Chevron Corporation (CVX) Q4 2016 Earnings Report, Transcript and Summary

Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's Fourth 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. [Operator Instructions] 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 2. Okay, let's start with the key messages on Slide 3. I've said we needed to do five things well to adjust the lower prices. First, finish project under construction which reduces spend and brings on new revenue. Gorgon Train 1 and 2, Shandong Bay, Bangka, Alder, Angola LNG are all on production and stable. In 2017 progress will continue with Gorgon Train 3 and Wheatstone coming online. Second, we need to reduce capital expenditures and focus on work that's profitable 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 are lowering operating expenses by getting more efficient in all that we do. 2016 operating expense was down 9% or $2.5 billion from 2015 and 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 and we expect 2017 proceeds will likely move us toward the upper end of the 2016, 2017 guidance range of $5 billion to $10 billion 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 continuing to 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. Turn to Slide 4, Chevron's total shareholder return outpaced our major competitors and the S&P 500 in 2016 and is number one relative to our peers for any cumulative holding period going back 20 years. We appreciate the support from our investors but 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 not 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 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 item and timing effects. Downstream results were weak reflecting adverse timing affect 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 in average quarter. Our debt ratio at year 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 6, cash generated from operations was $3.9 billion during the fourth quarter. Fourth quarter cash flow benefited from stronger oil prices but had offset the 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 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 assets 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 expense expiration. 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 7. 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 results. 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 cooperate charges and interest expense. Full year 2016 results are in line with our standing guidance of $350 million to $400 million in net charges per quarter for the other segment. Turning to Slide 8. I’ll now compare results for the fourth quarter of 2016 with the third quarter of 2016. Fourth quarter sales 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 crude utilization, 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 effect. 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 $22.4 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 hi-grading future investment and realizing efficiency gains and supplier cost reduction. In December we announced a total capital and exploratory budget for 2017 of $19.8 million 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 '16. 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 work-over 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'll see 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 TCL maintenance shutdowns are behind us. We expect production growth this year of 49% 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 ultimate base decline rates. Growth comes from a number of areas. First, we expect to see full-year production from project started up in 2016. Gorgon train one and two, Shandong Bay, Angola LNG, Alder, Bangka and we also expect to see partially a contribution for project starting up in 2017, Gorgon Train 3, Wheatstone and Mafumeria 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 -- on the timing of the close of the individual transaction is one variable. Our current estimate is a reduction of 50,000 to 100,000 barrels a day. Turing to Slide 12, the chart on the left side shows our $5 billion to $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 in 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 barrel. Despite a sharp reduction in capital spending we have a strong reserve 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 are reserves added from improved reservoir characterization in several areas and strong well performance in shale and tight and various other locations. Lower commodity prices benefited entitlement volumes from profit-sharing and variable royalty contracts. This was partially offset by lower economic produce ability 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 activity starting with Gorgon. Gorgon currently is stable with growth output of over 200,000 barrels a day and 130 million cubic feet of domestic gas output, a total of 39 cargos 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 2 and consequently Train 2 ramped up 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 the foundations and the site is under permanent power. Ongoing hook up 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 six to eight months following Train 1. Turning to 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 will do our best to get all of your question answered, thanks. Jonathan please open the lines for questions.

[Operator Instructions] Our first question comes from the line of Phil Gresh from JPMorgan. Your question please.

Hi, good morning. 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 it would be around 2.75 million barrels a day. And I know it is 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 to volumes there would be from projects.

Yes, it's a good question. If you go back to that time we did put out an estimate of 2.9 to 3 range and actually the results were shown - now are very consistent with a couple of exceptions. The first and obvious one is the Partitioned 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 two together and that's 150,000 barrels a day and that really explains it. Now as you point out, there are some other ups and downs notably, some delays in capital projects, but the flipside of that is we got benefits the shale and tight volume is growing, Jack St. Malo has performed better than we expected. We have some price, a little bit of benefit from price effects. But those about offset. So the two 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 is 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 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. So I guess I was just wondering how you are thinking about that $17 billion to $22 billion range, especially as we look at 2018 and you potentially have a couple 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?

Yes, first, if I got back a year and you told me we would be able to get our spending, do all the work we did this year and have spending at $22.4 billion, 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 examine, the wells we drilled in 2016 if we had had the productivity we had in 2014, we would have spent $1 billion more. So the drilling efficiencies that we have put in place and I was just in the deep water. So the efficiencies we put in place had allowed us to bring down cost. 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 -- we're showing a range out of 2020 that's a four-year period and so when we 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 talked about ramping up the Permian and I think that will be the case. We were budgeting about $2 billion this year, but you could easily see another $1 billion there. We have very little activity in the Marsalis now. I would -- we've gotten very efficient there. So we would expect better market conditions and an offtake capability there. We 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 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 right economics associated with them, but all of that can comfortably fit in the range that we've talked about, but I'll just say that if where at $50 to $55, you should expect spending to go down next year. Thanks Phil.

