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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's Third Quarter 2018 Earnings Conference Call. As a reminder, this conference is being recorded.
I will now turn the call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.
All right. Good morning and thank you, Jonathan. Welcome to Chevron's third quarter earnings conference call and webcast. On the call with me today are Pierre Breber, Executive Vice President, Downstream & Chemicals; and Wayne Borduin, General Manager of Investor Relations. We will refer to the slides that are available on Chevron's website.
But before I get started, please be reminded that this presentation contains estimates, projections, and other forward-looking statements and we ask that you review the cautionary statement shown on Slide 2.
Turning now to Slide 3, an overview of our financial performance. The company's third quarter earnings were $4 billion or $2.11 per diluted share. This is more than $2 billion higher than the same period a year ago and this is the highest recorded earnings per share since third quarter 2014. The company's year-to-date earnings were $11.1 billion or $5.79 per diluted share. This was $5 billion higher than the same period a year ago.
The quarter included the unfavorable impacts of a project write-off, an impairment, and a nonrecurring contract settlement, which totaled $930 million. These were partially offset by a $350 million gain on the sale of our Southern African refining and marketing assets. Foreign exchange losses for the quarter were $51 million.
A reconciliation of special items, foreign exchange and other non-GAAP measures can be found in the appendix to this presentation. Excluding these special items and foreign exchange impacts, earnings totaled $4.7 billion or $2.44 per share.
Cash flow from operations for the quarter was $9.6 billion. Excluding working capital effects, cash flow from operations was $9.2 billion. Cash flow from operations continued to grow in the third quarter and was the highest it has been in nearly five years, back when Brent crude prices were averaging about $110 per barrel. Year-to-date cash flow from operations totaled $21.5 billion, about $7 billion more than a year ago.
At quarter-end debt balances stood at approximately $36 billion, giving us a debt ratio of 19%. During the third quarter we paid $2.1 billion in dividends and we repurchased $750 million of our shares during the quarter. We currently yield 4%.
Turning to Slide 4. Our third-quarter cash flow from operations, excluding working capital effects, increased to $9.2 billion, reflecting higher realizations and growing volumes in our U.S. and international upstream.
On a year-to-date basis, cash flow from operations, excluding working capital, totaled $23.3 billion. This included $600 million in discretionary U.S. pension contributions, $800 million in deferred income taxes, and affiliate dividends approximately $2.5 billion less than equity affiliate earnings.
Cash capital expenditures for the quarter were $3.6 billion and $9.8 billion year-to-date. The result, free cash flow excluding working capital effects of $5.6 billion for the quarter and $13.5 billion year-to-date.
Through the first three quarters of the year, normalized for $60 Brent, we are on track to deliver the $14 billion cash generation guidance communicated at the Analyst Meeting in March.
Turning now to Slide 5, a view of our sources and uses of cash through the quarter. We are delivering on all four of our financial priorities. We maintained our commitment to competitive dividend growth by paying out $2.1 billion in cash dividends to our shareholders. We continue to fund our highest return projects at a reasonable pace. We further strengthened our balance sheet and paid down debt by $2.4 billion, lowering our debt ratio to 19%. And finally, we commenced our share repurchase program in the third quarter and returned $750 million of surplus cash to shareholders.
Now on Slide 6, I'd like to provide an update on our portfolio optimization efforts. Through the third quarter. We received before tax asset sale proceeds of $1.9 billion, including the divestment of our Southern African refining and marketing business. Most recently, we signed sale and purchase agreements including the sale of our 12% non-operated interest in the Danish Underground Consortium and the sale of our 40% interest in the Rosebank project west of Shetlands in the UK.
In addition, we continue the process of marketing our UK Central North Sea assets. As with all divestments, we are focused on generating good value from any transaction. The progress we have made year-to-date on portfolio optimization puts us on track to generate $5 billion to $10 billion in asset sale proceeds over the 2018 to 2020 time period as we guided back in March.
Turning to Slide 7, third quarter 2018 after tax earnings $4 billion were approximately two times that of third quarter 2017. Special Items reduced earnings by approximately $1 billion between periods. In the current period, special items included a gain on the sale of South African R&M assets. The write-off of the Tigris project in the U.S. Gulf of Mexico, an impairment on an asset held for sale, and a non-recurring contractual settlement. All of which netted to a negative $580 million.
In third quarter 2017, special items included a gain on the sale of Canadian R&M assets, less project write-offs, for a net positive impact of $455 million. Foreign exchange impacts increased earnings by $61 million between periods.
Upstream earnings excluding special items and foreign exchange increased by almost $3.5 billion between the periods or about five times, mainly on improved realizations and higher liftings. Oil prices were approximately 45% higher in the current period than a year ago.
Downstream results, excluding special items and foreign exchange decreased by about $100 million. This reflected lower margins in Asia and in the U.S., along with foregone contributions from our Canadian downstream assets which were sold. Favorable timing effects and higher earnings from CPChem were partially offsetting. The variance in the other segment was primarily the result of higher corporate tax items and interest expense.
Turning to Slide 8, this compares results for third quarter 2018 with second quarter 2018. Third quarter results were approximately $600 million higher than second quarter. Third quarter special items as detailed previously, when compared to second quarter's non-recurring receivable write-down, resulted in a net negative variance between the quarters of $310 million.
Of about equal size was an adverse swing in foreign exchange impacts between the periods. Upstream results excluding special items and foreign exchange increased by $1 billion between the quarters due to higher liftings and improved realizations.
