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 listen-only mode. After the speakers' remarks, there will be a question-and-answer session, and instructions will be given at that time. If anyone should require assistance during the conference call, please press star then zero on your touchtone telephone. 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 two. 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 then with Slide three, 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 four, 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, our cash and cash equivalents were $13.2 billion and our net debt position was $22.6 billion. Debt issuance through nine months has amounted to $8 billion. Slide five compares current quarter earnings with the same period last year. Third quarter 2015 earnings were approximately $3.6 billion lower than third quarter 2014 results. Upstream earnings decreased $4.6 billion between quarters, virtually all of this related to significantly lower realizations between periods. Downstream results increased by $824 million, primarily driven by higher margins and favorable foreign exchange effects, partially offset by the absence of third quarter 2014 gains on asset sales.
The variance in the other segment was mainly lower environmental reserve additions, in particular, the absence of a reserve taken last year in the third quarter related to a closed mining operation. I will now compare results for the third quarter 2015 with the second quarter of 2015. Third quarter earnings were $1.5 billion higher than second quarter results. Upstream earnings increased by $2.3 billion, primarily reflecting the absence of second quarter impairments and other related charges worth $2.6 billion. Lower realizations reduced earnings between quarters. A favorable swing in foreign exchange and lower exploration expenses were largely offsetting. Downstream earnings decreased $745 million, mainly due to the absence of a $1.7 billion in asset sale gains recorded in the second quarter.
The current quarter also saw stronger margins and volumes, particularly in the U.S., favorable foreign exchange impacts, as well as lower operating expenses and positive timing effects in the face of declining prices. The variance in the other segment was primarily unfavorable tax items, partially offset by lower corporate charges. John will now provide an update on our current priorities and focus areas.
Okay, thanks, Pat. Turning to Slide seven, I would like to start by reinforcing that our 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 the time, the futures market was envisioning $70 prices in 2017. Today, the futures market is lower. 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 our 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 WoodMac 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 for the first several months of 2014. Note the spike in production when the Saudis increased production, and the shale growth continued its surge in late 2014. The result in two million barrels per day surplus has pushed prices down. Suppliers are adjusting. World production peaked and turned down last month. U.S. production, particularly shales, has peaked and is now in decline. We expect this trend to continue and accelerate at current prices. Demand is strong as low prices provide stimulus to consumers in the U.S. and elsewhere, leading to annual growth of one to one and a half million barrels per day. Markets will likely rebalance at some point next year, though seasonal demand patterns are apt to blur the exact timing.
With a new equilibrium will come price recovery, which is one of the levers that will help balance our cash equation. While we're confident in a price recovery, the timing, of course, is uncertain. We're taking actions that will allow Chevron to compete effectively in a low price environment while positioning us effectively for value growth over the longer term. Turning to slide nine. A second lever to help us balance cash flow is volume growth. As most are aware, we expect to see a significant inflection point over the next two years as a number of major capital projects move from being cash consumers to cash generators. Gorgon and Wheatstone are obvious contributors, but the list is long, starting with Lianzi in West Africa.
Over the next several quarters, we expect a progression of startups that will include Angola LNG, Mafumeira Sul, Moho Nord, Sonam, all these are in West Africa, Chuandongbei in China, the Bangka development in Indonesia, Alder in the North Sea, the Chevron Phillips Chemical project on the U.S. Gulf Coast, and of course, 3 trains at Gorgon and 2 trains at Wheatstone. Our strong shale and tight portfolio, particularly in the Permian, gives us low cost, short cycle investment opportunities that nicely supplement production growth from the major capital projects. In the shale and tight class, our focus is on high-grading our investment opportunities to maximize returns and cash flow. We like our portfolio diversity, which, when market conditions improve, will provide growth opportunities. Turning to slide 10. We're in the final stages of commissioning systems to allow startup of train 1 at Gorgon.
At the plant, our focus is on starting up the process units ahead of commencing liquefaction. An LNG cooldown cargo is planned to arrive mid-December to assist in cooling down the LNG tanks and associated facilities prior to first LNG export. The Jansz-Io field subsea infrastructure is fully complete. We have opened the first two wells to the Jansz pipeline, confirming the full operability of these subsea systems. Our current outlook for loading the first LNG cargo is early 2016. We are continuing to make good progress on trains two and three, with all train two and nine of 13 train three modules installed and hookups underway. At Wheatstone, all subsea infrastructure and over 100 kilometers of flow lines have been installed. Hookup and commissioning of the offshore platform continues on plan.
