© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, ladies and gentlemen. Welcome to the Valero Energy Corporation’s Fourth Quarter 2018 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, there will be a question-and-answer session, and instructions will follow at that time. [Operator Instructions] As a reminder, this conference call is being recorded.
I would now like to turn the conference over to Homer Bhullar, Vice President, Investor Relations. Sir, you may begin.
Good morning. And welcome to Valero Energy Corporation's fourth quarter 2018 earnings conference call. With me today are Joe Gorder, our Chairman, President and Chief Executive Officer; Donna Titzman, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President and COO; Jason Fraser, our Executive Vice President and General Counsel, and several other members of Valero's senior management team.
If you've 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’s 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.
Now, I will turn the call over to Joe for opening remarks.
Thanks, Homer, and good morning, everyone.
We're pleased to report that we completed another good quarter where we ran our business well and delivered solid financial results. Throughout the quarter, we maintained our unrelenting focus on operations excellence, which enabled us to operate safely and reliably in an environmentally responsible manner. We also delivered on our commitment to invest in growth projects and acquisitions that increased Valero's earnings capability while maintaining solid returns to our stockholders.
In 2018, we matched 2017 record for process safety performance, and we continue to outperform the industry on our personal injury rates. Logistics investments we made over the last several years are contributing significantly to earnings. Our investments in Line 9B, the Diamond Pipeline and the Sunrise Pipeline expansion increased our system’s flexibility, allowing us to take advantage of the opportunities available in the fourth quarter of 2018. In fact, we set a record for total light crude runs at 1.5 million barrels per day and a record for North American light crude processed at over 1.3 million barrels per day. We also continued to maximize products exports into higher netback markets in Latin America.
Turning to capital allocation. We continue to execute according to our disciplined framework. Our projects and execution remain on track. Construction is scheduled to finish on the Houston alkylation unit in the second quarter. And the Central Texas pipelines and terminals are expected to be completed in mid-2019.
In November, the Board of Directors of Valero and Darling Ingredients, approved an expansion of the Diamond Green Diesel plant to 675 million gallons per year of renewable diesel production and the construction of a renewable naphtha finishing facility.
With respect to cash returns to stockholders in 2018, we paid out 54% of our annual adjusted net cash provided by operating activities, exceeding our target annual payout range of 40% to 50%. Our solid financial position and a favorable outlook for our business enabled us to further demonstrate our commitment to our investors, as last week, our Board approved a 12.5% increase in the regular quarterly dividend to $0.90 per share or $3.60 annually.
Lastly, earlier in January, we closed the acquisition of Valero Energy Partners. This transaction was immediately accretive and it's greatly simplified our structure. While Valero will no longer have a publicly traded midstream business, VLP’s assets and ongoing logistics investments at Valero will continue to enhance our feedstock and product flexibility.
Now, as we look ahead, we remain committed to our capital allocation framework. There has been no change in our capital discipline strategy, which prioritizes our investment grade ratings, sustaining investments and paying our dividends. We expect our annual CapEx for both 2019 and 2020 to be approximately $2.5 billion, in line with where it's been over the last several years. And you should expect incremental discretionary cash flow to continue to compete with other discretionary uses, including cash returns, growth investments and M&A.
In closing, with a growing economy, a year-over-year increase in vehicle miles traveled, and low fuel prices, we’re encouraged for 2019. We expect good demand in domestic and exports markets this year. Despite seasonal weakness in the gasoline market, days of supply for distillate inventories remained below the five-year average. Expected incremental diesel demand and discounts for sour feedstocks associated with the impending global fuel oil sulfur reduction also give us a reason to remain optimistic.
We believe that our system’s flexibility to process a wide range of feedstocks and reliably supply quality fuels as evidenced by our fourth quarter 2018 results, positions Valero well for whatever opportunity the market presents to us.
So, with that, Homer, I'll hand the call back to you.
Thank you, Joe.
For the fourth quarter, net income attributable to Valero stockholders was $952 million or $2.24 per share compared to $2.4 billion or $5.42 per share in the fourth quarter of 2017. Fourth quarter 2018 adjusted net income attributable to Valero stockholders was $900 million or $2.12 per share, compared to $509 million for $1.16 per share for the fourth quarter of 2017.
For 2018, net income attributable to Valero stockholders was $3.1 billion or $7.29 per share, compared to $4.1 billion or $9.16 per share in 2017. 2018 adjusted net income attributable to Valero stockholders was $3.2 billion or $7.37 per share, compared to $2.2 billion or $4.96 per share in 2017.
The 2018 adjusted results exclude several items reflected in the financial tables that accompany this release, while the 2017 adjusted results exclude an income tax benefit of $1.9 billion from the Tax Cuts and Jobs Act. For reconciliations of actual to adjust amounts, please refer to those financial tables.
Operating income for the refining segment in the fourth quarter of 2018 was $1.5 billion, compared to $971 million for the fourth quarter of 2017. The increase from 2017 was mainly attributed to wider discounts for North American sweet crude and certain sour crudes relative to Brent, partly offset by weaker gasoline margins.
Refining throughput volumes averaged 3 million barrels per day, which was in line with the fourth quarter of 2017. Throughput capacity utilization was 96% in the fourth quarter of 2018. Refining cash operating expenses of $3.92 per barrel were $0.34 per barrel higher than the fourth quarter of 2017, mostly due to higher natural gas costs in the fourth quarter of 2018.
