Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's fourth quarter 2018 earnings conference call. At this time, all participants are in listen-only mode. After the speakers' remarks, there will be a question-and-answer session, and instructions will be given at that time. If anyone should require assistance during the conference call, please press star then zero on your touch-tone telephone. As a reminder, this conference call is being recorded. I will now turn the conference call over to the Chairman and Chief Executive Officer of Chevron Corporation, Mr. Mike Wirth. Please go ahead.
Thank you, Jonathan. Welcome to Chevron's fourth quarter earnings conference call and webcast. On the call with me today are Pat Yarrington, Vice President and Chief Financial Officer, and Wayne Borduin, General Manager of Investor Relations. We'll refer to the slides that are available on Chevron's website. Before we get started, please be reminded that this presentation contains estimates, projections, and other forward-looking statements. Please review the cautionary statement on slide two. Back in March, I laid out Chevron's strategy to win in any environment. I outlined our three compelling strengths: an advantage portfolio, sustainability at lower prices, and a strong balance sheet. I also indicated that the combination of these distinct advantages, together with the commitments to action highlighted in blue, would deliver growing free cash flow and shareholder returns. In 2018, we delivered.
We grew oil and gas production by more than 7%, achieving our highest ever annual production. We grew cash margins in our operated upstream assets, contributing to an improvement in cash returns. We lowered our unit costs, and we sold $2 billion of assets. These outcomes yielded record free cash flow, a dividend increase, and the initiation of a share repurchase program. 2018 was a very successful year, and we intend to build on this momentum in 2019. Turning to slide four, a view of our sources and uses of cash. Excluding working capital, we generated over $31 billion in cash flow from operations, and we achieved record free cash flow of nearly $17 billion, the highest level ever achieved by Chevron in any price environment. This allowed us to deliver on all four of our financial priorities.
For the 31st consecutive year, we maintained our commitment to dividend growth and paid out $8.5 billion in cash dividends to our shareholders. Earlier this week, we announced a $0.07 per share increase in our quarterly dividend to $1.19 per share, representing a 6% increase. Second, we allocated capital across a diverse portfolio and funded our highest return projects. We have confidence these investments position us for sustainable growth and free cash flow. Third, we strengthened our balance sheet and paid down debt by $4.5 billion. Finally, we began repurchasing shares in the third quarter and increased the rate in the fourth quarter, demonstrating further confidence in our future cash generation. With that, I'll turn the call over to Pat, who will take you through the financial results. Pat?
Okay, thanks, Mike. Turning to slide five, an overview of our financial performance. Fourth quarter earnings were $3.7 billion, or $1.95 per diluted share. 2018 full-year earnings were $14.8 billion, or $7.74 per diluted share, up more than 60% from 2017. In the quarter, foreign exchange gains of $268 million were offset by a special item related to a project write-off. A detailed reconciliation of special items and foreign exchange is included in the appendix to this presentation. For the full year, earnings excluding special items and foreign exchange total $15.5 billion. Return on capital employed for 2018 was 8.2%, up from 5% in 2017. Our debt ratio at year-end was 18%, and our net debt ratio was approximately 14%. During the fourth quarter, we paid $2.1 billion in dividends, bringing the full-year total to $8.5 billion.
We increased the rate of our share repurchases from $750 million in the third quarter to $1 billion in the fourth quarter. Turning to slide six. For the full year, cash flow from operations totaled $30.6 billion, about 50% higher than 2017. Headwinds, as we've defined them in the past, totaled $3.2 billion for the year, in line with my original guidance. For the quarter, cash flow from operations was $9.2 billion. It was lower than in the third quarter, primarily because of lower commodity prices, but it was well above first quarter when prices were comparable. This improvement within the year was due to the growth in production. Cash capital expenditures for the quarter were $4 billion and $13.8 billion for the year. The resulting free cash flow of almost $17 billion reduced our dividend break-even price.
We are covering our cash CapEx and dividend at just under $53 Brent without consideration of asset sale proceeds. Before moving off cash flow, a little guidance for 2019. If prices hold at current levels, we expect headwinds for 2019 to be between $2 billion and $3 billion. Now on to slide seven. Full-year 2018 earnings of $14.8 billion were approximately $5.6 billion higher than 2017. Special items, primarily the absence of a U.S. tax reform gain of $2 billion, lower gains on asset sales, and an increase in charges relating to project write-off. Resulted in a net $3.9 billion decrease in earnings. A swing in foreign exchange impacts benefited earnings between the periods by $1.1 billion. Upstream earnings, excluding special items and foreign exchange, increased by about $9.3 billion between periods, primarily because of higher realization and increased lifting.
Slightly offsetting were higher operating expenses, largely associated with continued ramp-up in production, along with additional taxes and other costs. Downstream results, excluding special items and foreign exchange, decreased by just over $90 million. Lower volumes reflected the sales of our Canadian and South African refining and marketing assets, while higher operating expenses were associated with planned turnaround activity in the U.S. These items are mostly offset by favorable timing effects and improved results at CPChem. In the other segment, excluding special items and foreign exchange, net charges for the period increased by almost $750 million, due primarily to higher interest expense and lower tax deductibility for corporate charges. Full-year net charges were $2.3 billion, in line with our guidance. Our 2019 guidance for the other segment remains about $2.4 billion in net charges. As a reminder though, quarterly results in this segment are non-ratable.
