Welcome to the Valero Energy Corporation report for 2014 first quarter results. My name is Bakiba, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. Please note that this conference is being recorded. I will now turn the call over to Mr. Ashley Smith. Mr. Ashley Smith, you may begin.
Thank you, Bakiba. Good morning. Welcome to our call. With me today are Bill Klesse, our Chairman and CEO, who will step down from the CEO position this Thursday, Joe Gorder, President and COO, who will become the CEO this Thursday, Mike Ciskowski, our CFO, Gene Edwards, and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at valero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact our investor relations team after the call. Now I'd like to direct your attention to the forward-looking statement disclaimer contained in the press release.
In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC. As noted in the release, we reported first quarter 2014 earnings of $828 million, or $1.54 per share. First quarter 2014 operating income improved over first quarter 2013, with gains in the Refining and Ethanol segments partly offset by a decrease in our former retail segment due to the spinoff of CST Brands in May 2013.
The Refining segment throughput margin in the first quarter of 2014 was $10.90 per barrel, which is an increase of $0.31 per barrel versus the first quarter of 2013. Decreases in gasoline and distillate margins in most regions and WTI discounts in the Mid-Continent relative to Brent were more than offset by increases in light sweet and sour crude oil discounts in the U.S. Gulf Coast. Also contributing to the higher throughput margin was our Quebec City refinery's increased consumption of cost-advantaged North American crudes in the first quarter. North American grades comprised 45% of the refinery's feedstock diet, up from 28% in the fourth quarter of 2013 and zero in the first quarter of 2013. This shows execution of our strategy to process more volumes of these cost-advantaged North American crudes.
For color on crude pricing, the shifting of U.S. Mid-Continent crude supplies from Cushing to the U.S. Gulf Coast as pipeline flow rates ramped up in the first quarter drove WTI discounts versus Brent to narrow by $9.15 per barrel. While LLS discounts to Brent widened by $5.39 per barrel as crude inventories built in the U.S. Gulf Coast between the first quarter of 2013 and the first quarter of 2014. Gulf Coast sour crude oil differentials to Brent also widened from the first quarter of 2013 to the first quarter of 2014 in response to the increasing supply of light sweet crude. The discounts for Mars and Maya relative to Brent increased by $4.10 per barrel and $8.76 per barrel respectively.
Refining throughput volumes averaged 2.7 MMbpd in the first quarter of 2014, which is an increase of 135,000 bpd versus the first quarter of 2013. Refining volumes were higher primarily due to less maintenance activity, which enabled the refineries to run at higher rates and capture margins. Refining cash operating expenses in the first quarter of 2014 were $4 per barrel, which is $0.21 per barrel higher than the first quarter of 2013, due primarily to increased energy costs on higher natural gas prices. I'd like to highlight another item in our operations during the first quarter of 2014. The new hydrocrackers at Port Arthur and St. Charles ran well and at a combined feed rate of about 120,000 bpd , which is their stated capacity.
The new hydrocrackers also contributed to an increase in yields of gasoline and distillates and a reduction in the yields of other lower-value products. The Ethanol segment delivered record first-quarter earnings, generating $243 million of operating income versus $14 million of operating income in the first quarter of 2013. Increased gross margin was driven by weather-related supply disruptions, low industry ethanol inventories, low ethanol imports, and lower corn costs relative to the first quarter of 2013. Ethanol production volumes averaged 3.1 million gallons per day in the first quarter of 2014, which is higher than first quarter 2013, but lower versus the fourth quarter of 2013 due to production slowdowns caused by weather-related rail congestion. As noted in the earnings release, we acquired an idled 110 million gallons per year ethanol plant in Mount Vernon, Indiana, for $34 million in March.
Efforts are underway to restart the facility, and production is expected to resume in the third quarter of this year. Given the favorable Ethanol margin environment, we like the returns potential for this new facility. General and administrative expenses, excluding corporate depreciation, were $160 million in the first quarter of 2014. Net interest expense was $100 million, and total depreciation and amortization expense was $420 million. The effective tax rate was 33.9%. With respect to our balance sheet at quarter end, total debt was $6.6 billion and cash and temporary cash investments were $3.6 billion, of which $384 million was held by Valero Energy Partners LP. Valero's debt to capitalization ratio net of cash was 14.3%, excluding cash held by Valero Energy Partners. Valero had approximately $5.4 billion and Valero Energy Partners had $300 million of available liquidity in addition to cash.
