Good morning. My name is Jonathan, I will be your conference facilitator today. Welcome to Chevron's fourth quarter 2016 earnings conference call. At this time, all participants are in listen only mode. After the speaker's remarks, there will be a question and answer session, 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 will now turn the conference call over to the Chairman and Chief Executive Officer of Chevron Corporation, Mr. John Watson. Please go ahead.
Thanks, Jonathan. Welcome to Chevron's fourth quarter earnings conference call and webcast. On the call with me today are Pat Yarrington, our Vice President and Chief Financial Officer, 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 review the cautionary statement on slide two. Okay, let's start with the key messages on slide three. I've said we needed to do five things well to adjust to lower prices. First, finish projects under construction, which reduces spend and brings on new revenue. Gorgon Train One and Train Two, Chuandongbei, Bangka, Alder, Angola LNG are all on production and stable. In 2017, progress will continue with Gorgon Train Three and Wheatstone coming online.
Second, we need to reduce capital expenditures and focus on work that's profitable at lower prices. 2016 capital was down 34%, or $11.6 billion from 2015. We're further reducing capital spending in 2017 and investing a larger percentage of capital in short cycle, high return opportunities presented by our advantage portfolio. Third, we're lowering operating expenses by getting more efficient in all that we do. 2016 operating expense was down 9%, or $2.5 billion from 2015, we expect further reductions in 2017. Fourth, we need to complete planned asset sales. We're on track with $2.8 billion in proceeds in 2016, we expect 2017 proceeds will likely move us towards the upper end of the 2016-17 guidance range of $5 billion-$10 billion we previously communicated. Finally, we need to do all of this while operating safely and reliably.
The result, free cash flow is improving with momentum building through 2016. We expect to be cash balanced in 2017, the cash flow improvement to continue into 2018 and beyond. Our actions support our number one financial priority, which is maintaining and growing the dividend as the pattern of earnings and cash flow permit. Turning to slide four. Chevron's total shareholder return outpaced our major competitors and the S&P 500 in 2016, is number one relative to our peers for any cumulative holding period going back 20 years. We appreciate the support from our investors, recognize markets are forward-looking and expectations are high. We need to continue to deliver on our commitments and manage our advantage portfolio for growing cash flow and competitive returns. Pat will now take you through the financial results.
Okay. Thank you, John. Turning now to slide five, which is an overview of our financial performance. The company's fourth quarter earnings were $415 million, or $0.22 per diluted share. While earnings for the full year 2016 were a loss of $497 million. Excluding special items and foreign exchange, Chevron earned $1.8 billion in 2016. A detailed reconciliation of special items and foreign exchange is included in the appendix to this presentation. Fourth quarter results were impacted by non-routine items and timing effects. Downstream results were weak, reflecting adverse timing effects because of a rising crude price environment and an extensive turnaround at the Richmond Refinery, a once in every five-year event. At the same time, fourth quarter corporate charges, which are known to be non-ratable, were heavier than an average quarter. Our debt ratio at year-end was 24%.
During the fourth quarter, we paid $2 billion in dividends, bringing our total for the year to $8 billion or $4.29 per share. 2016 was our 29th consecutive year of an annual per share increase. We currently yield 3.7%. Turning to slide six. Cash generated from operations was $3.9 billion during the fourth quarter. Fourth quarter cash flow benefited from stronger oil prices, but had offsets from seasonal downstream margin patterns and the Richmond Refinery turnaround. On a year-to-date basis, operating cash flow totaled $12.8 billion, a function of low oil and gas prices and weaker downstream margins than in 2015. 2016 working capital consumption of approximately $600 million and lower affiliate dividends relative to earnings reduced operating cash. We had deferred tax items of nearly $4 billion, for example, those associated with tax loss positions. These will benefit cash in future periods.
Proceeds from asset sales for 2016 were $2.8 billion. Cash capital expenditures were $4 billion for the quarter and about $18 billion for the full year, excluding expensed exploration. This continues a trend towards lower outlays. At year-end, our cash and cash equivalents totaled $7 billion. Our net debt stood at $39 billion, resulting in a net debt ratio of approximately 21%. Turning to slide seven. Slide seven compares 2016 annual earnings to 2015. Full year 2016 results were a loss of $497 million, or approximately $5 billion lower than the 2015 result. The impact of special items, primarily due to lower gains on asset sales, reduced earnings by $515 million. Lower foreign exchange gains decreased earnings by about $710 million. Upstream earnings, excluding special items and foreign exchange, decreased $798 million between periods, as lower realizations were only partly offset by lower operating costs and exploration expense.
Downstream results, excluding special items and foreign exchange, decreased by $2.8 billion, primarily due to lower margins. Recall that 2015 downstream margins were among the strongest we've seen in a number of years. The variance in the other segment primarily reflects higher corporate charges and interest expense. Full year 2016 results are in line with our standing guidance of $350 million-$400 million in net charges per quarter for the other segment. Turning to slide eight. I'll now compare results for the fourth quarter of 2016 with the third quarter of 2016. Fourth quarter results were approximately $870 million lower than the third quarter. The absence of third quarter 2016 gains from special items reduced earnings by $290 million between periods. Lower foreign exchange gains reduced earnings by approximately $50 million between periods.
Upstream results, excluding special items and foreign exchange, increased approximately $850 million between quarters, primarily reflecting higher crude realizations, higher volumes, and lower taxes. Downstream earnings, excluding special items and foreign exchange, were lower by $765 million. This outcome was primarily driven by decreased volumes and increased operating expense associated with the Richmond Refinery turnaround, lower worldwide margins, and an unfavorable swing in inventory timing effects. The variance in the other segment is largely driven by adverse tax effects and corporate charges. These impacts are non-ratable and tend to fluctuate from quarter to quarter. Now I'll turn it back to John.