The ethanol segment generated $27 million operating loss in the fourth quarter of 2018, compared to $37 million of operating income in the fourth quarter of 2017. The decrease from 2017 was primarily due to lower margins, resulting from lower ethanol prices.
Operating income for the VLP segment in the fourth quarter of 2018 was $88 million, compared to $80 million in the fourth quarter of 2017. The increase from 2017 was mainly due to contributions from the Port Arthur terminal assets and Parkway Pipeline, which were acquired in November 2017.
For the fourth quarter of 2018, general and administrative expenses were $230 million and net interest expense was $114 million. General and administrative expenses for 2018 of $925 million were higher than 2017, mainly due to adjustments to our environmental liabilities.
For the fourth quarter of 2018, depreciation and amortization expense was $531 million. And income tax expense, which includes certain income tax benefits, as reflected in the accompanying earnings release tables, was $205 million. Excluding these benefits, the effective tax rate was 21%. With respect to our balance sheet at quarter-end, total debt was $9.1 billion, and cash and cash equivalents was $3 billion. Valero’s debt to capitalization ratio net of $2 billion in cash was 24%
At the end of December, we had $4.4 billion of available liquidity, excluding cash. We generated $1.7 billion of net cash from operating activities in the fourth quarter. Excluding the unfavorable impact from a working capital decrease of approximately $120 million, net cash generated was $1.8 billion.
With regard to investing activities, we made $771 million of growth and sustaining capital investments in the fourth quarter of 2018, of which $254 million was for turnarounds and catalyst. For 2018, we invested $2.7 billion of which approximately $1.9 billion was for sustaining and $800 million was for growth.
Moving to financing activities. We returned $965 million to our stockholders in the fourth quarter, $627 million was for the purchase of 7.7 million shares of Valero common stock and $338 million was paid as dividends. As of December 31st, we had approximately $2.2 billion of share repurchase authorization remaining.
We expect capital investments for 2019 to be approximately $2.5 billion, with approximately 60% allocated to sustaining the business and approximately 40% to growth. Included in the total, our turnarounds, catalyst and joint venture investments.
For modeling our first quarter operations, we expect throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.67 million to 1.72 million barrels per day; U.S. Mid-Continent at 440,000 to 460,000 barrels per day; U.S. West Coast at 265,000 to 285,000 barrels per day; and North Atlantic at 475,000 to 495,000 barrels per day.
We expect refining cash operating expenses in the first quarter to be approximately $4.05 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 $0.42 per gallon, which includes $0.06 for gallon for noncash costs, such as depreciation and amortization.
For 2019, we expect G&A expenses excluding corporate depreciation to be approximately $840 million. The annual effective tax rate is estimated at 23%. For the first quarter, net interest expense should be about $110 million, and total depreciation and amortization expense should be approximately $550 million.
Lastly, we expect RIN’s expense for the year to be between $400 million and $500 million.
That concludes our opening remarks. 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. If you have more than two questions, please rejoin the queue as time permits. This helps us ensure other callers have time to ask their questions.
Thank you. [Operator Instructions] Our first question comes from Blake Fernandez with Simmons Energy. Your line is open.
Good morning, guys. Congrats on the stellar results. I appreciate the outlook for two years on CapEx. I think, there was some perception maybe with the project sanction last year that there would be upward pressure, and we're actually seeing a $200 million decrease year-over-year, and that sustained into 2020. Can you talk a little bit about where maybe some of that defilation has coming from, whether it's the growth component or sustaining or turnarounds?
This is Lane. I wouldn't call it deflation, I would call that we had a -- we had a lot of sustaining capital with respect to Tier 3 and plus the reliability project at our Corpus Christi refinery in 2018. Our run rate is like what we've said is normally about $1.5 billion to sustain our assets. We had a little bit more than that in this past year. And there's obviously timing involved and all that. Whether our turnarounds get a little bit lumpy or again we end up having to do something a little bit special on some environmental, currently we don't have anything on our forward view of that.
Okay, great. The second question is on Venezuela, obviously very topical. I guess, one, could you confirm how much you're currently importing crude there? But then, I guess more importantly, I’m just curious, in order to replace those barrels, are you looking to resort to more light sweet domestic crudes or just largely maxed out on light sweet to where you're actually going to have to resort to the global market for kind of medium and heavy sour replacement barrels? Thanks.
Yes. Blake, this is Gary. Of course, with the sanctions, we're currently not taking anything from Venezuela. But, it was about 20% of our heavy sour that we run was Venezuelan barrels historically. We're certainly hopeful that we’ll see proper resolution to the crisis, not only for the benefit of the crude markets but for the welfare of the people of Venezuela. We've seen production decline in Venezuela for years, and we've also known there was a threat of sanctions. So, we’ve put alternatives in place to be prepared for this. Of course, the announcement was just made Monday; we've only had 48 hours to respond.
Our top priority really has been to get to next 30-day supply plan covered. And I can tell you we're in a lot better position today than we were on Tuesday, but we still have some holes to fill in our supply plan. We really run Venezuelan barrels at two of our refineries in the Gulf, St. Charles and Port Arthur. The St. Charles refinery did begin a turnaround on their crude and coker unit. So, that definitely minimizes the impacts that the sanctions had on our system.
