Good morning. My name is Jonathan, I will be your conference facilitator today. Welcome to Chevron's first 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, instructions will be given at that time. If anyone should require assistance during the conference call, please press star then zero on your touchtone telephone. As a reminder, this conference call is being recorded. I will now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.
All right. Thank you, Jonathan. Welcome to Chevron's first quarter earnings conference call and webcast. On the call with me today is Mark Nelson, Vice President, Midstream Strategy and Policy. Also joining us on the call are Frank Mount and Wayne Borduin, who are currently transitioning in the role of General Manager of Investor Relations. We will 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. We ask that you review the cautionary statement here on slide two. Turning to slide three, an overview of our financial performance. The company's first quarter earnings were $3.6 billion, or $1.90 per diluted share. Earnings excluding foreign exchange and special items were also $3.6 billion.
A reconciliation of special items and foreign exchange and other non-GAAP measures can be found in an appendix to this presentation. This is our strongest earnings result since the third quarter of 2014, when Brent prices were above $100. For the current quarter, Brent prices averaged $67 per barrel. Cash flow from operations for the quarter was $5 billion. Excluding working capital effects, cash flow from operations was $7.1 billion. At quarter end, debt balances stood at approximately $40 billion, which resulted in a headline debt ratio of 20.9% and a net debt ratio of 18.1%. During the first quarter, we paid $2.1 billion in dividends. We currently yield 3.6%. Turning to slide four. We are on track to deliver on our 2018 cash generation guidance from our recent analyst meeting. Cash flow from operations, excluding working capital effects, grew to $7.1 billion.
Positive impacts from strong realizations and high-margin volume growth were partially offset by equity affiliate dividends that were about $1 billion lower than equity affiliate earnings. Cash capital expenditures for the quarter were $3 billion, approximately $300 million or 10% below first quarter 2017, as we continue to complete our major capital projects under construction and drive improved capital efficiency across our portfolio. The result, free cash flow, excluding working capital effects, was $4.2 billion, approximately $2.5 billion higher than the average quarter in 2017. Asset sale proceeds within the quarter were minimal. However, with the closing in April of the Elk Hills transaction and the anticipated closing of the sale of our Southern Africa downstream business later this year, we remain on track for asset sale proceeds of $1 billion to $3 billion in 2018. Turning to slide five.
As many of you are aware, working capital effects impact our business unevenly throughout the year. These impacts are, to a large degree, transitory. Because of this uneven pattern by quarter, many of you exclude working capital impacts from your models. However, while uneven by quarter, our pattern is fairly consistent year to year. The chart drawn from this decade's average working capital impacts demonstrates the pattern. Normally, working capital is a cash penalty in the first and second quarters, followed by a cash benefit in the third and fourth quarters. The variation has, at times, been two to three times the quarterly averages shown. This rhythm is fairly consistent and mainly results from seasonal inventory builds and draws, as well as the timing of supplier, JV partner, and tax payments. We anticipate this year's pattern to be no different.
If price levels generally hold where they are today, we expect a majority of the $2.1 billion of working capital consumed during the first quarter to be released throughout the remainder of the year. The residual is expected to be mostly receivables related to both higher prices and higher production compared to 2017. Turning to slide six. First quarter 2018 results were approximately $950 million higher than first quarter 2017. Special items, primarily the absence of a first quarter 2017 gain from the sale of our Indonesian geothermal assets, coupled with a first quarter 2018 U.S. upstream asset impairment, decreased earnings by $720 million between periods. A swing in foreign exchange impacts increased earnings between the periods by $370 million. Upstream earnings, excluding special items and foreign exchange, increased around $2.2 billion between the periods, mainly on improved realizations and higher lifting.
Downstream earnings, excluding special items and foreign exchange, decreased by about $255 million, mostly due to an unfavorable swing in timing effects and lower volumes, largely from the sale of our Canadian assets. The variance in the other segment was primarily the result of the absence of prior year's favorable corporate tax items. As we indicated previously, our guidance for the other segment is $2.4 billion in annual net charges, so quarterly results are likely to be non-ratable. Turning now to slide seven, a beautiful chart, if I do say so myself. This compares results for the first quarter of 2018 with fourth quarter of 2017. First quarter results were approximately $530 million higher than the fourth quarter.
Special items, mainly from the absence of the fourth quarter 2017 U.S. tax reform gain, decreased earnings between periods by approximately $2 billion, while a swing in foreign exchange impact increased earnings by $225 million between the periods. Upstream results, excluding special items and foreign exchange, increased by around $1.4 billion between quarters, primarily reflecting higher realizations and liftings, along with lower depreciation and operating expenses. Downstream earnings, excluding special items and foreign exchange, improved by about $540 million, reflecting higher earnings from CP Chem, mainly due to the absence of fourth quarter 2017 hurricane impacts, along with improved refining and marketing margins. The variance in the other segment largely reflects lower corporate charges and a favorable swing in corporate tax items between quarters. Turning now to slide eight.