All nine wells are drilled to the top of the reservoir, with four of nine wells now completed and subsea trees installed. At the plant, 17 of the 24 modules required for first LNG have been delivered, and all refrigeration compressors and gas turbine generators have been installed. Installation of all pipe racks and electrical switchgear buildings on the product loading facility is now complete, as is startup of the power systems in the plant operations center. We are still targeting the first LNG cargo by year-end 2016. We continue to work to mitigate Wheatstone schedule pressures from previous delays in module delivery. We've posted some new pictures today, and I encourage you to look at them on our investor website at chevron.com. Turning to slide 11. Another lever to deliver free cash flow is reduced capital spending.
As indicated during our March Analyst Day, we have significant flexibility in our capital program as we complete projects under construction. Given the near term price outlook, we are exercising more discretion in pacing projects that have not reached Final Investment Decision. We are also negotiating cost reductions from suppliers. Overall, our investment programs are being set at levels that will enable us to complete and ramp up the projects under construction, fund high return short cycle investments, preserve options for viable long cycle projects, and finally, ensure safe, reliable operations. We expect capital exploratory spend in 2016 to be in the range of $25 billion-$28 billion, down from $35 billion this year. We expect further reductions in 2017 and 2018 into the $20 billion-$24 billion range, depending on business conditions.
Of specific note, the plan does include funding for the Wellhead Pressure Management and future growth project at Tengiz in Kazakhstan, which has undergone rigorous engineering and readiness reviews based on our learnings from other projects. Turning to slide 12, to another cash flow improvement lever. We're working on reducing costs across the company and are beginning to see the results. Compared to prior year date periods, enterprise operating costs are 7% lower. In the third quarter to third quarter comparison, they're 12% lower. On another basis, year-to-date upstream unit operating expenses are down 13% versus last year. At this point, we have identified spend reductions of approximately $4 billion on an annual full run rate basis. About half of this is coming through organizational reviews and portfolio rationalization, and about half working through the supply chain.
On the organizational side, lower investment activity, portfolio changes, and efficiency reviews across the upstream gas and midstream and the corporate and service company groups are expected to result in employee reductions of between 6,000 to 7,000. A similar number of contractor reductions are anticipated over the same period. Supply chain initiatives, including rate reductions, greater equipment standardization, project rescoping, and timing optimization, are expected to contribute approximately $2 billion also on an annual run rate basis. An example, we're leveraging our enterprise spend for drill pipe across the company, and we're seeing cost reductions of up to 35%. These supply chain benefits will show up as lower operating expense, lower capital expenditures, and lower cost of goods sold. Finally, we're seeing efficiency improvements throughout the organization, which are driving improved value capture.
As an example, in the last year, we have seen the drilling cycle time from spud to rig release reduced by 55% within our Permian horizontal drilling program. Turning to Slide 13. A final cash flow lever is asset sales. These are a normal part of portfolio work and contribute proceeds to help manage the balance sheet. We divest assets that no longer have a strategic fit or where we no longer see the cost-effective application of our technology, where future investments do not compete for capital within our portfolio, and where we can obtain good value. There are a number of drivers on asset sales. As you know, we made a commitment to generate $15 billion from the asset sales program from 2014 through 2017, and over the last seven quarters, we've made real good progress and achieved $11 billion of this goal.
From today out through 2017, we could see another $10 billion in sales proceeds. There's a range around this new expectation because of uncertainties on future market conditions. We're only going to sell assets where we can obtain good value. Turning to Slide 14. We expect to end this year within the production guidance range we provided back in January. Over the next couple of years, you will see the growth projects we've talked about for some time come on stream. Gorgon, Wheatstone, and Angola LNG are collectively expected to provide the majority of our volume growth. This growth will not be realized at one time, as there's a ramp-up over three years, and there is variability depending upon start date. We expect offshore projects, the majority coming from West Africa, also to be a significant part of our growth.
