Welcome to the Valero Energy Corporation Announces Fourth Quarter 2014 Earnings Results Conference Call. My name is Hilda, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Mr. John Locke. Mr. Locke, you may begin.
Thank you, Hilda, and good morning, and welcome to Valero Energy Corporation's fourth quarter 2014 earnings conference call. With me today are Joe Gorder, our Chairman and CEO; Michael 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. Now, I will turn the call over to Joe for an update on company operations and strategy.
Well, thanks very much, John, and good morning, everyone. Well, as John will cover in more detail momentarily, we did have a great fourth quarter and a great year. What I'd like to do is spend a few minutes discussing our key strategies and highlight a few of our accomplishments in the quarter. As you've seen from our recent disclosure, our strategies are focused on operations excellence, returning capital to stockholders, maintaining disciplined capital investments, and unlocking asset value. Operations excellence continues to be important to us. Our team understands that reliability drives safe and profitable operations, so we are relentlessly committed here. An example of this can be seen at our Meraux refinery, where we completed our reliability improvement program and the hydrocracker revamp project. We expect the investments we've made here to improve the refinery's reliability and performance. Disciplined capital allocation is another key focus for us.
Last week, we increased our regular cash quarterly dividend by 45% to $0.40 per share or $1.60 annualized. This increase demonstrates our belief in Valero's earnings power and our commitment to returning cash to stockholders. Regarding capital investments, we completed our 2014 capital program under budget, as noted in the release. This resulted from the rigor and discipline that Lane and his team applied to spending throughout Valero's gated project management process. We are committed to applying the same rigor to future investments. The majority of our growth investments for 2015 and 2016 are allocated to logistics and to increasing our capability to access and process advantage crudes through our flexible refining system. We expect the majority of the logistics investments to be eligible for future drops to Valero Energy Partners, which is our sponsored master limited partnership.
On the topic of VLP, we are committed to its growth and unlocking value. As we noted in the release, we are targeting approximately $1 billion of drops into VLP in 2015. At that level of growth, we also expect VLP's distribution to exceed the 50% tier for our general partner in incentive distribution rights by the end of this year. We are continuing to evaluate and structure new potential earning streams that can be dropped to VLP, and those represent incremental growth opportunities. We understand the MLP landscape has changed since our IPO, and we are committed to unlocking value. In summary, we are focused on operational excellence, disciplined capital allocation, and value creation. Our team remains committed to high performance and achievement. With that, John, I will go ahead and turn it over to you to cover the results.
Thank you, Joe. As shown in our earnings release, we had another strong quarter. We reported fourth quarter 2014 earnings from continuing operations of $1.2 billion, or $2.22 per share. Adjusting for special items described on page seven of the financial tables that accompany our release, we earned $952 million, or $1.83 per share, which compares to $963 million, or $1.78 per share in the fourth quarter of 2013. For the full year 2014, we reported earnings from continuing operations of $3.7 billion, or $6.97 per share. Adjusting for special items, we earned $3.5 billion, or $6.68 per share in 2014, versus $2.4 billion or $4.41 per share in 2013. The refining segment reported fourth quarter 2014 operating income of $1.9 billion versus $1.5 billion in the fourth quarter of 2013. Nearly all of the $377 million increase in operating income resulted from the previously noted special items.
Excluding the special items, operating income was flat in the fourth quarter of 2014 versus the fourth quarter of 2013, as stronger gasoline, distillate, and other product margins relative to Brent crude oil, as well as higher refining throughput volumes were offset. And sour crude oils relative to Brent crude oil. Refining throughput volumes averaged 2.8 million barrels per day in the fourth quarter of 2014, which is an increase of 41,000 barrels per day versus the fourth quarter of 2013. Refining cash operating expenses in the fourth quarter of 2014 were $3.76 per barrel, which is $0.03 per barrel lower than the fourth quarter of 2013. The ethanol segment generated $158 million of operating income in the fourth quarter of 2014 versus $269 million in the fourth quarter of 2013.
The decrease in ethanol segment operating income was mainly due to a $0.31 per gallon decrease in gross margin driven by lower gasoline and ethanol prices, with relatively stable corn prices. Production from the Mount Vernon plant contributed to record quarterly ethanol production volumes, which averaged 3.8 million gallons per day in the fourth quarter of 2014. General and administrative expenses, excluding corporate depreciation, were $214 million in the fourth quarter of 2014, which is $35 million higher than in the fourth quarter of 2013, primarily due to changes in legal reserves. Also in the fourth quarter of 2014, net interest expense was $101 million, and total depreciation and amortization expense was $425 million. The effective tax rate was 28.4%.
The rate was lower than normal due primarily to earnings from our international operations that were higher than projected and taxed at statutory rates that are lower than in the U.S. The biodiesel blenders tax credit that was passed into law in December and a reversal of certain tax reserves. With respect to our balance sheet at quarter end, total debt was $6.4 billion, and cash and temporary cash investments were $3.7 billion, of which $237 million was held by VLP. Valero's debt to capitalization ratio net of $2 billion in cash and excluding VLP, was 17.4%. Valero had approximately $6.1 billion of available equity in addition to cash, including VLP's $300 million of available equity. Cash flows in the fourth quarter included $857 million of capital expenditures, of which $157 million was for turnarounds and catalysts.