First quarter production was 2.852 million barrels a day, an increase of 4.5% over average 2017 production, and within our guidance range for 2018. This production level represents an all-time quarterly high for the company. Growth is expected to continue during 2018, with Wheatstone Train Two coming online, major capital projects such as Wheatstone, Hebron and Stampede ramping up, and continued growth in our shale and tight assets. During the quarter, the impact of asset sales on production was negligible. In the second quarter, we forecast a quarterly asset sale impact of around 15,000 barrels per day, mainly from our recent Elk Hills and Democratic Republic of the Congo transactions. We'll also start our planned turnaround activity in the second quarter. Our full year production guidance remains unchanged at 4%-7% growth over 2017, excluding the impact of asset sales.
On slide nine, first quarter 2018 production was an increase of 176,000 barrels a day, or 6.6% from first quarter 2017. Major capital projects increased production by 228,000 barrels a day as we started and ramped up multiple projects, including Gorgon and Wheatstone. Shale and tight production increased 101,000 barrels a day, mainly due to the growth in the Midland and Delaware basins in the Permian. Base declines, net of production from new wells, such as those in the Gulf of Mexico and Nigeria, were 39,000 barrels a day. The impact of 2017 asset sales, mainly in the U.S. Mid-Continent, Gulf of Mexico, and South Natuna Sea, reduced production by 61,000 barrels a day. Entitlement effects reduced production by 50,000 barrels a day as rising prices and lower spend reduced cost recovery barrels. Turning to slide 10. Gorgon and Wheatstone delivered strong and reliable performance in the first quarter.
First quarter net production was 202,000 barrels of oil equivalent per day from Gorgon and 67,000 barrels of oil equivalent per day from Wheatstone. We shipped 69 LNG and four condensate cargos and were able to take advantage of rising oil-linked prices as well as strong Asia LNG spot prices, which averaged over $10 per BOE for the quarter. We continue to fine tune the plants to enhance reliability and boost capacity. These efforts are yielding favorable results. Gorgon first quarter production is more than 5% higher than our previous best quarter, and Wheatstone Train One has been running well. We have a planned pit stop on Gorgon Train Two next month to replicate performance improvement modifications that we have made in the other two trains. Work on Wheatstone Train Two is progressing well and commissioning activities are ongoing.
The warm end is expected to be ready for startup shortly. We're expecting to begin LNG production this quarter. Domgas is expected to start up late in the third quarter. Turning to the Permian. Permian shale and tight production in the first quarter was up about 100,000 barrels a day, or 65% relative to the same quarter last year. Looking forward, we forecast Permian unconventional growth of 30%-40% annually through 2020. All of this is premised on running 20 company-operated and approximately nine net rigs on an NOJV properties by year-end. In March, we guided to 2%-3% annual growth from our base plus shale and tight business through 2022 at a $9 billion-$10 billion of annual capital spend. We are currently running 17 rigs and expect to stand up our 18th company-operated rig next month. We also continue creating value through land transactions.
We executed nine deals, swapping approximately 25,000 acres in the first quarter, and we have several others under negotiation. As you know, these laterals enable high value, longer laterals. We often get questions about our Permian takeaway capacity as well as other questions on the industry macro environment. Mark heads up our midstream and strategy groups and will provide some additional insights. Over to you, Mark.
Thanks, Pat. As Pat mentioned, we get questions these days about Permian-related differentials, the long-term oil market, and LNG supply and demand. Turning to slide 12, let's continue with the Permian story, where we believe optimizing the value chain from wellhead to customer differentiates Chevron from many in the business. As you know, our advantage starts with our land position and our factory model and continues with the market knowledge of each barrel's value at any point in time and ends with the ability to appropriately place those barrels. For example, recent crude differentials in the Midland Basin have widened, and we've secured flow and preserved margin by proactively procuring enough capacity to move product to multiple market centers, negotiating highly competitive transportation rates, batching and blending to meet market demands and avoid price discounts, and by accessing the best world markets for each barrel with our export capabilities.
Simply said, our goal is to maximize the return on every Permian molecule. Another question that is often asked is reflected on slide 13. That is what role does oil play in meeting the world's growing energy demand in the decades to come? In developing our point of view, as you would expect, we use detailed internal and external analysis to evaluate supply-demand scenarios and the associated opportunities and risks in our business. Our macro liquids view is similar to a number of independent assessments, and we're showing one of these assessments, the IEA New Policies Scenario in the upper right. We believe that oil demand will continue to grow for the foreseeable future, and the need for incremental supply continues to exist in any realistic scenario. Reinforcing this view, today's liquids demand continues to be on the higher end of most independent forecasts.