Our projected shale and tight ramp-up is steady, though the current price environment is expected to lead to a slower pace of growth than we anticipated at our March Analyst Day. Similarly, our future base business spending is influenced by the current environment and its impact on economics and partner funding capabilities. We anticipate lower base business spending and, as a result, expect to see higher decline rates compared to our more recent pattern. Under these assumptions, we're anticipating a 13%-15% increase in volume, 3 million barrels per day in 2017. Note, this range excludes the impact of divestments. Their specific timing is difficult to predict. Actual production growth is also dependent upon production sharing contract effects and the partition zone restart timing. We will issue further guidance for 2016 production as we normally would in January. Turning to Slide 15.
That brings me back where I started. We like the go-forward prospect for energy as we are constructive on the long-term price outlook, sober about the current realities of lower prices. We have consistent and clear financial priorities. We are taking significant action to balance the cash equations and cover the dividend with free cash flow by 2017. We expect to deliver volume growth and emerge on the other side of this downturn leaner and better. All of our actions are geared toward delivering value through dividend growth and stock price appreciation. That concludes our prepared remarks. We're now ready to take some questions. Keep in mind that we have a full queue, please try to limit yourself to one question and one follow-up if necessary. We'll do our best to get all of your questions answered. Jonathan, please open the lines for questions.
Thank you. Ladies and gentlemen, if you have a question at this time, please press star then one on your touch tone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. If you're listening on a speakerphone, we ask that you please lift your handset before asking your question to provide optimum sound quality. Again, if you have a question, please press star then one on your touch tone telephone. Our first question comes from the line of Phil Gresh from JP Morgan.
Hi, good morning.
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 to dividend coverage at a point in the cycle rather than through the cycle. I fully appreciate Chevron has a full stable of capital projects over these past few years, so the spending flexibility is very high. 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?
Yeah. 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, 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 from following the moratorium in the Gulf of Mexico, we started it at the same time. We went through a period of capital spend that was pretty high.
We thought these were very good projects, there's no doubt that we were going through a period of heavy capital spend, we kept our balance sheet pretty strong to enable us to withstand the ups and downs that we see in the market. We saw prices rise dramatically, we've seen them come back down a little harder than we thought. We do have to manage through this cycle, 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, we do have to live within our means here. 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 prices.
We do invest through the cycle with some of these long projects. We have to be able to do that. We have had a period of heavy spend that we've had to go through. There is an adjustment when prices go from 100 to 50, we're just having to deal with that. Certainly, we're investing through the cycle, making some adjustments to deal with the low prices we've got.
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%-1.5% range, and so that's probably a more reasonable expectation going forward. 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. 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.
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. That's a significant project 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. That and other investments will provide growth going forward.
Sure. Okay.
Thanks, Phil.
Thank you.
Thank you. Our next question comes to the line of Paul Cheng from Barclays. Your question, please.
Thank you. Hey, guys. Good morning.
Morning, Paul. How you doing, Paul?
Very good, thank you. John, two question. One is really short. Let me go for that first. With the cutback in the CapEx, you're saying that the base operation decline rate will be higher? I think for the last five year, you guys been about 3%-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%, or it's been less than 2%, certainly during that period. We see it being more like 3%. 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 the hallmark for Chevron has always been on the LNG deep water mega project development. I think the market is concerned this type of development, the supply cost curve has increasingly towards the last several year 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 soft cycle. The question is that, do you agree with that view and is concerned that the hallmark of the company, what you're good at, end up that to be at the high end of the supply cost curve?
If you sort of agree with that, what initiative that Chevron is taking to trying 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. I think that's just factually true, particularly in the U.S., but also around the world. Rig rates and service costs, things of that sort. That certainly is true. It's also true that some short cycle based business spend traditionally has lower costs once you have infrastructure in place, and it's certainly 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, but also, of course, in every other producing asset.
It's going to take contributions from all asset classes to meet demand. We're going to need all forms of supply. What we're doing is trying to take on cost reductions and get better everywhere to take costs down. We've been able to do that. We've shown you some charts periodically in the-- Offshore is about 25% of worldwide production, and deep water production, it continues to grow and will continue to make contributions to worldwide supply. If you look at drilling and completions technology, we've talked about things like the single trip multi-zone frac pack, which is just a more efficient way of getting 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 costs down. In fact, in our Gulf of Mexico operations, our deep water, we've been able to reduce drilling days significantly. Our drilling days per 10,000 feet are down 25% over the last two years. We've been able to take those costs down. I think you're also likely to see the work that we did in the Gulf of Mexico to consolidate holdings, for the industry to collaborate, to create hub class developments will also help with economies of scale. I think you'll see bigger hubs. I think all classes of assets at the current low prices will have some spending that will fall out.