Given our financial strength and favorable outlook for refining margin conditions, last week, S&P affirmed our BBB investment credit rating and raised our outlook from negative to stable. Cash flows in the first quarter included $517 million of capital expenditures, which included $129 million for turnarounds and catalysts. In the first quarter, we returned $359 million in cash to our stockholders by paying $133 million in dividends and by purchasing approximately 4.3 million shares of Valero common stock for $226 million. For 2014, we maintain our guidance for capital expenditures, including turnaround and catalyst at approximately $3 billion. We expect stay in business capital to account for approximately 50% of total spending and for the remainder to be allocated to strategic growth investments, which are primarily for logistics and light crude oil processing projects.
For modeling our second quarter operations, you should expect refinery throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.42 MMbpd-1.47 MMbpd , U.S. Midcontinent at 370,000 bpd-390,000 bpd , U.S. West Coast at 260,000 bpd-280,000 bpd , and North Atlantic at 420,000 bpd-440,000 bpd . We expect refining cash operating expenses in the second quarter to be around $4.20 per barrel. For our Ethanol operations in the second quarter, we expect total production volumes of 3.5 million gallons per day, and operating expenses should average $0.40 per gallon, which includes $0.04 per gallon for non-cash costs such as depreciation and amortization. We expect G&A expense excluding depreciation for the second quarter to be around $160 million, and net interest expense should be around $95 million.
Total depreciation and amortization expense in the second quarter should be approximately $410 million, and our effective tax rate should be around 35%. Okay, Bakiba, we have concluded our opening remarks. In a moment, we will open the call to questions. Just want to remind our callers that during this segment, we would like to limit you each turn to two questions. You can always jump back into the queue for additional questions. Okay, Bakiba, we are ready.
Thank you. We will now begin the question and answer session. If you have a question, please press star then one on your touchtone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touchtone phone. Our first question is on a call from Paul Cheng from Barclays. Please go ahead, your line is open.
Hey, guys. Good morning.
Morning, Paul.
When I am looking at your buyback in the first quarter is $226 million. In January, from your last conference call is $204 million. When we are looking at, say, in February and March, the decision to slow down the buyback, can you help us understand what is the thinking, what is the criteria, when you determine how much you want to buy back?
This is Klesse. We were basically out of the market in February and March because of our pending management change, which our legal advice was we could not be out buying our stock. Then in March because of the earnings, the whole period of February, March, and then into April here with the earnings. We have really just been, in a way, blacked out or locked out of the market. There is no change in our strategy here of returning cash to the shareholders in our dividend, which we raised in January, and then buying our shares.
Second question, Bill. Strategically, how fast do you guys want to grow the LP EBITDA or distribution, whatever you want to talk about, during the initial years? I think there are two schools of thought amongst some of your peers. One is that they want to grow the LP as quickly as they could so that they will get to a size they can use their own balance sheet to raise debt to fund future growth. The other school is that they want to be just variable in the high teens. What is the school of thought that you guys belong?
Hey, Paul. This is Joe. If you look at our peer group in this, and we are really talking about the sponsored MLPs.
We consider Phillips and Marathon to be the two. Phillips h as said publicly that they are going to grow their distribution in the 20%-25% range. Marathon is at a range slightly below that we understand, and we tend to focus on the higher end of the range. So we are targeting 20%, 22%, 23% distribution growth annually going forward. Our approach would be to do it initially with drop-down assets that are of the same type of asset that we did when we put the initial assets in, which are those with very ratable stable cash flows based on fee-based income. We are going to target the timing for our first drop to be early part of the second half of this year, and then I would think, although we cannot give that kind of direction, it should increase the cash flows and distribution increases should follow.
Joe, can we still assume that the MLP-able assets sitting in the C corp today is somewhere in the $300 million-$400 million for you?
Paul, the range that we talk about is actually higher than that. I would say we're in the $800 million of EBITDA range that we believe we can drop.
Thank you. Before I finish that, Gene and Bill, congratulations on the retirement. Thank you for all the years of your insight. Really appreciate it. Best of luck and have a lot of fun there. Do not spend too much time in the beach, or you will get bored.
Thanks, Paul.
Thank you. Our next question is on the call from Roger Read from Wells Fargo. Please go ahead. Your line is open.
Hey, good morning.
Good morning, Roger.
Could we talk a little bit about Gulf Coast volumes here in the second quarter, and then within that broader expectation, generally speaking, volume has been better the last two quarters than I think, or at the higher end of the range of expectations. Can you walk us through what's happening in the Gulf Coast and then maybe what could push that to the higher end of the range again?
This is Lane Riggs. Are you asking in terms of our performance or the overall industry Gulf Coast?
Specific to you.
Okay. Specific to us, when you look at quarter-to-quarter or year-over-year, our turnaround activity was lower in the first quarter. We've had a little bit higher in the second quarter. In terms of our volumes, you'll see our second quarter volumes will be a little bit lower in terms of Gulf Coast because we have a bigger turnaround period. In terms of the amount of North American crude or light crude processing that we have versus our capacity, we still have about 165 bpd versus our capacity that we could have run. This is largely due that we have medium sour and heavy sour. We're still quite competitive in the first quarter versus our capacity. We could still run about 165 bbl more. Other than that, we were signaled to run full. Our crude units are as full as our availability will allow.