During the quarter we were in an overlifted position but on a year-to-date basis we are modestly underlifted. Downstream earnings, excluding special items and foreign exchange improved by almost $240 million, reflecting lower operating expenses, particularly those associated with the second quarter turnaround at the Pascagoula Refinery. Favorable timing effects were also evident between periods.
Turning to Slide 9, third quarter production was 2.96 million barrels a day, our highest ever production for a quarter. This moved our year-to-date production to 2.88 million barrels a day. Excluding the impact of 2018 asset sales, which is the middle bar, our year-to-date production growth through the third quarter was 6%higher than the daily average production for full year 2017.
As Jay mentioned on our last quarter call, we had planned turnaround activity across multiple locations in the third quarter. The production impact from these turnarounds was 103,000 barrels per day. 2018 asset sales impacted third quarter production by 18,000 barrels a day and impacted year-to-date production by 12,000 barrels per day. At year end we expect to be at the top of our original guidance range, approximately 7% growth excluding the impact of asset sales. And this is even without normalizing for the impact of current prices on production sharing contracts.
Turning to Slide 10, third quarter 2018 production was 2.96 million barrels per day, an increase of 239,000 barrels a day, or 9% from third quarter 2017. Major capital projects increased production by 237,000 barrels per day, as we continued to ramp up multiple projects, most significantly Wheatstone, Gorgon and Hebron.
Shale and tight production increased 155,000 barrels per day, primarily due to growth in the Midland and Delaware Basins in the Permian, where production grew by 80% from a year ago.
Base declines, net of production from new wells, such as those in the U.S. Gulf of Mexico and Nigeria were 6,000 barrels a day. Major turnarounds, along with planned and unplanned downtime reduced production by 59,000 barrels per day between the periods.
Entitlement effects reduced production by 41,000 barrels a day due primarily to rising prices between the periods. The impact of 2017 and 2018 asset sales reduced production by 31,000 barrels a day between the periods.
Now on Slide 11, Gorgon and Wheatstone continued to operate very well. Combined, these plants averaged 379,000 barrels a day of production during the quarter. This is a 35% increase over the previous quarter.
We had two planned maintenance activities on Wheatstone during the quarter, a scheduled compressor overhaul on Train 1 and a startup strainer removal on Train 2. These reduced production by approximately 21,000 barrels a day on average over the quarter.
We are finalizing the commissioning of the Wheatstone domestic gas plant and expect first sales in first quarter 2019. For this gas, production and sales activity will be dependent on local demand.
With all five Australian LNG trains running reliably, we're focusing on finding opportunities to incrementally add production and enhance reliability.
Turning to the Permian, on Slide 12, Permian shale and tight production in the second quarter was 338,000 barrels per day, representing an increase of 150,000 barrels per day. Let me say it again, this is up 80% relative to the same quarter last year. As many of you will realize, that's the equivalent of adding a mid-sized Permian pure play E&P company in a matter of months.
In our operated Permian acreage, where we hold 100% of the working interest, we had an average of 20 rigs in operation during the quarter. We also had 21 non-operated rigs working on our acreage, which equates to approximately 7 net rigs, Chevron's share.
As Jay discussed on the last earnings call, we remain focused on returns, capital efficiency and operational discipline. Within this framework our production levels are trending about one year ahead of the guidance we gave in March.
I'll now pass it on to Pierre, who can give an update on our downstream and chemicals business.
Thanks. Pat. We have a tightly integrated and profitable downstream and chemicals business. Slide 13 shows that Chevron's downstream has consistently led our peer group in earnings per barrel. And during the past five years our adjusted return on capital employed has averaged over 15%.
Our fuels businesses are focused in the best markets in the U.S. and Asia. In petrochemicals, we are feedstock advantaged, heavily weighted to ethane. And we are the only major integrated with wholly owned lubricants and additives businesses. Looking forward, our objective is to grow earnings across our feedstock to customer value chains and target investments to lead the industry in returns.
Now let me address IMO 2020. As a reminder, new International Maritime Organization regulations will reduce the sulfur emissions from bunker fuels starting in 2020. Although there are a lot of unknowns and uncertainties with how markets will react, most agree that complex refiners should benefit, as demand increases for marine gas oil.
Slide 14 shows that Chevron's refining network has the highest complexity and the highest percentage of conversion capacity among its peer group. It is a result of high-grading our refinery portfolio over the years and investing in upgrading capability. Forward markets expect mid-distillate margins to increase post-IMO and high sulfur fuel oil and sour crude discounts to widen.
Chevron's refining network produces over 40% mid-distillates and about 5% fuel oil. And as a complex refiner, we run a high proportion of heavy sour crudes. We believe we're well positioned to benefit from IMO impacts.
We like the petrochemicals business and have highly competitive 50-50 joint ventures in ChevronPhillips Chemical Company and GS Caltex. Slide 15 shows our major chemical projects in various stages of development.
CPChem successfully started up its Gulf Coast project after a remarkable recovery from Hurricane Harvey. The ethylene plant reached full production rates two weeks after a March start up and exceeded nameplate capacity soon after. CPChem is focused on additional de-bottlenecking opportunities.
Following its success with this project, CPChem is in the evaluation stage of a second one in the U.S. Gulf Coast. We like the Gulf Coast because of its feedstock advantages and expect competitive ethane supply for a long time. We are focused on developing the most capital and cost efficient project, one that is on the left side of the supply stack.
