Welcome to the Valero Energy Corporation Reports 2015 fourth quarter earnings conference call. My name is Yolanda, and I will be your operator for today's call. At this time, all participants are on a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. It is now my pleasure to turn the call over to Mr. John Locke. You may begin.
Good morning, welcome to Valero Energy Corporation's fourth quarter 2015 earnings conference call. With me today are Joe Gorder, our Chairman, President, and Chief Executive Officer, Mike Ciskowski, our Executive Vice President and CFO, Lane Riggs, our Executive Vice President of Refining Operations and Engineering, Jay Browning, our Executive Vice President and General Counsel, 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. I would 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've described in our filings with the SEC. I will turn the call over to Joe for a few opening remarks.
Well, thanks, John, good morning, everyone. The fourth quarter and full year 2015 were really great for Valero. We operated safely and reliably, achieving our lowest-ever employee injury rate in refining and reaching an annual average refinery utilization rate of 95%. The markets were favorable during the quarter. Domestic product demand grew, supported by lower pump prices, sour crude discounts relative to Brent were attractive to our highly complex refining system. While distillate margins were pressured during unseasonably warm weather in North America and Europe, distillate demand in Latin America remained robust. In fact, we exported record volumes of distillate and gasoline in the fourth quarter. We continue to execute well on our projects. In the quarter, we successfully commissioned the new Corpus Christi crude unit, the Port Arthur gasoil hydrocracker expansion, and the McKee crude unit expansion.
Our Quebec City refinery also began receiving crude via Enbridge's Line 9B. We exercised our option with Plains All American to acquire a 50% interest in the Diamond crude oil pipeline project. Once completed, this project will connect Cushing with Memphis and provide us with crude optionality and long-term cost savings versus sourcing crude oil from St. James. Additionally, Valero Energy Partners continues to execute its growth strategy, and Valero GP's interest in VLP reached the highest splits with the distribution increase we announced earlier this week. We also continued to advance our refining growth strategy. Construction of the Houston crude unit remains on schedule with startup planned in the second quarter of 2016. Earlier this month, our board of directors approved the Houston alkylation project. This project is estimated to cost $300 million and is expected to be completed in the first half of 2019.
Finally, regarding cash returns to stockholders, we paid out 80% of our 2015 adjusted net income, exceeding the 75% annual payout target. Further demonstrating our belief in Valero's earnings potential, last week, our board of directors approved a 20% increase in the regular quarterly dividend to $0.60 per share or $2.40 annually. With that, John, I'll hand it back over to you.
Okay. Thank you, Joe. Moving on to the results. We reported fourth quarter 2015 adjusted net income from continuing operations of $862 million, or $1.79 per share, versus $952 million or $1.83 per share for the fourth quarter of 2014. Actual net income from continuing operations was $298 million, or $0.62 per share, which compares to $1.2 billion or $2.22 per share in the fourth quarter of 2014. Please refer to the reconciliations of actual to adjusted amounts as shown in the financial tables that accompany our release. For 2015, we reported adjusted net income from continuing operations of $4.6 billion or $9.24 per share, compared to $3.5 billion or $6.68 per share for 2014. Actual net income from continuing operations was $4 billion or $7.99 per share in 2015 versus $3.7 billion or $6.97 per share in 2014.
Fourth quarter 2015 refining segment adjusted operating income of $1.5 billion was in line with the fourth quarter of 2014. Stronger gasoline and other product margins, combined with higher refining throughput volumes, were offset by lower distillate and petrochemical margins and lower discounts for sweet crude oils relative to Brent crude oil. Refining throughput volumes averaged 2.9 million barrels per day, which was 34,000 barrels per day higher than the fourth quarter of 2014. Our refineries operated at 97% throughput capacity utilization in the fourth quarter of 2015. Refining cash operating expenses of $3.47 per barrel or $0.29 per barrel lower than the fourth quarter of 2014, largely driven by favorable property tax settlements and reserve adjustments and lower energy costs.
The ethanol segment generated $37 million of adjusted operating income in the fourth quarter of 2015 versus $154 million in the fourth quarter of 2014, due primarily to lower gross margin per gallon driven by a decline in ethanol prices versus relatively stable corn prices. For the fourth quarter of 2015, general and administrative expenses, excluding corporate depreciation, were $206 million, and net interest expense was $107 million. Depreciation and amortization expense was $494 million, and the effective tax rate was 28% in the fourth quarter of 2015. The effective tax rate was lower than expected, due primarily to a reduction in the statutory tax rate in the United Kingdom and the settlement of income tax audits in the United States.