Hey, could you walk us through what the turnarounds are in the Gulf Coast in Q2, to the extent that you want to the specific units or type of work that's being done?
We no longer. We choose not to disclose that until after the turnarounds, until the following quarter when the turnarounds are complete. The numbers are, in terms of the overall volume metric, they were in Ashley's initial comments in terms of the guidance on the volume.
Yeah. So what's happened here is, this is all legal advice and some of the things that have happened in the markets. We've changed our policy on this, I think some of you have noticed. We no longer announce our turnarounds ahead of time. You just have to rely on the guidance that Ashley gives you as the volumes we're looking at.
Okay. Well, as long as we know who to blame if it doesn't go the way it was supposed to go.
Well, blame Ashley.
There you go. Just a last question here then. Condensate, we're hearing a lot more about that becoming a bigger and bigger issue, and even in some parts of West Texas where it's being rejected. I was wondering, what are you seeing along the Gulf Coast or in any other part of your operations in terms of condensate? Are you having any rejection issues, in terms of what's being delivered to the units? And then what your thoughts are on how Valero may deal with the condensate issue, not worrying so much about the industry with condensate splitters, et cetera.
Hey, Roger, this is Gary Simmons. I would say in the Gulf, we haven't had too much of an issue with getting light material to our crude units. We've taken a hard look at the condensate. We don't really see that the discounts are wide enough to really warrant a capital investment to be able to run a lot larger volumes of condensates in the Gulf Coast. We are taking a heavy look at this in the Permian Basin in some regions and getting with producers and seeing where they're seeing the production to see if there is some opportunity. But right now, we don't have anything planned.
Okay. Thank you.
Thank you. Our next question is going to come from Evan Calio from Morgan Stanley. Please go ahead. Your line is open.
Hey, good morning, guys. First, congratulations to Bill and Gene on your careers and retirement, and to Joe in the new role come May. First question really for Bill, and it's more general and somewhat reflective question. As you think about your 40+ year career with Valero and its predecessors, a lot has changed. How do you think about the current Valero and how it stacks up relative to your history and just your outlook today for the company versus other periods of time?
Independents are a bigger segment of the business today than it used to be, for sure. I think that will continue. That's one of the major changes in refining, is that the independent segment has far more weight. I think we react quicker to market influences. Valero, we're a company that's put together a bunch of assets and a bunch of people. Some of those assets were under-invested in, some were operated very poorly. We come together with one culture, and we have one goal, and it's really to perform with excellence. We've improved our operations tremendously over the last few years. We're a far more reliable operator, a much, much better operator. That thanks goes to our people being very focused on excellence, respect for each other, hard work, safety, and teamwork. Valero is one company.
Knowing our history, you know all the acquisitions, but we're one company. This business, though, a little forward, it's going to continue to be volatile. It'll be seasonal. It's made up of very hardworking people. I always like to point this out to people. This industry pays taxes, and we give a product to society that makes people's lives better. The world needs the oil and gas, regardless of the rhetoric that people talk about. Oil and gas is inexpensive, and frankly, the developing world has to have oil and gas. All the alternatives, and we know them all, and we know all the cost structures. Except for ethanol that has been able to work into the fuel mix, all the rest of these alternatives are too expensive, inefficient, and will do absolutely nothing to improve the environment. It's a waste of money.
I think we're very well or competitively positioned, and we add value to society. Valero has a very bright future. No question that the crude oil and natural gas that's happening in North America is the biggest thing in my career, and I'm sure in Gene's as well. It's having a tremendous influence on all manufacturing in the U.S. that people thought was really lost forever because the jobs in our industry really do allow people to own their home, educate their kids, and retire with benefits.
That's great. I have a second question. There's a current debate regarding the impact of current PADD 3 crude inventories that are well above five-year highs and the continuing heavy turnaround through the second quarter of this year and just how full the system might be as it relates to Gulf Coast crude differentials. I know PADD 3 is a big place. I was wondering if you could comment on what you're seeing in the physical inventory market. I know you talked on the condensate side, but how many tank tops or general inventory levels that you're seeing in various Gulf Coast storage regions? I'll leave it at that. Thanks.