GSC is in front end engineering and design for a mixed feed olefins cracker, about two-thirds naphtha and the rest refinery LPGs and off-gases. We plan to make a final investment decision next year. Estimated costs are not final, but we expect our share of the capital to be a little more than $1 billion.
The fundamentals of chemicals are strong, but costs always matter. We'll continue to be disciplined in how we invest in our next set of chemical projects.
In our fuels businesses, retail is an important part of a tightly integrated value chain that starts with our complex refineries. Two recent retail highlights are shown on Slide 16.
In Mexico, we have about 100 Chevron-branded marketer-owned sites. Customer response has been very positive. Stations rebranded during the first half of 2018 averaged 30% higher sales through September.
We've also signed access agreements for two new terminals under development. After the terminals are complete, we will have built, in a capital-light way, an additional market to integrate with our West Coast value chain.
We continue to grow our convenience store offering with now over 800 stores. As the only major with a leading C-store franchise in the U.S., we have an advantage in retaining and growing our relationships with retailers. Same-store sales at ExtraMile C-stores have grown 7.4% year-to-date, more than double the industry average.
In the digital space, we made announcements on new mobile pay partnerships in the U.S. and went live with a pay app in Southeast Asia. These are important efforts to speed up and simplify the fuels retailing experience.
In our Oronite additives business, we celebrated the groundbreaking for our blending and shipping project in China. This facility will help us serve the growing Chinese market when it's operational in 2021.
Finally, in our lubricants business we are co-developing a renewable biodegradable base oil with ultra low viscosity and ultra low volatility, important properties for OEMs as they develop engines to meet increasingly stringent fuel efficiency and environmental regulations. It's early days, but we're excited by the potential of this new product.
As shown earlier, Chevron's downstream and chemicals has a track record of consistent financial performance. That said, in any one quarter refinery planned turnarounds impact our results. Through our recent investor engagements, we've heard your requests for improved guidance in this area.
Slide 17 shows the average after-tax quarterly earnings impact of planned turnaround activity for the last five years for our refineries in the U.S. and Asia. The impact is defined as shutdown expenses, plus the forgone margin from volumes not produced. Planned turnarounds are seasonal, but have a fair amount of variability in any given quarter. As a result, we believe that the best way to provide forward-looking guidance is by characterizing turnaround activity as high if the earnings impact is expected to be greater than $200 million; low if it's expected to be below $100 million; and medium in between. During 2018 the first two quarters had high turnaround activity and the third quarter was low.
Now I'll turn it over to Pat to close out with fourth quarter guidance and year-to-date results.
Okay. So now looking at Slide 18 just a couple of comments about expectations for the remainder of the year we expect positive production trends to continue in the fourth quarter fueled by sustained Permian growth and fewer planned upstream turnarounds.
Downstream in contrast has a high turnaround activity planned and this is expected to weigh on this segment's fourth quarter earnings and cash flow. For C&E, you'll recall that we don't budget for unanticipated inorganic spend. Through the first nine months, we have spent approximately $150 million on inorganic C&E and we expect to spend a total of $600 million for the full-year, primarily as the result of six blocks won in the Brazil licensing round. Organic C&E is running modestly above our plan and we expect it to be approximately 5% higher than our full-year budget of $18.3 billion.
Cash flow from operations is expected to be strong in the fourth quarter. Oil prices of course will be the primary determinant of this outcome and we can't predict those. While we do anticipate fewer affiliate dividends in the fourth quarter, we'll continue to benefit from further production growth, modest asset sale proceeds and some expected additional release of working capital.
Lastly, let's revisit our year-to-date results and how they compare against commitments that we laid out earlier in the year. Cash flow from operations is expanding as anticipated given our strong production growth, favorable market conditions and asset reliability. Excluding the impact of asset sales, production growth is currently at 6% relative to full-year 2017 and we expect to end the year closer to a 7% year-on-year increase. Our Permian assets are performing well ahead of guidance.
We continue to rationalize and optimize our portfolio, with proceeds of $1.9 billion captured year-to-date. We're demonstrating our commitment to capital discipline and are returning cash to our shareholders.
Total shareholder distributions have amounted to $7.2 billion year-to-date, $6.4 billion in dividends and $750 million in share repurchases.
We've had a very solid operating and financial performance so far in 2018 and we expect that performance to continue. We're seeing significant growth in cash generation due to the above plan production growth, continuing capital and operating expense discipline and favorable market conditions. As a result, we've been able to grow shareholder distributions and strengthen our balance sheet.
We believe that Chevron offers a very attractive offering for investors with oil price levered momentum in the up cycle and low cost portfolio resilience in the down cycle.
So that concludes our prepared remarks and we're now ready to take your questions. Please keep in mind that we do have a full queue and so please try to limit yourself to one question and one follow-up if necessary. We'll certainly do our best to get all your questions answered. Jonathan, please go ahead and open the line.
Certainly. Thank you. Our first question comes from the line of Jason Gammel from Jefferies. Your question please.
Thank you very much. I guess first turn to the Permian. Obviously very strong operational performance there in 3Q. And while I certainly wouldn't prorate the growth that you saw there moving forward, I was hoping you might be able to address some of the factors that led to such strong production growth.
Okay, Jason, thanks. I think, first of all we have been ramping up to the 20 rigs throughout the last couple of years and we achieved that 20 rig potential or realization here in the third quarter so that was the primary determinant. We are operating off of a new basis of design and we're finding that that has been incredibly successful. We're pursuing high density fracs and we're finding that that has been successful as well. So there's a number of factors that have led to the overall improvement that we have seen and I would say too, our NOJV partners, because prices have been stronger, perhaps than they were thinking at the beginning of the year, the NOJV activity has risen as well.