The chart in the bottom right illustrates another of our points of view. We believe in a longer, flatter supply curve. Despite the recent run-up in prices, we believe capital discipline, cost management, and market signpost will always matter. We are well positioned to win in any environment given our advantage portfolio. Turning to page 12 and the macro LNG view, this graph reflects the latest LNG demand projections from Wood Mackenzie with their supply forecast, highlighting that the LNG market is becoming oversupplied in the short term as new projects continue to ramp up in both the Pacific and Atlantic basins. North Asian LNG demand, however, especially in China, was stronger last winter than the market anticipated. In fact, 2017 Chinese gas demand was up 15% year-on-year, with LNG imports up 46%.
While this growth rate may moderate, the demand drivers appear mostly sustainable, with coal to gas switching in residential and industrial applications mandated by the Chinese government to reduce air pollution. The LNG market should rebalance with a supply gap expected to open before the middle of the next decade. This is where Gorgon and Wheatstone capacity creep and debottlenecking opportunities will fit very nicely. Only the most cost-competitive projects will be able to move forward in this space, we will be very disciplined with our investment and will fund only those projects that will generate top returns. With that, I'll turn it back over to you, Pat.
All right. Let me close this out here on slide 15. I'd like to reiterate some of our key messages from our recent security analyst meeting and to demonstrate how we're delivering on those commitments. First, our cash generation improvement trend continues and is in line with previous guidance. In the first quarter 2018 cash flow from operations, excluding working capital, was $7.1 billion, well in excess of our cash capital expenditures and quarterly dividend commitments. Second, we are executing a disciplined C&E program, allocating capital to the highest return projects that compete in our portfolio. Third, we grew production by 4.5% from full year 2017 to 2.85 million barrels a day, achieving an all-time quarterly high for the company and trending well within guidance. Fourth, we have an advantage portfolio in the Permian Basin that is delivering on all cylinders.
Year-on-year, we added 100,000 barrels per day of shale and tight production here, trending ahead of recent guidance. We are leveraging our midstream business to maximize the returns on every molecule. Lastly, but very importantly, we increased the dividend per share by 4%, delivering on our number one financial priority to shareholders. That concludes our prepared remarks, Mark and I are now ready to take your questions. Please keep in mind that we have a full queue and try to limit yourself to one question and one follow-up if necessary, we'll certainly do our best to try to get all of your questions answered. Jonathan, go ahead and open the lines, please.
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're 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 Jason Gabelman from Jefferies. Your question, please.
Thanks, good morning, everyone.
Morning, Jason.
Pat, really great quarter just in terms of demonstrating the cash generation potential that Chevron has moving forward. I guess we actually get to the high-quality question about what you would potentially do with discretionary cash flow in the capital program. It's obviously very disciplined. It's within a fairly tight range. Balance sheet's about where you want it to be. That kind of leads us to share buybacks and what would you potentially need to see to begin a repurchase program?
Yeah. Jason, thanks for the question, thanks for acknowledging the good quarter. I think at this particular point in time, our messaging around share repurchases really haven't changed from what we said just a few short six weeks or so ago. At that time, we said we wanted to see the cash flow actually materialize. We said we wanted to see prices sustained a little bit. We do fundamentally believe that it is our fourth priority. Dividend growth is number 1, feeding the business is number 2, the balance sheet, as you say, is number 3, then surplus cash, once we've satisfied all those other commitments, turns into a share repurchase program. It is part of the value proposition that we have offered shareholders in the past.
As you know, 10 out of the last 14 years, we have had share repurchases. We only stopped them during the financial crisis, then in the last three years when prices had their collapse. It's very much a part of our thinking these days. When we re-inaugurate it, if the circumstances permit that, we want to be able to do so in a sustainable fashion.
Appreciate those comments, Pat. Maybe just as my follow-up one for Mark. Mark, you mentioned that the debottlenecking at Gorgon and Wheatstone would be towards the low end of the cost curve in the LNG supply stack. Do you see anything else in the portfolio that would potentially be competitive? I guess I might even be referring specifically to expansion trains at either one of those projects.
Well, great question, Jason. I think from an Asia LNG perspective, the most exciting thing for us, of course, is the amount of demand that we're seeing in that part of the world. It's probably premature for us to be thinking about extra trains as we have considerable opportunity moving from both ramp-up to debottlenecking. Having spent much of my career around refineries, I wouldn't underestimate the opportunity there and the size of prize. We're focused on ramp-up, efficient operation, then building our way into leveraging the existing infrastructure in Australia. Thanks for the question.