Evan, this is Gary Simmons. If you look at the DOE stats from last week, we were at 209 million barrels. When we combine refinery tankage with third-party terminals, we would say that the working capacity in the Gulf is somewhere in the 275 million barrels range. So that puts you about 76% of overall working capacity that is being utilized today. We are not seeing problems in the Gulf. There are some areas that it does appear are starting to get pretty full with the SPR release. LOOP seems pretty full. One of the things that we are seeing is our barrels are showing up faster than they used to, so the third-party terminal operators are not sitting on inventory. They are turning those barrels pretty fast, and they are showing up at our refinery sites a little bit faster than what we have seen in the past. But no real issues that we have seen thus far.
Great. Appreciate it, guys.
Thanks, Evan.
Thank you. Our next question is going to come from Edward Westlake from Credit Suisse. Please go ahead. Your line is open.
Yes. Let me also say congratulations. $6.50, I think, is the EPS consensus, so not quite the $8 you guys did in the boom times, but certainly Valero looks like in good shape. I guess just a follow-on question on the MLP. Obviously, it's a great currency as well, not just for what you can drop down into it, trading at a 2% yield. Maybe think a little more broadly about talking to us about what you envisage the MLP to allow you to do over the next several years, potentially external M&A as well as the drop-downs. Thank you.
Okay. This is Joe. It's a good question. Obviously, the drop-downs are the primary focus for the strategy in the short term, but we do realize that we've got a very competitive currency to use to do other transactions. I think if you look at the logistics investments that Valero's making this year and that we'll continue to make next year in docks, we even have the rail, we've got pipe investments that we're making and looking at. We're going to continue to build the logistics portfolio at Valero Energy that will allow us to look the drops for extended period of time, which really just
eliminates the need to go into the market to pay a premium for assets. So we find that to be a great benefit to us. But we would not hesitate to look at what's available in the marketplace and to consider those assets and to use the currency to acquire those assets. But we felt that they fit into the system, and they were really assets that Valero Energy felt good about being able to make commitments to that provided that stable ratable cash flow stream going forward.
Okay, then a specific question on, and condensate's been a theme so far this call, but say you look at your more Mid-Continent refineries, the Ardmore, McKee. As you look at the crude that's coming into those refineries, presume, say, it's a WTI mix. A lot of refiners are starting to complain that WTI isn't the same WTI it used to be because obviously condensates are being spiked into it. Do you have any color on how the sort of gravity of that WTI has changed over time or where we are against the sort of 42 API spec?
Yes, I'd say at both Ardmore and McKee, we definitely see a trend towards the crude getting lighter, and it has caused some operating issues for us, some constraints where we have to cut rates because the gravity of the crude is getting higher. We try to control that the best we can with working with producers to control the quality of the barrels that we're getting. We have seen issues with the barrels getting lighter.
I guess I'll ask the direct question I should have asked, which is: do you think there will be a point where the really light crude will need its own infrastructure rather than being blended into the TI stream?
Yes, I do. I think ultimately we'll have to do that because the refineries just can't reject the light ends.
But how that structure comes out remains to be seen. I'm not necessarily sure you're going to see a gathering system. But you may see some type of fractionation that occurs that allows it to move from the field economically into these hubs and then gets addressed at a hub before it then moves to the refiners. You wouldn't necessarily think you're going to have a whole pipeline network to handle this, but you may have fractionation occur at different places in the system, including at the refinery.
Yep. Which would be an opportunity for you guys in the MLP.
That is right.
Okay. Thank you.
Thank you. Our next question is on a call from Jeff Dietert from Simmons. Please go ahead. Your line is open.
Good morning. It's Jeff Dietert.
Morning, Jeff.
Good morning. My congratulations to Bill and Gene, and appreciate all your education and knowledge and being an industry statement for the last many years. I'd like to focus on some of the medium sour crudes on the Gulf Coast. I think there's been a lot of discussion about light crudes coming in and more competition between light and medium. Yet when you look at Mars, it's trading $5.5 under LLS, which is wider than average over the last 18 months. You look at Thunder Horse, Southern Green Canyon, some of the other medium sours, and they're trading at nice discounts as well. Obviously, the 700,000 bpd Keystone South Pipeline has started up, and we've got SPR putting medium crude into the market.
Could you talk about how significant these factors are and maybe other considerations you believe are driving the wide discounts for medium crudes in the Gulf Coast and maybe how sustainable that weakness will be?
Yeah. I think we've been fairly consistent in our view that the medium sours and the heavy sours are going to have to trade at a quality-adjusted differentials to the light suites. As the light suites are pressured down, the medium sours and the heavy sours are going to have to follow. I agree with your comments. Certainly in the short term, the medium sours, probably the SPR release pressured the medium sours down in the Gulf a little bit more than what we had seen, especially in the first quarter. But overall, I think we'll see that trend continue.
Are your LPs arguing that you should run near maximum rates given where discounts are and crack spreads are and just looking at the high levels of inventory, reasonable U.S. demand, and increasing product exports?