That's great. And maybe to take advantage of Pierre being on the call. Pierre, we've had the discussion before about your downstream business being very high return and very high margin but relatively small compared to your competitors. I believe you've been quoted as saying that you may be interested in expanding your refining presence on the U.S. Gulf Coast. Can you, if that's correct, maybe talk about some of the strategic drivers for wanting to expand there?
Thanks, Jason. Look, I won't comment on media reports or speculation but what I can say is I have for almost as long as I've been on the job now, over two years, talked about the strategic rationale of a Gulf Coast refinery, for three primary reasons. One, we're the only major company that operates one refinery in the Gulf Coast. Second is, we have a strong retail presence in Texas that we supply with third party barrels. And third is the possible integration and synergies with our advantaged position that Pat just talked about in the Permian.
At the same time, I've also said we don't need to do anything. Pascagoula is a top quartile refinery. We have a tight value chain built around it. And I've also said we're value-oriented. Any acquisition has to be at the right price. Any investment that we do has to earn attractive returns. And so, I think that's all I can really say at this time.
Thanks, Jason.
Okay. Appreciate the comments.
Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question please.
Hey congrats, guys on a good quarter. Pat and Pierre, I want to get your thoughts on divestitures. You laid out a $5 billion to $10 billion target. You're about $2 billion of the way there, just how do you feel about the ability to achieve that? Where do you think you guys are going to fall in the range and just any updates on deal – on processes that might be outstanding.
Yes, I would say, overall, Neil, we feel positive about coming in within the range that we've indicated, the $5 billion to $10 billion over the three-year period of time. We're at $2 billion a little bit and change so far. There is a little bit more that will come in we believe in the fourth quarter. And then we have certain, I guess, I would say marketing activities that are underway already that should, we believe, realize results in 2019.
So we feel comfortable about the $5 billion to $10 billion range. The assets – we're finding for those that are being marketed for example in the U.K. we're having reasonable interest. Actually, I'd say probably significant interest being shown by multiple potential buyers. So I think we feel very good about that range that we've given.
That's great. And then when we talk to investors about – who are a little bit more skeptical of the bullish view on Chevron, they point to two things. I want you guys to address it head-on. And one is the concern that post-2020, capital spending might need to materially increase because you're in a period of harvest right now, but you might not have the projects to reload growth post-2020. The second source of concern is around production sharing contracts in Asia and the risk of them rolling off, particularly in Thailand, less so of a concern around Indonesia but anything you can say on both of those topics to help comfort the market would be helpful.
Okay. Well, let me just speak here to the issue around growth once we get into the early part of the next decade and investment opportunities therein. We obviously have a wonderful position in the Permian and with other unconventionals. And as you know, these are low capital intensity, short cycle high-return opportunities for continued volumetric growth. So that's number one.
We've got TCO coming online with production in 2022. We have opportunities for de-bottlenecking on our LNG plants in Australia. We're just getting them to a fully run rate, high-reliability position now and we think the opportunity for reasonable de-bottlenecking is evident over the next several years.
We have growth potential in deepwater. We have three potential areas in Gulf of Mexico; Ballymore, Whale and Anchor. And I think that's where people are thinking there will be substantial capital. And the reality is our objective is to pace those out over a several year period of time. And there's nothing in terms of the intensity on future investment there that would ever come close to the intensity that we've had in prior years which is where I think people's – they're thinking the history is going to color our future and that's really not the case.
So I think we have growth potential, but it's going to be at a much lower capital rate. There may be some need to increase capital coming in say, 2021, 2022, that kind of range. But it will be small relative to where people might be thinking. Now I've taken so long on that; what was the other question that you had? Oh, the concession extension?
Yeah. Concession. Yeah.
Yes. Okay. So I think it's – I'm really glad you asked the question because there's been a lot written on this and it's a good opportunity to try to work through the specifics. So if you look at our particular situation – and by the way, we put concession extension information, our expiration information in our stat supplement. So I really encourage people to look at those documents and get a good understanding of what is coming due when.
But if you look out over the next three to four years, we've got about six contracts that will expire. We have one that is in a non-producing area, this is the Nsoko contract in Congo which expires in 2018 here. In Indonesia, we have the East Kalimantan PSC that expired just about 10 days ago or so. And the Makassar Strait PSC is going to expire in 2020. And we have a small NOJV PSC in China which is going to expire in 2022.
So there are a couple of others that have more substance to us. All of those are relatively immaterial and not substantive. There are a couple that do have impacts for us and one would be the Rokan PSC in Indonesia and this has gotten a lot of press lately. We did bid on this, but we were not the successful bidder. The government of Indonesia elected to return this asset to Pertamina and this will expire in 2021. We're disappointed in that but we did put in a bid that we felt offered value to the government of Indonesia, as well as to the Chevron shareholder. Our net production in Indonesia today is about 100,000 barrels a day. But the earnings and cash contribution out of that is much smaller than that would indicate as a percentage of the upstream portfolio.
And then the other contract of note, concession area is the Erawan PSC in Thailand and this expires in 2022. I can't say a great deal about this at this particular moment, but we have put in a bid that is under evaluation. We are taking the same approach that we did in Indonesia, which is to put in a bid that we feel offers value for Indonesia but also offers value for the Chevron shareholder.