In the fourth quarter, we returned $640 million in cash to our stockholders, which included $143 million in dividend payments and $497 million in purchases of approximately 10.3 million shares of Valero common stock. Our total cash return to stockholders for 2014 was $1.9 billion, a 33% increase over 2013, and included $554 million in dividend payments and purchases of 25.7 million shares for $1.3 billion. For 2015 and 2016, we maintain our guidance for capital expenditures, including turnarounds and catalysts. In 2015, we expect to spend approximately $2.65 billion, consisting of approximately $1.5 billion for stay-in-business capital and $1.15 billion for growth investments, and this excludes $150 million for a St. Charles methanol project that remains under evaluation. For 2016, we expect to spend approximately $2.4 billion, consisting of $1.4 billion for stay-in-business capital and $1 billion for growth investments, excluding $300 million for the St. Charles methanol project.
For modeling our first quarter operations, we expect throughput volumes to fall within the following ranges: Gulf Coast at 1.45 million to 1.5 million barrels per day. Mid-Continent at 430,000 to 450,000 barrels per day. West Coast at 240,000 to 260,000 barrels per day. North Atlantic at 450,000 to 470,000 barrels per day. We expect refining cash operating expenses in the first quarter to be around $4.20 per barrel. For ethanol operations in the first quarter, we expect total production volumes of 3.7 million gallons per day, and operating expenses should average $0.37 per gallon, which includes $0.04 per gallon for non-cash costs such as depreciation and amortization. We expect G&A expense excluding depreciation for the first quarter to be around $170 million, and net interest expense should be about $100 million.
Total depreciation and amortization expense in the first quarter should be approximately $440 million, and our effective tax rate should be around 33%. Operator, we have concluded our opening remarks. In a moment, we will open the call to questions. During this segment, we request that our callers limit each turn to two questions. Callers may rejoin the queue with additional questions.
Thank you. We will now begin the question-and-answer session. If you have a question, please press star and then one on your touchtone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star and then one on your touchtone phone. The first question comes from Chi Chow from Tudor, Pickering & Holt.
Great. Thank you. I got a couple questions regarding your very strong performance in the Gulf Coast region. I guess first, can you explain the gross margin adjustments you show on the back of the table, in particular that blenders tax credit, and if that's going to be sustainable going forward? Secondly, even with the adjustments, looks like your capture rate was very strong sequentially versus 3Q when all the indicator cracks were down. I just wondered if you could explain some of the factors that were coming into play versus the indicator.
Okay. This is Mike. On the blenders tax credit, that was passed into law in December for 2014. So it was available to us last year. At this point, it is not passed for 2015, so we would not have that in our earnings going forward.
Okay.
On the margin capture, Gary, you want to speak to that?
Yes. I would say in the Gulf Coast, margin capture largely attributable to great performance on the hydrocrackers in terms of refinery operations. Then we also began to see some good advantages on running some of the South American heavy sour crude again in our Gulf Coast system in the fourth quarter.
Okay, great. How much impact was there just with the decline in crude prices? Is that something that if crude prices stabilize or eventually increases, the capture rate going to switch there versus what we saw in the fourth quarter?
We definitely see some benefit in terms of capture rate at a lower flat price. It is mainly the other products that we produce, the sulfur, pet coke, LPG, those types of things. When the flat price is lower, we tend to have higher capture rate because those products tend to be a little sticky with crude.
Okay, great. I guess one final question on the Gulf Coast. Looks like the Maya light heavy differential is pretty wide here in the first quarter so far on a percentage basis. How has your crude slate changed versus 4Q? Looked like you ran a lot of light crudes in the fourth quarter. Has that changed here going forward? Do you have any sort of earnings sensitivity to the Maya spread?
Yes. I guess to answer the question on our crude diet. We tend to buy crude out quite a way. So probably the first month you start seeing a significant change in our crude diet will be March, and we have started to move in the direction that exactly what you talked about. At several of our Gulf Coast refiners, we're backing down on some of the light domestic type crudes and starting to run a higher percentage of medium sour crudes and heavy sour crudes. Those have been more economic for us to process in the Gulf.
Okay, thanks. Do you have any sort of EPS sensitivity to changes in the light heavy?
No, chi, we don't.
Okay. All right. Thanks a lot.
The next question comes from Brad Heffern from RBC Capital Markets.
Morning, guys.
Morning.
You all announced a pretty substantial dividend increase last week, I think. Has that changed your thoughts at all on the buyback? How do you think about dividend versus buyback in general and then versus capital projects or acquisitions?
Mike, you want to-
Yeah. No, we're committed to returning more of our cash to our stockholders based on our analysis of the market data and capital allocation scenarios. We're still interested in high return projects, but our capital is down projected as we've disclosed, so we felt it was appropriate to increase the dividend at that level. We're going to be looking at exceeding our payout ratio going forward in 2015 from what we've had the last couple of years.