Some of your points are true, but I think you'll see cost over time come down everywhere. Of course, these projects are over a long period of time. LNG are 40-year projects, so you have a different life cycle to these things as well, which can impact. Some of the long cycle LNG, 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. They have a little different characteristic to them.
Thank you.
Thanks, Paul.
Okay.
Thanks very much.
Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question, please.
Yeah, good morning, thanks for all of the color. Just on the opening remarks, I think you said slower ramp up on projects. 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. Key is getting them started and getting first LNG, the ramp up will take place over time. 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. I was pleased with the progress that I heard. I gave you some of the kind of proof points to where we're headed there. ALNG will start up early next year as well.
There's no secret that this has been a challenge as we've worked through some of the engineering issues. 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. ALNG will start up early next year as well. 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. What I mean by that is with some delay in modules, we're really now looking at bulk construction timing and some of the startup 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 of Australia and Gorgon, really looking to see if we can take time out of those schedules by really taking all the best practices that were effective in those projects to keep us back on a fourth quarter 2016 startup schedule. The work is progressing well. The point in having a range on production is really that a quarter one way or another, when you've got projects that go up to 200,000 barrels a day at full capacity makes a difference. It's just reflecting that reality.
Yeah. Okay. Second question's on cash flow, maybe for Pat or John. You can see this year you've done $17.2 billion before working capital, you could gross that up and say $23 billion. You've got these new projects, they'll add cash and your cash CapEx is going down. Sorry, your overall group CapEx is going down to $20 billion to $24 billion. You can see how the dividends are sustainable in sort of this year conditions. That works fine. It's still a long way away from the cash flow that was presented a few years back at higher oil prices. I guess my question is there anything this year in the cash generation of the company that you feel has underperformed? I guess the downstream has been pretty strong.
Well-
Maybe it's startup costs in some of these projects.
No. Actually, I think if you look at our cash flow and the rule of thumb that we gave you for the effect of oil prices was roughly $350 million after-tax and earnings and cash flow for every $1 per barrel, you multiply it by the change in barrels, I 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, 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. In fact, it's better because our downstream has performed so well.
The grim reality is when you have oil prices in the 40s, as we saw in the third quarter, as you look across the sector, particularly in the U.S., it's tough sledding. If you've got natural gas prices where they are in the U.S., it's a challenge. 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, 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 cost and spend.
It's just oil sensitivity. I understand. Thanks.
Right. 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 the drivers here, John, but I was just trying to reconcile the new production range of 2.9-3.0 relative to the 3.1 million barrels a day that was presented at the analyst meeting. I wasn't really clear whether the partition zone was included in the 2.9-3.0 or whether it's out, because that's obviously a big reconciling factor. 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. 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. If you add 2% to the decline, that's 100,000 barrels a day over a couple of years. That's number one. To answer your question about the partition zone, that production a year ago was roughly 80,000 barrels a day, and if you look at where we expected 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 partition zone between Saudi Arabia and Kuwait. It's in the Kuwaiti portion of the zone, they administer work visas, equipment permits, and things like that, and they stopped issuing them. We ended up shutting in in May, 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. Saudi Arabia is able to increase production elsewhere.
I think there's motivation for the Kuwaitis to begin issuing work permits and allowing work to continue while whatever disputes are resolved. 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. 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. We can compete with anybody, but for the time being, we're scaling back investment there.
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. 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 from, again, the analyst 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. We had funding in those out years. Again, some of it was ultimately discretionary around certain projects. Some of that has been removed or deferred, in some cases. That's just reflecting the realities that we're seeing lower prices. There is 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.
Morning, Doug.
John, first of all, you've given a lot of information this morning. We really appreciate that, thank you for all the disclosure. When we get to 2017, let's assume your prognosis on oil prices, or at least the supply-demand balance is a little bit more optimistic. How does Chevron's sort of strategic go forward view change in terms of perhaps re-upping into another round of large-scale projects, of which you clearly have plenty of options, versus staying with the short cycle, I guess, flexibility until this sorts itself out? What's really at the back of my mind is I'm curious if you feel that you've got a big enough footprint to offer you that kind of flexibility. I've got a quick follow-up, please.