Okay. Thanks, Pat. Turning to slide nine. 2016 capital spending was $22.4 billion. That's approximately $4 billion less than our original budget and more than $11 billion lower than last year. Cash C&E was $18.7 billion. Productions are mainly from finishing our major projects under construction, pacing and high-grading future investment, and realizing efficiency gains and supplier cost reductions. In December, we announced a total capital and exploratory budget for 2017 of $19.8 billion, which is right in the middle of our $17 billion-$22 billion guidance range for the period out to 2020. Cash capital and exploratory expenditures, which exclude affiliate spend, are expected to be $15.1 billion. 70% of our expenditures in 2017 will generate cash flow within two years, reducing cash flow cycle time and financial risk.
2016 operating expense was $25 billion, better than we had most recently guided and more than $2.5 billion less than last year. We're sizing the organization to fit the work we anticipate. Our employee workforce is down 9,500 since the end of 2014. We've improved work processes and have negotiated better rates from contractors and vendors. Upstream operating expenses, excluding fuel, are down nearly $3 per barrel since 2014. Most significant workforce reductions are behind us, but our focus on improving efficiencies in all aspects of the business continue, and we expect further progress on OpEx in 2017 and beyond. Slide 10 shows the sources of changes in production between 2015 and 2016. 2016 net production was 2.6 million barrels per day. Growth continues from completing and ramping up major capital projects. Our short cycle shale and base business work was excellent, particularly in light of significant reductions in spending.
We limited declines in mature fields by improvements in reliability and drilling work and an effective workover program. Production was impacted by the ongoing shut-in of the Partitioned Zone, security issues in Nigeria, and Gulf of Mexico asset sales. Looking at the fourth quarter bar, you see that the fourth quarter was strong and production growth is accelerating. As we start the year, two trains at Gorgon are running near capacity, Angola LNG is operating well, and the successful Agbami and TCO maintenance shutdowns are behind us. We expect production growth this year of 4%-9% at $50 per barrel before asset sales. The uncertainty reflects variables such as the speed of major capital project ramp-ups, external events such as the timing of the Partitioned Zone restart, and our ultimate base decline rates. Growth comes from a number of areas.
First, we expect to see full-year production from projects started up in 2016, Gorgon Train 1 and 2, Chuandongbei , Angola LNG, Alder, Bangka. We also expect to see partial year contributions for projects starting up in 2017, Gorgon Train 3, Wheatstone, and Mafumeira Sul, for example. Shale and tight production, headlined by the Permian, will also show growth as we take advantage of our valuable acreage. Base declines, along with full-year 2017 impacts of sales consummated in 2016 will both reduce production. The impact of 2017 asset sales on the timing of the close of the individual transaction is one variable. Our current estimate is a reduction of 50,000-100,000 barrels a day. Turning to slide 12. The chart on the left side shows our $5 billion-$10 billion guidance range for asset sale proceeds for 2016 and 2017.
In 2016, we made good progress with $2.8 billion in proceeds as we sold assets for value that were not essential to delivering on strategy, didn't compete for capital with our current opportunity set, and were worth more to others than to us. Additional opportunities are in progress and many will close in 2017. We expect proceeds close to the top of the guidance range. With new assets coming online and the benefits of portfolio actions, we expect to increase cash margins. The chart on the right shows a doubling of production in the more than $25 per barrel category and a reduction in low-margin barrels. Despite the sharp reduction in capital spending, we had a strong reserves replacement year, exceeding 100% before asset sales for the one- and five-year periods. We saw significant adds from the Final Investment Decision on TCO's future growth project.
Additionally, there were reserves added from improved reservoir characterization in several areas and strong well performance in shale and tight in various other locations. Lower commodity prices benefited entitlement volumes from profit sharing and variable royalty contracts. This was partially offset by lower economic producibility in a few assets. Asset sales resulted in an RRR reserve replacement rate slightly below 100%. Consistent with the expectation of 2017 asset sales impacting production, we also expect an impact on 2017 reserves from these sales. Let's talk now about some of the major activity starting with Gorgon. Gorgon currently is stable, with gross output of over 200,000 barrels a day and 130 million cubic feet of domestic gas output. A total of 39 cargoes have been shipped, 10 since the beginning of the year. Train 1 ramp-up was below expectations as we worked through startup issues we've discussed previously.
All learnings from Train 1 were applied to Train 2, and consequently, Train 2 ramped up to over 90% of capacity within a week and continues to exceed expectations. Train 3 is also expected to benefit from these learnings. Construction is complete, and we're well into startup and commissioning. We expect first LNG early in the second quarter of this year. At Wheatstone, our outlook for first LNG remains mid-2017. All modules for Train 1 and Train 2 are on their foundations, and the site is under permanent power. Ongoing hookup and commissioning of the offshore platform is the critical path activity. We're leveraging our experience from Gorgon and incorporating learnings into our ongoing activities. We expect Train 2 to start up 6-8 months following Train 1. Turning to the Permian, we're making excellent progress.
Last year, we lowered unit development costs by 20% and lowered unit operating costs by 35% compared to 2015. We're improving recoveries, and our results are validating expectations around improvements in type curves. We're currently running 10 company-operated rigs, and we're adding a new rig about every eight weeks. The story keeps getting better. We'll update this chart and provide much more information about our Permian operations at our Analyst Day in March. That concludes our prepared remarks. We're now ready to take some questions. Keep in mind we actually have a very full queue, so please try to limit yourself to one question and one follow-up if necessary, and we'll do our best to get all of your questions answered. Thanks. Jonathan, please open the lines for questions.
Certainly. 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 a question to provide optimum sound quality. Again, if you have a question, please press star then one. Our first question comes from the line of Phil Gresh from JP Morgan. Your question please.
Hi, good morning.
Hey, Phil.
Hey, Phil.
I just want to start on the 2017 production guidance. If I look at that guidance, maybe on an absolute volume basis at the midpoint, maybe around 2.75 million barrels a day, I know it's a little bit stale, but a couple of years ago, you had talked about a 2.9 to 3.0 type of range, obviously a lot has changed from then to now. I was hoping maybe you could help bridge some of those moving pieces between project timing, asset sales, P&D effects, and really just trying to think through ultimately after 2017, how much additional uplift to volumes there would be from projects.