On slide eight, 2018 production was 2.93 MMbpd , an increase of 202,000 bpd , or more than 7% from 2017. This is the highest level of production in the company's history. Excluding the impact of 2018 asset sales, production grew approximately 8%, or 1% above the top of the guidance range we provided last January. Major capital projects increased production by 227,000 bpd as we continue to ramp up production at multiple projects, most significantly Wheatstone and Gorgon. Shale and tight production increased 132,000 bpd , primarily in the Permian, where production grew by more than 70% from 2017. Base declines, net of production from new wells, mostly in the U.S. Gulf of Mexico and Nigeria, were 19,000 bpd .
The impact of asset sales, in particular from the U.S. Mid-Continent, Gulf of Mexico Shelf, and the Elk Hills field in California, reduced production by 50,000 bpd . Entitlement effects in total reduced production by 46,000 bpd , 17,000 bpd of which was due to the effect of higher prices during the year. Higher planned turnaround effects, primarily at Angola LNG and Tengiz, reduced production between years by 26,000 bpd . I'll hand it back to Mike.
Thanks, Pat. Turning to slide nine, reserve replacement continues to be a real success story. In 2018, our reserve replacement ratio was 136%. We added almost 400 million more barrels than we produced and divested. This outcome is especially significant because it was achieved while growing production more than 7%. Our reserves to production ratio stands at a healthy 11.3 years, showing the strength and sustainability of our portfolio. Our five-year reserve replacement ratio of 117% further illustrates that strength through the price downturn. Moving to slide 10. We continue to maintain our commitment to capital discipline. Total C&E in 2018 was $20.1 billion. This included approximately $600 million of inorganic spend for which we don't budget, primarily related to bonus payments for offshore leases in Brazil and the Gulf of Mexico. The stacked bar depicts our organic C&E budget for 2019 of $20 billion.
Within this budget, the cash component is $13.7 billion, while the remaining $6.3 billion is expenditures by affiliates, primarily TCO and CPChem. In the 2019 budget, $3.6 billion is allocated to the Permian, and another $1.6 billion is allocated to other shale and tight assets. We expect approximately 70% of our total 2019 spend to deliver cash within two years. Our current spend profile has significantly lower execution risk relative to the past, when we had several large-scale major capital projects underway concurrently. Turning to slide 11, I'd like to provide an update on our portfolio optimization efforts. During 2018, we received before tax asset sale proceeds of $2 billion, with the largest contributors being the divestment of our Southern Africa refining and marketing business and our interests in the Elk Hills field in California.
We recently completed the sale of our interest in the Rosebank project west of Shetlands in the U.K. In addition, we expect to close the sale of our interest in the Danish Underground Consortium in the first half of 2019. Earlier this week, we executed an agreement to sell our interest in the Frade field in Brazil. We continue marketing our U.K. Central North Sea and Azerbaijan assets. As with all divestments, we're focused on generating good value from any transaction. The progress we made last year is consistent with our guidance of $5 billion-$10 billion in asset sale proceeds from 2018-2020. Turning to the Permian, production in the fourth quarter was 377,000 bpd up 172,000 bpd or 84% relative to the same quarter last year. Annual production was up more than 70%. In the Permian, we remain focused on returns.
We're not chasing a production target, nor are we altering our plans based on the price of the day. Over the last two years, we transacted more than 150,000 acres through swaps, joint ventures, farm outs, and sales, further optimizing our large land position. In 2018, we had takeaway capacity for oil and liquids that was more than sufficient, and we've already added more capacity this year. We are pleased with our position and leading performance in the Permian. In just two years, we've doubled our rig count, increased our resource base, decreased unit development and operating costs, and more than doubled our production. We'll provide new guidance for our Permian portfolio in March. Moving to LNG, the plants at Gorgon and Wheatstone performed well during the fourth quarter and averaged almost 400,000 bbl of oil equivalent per day. This was despite higher summer temperatures in December.
Higher temperatures, as you know, generally reduce LNG throughput. We loaded 329 LNG cargoes from Gorgon and Wheatstone last year. We've now commissioned the Wheatstone domestic gas plant and expect to provide gas to the local market in the next few weeks. We'll begin our routine cycle of plant turnarounds at Gorgon this year. We'll be on a four-year cycle with one train undergoing maintenance each of the first three years, and the fourth year having no turnaround scheduled. We expect turnarounds at the Gorgon trains to last about 40 days. These turnarounds offer the opportunity to perform routine maintenance and also to make small enhancements that increase reliability and throughput. We anticipate significant cash generation from these assets for many years to come. Slide 14 shows our production outlook for this year, assuming a $60 Brent price.