Yeah, it's a very fair question. I comment 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 portfolio. 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, we've got others. We'll take the best of those projects and move them forward. 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. You will see over time additional monies that will go to the shale developments.
I mentioned that I had some reviews with my business units yesterday. I also had reviews with my four shale organizations, which are nicely sharing their successes. 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, we're working closely with YPF, trying to put those same practices in place. We've delineated. We know where the sweet spots are down there. We're starting a horizontal drilling program, we expect to get better. I think you'll see a more balanced portfolio, I think you'll see projects that will have good economics at moderate prices as we work to standardize and take costs down. We'll have some optionality in the portfolio.
I can't envision having two big LNG projects at the same time. The Tengiz project is a significant capital project, 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 kind of on the headcount reduction and the fact that you are now getting to the point where these major developments are coming on stream. Are there any portfolio consequences of having to amortize or rationalize a smaller headcount across a much larger portfolio? Of course, the tail changes when Gorgon and Wheatstone come on. 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.
Excuse me. 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, Australia has a provision for fixed-term employees, and some of those people will be coming off the payroll. We've got a significant reorganization that's taking place in Angola. 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. 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. We've seen those kinds of reductions.
There is some portfolio work that some of it I would classify as normal as assets mature. You saw that, for example, we sold our Netherlands operations. Our view was that the Chad business was sort of on that a lot of the value had already been extracted. We sold out of that business. 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. Sometimes there's a good match for them, and we'll sell those. Those can result in reduced employees, and I expect it will. I would classify that as a normal part of our business.
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. I would classify it as more routine activity.
Thanks very much, sir.
Thanks, Doug.
Thanks.
Thank you. Our next question comes from the line of Evan Calio from Morgan Stanley.
Hey, good morning, everybody.
Good morning.
You've covered a lot of ground today. 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've made here and your confidence that execution will improve as you move through this key execution phase?
You're right. We are focused on that. Jay Johnson went through some of those in a little bit of detail, Jay, of course, is really good on projects. 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. That is engineering and engineering maturity. We simply have to, in order to have a better understanding of what we're going to build, we have to advance engineering further. 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.
The example we've given is the Tengiz Project, which is a big one that we'll move forward with here. That one, we're 35% done with the engineering now, and we'll be somewhere close to 50% by the time we take final investment decisions. That's number one. Once you complete the engineering, you also have to do more reviews of that engineering. I would say at a higher level, taking a look at constructability of facilities 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, there's greater variability in feed quality.
I think if we had done more work at the front end, perhaps we would have designed that with more flexibility in mind. 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. 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. All of these things, I think, are going to make us better, not to mention the usual things around quality assurance that the industry has seen and things of that sort. The answer is, yes, we're working on improving execution.
Great. My second question on Anchor, it looks like great appraisal results. Any comments around reservoir quality, size range or next appraisal steps and maybe even somewhat related to Doug's question before? In the 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've benefited faster on cost savings, but you will, I presume, they'll reflate over time with a higher decline rate? Maybe how you think about that?
Yeah. We just finished the second well, we're likely to have another appraisal well that will be drilled. 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-500 million barrel type developments, and we feel pretty good about this one. We've got more work to do, but we feel pretty good. As far as doing them off cycle, this one needs more work to do before we can progress it. There's a cycle time to that. Costs, I don't want to give you the wrong impression. Costs have come down. Deep water rig rates, you can get deep water 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. Finally, some of the big cost reductions are in drilling efficiency, which I noted earlier. Just to be clear, our view is that hub class developments in that 400 million-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 tiebacks, in the 100 million-200 million barrel category can also be economic.
We're going through our plans right now, doing exactly what you described in trying to decide which of these to move counter-cyclically and which are just going to have to wait.
Makes sense. Nice talking to you.
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-$24 billion. Can you break down what comprises that $15 billion? Just a very quick follow-up as well, can you give us the start date for Tengiz? Thank you.
Well, 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.
Yeah, I guess what I wanted to know is how much of it's cost saving, how much of it is deferred projects, which projects have been deferred, the specifics of where we got the $15 billion-$20 billion of savings from? Thanks.
Oh, it's across the board. There are some specific projects. An example, 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 plan 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. 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. For now, a lot of these have come out, and we're going to pace them.
Would I guesstimate that about half of it's cost savings from lower prices and half is deferred projects? I'm guesstimating. I just wondered.
