Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's 4th Quarter 2016 Earnings Conference Call. At this time, all participants are in a listen only mode. After the speakers' remarks, there will be a question and answer session and instructions will be given at that time.
As a reminder, this conference call is being recorded. I will now turn the conference call over to the Chairman and Chief Executive Officer of Chevron Corporation, Mr. John Watson. Please go ahead.
Thanks, Jonathan. Welcome to Chevron's 4th quarter earnings conference call and webcast. On the call with me today are Pat Yerington, our Vice President and Chief Financial Officer and Frank Mound, 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 2. Okay. Let's start with the key messages on slide 3. I've said we needed to do 5 things well to adjust to lower prices. First, finished projects under construction, which reduces spend and brings on new revenue.
Gorgon Train 12, Shandong Bay, Bonga, Alder, Angola LNG are all on production and stable. In 2017, progress will continue with Gorgon Train 3 and Wheatstone coming online. 2nd, we need to reduce capital expenditures and focus on work that's profitable
at lower
prices. 2016 capital was down 34% or $11,600,000,000 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 advantaged portfolio. 3rd, we're lowering operating expenses by getting more efficient in all that we do. 2016 operating expense was down 9% or $2,500,000,000 from 2015 and we expect further reductions in 2017.
4th, we need to complete planned asset sales. We're on track with $2,800,000,000 in proceeds in 2016 and we expect 2017 proceeds will likely move us towards the upper end of the 20 sixteen-twenty 17 guidance range of $5,000,000,000 to $10,000,000,000 we previously communicated. And 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 and the cash flow improvement to continue into 2018 and beyond.
Our actions support our number one financial priority, which is maintaining growing the dividend as the pattern of earnings and cash flow permit. Turning to slide 4. Chevron's total shareholder return outpaced our major competitors and the S and P 500 in 2016 and is number 1 relative to our peers for any cumulative holding period going back 20 years. We appreciate the support from our investors, but recognized 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 5, which is an overview of our financial performance. The company's 4th quarter earnings were $415,000,000 or 0 point 2016 were a loss of $497,000,000 Excluding special items and foreign exchange, Chevron earned $1,800,000,000 in 2016. A detailed reconciliation of special items and foreign exchange is included in the appendix to this presentation.
4th 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 5 year event. At the same time, 4th 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 Q4, we paid $2,000,000,000 in dividends, bringing our total for the year to 8,000,000,000 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 6. Cash generated from operations was $3,900,000,000 during the Q4. 4th quarter cash flow benefited from stronger oil prices, but had offset from seasonal downstream margin patterns and the Richmond refinery turnaround.
On a year to date basis, operating cash flow totaled $12,800,000,000 a function of low oil and gas prices and weaker downstream margins than in 2015. 2016 working capital consumption of approximately 600,000,000 dollars and lower affiliate dividends relative to earnings reduced operating cash. We had deferred tax items of nearly $4,000,000,000 dollars for example, those associated with tax loss positions. These will benefit cash in future periods. Proceeds from asset sales for 2016 were $2,800,000,000 Cash capital expenditures were $4,000,000,000 for the quarter and about $18,000,000,000 for the full year, excluding expense exploration.
This continues to trend towards lower outlays. At year end, our cash and cash equivalents totaled $7,000,000,000 Our net debt stood at $39,000,000,000 resulting in a net debt ratio of approximately 21%. Turning to Slide 7. Slide 7 compares 2016 annual earnings to 2015. Full year 2016 results were a loss of $497,000,000 or approximately $5,000,000,000 lower than the 2015 results.
The impact of special items, primarily due to lower gains on asset sales, reduced earnings by $515,000,000 Lower foreign exchange gains decreased earnings by about 710,000,000 dollars Upstream earnings, excluding special items and foreign exchange, decreased $798,000,000 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 $2,800,000,000 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 20 16 results are in line with our standing guidance of $350,000,000 to $400,000,000 in net charges per quarter for the other segment.
Turning to Slide 8. I'll now compare results for the Q4 of 2016 with the Q3 of 2016. 4th quarter results were approximately $870,000,000 lower than the Q3. The absence of Q3 2016 gains from special items reduced earnings by $290,000,000 between periods. Lower foreign exchange gains reduced earnings by approximately $50,000,000 between periods.