We expect production to be 4%-7% higher than last year, excluding the impact of any 2019 asset sales. Our growth is largely driven by shale and tight assets and full-year production from train 2 at Wheatstone. These forecasts always need to acknowledge the uncertainties in our business as noted on the slide. In summary, we anticipate a third consecutive year of strong production growth. Moving to slide 15. As announced earlier this week, we've signed an agreement with Petrobras America Inc. to purchase its 110,000 bpd refinery and related assets in Pasadena, Texas. This addition to our Gulf Coast refining system allows us to process more domestic light crude, supply a portion of our retail market in Texas and Louisiana with Chevron-produced products, and realize regional synergies through coordination with our refinery in Pascagoula.
We expect to close by mid-year, and we'll provide further updates at our analyst meeting in March. Now, just a few comments about future expectations. We expect positive production trends to continue in the first quarter and throughout 2019, reflected in the 4%-7% growth forecast. As early as the first quarter, we expect additional co-lending to TCO in support of the future growth project. In downstream, we expect low refinery turnaround activity in the first quarter, which as you'll recall from our previous disclosure, equates to an estimated after-tax earnings impact of less than $100 million. Earlier in the call, Pat provided you guidance on cash flow headwinds and corporate charges for 2019. As we communicated earlier this week, there will be a $0.07 per share quarterly dividend increase, and we anticipate $1 billion in share repurchases during the quarter.
Moving to slide 17, I'd like to share a few closing thoughts. As I mentioned before, we intend to win in any environment. As a result of our advantaged portfolio, capital discipline, lower execution risk, strong balance sheet, and record level free cash flow, we are well-positioned to continue to deliver strong shareholder returns. That concludes our prepared remarks. We're now ready to take your questions. Keep in mind that we do have a 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. Jonathan, please open the lines.
Thank you. Ladies and gentlemen, if you have a question at this time, please press star then one on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. If you are listening on a speakerphone, we ask that you please lift your handset before asking your question to provide optimum sound quality. Again, if you have a question, please press star then one on your touchtone telephone. Our first question comes from the line of Phil Gresh from JP Morgan. Your question please.
Yes. Hey, good morning, Mike and Pat.
Morning, Phil.
First question. You talked about the dividend break-even of $53 in 2018. You've stepped up the dividend here at a higher rate than last year, and you're also stepping up the buyback. I guess maybe if you could just elaborate a little bit on this, on the break-even, where you see that going. Is it moving lower and giving you more confidence in more return of capital, or just how you think about that calculus?
Well, Phil, we worked really hard over the last few years to get that break-even down. We were in the 80s not that long ago and have made significant progress in bringing the dividend break-even down. We've provided, I think, a simple way to think about it in some of our prior definitions. As we look forward in 2019, we think the dividend break-even remains in the area where it was last year. You see we've got really strong cash flows coming in right now. The commitment to a competitive increase in the dividend, the confidence to step up the rate of share repurchases is evidence of our confidence that we've got those cash flows coming in a price environment, any reasonable price environment, as Pat has said, that we'll be able to sustain those kinds of payouts.
The other thing I'll just point out is our capital spending is still the same, and we've got the ability to provide strong production growth, sustain the kind of cash margins that you've seen out of our portfolio, and do that at really modest capital spending relative to our history.
Sure. Okay. Thank you. The second question, I guess, would just be on that capital spending budget, specifically for 2019. The Permian piece, pretty flattish year-over-year, which I think you highlighted last quarter. The non-Permian shale piece is stepping up quite a bit here, and I just want to know if you could maybe elaborate on that a little bit, not to steal any thunder from the Analyst Day. Is that something that is going to be contributing to this 2019 production growth guidance, or is that something that you're ramping in 2019, it would be more of a future contribution?
We are beginning to ramp in the other basins. We've added rigs, actually, in all the other shale and tight basins in which we operate. We've seen significant reductions in development costs in the Marcellus, in the Duvernay, and in the Vaca Muerta, as we've shared the learnings and improvements that are emanating from the large-scale activity we have in the Permian. The economics on each of these are compelling. The EURs are coming up. While the Permian may be in the spotlight within our shale and tight portfolio, it's far from the only asset that we have. The other thing that I just note is we've begun an eight-well appraisal program in El Trapial in the north of the Vaca Muerta. We're currently producing in the southern area at Loma Campana.
Our folks are intrigued by the possibilities up in the north at El Trapial, and we continue to prosecute that program. We've also picked up additional acreage in the Neuquén, 25,000 net acres where we're non-operated with YPF, and we've got a four-well pilot that we plan to execute there in 2019 as well. Great potential in Argentina. We really like our entire shale and tight portfolio. Again, it brings some of the characteristics we've been talking about, which is short cycle time, attractive economics, low development costs, and the ability to generate cash relatively rapidly. The last thing I'll say about that is it brings a much lower risk profile than multi-year, multi-billion dollar capital projects.
Okay. Thanks, Mike. Pat, what was the amount of the co-lend there for TCO?
In 2018, the co-lend was zero.
No, for the 1Q guide. I'm sorry.
Oh, the 1Q guide. Okay. I don't have a confirmed number here for you because it will depend on what happens to price. It will depend on what happens and how cash flow that's generated from operations matches against the investment profile for the project. It will also depend on the dividend distribution requirements for the partners. I think order of magnitude, if you go back and you look at 2016 when we first started the co-lending, that was about $2 billion. I think as an order of magnitude starting off base, maybe think about $2 billion for this year. As I say, we reserve the right to change that number as the year progresses and we see what actually happens to prices and the investment profile and as discussions are underway on dividends.