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. I don't have a good breakdown for you on that, sorry.
Okay. 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.
Just to be clear, I think that you said that the spending in the 2017 number does include some Tengiz spending?
It does.
Got it.
It does. We've been doing work to get the port ready. We've been doing work on site infrastructure. One of the lessons learned on these big capital projects is that you need to take care of some of these long leads in certain cases, and site infrastructure and preparation work. We're spending some money as a part of the FEED work that we're doing to get greater certainty on costs. This is a 5-plus year construction project, so you can think of it as being into the next decade. We'll give you more detail after we take FID.
Thank you, sir.
Sure.
Thanks, Paul.
Thank you.
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? Then secondly, U.S. natural gas has been ramping up pretty healthy as far as production is concerned. John, you mentioned a low break even 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-$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. Your second question on Marcellus, we're not shutting down activity completely there, don't get me wrong. We're not going to be running six to eight rigs or anything like that in these kinds of conditions. Right now, we've got just a couple of rigs that are running there.
Okay. John, if I could just confirm, those equity affiliates, that should remain self-funding. Is that correct?
Not necessarily. In general, the answer is yes. Depending upon where prices are, 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. 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 guess it comes from a combination of things, which is either lower levels of operating cash flow, as well as an effort to drive down project costs and improve economics. As you think going forward and of where you are right now, 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 strategic engineering improvements on your end that have to happen?
If cash flows were to improve, do you feel like you're at a point where the industry would be able to start to reinvest in those, or is there still some gains to be made?
Yeah. 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. We have a pretty good idea of the glide path on technology and where costs are going to go for deep water projects. 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. There is some uncertainty on price, and 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.
We're just working through the cycle and kind of living within our means while we take costs 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. 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. 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. 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 counter-cyclical investment, but we do need to live within our means.
Great. Thanks. Maybe if I could just get your quick thoughts on global gas demand, Asian gas demand, maybe even more in particular on weather. Probably less as a relation to Gorgon and Wheatstone as those are contracted to a large extent. 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. 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. While we see literally a doubling of LNG consumption if you go out 10 years versus now, a 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.
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. 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. 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 that would be more geared towards supply in the early to middle part of the next decade.
Great. Thanks, John. I appreciate it.
Sure.
Thank you. Our next question comes from the line of Roger Read from Wells Fargo.
Yeah, thank you and good morning.
Morning.
I guess I'd like to kind of get a little more into some of the impacts of potential production declines. You mentioned some of 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 2018 and beyond world.
Is there a specific 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.
Yeah.
How do you maybe take that into account in your forecast as a risk factor?
Oh, yeah. Well, certainly we're in dialogue with operators. For example, Total's operator on some of the West Africa projects that are potentially in the portfolio. We're an operator of some, they're an operator of some. The dialogue's been pretty good. I would say the biggest area where we can get influence, 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. That's nothing that we can't deal with and accommodate. I don't think that's going to determine our flexibility in our capital budget.
Well, I wasn't thinking so much a capital budget as I was just you mentioned earlier the underlying production decline kind of been 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 aren't necessarily in your full control.
Well, I'm not going to say the change from 1% to 3% is a function of non-op decisions. 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 question.
We've got time for one more.
Certainly. Our final question comes from the line of Doug Terreson from Evercore ISI.
Good morning, everybody.
Morning.
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. On this point, I wanted to see if you'd elaborate a little bit on the drivers of the proposed changes. 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 of it. 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? The question is really what's driving the more disciplined approach to investment at Chevron internally when you guys put this together?
Is it cyclical? Is it secular? Is it both? Could you just spend a minute on that?
Yeah. Truthfully, I would say 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. We were going to head to a period where we were going to be digesting those projects, then we would supplement those with a more ratable number of long cycle projects, then continue to invest in that new base of assets that we've acquired. I think that pattern is playing out. I think the issue is what can we do to enhance returns? We said before, we took down our price deck a little bit from where we were before. There is a new reality in that sense.
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, also elsewhere. Our focus going forward directionally is consistent with what we would have done anyway, 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, that's where we are.
I do think commodity prices will improve, and I've said that, but we need to improve our returns. I think that's the focus. I commented earlier, if you push the organization in that direction, I mean, we're already seeing. 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. Maybe that's the way I can describe it. It's all the above, including taking costs out of bigger projects going forward. Okay.
Thanks, John.
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.