This is Joe. As far as our consideration of the dividend versus buybacks, when we did the analysis and looked at where our dividend was relative to the peer group, we felt that we were a little bit low. This type of move was something to get us more aligned with the other guys. It's also something that we view as being non-discretionary when we look at our use of cash going forward. The share repurchases, we're committed to trying to achieve a metric that we've defined internally, and we're going to continue to pursue that, as Mike said. But that will be more flexible for us than the dividend, which we consider to be, as I mentioned, non-discretionary.
Okay. That's great color. Thanks. Looking at refined product exports for the fourth quarter, do you have a figure you can provide as to how much you exported? Can you also talk about how demand is looking for those exported barrels?
Yes. This is Gary Simmons again. In the fourth quarter, we did 139,000 barrels a day of gasoline exports. on the distillate side, ULSD, we did 208,000 barrels a day. In addition to the ULSD, we also exported kerosene and jet. If you included that, total distillates would be 255,000 barrels a day. In terms of the current market, I would tell you we're starting to see some incentive to export gasoline again, especially to Latin America and to Canada. Most of the distillate arb was the strength in the Gulf. There's not a lot of incentive to do much distillate export in the current market.
Great. Thank you, guys.
The next question comes from Phil Gresh from JPMorgan.
Hey, good morning.
Morning, Phil.
Just a follow-up on the capital allocation question. You talk about having a payout ratio that exceeds the 50% of net income for 2014. Consensus actually has EPS down year-over-year. You also have some excess cash. You have this accelerated drop program. I was just trying to calibrate how high you're comfortable going
in 2015, as a percent of net income, if indeed consensus is right.
Okay. Well, I figured that you'd probably ask a question like this. The target that we've set is the one that we've stated. It's to exceed the previous year. As I mentioned previously, internally, we've got a target that would be higher than that. I'm not prepared right now to give you a fixed percentage for the overall payout ratio. I just think we need to see how the year evolves. Look at the dynamic nature of the market that we're dealing with today, and we've seen crude go from $100 late last year to $50 this year. For me to give you a committed number right now is something that probably just wouldn't be prudent to do. I think for now, if I were you, I'd just assume that we're going to exceed the 50% target and go with that.
Okay, understood. That actually tees up my next question, which is just your general outlook for the market. As we exit 2016, it is starting to look like crude oil production growth could actually be down year-over-year. There is talk of increased global refining capacity. Given this dynamic market, I would love to hear your general big picture views and just how you are thinking about planning for this type of environment.
That is a fine question, and Gary Simmons is so very close to this, let us let him go ahead and comment on it.
Yeah. Overall, I think we see that the crude market will continue to be in an oversupplied position for the foreseeable future. I think the fact that the Saudis have signaled that they are going to continue to put medium sour barrels on the market will mean that our medium sour differential should remain supportive. The combination of that with additional Canadian heavy into the Gulf, we believe will give us good heavy sour differentials as well. Both those things we think are very supportive in terms of Valero's performance moving forward. When you turn to the refined product side, I think it is a little unclear at this stage to see exactly what will happen with refinery margins.
However, we think that the fall off in flat price, we should see a positive demand response, and you have been able to see that the past few weeks from the DOE stats. As demand increases, that should also be supportive of refining margins.
Sure. Okay. Thanks a lot.
The next question comes from Paul Cheng from Barclays.
Hey, guys. Good morning.
Morning, Paul.
Morning, Paul.
Two questions. First, if I look at your margin capture rate against your Valero index that you post in your website, it was quite amazing that the last two years, 2013 and 2014, versus the two years before in 2011, 2012, your capture rate actually improved somewhere between 3% and 9% between these two periods with the exception of the West Coast. So wondering if you can help us that, trying to quantify, how much of the improvement you think is just that the market condition is just in favor of your configuration, and how much is that is really based on the better operation reliability that you guys have been able to improve, and how much is related to the large capital investment that previous years you guys have made and that had subsequently come on stream?
The second question, or that you want to answer that before I go to the second?
Yeah, because Paul, that was a pretty long one, huh? Paul, I tell you, we'll let Gary speak to this, but just as a member of management for the last several years, I'd like for us to take credit for all of it. That being said, Gary, you want to give your view?
Yeah. I would tell you, Paul, probably you have to look at this regionally, and when you look to the Mid-Continent, some of our improvement in capture rate has just been due to the fact that the Midland market has been very disconnected from the Cushing market over the past couple of years. The wider Midland spreads where we're running a lot of Midland barrels to Ardmore and McKee has certainly helped our capture rates there. Same thing in the North Atlantic Basin. I would say a lot of that is market driven, especially as we transition Quebec from a foreign crude diet to a North American light sweet crude diet. We saw a significant increase in our capture rate there.
However, in the Gulf, I would say that the improvement in capture rate is primarily just the fact that we're seeing a lot better yield and the operational improvements we've made in our Gulf Coast system.
How much is the benefit is coming from the investment that you guys have been making? Is there any way that we can quantify it?