Thanks, Pat.
Thanks, Phil.
Thanks, Phil.
Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question please.
Hey, guys. Good morning.
Good morning.
Morning, Paul.
Mike, you talk about Argentina. Wondering, given the political environment, the infrastructure or lack of infrastructure over there, how quickly you think you can proceed with the development plan, and any kind of timeline or the pace or the capital outlook, any kind of data that you can share?
We'll probably talk about this a little bit more in March, Paul. I'll just reiterate, YPF has been a very good partner there. The Macri government is committed to improving the investment climate in Argentina and has instituted a number of reforms to encourage and support energy development in the country. We have great resource there that's benefiting from the Permian learnings and competitive economics, multiple blocks that we've picked up. Much of the production can actually stay in the country. At this point, yes, the infrastructure is not developed the way that it is in the U.S. or perhaps North America more broadly. There's a commitment on the part of the government to do that, and we'll pace our development with gas and liquids takeaway and market conditions.
The realities on the ground in Argentina are a little bit different. I got to say the resource is tremendous and we're very encouraged by the policy reforms that have been put forth by the government.
For Pasadena, the refinery that you just bought, what's the game plan for that facility? Are you going to need to make significant investment upfront to bring them to the Chevron standard? Because that facility probably has been under-invested at least for 20 years, if not 30+ years, and that the labor relationship has been always very rocky. What's the game plan, how much is the upfront investment? Exactly, are you going to run it as a full-blown facility or is that sort of like an extension of Pascagoula?
Let me try to respond to that, Paul, as best I can. We just executed an agreement this week. We don't expect to close here until somewhat later here in the first half of the year. It's a little premature for me to lay out an investment plan till we actually close the transaction. In the due diligence, we've satisfied ourselves that we can operate the facility safely and reliably at the standards that we would expect. I don't think you should have any concerns there. It meets our kind of three primary criteria. One, we're getting it at a good price. I believe one of the ways that you take risk out of refinery acquisitions is you don't overpay. I don't think that we're overpaying for the asset.
It's in a great location, that allows us to integrate to increasing light crude production out of West Texas. It allows us to serve our markets in Texas with product that we run through our own system as opposed to exchange or purchase product, it will allow us to optimize and integrate with the Pascagoula refinery. The third thing is it provides good, strong economics. Because of our system and the three kind of strategic levers that I just talked about, we ought to be able to optimize that refinery as a part of our system in a way that is different than what the current owner can, simply because they don't have those other assets and those other positions. Within our business, this fills a bit of a gap. It gives us the ability to capture value in multiple different dimensions.
Over time, we'll evaluate what investments we may choose to make there as we would in any other refinery. I would expect those to be relatively modest. I would expect them to be thoughtfully paced over time and to fit within the level of spending that we've established over the past many years in our downstream business.
Thank you.
Thanks, Paul.
Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question, please.
Good morning, Mike and Pat and Wayne here. The first question I had was around Tengiz and the latest on the project. Are you feeling good about the timeline and thoughts on costs and the contingency as well?
Yeah, Neil, I probably don't have a lot to add to what we've previously said on this. We're still on schedule, we're still targeting a 2022 startup. As I think Jay mentioned on the third quarter call, on-site productivity has improved. We had a very good summer. The logistics are working very well as we're moving modules now from Korea to the staging points. We can't move through the inland waterway system during the wintertime because it freezes up, but modules are arriving from Korea, from Italy, and from Kazakhstan. The quality levels are very high. We're about halfway through the project, about 50% complete at this point. 2019 will be a key year. There's a lot of activity in terms of moving modules into the Caspian to the site, a lot of field work.
We'll see if these productivity gains can be built upon again in 2019. It's certainly a year where we will reduce uncertainty. Jay is actually headed there this weekend and will be there next week. When we get to New York in March, he will have had recent field visits to Kazakhstan and also to Korea. He was in Korea visiting the module fabrication yards last week, he'll be in a position to give you a very good insight into exactly where we stand and what our expectations are.
Yeah, looking forward to that. The follow-up, we just want to get some more color on the share buyback to follow up on Phil's question. I think most of us were expecting $750 million. You came in at $1 billion in the fourth quarter. As we think about the share buyback program, our view had been that this program would be a kind of a base load $3 billion program into perpetuity, you're demonstrating that you're willing to flex and lean into it. Can you talk about the philosophy behind that share repurchase program? Is a higher run rate potential and potentially sustainable? How you think about flexing it from a big picture then a more granular perspective?
Yeah, I'm going to let Pat take that.
Neil, thanks for the question, and I think the key word here is sustainability. What you saw with our increase was just our view of our future cash generation, the confidence that we have in our future cash generation, and a belief that we could move that rate of quarterly purchase up to $4 billion. When we first initiated this back in the second quarter call, the points that I made were that we really wanted to have this be through the cycle and sustainable through the cycle. We pegged it at $3 billion because we thought that would be supportable through any reasonable price environment. We obviously had stronger prices in 2018. Now they've come off a little bit, but we still feel very strong about our cash generation in 2019 and frankly, in the years to come.