Upstream results, excluding special items and foreign exchange, increased approximately $850,000,000 between quarters, primarily reflecting higher crude realizations, higher volumes and lower taxes. Downstream earnings, excluding special items and foreign exchange, were lower by 765,000,000 dollars 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. And now I'll turn it back to John.
Okay. Thanks, Pat. Turning to Slide 9. 2016 capital spending was $22,400,000,000 That's approximately $4,000,000,000 less than our original budget and more than $11,000,000,000 lower than last year. Cash C and E was 18,700,000,000 dollars Reductions 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 $19,800,000,000 which is right in the middle of our dollars to $22,000,000,000 guidance range for the period out to 2020. Cash, capital and exploratory expenditures, which exclude affiliate spend are expected to be $15,100,000,000 70% of our expenditures in 2017 will generate cash flow within 2 years, reducing cash flow cycle time and financial risk. 2016 operating expense was $25,000,000,000 better than we had most recently guided and more than $2,500,000,000 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 2016. 2016 net production was 2.6 1,000,000 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 partition zone, security issues in Nigeria and Gulf of Mexico asset sales. Looking at the 4th quarter bar, you see that the 4th quarter was strong and production growth is accelerating.
As we start the year, 2 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% to 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 partition 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 12, Shandong Bay, Angola LNG, Alder, Bonka.
Then we also expect to see partial year contributions for project starting up in 2017, Gorgon Train 3, Wheatstone and Mothamir Sol 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 1,000 to 100,000 barrels a day.
Turning to slide 12. The chart on the left side shows our $5,000,000,000 to $10,000,000,000 guidance range for asset sale proceeds for 2016 2017. In 2016, we made good progress with $2,800,000,000 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 1 5 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 Tide and 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 a 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 the sales. Let's talk now about some of the major activities starting with Gorgon. Gorgon currently is stable with gross output of over 200,000 barrels a day and 130,000,000 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 work through start up issues we've discussed previously. All learnings from Train 1 were applied to Train 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 start up and commissioning.
We expect first LNG early in the Q2 of this year. At Wheatstone, our outlook for first LNG remains mid-twenty 17. 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 to 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 8 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
Our first question comes from the line of Bill Gresh from JPMorgan. Your question please.
Hi, good morning.
Hey, Phil. Hey, Phil.
So 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 2,750,000 barrels a day. And 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, and obviously, a lot has changed from then to now. But I was hoping maybe you could help bridge some of those moving pieces between project timing, asset sales, P and Z effects and really just trying to think through ultimately after 2017, how much additional uplift the volumes there would be from projects?
Yes. It's a good question. If you go back to that time, we did put our NSP in the 2.9% to 3% range. And 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 partition zone.
We were producing we expected we'd be back up and operating and that's about 70,000 barrels a day. So 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. And so you put those 2 together and that's 150,000 barrels a day and that really explains it.
Now there are as you point out, there are some other ups and downs, notably some delays in capital projects, but the flip side of that is we got benefits. The shale and tight volume is growing. JAKKS A. Model has performed better than we expected. We have some price a little bit of benefit from price effects.
So but those about offset. So the 2 big items are really the partition zone and asset sales and you get kind of right back into the zone we talked about.
Okay, got it. That's very helpful. And then the second question would just be on the longer term CapEx budget. Looking at the bars that you gave for 2017, there's still $2,000,000,000 in there for Vergan and Wheatstone and then another $2,000,000,000 plus it looks like, just looking at the bars for projects that are outside of Tengiz. So I guess I was just wondering how you're thinking about that 17% to 22% range, especially as we look at 2018 and you potentially have a couple of 1,000,000,000 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?
Yes. 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. So 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 spent $1,000,000,000 more.
So the drilling efficiencies that we have put in place and that was just in the deepwater. So the efficiencies we've put in place have allowed us to bring down costs. So the trend of spend is down. And as you point out, we have some major capital projects that are being completed. If we're still in the $50 to $55 world, you'll see us tracking at the bottom end of that range.
Now we have showing a range out to 2020 that's a 4 year period. And so 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 will be the case. We're budgeting about $2,000,000,000 this year, but you could easily see another $1,000,000,000 there.
We have very little activity in the Marcellus now. I would we've gotten very efficient there, but we would expect better market conditions and off take capability there. We've made good progress in the Duvernay, Argentina. So just in the shale and tight area, you could see some increases. But again, that's short cycle high return activity.