Thanks, guys. Appreciate the time.
Thanks, Neil.
Thank you. Our next question comes from the line of Phil Gresh from JPMorgan. Your question, please.
Thanks, good morning. First question, I guess...
Good morning.
...would just be a follow-up on the Permian, given your success that you're seeing there and that you hit your rig count targets for the end of the year. How are you thinking about the go-forward plans here? You talked previously about leveling off with the rig count at this point. But given the success you're seeing, does this make you want to kind of lean forward and add rigs in the Permian? Or how are you thinking about that today?
So I think we feel good about having gotten to the 20 rigs. And our approach right now would be to take a bit of a pause and to really focus on capturing all the efficiencies that we can that a 20 rig fleet would necessitate basically. And that's from the land position to the drillings to the completions, all the way through to the market realization.
So our approach right now is to take a pause, gain all that efficiency. We're really focused on the returns that we're getting from the investment that we're making. And we want to make sure that we're as capital efficient and as operating efficient as we can possibly be. And then we can always reappraise and look at our options and decide what we would like to do going forward.
I will say that it's not so much about the actual rig – number of rigs that you have drilling, but it's the activity that's being generated and the results that you're getting and the cost per BOE that you're getting. And so I think over time we're going to try to move what we consider to be a critical performance metric away from just the rigs to something that would be more indicative of an efficiency measure.
Yeah. Got it. That makes sense. Second question is just on the balance sheet metrics, 19% gross debt to cap, but 15% net debt to cap, so you're trending quite well on the balance sheet.
How do you think about the desire to – given where we're at in the cycle, to continue to lower that metric versus other opportunities? You obviously started with the buyback last quarter of $3 billion. Is there any desire to potentially at some stage in the future increase that amount? Or given – do you have a more kind of conservative macro view, and you'd rather stick with where you're at?
Yeah, I think – so it's a wonderful question and it's a great position to be in, Phil. We have only three months into the share repurchase program. We obviously feel very comfortable and good about the cash generation that is occurring in the company. And we also know that we've got a confirmed $18 billion to $20 billion capital program.
So if we are in a position where we continue to see high cash generation, the market continues to give – to be at prices at current levels or approximately current levels, and we know our confirmed spending, then there's going to be surplus cash that is being generated.
And if those circumstances all materialize, then we would obviously give consideration to the size of the share repurchase program. We will want the same kind of parameters that I outlined back in the last quarter to be evident. In other words, we want to make sure that whatever we do, we can have it be sustainable and that it's a reliable component available to our shareholders.
I will say in that regard, the improvement to the balance sheet supports that sustainability. Because to the extent that we have a stronger balance sheet, then when we get into a downturn on price, and we believe that at some point in time that will come. When we get into that position, then we've got a balance sheet that can help support distributions to shareholders through the thin part of the cycle.
Sure. Okay, thanks a lot.
Thanks, Phil.
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. So, Pat, I'm afraid I'm probably the guy responsible for all these PSC questions, so I apologize. But I do want to follow up on the question from earlier if I may.
Thailand is a legacy tax concession. And it's been re-bid as a PSC. The government has been quite transparent about the minimum terms. So I just wonder if you could address one issue. If you look at third-party analysis on this, meaning tax – very old tax framework information, this thing could be as much as $2 billion of your cash flow this year. Is that anywhere close to being right? And if so, under the new terms, how would you expect the delta on cash flow to look, even though that you might retain the contract from a production standpoint?
Yes, Doug, you're putting me in an uncomfortable position. I really can't comment while commercial discussions are underway and bids have been put forth and are being evaluated.
I think we're going to have to wait and see what the outcome is from the discussions and the – whatever gets awarded. I think by the end of this year is sort of the planned date for understanding what the outcome will be. We'll have to give you an indication then of what the results will be.
I can confirm that the bidding package does contain tougher fiscal terms. So I think you can build that into your expectations. But exactly what the degree will be, I'm not at liberty to say at this point.
I certainly did not mean to put you in an awkward spot, but thanks for trying to answer it. My follow-up is hopefully a bit more constructive and it's on the Permian.
So you're saying – in your prepared remarks you said you're running about a year ahead of schedule. So with the change in design and obviously the improvement we expect next year, at least in Permian spreads, differentials and so on, would you expect to basically maintain the same plateau target? Or given that you're running so far ahead, would you expect to see further upside risks to your production outlook?
In other words, will you do more with less? Or maintain the same – or continue the same growth trajectory and take what it gives you with the same level of activity if you know what I mean?
Yes, I mean, I think we're really constructive on the Permian. And just some things to keep in mind, right. We've been ramping up to the 20 rig rate. We're now going to have 20 rigs for the full calendar year, once you go into 2019. So that will be a positive.
We're seeing continued benefits coming from our new basis of design and continuing improvements in efficiencies as we move along. So we think that there's upside potential here as we continue to fine-tune our well placement; fine-tune really the entire I guess I would say value chain associated with the Permian. So, I think we're constructive on the Permian. And we'll certainly give you an update at our March in 2019 SAM, which we've done for several years now running. But I think it's a positive outlook that we feel for that asset.
Thanks, Doug.
Thanks for taking my questions, Pat. Appreciate it.
Thank you. Our next question comes from the line of Paul Sankey from Mizuho. Your question please.