To your point, current economics are certainly pushing us to maximize light sweet in the system.
Our next question comes from Doug Terreson with Evercore. Your line is open.
I wanted to see if we could get some elaboration on Joe's points that you made a few minutes ago about market fundamental. And typically while distillate demand and inventories appear to be positive in both the U.S. and the Atlantic Basin, the converse seems true for gasoline, although seasonality and net exports should be supportive. And then, also, could you just spend a minute covering how fuel oil markets are likely to sort out this year, given the uncertainty that Blake just highlighted about Canada and Venezuela and heavy feedstocks and how you might adjust?
Yes. This is Gary again. Of course, it seems like early in the year, during this call, we always are kind of panic on the gasoline markets. We feel very good about gasoline demand moving forward. high employment and low gasoline prices should result in good gasoline demand. The wild card of course becomes refinery utilization. So, with the 20-year high refinery utilization we saw last year, we are starting the year with a bit of an overhanging. The overhanging gasoline has primarily been PADD 1, PADD 2 and PADD 3.
If I look at those regions individually, I could see that we build a little bit more inventory in PADD 1. The market structure is such that there's an economic incentive to make summer grade gasoline and put it in tankage in New York Harbor, and they're still tankage available. So, that would come. You could some inventory again in PADD 1. I think you'll see some significant improvements in both PADD 2 and PADD 3 moving forward.
PADD 2, I think, a lot of the gasoline build was a result of the crude discount. The margins were just very strong. So, typically at PADD 2, you see refinery utilization drop off in the winter to balance the market. But with the crude discounts where, they ran hard. But if I look at the PADD 2 market now, there looks to be more planned maintenance this year than was last year. As we move forward and then currently with the cold snap hitting PADD 2, there seems to be quite a few refinery issues in that region. In fact, the Explorer Pipeline between group 3 and Chicago is now pro-rated, indicating there's a big pull for products in that region.
So, I think you'll see gasoline inventories draw in PADD 2. And I also think you'll see some good gasoline draws in PADD 3 as well. Then, the Gulf, early in the year, we typically have fog issues which hinder our ability to export product, and we saw that again this year. We also saw a bottleneck trying to get gasoline into Mexico, which is obviously our largest export destination. And then, we saw a lot of refiner buying interest in the Gulf as well as people build some inventory in preparation for turnaround, so they could cover their supply during their outages.
So, I think, all those things, as you see lower utilization in the Gulf as a result of planned maintenance beginning and you see exports pick up, I'm confident you'll see inventories in PADD 3 grow as well. So, I think we feel pretty good about gasoline. We feel very good about gasoline demand. And again, the wildcard is what utilization is going to be going forward.
Okay. Any insight on fuel oil too?
Yes, fuel oil. I think, it definitely is the issue you talk about. There has been a lot of significant hits to fuel on the supply side with OPEC cuts and the Iranian sanctions, now Venezuelan sanctions and production cuts in Western Canada. If you look at the forward curve on fuel oil, it's backward about $1 a month, and a lot of that is tied to the IMO 2020 fuel spec change. We do see fuel moving weaker as a result of lower demand for high sulfur fuel oil. And then, there's some signs that some of the production can be coming on. The Alberta government did announce that they're going to go ahead and raise production in February, at least 75,000 barrels day. So, some of those things will help as well.
Our next question comes from Paul Cheng with Barclays. Your line is open.
Hi. Good morning, guys. Before I ask my question, since that I told John Locke, if your Gulf Coast realized margin is going to be filed probably in excess of 650, I will publicly lobby Joe you to give Gary and his crude supply team a big bonus. So, I'm lobbying you.
Paul, you're really helpful to me here.
Anyway. So, other than that, two questions. First, looking at the current level in the fourth quarter, I mean, I think everyone is already trying to maximize on the distillate yield. So, in your system, is there any more that you can actually do that to shift from gasoline to distillate. And also, you said you're running a record 1.5 million barrels per day in the light oil. Is there any more that you can -- can you quantify that, how much more if there's any that you can actually move from medium and heavy into light?
Yes. So, I would tell you on the gasoline to distillate swing, there's very little else we can do. We're pretty much maxed out on distillate today. On light crude, we would tell you that the numbers Joe gave you that was about 90% of our light sweet capacity. And so, there is some room there to push some additional light sweet crude into our system.
So, Gary, you mean that if 90%, that means that at most you can push another 100,000, 150,000 barrel per day?
Exactly. So, we've been saying we have about 1.6 million barrels a day of light sweet crude capacity.
Secondly that do you expect the Mexico export that you're shipping there that you expect to increase in the coming weeks, given the fuel shortage there? If we look back in the last two months, have you seen any noticeable decline in your gasoline export to Mexico?
No, we really haven't. Historically, we see a lot of buying interest in December from Mexico and we see these bottlenecks then trying to get the barrels into the country. And obviously, the crackdown on fuels made that even worse. We're seeing good demand from Mexico, not only waterborne barrels, but we continue to ramp up our business of actually importing the barrels into the country and we're seeing very good demand for barrels delivered all the way in the country as well.
Our next question comes from Manav Gupta with Credit Suisse. Your line is open.