With respect to our balance sheet at quarter end, total debt was $7.4 billion, and cash and temporary cash investments were $4.1 billion, of which $81 million was held by VLP. Valero's debt to capitalization ratio, net of $2 billion in cash, was 20%, yet $5.6 billion of available liquidity excluding cash. Cash flows in the fourth quarter included $732 million of capital investments, of which $164 million was for turnarounds in catalysts and $136 million was for our investment in the Diamond Pipeline. For 2015, capital investment included $1.4 billion for stay-in business and $1 billion for growth. We returned $1 billion in cash to our stockholders in the fourth quarter, which included $240 million in dividend payments and $767 million for the purchase of 11.1 million shares of Valero common stock. For 2015, we purchased 44.9 million shares for $2.8 billion.
For 2016, we maintain our guidance of $2.6 billion for capital investments, including turnarounds, catalysts, joint venture, and strategic investments. This consists of approximately $1.6 billion for stay-in business and $1 billion for growth. For modeling our first quarter operations, we expect throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.61 million to 1.66 million barrels per day, U.S. Mid-Continent at 430,000 to 450,000 barrels per day, U.S. West Coast at 245,000 to 265,000 barrels per day, and North Atlantic at 465,000 to 485,000 barrels per day. We expect refining cash operating expenses in the first quarter to be approximately $3.85 per barrel. Our ethanol segment is expected to produce a total of 3.8 million gallons per day in the first quarter. Operating expenses should average $0.37 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization.
We expect G&A expenses, excluding corporate depreciation for the first quarter, to be around $175 million, and net interest expense should be about $110 million. Total depreciation and amortization expense should be approximately $470 million, and our effective tax rate is expected to be around 32%. That concludes our opening remarks. Now, before we open the call to questions, we again respectfully request that callers adhere to our protocol of limiting each turn in the Q&A to two questions. This will help us ensure that other callers have time to ask their questions, which are also important. If you have more than two questions, please rejoin the queue as time permits.
Thank you. We will now begin the question and answer session. If you have a question, please press star then one on your touch-tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you're using a speakerphone, you may need to pick up your handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touch-tone phone. Our first question comes from Blake Fernandez from Howard Weil. Your line is open.
Guys, good morning. Just a quick question on the alkylation unit. First, can you provide any kind of return expectations that you have for the project? Secondly, on the spending profile, it looks like your CapEx guidance into 2016 is about the same as it was before. I'm just confirming that most of the spending probably is weighted towards 2017 and 2018.
Well, hey, Blake, this is Lane. Yeah, the board approved the alkylation unit nominally about $300 million. The front-end decision EBITDA was about $105 million. If you use 2015 prices, it would be about $140 million EBITDA. With respect to the budget, when you look at our original, we gave out the 2016 guidance on our budget for this year two years ago. It's up about $100 million, and it's nominally the Port Arthur turnaround. We have a little more turnaround than our outlook was two years ago, but certainly, all the rest of it, the alky's clearly fitting inside our sort of $1 billion a year strategic capital. It's nominally about $100 million a year, and it is back-weighted, like you said, towards 2017 and 2018.
Okay. Thanks, Lane. Secondly, just maybe if you don't mind sharing some thoughts around light heavy spreads into 2016. I guess what I'm thinking, especially in light of Iranian barrels coming to market that could potentially displace some other barrels globally, seems like maybe that would have an indirect benefit to Valero given your leverage to Gulf Coast and heavy processing.
Yeah, Blake, this is Gary Simmons. Overall, we've seen very good spreads between the medium sours and light and heavy sours as well. Certainly the Iranian production coming online will put further pressure on those differentials. I think we see several things in the market. The increase in OPEC production is putting medium sour barrels into the Gulf. You see Gulf of Mexico deep water medium sour production rising. At the same time, we're seeing some of the light sweet production falling off here in the United States, so it's leading to very good differentials. I think the other thing that's a fundamental shift is where fuel oil had been trading around 80% of Brent, it's now trading around 60% of Brent, which should mean that we would expect to see good medium sour and heavy sour differentials throughout the year.
I think the other thing for us, the Iranian production, of course, we won't be running any of those barrels, but we do think the market rebalances and makes some additional heavy and medium grades available to us from Latin America.
Great. Thanks for the color, Gary. Appreciate it, guys.
Our next question comes from Neil Mehta from Goldman Sachs. Your line is open.
Hey, good morning.
Morning, Neil.