Hi. Good morning, everyone. Pierre – hi, Pat. Pierre, since you're especially on the line, I thought we'd go back to your IMO comments. There's been some recent press that the potential is for the market impact to be too severe for perhaps the administration to handle. I would imagine that would have to be on the gasoline price. Can you talk a little bit more – U.S. gasoline price for that matter, can you talk a little bit more about how you think the effect of IMO will play out? And to be specific, do you think there will be a major impact on U.S. gasoline prices as opposed to distillate?
And one other thing I would ask is that, as regards fuel oil where do you expect the unused residual to end up and how will that clear the market given the transport difficulties there? Thanks.
Okay. Thanks, Paul. Well, let's see. There are a lot of unknowns and uncertainties around how IMO is going to roll through the system. I think part of the challenge is that IMO is not in a vacuum, right. You can't hold everything else constant and think of IMO because it will be happening in 2020 when there will be other supply and demand factors happening. What's the economy doing at that point in time? What are sour crudes global production happening?
So there are a lot of moving parts that are going on. But what you can step back and say and one of my comments sort of alluded to, if you look at the forward markets right now is you would see mid-distillates, diesel, gen diesel, crack spreads increasing post-2020. And you'll see HSFO or high-sulfur fuel oil and sour crudes discounts widening. And that makes sense, right?
As you point out, there is a lot of fuel that goes to the bunker market. The expectation is that there's not enough scrubbers that have been put in place to consume all the high-sulfur fuel oil. So they are going to look to alternatives and those alternatives will be marine gas oil that will look like distillate. And/or it could be a low-sulfur fuel oil and there's a lot that's going on in that space.
So in terms of MO gas, it's a difficult thing to predict, because there's so many factors. I think one thing I would say is that the underlying – we've seen crude move plus or minus $10 in a few weeks the last couple months. Those movements are much bigger movements on gasoline pricing or any product pricing. We're really talking just about differentials.
And MO gas can really – you can see it going either way. It could get pulled up if some of the intermediates that are used for MO gas go to make distillates. You could also make arguments that it could weaken a little bit if runs are higher and there's excess MO gas.
So it's really something that I can't predict. What we're focused on is being prepared for it, minimizing high-sulfur fuel oil production in our refineries by making small-scale modifications. We are seeing scrubber uptake increase for ship owners. We are looking to sell what we do produce to them. We're looking at alternative markets that are non-marine, like power generation, asphalt, folks, who have excess upgrading capability. And we're confident that we're prepared for IMO.
We're also working on testing low-sulfur fuel oils, so different marine fuels, lubricants and additives and we're a leader in marine lubricants and additives. They are going to be a big part of the solution, so we're testing and developing new products for that. So there's a lot of work underway. We got a little more than a year to go and we'll be ready for it.
Pierre, I feel like I'm not the first guy to have asked that question. Can you just give us any sense for the power generation market and your expectation of scrubbing penetration? Thanks.
Well, again on scrubbing penetration, our view if you step back, the most economic way to comply with the IMO regulations is for ship owners to put in scrubbers, right. That's a much more cost-effective mechanism than investing capital. And we're not – or for refineries to invest capital. We're not looking to make any investments that – large-scale investments that are IMO-related. It's because we view it as transient. One thing about our markets is they work. And when arbs open up, they get closed. There's lots of players. There's lots of capital. And there are lots of people who are working to reduce arbs. So our view is that – sorry, I lost the track on that a bit.
Power.
Oh, on power generation, I'm sorry. Yes, on power generation there's a pretty good-sized market in the Middle East and other places. Again, it's not the – it's a lower-value market clearly. But our view is it's likely to require some power generation market to go through the transition. But again, over time, we expect scrubber uptake to increase and that will be the primary mechanism of complying with IMO.
Pierre, thanks. I'll let someone else have a go. Thank you.
Thanks, Paul.
Thanks, Paul.
Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question please.
Hey guys, good morning.
Good morning, Paul.
Pierre, since you are here, so two questions for you; one really short. Your refining system, can you tell us what percentage you run as heavy oil, those we define as over – below 25 API? And how much is the medium sour you run, those we define between 25 to 30, 31 API?
And the second question is that given your position that when you're looking to support your upstream, will you be involved or that think you need to be involved in terms of helping to ensure we have sufficient Gulf Coast oil export capacity because you may have some concern by late 2019 or early 2020 where you may have a gap. Or that you think that it's so transitionary that it's not really a concern and you guys don't need to be as an equity owner in those?
And also then if you can comment on Duvernay, that it seems like we also have infrastructure issue. And that will – given your position and you're doing some pilot project and all that, is that something that you guys will involve? Or need to be involved I guess the question is.
Okay. Let me see. Let me take the first one at least. We do not disclose specific sour content or API gravity. What we do disclose in our Annual Report Supplement is the region or country of origin of the crudes. And I think folks can figure it out from there. Again, I showed a chart that showed that we're the – have the highest Nelson Complexity, the highest amount of upgrading capacity. I mean, we are designed to run lower-value feedstocks and we've invested to make that happen but we don't disclose specifics on that.
On your second question, on how we think about the upstream in the Permian, I guess, I would say the downstream is – has to stand on its own. Any investment we do has to stand on its own. We're competing as a segment. We're – I showed charts that showed how we are in earnings per barrel versus our major competitors. And so we have to look at that way. Now we're part of an enterprise; and if we can have synergies with the upstream, of course, that's an added benefit. But investments in the downstream can't ride on the back of, in particular, very attractive economics in the Permian. Again, we have to have investments that stand on their own merit that compete against our competitors. Any extra benefit from synergies is upside on that.
On the third question, I think it was around takeaway and I'll leave that with Pat.