Paul, in the recent analyst presentations we put together, we have included a lot of information on the economics associated with the projects, and the hydrocrackers are the one that we tend to focus on. I think what you can expect is that we'll continue to disclose this information as we go forward, and we obviously believe that the capital that's been invested over the last several years has had a significant effect, not only in, for example, the hydrocracker projects in driving the capture rates relative to more distillate production, but the increase in the reliability in our system and so on. It's all beneficial. We haven't tried to pin down specifically what's related to what, but I think we can all see it in the results.
A final one. I think that there's a change in your project investment decision process comparing to the past. Maybe you can elaborate a little bit more in terms of what condition may have changed or what criteria you have changed differently now. Thank you.
Hi, Paul. It's Lane. As you mentioned, we're calling a more deliberate gated process. Really what we look for are projects that will enter our gated system. Some we don't even look at unless they have a 50% IRR at the gate one. And they also right now have a tendency to be a little bit more focused towards feedstock optimization and not as nearly as large as maybe some of the projects that we had started in the past.
Thank you.
Our next question comes from Jeff Dietert from Simmons & Company.
Good morning.
Morning, Jeff.
There's been some refining margin strength in Europe and on the U.S. East Coast. The Atlantic Basin refining margins overall have been pretty healthy relative to the other regions. Could you talk about what factors you believe are contributing to this strength? Is a marginal product on the U.S. East Coast, is it supplied by U.S. Gulf Coast via the Jones Act ship? Or what do you think is causing the strength in the Atlantic Basin?
Yes, Jeff, this is Gary, and I think you hit exactly on it. We saw the New York Harbor market get very strong. The Colonial Pipeline is always full, so that means the barrel that's flowing in there to set the price is either a barrel from the U.S. Gulf Coast on a Jones Act ship or a barrel from Western Europe. So it incentivized imports and incentivized the flow with Jones Act ships from the Gulf. The harbor market had to strengthen.
Jones Act laws are actually increasing prices on the East Coast?
Yes.
Secondly, I was hoping you could comment on the EPA and the Renewable Fuel Standard and what you're anticipating could happen there. RIN prices have risen with the uncertainty that's been created there. Could you comment on that issue?
Yeah. We're still waiting for the final numbers for 2014 and the numbers for 2015 to come out from the EPA. We're hopeful we'll have something by the end of March. That's what we're hearing. As you pointed to, until those numbers are set, we see the RIN market as being very volatile. We're hopeful we get some direction here pretty soon from the EPA.
Thanks for your comments.
The next question comes from Blake Fernandez from Howard Weil.
Hey, guys. Good morning. My question's on the VLP drop. Appreciate the more aggressive strategy. The way I had envisioned this in the past was a progressive increase over time. I'm just curious, do you think the $1 billion in 2015 sets a baseline to where we should expect progressive increases into 2016, 2017, et cetera?
Yeah. This is Joe, Blake. This drop, as you mentioned, is really much larger than we had previously planned. But we have quite a portfolio of logistics assets, which we've mentioned, and obviously this level of drops based on the EBITDA that we have in the system would allow us to sustain this level of drops for some years to come. It's our intention to continue to drop at a pace that makes sense for Valero and for VLP. As you know, we continue to invest in logistics projects that support the refining operations, and then Michael Ciskowski and his team are evaluating additional sources of qualifying EBITDA, such as that from the fuels distribution business. So when we look at our portfolio today, we believe that this is sustainable for some period of time.
If you look at VLP specifically, we've stated that our plans were to increase the distribution by 20% to 25% a year. Based on this particular drop, I think that you can expect that we're certainly going to be at the high range of that for this year, and it looks like it's very sustainable going forward.
Great. Thanks, Joe. Second question. The OpEx guidance you have, $4.20 a barrel, if I'm not mistaken, that seems a little bit higher than where we've been trending last year. I'm just curious if there's anything in there that's driving that, and maybe if you could tie in with that as we move more toward heavy sour runs. Should we expect that to create some upward pressure on the operating costs? I'll leave it there. Thanks.
Hey, Blake, this is Lane. The guidance really is a function of we have some exceptional turnaround activity that's going to occur here late in the first quarter, so our volumes are a little bit lower. I would also say that the outlook is pretty consistent in terms of the natural gas price from the fourth quarter to the first quarter. So that's the reason we have the guidance where it is.
Okay. If you don't mind, just any comments on, again, with the heavy sours coming back into favor, would that have a kind of upward pressure on operating costs moving forward?
Oh, no, not really. No.
Okay. Thank you.
The next question comes from Evan Calio from Morgan Stanley.
Calio.
Morning, guys. Nice to see strong results energy somewhere. My first question is, it's a different take on a prior question on the outlook. You addressed the souring and heavy and crude oil global slate with higher OPEC market share going Gulf of Mexico and Canadian production. Yet, can you discuss the developing and steepening contango and how it benefits Valero, especially given the structural way in which the crude markets are being forced to balance with the U.S. as the new swing producer?
I mean, really the contango market structure is just a good indication that the crude market is oversupplied. As a buyer of crude, Valero benefits from the competition for producers to gain market share. So we think this is supportive for us for at least the next couple of years.