Joe, congrats on a good quarter. And Homer, congrats on joining a great team. We will all miss John Locke and would like to wish him all the best in his new role. So, I just have a quick question on Diamond Green Diesel expansion. Like, if you look at the current margins, is it fair to assume that this is like a 35-plus-percent return for project for you? And the second follow-up on it is, what advantage does Darling Ingredients brings to the table? Are they just a financial partner or they give you some kind of competitive edge on your peers, who are also trying similar projects?
This is Martin. On Diamond Green, we're looking at historically -- we think going forward, we're going to be at about $1.25 a gallon, so doing the math, you’re probably in the right ballpark with that return on EBITDA margins. Now, Darling is not just a financial partner. Darling processes about 10% of the world’s meat byproduct. They also do a significant work on collecting used cooking oil. They've been in these markets for years. Diamond Green, we've been in this fat market for 5 years now, 5.5 years, they've been in for a long time. They bring a lot to the table around sourcing the fat pre-treating the fat for the unit. So, it's a really good synergy here. We've got a refining expertise, we've got expertise in marketing a product, they've got pre-treatment expertise and bringing the fat into the joint venture. So, it's a really good partnership.
Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Your line is open.
Joe, you guys do a great job of making the sell side look really dumb every quarter; it’s a great quarter, obviously. But my question is a $30 correction in oil prices, obviously there's some lag effect in your capture rate. I'm just curious as to the capture rate move that we saw and off of 100% on our numbers is running about 30%, 40% above what you would normally deliver. Was that just lag effect, or is there something structural going on such as the shift to the lighter grades that we should pay more attention to going forward?
Doug, that's a good question.
Why don’t I take a shot at it and Gary for recal -- retune whatever I'm saying here. But there is really a few -- couple of reasons. One is as we alluded to in the opening remarks, we've had the pipeline projects. We have the Line 9 and we had the Diamond Pipeline and the Sunrise. And all of those put up the position in the Mid-Continent and in our Quebec refinery position us to take advantage of essentially the distressed markets in the fourth quarter.
And then, the other side of that is on the product side, really lower rent price, allowed us to capture essentially higher net-backs on our product prices. I'm sure, there's a contribution on the other things, like pet coke, all the stuff to contribute our capture rate. But really, the first two things that really drove our capture rate in the fourth quarter.
So, should we consider that the capture rate is structurally moving higher?
I would say, you should -- on the product side with the lower rent prices, yes. On the crude side, it's just a matter of how distressed those markets are. And you have a line -- you have a view of what [indiscernible] looks like and a view of what Midland looks like and Cushing.
Okay. Thank you for trying to answer that. I know it was tough one. My follow-up is really -- is kind of a follow-up to the Doug Terreson’s question, I guess. Normally, we would see this -- the industry pivot obviously between distillate and gasoline to some extent, as you move through the summer, but obviously we've got this IMO even going into 2020. So, I'm wondering, is there a possibility that we see Valero specifically maintain a max distillate bias through the whole of 2019 as one part of the solution to the gasoline overhang? And I'll leave it there. Thanks.
This is Lane again. We absolutely believe that it’ll be the case. I mean, we've been in max distillate for a while now and will continue to be in that way through the at least the way we see the rest of the year going in 2019. Obviously, it’s early but that's the way the forward market is pointing right now.
Our next question comes from Prashant Rao with Citigroup. Your line is open.
Good morning, guys, and thanks for taking the question. I wanted to circle back to crude sourcing and drill down a little bit, obviously really strong performance there. And as Paul said, it makes us all look we underestimated you this quarter. On the Maya or other Central American heavy sours, I just want to get a confirmation? I mean, lot of those grades have priced themselves out of the market we saw in 4Q. But were you -- what was your purchasing like in for 4Q and is it -- were you not running as much and should -- how should we expect that to look now that we some price normalization as we go forward in 1Q?
So, I think on the heavy side, we've definitely seen that Maya is probably not the best marker for what we're paying for a heavy sour crude. So, in the fourth quarter, if you look Maya was priced at 4.50 discount to Brent. WCS or Western Canadian Select in the U.S. Gulf Coast was trading at a $10.60 discount to Brent. And we believe that the Canadian quote was much more representative of our actual delivered heavy sour into the system. In addition to that, then there were certainly some things with the connect -- disconnect in western Canadian pricing. We had a significant uplift on the crude by rail, we did 43,000 barrels a day of heavy Canadian by rail in Port Arthur, and those were very discounted barrels.
Okay, thanks. And I guess that sort of leads nicely to my second question. My follow-up is on the Canadian barrels. It year-to-date seems like the import data and purchasing data, what we've heard the market is -- you continue to be able to get good access to those Canadian barrels. Just wondering if you could give some color on the sourcing, especially given that we've had production cuts up in Canada with the dynamics of those barrels also coming in by rail, or are there more available in the market, just any color on how we should think about the variety of sourcing there?
Yes. So, in the fourth quarter, we also set a record on the volume of Canadian heavy that we ran in our system. We ran over 180,000 barrels a day of heavy Canadian. And it is sourced via pipe, delivered into the Gulf, and then we do about 40,000 barrels a day crude by rail. Our view is that crude by rail will be necessary until one of the major pipeline projects gets approved out of western Canada.
Thank you. Our next question comes from Roger Read with Wells Fargo. Your line is open.