Yeah. I mean, I was just going to add, I think you had a question about export capacity. And I think our corporate view would be yes, there may be a little bit of a need to build out export capacity over the next two or three years. But kind of going back to the belief that markets see this opportunity and that that capacity will be in fact built out, we don't see it as a risk to flow assurance.
We have ourselves dedicated export capacity of about 25,000 barrels a day now. We see that expanding in the early part of next year to about 80,000 barrels a day. So far we've exported about 8 million barrels, I believe is the number. So we feel that we're investing appropriately for our flow. But we don't think in general over time that there will be a risk to flow assurance in the Permian because of export capacity.
Pat, is that the same apply to in the Duvernay area in Canada, that you don't believe that you need to involve on the build-out of the infrastructure there?
In Canada?
Your question is in reference to the oil sands, Paul?
No, to the Duvernay?
Oh, Duvernay.
Duvernay? Yeah, I guess I don't have any particular insights associated with Duvernay.
Yeah, I think I would just chime in. Pat, I think we have previously disclosed that we...
(00:49:07).
...a while ago we committed to the Pembina infrastructure agreement that is well-paired to enable our production out of the Duvernay. And you'd expect that as we continue to progress that development there that we would be able to step into additional capacity agreements to enable that flow.
Okay. Thank you.
Thank you. Our next question comes from the line of Blake Fernandez from Simmons & Company. Your question please.
Hi, folks. Good morning. Pat, a question for you on CapEx, it looks like you're trending about 5% above. Could you talk a little bit about what the drivers are there, whether it's activity or inflationary based? And should we be thinking about that kind of giving upward momentum into the next couple of years as well? So maybe like toward the upper end of your range?
Right. So, good question, Blake. Yeah, we're about $600 million on a year-to-date basis. We're about $600 million above plan if plan were ratable there. And about $150 million of this or so relates to inorganic, lease acquisitions, bonus lease payments that we have made. And as I said in my prepared remarks we expect that number to go to about $600 million by the time we get to the full year.
But back to the nine months, that means we're about $450 million over on an organic basis, and there's really several reasons for this. It's not concentrated in any one particular area. The first thing I would call out is, just the fact that oil prices have been noticeably higher in 2018 than the planning premise that we use when we put the budget together. So there has been some cost savings. There were cost savings that we had built into our plan that we thought we would be able to capture from a capital standpoint. And we really haven't been able to capture those. Because the cost trends stopped going down; and in fact they leveled out, and in fact have turned the other direction along with oil price.
So there's a piece of the overrun that relates to that. There is a piece that relates to major capital projects. Jay mentioned TCO on the last call, but there's other projects as well that I could throw in there with small overruns. And then, there's also more that's being spent in the Permian and again, we've talked about the drilling efficiencies, a new basis of design, the fact that we're able to prosecute the development plan against more acreage than we had originally envisioned.
And with the high density fracs, they cost more, but in fact, the economic outcomes are really outstanding. And so the dollar per barrel per EUR is much better. So that's money – that's good money being spent. So those are the reasons that I would outline for the overrun that we have so far.
In terms of pressures, inflationary pressures, I will say, we are continuing to see inflationary pressures, for example, in the Permian. And we do expect increases there, maybe in the order of 5% to 10% in the 2019 period.
In general, because oil prices have been sustained higher, I think that the cost structure in the industry has moved up some. So I would say, yes, we are facing that and that would be something that would be reasonable to build into your expectations.
That is helpful. Thank you very much. The second question, I hope you didn't necessarily kind of cover this in exact detail on Paul's question, but mine was on the Permian takeaway.
I think in last quarter's call you had kind of highlighted excess capacity through June and then ample takeaway for non-operated production through 2019. I'm just curious with the massive ramp-up that we're seeing here, are you still pretty well taken care of from a takeaway capacity through that same timeframe and say throughout next year?
Yes, we are. Absolutely. I mean the whole process that we have, whether it be for crude or NGL transportation or fractionation, the whole setup that we've got is trying to stay ahead of what we expect the Permian growth to be.
And so we do this through securing from – in increment, contractual offtake. So we feel very nicely covered for our position out of the Midland on those elements for the next couple of years. And of course, the team that we have working this will be working for the three year period and the four year period. I mean, it's a perpetual step-up that we are trying to orchestrate here.
That's great. Thank you.
Thanks, Blake.
Thank you. Our next question comes from the line of Alastair Syme from Citi. Your question please.
Hi. Pat, can I just ask what makes Tigris different to Ballymore, Whale, and Anchor?
I think it really comes down to the – it fundamentally comes down to the economics that we anticipate out of those individual developments. So you're influenced by the size of the resource, the demands as to whether that needs to be an independent topsides or whether it's got tieback opportunity, the complexity of the reservoir. I mean, there's a whole number of factors that go into account. And Tigris had its own complexity, because it was a three-field aggregated development.
So you shouldn't read in to the fact that we decided to exit the Tigris leases, you shouldn't read in anything there about our dedication to the deepwater. We are still dedicated to the deepwater. We think we have expertise in the deepwater. We picked up a significant number of leases in the Gulf of Mexico deepwater as well as offshore Mexico and Brazil as well. So we're still invested in the deepwater.
And we're just looking for the highest return projects. It's all about making choices and going after what we believe will be the best opportunity to secure high returns in our portfolio.
Thank you. Can I – as a follow-up, can I just return to the discussion around PSCs and just clarify for the sake of the guidance that you put in the SAM around cash returns out to 2020. What sort of assumptions are made around contract renewal?
