through the cycle and kind of living within our means while we take cost down. One of the things that happens if you're taking on fewer projects is the organization will focus harder on getting more efficient at what they do. And we need to do that. We've got a very good U.S. upstream business, but we didn't make any money in this quarter. And so, we need to get more efficient at what we do, we need to look at our structures and we need to get our costs down. And in the meantime, we're going to be ready for some of the projects that I talked about earlier to move them forward. We'll have some countercyclical investment, but we do need to live within our means.

Thanks. So then maybe if I could just get your quick thoughts on maybe on global gas demand, Asian gas demand, maybe even more in particular and whether probably less is a relation to Gorgon and Wheatstone, as those are contracted to a large extent. But has there been any shift in your view on global gas demand or Asian gas demand longer term? And how would that affect potentially your longer term view on incremental LNG projects going forward?

Yeah. That's a fair question. I think overall, demand is set to grow very rapidly. And I think the conventional wisdom has been that you're just going to see natural gas displacing coal and gas demand just growing at very rapid rates. Gas has to be competitive with other options in the portfolio for these developing countries. Affordability is very much key, and so while we see literally a doubling of LNG consumption if you go out 10 years versus now, very significant growth in demand, I don't think that's changed. What has changed is the supply picture. We have seen a number of projects take FID and a number of projects are under construction, and the world economy isn't growing quite as fast as we might have thought a few years ago. It's still growing, but it isn't growing quite as rapidly as a few years ago. And so it's a well-supplied market right now. There still are contracting opportunities out there. Customers do value security of supply. They do value having a known source of supply. Not everybody wants to run their economy on spot gas. And so I think there are a number of buyers that want to firm up supply. For example, we signed a medium-term contract earlier this year, and we think there are other opportunities to do that. And as you see slowdown in FIDs on this, I think you'll see consuming countries take stock of that and start to think about additional commitments more toward – that would be more geared toward supply in the early to middle part of the next decade.

Thanks, John. I appreciate it.

Thanks, Ryan.

Sure.

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

Yeah, thank you, and good morning.

Good morning.

I guess I'd like to kind of get a little more into some of the impacts of potential production declines from – that you've mentioned from the equity spending at Tengiz, but think about spending on non-operated projects that you're on or non-operating legacy production, and how that may impact the sort of revised production guidance we should think about, or even as a challenge in the 18 and beyond world.

I'm not – what – is there a special non-op question or concern?

No, not a specific one, but let's just think about anywhere where you're not necessarily making the decision, right. You're dependent on someone else for that. How do you maybe take that into account in your forecast as a risk factor?

Well, certainly we're in dialogue with operators. For example, Total is operator in some of the West Africa projects that are potentially in the portfolio. We're an operator of some, and they're an operator of some. And so the dialogue has been pretty good. I would say the biggest area where we can get influenced, frankly, is in the Permian where we've got some smaller companies and they're very good at what they do, but their budgets can move around a little bit. But that's nothing that we can't deal with and accommodate. But I would – I don't think that's going to determine our flexibility in our capital budget.

Well, I wasn't thinking so much of capital budget as I was just - you mentioned earlier the underlying production decline kind of being close to 1% in your outlook. You're thinking maybe more of the 2% to 3%, and I'm just kind of wondering what would push you to the 3% or potentially beyond the 3% being these things that are not necessarily in your full control.

Well, it's – I'm not going to push the 2% to – I'm not going to say the change of 1% to 3% is a function of non-op decisions, because I think everyone in the industry is doing similar things now. We've been reasonably well aligned on budgets with our partners, whether we're the operator talking to them or they're the operator talking to us.

Thanks, Roger.

Thank you.

Thank you. Our next -

We've got time for one more.

Certainly. Our final question comes from the line of Doug Terreson from Evercore ISI Group.

Good morning, everybody.

Good morning.

Good morning, Doug.

John, your new capital management plan appears to be one of the more direct steps towards better capital allocation outcomes that we've seen announced thus far in a super major category on these calls. And on this point, I wanted to see if you'd elaborate a little bit on the drivers of the proposed changes. Meaning, a few minutes ago, you talked about how the cyclical element, which is in response to lower oil prices and the need for cash flow to cover the dividend at some point was part it. But also, is there an element of the new plan which relates to the more challenging, competitive condition that appeared to have been a factor for the longer term industry returns in recent years? So the question's really, what's driving the more disciplined approach to investment at Chevron internally when you guys put this together? Meaning, is it cyclical, is it secular, is it both? Could you just spend a minute on that?

Yeah. Truthfully, I would say that there's an element of all the things that you described. I think in general we were heading through a period where we had a disproportionate amount of our spend in big, long cycle projects. So we were going to head to a period where we were going to be digesting those projects and then we would supplement those with a more ratable number of long cycle projects, but then continue to invest in that new base of assets that we've acquired. And so I think that pattern is playing out. I think the issue is what can we do to enhance returns? We've said before, we took down our price deck a little bit from where we were before. And so there is a new reality in that sense, and whether that's due to industry supply conditions or the U.S. dollar or a lot of other factors that have taken commodities down, there is a new reality, if you will, in the commodity price environment for both oil and gas that we're seeing. The industry has been fabulously successful in providing supply. A lot of it is through shale, but also elsewhere. So our focus going forward directionally is consistent with what we would have done anyway. But we've taken spend down, as I commented earlier, to help us really focus on getting the most out of the assets that we have and taking costs down so that we can improve returns. It's unacceptable for us to not be able to make money at whatever commodity price the market is giving us. And that's where we are. Now, I do think commodity prices will improve, and I've said that, but we need to improve our returns. And so, I think that's the focus. And as I commented earlier, if you push the organization in that direction – I mean, we're already seeing – I mean, it's hard to put together a business plan right now because the organization is achieving good things in terms of getting our costs down, and it's hard to be forward-looking to know exactly where all the efficiencies might come from as the organization gets more focused on making the best of the assets that they have. So maybe that's the way I can describe it. So it's all of the above including taking costs out of bigger projects going forward.

Thanks, John.

Okay, so. Well, thank you very much. I would like to thank everyone for your time today. We appreciate your interest in the company. Jonathan, back to you.

Ladies and gentlemen, this concludes Chevron's third quarter 2015 earnings conference call. You may now disconnect.