Right. Can you quantify how much you are hedging on TI to LLS, one to two or one to three months contango, and how you think about your own storage assets in this market, or even do you see the potential for U.S. storage filling?
Yeah. I think definitely when you look at the economics of what you can get tankage in Cushing, those economics are supportive of putting oil in tankage and storing it there. I think we will continue to see Cushing build. I read something this morning, they expect Cushing to continue to build about 1.5 million barrels a week through April. In terms of us particularly, we do some of that. We do not do a lot of it. When we choose to put barrels in storage and take advantage of contango, it is also for other reasons. We may see an opportunistic barrel that we think has a good discount. We might not be able to fit it into our system.
We will go ahead and put those in tankage in Aruba and take advantage of the contango and also what looks to be an opportunistic purchase for us.
Great. Maybe a second one for me, and maybe it is more a request for detailed information if you do not have that data. But can you break down the $900 million of MLP EBITDA into any subcategories? I guess I raised the question in the sense of one of the subcategories of recent spending is rail. Also has some commodity price exposure to that subsegment. Yet I know, however, you use a significant portion of that rail fleet to move product and/or ethanol, which should have relatively higher utilization tariff. Any breakdown or help us in the composition of the EBITDA and/or Sorry, I think this is a multi-part question. I did not intend to. Or any breakdown of just that rail segment, how much is product and ethanol? I will leave it at that. Thanks.
Yeah, Evan, no, that's fine. Because it's a multi-part question, we'll let Rich and Martin Parrish answer this. Obviously, Rich is the President of VLP, and Martin runs the ethanol business, the renewables business. So why don't we let those two guys speak to this, see if we can get you some color here.
That's great.
Okay. On the rail cars, just to break that down a little bit. So obviously they are qualifying to drop down to VLP. We've created a company to hold these cars, and our intent is to drop these cars down in tranches over time. But if you look at the cars that we have, there's general purpose and they're coil and insulated cars. The coil and insulated cars obviously fit well into the ethanol business, and the coil and insulated would fit into the asphalt and crude and fuel oil business. But our intent would be to drop these down over time in tranches.
Okay.
Yeah, this is Martin Parrish. We have about 3,000 cars in ethanol service to general purpose cars, as Rich said. As those leases expire, we'll take those off and use the VLP cars. As you know, rail is the primary transport for ethanol. We expect these cars to be highly utilized and a good fit for VLP.
Now to the broader question on the $900 million. Rich, you want to provide a little more?
Yeah. Evan, this is Rich again. To break down broadly the $900 million of EBITDA. When we were out on the road a year ago, we talked about our retained assets. There's probably about $620 million of EBITDA implied upstairs at the parent level.
From 2013 and 2014, we've got about $140 million capital spending, which is mostly complete. That would generate roughly another $140 million of EBITDA. That gets you to an 800 number. In 2014, we've got another $400 million of capital spending, which generates another $40 million. In 2016 and 2017, we've got large spending on what we've talked about in the past of the Diamond Pipeline and some other pipeline projects. So through 2017, the capital spending, it gets you to about $900 million of EBITDA.
Great.
Is that better?
No, that's helpful. Maybe at some point, just color on the types, whether how much is pipeline, how much is storage, how much is rail or fuel marketing distribution to at least better highlight the drop-down values given the assets have some different multiples on them.
Evan, we can sure do that. Obviously, in this case, the bulk of this is logistics assets.
The numbers that Rich is quoting doesn't include anything that would be associated with the fuels marketing business.
Good stuff. Well, thanks, and thanks again. Again, good results.
Thank you.
Our next question comes from Roger Read from Wells Fargo.
Hi, good morning.
Morning.
Morning, Roger.
Just maybe hit a couple questions here. You've done a fairly phenomenal job the last several quarters of
outperforming volume expectations, particularly in the Gulf Coast. Clearly from guidance here, you're expecting a decent amount of turnarounds in the first quarter. Could you just give us a, is it strictly market conditions or have there been other things that have allowed you to outperform volume expectations? I'm thinking you made comments earlier about the hydrocrackers having run very well in the fourth quarter. Just walk us through that and maybe how that could imply stronger results in the first half of the year.
Roger, our performance, when we give guidance is based on what we plan. We plan conservatively. If the market provides opportunity, and we're constantly seeking opportunity. As crude prices or as product prices change, we try to optimize. If we have the opportunity to go after extra barrels, we'll do it. That's what you've seen the last. That's probably what you're talking about here.
Well, that's a fact. I would tell you that the fact that we've invested capital in the business the way we've invested it over the last several years, and our commitment to continuing to maintain the high levels of reliability and safety within our refining system is going to contribute to this. I think what you're beginning to see here is a realization of the value of the investments that have been made, and the capabilities of this management team to execute, to optimize the slates in the movement of products out, and the day-to-day operations of the refineries.
Okay. That's helpful. Coming back on the other side of that, the comment earlier about distillate exports not exactly being incentivized in this environment. I know there's all kinds of seasonal factors and other things going on. Are you seeing anything particularly different on just general volume demand sides here in the U.S.? We've seen decent data, although obviously somewhat we have to be skeptical exactly what we see out of the EIA and API on a weekly basis. Looks like gasoline demand is better here. How maybe that's flowing through both in terms of the export market demand-wise, not just arbitrage-wise, and then local demand as well.