Joe, Lane, and Gary, you guys have a unique window into what's happening from a product demand perspective. It's one of the big debates in the oil markets right now. Can you talk about what the export markets look like from your perspective for diesel and gasoline? Then to piggyback off of that, we've seen four weeks now of these gasoline builds in the DOEs. Is that consistent with what you're seeing on the ground?
Yeah, Neil, this is Gary. I think we continue to see very good export demand for our product. As Joe mentioned, we had record volumes in the fourth quarter. We continue to see good demand for both distillate and gasoline abroad. Our rack volumes remain very strong. We're moving a lot of product over the racks. We've seen good domestic demand for our product as well. Certainly, I think when you get this early in the year, it's kind of hard to dissect the DOE data. We've seen the large builds as well. Some of the data to us looks a little suspect. I think we've seen a lot of weather issues in the Gulf that our belief may have been that it hindered some of the waterborne barrels from being able to leave due to fog and weather that we've had in the Gulf.
The Mississippi River flooding also has hindered some of the refiners along the river, their ability to clear those barrels as well. I think we're just too early to really get a good view of what demand's going to look like. Everything from us, our perspective looks good.
Yeah. The fundamentals I think for strong demand are still there. There's no question about that. I mean, we continue to have prices that are very attractive at the street, there's a lot of data that's coming out recently on vehicle miles traveled being up and also on auto sales being skewed towards larger SUVs and light heavy trucks. Again, as Gary said, it seems like every January, Neil, we find ourselves in a situation where we're looking at the year and everybody's trying to figure out, oh, gee, is this over and is demand going to be totally eroded? As he said, I think it's just a little early to tell, but fundamentally, it looks like things should bode well for us going forward.
I appreciate that. The second question, Joe, this is for you, is just the outlook for M&A. I think in the past you've said that you want to see that relative multiple between Valero and the group move a little bit higher before you would be more aggressive around M&A. Just your latest thoughts there, also at the parent level, also at the midstream level.
Okay. Neil, Michael Ciskowski If I'll give him a crack at this to start.
Yeah. Thanks, Joe. I appreciate it. For Valero, our appetite for midstream M&A and M&A in general hasn't changed. We continue to look at opportunities, particularly those that support the earnings growth that we can achieve in our core business. The good news is we have a great portfolio and significant earnings capability as we demonstrated in 2015. More specific to VLP hasn't reached the size where it can execute most of the M&A transactions on its own. We do continue to evaluate opportunities there as well. As we've said before, we remain committed to VLP's drop-down growth strategy, and we're not interested in a step-out transaction that would change VLP's risk profile or its growth story.
Appreciate that, Joe, Cisco. Thank you.
Good. Thanks, Neil.
Our next question comes from Ed Westlake from Credit Suisse. Your line is open.
Good morning. Congrats. I think this time last year, I said I was going to drive down in an S350 to Disney World and would there be enough gasoline yield from Valero and the other refiners in the summer to make it possible for me to do so. I'm going to ask the same question after a year of looking at gasoline markets and some very strong cracks and strong demand. What are you guys doing to be able to make more summer-grade gasoline?
In the short run, I don't think we really have anything that we have on the horizon that is going to be able to increase our gasoline yield. The big thing is the Alky project that Lane mentioned that will give us additional ability in terms of making additional gasoline when that project comes online.
Hey, we are in maximum gasoline mode now, though, within the system, aren't we?
That's right. Yeah, we are.
Okay. Switching to the self-help. Obviously, the toppers coming on stream, we've started to see that maybe in full Q and into this year. You used to have sort of a $500 million number. I think that's gone down to $430 million. Just a reminder of what you think the key drivers will be in terms of the spreads driving that $430 million.
Hey, Ed, this is Lane. The funding decision on both those units, we had Brent and LLS at parity, you're pretty much in that environment. We like to reference this historical price set. If you look at those projects in 2015, the Corpus unit would give us about $200 million of EBITDA, and the Houston crude unit would be about $230 million. Those are slightly exceeding, obviously, our funding decision. In the current market, we're pretty much at our funding decision. As Joe alluded to, the Houston crude unit will start up in the second quarter, and we start up the crude unit in Corpus Christi without any incident and start it fine.
Okay. It's mainly crude against VGO spreads we should look at?
That's right. The big driver here is crude versus really resid. Low sulfur resid.
Okay. Helpful. Thank you.
We have a question from Evan Calio from Morgan Stanley. Your line is open.
Hey. Good morning, guys. Maybe a follow-on to the product demand question. Given the macro uncertainty, pacing your cash returns to the net income makes sense on a quarterly basis. Has that changed at all given macro uncertainty or share price volatility?