Yes. I think as Lane commented, the LPs are really pushing towards maximum utilization across the system.
Thanks for your comments.
Thanks, Jeff.
Thank you. Our next question is on a call from Paul Sankey from Wolfe Research. Please go ahead, Paul. Your line is open.
Hi. Good morning, everyone.
Morning, Paul.
Bill and Joe, congratulations indeed to both of you. Again, as others have said, thanks for being so much fun to deal with over the years and so interesting to deal with. Could we just talk a bit about Gulf Coast again? Sorry to go back to this, but the throughput number, could you just remind me what that was in terms of what you expect it to be in the second quarter? Could you just repeat, to make it easy, what you did in the first quarter? Could you also talk about what your capacity is now on the Gulf Coast, what you think your refining throughput capacity is overall? Thanks.
Yeah, Paul. In the first quarter, our throughput was 1.585 MMbpd . Our guidance for the second quarter is 1.42 MMbpd-1.47 MMbpd . Hold on one second. I'm going to get an updated capacity. Capacity is around a total throughputs just over 1.6 MMbpd .
Yeah. Okay. So I've got that 1.6 MMbpd and then I think it was officially 1.54 MMbpd last year. Then, sorry to be so detailed here, but then I think you gave a light sweep throughput capacity as well for that system.
Hi, Paul.
On the call.
Yeah. This is Lane Riggs. In the Gulf Coast, it's about 480,000 bpd .
For you guys?
Yes.
Yeah. Okay. That's interesting. The outlook for that as we move forward, firstly, I guess that's a turnaround number in Q4. That's the reason why you're so much lower. But then I suppose that we're going to go back up to a much higher level of utilization through the rest of the year, Q3, Q4. Then when we move forward beyond that, is your capacity going to increase, let's say, into 2015? Or do you think you've reached a steady state, firstly, for the overall capacity, second for the light sweep? Thanks.
Uh-
Sorry to be so detailed.
Yeah. Paul, this is Lane again. We have the two crude unit projects. Everything you said is true. But in terms of projects we have in terms of our pipeline of projects is our crude expansions at both Corpus Christi and Houston, both of which will be somewhere finished towards the end of next year. The capacity of those 90,000 bpd at Houston and 70,000 bpd at Corpus in terms of our additional capacity in the Gulf Coast run light sweep.
They would be at the end of 2015?
Yeah. We're calling early 2016 when those are operating.
Okay, great. The other question I have for you is just related to the further outlets for light sweep crude, in terms of exports. Can you just, again, on a look-forward basis, talk about how much more oil you guys will be using in Canada? I know that there's some line reversal stories as well as some shipping stories. Thanks.
Yeah. What we've said is our Canadian refinery should be at 100% domestic light sweep by the end of the year. We're still on pace to complete that. We're a little bit ahead of schedule. We probably have about 130,000 bpd of capacity that we haven't utilized yet for the domestic light sweep. So if you take Lane's number in the Gulf of 165 bpd in the Gulf plus 130 bpd at Quebec, you're in this 295 bpd range of capacity that we still have to absorb light sweep crude, absent the capital program that we have.
Understood. Is that the limit on what you can do, absent the capital program? I mean, the only crude that you'll take up there is for your own use in your own refinery?
I guess I don't understand what you're asking.
Well, you mean we could ship up there and sell it to one of the other refiners in Canada?
Yeah, exactly what-
Yeah, of course we can. Our permit allows us to ship it to all four, I think.
Yeah.
Because the Irving and there's somebody else. I think there's four anyway.
Okay, great. If I could slip a final one in, Bill, because it's presumably your last call. Do you want to talk about how things have changed and what you think the outlook is in Washington, D.C.? Particularly, I'm wondering, do you think we'll be able to export condensate in relatively short order? Then longer term, whether you feel that in due course, potentially if prices in the U.S. get very low, we may be exporting crude as well. Any other thoughts you have on what's going on in Washington? Thanks.
Well, I do accept that the groundwork is being laid for condensates to be an issue, and that's all a definition of what crude oil is. Then the question was asked earlier about infrastructure, which is absolutely correct. So condensates may need to get addressed at some point. As far as exporting of crude, though, the industry is running the oil. The discounts we have in the marketplace today are really because of logistics in many of these markets. We're doing things, and I'm sure every one of our peer group are doing things to be able to run more oil. Then, we support the free markets, but you need to remember that this business isn't very free. There's lots of restrictions from the Jones Act and cartels to everything else that goes with it.