You will note, maybe you won't note, but we did release an 8-K this morning as well that talked to the fact that our board has supported a resolution for a $25 billion share repurchase program with no term limit. I think that $25 billion gives you an indication of the commitment that we have to this program, our view about the sustainability, and I think that should be a very strong message to our investors about our willingness and intent to boost shareholder distributions.
Thanks, Neil.
Thank you.
Thank you. Our next question comes from the line of Jason Gammel from Jefferies. Your question, please.
Thanks very much. Hello, folks. I wanted to ask a question about the cost structure of the company. The reason I ask is you've already taken a lot of cost out of the upstream, but you seem to be with divestitures and some expirations concentrating more and more into the highest quality assets. I'm just wondering if there's the potential to take further overhead out of the business through medium term, shutting down regional offices, et cetera. This seems to be right out of the Mike Wirth downstream playbook of taking further costs out and enhancing returns through concentration.
Well, Jason, I'll give you a short answer. The answer is yes. I think in a commodity business, you always have to be looking for efficiencies, and I think scale matters, and we need to continue to look for ways to control our own destiny. A big part of that is moving into assets that have inherently lower cost structures and continually seeking an efficient overhead structure to support that. I will tell you that not only can you do that through what I would call conventional means in the way that it's always been done, but technology today offers us the ability to do even more as we bring digital technologies into our business and can do things in a business that really grew up in an analog world. There's a lot of opportunity to find more efficiencies.
The other thing, when you're growing your business, it's important to pay attention to unit costs, and we've seen unit costs come down significantly. We see this year another 2% reduction or so in unit costs. As you look out to 2020 and 2021, I think that number can go up even more in terms of the percent reduction or the other way to say it is unit costs can come down even more. We need to be prepared to be competitive in an environment where prices are not what we look to, and we'll continue to work on cost efficiencies across our entire portfolio.
Appreciate your thoughts, Mike. Just a very quick follow-up. Can you talk about the ramp-up progress at Bigfoot?
We've got the first well online, and it's been performing very well. It came on in November of last year. The second well is being drilled and completed as we speak, and we anticipate that coming on here in the first quarter. We'll steadily move through the process of adding wells at Bigfoot, and you can expect that to be part of the net production story in 2019.
Appreciate your thoughts. Look forward to seeing you in March.
Thanks, Jason.
Thanks, Jason.
Thank you. Our next question comes from the line of Paul Sankey from Mizuho. Your question, please.
Good morning. You mentioned that you've done about 150,000 acres of swaps or sales, I believe, in the Permian, Mike. Hi, Pat, by the way. Sorry, I slightly caught off guard there. I wanted just an update on where your final numbers are for Permian acreage and how you feel about that, given that there's potentially some fairly major assets available. I guess you're strongly outperforming your volume targets. Can you also talk about your returns there? Because there's concerns that you're perhaps not as leading edge as we might want you to be in terms of your Permian performance on a returns basis. Thanks.
Yeah. We'll share a lot more detail in March because as you can see, the performance out of the Permian continues to be exceptionally strong. With the large land position that we have, we've got good currency and optionality to try to improve that because everybody is interested in drilling longer laterals, finding contiguous development areas. With our 2.2 million net acres and 1.7 million in the Midland and Delaware basins, we've got lots of levers with which to optimize our position. The nice thing about these transactions is they are truly win-win because you can transact with other people. There's enough economic value creation that you're not trying to split a finite pie, but you're actually creating a bigger pie for both. Our currently disclosed resource there is 11.2 billion bbl. That's a figure we would expect to grow.
Our confidence in the Permian is higher today than it was the last time that I spoke to you. When you talk about returns, we've put out data before on the returns that we're seeing, and they're well up in the 35%+ range as we've moved to longer laterals, a better basis of design. Even in a modest price environment, we're seeing very strong returns. It's as good or better than anything else we could be doing. We are returns driven, I mentioned that in my prepared remarks, and I'll reiterate that. It's returns across the life cycle of the asset, and it's returns across the entire value chain. We're not looking to put the most wells online or have the biggest IPs. We're looking to get the best returns out of the system. We paused at 20 rigs.
For several years, we've been telling you we're going to grow to a 20-rig fleet. As you go through that kind of growth, you stress the system a little bit. We're pausing in terms of adding rigs at this point in order to ensure that anything that needs to improve from a performance standpoint will. We engage in regular benchmarking within the basin. We have a number of non-operated joint ventures. We've got really good visibility into what other operators are doing and what levels they're performing at. I'll simply tell you that we are continuing to improve performance in every dimension and intend to continue to, using benchmarking to identify the areas where we can get better. Jay will talk a lot more about this in March.
We'll have a breakout session that'll give you a chance to go into detail with questions as well. We feel like we're delivering better performance. Across the value chain, I mentioned we've been well situated with takeaway capacity, we've added capacity already in 2019. We're able to capture margin across the value chain, later this year, that will include refining margin.