Thanks John.

Thank you. Our next question comes from the line of Doug Leggate from Banc of America, Merrill Lynch. Your question please.

Thanks. Good morning, everybody. You have 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 declining 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?

Yes, I think that 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 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 you know 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 is what I was trying to get at. I guess my follow up is also in the 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 [BotCO] [ph] deal, they are talking about going to 15 rigs; my understanding is it's a fraction of that number today. You are talking about adding a rig every eight weeks, stepping up your spending and so on. Can you give us some idea, John, what is the strategic thinking here? Is there a real pivot away from large capital projects at least in the short term to work with 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? And I will leave it there. Thanks.

As told on Slide 15, we haven't updated since the last time we talked but we will update it, the next time that we see 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 on the Permian. We've taken the approach of trying to delineate understand what we have and then put together plans that consider off-take, 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 told we've been able to bring our cost down but we will continue to ramp up. We talked about over next couple 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 on infrastructure around a rig contracts, the quality of crude, 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 done but the facts are we only have five non-operated rigs running at the end of the year and we've been steadily going during the year and so there's a lot of up and down that other operators put in place. We want to do as we add rigs we want those rigs to be in service to us going forward we want to steady ramp up and not whipsawing our organization around. And so you'll see it 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 want to anecdote for you, the kind of getting 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. 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 help us to prioritize the stand that we're doing. So we will prosecute our agenda, you'll see the potential on 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. So this is a really solid asset class but it's one it's going to be driven by our ability to generate good returns and fit the proper role in the portfolio.

Appreciate the answer. Thanks a lot.

Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question please.

Good morning, John, Pat, Frank. There has 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 messages, you think everything is tracking well here. Can you 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?

Well Gorgon is 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 will fill out those plans 100% when the Gorgon field comes online shortly. So in terms of construction activity at Gorgon all is good. Now we do have - we do have to have an effective startup and commissioning process and we had some bumps on train one. We 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 two and on train three. 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 but my subtlety in my comments was we expect LNG early in the second quarter. So I think the story of Gorgon is a good one. At Wheatstone we're making good progress, certainly at the plant and I think the comment I made is the critical path activity is the offshore platform. Now the well worth subsea flowlines, pipelines umbilical, all that is complete. Train one construction is nearing completion and commission is underway and so the critical path activity is in some of the platform piping systems. They’ve taken 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. But it's just the ongoing activity and ebb and flow in the construction work, but the plan is still for midyear startup of that plant, but the message I'm trying to give you is it's pretty good and as activity winds down, you can really focus on the work faces 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 on Gorgon, but it's also progressing well.

And shifting to policy, there is 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 is your view on whether that is 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 published and others and I think you've assessed it reasonably well. Let me make a couple of comments. First, in an overall sense I've been very pleased with the agenda that the Trump administration has. We've seen an avalanche of regulation over the last decade and putting a much, much more balanced cost-benefit framework in place to assess the value of those regulations freeing up infrastructure pipeline, 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 menstruation has a focus on bringing jobs and capital back to the U.S. and lower rate will help that. In my view, they're looking for pay-for, they're looking for ways to make those always 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 of them 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 anticipation 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 Neil.

Thanks John.

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 this year and the impacts that you anticipate? My understanding was that Partitioned neutral Zone would be part of the cuts. But also I would 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 are 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 operations, certainly in Venezuela and Nigeria indications are they been operating at lower rates and we've had no indication that we're going to be impacted. When I 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 we - where that Saudis and Kuwaitis are partners and we represent the Kingdom of Saudi Arabia. They have a strong desire to get that online and they have indicated that it won't have an impact on quarters. So to me the issues are between the two governments and if they can resolve those, we will 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 those are high margin barrels when they come online. I mean if you look at the work during this time and we've been down there, our people have taken the time to dramatically reduce costs and they have 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 this is - these are issues between governments, I'm not going to give you a forecast of when that might be resolved.

Right, but on balance you are expecting little impact from OPEC. My follow up is on decline rates. John, you have talked in the past a lot about them. Have you been surprised by how little global oil supply has declined post 2014? But do you anticipate an acceleration in declines? Thank you.

It’s a really good question Paul. I think the shorter 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 in 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 in the context of the shale but the same thing is true in other conventional activity. So I think the short answer is, I have been 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 are not just seeing FID's been taken on significant new Greenfield 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 is 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.

Your next question comes from the line of Jason Gammel from Jefferies. Your question please.

John, I wanted to come back to the comment you made about 70% of capital spend having an effect on production within two 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 are shifting towards short cycle spend. And 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?