I think it remains to be seen, but under the law, there's a lot of flexibility. You can re-export Canadian crude. You can get licenses for that. As Gary just spoke, you have licenses to send U.S. domestic crude to Canada. There's also possibilities of exchanges if it becomes so much. But the thing I think that people need to remember is this is a windfall for the North America and the United States as far as manufacturing, whether it's natural gas liquids, natural gas, or crude oil. We can have a manufacturing boom. The petrochemical industry can boom. Where do you build petrochemical plants? Resource advantage, consumer advantage. The U.S. is now resource advantaged. This is a huge opportunity for jobs. We have a lot of rhetoric about jobs.
Here is a real area for jobs, job training, huge opportunities for welders, pipe fitters, instrument techs, operators. That was not here just five years ago. This question of exports and how our country should conduct themselves, especially when you see the turmoil in the world that we have going on, I think should take a lot of study. I think it will.
Great. Thanks for your thoughts. Thank you, guys.
Thanks, Paul.
Thank you. Our next question is going to come from Faisel Khan from Citigroup. Please go ahead. Your line is open.
Thanks. Good morning. Faisel from Citi. If I could ask a question on the heavy oil consumption in the Gulf Coast. Just with all the things going on in Venezuela, what are the risks to you guys, the volumes into your facilities from heavy crude you're taking from Venezuela? To counter that, can you give us an update on how much heavy crude you're bringing down from Canada, specifically through the pipeline into Port Arthur as well?
Yes. Our heavy sour volumes were fairly consistent from the fourth quarter to the first quarter. You brought up Venezuela. We did choose to allow our heavy sour inventories to creep up a little bit in the first quarter, in case we had a supply disruption from Venezuela. We haven't seen any changes that would indicate that we would have a risk of supply loss from Venezuela. The Canadian values, our Canadian volumes were down in the first quarter, and that was mainly just a matter of pricing. The heavy Canadian production was down somewhat due to weather, and then demand was also a little higher with BP Whiting's coker coming online. We didn't see the economic incentive to run the Canadians in the first quarter that we had seen in the fourth quarter and earlier.
That incentive is starting to come back, and we are ramping the Canadians back into Port Arthur here in April.
Okay. Understood. Can you also give us an update on what your strategic thinking is with the California assets? Has that changed at all? Is there a process going on or how are you guys thinking about those particular assets?
Well, in California, obviously our financial performance is not that great. It is our weakest group of assets now financially. Operationally, though, it's excellent. We have very solid assets. They're operated very well. We continue to make improvements on those assets. When you look at the basic issue of supply and demand, where demand has not really recovered out there at all from pre-Great Recession, although we're starting to see some improving economy and some uptick in demand. The focus that we have is to work on our crude costs and to continue to work on the operating costs and of course, adjusting our yields to fit the market. We view it as some of our competitors have publicly stated that in a way it's an option value out there. It's a huge market. The L.A. Basin is still absolutely a huge gasoline market.
The market's there. We just need it to show a little bit of growth back to levels it was before.
Okay, understood. Last question from me. Can you give us an update on the methanol plant alkylation unit projects and when you might think of sanctioning those projects?
Hey Faisel, this is Lane Riggs. Where we are, we're in the, what we would call between our phase two and phase three process in terms of working on the methanol, which means we're doing a more detailed engineering to get a better cost estimate, fine-tune our economics. We will bring the project forward for a phase three review at around November of this year, and we'll probably have a go, no-go on the project at that time. But so far, the project looks very favorable. There's no showstopper at this point in time with respect to that project.
Okay, great. I appreciate the time, guys.
Hey, thanks, Faisel.
Thank you. Our next question is going to come from Doug Leggate from Bank of America Merrill Lynch. Please go ahead. Your line is open.
Thanks. Good morning, everybody. Bill, Joe, and everybody, congratulations. You've been a great educator, Bill, for the industry, and we'll miss you at The Grenadier for sure. Good luck to all of you. My two questions, if I may. First of all, on the Gulf Coast, I think Lane made a comment earlier about Valero's refinery utilization, but I'd really like to go to more the industry's utilization. We have seen this huge build in crude inventories, but we've also seen a step change in utilization rates. As I look at it, if you want to characterize it as supply days of crude on the Gulf Coast, they're actually near the lowest level seasonally that we've seen in quite some time.
I'm just wondering if you guys could comment on that and what it means for working capital for the industry and for Valero specifically as you move your utilization rates higher on the Gulf Coast. I've got a follow-up, please.
Well, hey, this is Lane. Doug, I will take a little bit of a shot at that. The days of supply, I will defer to my friend here to the left, Gary. But in terms of if you look at our crude margins from the LT guys we've had a huge incentive to run crude in all of the first quarter
absolutely where the margin in the refineries exist today. So if you are not in turnaround or if you are not having any issues, you are trying to run crude. And you are not only trying to run crude in your crude stills. For example, we are running crude in some of our FCCs, two or three of our FCCs where we have the ability to run resid, we are running crude in lieu of that. So the industry is doing quite a bit in terms of trying to run more crude, because that is where the economic signals are telling us to be. And I do not know if you want to comment any more than that.