Yeah, it's a good question. If you go back to that time, we did put an estimate in the 2.9 to 3 range, actually the results we're showing you now are very consistent with that, with a couple of exceptions. The first and obvious one is the Partitioned Z one. We expected we'd be back up and operating, that's about 70,000 barrels a day. That's a clear delta. The second is the effects of asset sales that we didn't anticipate at that time. If you add up what's already closed, you can get another 70,000 barrels a day pretty quickly. You put those two together, that's 150,000 barrels a day, that really explains it. Now, as you point out, there are some other ups and downs notably some delays in capital projects, the flip side of that is we got benefits.
The shale and tight volume is growing. Jack/St. Malo's performed better than we expected. We have a little bit of benefit from price effects. Those about offset. The two big items are really the partition zone and asset sales, you get right back into the zone we talked about.
Okay, got it. That's very helpful. The second question would just be on the longer-term CapEx budget. Looking at the bars that you gave for 2017, there's still $2 billion in there for Gorgon and Wheatstone, and then another $2 billion plus it looks like, just looking at the bars for projects that are outside of Tengiz. I guess I was just wondering how you're thinking about that $17-$22 range, especially as we look at 2018 and you potentially have a couple of billion still rolling off. Are there a lot of projects in the queue that you think work in the mid-$50s, or how are you thinking about that now?
Yeah. First, if I go back a year and you told me we'd be able to get our spending, do all the work we did this year, and have spending of $22.4, I wouldn't have believed it. We've made remarkable progress in bringing our cost down. I had my drilling guy in the other day, and he gave me an example. The wells we drilled in 2016, if we had had the productivity we had in 2014, we would've spent $1 billion more. The drilling efficiencies that we have put in place, and that was just in the deep water. The efficiencies we've put in place have allowed us to bring down costs. The trend of spend is down. As you point out, we have some major capital projects that are being completed.
If we're still in the $50-$55 world, you'll see us tracking at the bottom end of that range. We're showing a range out to 2020. That's a four-year period. When you think out over that time period, obviously a lot of things can change. Notably, I would expect that we would see an increase in unconventional spending. We've talked about ramping up the Permian, and I think that'll be the case. We're budgeting about $2 billion this year, but you could easily see another $1 billion there. We have very little activity in the Marcellus now. We've gotten very efficient there, we would expect better market conditions and offtake capability there. We've made good progress in the Duvernay, Argentina. Just in the shale and tight area, you could see some increases. Again, that's short cycle, high return activity.
We do have some opportunities in the portfolio that if we continue to make good progress on concepts and delineation drilling, things like Anchor and Tigris, and we've highlighted Rosebank and a few others. We have a good queue of projects, we need to make sure that those have the right economics associated with them. All of that can comfortably fit in the range that we've talked about. I'll just say that if we're at $50-$55, you should expect spending to go down next year.
Thanks, Phil.
Thanks, John.
Okay.
Next? Sure. Thank you.
Thank you. Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your question, please.
Thanks. Good morning, everybody.
Morning, Doug.
John, you've normally talked about the base business and the tight unconventional business in the same breath as one offsetting the declines in the other. I guess my first question is in the context of decline rates and maintenance spending, your budget this year puts that number about $8.5 billion. Is that how we should interpret Chevron's definition of maintenance CapEx on a go-forward basis, at least for the portfolio as it stands today?
Yeah, I think that's right. If I understand the question, we've been trying to isolate the shale from the other base business activity just because it's such a high profile activity. The fundamental nature of it has a lot of similarities with base business in the sense that it's relatively short cycle activity, and it has to compete for capital with, for example, infill drilling in Bakersfield or Thailand or places like that. I think that's the right way to look at it, and that's why we've talked about declines in the 2%-3% range, and despite the big drop in capital, we were able to maintain that sort of a decline rate. I think that's the right way to look at it, and I think we'll generally separate the shale from the base business so that you have transparency in that way.
You're right, when you put them both together, if you lump them together, it'll mask what's going on in the underlying conventional business. If I understand your question right, I think the answer is yes.
Okay. I appreciate that, John. That's what I was trying to get at. I guess my follow-up is also in Permian. I realize you probably want to hold some details for the Analyst Day, but just to frame this, Exxon has done the BOPCO deal. They're talking about going to 15 rigs. My understanding is it's a fraction of that number today. You're talking about adding a rig every eight weeks, stepping up your spending and so on. Can you give us some idea, John? What's the strategic thinking here? Has there been a real pivot away from large capital projects, at least in the short term, towards the Permian? If that's the case, how big a piece of the portfolio would you like to see the Permian ultimately represent given things like dividend commitments and other portfolio decisions that you have out there? Thanks.
Well, the chart on slide 15, we haven't updated since the last time we talked, but we will update it the next time that we see you. If my foreshadowing was any good, you know that it's likely to improve. We have taken a different approach than some in the Permian. We've taken the approach of trying to delineate, understand what we have, and then put together plans that consider offtake, consider infrastructure, and really get lined out so that we can steadily grow over the period consistent with generating good returns in this business. Now, we've told you we've been able to bring our cost down, but we will continue to ramp up. We talked about over the next couple of years getting up to 20 rigs, but we're not limited per se.
We're only limited by the good planning that we can do, the planning around infrastructure, around rig contracts, the quality of crews, frac spreads, and other aspects of this so that we can move forward rapidly, and we'll continue to do that. It's kind of interesting. We hear a lot about how rapidly others are doing, but the facts are we only had five non-operated rigs running at the end of the year, and we've been steadily growing during the year. There's a lot of up and down that other operators put in place. What we want to do is as we add rigs, we want those rigs to be in service to us going forward. We want a steady ramp-up and not be whipsawing our organization around.
You'll see us steadily growing, and I've told my group in the Permian that they are not capital limited. They just need to be sure that they are disciplined about their spend, that we get good returns on it, and that we properly evaluate the acreage. Just one anecdote for you to getting at the efficiency argument that might be of interest. We added to our resource base 500 million barrels this year in the Permian without spending any money. We did that by watching what offset operators have done. Obviously these are continuous plays. We have been able to learn by being a little bit behind others. We have been able to learn, and that's helped us prioritize the spend that we're doing. We will prosecute our agenda. You'll see the potential and growth profile rise.