Yeah, Roger. I would tell you that we have definitely since the flat price has fallen off, we see greater demand for refined products on the gasoline and distillate side. That's some of the reason why the Gulf has been supported. When the Gulf is supported, then we might not see quite the incentive to export that we do. I would tell you we're still sending distillate to South America. We still see good export demand, not necessarily quite the demand in Europe. Some of the reason for that is it's just they've had mild weather in Europe, and so distillate demand is down there.
Okay. Just a last question is, the North Atlantic margins, I know you don't like to do this, but if you were to break down how Pembroke performed versus how Canada performed, was there an unusual item? Both units were better, one was better than the other, just any granularity you can offer there?
Well, you kind of prefaced the question by the fact that we weren't going to answer it. We appreciate you doing that. Both refineries are performing well. Obviously our Canadian operations, it's a very strong operation. Beyond that, I don't think we want to try to get into that detail.
All right. Well, had to be worth a try anyway.
Roger, I'll give you credit for that. Thank you.
All right. Thank you.
See you.
The next question comes from Doug Leggate from Bank of America.
Hey, good morning, guys. It's actually Jason Smith on for Doug.
Hello, Jason.
Just to follow up on refining projects and being a bit more selective, can you just update us as to where the Benicia unloading facility is in the permit process, and then is there incentive on your end to continue moving forward given the recent narrowing in spreads?
Hey, Jason, this is Lane. We are still working with the city to try to address all the comments that came out we had when we submitted the EIR for review. We are in the process with their folks to continue to push this forward. We are still pretty optimistic we will get the permit. Timing at this point is a little bit difficult for us to project. I would say sometime early next year would be when we would actually get started putting the crude by rail project in place. I will let Gary speak to the economics of crude by rail right now.
Yeah. I would say definitely over the last few weeks from where the Brent-TI arb was, we would not be incentivized to move crude by rail to Benicia. But we are starting to see that arb widen back out, and our view is that we will see a wider Brent-TI than what we have seen over the last few weeks, and we believe that we will have an economic incentive to move the crude to Benicia.
Is there anything in your 2015 or 2016 budget for that project at this time, or is there anything else in your budget for 2015 or 2016 that could potentially get cut beyond the methanol project that you guys obviously are slowing down on?
This is Lane again. Yes, there is money budgeted in the 2015 budget for crude by rail.
Again, slowing down?
Clearly, that'll mean that we'll slow that spend down versus the budget, what we at least have seeded right now.
Got it. Okay. Just one quick follow-up on the splitter projects. I think you guys had talked about $500 million of EBITDA in a 2014 environment. Can you maybe frame what those look like in the current environment?
You're talking about the crude topper projects?
Yes.
This is Lane again. What I would do is refer you to our investment, our slides that have sensitivity. Again, you are right, the $500 million EBITDA is based on 2014 prices. The very next page right in there, we have this whole set of sensitivities and drivers that affect the economics of that project.
Okay, thanks, guys. Appreciate it.
The next question comes from Sam Margolin from Cowen and Company.
Good morning.
Morning.
Back to the capture rate question, I guess in light of the outperformance and some of the comments you just made in general about crude oversupply. I was wondering if you could maybe give us some color on some crude prices that maybe aren't necessarily in the benchmark that we can't see every day. You mentioned the South American barrels, but I was also wondering about some domestic areas, so that's Houston, South Texas, and maybe even the Bakken wellhead, where you have some real exposure too. If there's some contribution for pricing there at discounts below sort of what we see on the boards.
It's difficult to get into a lot of detail. But we continue to see that, if you look at an LLS-related market, in terms of the Eastern Gulf, the Houston market is discounted a couple of dollars below that. Then you move further west and you get into the Corpus Christi area market. Again, we see another couple of dollars of discount off LLS for an Eagle Ford-type barrel. The same thing as you move up into the Mid-Continent. The discounts get deeper as you move up on the light sweet side. On the heavy sour side, definitely we're seeing some incentive to run a lot of these South American barrels. The biggest switch, without going into a lot of details on discounts, as the Canadian differentials came in, we started to see an advantage to switch to more Brazilian grades and less Canadian grades.
That's just an optimization we do every day.
Okay, great. Then switching gears to the drop-down commentary. The MLP space has obviously been really volatile. VLP has outperformed, but I'm wondering if there's any consideration or any effect on sort of valuation of drop-downs in general. There was a question before about, obviously, the valuation spectrum between types of midstream assets, but I'm just wondering sort of as a complex, if there's been any impact or if it's simple as long as VLP is over 10 times EBITDA, the drop-down values can stay at 10 times EBITDA, and there's no real problem.
We haven't seen any change in the drop-down multiples of the deals that have been occurring here recently. They're still at roughly 12% pre-tax for VLP and 10 times multiple.
Okay, great. Thank you so much.
The next question comes from Mohit Bhardwaj from Citigroup.