Right. I mean, on the two important ones that I talked about for both Rokan and Erawan, both of the assumptions in the materials that we provided back in March were that those concessions were extended.
In terms of the concession extension dates though, I think that's important. Both of those are 2021, 2022. So for the next several years we still have those available to us.
Thanks for the clarification.
Okay. And I'd just say, and we can still, because we've seen such strong growth in the unconventional, even without those concession extensions, our – we can still see growth in our base plus shale and tight.
Great. Thank you very much.
Thank you. Our next question comes from the line of Roger Read from Wells Fargo. Your question, please.
Yeah, thanks. Good morning. I guess could we follow up a little bit your comments on the cost inflation on the CapEx side, specifically any update on TCO relative to where we were? And then, how these cost inflation issues or CapEx overruns affect the overall spending budget or run the risk of? And then as you're starting to think about where projects are going to bid out for 2019, is that already being incorporated in expectations?
Yeah, Roger, thanks for the question. First, let me let me just reiterate, staying within the $18 billion to $20 billion range is our focus here. And that comes with any sort of adjustment that needs to be made, whether it's on the major capital project side or it's on the inflationary side. We're making choices. And our choice is to stay within that $18 billion to $20 billion range. And we think it's very doable, because we've got lined out activity over the next couple of years.
To TCO in particular, let me just make a few comments about that, because I did happen to visit the plant about 10 days or so ago with both Wayne and Jay Johnson. And so I do have a firsthand view of what's going on there.
And just making a couple of personal observations here, got to start with the fact though, that we're only 2.5 years in and we still got 3.5 years to go. First oil is still scheduled for 2022. So we're only about 50% of the way through on all this.
And I would say from my observation, a number of things are going quite well in the project. It's a big complex project. It's been broken down into individual, five individual work streams and those individual work streams have gotten lined out, kind of what I'll call productivity packages, work packages, where daily/weekly/monthly they've got identified activity that's being done and they're tracking their progress daily. And so we are seeing site productivity improve tremendously.
I think Jay mentioned on the second quarter call, that 2019 – the rest of 2018 and 2019 are the really critical execution years. We're moving away from being out of the civils and undergrounds into the MEI phase. And so, 2019 will be an absolutely critical year from an execution standpoint.
So I'm really – I was really impressed with the productivity gains that we're seeing. And of course, we still have a lot of work ahead of us. I don't want to get too far out over my skis or overstate anything here, but things are working well. The logistics are working well, the modules are being delivered. It's being lined out and proceeding quite nicely.
That's fair. I think given the performance of the quarter we won't try to put you on the rack or stretch you right here.
(00:59:31). I appreciate that.
The follow-up question, as we think about the outperformance in the Permian this quarter, and I mean, it's been building for a while, just really spiked up here. Between the operated and the non-operated and thinking about your comments on the high density fracs and so forth, is – should we think about the outperformance being overwhelmingly within Chevron operated rigs, or spread out? In other words, you're – what you're learning in your own wells is being applied even to the non-op. I'm just – as we think about a change in rig percentages operated versus non-operated, whether or not that would affect growth going forward?
Yeah. So I would say in the quarter, the contribution in terms of absolute production between operated and non-operated was about the same. We had been building up activity, rig activity, as well as the non-ops had too. But of course, the non-ops had kind of rig activity that had started – production activity that started several years previously. So I feel, as though the contributions in the quarter are relatively comparable between non-op and co-op. Both areas are seeing improvement.
All right. Great. Thank you.
Thanks, Roger.
Thank you. Our final question for today comes from the line of Sam Margolin from Wolfe Research. Your question, please.
Good morning. I'm sorry, it's late stage in the call. I sort of have a thematic question, but I'll try to keep it concise. You made a reference to fiscal terms kind of tightening or escalating in Thailand. That might be happening in other places too and at the same time, even with cost inflation in the Permian accounted for, sort of effectively the opposite is happening, where you're getting more efficient and economics are improving.
So I guess, my question is just broadly, how do you manage that? In the past you've kind of set a level of where you think unconventional production could be within your portfolio, but if the economics on a relative basis are getting so much better than they are everywhere else, what's the process of kind of managing your mix here to make sure that you're optimized when things on the screen seem to incent you to go wildly in one direction?
Yeah, yeah. Sam, I would just say, we have a fundamental belief in the value of diversification and having a diversified portfolio. And we have several legacy assets whether you think of Australia or unconventional in the Permian, TCO, deepwater. We have several significant asset classes that we want to continue to pursue.
And you're right, in some locations around the world, you see a tightening of fiscal terms, but in other locations around the world you see the fact that the host governments are realizing that in order to incent foreign investment they need to revise the fiscal terms in a more kind of favorable to the investor, like a Chevron would be situation.
So it ebbs and flows and we're in the business for the long term. And so we just – we continue to assess our portfolio and try to make the best decisions we can make not only for a short term, but also for long term; production growth, reserve replacement, cash flow growth, dividend growth, et cetera. So it's a – we look at it as a portfolio.
All right. Thanks so much for all the color on a long call.
Okay, thank you.
Thank you.
Okay, I guess that was our last call. So I want to thank everybody for your time today. We certainly appreciate your interest in Chevron and we appreciate everyone's participation on the call. Have a good day. Jonathan, back to you.
Thank you. Ladies and gentlemen, this concludes Chevron's third quarter 2018 earnings conference call. You may now disconnect.