In an overall sense, it wouldn't surprise me to see our unconventional activity be 25% of our production by the middle of the next decade. This is a really solid asset class, but it's one that's going to be driven by our ability to generate good returns and fit the proper role in the portfolio.
Thanks, Doug.
Appreciate the answer, John. Thanks a lot.
Sure. Mm-hmm.
Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question, please.
Good morning, John, Pat, Frank.
Good morning.
Good morning.
There's been some investor questions about Gorgon and Wheatstone timing, especially with some of the choppiness around Train 1 in the fourth quarter, but it sounds like your message is you think everything is tracking well here. Can you just give us an up-to-date on what the confidence level is around construction execution at the assets and what the greatest risk to timing at Gorgon and Wheatstone ramp is?
Sure. Well, Gorgon, it's done, I guess would be the way I would describe. The construction is completed on Train 3. Train one and two are operating near capacity. In fact, the only remaining thing to do is to bring on the Gorgon offshore field. We've been running on the Jansz field, and so we'll fill out those plants 100% when the Gorgon field comes online shortly. In terms of construction activity at Gorgon, all is good. We do have to have an effective startup and commissioning process, and we had some bumps on train one. We've talked about that before. I've been really pleased that the organization has taken all that in and addressed anything that might from those learnings on Train 2 and on Train 3 .
It's obviously been very effective on train two, and I've got no reason to believe it won't be effective on train three, but a strong startup in commissioning is really key for Gorgon. My subtlety in my comments was we expect LNG early in the second quarter, so I think the story at Gorgon is a good one. At Wheatstone, we're making good progress, certainly at the plant. The comment I made is that the critical path activity is the offshore platform. The well work, the subsea flow lines, pipelines, umbilicals, all that is complete. Train one construction is nearing completion and commissioning is well underway, and so the critical path activity is in some of the platform piping systems that are taking a little longer to complete and be commissioned.
We've supplemented our workforce on the platform, but it hasn't changed our expectation of a midyear start date. It's just the ongoing activity and ebb and flow in the construction work. The plan is still for a midyear startup of that plant. The message I'm trying to give you is it's pretty good. As activity winds down, you can really focus on the work phases that are still open, high-grading crews, and so I expect you'll continue to see a good story coming out of this. It's obviously a little bit earlier in the process, so there's more work to do than Gorgon, but it's also progressing well.
Shifting to policy, there's obviously a lot of changes under this new administration. One of the things that's caught a lot of investor attention is the border tax adjustment. John, what's your view on whether that's good policy and whether that has a meaningful impact on global oil prices and the refining business if it goes through?
Well, Neil, I've seen what you've published and others, and I think you've assessed it reasonably well. Let me make a couple comments. First, in an overall sense, I've been very pleased with the agenda that the Trump administration has. We have seen an avalanche of regulation over the last decade and putting a much more balanced cost-benefit framework in place to assess the value of those regulations, freeing up infrastructure pipelines, all of that is quite positive for our business, for the country, job creation, and a lot of things. That is very much a positive. We all know that our tax system is not competitive. We want American companies to be able to compete. There's a lot of work being done to try to bring down corporate rates so that we can compete both at home and abroad for capital.
Of course, the administration has a focus on bringing jobs and capital back to the U.S., and lower rates will help that. In my view, they're looking for pay-fors. They're looking for ways to make those lower rates happen. They're looking at a variety of different concepts. The truth is, there are a lot of different ideas being floated right now, and I think they're looking for input and we'll continue to provide it. President Trump has indicated that the border adjustment concept is complex, and I would agree with that. I think we need to take a close look at perhaps the consequences of that, both some that could be positive and the unintended consequences in terms of impact on consumers, exchange rates, and knock-on effects on the global economy.
I have no doubt that the administration will do a good job at doing that and will settle on the right kind of tax reform at the end of the day. I think we need to have a little patience for the different ideas that are being put out there, and hopefully, we'll get to the right outcome.
Thanks, John.
Thanks, Neil.
Thank you.
Thank you. Our next question comes from the line of Paul Sankey from Wolfe Research. Your question, please.
Good morning, everyone. John, could you talk about OPEC? Hi. Could you talk about OPEC this year and the impacts that you anticipate? My understanding was that Partitioned Neutral Zone would be part of the cuts, but also I'd be interested if you had observations on some of your other areas of exposure. A couple of the more obscure ones would be obviously Venezuela and whether or not exactly where you're at in Nigeria right now. Thank you.
Sure. The short answer is I don't expect a significant impact from any of these things on our operation. Certainly in Venezuela and Nigeria, indications are they've been operating at lower rates, and we've had no indication that we're going to be impacted. When you look at the Partitioned Zone and you look at the public comments that have been made by Kuwait, they have a strong desire to get the onshore Partitioned Zone where the Saudis and Kuwaitis are partners, and we represent the Kingdom of Saudi Arabia. They have a strong desire to get that online, and they've indicated that it won't have an impact on quotas. To me, the issues are between the two governments, and if they can resolve those, we'll be able to bring it back up.
I think both countries have flexibility in terms of which fields they produce and where that volume will come from. We think those are high-margin barrels when they come online. In fact, if you look at the work, during this time when we've been down there, our people have taken the time to dramatically reduce costs, and they've taken a close look at the reservoir, and we've got a queue of base business activity that is very high return. It'll compete with the best we've got in the world, and it's very economic. I think the Kuwaitis understand that, and I think there's a desire to get it back on production. Look, these are issues between government, and I'm not going to give you a forecast of when that might be resolved.
On balance, you're expecting little impact from OPEC. My follow-up is on decline rates, John. You've talked in the past a lot about them. Have you been surprised by how little global oil supply has declined post-2014, and do you anticipate an acceleration in decline? Thank you.
It's a really good question, Paul. I think the short answer is I have been surprised at how resilient production has been in many locations around the world. Some of that is we just keep getting better. If you look at, for example, some of the deep water developments that we and others have, we've been on plateau at Agbami for a long time. We've been on plateau in some of our Gulf of Mexico projects, and I think we and others are getting very good at extending plateaus, and technology only goes in one direction. We hear about it in the context of the shales, but the same thing is true in other conventional activities.