Yeah, hi. Thanks for taking the question. The question is on ethanol. If you could just talk about the ethanol market in 2015. Obviously, in 2014, ethanol was a big support, and you guys made like $700 million-$800 million in operating margins. Going into 2015, it looks like the corn prices have held up, and ethanol prices are coming down based on blending economics. If you could just talk about that.
Sure. This is Martin Parrish. ethanol margins are likely to remain low in a $50 crude environment. We don't know how long crude's going to stay at these prices, obviously. What we do know is we have the best assets in the ethanol industry in the U.S., and we're in advantage locations, and we know we're not the marginal producer. So we expect to weather this fine.
Great. Martin, do you expect to remain in the positive territory, or do you think at right now you're seeing negative margins in that?
I think it's going to chop around some, but we think overall we'll be positive with our fleet.
It's positive today, yes.
Okay. You guys mentioned crude by rail to California. I just was wondering, as Flanagan South is running at 400,000 barrels per day plus, is Port Arthur and St. Charles being utilized on the rail side, or are you guys just looking at getting heavy sours from Latin America?
Your question is, can you restate your question?
Yeah. I was just wondering if the economics of crude by rail into Port Arthur and St. Charles for heavy Canadian is still working out, or is it more profitable to just look for opportunities for Latin American heavy barrels right now?
Yeah. I would tell you today, the barrels that we're bringing to Port Arthur with today's economics would be break-even versus a mile alternative with where the market is today.
Correct. And one final one for me. Just looking at California, there are competitors of yours who talk about California margins improving for them, and California remains the only place where the margin has got a lot beaten at par for you guys. Are there opportunities that you see to improve margins there?
To improve margins in California.
This is Lane. The only project that we are working on really besides our ongoing optimization efforts and maybe real small things is the crude by rail. We believe in the optionality to be able to source crude from the Mid-Continent ultimately. But because our view is the West Coast is a very challenged environment, we are very careful and very disciplined in how we approach capital into the West Coast versus all of our opportunities we have elsewhere in our operations.
Thanks a lot. Thanks for your comments.
Thank you.
Sure, Mohit.
The next question comes from Ed Westlake from Credit Suisse.
Hey. Yeah, good morning, and congratulations on the earnings. I guess last year we were talking about LLS, and this year we are just talking about all-round good performance and margin capture, so well done. One of the, I guess, opening comments you made was it was attributable to great performance from the hydrocrackers. Obviously, oil has fallen further, and there is a sort of a swell. Then you obviously mentioned that diesel demand is a bit weaker, partly due to weather. Presumably some of that will give back, although, obviously take the point that the crude market part of it could still be an area of positive surprise. Just some thoughts there.
Well, Ed, this is Lane Riggs. We have a pretty good slide in our IR presentation on how these hydrocrackers perform and sensitivities around it. You have sort of a base set of economics on the 2014 price set. With that said, oil prices have fallen, and the distillate crack is where it is, but natural gas prices have fallen as well. I think when you look at it and you look at these drivers, you just need to take all that into consideration. Today, we still have very good margins on these hydrocrackers.
Okay, good. Was there any wholesale benefit off the, I guess, racks in Q4 as crude fell?
Yes, we did see a benefit on the wholesale side. The rack prices tend to lag a little bit, and so we had very good rack margins through the fourth quarter.
Is there a way to quantify it in dollar millions? Just obviously trying to get to a sense of a more steady state level of earnings. I appreciate there's lots of volatility in the fourth quarter and still today.
I don't have those numbers.
Right. Okay. Or any volumes of wholesale products which perhaps where the because there's stuff which you can sell over the rack where the wholesale margin may not have expanded as much, and then there are other parts of the U.S., I'm thinking some of the states which don't have refining, where you'd imagine that there would be a greater sensitivity to wholesale. Any sort of overall number for production that is sold in rack prices which surprised to the positive?
Well, our wholesale business really consists of, I would say, several different types of businesses. We've got the branded wholesale business, we've got the unbranded contract business, we've got our national accounts business, and then we've got our spot wholesale business, and all that is volume that's moved across the rack. Ed, we don't have a problem talking about it, but quite honestly, the income associated with the wholesale business is embedded right now in the way we report our refinery operations. And the volume and the margins on the wholesale business are so much smaller than we would have if you look at the refining margin, that it just hasn't made sense to break it out before. It also tends to vary so much.
I would tell you, if you want, we can talk about this a little bit offline, but I don't think it's going to have a material impact to your forecasting going forward.
Good. I was just trying to check, when you have surprises like this, you kind of work out where they came from.
Sure. I understand, but I would tell you that it was a good quarter for wholesale, though it wasn't something that materially affected the numbers that we reported.
Okay. Very helpful. Then just a pet theory of mine. We're all driving F-150s to Disney World this summer. I'm driving from New York. It's a long way. I might even take the F-350 on the road.
That's the boy.
Six tires.
I hope you used a credit card.
That's what I'm saying. How do you think the industry is going to be prepared to make the summer-grade gasoline, given that we probably haven't had this type of market for some time? Maybe just give us a color on any constraints that you see in making summer-grade gasoline or not. Just a view.