I think it's true. There are - there are different kinds of risk when you think about it Deepwater development versus some of the base business activity or some of the shale development and so we're cognizant of that and I think that driven some of the comments you 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 to five 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 on a different period. We do have the Tengiz project but I don't see the same anything like Gorgon, Wheatstone or Tengiz 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 in and be in a good position to take advantage of opportunities, but you 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 taken 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 risk and means you don't have to keep that as much capacity on the balance sheet.

Can I ask one follow up, please?

Sure.

Okay. I just wanted to -- I have two quick questions about what is 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 and then also how the Partitioned Zone factors into the 4% to 9% guidance range.

Sure. I think if I understand the question, the base decline that we show by the red bar are kind of in the 2% to 3% range and we do have a range, the bottom of the production range in our estimate that we put forward, assumes that we get nothing from the Partitioned Zone this year. The top of the range assume it starts up about midyear 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 -- I just can't handicap that perfectly, but the base decline is that 2% to 3% range.

Thanks.

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

Hey guys. Good morning. John, if we look at the industry it seems like you already bottom and the Company is in good shape, that projects are coming on stream and you should reach cash flow neutral not and it depends on the projects should be cash flow positive. So can we -- using this opportunity that you're already resizing your company also for this -- currently the lower oil prices. 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 the roadmaps that you have in mind? How do you want to differentiate yourself with the peers and the other international major corporations? Is it that everyone is now saying that oh I mean there is no differentiation, we're in commodity business and the big major IOC is really in a disadvantage on the business model? So, can you help us that to wrap it altogether now that you no longer -- not you necessarily, but for most other people that no longer is in the mode of survival, can we look a little bit further out, now can you afford that business to look at it and saying that give us what is the roadmap?

Sure. Well Paul look, it won't surprise you that 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 independence over a period of time we look pretty good and I would say that we are differentiated from some of our competitors and let me see if I can describe why. We aren't 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. We got a diverse portfolio for example if you look at our position in Australia, the resource base we have there will have five LNG trains plus a position in a six that's or a third project down there in the Northwest shelf. We have a very advantage manufacturing position and a lot of resource that can feed those facilities over time. So Australia is a terrific asset. Tengiz we have talked about. That distinguishes us from many of our competitors and the Permian is of course the emerging asset and we got a terrific position there that I think is the envy of a lot of others and you will see - you are 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 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 anyone asset has some risk associated with it from an industry perspective and I think we've got a position that second to none. Now our approach is 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 and I would want them to be but if you look at the cost trends and efficiency trends we've got and - where we’re putting on capital going forward as capital base roles over I think we've got some very strong assets so that going forward the assets that we got the investments that we’ll able to make will earn good return. So I think all of those things distinguish us in what is - from a topline point of view a difficult time that we're emerging from and one that will not likely be the same $100 environment that that we saw a few years ago, maybe that's a long answer.

Really great. Just a quick second one, Venezuela. Any insight to how bad is the industry - 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 will be able to hold relatively flat or will you going to continue to see this decline for the year?

Well for the most part I’m going to comment on our operations and we've been able to navigate pretty well down there have good relationships in Venezuela but 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 difficulties there 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 difficult time thus far we've been able to manage it working well with the government.

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 and 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 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 cash from operations in the 13 billion range but it's easy to see big chunks of improving in cash flow going forward. Capital spending, the cash C&E was 18.7 last year with 15.1 that's 3.5. Oil averaged $44 a barrel if it averages 55 our sensitivity is you know that that's another $3.5 billion. We made a capital contribution to TCO technically alone for $2 billion last year and didn't receive a dividend of consequence last year. So you could see another $3 million swing net out of TCO and that doesn't even count the Gorgon and Wheatstone. The fourth quarter had a once in five years shutdown of Richmond refinery that probably cost us $3 million. We had Agbami down for once in eight 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 the – obviously the underlying risk will have to be considered in price, 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 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 four 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, [Atwater] [ph] 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 am just wondering if there is 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 those 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 decline. So I don't have the real – when we were early last year we were down around $30 a barrel and we weren’t 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 I think it was very difficult time for everyone in the industry. But if we get back to a more normal level of activity you can see sort to 2% to 4% kind of declines that I think would be normal and the individual asset ultimately matures but -- I don’t think I can give you a lot more general guidance than that.

Thanks Ed.

Okay. Thank you.

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

Yes, good morning. John, you should tweet your US 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 US. 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 offset there as they 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 bouts 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 workers 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 confide 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. 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 deepwater rigs. But over time all these rigs come off contracts and so when you think about the future of a deepwater development, the costs are coming down not going up. So there's some risk in isolated markets in areas but I think overall we’ll be able to manage it.

No, 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 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. 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 on the non-operated side. We've got - our budget is about $2 billion there and look we expect to ramp up this year in the $50 to $60 range. We're going to continue to ramp up and I just want to say we want to do it efficiently.

Thanks Evan.

I appreciate it.