Now we do have some opportunities in the portfolio that if we continue to make good progress on concepts and sort of delineation drilling, things like Anchor and Tigris and we've highlighted Rosebank and a few others. So we have a good queue of projects, but we need to make sure that those have kind of the right economics associated with them that but all of that can comfortably fit in the range that we've talked about. But I'll just say that if we're at $50 to $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.
You've normally talked about
the base business and the tight unconventional business kind of in the same breath as one offsetting the declines in the other. So I guess my first question is in the context of decline rates and maintenance spending. Your budget this year puts that number about $8,500,000,000 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?
Yes, 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. So I think that's the right way to look at it. And that's why we've talked about declines in the 2% to 3% range.
And despite the big drop in capital, we were able to maintain that sort of a decline rate. But 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. Because you're right, when you put them both together, if you lump them together, it will mask what's going on in the underlying sort of conventional business. So 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 on Permian. I realize you probably want to hold some details for the Analyst Day, but just to kind of frame this.
So Exxon has done the Bobco 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 8 weeks, stepping up your spending and so on. Can you give us some idea, John, what's the strategic thinking here?
Is there a real pivot away from large capital projects, at least in the short term towards the Permian? And 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 on the dividend? 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. And if you if my foreshadowing was any good, you know that it's likely to improve. So we have taken a different approach than some in the Permian. We have 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 costs 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 have 5 non operated rigs running at the end of the year. And we've been steadily growing during the year.
And so 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. And so you'll see a 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, kind of getting at the efficiency argument that might be of interest. We added to our resource base 500,000,000 barrels this year in the Permian without spending any money. And we did that by watching what offset operators have done. So obviously, these are continuous plays. We were able so 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. So we will prosecute our our unconventional activity be 25% of our production. Our unconventional activity be 25% of our production by the middle of the next decade. So 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, Doug. Thanks a lot. Sure.
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. Good morning.
There's been some investor questions about Gorgon and Wheatstone timing, especially with some of the choppiness around Train 1 in the Q4. 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's 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 1 and 2 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. So in terms of construction activity at Gorgon, all is good. Now we do have to have an effective start up and commissioning process and we had some bumps on Train 1. We've talked about that before.
But I've been really pleased that the organization has taken all that in and addressed anything that might from that those learnings on Train 2 and on Train 3. It's obviously been very effective on Train 2 and I've got no reason to believe it won't be effective on Train 3, but a strong start up in commissioning is really key for Gorgon. But my subtlety in my comments was we expect LNG early in the Q2. So I think the story at Gorgon is a good one. At Wheatstone, we're making good progress certainly at the plant.
And what I the comment I made is the critical path activity is the offshore platform. Now the well worth, the subsea flow lines, pipelines, umbilicals, all that is complete. Train 1 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 mid year start date, but it's just the ongoing activity and ebb and flow in the construction work.
But the plan is still for a mid year startup of that plant. But the message I'm trying to give you is it's pretty good. And as activity winds down you start 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. But, 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.
And 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 in 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 of comments. 1st, 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. So that is very much a positive.
And we all know that our tax system is not competitive. We want American companies to be able to compete. And so 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. And 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. And so they're looking at a variety of different concepts. And 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. And so 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. And I have no doubt that the administration will do a good job of doing that and will settle on the right kind of tax reform at the end of the day. But 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, Jeff.
Thanks, Neil. Thank you.
Thank you. Our next question comes from the line of Paul Sankey from Wolfe Research.
John, could you talk about OPEC this year and the impacts that you anticipate? My understanding was that partition 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. And 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 partition zone and you look at the public comments that have been made by Kuwait, they have a strong desire to get the onshore partition zone where we the Saudi's and Kuwaiti's 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. So to me the issues are between the two governments and if they can resolve those we'll be able to bring it back up.
And I think both countries have flexibility in terms of which fields they produce and where that volume will come from. We think it's high we think those are high margin barrels when they come online. I mean, 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 will compete with the best we've got in the world and it's very economic. So I think the Kuwaitis understand that and I think there's a desire to move it back to get it back on production.
But look, these are issues between government and I'm not going to give you a forecast of when that might be resolved.
Great. But 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 suppliers declined post 2014?
And do you anticipate an acceleration in decline?
Thank you.