I think the short answer is I have been a little surprised, and with the benefit from, for example, in Russia, from declining exchange rates and things of that sort, it's made some of that base activity more competitive. Ultimately, however, you do need new major capital projects to fill the gap if you look out a few years, and we're just not seeing FIDs being taken on significant new greenfield opportunities. At some point, we do expect to see, at least in the conventional area, some declines in production. There's a limit to this, and it has surprised us that it's held up as well as it has. At some point, you're going to need new activity. Thank you, Paul.
Thank you.
Thanks, Paul.
Thank you. Our next question comes from the line of Jason Gammel from Jefferies. Your question, please.
Thanks, and hi, everyone. John, I wanted to come back to the comment you made about 70% of capital spend having an effect on production within two years. I assume part of that is still spending on major capital projects that start in that time. Nevertheless, it does illustrate how much you're shifting towards short cycle spend. Really the question is, how has this changed how you manage the risk profile of the company on a move forward basis? Thinking really about how you view uncertainty of earnings from the production profile by not having the big step changes necessarily being as impactful, and how you think about the balance sheet without having those big capital commitments.
Well, I think it's true. There are different kinds of risk when you think about a deep water development versus some of the base business activity or some of the shale developments. So we're cognizant of that, and I think that's driven some of the comments you've heard me and Pat make about how we look at the balance sheet. During the period of time in the early part of this decade, I was very clear going back five years plus. We were going to keep some capacity on the balance sheet. So we had more cash than debt on the balance sheet. So because we knew we were going to be drawing on the balance sheet.
We didn't expect to see the drop in prices as big as we saw, but it proved to be pretty wise to keep that capacity on the balance sheet. Now we're in a different period. We do have the Tengiz project, but I don't see anything like a Gorgon, Wheatstone or Tengiz that's in our future. We could see a deepwater development, but none of these are of that same magnitude. With the drop in interest rates that we've seen during that period, debt is a very effective form of financing. We want to keep some capacity on the balance sheet to withstand the ups and downs and be in a good position to take advantage of opportunities. I think you'll see us carrying more debt on the balance sheet than we have in the past.
We've talked in the 20%-25% debt range, we think that balance is keeping some capacity and taking advantage of the low cost of debt. The key for us is having some financial flexibility around our capital spending that really reduces the execution risks and means you don't have to keep that as much capacity on the balance sheet.
That's helpful. Thanks, Jason. Can I ask one follow-up, please?
Sure.
Two quick questions about what's included in the production guidance. If I look at the chart on page 10, if I take the net of the base decline and the base investment, it implies a mitigated decline rate of 1%. Could you tell me what factors into the guidance range? Also how the partition zone factors into the 4%-9% guidance range?
Sure. I think if I understand the question, the base declines that we show by that red bar are kind of in the 2%-3% range. We do have a range. The bottom of the production range in our estimate that we've put forward assumes that we get nothing from the partition zone this year. The top of the range assume it starts up about mid-year or so. Those are the two variables. That's why we put the fuzzy bar and some brackets around it, because I just can't handicap that perfectly. The base decline is in that 2%-3% range.
Thanks, Jason. Very clear. Thanks.
Yeah.
Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question, please.
Hey, guys. Good morning.
Good morning.
John, if we look, the industry seems like already bottom, and the company is in a good shape that project are coming on stream, and you should reach cash flow neutrality, and depends on the oil price, you should be cash flow positive. Using this opportunity that you already resized your company also for this currently the lower oil price. Can we step a step back and maybe that you can tell us that how the next 5, 10 years, how you want to position? What roadmap that you have in mind? How you want to differentiate yourself with the peers and the other international major corporation? Is it that everyone is now saying that, oh, there's no differentiation? We are in commodity business, and the big major IOC is really in a disadvantage on the business model.
Can you help us that to wrap it all together now that you're no longer, not you necessary, but for most of the people that no longer is in the mode of survival. Can we look a bit further out? Can you afford to look at it and saying that give us what is the roadmap?
Sure. Well, Paul, look, it won't surprise you, is I don't agree with some of those assessments. I think we're in a terrific position. Some of the TSR data that we show, even looking at independents over a period of time, we look pretty good. I would tell you that we are differentiated from some of our competitors, and let me see if I can describe why. We are an integrated oil and gas company, and we have shown a bias toward the upstream portfolio. We think over time we can earn very strong returns and that we have competitive technology and assets to do just that. We do have a strong downstream and chemical business. It earns good returns. It has complementary activity that add value to some of our resources around the world, as well as a lot of very talented people.
We will have a downstream and chemical business, certainly we will be predominantly an upstream company, and that in and of itself is a bit of a difference from some of our competitors. Within the upstream, I think we also differentiate ourselves by the quality of the assets that we have. There are risks to being a company that's only in one particular asset play, regardless of how good that play is. We've got a diverse portfolio. For example, if you look at our position in Australia and the resource base we have there, we'll have five LNG trains plus a position and a third project down there in the Northwest Shelf. We have a very advantaged manufacturing position and a lot of resource that can feed those facilities over time. Australia is a terrific asset. Tengiz we've talked about.
That distinguishes us from many of our competitors. The Permian is, of course, the emerging asset, we've got a terrific position there that I think is the envy of a lot of others, you're seeing us, and you will see us in the future really get after that business. I haven't even talked about the talent we have and the asset position we've got in the deepwater and elsewhere. We have a very good portfolio that I wouldn't trade with anybody. I think over time, the diversity in that portfolio will show benefits. Any one asset has some risk associated with it from an industry perspective, and I think we've got a position that's second to none.
Our approach going forward is. We know we have to improve returns because in a lower price environment the financial returns haven't been what you or I would want them to be. If you look at the cost trends and the efficiency trends that we've got and where we're putting our capital going forward as the capital base rolls over, I think we've got some very strong assets so that going forward, the assets that we've got, the investments that we'll be able to make will earn good returns. I think all of those things distinguish us in what is from a top-line point of view, a difficult time that we're emerging from, and one that will not likely be the same $100 environment that we saw a few years ago. Maybe that's a long answer, but that's.