Thanks, Mike. We know also that you've got an advantaged mineral right position now, which seems to be one of the issues with any potential major deals that might occur in the Permian in the near future. Mike, if I could ask you another one. I was going to make some elaborate joke about you keeping it competitive by not having just the CEO on the call, but also the CFO. Obviously referring to Exxon's CEO being on the call this morning. There is a number of major differentiations between the two companies, and one of them is your flat CapEx outlook. I think that you would do well to maintain that. I think it is a relatively long-term outlook as it stands. You've just drifted towards the top of the range without going above it.
What are the prospects of you actually seeing falling CapEx and CapEx that surprises to the downside going forward, given that your growth trajectory looks very good for a company of your size? Thank you.
Yeah. We're committed to capital discipline. We can grow our business at modest capital levels, and we've got more good things to invest in than we will invest in. Last year, there are two notable examples. We relinquished our rights to the Tigris development project in the deepwater Gulf of Mexico, not because it's not a good project, not because it can't generate a return, but we have better opportunities within our portfolio. The same thing with Rosebank. A good project, a lot of resource, but one that probably fits better for someone else than it does for us, given our alternatives to invest. We will continue to make those kinds of choices. The one thing that came up in the call earlier were the other shale and tight opportunities, and those are really economic as well.
There's opportunities for us to, whether you're talking in the Permian or some of these other areas over time, to find highly attractive opportunities to invest further capital, generate strong returns, minimize execution risk, short cycle. As our portfolio grows, we were up 5% in production two years ago, 7% last year. We've just outlined 4%-7% this year. A growing portfolio over time does require modestly higher base capital spending that would go with that. We're committed to capital discipline, and I think you've characterized our ability to grow at relatively flat capital well. We'll update forward views beyond what we've already articulated when we get to the March meetings. Thanks, Paul.
Thank you.
Thank you. Our next question comes from the line of Blake Fernandez from Simmons. Your question, please.
Hey, folks. Good morning. Two questions for you. One, could you talk a little bit about Venezuela? I know it's early days, but obviously you do have exposure there, both upstream and downstream, and just any helpful thoughts that might help us out on our end?
Yeah. I can give you a quick update on Venezuela, Blake. The first and most important thing for us is the safety of our people on the ground. That's what we're really focused on. We also want to be sure the operations where we have an interest are safe and environmentally sound, and I can tell you that is the case. We've worked closely with the government to be sure that we understand the intent of the sanctions. There's been a number of new general licenses issued by the Treasury Department. We're in close consultation to be sure we understand them and how they are to be applied. I will say that the U.S. government has been very interested in engaging with us to understand our position on the ground, and we continue to operate.
I think for the foreseeable future, we feel like we can maintain a good, stable operation and a safe operation on the ground in Venezuela. If you look at it from the downstream side in the U.S., Pascagoula is the one refinery of ours that tends to run Venezuelan crude, and it runs 70,000 bbl, 75,000 bbl, give or take. For some time, the prospects of actions like this have been clear, we've had contingency plans in place. We've got alternate sourcing. We've got plenty of crude in tank for Pascagoula. We've got crude on the water there. We're good here for the balance of the first quarter and maybe even a little bit beyond. We've activated our contingency planning into a full-scale execution right now. We'll keep the refinery full with crude.
We'll optimize, I think we feel like we're going to be able to navigate through this. Our biggest hope is for stability on the ground in Venezuela and the safety of not only our employees, but our contractors and the people in Venezuela.
Okay. I appreciate that. The second question, I know you've covered Pasadena, we'll get some additional color in March. Just more broadly speaking, I think you've alluded to a potential acquisition of a refinery on the Gulf Coast for some time. The size of this is 110,000 bpd or so, which isn't small, but it's not really large in context of some of the Gulf Coast facilities. Does this satisfy your appetite or integration potential there, or do you think there's additional scope to expand that over time?
I don't want to speculate. We've got one transaction here that we've signed an agreement on. The key is value and the ability for it to not only yield value on a standalone basis, but to integrate into our network and be sure we can capture value out of that. We're focused on that with the Pasadena refinery, I think I'll leave it at that.
Understood. Thank you, Mike.
Thanks, Blake.
Thank you. Our next question comes from the line of Roger Read from Wells Fargo. Your question, please.
Yeah. Thank you. Good morning.
Roger.
I know all the really fun stuff has got to wait till March, but maybe to take a look at your CapEx mix, you mentioned 70% has a two-year or less waiting to cash flow, whereas the rest, obviously longer. Do you think as we not so much look at a total CapEx number, but the mix within that CapEx, does that start to change back over the next couple of years? I'm thinking, number one, you signed a long-term deepwater rig contract, obviously aimed at some of the more challenging parts of the deepwater Gulf of Mexico. As things like that start to come in, do we see that start to move maybe to more of a 50/50 on CapEx, or is that something you want to maintain maybe more at the 70/30 level as we think over the next several years?