Well, Evan, this is Mike. Our balance sheet is very strong, and we intend to keep it that way. Our guidance is to pay out 75% of net income for 2016. As far as levering up to meet that target, I'm not sure we'll be required to do that. It's early in the year, we'll just have to see how the year plays out.
Got it. Then maybe a different follow-up on, you shared the EBITDA on all these new projects that'll be contributing in 2016 in Corpus, Port Arthur, McKee, Houston in 1Q. Any color in aggregate how they affect your crude slate flexibility or just related, given the right economic indicators where do you think you could max out your heavy sour and then medium sour runs?
Yeah. The topper really just gave us more capability to run domestic light sweet barrels or foreign light sweet barrels. It really added to that. We haven't done anything that really materially changes our ability to process medium or heavy sour grades in our system. It was mainly those two units are adding 160,000 barrels a day of light sweet capacity.
Yes.
Right. Then but the uptick quarter to quarter on overall heavy and medium sour runs, where could that be? I'm sure that's an average number, so I'm just trying to get a sense of if you're kind of max flexed at this point or where would you take that?
Yeah, a little color on that, Evan. I'll take the topper out so you can have an apples to apples comparison. If you take the toppers out between last quarter and where we are today, we backed out about 400,000 barrels a day of lower 48 domestic light sweet crude, and we've replaced that with medium sour grades and foreign light sweet imports. That's the big change in our system. Heavy sours are about the same.
Got it. Appreciate it.
Paul Cheng from Barclays, your line is now open.
Hey, guys. Good morning.
Good morning, Paul.
Mike, actually, this is for you. I'm going to ask from the other angle on the balance sheet. The last several years that you guys have done phenomenally well, both operationally and financially, and also the return to shareholder. I'm just curious then, has the cash flow remained strong at this point? Does it make sense, even though you already have a very strong balance sheet, to maybe utilize a part of the free cash flow, maybe 20% or so, to further strengthen the balance sheet? I think that we all live through the up and down. While I'm bullish on the market, I could be wrong, and that we have seen what happened, that everyone was bullish in 2007, and then the bottom fell off because of the economy.
Should we actually take maybe a slightly different view at this point, just as a safeguard to ensure that we build up some additional cushion, even though your balance sheet is already remarkably strong? If cash flow cut by half, then maybe that will allow you to even have better opportunity to strike and take the opportunity when everyone this week.
Okay. That's quite a question, Paul. I remember those days very well. Our balance sheet is very strong, and we intend to keep it that way. If you're suggesting that we build cash here, our current focus is to continue to look for opportunities to grow our business and increase our earnings per share.
If you're suggesting that we prepay some debt, the majority of our remaining debt contains make-whole provisions that make those prepayments less than compelling.
I see. You won't be able to prepay, and you won't add on some additional cushion into your balance sheet by adding cash?
No, I don't think at this time that's what we'll be doing. I think we can execute on our payout strategy and all that type stuff, as I said earlier, without levering up the balance sheet.
Joe, just curious that with, I think that some of the other company in distress and look like some retail asset maybe become cheaper. If you're looking at your portfolio, does it make sense that if the entry point is right for you to re-enter into retail by doing so that can maybe that cushion your gains or the hedge against any RIN cost increase or that you provide even a more direct outlet to your own refinery product? That this is you really not interested going back into that business?
No, Paul, that's a good question. We look at it periodically. The retail business is materially different from the refining business, and you know that. Refining is capital intensive and fewer people, the retail business is people intensive. When we look at it, I think our view would generally be that we don't need to control the retail outlet to be able to be a very good supplier into that market. Frankly, what we're focused on is further extending our wholesale business where we could have contractual relationships and support the Valero brand at the street from the wholesale side rather than from a direct retail operation. If you reflect back on our retail volumes when we owned CST in the 1,000 or so sites and the sites in Canada, the volume we moved through them was about 125,000 barrels a day.
When you look at that as its order of magnitude relative to the total motor fuels that Valero's producing, it's a very small percentage. It would take a real huge step for us to have any kind of material presence to really allow us to hedge the benefits associated with owning retail directly. I don't know that unless there was really something that was just incredibly good or allowed us to sustain our contractual relationships with customers, I don't see us re-entering that market in the retail business.
Thank you.
Our next question comes from Jeff Dietert from Simmons & Company. Your line is open.
It's Jeff Dietert with Simmons. Good morning.
Good morning, Jeff.
I appreciate the update on all the projects. I think the St. Charles hydrocracker, I didn't see an update on that. I apologize if I missed it. Could you talk about St. Charles?