I guess, maybe to dig in a little deeper, thinking about the summer time here with gasoline. So, you're running max distillate, presumably most if not all the industry is doing the same. So, if we see, relatively speaking, weaker gasoline cracks this summer, does that imply that to get things in balance effectively, the industry has to employ run cuts or should we think about additional toggles you can do, if you ended up with a summertime situation with stronger distillate cracks relative to the gasoline, especially with IMO staring us in the face by the latter part of the summer?
Roger, it’s difficult to answer, certainly thinking of the gasoline situation is a combination of yield, which certainly we expect to be in the max distillate mode. And then, the other thing I’d refer to is just what the utilization rate and the refining capacity is, and whether that 20-year high that we saw last year is sustainable.
Yes. I mean, I would think though with this -- with more light barrels available, there's no reason to think U.S. refines throughout have come off. It’s strictly a margin decision. We heard others companies, other refiners talk about different things you can do in terms of how hard you run your FCC units versus other decisions you can make. I was just curious, if there's anything like that that occurs for IMO as your look at your overall system?
This is Lane. I'll take a stab at that. So, we do -- FCC is obviously a pivotal part of our operation, and there's certain inflection point, economic inflection point. And it almost always makes sense fill our alky. So, we’ll run up to the point to make sure alkylation units are full. And so, the marginal capacity we're always looking is to make sense to run-pass that point. And to your point, interestingly enough, the stream that we put in these out also can go into the fuel market for the halfway percent to meet the IMO reg. So, we do think structurally at least one of the things that will happen here is that FCC probably won’t run a whole lot pass, drilling their alky, it’s certainly in the context of how IMO 2020 is going to work out.
And then, Joe, you’ve done a great job over the years here in terms of capital allocation. The decision to roll up VLP kind of brings the balance sheet more into like the true issue on cash and that as opposed to the non-recourse side. I was wondering, as you think about future capital allocation, is there anything you want to do on the balance sheet? Is there a goal to reduce debt here or maybe to increase kind of future flexibility, if you were to pursue anything on the acquisition front?
Roger, that's a good question. I would say generally, there isn't anything that we're expecting to change. We set the target within the capital allocation framework debt-to-cap of 20% to 30% range. Donna has got kind of a minimum cash balance target $2 billion, things like that. Those are just things that we operate with is fundamental assumption day in and day out as we go forward. We get asked periodically about, somebody raised the issue about the sustainability of the dividend. And, that's a really interesting question to come up at this point in time. Because in October, we were all being asked what we were going to do with all the cash that IMO 2020 was going to provide.
So, that being said, I think when I look at Valero, I realize that we understand our business and we're making decisions for the long-term based on our strategic view of the market and not hype. And so, we always try to position ourselves financially to be able to deal with whatever the market might be giving us.
So, if we think in terms of dividend, for example, I can just say without reservation that we consider a sustaining CapEx and the dividend to be totally non-discretionary, and we're going to defend them as we allocate cash. We got a really strong balance sheet, and we certainly wouldn't have raised the dividend if we thought sustainably was any kind of issue there. And really, that's it around that.
From an acquisition perspective, we'll continue to review them in the context of growth projects. And, when you think in terms of the roll up of VLP, it kind of takes you to the question, well, are you going to continue to invest in logistics projects going forward? And the answer to that would be, yes, to the extent the same benefits Valero's business. And if you recall, even with VLP is a publicly traded entity, we always started with a need at Valero. And then, if we did the project to satisfy that need at VLP and take VLP at 12% rate of return, would it still makes sense for Valero to do the project? Okay. That was kind of the calculus that we went through. And if it was yes, we proceeded.
Now, we just look at these projects as an aggregate project. So, the Diamond Pipeline for example, we have a huge benefit on the crude sourcing in the Memphis as a result of the Diamond Pipeline, and VLP was getting the 12% rate of return. Now, all that's rolled in to one set of economics and we look at it in the context of 25% rates of return on refining projects.
So, the way we structured the framework, it's flexible enough to allow us to adjust a little bit from time to time, but it hasn't fundamentally changed what we're doing and what we're focused on.
So that was a really long answer to a pretty simple question, Roger. So sorry about that.
No, I appreciate that. I just can't believe you accused Wall Street to be in fickle...
Yes. I know it's hard to imagine. Isn’t it?
Absolutely. All right. Thank you.
Thank you.
Our next question comes from Phil Gresh with JP Morgan. Your line is open.
First question, Joe, would be, you talked for a couple of years now about the illustrative EBITDA that you can generate from these projects that you have under way. And, I think in your slides, you talked about $175 million incremental for 2018 from completed projects. So, I'm wondering how you think about that ramp in 2019 and 2020 that we should be thinking about from the projects underway?
Well, we haven't been that explicit in giving EBITDA forecast for ‘19 and ‘20, right? And I don't think we're going to go there. I think, what you've got to rely on really, Phil, is, is the chart we got in the slide deck. And, if you look at our return threshold for our projects, and you say you're going to invest this much strategic capital year-in and year-out, what kind of EBITDA do you expected to produce? And our numbers are $1 billion to $1.4 billion. And that includes the benefit of the coker project, of our ownership interest in DGD, of all the pipeline to terminal projects going on, the alky and so on. And we're still very, very comfortable with those numbers.
And so, in terms of moving the needle from an EBITDA perspective in light of our capital allocation framework and the clear recognition that capital is a finite resource, we're going to invest in it accordingly, and the projects we're targeting are going to produce $1 billion to $1.5 billion of incremental EBITDA.