I don't see anything where I would tell you that we will have any constraints on being able to produce the gasoline for the summertime market.
Okay. It should just be a normal seasonal trade as we switch out from winter to summer, but nothing exceptional in your view.
Yeah.
Okay, great. Very helpful. Thanks very much for your time. Look forward to seeing you soon.
Our next question comes from Neil Mehta from Goldman Sachs.
Good morning, guys.
Good morning.
Good morning, Neil.
Jared, just as a follow-up from a conversation a couple of months ago, Brent-TI is tighter, so we're inside this export arbitrage. We're now in 2015, the politics in Washington are a little bit different. Wanted to get your temperature on the discussion around the crude export ban and what discussions in Washington feel like around that right now.
Well, that's a good question. We maintain our position that we're totally supportive of free and open markets. If the crude export ban were lifted, we believe that Congress is going to address this and needs to address this and the other issues associated with this as well, such as the Jones Act cross-border pipelines and the RFS. That's been our position, and I think that we continue to believe that. It's hard to pick one particular issue and focus attention on that without looking at the overall energy policy that we have here in the U.S. in aggregate. We talk to our government relations guys all the time. We know that there is a lot of conversation taking place around crude oil exports. We're not seeing it being promoted in any kind of material way at this point in time.
Now, if you go to the practical side of this, we are still importers of crude in the United States. We import significant volumes, probably still 4.5 million to 5 million barrels per day.
That is not from Canada. There are additional volumes that come in from Canada. You have crude that is being brought into the country. You have a market right now that is putting downward pressure on crude prices, and you ultimately will get to who has the lowest cost to produce to determine who is going to be continuing to produce and provide the supply. I honestly am not sure where you would see domestically produced crude be exported to today as it is trying to find its way into refining capacity globally. Issues flare up, and then they tend to calm down a little bit. This one is still getting some conversation, but I do not think our perspective has changed from what we have talked about historically.
That is very helpful. The other question is around Brent-WTI, just separately. You made the comment that you think that has the potential to widen out here over the next couple of months. What has driven the widening over the last couple of weeks? What do you guys see in Cushing happening? As you think about where that widening could occur, is it on the TI LLS piece of the equation, or is it Brent LLS?
Yeah. I would say the thing that has driven the Brent-TI to widen is if you look at the DOE stats over the last two weeks, we have had two very large crude builds. It starts to tell you that as the Saudis start forcing more medium sour barrels into the market, it displaces some of this light sweet, and then we begin to build light sweet. As inventories build, then it means we need a wider Brent-TI arb in order to start incentivizing refiners to take that light barrel back into the market. I think that is what has happened. I do think it will get wider to the point where we are incentivized to go back to the light sweet.
I would tell you that I would expect that the Brent-TI to be a little bit wider, and part of that is also due to the fact that we're building all this inventory in Cushing. Maybe the Brent-TI a little bit wider than the LLS to Brent spread.
Perfect. Thank you very much, guys.
The next question comes from Chi Chow from Tudor, Pickering, and Holt.
Hi. Thanks. Just a couple of follow-ups here. I guess--
Hey, Chi. Chi, we know how to pronounce your name.
How big is that? I have heard it all. I guess this is really a question for the second half of the year. With the Line 9 reversal, what sort of volumes do you have committed on that line, and what types of crudes are you expecting to move on it? Is it Bakken or Syncrude or some other Canadian barrel?
We have not talked about what our line commitment is. What we have said is when Line 9 comes up, we will be able to completely supply the Quebec refinery with North American domestic barrels. In terms of the quality of crude, we would expect to ship about 50% of the volume we ship would be a synthetic-type barrel, and the other, a mix of other Canadian light sweet Bakken.
Okay. Do those crudes, when you bring them in, are they going to change the yield at all, or is it going to increase the profitability from a product standpoint on yields or volumes?
What we would say is with the change in diet, the crudes that we anticipate getting off Line 9 tend to be a higher distillate yield crude. We do show that they have a margin advantage as long as distillate is over gasoline compared to some of the West African grades that we run today, which tend to be a higher gasoline yield crude.
Okay, great. Thanks. That's helpful. A couple of questions for Mike. I guess you've got a couple debt maturities this year. What's the timing of those? Secondly, how do you think about a minimum cash balance that you're comfortable operating at?
Yeah, the timings, there's what? $400 million is due next week, I believe it is, and then we have $75 million that's a couple of months later, is on the timing. What was the second question?
Just how you think about minimum cash balance. What sort of minimum levels are you comfortable operating at?
We really don't have a minimum cash balance identified, but when you look at our operations, I think we're comfortable in the range of around $2 billion.
Okay, great. Thanks a lot.
Take care, Chi.
Thank you.
At this moment, we show no further questions. I would like to turn the meeting over to you for any closing remarks.
Okay. Thank you, Hilda. We appreciate everyone calling in and those listening today. If you have any additional questions, please contact our IR department. Thank you very much.
Ladies and gentlemen, this concludes today's conference. We thank you for participating. You may now disconnect.