Okay. It's like a systematic approach. Thanks.
Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question, please.
Hey, guys. Good morning.
Good morning, Paul.
I have two questions. I think both of them for Mark. Mark, how much is the oil production from Permian that you are selling inside Permian in the first quarter? What is your takeaway capacity for the next couple of years? Have you already locked in sufficient according to your current growth plan? Also, we have heard some people talking about gas handling in the basin may start to become an issue. Want to see what is your view on that. That's the first one. May as well ask the second one is on the LNG market. Want to see whether you guys have been actively marketing or trying to market additional gas, and what's the conversation with the customer this day, and what's the bid-ask differences, if there's any?
Thanks, Paul Cheng. I'll address your Permian takeaway capacity questions kind of at the high level, as you can imagine. We're very comfortable with our offtake positions today, and it goes all the way back to that advantaged portfolio, and maybe equally importantly, disciplined development. It allows us to keep up with our production, and we do that by partnering with our strong infrastructure companies, and we get highly competitive rates, and then they execute on infrastructure projects that quite frankly, might not compete in our portfolio. We view that as activating our value chain at the lowest possible capital investments, which is kind of a return-driven mentality. We will hit moments of tightness and length, we like our position moving forward.
How about the gas handling?
Yeah. From a gas perspective, all three streams, so oil, gas, and NGLs all must flow in the Permian. As you know, the oil tends to drive the economics, but we have flow assurance across all three streams today. Again, we're comfortable with our position looking forward.
Do you think the basin as a whole will have a problem if not Chevron?
Yeah. From a basin perspective, as we've all read the news, you can see some competitors who perhaps don't have either the same discipline or the same advantage portfolio experiencing problems. In the Permian in general, most of those would be temporal. We see that as a region that will solve those type of problems and only have kind of temporal challenges.
Okay. Great.
On your LNG marketing question, as you know, we've chosen to do business with some of the largest, most reliable customers in that part of the world, and we have long-term contracts. The natural discussions that go on about wanting reliability and the best sustainable price continues as we would have expected. We're seeing customers continuing to like the reliability that we've been able to deliver and our flexibility in helping them with some of their operating challenges. From our perspective, we see those relationships remaining very strong.
Thanks, Paul.
Thank you.
Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question, please.
Hey. Good morning, guys, and congrats on a good quarter. My first question is just related to cost inflation across the portfolio. If you're seeing any early signs of cost increasing, and any comments specifically international versus U.S.
Okay. Yeah, I think that by and large, the more material cost pressures that we have seen have been limited to the Permian and the U.S. unconventional market. The rest of the world, we're beginning to see some cost pressures, but not of the same. It's really as though the future rates of decline in the rest of the world probably have stopped, and so you're probably leveling out there, so you're beginning to see a little tension there. Whereas in the Permian, you are actually beginning to see cost increases. I'd like to take a moment, though, and acknowledge that we're largely protected in our Permian cost structure this year because of the contracting strategies that we have followed. This is, again, one of the benefits of having a 20 rig program that has been long planned, and we're well-disciplined around it.
It's allowed us to line out all of the services and contract arrangements that we have needed well in advance. We have about two-thirds of our spending this year that's either occurring at known prices or index costs, or have cost containment capabilities built into them.
Thanks, Pat. The follow-up question is just how do you get comfortable as a management team that the company is not under-investing? One of your peers is out taking a much more aggressive approach around capital spend over the next couple of years. I guess one of the things that we hear when people push back on our view on the company is that the fear is that you're in harvest mode right now, but we're going to go into early next decade, and what are the projects that will drive the next wedge of ultimately cash flow growth that enables you to replenish the portfolio and offset the declines? I wanted you to respond to that narrative because it's out there in the market.
I think the primary thing that I would say is, we're not after volume growth for volume growth's sake. We're after growing value, and we have a tremendous portfolio here. We showed a slide back in March that had 40 years of 2P resource development opportunity, and it's a very attractive resource that can be developed at relatively modest capital investment programs. We feel very comfortable about the portfolio that we have. Individually, we've got line of sight in the unconventional growth between now and into 2022. In 2022, we see TCOs, the Tengizchevroil, WPMP, FGP project first production coming online. For the next several years, we've got line of sight on very good growth and frankly, a portfolio that allows growth beyond that.
Thanks, Pat.
Thanks, Neil.
Thank you. Our next question comes from the line of Douglas Leggate from Bank of America. Your question, please?