Yes. 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 deepwater 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 activity. So 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 opportunities. And so at some point, we do need we do expect to see, at least in the conventional area, some declines in production. And there's a limit to this. And it has surprised us that it's held up as well as it has, but 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 2 years. Now I assume part of that is still spending on major capital projects that start in that time, but nevertheless, it does illustrate how much you're shifting towards short cycle spend. And really the question is, how does this change 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 I mean, there are different kinds of risk when you think about a deepwater development versus some of the base business activity or some of the shale developments. And 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 made I was very clear going back 5 years plus, we were heading into a period where we had significant major capital projects.
We were going to keep some capacity on the balance sheet. And so we had more cash than debt on the balance sheet. And so because we knew we were going to be drawing on that drawing on the balance sheet. Now 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 the same 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. And with the drop in interest rates that we've seen during that period, debt is a very effective form of financing. And so 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. But 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% to 25% debt range and 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. Thanks, Jason.
Can I ask one follow-up, please?
Sure, sure.
Okay. I just wanted to add 2 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 in the base investment, it declines it implies a mitigated decline rate of 1%. But could you tell me what factors into the guidance range? And then also how the partition zone factors into the 4% to 9% guidance range?
Sure. I think if I understand the question, I mean the base declines that we show by that red bar are kind of in the 2% to 3% 2% to 3% range. And 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.
So those are the two variables. And that's why we put the fuzzy bar and some brackets around it because I just can't handicap that perfectly. But the base decline is in that 2% to 3% range. Thanks, Jason.
Very clear. Thanks.
Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question, please.
Hey guys, good morning. Good
morning, Paul.
John, if we look, the industry seems like you're already bottomed and the company is in a good shape that projects are coming on stream and you should reach cash flow neutrality and depends on the like why you should be cash flow positive. So can we using this opportunity that you already resize your company also for this currently the lower oil price, So 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 are roadmap that you have in mind? How you want to differentiate yourself with the peers and the other international major corporation? I mean, is it that everyone is now saying that, oh, I mean, there's no differentiation in commodity business and the big major IOC is really in disadvantage on the business model. So can you help us that to wrap it all together now that you no longer not new necessary, but for most of the people that no longer is in the mode of survival.
Can we look near a bit further out now, can you afford that to look at it and saying that give us what is the roadmap?
Sure. Well, Paul, look, it won't surprise you. I don't agree with some of those assessments. I think we're in a terrific position. And some of the TSR data that we show, even looking at independents over a period of time, we look pretty good.
And 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. So we will have a downstream and chemical business, but 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. And we've got a diverse portfolio. For example, if you look at our position in Australia, the resource base we have there will have 5 LNG trains plus a position and a 6 that's or 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. So Australia is a terrific asset.
Tengiz, we've talked about, that distinguishes us from many of our competitors. And the Permian is of course the emerging asset and we've got a terrific position there that I think is the envy of a lot of others and you will see us you're seeing us and you'll see us in the future really get after that business. And I haven't even talked about the talent we have and the asset position we've got in the deepwater and elsewhere. So we have a very good portfolio that I wouldn't trade with anybody. And I think over time, the diversity in that portfolio will show benefits.
And because 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. Now our approach going forward is to 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. But 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 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. So 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.
So 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? And do you think that any systematic risk is likely or that if not, then do you think that the current production capacity actually would be able to hold relatively flat? Or will you going to continue to see pretty steep decline throughout the year?
Well, for the most part, I can only comment on our operations and we've been able to navigate pretty well down there and have good relationships in Venezuela that we've been able to maintain. And we have a structure in place that is enabling us to continue work, enabling us to continue to invest and enabling importantly to enable the contractors, the tax authorities and ourselves to get paid. And so that seems to be working very well. What I point out is despite the 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. And 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. But it's unquestionably a difficult time. Thus far, we've been able to manage it working well with the government. Thanks, Paul.
Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question, please.
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. You spoke about debt balances, but what about growth in, say, over the next decade versus dividends, buybacks?
I mean, any philosophical changes there?
There aren't changes philosophically. But let me make a couple of comments because I am encouraged 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 $13,000,000,000 range, but it's easy to see big chunks of improvement in cash flow going forward. Capital spending, the cash C and E was $18,700,000 last year, it's $15,100,000 that's 3.5 percent.
If you have oil averaged $44 a barrel, if it averages $55,000,000 our sensitivity is that's another $3,500,000,000 We made a capital contribution to TCO, technically alone for $2,000,000,000 last year and didn't receive a dividend The 4th quarter had a once in 5 year shutdown of The Q4 had a once in 5 year shutdown at Richmond Refinery that probably cost us $300,000,000 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. I mean, all these things are portending, strong cash flow. But, certainly the message going forward is good.