Thank you. Our next question comes from the line of Alastair Syme from Citi. Your question please.

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've had good demand for LNG. We were able to sign a couple of contracts last year. So that now Gorgon and Wheatstone sort of 85% maybe slightly more sold which is right about where we want to be. And if you look at where spot pricing have been it’s clear that there's been incremental cargos going into China and Japan. So it's been somewhat encouraging I think and if you look at some of the environmental objectives they are 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 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 FID is taken on new projects but it's been encouraging to see a bump up in prices.

As a follow-up John, 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 off take 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 and of course we've done some work on pipeline. But I don’t want to advertise, 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 got the three trains lined down and operating smoothly and I think that will happen then you'll see the potential for debottlenecking and re-rating 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 for that matter where the same sort of principles will apply. We want to really get the most we can out of the year and hardware that we have and then contingent on market. We have a strong resource base there. We’ll contemplate additional development.

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

Hello, good morning. 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 is anything necessarily that’s going to reverse. 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 5,200 pure 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 under funded on our pension and now those retirements occurs and 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 kind of employee reduction, 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 is 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 million to $400 million is 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. And then, John, maybe following up on Alastair's question but stepping out a little broader on FIDs. Is there, and I recognized the Analyst Day, that it might be more detailed 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 maybe more patience and waiting

I think most of the money that we'll be spending in fact the four deep water rigs I mentioned will be developing drilling. I think it’s a bit early to think about FID on something on Anchor and Tigris. We’re just completing a couple of appraisal well if you will. We need to evaluate those. We're looking a different concepts for example in the deepwater there is technology that needs to be qualified there to be sure that it move them along we got industry groups that are working with vendors and suppliers to try to take cost out so I would say its work-in-progress, there is plenty of work to do that I would call brownfield activity you know off of existing facilities and so that’s where most of the money will be spend. We talk previously about Rosebank and I would 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 any of those big ones where we likely to see and FID in 2017.

Great. Thank you.

Thank you. Our next question comes from the line of Guy Baber from Simmons and Company. Your question please.

Good morning everybody. I just wanted to follow up on the cash margin discussion a little bit more and 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 at 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 thereto kind abate you a little bit and to watch your appetite and I think we successfully did that and I think all the things you point to are or what we were 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 are seeing the place of portfolio actions that we're taking, we'll update you little bit more to SAM guys. 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 to the SAM in five 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&D costs this year? And then given F&D can be lumpy in any year and the cost deflation you have 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?

Well I agree with you that the reserve replacement numbers are pretty good, I'll tell you, if I go back to beginning of the year we weren't expecting to be near 100%, so a lot of the work that the people on our business units did, we got them focused on shorter cycle activity and it's an excellent work in terms of characterizing reservoir seismic work and others to enable us to appropriately book reserve. So you're right, we had a good year and particularly given that we understand dramatically relative to plan. So all that is - all that is good. F&D cost if you think the oil and gas disclosure can be really lumpy and you really have to look at and averaging over time. We've tended to give you development cost on a project-by-project basis. It doesn't always line up exactly with - the proved reserves 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 on 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 are 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 better idea of what development cost 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 when I got here today.

Understood. Thanks very much.

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 am 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 are 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 improvement, finishing capital projects, lower spending, some assets sale proceeds et cetera. We do expect to be cash-flow positive. The priority on the dividend is that 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 take stock of it. Every quarter we make a look and we'll increase it as we find appropriate. I guess the one point I'm trying 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 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 are cognizant of the dividend policy and we are going to maintain the strong balance sheet. But I am not going to give you a specific guidance on the dividend at this time other than to say I am acutely aware of how much 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. I was 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 am 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 the huge inventory you might not be drilling for 20, 30 years. So just how do you balance managing the asset versus kind of showing the value to the market?

It’s very important for us to have value realized in a reasonable period of time. And there is no intention to warehouse acreage that we are not to going to get to. In fact, if you look at the asset disposal we have, we've been high grading our portfolio very steadily. What I don't want to do, is dispose a acreage prematurely before we've been able to assess it fully. If we have followed what some wanted us to do, we would have sold things a couple of years ago that are now worth five 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 will just make a minor editorial comment. There are lot of people with ulterior motives out there when it comes to disposal of assets and we are prosecuting our agenda across our competitive and 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. That is and we recognize that we do continue to get 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. Very clear, thank you

I think we have one more question.

Our final question comes from the line of Blake Fernandez from Howard Weil. Your question please.

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 have heard from Chevron. So you can 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 work with the operator. We’ve been able to get cost 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 billion of deferred tax. And I assume that that begins to be a net positive once the US Upstream is net income positive, which it was this quarter. So is it fair to think that that is 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 the tax losses and carry them back to earlier periods where we have taxable income. And depending upon what happens to prices and how we operate U.S. both upstream and downstream, 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 you again in March and 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.