Really great. Just a quick second one. Venezuela. Any insight how bad is the industry or oil industry in the country at this point? Do you think that any systematic risk is likely? If not, do you think that the current production capacity actually will be able to hold relatively flat, or are we going to continue to see pretty steep decline throughout the year?
Well, for the most part, I can only comment on our operations. We've been able to navigate pretty well down there and have good relationships in Venezuela that we've been able to maintain. We have a structure in place that is enabling us to continue work, enabling us to continue to invest, and importantly to enable the contractors, the tax authorities, and ourselves to get paid. So that seems to be working very well. What I point out is despite obviously the concerns about what's happening in the country right now and some of the difficulties they're encountering, they have a huge resource base. Chevron is well respected there, and I think there's an opportunity for us to play a very constructive role in Venezuela going forward. Certainly maintaining the existing assets that we have and potentially, as time goes forward participating in other opportunities there.
It's unquestionably a difficult time. Thus far, we've been able to manage it working well with the government.
Thanks.
Thanks, Paul.
Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question please.
Yeah. Good morning, everyone. Thank you for the margin improvement chart into 2017. That was very helpful. Obviously, as you shift to short cycle in Permian, you probably also get, plus with deflation, some benefits on the capital intensity side as well, which should lead, as you pointed out, to returns and free cash flow. What about growth in, say, over the next decade versus dividends buybacks? Any philosophical changes there?
There aren't changes philosophically. Let me make a couple comments because you touched on cash flow. I am very encouraged by what I see going forward on cash flow. If you look at 2016 sort of cash from operations in the $13 billion range, it's easy to see big chunks of improvement in cash flow going forward. Capital spending, the cash C&E was $18.7 last year. It's $15.1. That's $3.5 billion. If you have oil averaged $44 a barrel. If it averages $55, our sensitivity is that's another $3.5 billion. We made a capital contribution to TCO, technically a loan for $2 billion last year and didn't receive a dividend of consequence last year. You could see another $3 billion swing net out of TCO.
That doesn't even count the Gorgon and Wheatstone that the fourth quarter had a once in 5-year shutdown of Richmond Refinery that probably cost us $300 million. We had Agbami down for once in 8 years. That's a very profitable investment. We had record production at TCO last year, despite one of the biggest shutdowns they've ever had that was done successfully. All these things are portending strong cash flow with obviously the underlying risks that have to be considered in price. Certainly the message going forward is good. The prospect for us to improve earnings, improve free cash flow, and increase the dividends are good. The priorities that you refer to really haven't changed. We want to increase the dividend as the pattern of earnings and cash flow permit.
We need to continue to invest in the highest return opportunities, we are definitely high-grading that, not funding everything that meets minimum hurdle rates. We need to do that and manage the balance sheet at the same time. It's something that Pat works very hard on, dividend policy ultimately is a purview of the board, in speaking for them, we've just reviewed what our plans are going forward. I think we have a very good support from the full board on this subject. I think the outlook is good, and I'll tell you, 4 years ago, I wouldn't have thought that would be the case at moderate prices. I think it's a good story, and we're going to continue in that direction.
Maybe a follow-up on the question on decline. You spoke more globally, but as you think about the Chevron assets and the ability to keep the decline rate at what has been a relatively low level over the past year, how long do you think that you can keep that up? The Tengiz decline rate when that was announced did surprise a few folks, so I'm just wondering if there's any things that we should be concerned about as we forecast out over the next several years.
There's always a requirement to reinvest in the business. In the case of Tengiz, it's a technically complex field, so there was needed pressure management equipment, and we have to make those investments. That's very different from, say, Bakersfield, California, where there's infill drilling that you need to do, but it's a pretty well understood phenomena. If you invest a certain amount of capital, you can manage the declines. When we were early last year, we were down around $30 a barrel, we weren't investing in the business, really, we were cutting back activity in lots of areas. There was the potential for declines to accelerate because we just weren't drilling wells, and it was a very difficult time for everyone in the industry.
If we get back to a more normal level of activity, you can see sort of 2%-4% kind of declines that I think would be normal. Any individual asset ultimately matures. I don't think I can give you a lot more general guidance than that.
Thanks, Dan.
Thank you.
Thank you.
Thank you. Our next question comes from the line of Evan Calio from Morgan Stanley. Your question, please.
Hi. Good morning. Hey, John, you should tweet your U.S. policy and BAT response later. My question is, you mentioned the Permian story keeps getting better with an ambitious 25% production potential in the middle of the next decade. As much as border tax, I think investors remain focused on service cost inflation here in the U.S. Any color or outlook there, and how much inflation would it take, sorry, to trigger a capital reallocation away from the Delaware in your plan? Or how do you see offsets there as it maybe relate to continuing improvement in well performance and otherwise?
Yeah, Evan. My view is, I think if you look globally, there isn't a lot of pressure on the supply chain. Now, I don't expect continuing reductions necessarily in market conditions. There isn't a lot of upside pressure globally. In the Permian, activity has picked up, and going forward, we would expect to see some pressure. If you look at the dramatic reductions in cost that we've been able to achieve, it's been mostly a function of efficiency measures that we think are sustainable. One of the reasons I made the comments I did earlier about steady ramp-up of rigs and having sort of a consistent and well-thought-through plan is it will be important to have consistency in work crews, for example. Not all rigs are the same. You want to have the best rigs.
You want to have the best crews. You want to have consistent relationships with suppliers who want to be with you through thick and thin so that you can maintain that productivity that we've worked so hard to put in place. Our view is despite some potential for increases, we don't think it's going to make a material difference to us over the next couple of years. I'll confine it to that period, but we don't think it's going to make a big difference even if you should see some changes. I should also point out, in areas like the deep water, our costs are going to come down because we've got deep water rigs that are under contract at above-market rates. Now, we're going to be releasing a couple of rigs here literally over the next couple of weeks, so we'll be down to four deep water rigs.
Over time, all these rigs come off contracts. When you think about the future of a deep water development, costs are coming down, not going up. There's some risk in isolated markets and areas, but I think overall we'll be able to manage it.
Right. Now, we kind of agree Permian's a winner here, but my follow-up is on the Permian, how big is your 2017 program, either in rig or well terms? I'm just trying to understand how much of the 2017 CapEx is being spent on infrastructure, pad development, or otherwise that is reflected in '18 and beyond. It would affect the model growth path.