So, But certainly the message going forward is good. So the prospect for us to improve earnings, improve free cash flow and increase the dividends are good. And the priorities that you referred to really haven't changed. We want to increase the dividend as a pattern of earnings and cash flow permit. We need to continue to invest in the highest return opportunities and we are definitely high grading that not funding everything that meets minimum hurdle rates.
And we need to do that and manage the balance sheet at the same time. And it's something that Pat works very hard on and dividend policy ultimately is a purview of the Board. But in speaking for them, we've just reviewed what our plans are going forward. I think we have a very good support for the Board from the full board on this subject. So 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. So I think it's a good story and we're going to continue in that direction.
And then 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, I mean, how long do you think that, you can keep that up? I mean, the Tengiz decline rate when that was announced, did surprise a few folks. And 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 and 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. So I don't have the real when we were early last year, we were down around $30 a barrel and we were investing in the business and 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 we were it was a very difficult time for everyone in the industry. But if we get back to a more normal level of activity, you can see sort of 2% to 4% kind of declines that I think would be normal. And any individual asset ultimately matures, But I don't think I can give you a lot more general guidance than that. Okay. Thank you.
Thank you.
Thank you. Our next question comes from the line of Evan Kallo from Morgan Stanley. Your question please.
Hi, good morning. John, you should tweet your U. S. Policy and BAT response later. My question is on you mentioned the Permian story keeps getting better with an ambitious 25% production potential in the middle of next decade.
I mean, as much as border tax, I think investors remain focused on service cost inflation here in the U. S. So any color or outlook there? And how much inflation would it trigger would it take, sorry, to trigger a capital reallocation away from the Delaware in your plan Or how do you see offsets there? Is it maybe relate to continuing improvement in well performance and otherwise?
Yes, Evan. Boy, that's a topic that gets a lot of attention. And my view is, I think if you look globally, there isn't a lot of pressure on the supply chain. I don't expect continuing reductions necessarily in market conditions, but 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. But 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. So 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 have that maintain that productivity that we've worked so hard to put in place. Our view is despite some increases, potential for increases, we don't think it's going to make a material difference to us over the next couple of years. And 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 deepwater, our costs are going to come down because we've got deepwater 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 4 deepwater rigs. But over time, all these rigs come off contracts. And so when you think about the future of a deepwater development, costs are coming down, not going up. So, 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 is a winner here, but my follow-up is on the Permian and how big is your 2017 program either in a 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 2018 and beyond. I mean, it affects it would affect the model growth path.
We ended the year at 15 rigs, 10 operated, 5 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. We've got our budget is about $2,000,000,000 there. And look, we expect to ramp up this year in the $50 to $60 range.
We're going to continue to ramp up. I just want to emphasize that we want to do it efficiently. Thanks, Evan.
Appreciate it.
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? And are you seeing any positive signs from your customers towards a willingness to turn new contracts in the market?
Yes. 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 the corgano wheat sown we're sort of 85% maybe slightly more sold, which is right about where we want to be. And if you look at where spot prices have been, it's clear that there's been incremental cargoes going into China and Japan.
So it's been somewhat encouraging, I think. And if you look at some of the environmental objectives, that are there, particularly throughout Asia, it's actually some encouraging signs. Now I temper that with the understanding that we've got projects that are coming online, but the long term trend for LNG is 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. So by 2025 or so, people are looking at demand increases that could be 65% or more. So 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, Garth, are you having any sort of indicative marketing discussions around the Gorgon Train 4 or Kitimat or any of these projects?
Well, we've had discussions over the years. I would say the most likely 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 1 in more efficiently. We're proving up the resource side, which is encouraging up in the yard and Horn River area.
And of course, we've done some work on pipeline. But 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 3 trains lined out and operating smoothly, and I think that will happen. Then you'll see the potential for debottlenecking and rerating of those. And I think those are probably in the queue certainly in the queue ahead of a Train 4 or other trains at Wheatstone 4 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, Alistair.
Thank you. Our next question comes from the line of Roger Read from Wells Fargo.
Yes. Hello. Good morning.
Good morning, Roger.
I guess 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?
Yes. So 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 and 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 and when those retirements occur, then of course you need to accelerate the recognition of that pension settlement cost. So that's an example of what's sitting there in that corporate and other sector. And since we anticipate moderating, certainly, we're not going to have the same 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.