Okay, fair enough. Second question is just coming back to your comment on the minimum cash balances. If I take your ending 2018, take out $915 million for the VLP volume in the first quarter, I think you're kind of around that $2 billion level. I realize working capital has also been a pretty big headwind in 2018. So, trying to think about that, is there some kind of perhaps reversal that could happen with crude oil prices now going back up? And just generally wondering how you think about that, in the context of the capital return plans and things of that nature?
That's a good questions. Donna, do you want to…?
Sure. So, in regards to the working capital, I mean, yes. So, to the extent prices would go up, you would see a shift in the more positive direction in 2019. A lot of the negative working capital that you saw in 2018 had to do with some timing on the capital wins that were really due in ‘17 that were pushed to 2018. So, that has sort of evened itself out. But certainly, there are some other movements in the working capital in 2018 that could reverse themselves.
And then, just in terms of VLP taking that down to $2 billion cash balance. So, I mean, you’re basically saying that you’re kind of at the levels you want to manage that or is there flexibility around that $2 billion or how do you think about that target?
Clearly, that was a big amount of cash going out in January. But, we're going to continue to make money, generate cash. And so, you should see the cash balance recover. But, again, we're at that $2 billion minimum; we are comfortable here at that level.
Phil, I mean, we’ve said this for years now. We never -- our plan was not to carry $5 billion of cash quarter-to-quarter-to-quarter-to-quarter. And we were just finding ourselves in that situation. And so, there was an intentional plan here to try to tighten this down a little bit. Now, Donna has got our target set. She is the CFO and we're going to try to abide by the target. But, there's no reason for us to sit here with $5 billion of cash on the balance sheet.
Our next question comes from Neil Mehta with Goldman Sachs. Your line is open.
So, Joe, team, I just wanted to start talk a little bit here about IMO 2020. It's funny, we're 40 minutes since the call and it's got a lot less tense than probably six months ago, which is a reflection perhaps of what you've seen in the forward curve where we’ve seen diesel FO; while it's still favorable, has compressed in 2020, 2021. As you look at this dynamic of IMO 2020, has anything changed in the team's mind about the potential upside from it? And just can you talk about how you see it playing itself out through the markets and the sustainability of that tailwind?
Sure, Neil. This is Gary. I don't think our view of what will transpire as a result of IMO 2020 has really changed at all. We still see that you'll see a significant uptick in diesel demand and you'll see weakness in the high sulfur fuel oil markets. The shape of the high sulfur fuel curve is pretty much as we assumed it would be. The starting point is a little higher with high sulfur fuel oil trading 94% of Brent today, but you still see steep backwardation in high sulfur fuel oil curve. I think, the one to us that we keep staring at is the ULSD forward curve really isn't showing any IMO impact at all. And we still believe there will be significant demand increases as a result of IMO and strong diesel cracks as a result of that as you approach that January 2020 date.
I appreciate that. And then, the other follow-up and that will be about good -- is RINs, just your thoughts on that market. Again, it seems like something we haven't paid as much attention to lately, prices have been lower for a period of time here. Is there any risk that you see in the RINs market that could send prices higher, and just your thoughts on how it plays out from here?
Yes. This is Jason. Just from a policy side, we don't see any seismic shift come in. I mean, the EPA has several rule-makings. They’re looking at the E15 waiver for the upcoming summer for the ethanol guys to give more ability to put more in the market, tied with the market reform aspects. Some rules have been hopefully improved the functioning of the RIN market within RFS reset. But, what's happened is those have all gotten stalled out with the government shutdown. So, we don't see any change in course, more just a delay right now, but I don't see any big catalyst to change things.
And then, the small refiner exemption is another piece of this, right? And the EPA followed the rules last year and got a small refiner exemptions where they were appropriate. And that certainly took some of the pressure off the RIN market also. We expect them to continue to follow the rules to comply with the legislation as it's crafted and issue the small refiner exemptions where they are appropriate. And so, Neil, I'm with Jason. I don't see a whole of change in this market going forward.
Thank you. Our next question comes from Paul Sankey with Mizuho. Your line is open.
Joe, this is good result obviously in Q4, but it feels like a tremendous number of things have changed into Q1 equally, so that your comments about gasoline for example. It's not a good time in January to sort of turn bearish. Can you talk a little bit about what the really big earnings impact changes have been? And obviously, I'm thinking about OPEC cuts, Alberta cuts, Venezuela, gasoline markets. It's just a very different environment. How do you expect things to progress in some of those things through 2019, and how different is the environment even in January compared to this very good result in Q4? Thanks.
So, Paul, I mean, that's a very good question. And you hit on the point. I mean, it is a very interesting market because there are so many moving parts right now. But, the thing that we always have to keep in mind is that January always stinks. Gasoline is usually weak at this point in time. If the winter is warm, distillates not too salty. A lot of times, Paul, we've been at your conference in the past in January when everybody wanted to slip their risk because things were so miserable. Right? But the reality is, is that we're managing our business for the long term. And we have been in this for a very long time and we understand the cycles in the business.
And so what do you do? You make adjustments day-in and day-out in your operations to try to deal with this and to be as profitable as possible. I mean, Lane mentioned some of the things we'll do around cash. Gary has changed in the way he's sourcing crude, on a weekly, daily basis to try to get the best net-back that we can in the plant.