We ended the year at 15 rigs, 10 operated, five non-operated, and we're going to be ramping up over the course of this year. We expect up to 15 rigs operated by the end of the year, with more in the non-operated side. Our budget's about $2 billion there. Look, we expect to ramp up this year in the $50-$60 range. We're going to continue to ramp up. I just want to emphasize we want to do it efficiently. Thanks, Evan.
Appreciate it.
Thanks.
Thank you. Our next question comes from the line of Alastair Syme from Citi. Your question, please.
Hi, everyone. John, global LNG demand looked to have picked up a bit last year. Can you comment on the state of the market? Are you seeing any positive signs from your customers towards a willingness to term new contracts in the market?
Yeah, it's been interesting, and it's been maybe a little surprising to some. We have had good demand for LNG. We were able to sign a couple of contracts last year so that now at Gorgon and Wheatstone, we're sort of 85%, maybe slightly more sold, which is right about where we want to be. If you look at where spot prices have been, it's clear that there's been incremental cargoes going into China and Japan. It's been somewhat encouraging, I think. If you look at some of the environmental objectives that are there, particularly throughout Asia, it's actually some encouraging signs. I temper that with the understanding that we've got projects that are coming online.
The long-term trend for LNG demand is good because it's competitive on price in many locations, and it certainly has desirable environmental characteristics, and the security of that steady supply out of places like Australia, it remains in demand. By 2025 or so, people are looking at demand increases. It could be 65% or more. It's a good story. I don't think we're yet at the place where you're going to see a lot of FIDs taken on new projects, but it's been encouraging to see a bump up in prices.
As a follow-up, can I ask, are you having any sort of indicative marketing discussions around the Gorgon train 4 or Kitimat or any of these projects?
We've had discussions over the years. You need to underpin a project like Kitimat with some type of contract and offtake, and I don't want to represent that we're very far along in those discussions. We've been looking at different concepts for an LNG plant to be able to put one in more efficiently. We're proving up the resource side, which is encouraging, up in the Liard and Horn River area. Of course, we've done some work on pipeline. I don't want to advertise that that's moving real quickly, primarily because of the economic side. When it comes to Gorgon, I think the first thing that you'll see at Gorgon is, first, we've got to get the three trains lined out and operating smoothly, and I think that will happen. You'll see the potential for debottlenecking and re-rating of those.
I think those are probably, certainly in the queue ahead of a train 4 or other trains at Wheatstone for that matter, where the same sort of principles will apply. We want to really get the most we can out of the gear and hardware that we have, and then contingent on market, we have a strong resource base there. We'll contemplate additional developments.
Thanks, Alastair.
Thank you. Our next question comes to the line of Roger Read from Wells Fargo.
Yeah, hello. Good morning.
Morning, Roger.
Just a quick question for you, Pat, just to come back to the comment about the kind of the other expense in the quarter, you said it wasn't ratable. Was there anything in there that is likely to reverse next year or that you can think of that we should expect next year in terms of higher taxes or unusual payments?
Yeah. I think it's a good question. I wouldn't say that there's anything necessarily that's going to reverse. I mean, an example that you might not have thought of, when we have as many retirements as we have had, for example, out of the U.S., John referenced over the current year, we have 6,200 fewer employees this year, over the last couple of years, it's about 9,500. For example, if you look at the U.S., we're slightly underfunded on our pension, when those retirements occur, of course, you need to accelerate the recognition of that pension settlement cost. That's an example of what's sitting there in that corporate and other sector. Since we anticipate moderating, certainly we're not going to have the same kind of employee reductions, that kind of thing will moderate going forward.
There is a fair amount of lumpiness just on a tax sense, where we continually every quarter go through and make assessments of our outstanding positions and make the appropriate bookings that are required there. I can't say that there's any pattern to that necessarily. As you look forward into 2017, though, I would say the one thing that probably is going to continue to grow would be our interest expense, because our debt balances are higher. We have had a guidance range of the $350 million-$400 million. It's probably towards the high end of that range. Probably you want to think in your mind around $400 million for each quarter for 2017.
Okay, great. Thanks. John, maybe following up on Alastair's question, but stepping out a little broader on FIDs. I recognize the Analyst Day, that it might be more detail coming then, as you think about kind of moving into the offshore, are costs down enough now? Are prices high enough and the returns attractive enough we should expect something in 2017? Or is it still a maybe more patience and waiting?
I think most of the money that we'll be spending, in fact, the four deepwater rigs I mentioned will be doing development drilling. I think it's a bit early to think about FID on something on Anchor or Tigris. We're just completing a couple of appraisal wells, if you will. We need to evaluate those. We're looking at different concepts. For example, in the deepwater, there's technology that needs to be qualified there to be sure we can move them along. We've got industry groups that are working with vendors and suppliers to try to take costs out. I would say it's a work in progress. There's plenty of work to do that I would call brownfield activity off of existing facilities, that's where most of the money will be spent. We've talked previously about Rosebank.
I mean, I'll just tell you, Rosebank, Anchor, Tigris, all are potential FIDs, we just have to get the cost resource development balance right. I wouldn't think for any of those big ones we're likely to see an FID in 2017.
Great. Thank you.
Thanks very much, Roger.
Thank you. Our next question comes from the line of Guy Baber from Simmons & Company. Your question, please.
Good morning, everybody.
Good morning, Guy.
I just wanted to follow up on the cash margin discussion a little bit more in slide 12 where you highlight that improvement. You introduced a slide, I believe, around a year ago that highlighted cash margins in 2017 at about $20 a barrel at $60 a barrel oil. Since then, over the last year, I believe your cost reductions have been more successful than anticipated. Some lower margin barrels have come out of the portfolio, and the Permian is looking better. Can you just help us to understand how your view on those 2017 cash margins has maybe evolved over the last year or so? Is it reasonable for us to think that those margins could be higher at the same price?