Yeah, Roger, it's a good question because our mix has shifted very dramatically from it was not long ago, and it's come down by 50% from the high watermark, and it's shifted in terms of its makeup. I think both really important issues. Going back to Paul Sankey's question, I think that is the new normal for us. We've got in this year's budget a little bit over $5 billion for shale and tight, 3.6 in the Permian, 1.6 on other shale and tight. Over time, I think that number is likely to grow rather than shrink. We've got FGP, which is in the peak spending years this year and next. That's a non-trivial amount, a little bit over $4 billion in this year's budget. As that moves past the peak and comes down, it creates room for other things.
That could include deepwater. It could include more shale and tight or other major capital projects. On the deepwater, our intent would be to have a ratable development program. I think one of the things that we have learned over this past cycle, I mentioned we had many large MCPs underway simultaneously, is that that introduces execution risk that is real. Our intent would be to have a balanced approach as we go forward and not to find ourselves so overly skewed to that kind of risk that it becomes an issue that's difficult to manage. Because we've got the really strong shale and tight portfolio, I think that plus our base business, which again requires investment but is typically short cycle and quick to go from capital spent to cash in the door.
I think the kind of range that we're in today is more likely to, plus or minus, be the range you would see in the future, as opposed to something that flips back the other direction.
Okay. Thanks for that. Just to beat the Pasadena refining horse a little bit harder here. Part of the acquisition indicated some undeveloped acreage. Are we wrong to think about this as just a refining acquisition, and maybe you should think about it more as an infrastructure opportunity across the board? I'm thinking we're moving more and more towards crude exports from the U.S.
No, I think there's a reason we disclosed that because the asset there is not simply the refinery, but it's the port access, it's the tankage, and it's the land. I've mentioned a couple of times that our goal is to integrate this into our system. That means our upstream system, our downstream system, our trading system. When I was a young pup, one of the lessons I learned from a seasoned engineer in one of our refineries is he said, "The cheapest process unit we have in this refinery is called a tank." There are times when we can fall in love with building complex equipment, and there are realities that you can create optionality and margin through infrastructure and commercial activity at relatively low investment.
I think this asset offers us the opportunity to not just participate in the refining margin, but also to look at the other ways that through our integrated system, we can capture value across the entire value chain, both up and downstream, and that's the way we're approaching this.
Great. Thank you.
Thanks, Roger.
Thank you. Our next question comes from the line of Sam Margolin from Wolfe Research. Your question please.
Good morning. How are you? Mike, I'm going to try to not ask you to say the same thing again in a different way. One of the outcomes of the much faster than expected Permian growth is maybe that the free cash flow profile of the Permian as a standalone entity has been pulled forward significantly. Maybe that's sort of an obvious statement or it's not new, but it seems like that's an important pendulum swing with respect to how you might think about additional long cycle projects.
Among all these other factors that you commented on, kind of pointing you to thinking about expanding the portfolio in deep water or other long cycle areas, is that something that's important too, or is that more something that's on plan and you're just thinking about that within the buyback and the dividend growth and all your other sort of uses of cash that are out there?
I think the increased performance of the Permian is a good news story. We did spend a little more capital last year because we're finding that we can drill more hole. We've changed our basis of design. A little bit of the capital overrun was related to the good news story that we're getting a lot more production out of the Permian. Our guidance has been we're free cash flow positive in 2020, and I think that's still a good way for you to think about it. As we reach the crossover point, it crosses over, and we've increased the dividend, Pat's already addressed the confidence in increasing the rate at which we're repurchasing shares and our intent to sustain that through the cycle.
Having strong free cash flow creates alternatives, we intend to use the free cash flow to be very mindful of the need for shareholder distributions and also to look for good investment opportunities. I mentioned we were able to meet all four priorities this last year in terms of dividend investment, balance sheet, and share repurchases, and our intent is to continue to respect that going forward. This kind of growth in free cash flow allows us to do that.
Okay. Just on a related note, I guess this one's for Pat. Leverage came down a lot. Is there a target leverage to think about conceptually, or is it just something that's going to be a function of commodity prices in terms of the rate at which the balance sheet fluctuates here?
Right. Sam, we don't have a target leverage rate. We think of the balance sheet as being the outcome of other previously outstanding decisions about how we've used the cash that we're generating. As I've said in the past, maybe a 20% leverage ratio on average through the cycle, and that when you're in a stronger price environment, you would obviously build back your balance sheet some, and when you're in a weaker price environment, you'd use it some. I think that's kind of the sweet spot or the sweet area that we're trying to play in. Having a good balance sheet, it's a good insurance policy, and having a good balance sheet allows us for both dividends and share repurchases to sustain those through any period of price weakness. We feel that that's an important component.
Thanks, Sam. Thank you.
Thank you. Our next question comes from the line of Alastair Syme from Citi. Your question please.
Hi. Thanks for taking my question. It was really just one on your view on the state of the Gulf Coast chemical polyethylene market, and how that makes you think about potential expansion plans. Thank you.
Yeah. We're still very positive on the petrochemical investment opportunity, and particularly here in the United States. I think it's a good long-term story. We've seen some pressure on margins here recently. Feedstock costs in the third quarter were up. I think olefin chain margins have been under a little bit of pressure. These things happen in commodity markets with long cycle times for projects and kind of ebbs and flows in the economy. That hasn't fundamentally changed our view on the attractiveness of the sector. Great. Thank you very much.