Thank you. Good morning, everybody. I'll take my two as well, if I may, Pat. I'm afraid that I'm going to open up with the buyback question again. Just go back to that very quickly. Just philosophically, I'm guessing buybacks are not something you'd want to chop around quarter to quarter. I guess my question is, what would management need to see to be comfortable to commence a buyback program, assuming you would need that to be ratable? I'm thinking about level of cash on the balance sheet, whether quarter to quarter, what we're seeing is a function of cash tax payments and interest charges and so on. At what point would you be comfortable to say, "Okay, now we're ready to get going with this"?
Yeah, I don't want to put a quantification on this at this point, because I don't want to get ahead of the internal thinking on this. Clearly, we would have to have sustainability and a view of surplus cash generation beyond the $18 billion-$20 billion capital program that we want to fund, beyond the growth rate that we anticipate around dividends. As you say, our balance sheet is hovering in a very reasonable place at the moment. We have to have a view of sustainability, and when I say sustainability, I don't just mean this quarter, the next quarter, to maybe the third quarter out, but I really mean over a series of years.
We would like to be able to dollar-average in the cost of that share repurchase program, because we do have some shareholders who are not in favor of share repurchases because of the concept that you only do them when you have the cash available, and when you have the cash available, your stock price is high. The way that we can mitigate that is by having a very sustainable share repurchase program. It really comes down to the longer-term, or I'll say medium-term, cash generation capability of the firm and expectations around that.
I appreciate that answer. That makes a lot of sense, and I'm guessing the dividend takes a priority, as you've said previously.
Absolutely.
My follow-up is just a quick one. Obviously, you had a tremendous quarter relative to what the Street was expecting, and when we look through the presentation, there's a couple of comments in there about liftings and other, both U.S. and international. Can you just talk a little bit about what that was? Because was there some favorable timing issues in terms of sales versus production? I'll leave it there. Thanks.
Yeah. Actually, for the first quarter, we were slightly under-lifted. I think it's just a variance between the position of this quarter versus the prior quarter. Very modest there. I think part of the earnings improvement or the earnings beat that you might be highlighting really relates to depreciation. In particular, if you'll recall back, we had 155% reserve replacement ratio in 2017, and that obviously allows you to, as you go forward, to lower your DD&A rate per barrel.
That makes a lot of sense. Thanks, everybody.
Thanks, Doug.
Thank you. Our next question comes from the line of Phil Gresh from JP Morgan. Your question, please?
Morning, Phil.
Hey. Thanks, and good morning. First question is a bit of a follow-up to Neil's, just around the growth outlook through 2025. You do have some capital spending that will be rolling off after this year, Wheatstone and some other things. How do you think about where that wedge of-- assuming you're going to keep a CapEx cap in place through 2020 as promised, how do you think about where that extra cash flow might go between, say, adding more rigs in the Permian versus something like Gulf of Mexico, where a peer of yours just sanctioned a project with a $35 breakeven proposition?
Yeah. I think that we really feel good about sticking to the 20 rig program in the Permian. We think there is still opportunity to lower development costs, lower operating costs there, and maximize revenue streams out of that. That will be a primary area of focus for us, getting really good efficiency out of that particular asset. If I think about other areas where there could be small incremental money spent, it would really be around the appraisal and pre-FEED, pre-engineering work, perhaps in the Gulf of Mexico. We have four potential areas of interest there or the areas of potential interest, I guess I should say, Anchor, Tigris, Ballymore and Whale. That would be areas where we would look to do further evaluation.
I should also mention that the development activity around other shales other than Permian, so in the Marcellus, in Kaybob Duvernay, in Vaca Muerta, those areas could likely pick up additional capital investment.
Got it. Okay. Just one question.
Can I just go back and mention one thing with regard to deepwater so that people don't misinterpret what I'm saying here. We do have multiple opportunities that we can evaluate, we would be very disciplined and very ratable, be working on the pacing of any sort of development that we would do there.
Right. The commitment to the $20 billion cap. Just one question on the quarter. One of your peers on cash flows reported a flip in their deferred tax from a headwind to a tailwind at these higher price levels. I just wonder, you mentioned the billion-dollar headwind in the quarter from affiliates earnings versus distributions, which is about half of the headwind you're expecting for the entire year. Just curious if deferred tax played out as you expected.
I would say directionally, deferred tax played out as we were expecting. It is influenced, as you might expect, by the timing of when you place assets in service and when you get bonus depreciation. In regard to the overall set of headwinds, I had given guidance back in March of $2.5 billion to $3.5 billion as the headwinds for the year. I had said at the time that we thought working capital would be nil. I would say if prices hold where they are today, there will be a little bit of a penalty in working capital, as I mentioned in my prepared remarks. You may want to think towards the certainly activity trending towards the higher end of that range that I gave you.