We put this chart in there on chart twelve to kind of bait you a little bit and to whet your appetite, I think we successfully did that. I think all the things you point to are what we're trying to get at. I am going to push off a little bit, though, and tell you that Jay Johnson will talk more about what we see in cash margins in our portfolio with the cost improvements you're seeing in place, the portfolio actions that we're taking. We'll update you a little bit more at the SAM, Guy. It's a really good question, I think it's one of our strengths and one of our good stories, I'll push you off till the SAM in five weeks or so.
Okay, understood. The follow-up from me, I thought your reserve additions and the replacement metrics were pretty favorable overall in light of the environment. Could you perhaps share with us the early view on F&D cost this year? Given F&D can be lumpy in any year and the cost deflation you've seen, your shift to prioritizing short cycle brownfield, do you have a view on maybe the new normal of F&D for your business going forward to 2020?
I agree with you that the reserve replacement numbers are pretty good. I'll tell you, if I go back to the beginning of the year, we weren't expecting to be near 100%. A lot of the work that the people in our business units did, we got them focused on shorter cycle activity, they did some excellent work in terms of characterizing reservoir seismic work and others to enable us to appropriately book reserves. You're right. We had a good year, particularly given that we underspent dramatically relative to plan. All that is good. F&D cost, if you think of the oil and gas disclosure, can be really lumpy, you really have to look at it averaging over time. We've tended to give you development cost on a project-by-project basis.
That doesn't always line up exactly with the proved reserve bookings that tend to be how things are viewed in the oil and gas disclosure. I won't make comments on what will appear in the oil and gas disclosure because that's a very specific set of calculations. I think as we look forward to the Security Analyst Meeting we're going to have in a few weeks, I think Jay will be able to talk a little bit more about progress in the Permian and what we're doing on deep water and other asset classes to give you a better idea of what development costs for any of those might be. We'll give you more. It's a real good question, but we need more time to talk about than I've got here today.
Understood.
Thanks very much.
Thank you.
Thank you. Our next question comes from the line of Anish Kapadia from TPH. Your question, please.
Thank you. My first question is, correct me if I'm wrong, Chevron seems like it'll be free cash flow positive in 2017 after dividends at around current oil prices. If you factor in disposals are certainly at the top end of the range, you're going to generate some significant excess cash flow. I was wondering if you could talk about the priorities for the use of that excess cash flow this year.
Well, sure. The expectation is to be cash flow positive between all those things you mentioned, the ongoing improvements, finishing capital projects, lower spending, some asset sale proceeds, et cetera. We do expect to be cash flow positive. The priority on the dividend has been, we said we'll increase the dividend as the pattern of earnings and cash flow permit. We'll take stock of it. The board takes stock of it. Every quarter, we make a look, and we'll increase it as we find appropriate. I guess the one point I'd try to make is we're very cognizant that we've increased the dividend 29 years in a row. I view that any increase in the dividend would be something I'd want to be able to sustain in perpetuity. Going in, that would be my expectation.
We always want to increase the dividend in a way that we can sustain over a period of time. We've given you the guidance on capital. I don't expect us to exceed the capital numbers that we have certainly. We're cognizant of the dividend policy, and we're going to maintain a strong balance sheet. I'm not going to give you a specific guidance on the dividend at this time, other than to say, I'm acutely aware of how much we all like dividends, and so is the board.
Thank you. A follow-up, going back to the Permian again. Just to kind of think of it bigger picture, just wondering how important is it to you for the market to recognize the value of your Permian acreage? If it is important, how do you get the market to recognize that? I'm kind of thinking of it in the terms of you can easily bring value forward by running a lot more rigs on the acreage or disposing of some of your acreage that I suppose you, given your huge inventory, you might not be drilling for 20, 30 years. Just how do you balance managing the asset versus showing the value to the market?
Look, well, first, it's very important for us to have value realized in a reasonable period of time, there's no intention to warehouse acreage that we're not going to get to. In fact, if you look at the asset disposals we have, we've been high-grading our portfolio very steadily. What I don't want to do is dispose of acreage prematurely before we've been able to assess it fully. If we had followed what some wanted us to do, we would've sold things a couple of years ago that are now worth five times what they are. We continue to assess it. If we find that there is acreage in the portfolio that we're not going to get to for a long period of time, I am more than happy to monetize it. That is not the way we think that we can realize most value.
I'll just make a minor editorial comment. There are a lot of people with ulterior motives out there when it comes to disposal of assets. We are prosecuting our agenda. Our costs are competitive, we will utilize our acreage and expose that value to shareholders in a way that will give them confidence that value will be realized from it. We recognize that we need to continue to give more information, and provide that so that you have that confidence. It's a very fair question, and it's on us to do that, and you'll see a lot more in March.
Okay. Very clear. Thank you.
You bet. I think we got one more question.
Certainly. Our final question comes from the line of Blake Fernandez from Howard Weil. Your question, please.
Folks, good morning.
Hey, Blake.
Thanks for squeezing me in. Back on the Deepwater Roger's question. Mad Dog was noticeably absent, and your partner and the operator has announced sanctioning there. Unless I missed it, I don't believe we've heard from Chevron. Can you talk about that and whether that's in the 2017 budget?
Yes. In a word, it is.
Okay.
We have a relatively small interest. We're not the operator, but yes, we've worked with the operator. We've been able to get costs down. They've taken FID. We have not yet taken FID, but I expect that we will.
Great. Okay. The second question, Pat, this may be for you, but you mentioned about $4 billion of deferred tax, and I assume that that begins to be a net positive once the U.S. upstream is net income positive, which it was this quarter. Is it fair to think that that's kind of a cash contributor into next year or this year, I should say?
I think it will be a cash contributor, a partial cash contributor in 2017, yes, because we have the ability in the U.S. to take some of the tax losses and carry them back to earlier periods where we had taxable income. Depending upon what happens to prices and how we operate U.S. both upstream and downstream, then we will get a schedule of repayments over time.
Thank you very much.
Okay. We went a little longer. I wanted to get as many of you in as I could. Thank you for your time today. We appreciate your interest in the company. We'll look forward to talking to you again in March. Until then, we'll continue to prosecute our agenda. Thank you.
Ladies and gentlemen, this concludes Chevron's fourth quarter 2016 earnings conference call. You may now disconnect.