Hey, this is Lane. Yeah, we're currently changing the catalyst out and doing the capital. It's a small capital project, $40 million. It's just really a catalyst change out, which is based on the cycle when we change out the catalyst and the capital implementation, we're doing it right now. It'll be ready to go here in the second quarter.
Okay. Could you talk about your EBITDA expectations on Port Arthur and St. Charles hydrocrackers, what those are expected to contribute?
Well, again, we spend nominally about $80 million on the two and our funding decision EBITDA is somewhere between a total of $60 million-$80 million. These are an example that's sort of quick-hitting, self-help. These were sort of the low-hanging fruit to sort of arbitrage out that there were maybe some, after we started running these units to figure out where we could put a little capital in and get a pretty good hit on it. I don't know if that'll show up as a revenue stream or something like that to you guys, but it'll certainly show up in our margin capture going forward.
Okay. Could you talk a little bit about Line 9 now that it's started up and what your flexibility is to take Canadian heavy versus Syncrude versus Bakken? What's the flexibility there in an environment where you're encouraged to take those grades?
Yeah, Jeff, this is Gary. Line 9, we began taking crude in December. It's fully up and operational in that capacity. In terms of flexibility of grades, all of our crude through Line 9 goes through Montreal, and we really don't have logistics to be taking heavy or medium sours. It's pretty much just for light sweet crude for the Quebec refinery.
Great. Thanks for your comments.
Our next question comes from Roger Read from Wells Fargo. Your line is open.
Yeah, thank you. Good morning.
Hi, Roger.
Just maybe coming back to the gasoline question for this summer. Octane availability. As you look around, what do you think the biggest roadblock will be again? Is it going to be the octane alkylate side? Is it going to be blending stocks? What is your assumption for gasoline demand growth this year as you set up your expectations and budget?
Hey, Roger, this is Gary. I think we see that as long as we have a strong gasoline market and we have length in a sub-octane blend component like naphtha, the gasoline pool is going to try to draw naphtha in, and it's going to mean octane is fairly expensive. We expect to see output values fairly strong again this summer.
I don't see anything on the horizon that really leads me to believe that's going to change anytime soon.
Where will the industry look? If you thought about it as a low-hanging fruit thing, where would you be looking to pick up octane? One of the thoughts is if U.S. light sweet is declining and we're importing a light barrel, maybe we create a little bit more that way, since the U.S. barrels tended to be on the low end for octane. Where else should we consider?
Well, I think for us, we've tried to look everywhere we can, and this Alky project was the best thing that we really felt was out there. We've studied reforming, expanding reforming, building new reformers, and the Alky project has the best return in our system.
more near term, are we just going to struggle 2016 and 2017? I understand where we are in 2019.
Yeah, I think we will. I don't see anything in the near term that's going to have a significant impact on the octane balance.
Okay, great. Thank you.
Sam Margolin from Cowen and Company, your line is now open.
Hey, good morning.
Hi, Sam.
I wanted to ask one more about the Alky project here. There's a couple others out there in the system. A lot of times, these units, as newly built units, are paired with a midstream acquisition or some other project to produce the feed by the operator. Is it fair to say that there's no real necessity to commit capital to source incremental NGLs here? There's plenty available, this Alky unit can be built as a standalone, or actually, is it paired with maybe something coming off the toppers or another attribute of your yield right now?
Well, hey, Sam, this is Lane. Ours is a little bit different, I would say, than other people in the industry. What we're doing is we're taking an existing alkylation unit at Houston, and we're converting it to alkylate C5 olefins. Normally, alkylation units alkylate C4 olefins and sometimes C3 olefins. We're taking the existing one to retrofit it such that it could alkylate C5 olefins, and we're building a new C4 olefins. What we're really doing, if you drew a boundary around the Houston refinery, is we're shifting C5 olefins that were going out in cat gasoline, bringing in IC4 from Mont Belvieu, which is readily available and inexpensive. That's really what's happening in making an alkylate and also blending some additional butane for this little RVP. That's really what this project is.
It is different than, I would say, other people that are looking at this, and we're clearly ahead of everybody else in the industry with this project.
Okay. Yeah, that makes sense. I think it's been evaluated for quite a while, so it's clear that there's a lot of thought into the process. This next one's sort of a moonshot. As you know, it's been reported Aramco is maybe looking to monetize some assets. You might also know that Shell has a fairly aggressive divestment target, too. I don't know. Is it fair to say that Motiva today is at least as attractive or as sensible of a consolidation candidate as maybe Citgo was two years ago in terms of what's out there to bring into the fold to the extent that, I think Mike kind of alluded to, the appetite hasn't changed, but I don't know, maybe availability of assets has?