I will say this is very hard for us to predict, though, I do want to reserve the right every quarter to come back and give you an update.
Thanks.
Thank you. Our next question comes from the line of Guy Baber from Simmons and Company. Your question, please.
Thanks for taking the question. Pat, I wanted to stick on the cash flow here a little bit, but the $7.1 billion in pre-working capital cash flow seemed to be better than the framework you all gave at the Analyst Day when we adjust for commodity price and understand that 1Q is typically weaker given downstream seasonality and the affiliate dividend timing. I just wanted to confirm that outperformance versus the internal plan and was wondering if you could isolate some of the key drivers of that better than expected cash flow. What sticks out to you all internally? With Brent at these higher levels here, just as a check, do the general sensitivities you all have given still hold, or do we need to rethink those a little bit?
Yeah. Guy, I'd say that the first quarter was really a very clean quarter, and it's a good basis, I would say, for you to build into your models going forward. I think we are running a little bit ahead, perhaps, on the guidance that we gave, but I think first quarter is a good benchmark for you there. The sensitivity that we had given for dollar improvement for Brent on earnings, on cash flow is about $450. Excuse me, on earnings, it's a little less than that.
That's helpful. Thanks. I had a follow-up from Mark. Appreciate the view on the macro oil landscape here. Can you just talk a little bit maybe about what your base case expectations are from a high level when you think about this decline in long cycle capital investment that's taken place for the industry over the last few years? From 2013 to 2018, we tallied up about 2 million barrels a day of major project capacity that started up per year on average, and then that drops to around only 1 million barrels a day from 2019 to 2022 or so. Is the Chevron view, do you see something similar? Do you see a supply gap emerging for the industry on the oil side over the next few years? And when might you see that beginning to show up in supply-demand balances?
Thanks, Guy. First, from a short-term perspective, obviously, we've hit a space where the market's rebalanced, and that's on the back of some fairly solid demand. In fact, demand that has surprised most folks to the upside and effective curtailment or planned or unplanned declines in certain countries around the world on top of geopolitics. That's all short-term.
price support for today. We're not designing our business on these kind of prices. We're driving our business for a lower for longer assumption. I think we're coming from a time where we're practiced at production coming from large investments versus short cycle activity. As an industry, we do not forecast that as well as we do the large projects. We have a perpetual supply gap, obviously. That's the industry that we're in. I would expect prices to stay in a fairly tight range over time, and we're going to design our business to deal with the lower end of those assumptions.
Thanks, Guy.
Thanks, Mark.
Thank you. Our next question comes from the line of Blake Fernandez from Howard Weil. Your question, please.
Folks, good morning. Frank, I presume this is your last call, so thanks for all the help and good luck to you.
Thanks, Blake.
Pat, I wanted to go back. You had mentioned the equity affiliate headwinds, and you kind of addressed that. I guess what I was thinking specifically is on Tengizchevroil. Is there an oil price level that you would actually begin to start getting distribution from that?
Actually, Blake Fernandez, we do still get distributions. It really is a determination that's made by the partnership council. It is not solely within Chevron's control. The partnership council folks take a look at what are the requirements for funding the project that's under development. They take a look at what cash generation has been. They take a look at what the partners' dividend interests are, and will negotiate basically to a dividend declaration. They can do that. They review that multiple times during the course of the year, and they can do one dividend a year, or they can do a couple dividends a year. It's really the partnership council.
Okay, it sounds like there is some flexibility and potentially could increase depending on what oil prices do.
There is. We had a dividend last year. Expectations are for a dividend this year as well. Again, it's not anything that we control uniquely within Chevron.
Okay. The second question, I'll just take advantage of Mark being on the call, but the 25,000 acres in the Permian that were transacted, it sounds like it was a swap. I just wanted to confirm that your acreage position hasn't really changed overall. I guess I was under the impression that a lot of those transactions had already come to fruition, and you all were done. Are you still in the process of marketing and coring up?
Thank you very much. You're right. Mostly swaps were discussed in the materials that you saw. Never done would be my answer in regard to potentially looking for ways to get longer laterals in the marketplace. From our perspective, we won't stop looking, and we believe it's created considerable value for that kind of disciplined execution that we talked about. In fact, I would expect more transactions in the future in this space.
I would just add, swaps are often kind of hard to put together just because you're trying to both parties optimize. They may take a little bit longer duration to come to fruition.
Okay.
Thanks, Blake.
Thank you.
Thank you. Our next question comes from the line of Ryan Todd from Deutsche Bank. Your question, please.
Great. Thanks. Maybe a first quick one on the Permian. Congrats on a great quarter. I think you guys may have blown out the Midland differential all by yourselves there. Can you talk a little bit about, obviously there's some timing issues here, but what drove some of the drivers of the particularly strong quarter-on-quarter performance in the Permian, whether it was from particular areas, number of completions, and how to think about the trajectory of that going forward?