The things that we don't change. We don't change our commitment to the things that make Valero really good, which is operating safely, reliably, honoring environmental stewardship, managing our capital appropriately. Those are the things we can control and that we pay a lot of attention to. Day-in and day-out optimization based on certain market conditions, okay, we're all over that too. But, we don't have a crystal ball. And so we just manage the business for the long-term and we do our best. Lane, you or Gary, want to talk any specifics around that?
One thing I would add on Venezuela, Venezuela at some point going to have to put oil on the market, even if these sanctions stay in place. So, there's going to be a balancing time through here where whoever buy any alternatives, they'll build buy Venezuelan oil and oil will come to our market. So, I mean, it will also allow you just sort of in a interim time period here where that's got to play out. And of course, if something changes in Venezuela, then it's just back to status quo. On OPEC, OPEC is clearly going to be looking at trying to set the amount of oil in the market based on what are the markets and what's the structure of the market. And again, as Joe alluded to, every day we wake up and we do -- we optimize our assets around what's available out there. We have a great system better than anyone in the markets to get the most value and understand these markets.
Great. Thanks, guys. And Joe, I greatly appreciate, shot out for our January refining conference. Saying that you are the only major refining out there this year, but do you remember that we've got our -- don't forget we've got our Napa Valley Energy Summit on the 1st and 2nd of April, and you're most welcome to join us in [Multiple speakers]. Apologies for the shameless plug.
Paul, I would expect nothing less. And if you are buying, all I can see, we can make it work.
I appreciate that, guys. Thanks very much indeed.
Thanks, Paul. Take care.
Our next question comes from Brad Heffern with RBC Capital Markets. Your line is open.
Lane, I was just hoping you could sort of expand on the comments that you just made about crude sourcing. I mean, it seems like all the numbers we see on the screen for pretty much anything sour waterborne, it's just not the math that you would normally expect. So, is Mars at minus 2 or Oriente at minus 4? Are those crudes actually pricing their way into the system or is there a chance that in the sort of interim period where the trade routes are sort of getting really drawn that we see cut and runs just because the mediums and the heavies are not competitive?
So, I'll take a shot at it and Gary obviously can tune me. Today, where we are is the most profitable crude that we run is our sweets. And then, it's sort of medium and heavy, you are sort of at parity with one another. And it depends on what part of your refinery is trying to sellout. But on the Mars, like the last barrels we try to run on the system where it's really sweet and they all still have margin, positive margin to an open crude unit. So, it's just really trying to navigate and get the right dive into our assets. In terms of just the way trade routes are deploying. I think, again, as I said, I mean, OPEC cuts, they aren't always going to be cuts. And we got to watch how Venezuela plays out on the sanction side. It's just like what happens when around, same thing. So, these all worked, they're not the permanent trade we pass, but the world rebalances when these things happen.
And then, I was just wondering if you could give any color on your union contracts. Obviously, the steel workers union negotiations going on right now and the contract expires tomorrow. So, I know you guys didn't have any impact four years ago, the last time that we saw this, but just curious if what do you expect this time around.
Sure. So, Shell is really negotiating on behalf of the industry for the pattern bargaining. In terms of Valero, we have two refineries, I think actually tonight at 12 midnight that these contracts expire. And we have two refineries that these contracts will expire that is our Memphis refinery and Port Arthur. We have a tentative agreement with our Memphis refinery right now in terms of just sort of local agreement, pending the sort of the Shell negotiations. And we're still working on our issues at Port Arthur. We don't expect a work stoppage during this whole process, but you just never know. So, we're prepared for that. We have a completely trained temporary workforce to take over the assets in the event that there is a walk out. But, I'm not trying to say we're going have one, but we're certainly prepared for it, as you would expect us to be.
Thank you. Our next question comes from Craig Shere with Tuohy Brothers. Your line is open.
So, picking up on Neil's IMO 2020 question. I just wonder if you could speak to the expanding wastewater regulations that appear to be limiting the option of ship-based scrubbers.
Hi. This is Lane. I think what you're asking about, there are some of these environment -- there are some sort of ports that are saying they're not allowing the discharges. Is that what you are talking about?
Exactly.
Yeah. So, again, that just makes it a little more difficult for the ships to invest in scrubbers. I mean, again the technology takes the SOX out of the air and puts it into the water. And I think some of these local ports are fully aware of that. It's just another headwind in terms of making it more difficult to try to solve this long range problem out of IMO, which is this really heavy bitumen that's historically been burning these ships and there's only a few other pathway to try to get rid of it. And as Gary mentioned, that's where you really see the forward market trying to understand exactly how it's going to happen is that particular strength.
So, would you agree that that's just another data point suggesting a perhaps deeper and more prolonged benefit to the refineries?
Exactly. That's exactly right.
And also, just picking up on Roger's M&A balance sheet question. 2018 was a robust acquisition year. We had the ethanol plants, the Peruvian terminaling and the VLP rollup obviously. Do you think that convergence was just a one-off event or do you see ongoing opportunities that can continue to soak up cash balance?