Well, Sam, that is a moonshot. Motiva has a good business, and they've got good assets. If they were for sale, I suspect that we'd take a really good hard look at them. We're not hearing anything. I haven't heard anything that they're in the market.
All right. Appreciate it. Have a good one.
You bet. Take care.
Phil Gresh from JPMorgan, your line is now open.
Hey, good morning.
Hi, Phil.
First question, just on VLP. How are you thinking about the drop-down potential to VLP this year? Last year, I think you had committed to $1 billion in drops, you didn't give any specific commentary on the release. Just curious how you're thinking about the MLP market more broadly, valuation impacts, et cetera.
Okay. Yeah, Phil, right now, $1 billion is our current plan for the drop-down. The capital markets are pretty challenging right now, we'll just have to continue to monitor this as we move through the year.
Okay. Second question is just there's been some talk about the uplift we could see from greater utilization rates from these Chinese teapot refineries and the impact it could have on product exports out of China. I'm just wondering how you're thinking about this risk, do you think China's product quality can compete on the global market, especially on the gasoline side?
Phil, this is Gary. I don't know that I can really comment on the quality of their products. Overall, to me, that capacity is capacity that's going to be very challenged globally because of the weak fuel oil markets. It's going to be very difficult to run low-complexity capacity with a very low fuel oil environment.
Okay. Thank you.
Ryan Todd from Deutsche Bank, your line is now open.
Great. Thanks. Good morning, gentlemen. Maybe you said all you wanted to say on it, but maybe a quick follow-up on the prior question on potential drops to VLP. Any thoughts as to what the mix might look like between cash proceeds and equity to Valero, or any thoughts on the evolution of multiples of those drops, or too much uncertainty in the market at this point?
Well, there's quite a bit of uncertainty in the market. At this point in time, I really can't comment on how the cash proceeds would be and how the financing of those drops would be structured.
Okay. Maybe one follow-up. We appreciate the comments that you made earlier in terms of some of your thoughts on medium sour and heavy sour differentials and the sustainability going forward. Maybe, can you give any thoughts in terms of how you see light sweet diffs, whether it's Brent-WTI or LLS-WTI evolving over the next 3 to 6 months? Are we going to need to see a widening of those spreads in order to clear a cushion and disincentivize imports? In particular, I was kind of curious, given the fact that you backed out 400,000 barrels a day of lower 48 light sweet through your system, just generally what your outlook is for those light sweet differentials going forward over the course of this year?
Yeah, this is Gary. I think, over time, LLS and Brent trade at pretty close to parity. I think we're going to have a lot of volatility between the grades as the year goes on. You can see we would have to pay a premium for LLS over Brent. We started importing foreign light sweets. You have inventory gains here in the U.S., which I think tells you LLS was too expensive. LLS will be discounted. I think we'll go through that volatility for the next 6 months, where we swing in and out of domestic light sweet production into our refining system.
Great. Thanks. I appreciate the help.
You're right.
Doug Leggate from Bank of America Merrill Lynch, your line is now open.
Hey, thanks. Good morning, everybody.
Morning, Doug.
Thanks, Joe. Joe, I wanted to go back to your comment about gasoline. I think you said you were in max gasoline mode right now. What I'm trying to understand is what happens to gasoline yields as the U.S. kind of swings back to imports and light sweet crude declines. I know everyone's focused on octane, but I'm just wondering if we start to see a tightening of the balance. You're in max gasoline mode at this point, I'm guessing that's because distillate is so weak. I'm just trying to understand the interplay as you see things going into the summer. I guess I'm really looking to your prognosis on how those things balance out.
Okay. Gary, do you want to go ahead?
Yeah. Overall, if you look at a foreign light sweet barrel versus an Eagle Ford or a Bakken-type barrel, the naphtha yield from a West African Saharan barrel is about the same as Bakken or Eagle Ford. In terms of refining yields, it's not significantly different whether we're running that West African barrel or we're running a domestic light sweet barrel.
As you swing by towards medium heavy, there's a yield mix change then?
Yeah. For a medium heavy barrel, it would, except for most of the refineries we're running those barrels are very high complexity refining assets. Again, we don't see much of a yield difference with the complexity of our refineries when we're running a heavier diet. The only thing that we can get into is, as we go heavy at some of our plants, it can lower our utilization some. We get a lever effect by running light sweet at some of our refineries. If we have a big incentive to run much heavier crude diet, it can mean that we're running slightly lower crude rates at some of those plants.