Yeah. So the days of supply working capital, in general, we generally see our domestic refineries that are taking ratable pipeline deliveries require less working capital than some of our Gulf Coast assets. And our view was, as we switch to more domestic barrels, it would drive down working capital. I am not sure. I think it is a little too early to tell that, and some of it is just we are not sure what our pipeline line fill capacities are going to be on some of these new lines to be able to really give you guidance on that at this time.
Yeah, I guess what I am really trying to figure out is, we are all looking at the differential on the Gulf Coast, and there has been obviously a consensus expectation that it was going to blow out again probably for LLS, and it has not, at least not in the magnitude in prior quarters when we have had downtime. And I guess what I am really trying to understand is, are you guys seeing the same sort of indicators that we are, which is that days of supply for the system as a whole is actually still quite tight given the higher utilization rates, or are you not seeing that at all?
It appears to me that the market in the Gulf is well supplied today. I do not know that I have actually looked at it in terms of day supply, but the market seems well supplied.
Okay. My follow-up, Gary, hopefully a quick one, more of a Valero specific. The comment you made earlier about you are seeing a lightening of the crude slate or for WTI specifically, and that is becoming more problematic, I guess, in terms of filling up some of your secondary units. Can you talk about what that is doing to your capture rates relative to the legacy capture rate of the system? I guess what I am really trying to get to is we have seen capture rates drift a little bit lower versus indicators, and I am just wondering if that has got something to do with it in terms of the incremental challenges you are having on running those crudes, and I will leave it there.
It is difficult for me to comment exactly what that does in terms of running lighter, in terms of where the capture rates go. We could look at that in more detail.
All right. I will take it offline. Thanks, guys.
Thanks, Doug.
Thank you. Our next question is going to come from Sam Margolin from Cowen & Company. Please go ahead. Your line is open.
Thanks. Good morning, everybody. I'll just echo the congrats to Bill, Gene, and Joe. Not a whole lot I could add, but I'd be remiss if I didn't say thanks, and I think it's going to continue to be as fun as it has been.
Hey, Sam, you might have to rejoin because we're hearing some weird feedback coming through.
Is it better now?
Every time you do it sounds like you are playing a video game.
Really?
Yeah. You might have to rejoin. We will wait for you.
Okay, thanks.
Our next question is going to come from Blake Fernandez from Howard Weil. Please go ahead. Your line is open.
Guys, good morning. Hopefully, you can hear me a little bit better.
Sounds good.
Okay, good. Congrats also to Bill, Gene, and Joe. It is great working with all you guys. Two quick ones for you. One, you mentioned the Quebec refinery and potential reversals Line 9, and of course, I know you barge in Eagle Ford crude up there as well. I am just curious if you could talk about how you see the economics unfolding. I guess I have always viewed pipeline as more efficient than barging crude, although I believe you outlined about a $2 cost to barge it on a non-Jones Act vessel. So I am just curious, once the line comes on, do you think we will start or maybe reduce the amount of Eagle Ford barge crude up there?
Yeah, Blake, this is Gary Simmons. I guess the way we would see it is that the pipeline deliveries would be the most advantaged, and second to that would be the barrels that we get over the water, and finally would be the tranches that we are currently taking by rail. So if barrels started to drop off, it would probably be the rail volume that you would see fall off before the volume that we are taking over the water.
Okay, great. The second one for you quickly, there are some press reports out there that the Milford Haven refinery will be closed next month. Obviously, you will get a direct benefit at Pembroke with those volumes being offline, but I am just curious if there is any opportunity to maybe buy some units or specific assets from that facility that would enhance Pembroke's performance.
Well, Klesse, we are fully aware of what is going on there, and we are not sure how this is all going to work out, and if there is an opportunity for us to improve our situation at Pembroke, we will take a look at it. But as of today, we do not have anything going on directly.
Okay. Fair enough. Thank you.
Thanks, Blake.
Thank you. Our next question is going to come from Chi Chow from Macquarie Capital. Please go ahead. Your line is open.
Great. Thank you. I want to go back to the Canadian strategy. It has been reported you have got this application for a re-export license of Canadian crude. First, have you received that permit yet? Secondly, can you just discuss the strategy with the permit, and what is the strategy on moving volumes out to either back up, I guess, to Quebec or out to Pembroke? From what I understand, that is part of the permit as well.
Yes, this is Gary Simmons. We do have the permit in place. Some of that, why we went out and got that, actually, when we were having the weather problems moving the Canadian by rail to Quebec. We wanted to be able to ship that volume and move the rail volume to the Gulf and then be able to bring it up over the water to Quebec, and we were not allowed to do that. This permit will allow us to do that. Certainly, at some point in time, we could also look at taking volume to Pembroke. Today, we do not have any plans to do that, at least in the short term.