Sure, Ryan. Basically, we had a large increase in the quarter because we put several wells on production at the very tail end of 2017. We also saw increased NOJV activity. The last point that I would make is that it can be lumpy. The production increases that we show can be lumpy. I wouldn't necessarily have you think that the increase from fourth to first quarter is something that would be repeatable or ratable necessarily.
Great. Thanks. Then maybe, we haven't talked about IMO 2020. Can you maybe talk a little bit about how you think about your relative positioning into it, and whether you would envision, or how you think about the attractiveness of any potential investments to take advantage of the situation?
Yeah. I think the short answer is really that Chevron's position is pretty well placed. We're well positioned. We have complex refineries, and we produce more distillates than fuel oil. We don't really produce much fuel oil in the U.S. We do have some exposure there around Asia. The situation that we've got from a refining capacity standpoint, as well as the fact that we've got midstream and trading capacity that we can optimize over the course of what we think will be an unstable market here as this rationalizes out, puts us, we think, in a pretty good position. It's a little hard to understand exactly what the impacts are. We continue to monitor what the industry response is going to be and what the actions are going to be taken by the various parties there.
It's kind of an unusual regulation in the sense that there's no single actor that's tagged with compliance. There's multiple ways that compliance can occur. It can occur on the part of the shippers, or it can occur on the part of the refiners. It's a little hard to understand exactly how compliance will take place.
At this point, you guys wouldn't envision deploying any meaningful capital?
No, we would not.
The kind of driven projects? Okay.
No, we would not. Yeah.
Thank you.
Thanks, Ryan.
Thank you. Our next question comes from the line, Roger Read from Wells Fargo. Your question, please.
Good morning. Again, congrats on the quarter. Frank, enjoy the operational side of life.
Thanks, Roger.
Hey, jumping in since I've got you, Mark and Pat on here. As we think about your ability to capture whatever differential exists between the Gulf Coast and the Permian, how should we think about that as flowing through your business? The reason I'm asking, Pat, is thinking about is it a realization, we'll see it in the upstream part there, or does it flow through somewhere else? Just trying to maybe head off at the pass, concerns that incoming quarters realizations could look weak, the overall number's fine. How does it flow through on your upstream business?
It would come through the upstream. Upstream realization.
Okay, whether it's commercial pipeline or whatever other capture, it all stay in the upstream side.
That's correct.
Okay. Then, switching gears, just since you put the chart up there with the longer, flatter supply curve. You've talked a little bit earlier about some of the Gulf of Mexico deep water opportunities. Price-wise, it looks like deep water non-OPEC would be in the money here. How do you think about when you're comfortable moving forward with an FID as you complete your studies on those various projects?
Pat, I'll start. It's about priorities from our perspective in capital allocation. The good news of having a portfolio that's so strong with the unconventionals, with short cycle, high return investments, it makes all of the other projects have to compete to be brought forward. I've heard Jay Johnson say numerous times, the idea of changing outcomes and improving returns. When you target a group of engineers on making a project have higher economics, it's amazing what can be developed for us to consider. Pat, would you add to that?
Yeah. I'd just say, first opportunity we've got obviously is infill drilling and keeping existing facilities fully loaded here. To the extent that there's a deep water, a new reservoir found that can tie into existing facilities, obviously, the economics there would be stronger. We're working to get the development cost of greenfield down significantly. Standardizing on surface facilities, design one, build many. Standardizing, along with the industry on subsea kit. We're also in a mode here now where we would be designing the production facilities, perhaps not for peak production, but for the best capital efficiency. Longer subsea laterals. There's just an awful lot that we think we can do in the deep water area to continue to get development costs down. We have to see that actually materialize before we would be in a position to take an FID.
We have a number of opportunities that are being evaluated, I'd say, at this particular point in time, and I can't really say which one is going to rise to the top first. It's nice to have activity underway there, and we're making good progress.
Great. Thank you.
Thanks, Roger Read.
Thank you. Our next question comes from the line of Dipan Jhaveri from Exane BNP Paribas. Your question, please.
Just one question, actually. Coming back to the LNG performance. Could you talk about just in terms of production, both at Wheatstone and Gorgon, how sustainable it is to produce above that nameplate capacity? Just a follow-up question to that would be, could you remind us in terms of the volumes from those two projects, is all of it on long-term contracts, or has there been some opportunities to, let's say, optimize some of that volume through price and arbitrage? Thank you.