Kind of back to the old school, I guess. Thanks for that. My follow-up is probably more a Ciskowski question. Mike, the tax rate looks like it's been consistently low now. It's becoming a kind of a regular thing. Should we be looking at tax rate guidance moving lower as like a permanent shift?
Well, we had a couple of unique items this past quarter. Because of the tax law, they got final approval in the U.K., and then we have some audits that are underway in the U.S., and we happened to get those settled this quarter. That was reflected, which pushed the rate down to 28%. We try to do the best that we can in giving that guidance to you. The 31%-32% is what I would say for the first quarter.
Is that a good run rate going forward, Mike?
Yeah, right now, that would be.
Okay. Helpful. Thanks, everybody.
Sure, Doug.
Our next question comes from Chi Chow from Tudor, Pickering, Holt & Co. Your line is open.
Great. Thank you.
Great. Chi.
Hey, how you doing, Joe? Close enough, I guess. Hey, back on the products markets, can you comment on how you're assessing the supply-demand balance of the global distillate market heading into this year? We saw a material weakening of the diesel cracks as the year progressed last year. I'm just wondering on your thoughts on the cause of this.
Chi, this is Gary Simmons. Overall, I think, if you look at what drives distillate demand, it's weather, and then it's economic activity. Thus far, both in the U.S. and in Northwest Europe, we've had warmer winters than what we've historically had. It's led to lower distillate demand. In terms of how do we correct from here, I think a lot of that correction gets back to some of this low complexity refining capacity. With discounted fuel pricing, I think we'll see some economic run cuts on some of that low complexity capacity that'll bring the distillate markets back into balance.
What about the economic activity side of things? You mentioned your exports are still pretty good, but are you concerned about global slowdown?
On the economic front.
I don't know that I can really comment on the global economic activity, but I can say we continue to see very robust demand for our products throughout the globe.
What were your exports of gasoline and diesel in the quarter?
Yeah. Gasoline, we did 157,000 barrels a day of gasoline. We did 264,000 barrels a day of diesel. If you add kerosene in with that, it would be 307,000 barrels a day of total distillate.
Okay. Thanks, Gary. One other question. This is just specific to your Gulf Coast system. We just noticed that your realized margin capture rate versus your index is always better in the fourth quarter in the Gulf Coast than the other three quarters of the year, and that's been pretty consistent in the last, I don't know, four years running. Why is that the case? Is there any specific reason for that?
Well, I would say, certainly, butane blending would come into play there. As butane has been discounted, and we're able to blend it into the pool, it helps our capture rates. I don't know if you have anything else.
Hey, this is Lane. I'd only add, normally, seasonally, what you see is medium and heavy sour discounts widen out. When you're using sort of the standard capture rates versus lights, we always outperform on that as well.
Okay. All right. Thanks, Lane. Appreciate it.
Our next question comes from Faisel Khan from Citigroup. Your line is open.
Good morning, guys.
Morning.
A quick question. On the timing of the projects that came online in the fourth quarter, so the Corpus Christi crude unit, the hydrocracker, and the expansion of the Alky, and also Line 9B, you already highlighted that was a December startup. How did those start up in the quarter? I'm trying to understand what the contribution was from the commissioning of these assets in the quarter, just so we get the uplift going into 2016.
This is Lane. The Alky, we finished that project, which took us about two years to fully implement the entire scope of that, which was two things. One was it was an energy efficiency project and distillate recovery, and the second was plus crude rate, and we finished it in October. I assume that's what you're after. You're after the timing piece.
Yes.
In Port Arthur, again, the hydrocracker was down in October. There we replaced the catalyst and did the expansion. Corpus Christi really started up during early to mid-December, so you wouldn't have seen anything with respect to fourth quarter improvement. That's really going to be entirely a 2016 thing.
Okay, got you. McKee, we would've seen a full contribution in the quarter, but it sounds like Port Arthur was down in October. Of course, nothing from the Corpus.
Yeah. That's right. Nothing from Corpus, obviously St. Charles we're doing right now.
Okay. Right now, given where crude prices are in Canada versus the Atlantic Basin, does it make sense to max out Line 9B, or where are we with the market in terms of how we would benefit from that?
Yeah. I would say on Line 9B, we're seeing some value in the Bakken that we're running. Most of the Western Canadian light sweets, we're not seeing a material difference in being or uplift in running those barrels compared to foreign light sweets that we could import into Quebec.
Got it. Okay, great. Thanks for the time, guys. Appreciate it.
Our next question comes from Vikas Dwivedi from Macquarie Group. Your line is open.