Does the permit allow you specifically to move to Pembroke only, or is it open to destinations within Europe or the U.K.?
I am not sure on the specifics for that.
I think in the permit you actually identify, and I believe we have nine different places we are allowed to take it in the permit. You actually have to specify. You asked a philosophy or strategy question. The strategy is to have flexibility. We have the assets going in place with rail at the U.S. Gulf Coast that allows us to keep the crude oil neat, that allow us then to go ahead and keep it segregated. Then if the economics are there, we have flexibility in our system.
Okay. Bill, the nine different places, are they all within your own facilities at Valero?
No, they are not.
I am just wondering, is not it in your best interest to keep as much crude in the Gulf as possible? At what point would you look to execute on this permit to move the crude out?
It is all flexibility, and this is about economics. We would do exactly what you are leading to, is all this in our self-interest for our shareholder.
Okay, thanks. I guess second question, can you give us the product export volumes in the first quarter, and what the capacity is for both gasoline and diesel at this point?
Sure. This is Gary Simmons again. In the first quarter, we exported 208,000 bpd of distillate. We would say that our capacity today is close to 325,000 bpd. We have some capital projects in the works that will bring that up to 425,000 bpd. On the gasoline side, we exported 124,000 bpd of gasoline in the first quarter, and that capacity is probably in the 225,000 bpd range. It will also go up to about 250,000 bpd with some of the dock work we have going on.
Okay. Thanks, Gary. Any timing on the increase in the capacity on both products?
Yes. The dock work is probably a year to two years away from being complete.
Okay. One final question on exports. Have you noticed any impact from some of the new refineries that have come into the market, and most notably the Jubail plant in Saudi Arabia?
We still see a margin today, a good margin to export when you take the RIN into account. We're finding plenty of homes to take the barrels. I can't say that we've seen a big impact from that.
Okay, great. Thanks a lot.
Thank you. Our next question is going to come from Sam Margolin from Cowen & Company. Please go ahead, your line is open.
Hey, coming through okay?
Sounds great.
Okay. Thanks for letting me back. I will keep it tight. I think it was brought up earlier, the connection between utilization and capture rate. I think one of the moving parts there might be intermediate feedstock costs. It seems to be one of the last remaining structural challenges. I bring it up because you guys are addressing it with the crude units. I was just curious if any of those economics are changing, if there is an opportunity at this stage to make them bigger or add another one or even drop them down and put a toll on it because the commodity structure is looking more favorable.
Hey, Sam, this is Lane Riggs. Both crude units that we did were as large as they could be and handle the greenhouse gas permit. We do not really have the opportunity to make them larger at this point in time without going through the process of getting a greenhouse gas permit.
Okay. I guess I will bring up Maya- Brent spreads have been pretty favorable. I think some of that has to do with WTS and the Midland leakage of the price dislocations there. As pipelines and infrastructure start to come online out of West Texas, maybe Midland normalizes closer to other benchmarks and WTS comes with it. If you guys are expecting any weird price action in Maya, maybe in the third quarter, and if there is something we should prepare for or try to bake in ahead of time to our estimates.
Well, I think with the Maya formula, there's always that risk that if Midland comes into Cushing, that it can affect the Maya formula in the short term. But we believe they're trying to price their crude so it can be competitive with Mars, and so that even if Midland comes in, they will eventually adjust the K to keep their crude competitive with a medium sour alternative.
Okay. Thanks so much. Have a good one.
Thanks, Sam.
Thank you. Then our next question is going to come from Cory Garcia from Raymond James. Please go ahead, Corey, your line is open.
Thanks. Good morning, fellas. Definitely want to echo everyone's thoughts and best wishes going forward for Bill and Gene. Most of my questions have already been answered, but I guess as a follow-up to Faisel's earlier. Lane, do we have any sort of go, no-go timeline on the alky unit that you guys talked about? Obviously, a little bit lower scope and scale of a project, but just wondering if you have a similar sort of thing for us to at least keep an eye out for.
Hey, Cory. It's on a similar timeline. We'll have the same sort of phase review in the fourth quarter with management and make similar decisions.
Okay, perfect. Thank you.
Thank you. We have no further questions at this time.
Listen, for those of you that are still on the call, and it was mentioned several times, but this is Gene and my last call with you all, and Gene and I both want to tell you guys thank you very much for the interest you've shown in Valero, and we wish all of you all the best going forward. Thank you very much for that.
Okay. Thank you, Bill. Thank you, Bakiba, and we appreciate everyone calling in, listening to the call today. If you have additional questions, please contact our investor relations department. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.