Okay. Yeah, I would say, we have been spending time and effort and taking these pit stops in order to improve the reliability, for example, at Gorgon. We do think there's opportunity over time to expand capacity through debottlenecks and gain more capacity and gain more efficiency. We're willing to make investments now to get to a certain reliability and efficiency today. Longer term, I think there's debottlenecking activity that will be available to us. In terms of the contracts on Gorgon and Wheatstone, we are about 90% committed under long-term contracts for those.
Great. Was it a particularly good quarter in terms of for that remaining 10% or?
It was.
in terms of arbitrage or trading profit?
No, it was a good quarter. In terms of the spot cargoes, Asian spot prices on average were above $10. It was a very good quarter from a spot standpoint.
Remember, that's only 10% of our production.
Yeah. No, that's helpful. Thank you all.
Thanks, Dipan.
Best of luck, Frank.
Thanks. Appreciate it very much.
Thank you. Our next question comes from the line of Sam Margolin from Cowen and Company. Your question, please.
Hey, good morning.
Good morning.
Frank, I know you like to keep the call tight, I would be remiss if I didn't say thanks and congrats as well. With that.
Appreciate it.
My first question is just sort of a mechanics question around the affiliates. I recall in the past some conversations that there would be a co-lending program that would sort of functionally exclude affiliate spending from what we might think about as operating cash flow. Is that still a factor, or has the Chevron level found more efficient uses of capital?
Yes. The co-lending is really specific to the Tengiz project. We had co-lending previously. Right now, through 2018, we have had no requirement for any sort of co-lending. With prices where they are today, and if they stay at this sort of level, it's not clear whether there will be a co-lending requirement in 2018. It's something you should always have in the back of your mind, but with prices at this sort of level, maybe that is something that won't materialize for 2018. The point of the co-lending, obviously, this project was inaugurated back in a lower price environment, and the point of the co-lending was to be able to assure and allow the fact of all partners being able to fund their share of the project.
It really has been dependent upon what prices have been and the ramp-up of spend on the project per se. 2018 and 2019 will be the peak years of spending for Tengizchevroil's investment project, 2018 so far has certainly been into a strong price environment.
I see. Okay. Thanks for the clarification. Then my follow-up's just, I guess it's for both Mark and Pat. The comments about thinking critically on Permian takeaway I think resonate with the market because it's come up among a lot of the independents. Given your view on LNG markets globally, how do you see U.S. LNG maybe playing a role, particularly with respect to the areas in the Permian, more in the West Texas part of the Delaware Basin that are a little gassier, if not as an operator, maybe as a partner or a customer of that solution?
From a macro perspective, obviously you'll see companies start to given some of the length that will occur in the region, you'll start to see people consider further investments in the Gulf, the Gulf Coast has to compete with landed prices in Asia. From our perspective, we've got such an advantaged position taking care of that Asian growth from our base assets in Gorgon, in Wheatstone, that we'll watch what others do. We certainly have other LNG options around the world, all of it has to compete with landed price in Asia.
Thanks, Sam.
Thanks very much.
Thank you. Our last question comes from the line of Rob West from Redburn. Your question, please.
Hello. Thank you for taking my question. I'd like to go back to something you said earlier, Pat, which was about the surge in production in the Permian over the quarter. You attribute it to more well completions. The follow-up that put in my mind was, can you say whether over the quarter you drew down your inventory of DUCs or whether they were still building, just in terms of trying to assess the sustainability of that growth rate? That's the first one. I've got a follow-up. Thanks.
Yeah. I think there was a modest reduction in DUCs during the quarter, but you have to think about it as being modest.
Okay. Thank you. The second one is about Indonesia, where I know you've got an early-stage gas project in the pipe, and one of your peers sanctioned a gas project this week, I think. Topical, and I was wondering, I think that particular project you have, the holdup is really on license extensions. Is that right? If so, what's the timing on resolving those? If it's not right, could you say anything about the other bottlenecks you still need to overcome there?
Yeah, it's a good question. It's called the Gendalo-Gehem project, and we do have a new development concept, or we're reworking, I guess, the development concept is the best way to say it. Work has been underway on that effort for the last several months, in fact, probably more than a year at this particular point in time. Work is progressing on that. I would also say that the contract extension is also an element here. We've delivered an expression of interest to the government of Indonesia with regard to extensions of the concession. We want to make sure that it's a long-life project, and we want to make sure that the combination of the development concept as well as the fiscal terms gives us a high return project. Thanks, Rob.
Okay. Thank you for those details.
Okay. I think that closes us off here. I'd like to thank everybody on the call today. We certainly appreciate your interest in Chevron and everyone's participation. Jonathan, back to you.
Ladies and gentlemen, this concludes Chevron's first quarter 2018 earnings conference call. You may now disconnect.