Hey. Hey, guys. Quick question on gasoline and ethanol. They've been inverted for a while. Does that change how you guys blend or any of the approach to the overall gasoline operation given sort of upside-down from normal?
You want to take it, Martin?
This is Martin Parrish. Well, it's really the impact on the blending margin, not on the refiner's margin. Ethanol is selling at about its blend value. Everything's kind of at blend value to tie octane. You have to remember that the blender still gets the RIN if they choose to blend ethanol. It kind of works out. I would say there's really no impact. We got to blend it.
Got it. Coming back to the Alky plant, is the C5 technology, is that also a call on kind of an oversupplied ethane or ethylene market down the road?
It's not a call. It's just really, you look at the whole NGL market, it's been long. It's really a view that we can take and move NGLs into the gasoline pool, and we can do it by alkylating amylenes in the refinery, which is a little bit different, and it makes a good high octane, low RVP component, which then in turn allows us to blend additional butane in the summer in particular.
Got it. We were just thinking if it was a call, it would be a great call. I think we're going to be drowning in the lighter end of the NGL barrel for a long time. That's for sure.
I wouldn't tie it to ethane. It's the whole NGL space, which we believe is really long going forward, too.
Yep. All right. Thank you, guys.
We have a question from Brad Heffern from RBC Capital Markets. Your line is open.
Morning, everyone.
Morning.
Circling back to VLP, I'm just curious, we all know the uncertainty and the turmoil in the capital markets, but it seems like the strategy is basically unchanged. You have 55% of the growth in 2016 in terms of budget going into VLP. At what point do you think about that, and maybe reexamine the pace of growth given that the market doesn't necessarily seem to be rewarding growth as much as it once was?
You want this?
Yeah. Right now our plan is to do the $1 billion, we'll continue to examine and monitor the markets as we move through the year. It is very challenging right now. We do have our revolver that we could use as a financing source for some of the drops. The bank market seems to be a little bit more attractive than the capital markets at this point in time.
Brad Heffern, let me just add to what Mike said, though. The capital that we're investing in logistics assets at Valero Energy are assets that can be dropped to VLP. We'll continue to build the droppable EBITDA base. We've shared this before, the motivation behind Valero investing in logistics assets are projects that benefit Valero's core business, its core refining business. They're projects that help us optimize our operations. We're not taking flyers on projects that we wouldn't be willing to commit contractually long-term to. Again, the things that we're investing in today, for example, the Diamond Pipeline, that is going to be a direct benefit to the Memphis refinery and provide crude optionality there that they don't currently have today.
This is a long game, and even though markets are challenged right now, I don't think we should sit here and throw the baby out with the bathwater and totally redirect strategies to try to accommodate it. The other thing that Mike hasn't mentioned is that VLP is in a great position. They got very high coverage ratios to maintain distribution growth at the targets we've talked about, is not going to be an issue. Here again, we're running the business to continue to improve the business and drive EPS growth at VLO, and VLP is going to go along for the ride. Anyway, that's just a little more color.
Thanks for that, Joe Gorder. I think that's clear. Then, thinking about logistics opportunities as well, I'm curious. Obviously the lifting of the crude export ban is seen as a negative for refiners in general, but I would think there might be some opportunities that present themselves to Valero, given the amount of dock space and general footprint in the Gulf Coast. Have you thought along those lines yet?
Well, this is Rich Lashway. Yes, we've thought about that opportunity. We're in conversations with a lot of different parties on projects that they have that they're willing to share now that they might not have been in the past. We do see quite a bit of opportunity out there given not just the decline in crude prices, but also the export opportunity.
Okay. Thank you.
Thanks.
Our last question is a follow-up question from Paul Cheng from Barclays. Your line is open.
Hey, guys. Real quick. Maybe this is for Gary. Gary, just curious, the crude inventory build over the last several weeks, quite substantial. Do you have any rough idea what's the split between if the financial buyer buying it to take advantage on the contango curve or what % is the operator actually the refiner that who are building inventory here?
Yeah, I don't suspect it's a lot of refiners building inventory. Most of our tankage and most refiners' tankage is more operational in nature, and so it's hard to really utilize that tankage for a contango play. Most of that, you see some inventory builds in Cushing. I don't know that I really could comment in terms of the build. I think what we had happen is LLS got at a premium to a foreign light sweet alternative, and Valero, along with many other refiners, started buying light sweet. It caused the inventory to build, and certainly the market structures incentivize people to store as well.
Okay. Thank you.
Okay. Yolanda, I think that is the last of the questions. We want to thank everyone for calling in today. Please feel free to call me and Karen if you guys have further follow-up questions. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.