Thanks, Alastair.
Thank you. Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your question please.
Thanks. Good morning, everyone, Mike, we always appreciate you getting on these calls, so thanks again for doing it this time around. Mike, my question might actually be for Pat. Pat, you talked about the $13+ billion of cash spending. Can you give us an idea as the affiliate spending rolls off with Tengiz completed, how do you anticipate that cash CapEx to trend, excuse me, given that you're holding the line on the $18 billion-$20 billion absolute spending at least through 2020?
I think Mike's answered that question in a way, although he didn't split out cash versus total headline C&E. As you see TCO spending come off and as we move towards first production there in 2022, the other affiliate where we have potentially investment opportunities would be CPChem. What occurs in that particular category will be a function of how decisions are made on file investments for example. It's not something that I can predict with any degree of certainty. I think what's important is that the summation of both what I would say company owned and operated and affiliate owned and operated, we're staying within that $18 billion-$20 billion C&E range for the near term here, certainly, and we'll give you an update in March on a prospectively longer period of time.
I think capital discipline is a theme that you want to read through all of this, and the fact is that we have the opportunity to be very judicious and very selective about how we work in additional projects into our queue.
I know it's a tough one to answer, but given all the variables. My follow-up is kind of related, I guess, but if we go back to 2010, 2011, 2012 through 2014, 2015, obviously a lot of big oils, yourselves included, were spending much higher levels than you are today. And one assumes that that created a lot of cost recovery barrels in some of the PSCs. I guess my question is, to the extent you can, as we look forward, in light of Thailand, how do you see your entitlement barrels trending if you maintain that CapEx at these levels? Do you start to see cost recovery barrels tail off? And if you could maybe offer some quantification of that, I'd appreciate it.
Doug, I don't think we've got numbers here that we can isolate for you on that. Cost recovery applies across a number of locations in our portfolio here. You're obviously aware of what's happened in Indonesia. I don't think I have a pinpointed answer that I can give you on that.
All right. It was worth a try. Thanks folks.
Thanks, Doug.
All right, Doug.
Thank you. Our next question comes from the line of Doug Terreson from Evercore ISI. Your question please.
Good morning, everybody.
Morning, Doug.
Hey, Doug.
Mike, I have a question about portfolio optimization and specifically the divestiture part of the plan. On this point, you guys have had a pretty active program over the years, but you still also have a decent amount of value left in the queue. My question is this because the market for assets has softened somewhat, or do you consider it to be kind of normal course of business during the cycle, or is it something else? Any color on your divestiture program and the market trends you guys are experiencing is really the question.
Yeah. I'm not 100% sure I'm tracking with you there, Doug. We've always had a program of divestitures.
Yeah.
At times it's a little high, at times it's a little bit lower. In this business, you're continually looking to upgrade your portfolio. We've got some things now that are really attractive. I earlier mentioned a couple of things that we stepped away from because we didn't think they would compete for capital. Divestments are driven by a view on strategic alignments with our broader portfolio and our view of the future, the resource potential that remains in a particular asset. Will it compete for capital within our portfolio? There are good things, as I mentioned earlier, that cannot. Can we receive fair value? That may be a little bit of a function of what's the macro environment and the forward view on commodity price. We're in a position that I think you can expect us to continue to high-grade our portfolio.
Yeah. Mike, maybe I should ask it differently. It seems like you guys are experiencing healthy enough appetite for assets if you're a seller. Is that a good way to think about it?
Yeah. Everything we're talking to people about right now, we think we're likely to receive very good value.
Okay. Thanks a lot.
Thanks, Doug.
Thanks, Doug.
Thank you. Our last question for today comes from the line of Biraj Borkhataria from RBC Capital Markets. Your question please.
Hi. Thanks for taking my question. It was actually on reserve replacement. In 2018, you had 136%. That was a pretty impressive figure given the growth trajectory over the last few years. I was wondering if you could just disaggregate some of the impacts there, particularly on the price impacts, in terms of revisions from 2017- 2018, and then what the key kind of moving parts were. Thank you.
We did have another strong year. Our largest adds came through our Permian shale and tight activity, through other shale and tight on some of these other basins we've been talking about, Gorgon and Wheatstone. Primarily in the unconventionals, but contributions across the board from Australia, Canada, Asia, Gulf of Mexico, Eurasia. Price was a relatively small negative revision, less than 100 million bbl on price. We produced just short of 1.1 billion bbl. We sold about 60 million bbl. There was not a big price impact in there. While unconventionals were the big piece, we had contributions from others. The one thing that I would call your attention to is what we view as very high-quality reserve additions. They are barrels that bring with them lower risk. That's lower execution risk and lower geologic risk, and lower breakeven prices.
We would expect to continue to have a good, strong reserve replacement story as we go forward given the quality of our portfolio and the continued improvements that we see, particularly in our unconventional development activities. All right. That is the top of the hour. I want to thank everybody for your time today. I appreciate your interest in Chevron and everyone's participation on the call, and I look forward to seeing many, if not all of you in New York City in March. Thanks very much.
Ladies and gentlemen, this concludes Chevron's fourth quarter 2018 earnings conference call. You may now disconnect.