Craig, I mean, our practice is not to really kind of foretell what we're looking at from a acquisition perspective. But, I can tell you, there is nothing on the radar screen at this point in time. We'll continue to evaluate opportunities as they arise, but we don't have any pressing need to fix our business sort of fill that gap with acquired assets. I can't call it coincidental, because we made the decision to do the acquisitions last year, right? So, it's far from a coincidence. But the facts are we saw some opportunities that we felt satisfied our strategic interest, and that really was to extend our supply chain and to continue to grow one of our businesses, the ethanol business, buying assets that were priced very-attractively in the market. And so, we took advantage of the opportunity. But, I'm going to tell you there -- I would not model for a repeat act in 2019.
So, barring ongoing strong M&A and relatively steady billion dollar growth CapEx, robust margins like we're seeing and the opportunity for IMO 2020, it seems like if anything is going to flex, it's going to be the share buybacks, which we saw in the fourth quarter?
Yes, sir.
Okay, good. Thank you very much.
You bet.
Thank you. Our next question comes from Matthew Blair with Tudor, Pickering, Holt. Your line is open.
Homer, did you say 3.8 on ethanol throughput guidance for Q1? And if so, does that reflect any economic run cuts or maybe a big turnaround or something else going on?
Well, this is Martin Parrish. Yes, we have cut back a little bit or run in all our plants, so we had some cut back a little bit. There's just not much fund in it right now. But, we take a long-term view and we expect things to turn around. Ethanol demand in the U.S. is going to grow marginally, and export demand way up this year, and we expect that to continue, it's more mandates worldwide, and even better than that just blending economics worldwide for ethanol where it's priced. And we just don't think that can stay that way where ethanol prices is cheap. So, that's the plan.
And then, I was also hoping you could talk about Octane in upcoming alky expansion. When we look at Gulf Coast octane spreads coming in around $5 a barrel, a couple of years ago that was more like $10 to $12 a barrel. So, is the alky unit -- what are the economics on today's pricing, and would you expect a widening octane spread going forward?
This is Lane. So, our Houston alky will come on stream in the second quarter. Our FID decision, I think, the EBITDA will come around 105 million or something like that. So, I'd have to go back and look and see where compare now. But, we are still committed with the idea that A, going forward octane is going to be more valuable. There's a couple of reasons for that. One is the auto is going higher octane; and two, you still haven't seen tier 3. All this tier 3 investment get in and sort of potentially pressure the octane. And then, finally, just all this light crude puts a lot in that out there. So, all that put together, essentially, we believe that octane is going to be valuable. Where it is versus our funding decisions, where we just have to check, but we still feel like it's a good project. And the same true for our St. Charles, Alkylation project.
Our next question comes from Craig Weiland with US Capital Advisors. Your line is open.
Yes. Hi. Good morning, and thank you for fitting my question, and congrats on the great quarter. You have about a quarter of your Gulf Coast refining capacity located in Eastern Louisiana. And it looks like probably bridge is about to start up here, start delivering barrels into St. James at some point, maybe this quarter, also a slew of other proposed projects that have been introduced in recent weeks and months, designed to move crude into that market over the next couple of years. So, I'm curious, if you could elaborate on how you think Valero's crude procurement options will develop on the back of these projects and what type of impact they could have on your Gulf Coast feedstocks. I appreciate any color you can share.
Yes. I think, the biggest thing for us in the eastern Gulf is St. Charles is obviously a heavy sour refinery, and getting better access to heavy Canadian crude would be a big advantage for us there. And so, we're certainly looking at some of the projects that are out there, namely the Capline reversal has a potential to be able to get more cost effective heavy sour crude in to St. Charles is a big benefit to our system.
Thank you. Our next question comes from Jason Gabelman with Cowen. Your line is open.
Hey, guys. Congrats on the quarter. Just a couple of questions. A follow-up on the comments about running the FCCs, just to maximize alky production. The inputs into the FCCs, are those able to be blended into the marine fuel pool, or is there from a technical standpoint, an issue with meeting marine fuel specs, if you try to blend that backing gas oil into the marine pool?
Hey, Jason. This is Lane. So, yes, the fees, particularly the marginal fee which is low sulfur VGO into these FCCs will fit into the half-a-way percent fuel oil market.
Okay, great. And there's not an issue with any of the other specs outside of meeting the sulfur spec?
We've done a lot of work in terms of blends, making sure that there's some compatibility. There is not -- the spec for is not that rigorous. It really ends up being -- there's just sulfur spec. So, really what you really got to be careful of is for something that you do to the blend that creates compatibility. I'm pretty confident, ultimately, industry will work through all that. It's not to say that really on there won't be some of those issues. We've worked with some of these people to try to work on our own blends around that. So, that's really the only issue this potentially could have.
And just looking more near term, obviously 4Q benefited from some better capture than anticipated and trying to figure out if that could continue into the first quarter. One area I think where there could be some upside is on the butane blending. It looks like butane prices have fallen pretty hard against where gasoline prices are. Do you expect that to support capture rates in the first quarter relative to its support in prior first quarters?
Yes. We see the spread. But, it's not a real meaningful contribution to our overall earnings for the quarter.
Thank you. This concludes the question-and-answer session. I would like to turn the call back over to Homer Bhullar for closing remarks.
Thanks, Shannon. We appreciate everyone joining us. Please feel free to contact the IR team, if you have any additional questions. Thank you.
Ladies and gentlemen, this concludes today's conference. Thank you for your participation. Have a wonderful day.