And 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. So we have had a guidance range of the $350,000,000 to $400,000,000 It's probably towards the high end of that range. Probably you want to think in your mind around $400,000,000 for each quarter for 2017.
Okay, great. Thanks. And then, John, maybe following up on Alistair's question, but stepping out a little broader on FIDs, is there and I recognize the Analyst Day that it might be more detail coming then. But 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 in waiting?
I think most of the money that we'll be spending, in fact, the 4 deepwater rigs I mentioned, we'll be doing development drilling. I think it's a bit early to think about FID on something on anchor or Tigris. We have 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. So 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. And so 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, but we just have to get the cost resource development balance right. And so I wouldn't think for any of those big ones we're likely to see NFID in 2017.
Great. Thank you.
Thanks very much, Roger.
Thank you. Our next question comes from the line of Guy Baber from Simmons and Company. Your question please.
Good morning, everybody. I wanted to follow-up on the cash margin discussion a little bit more in Slide 12 where you highlight that improvement. But 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. But 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.
So can you just help us to understand how your view on those 2017 cash margins has maybe evolved over the last year or so? And is it reasonable for us to think that those margins could be higher at the same price?
Yes. We put this chart in there on Trexwoke to kind of bait you a little bit and to wet your appetite. And I think we successfully did that. And 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 guide. So it's a really good question and I think it's one of our strengths and one of our good stories. But I'll push off till the SAM in 5 weeks or so.
Okay, understood. And then the follow-up for 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 and D cost this year? And then given F and 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 and D for your business going forward to 2020?
Well, 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%. So a lot of the work that the people in our business units did, we got them focused on shorter cycle activity and they did some excellent work in terms of characterizing reservoir seismic work and others to enable us to appropriately book reserves. So you're right, we had a good year and particularly given that we underspent dramatically relative to plan. So all that is good.
F and D cost, if you think of the oil and gas disclosure, can be really lumpy and you really have to look at an 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 what's the proved reserve bookings that tend to be, how things are viewed in the oil and gas disclosure. So I won't make comments on what will appear in the oil and gas disclosure because that's a very specific set of calculations. But I think as we look forward to the security announcement 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 seeing in some of our what we're doing on deepwater and other asset classes to give you a better idea of what development costs for any of those might be. So 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. 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, but Chevron seems like it will be free cash flow positive in 2017 after dividends around current oil prices. And then if you factor in disposals, certainly at the top end of the range, you're going to generate some significant excess cash flow. So 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 with between all those things you mentioned, the ongoing improvements, finishing capital projects, lower spending, some asset sale proceeds, etcetera. We do expect to be cash flow positive. The priority on the dividend has been we said we'll increase the dividend as a pattern of earnings and cash flow permit. So 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. And I view that any increase in the dividend would be something I'd want to be able to sustain in perpetuity. So going in that would be my expectation.
So we always want to increase the dividend in a way that we can sustain over a period of time. So we will 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. But 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 you we all like dividends and so is the Board.
Thank you. And a follow-up going back to the Permian again. Just to kind of think of it bigger picture, just wondering how important is it for you is it to you for the market to recognize the value of your Permian acreage? And if it is important, how do you get the market to recognize that? And 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.
I suppose you given your huge inventory, you might not be drilling for 20, 30 years. So just how do you balance kind of managing the asset versus kind of 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. And 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 have sold things a couple of years ago that are now worth 5 times what they are.
So 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. But that is not the way we think that we can realize most value. And 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.
And we are prosecuting our agenda. Our costs are competitive. And we will utilize acreage and expose that value to shareholders in a way that will give them confidence that value will be realized from it. That is and we recognize that we need to continue to give more information and provide that so that you have that confidence. So it's a very fair question and it's on us to do that and you'll see a lot more in March.
Okay. Thank you.
You bet. I think we have one more question.
Certainly. Our final question comes from the line of Blake Fernandez from Howard Weil. Your question please.
Folks, good morning. Thanks for squeezing me in. Back on the Deepwater Rogers 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. So can you talk about that and whether that's in the 2017 budget?
Yes. In a word, it is. 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. And the second question, Pat, this may be for you, but you mentioned about $4,000,000,000 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. So 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. And 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 look forward to talking to you again in March. And until then, we'll continue to prosecute our agenda. Thank you.
Ladies and gentlemen, this concludes Chevron's 4th quarter 2016 earnings conference call. You may now