Valero Energy Corporation (VLO) Q4 2014 Earnings Report, Transcript and Summary

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. [Operator Instructions] I will now turn the call over to Mr. John Locke. Mr. Locke, you may begin.

Thank you, Hilda. 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; Mike Ciskowski, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President of Refining Operations and Engineering; Jay Browning, our Executive Vice President and General Counsel; and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at valero.com. Also, attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions about 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 have 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 drive safe and profitable operations, so we are relentlessly committed here. An example of this can be seen in 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 for liability 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're 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 crude oil for 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're committed to its growth and unlocking value. As we noted in the release, we're 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 and incentive distribution rights by the end of this year. We're 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're committed unlocking value. In summary, we're focused on operational excellence, disciplined capital allocation and value creation. Our team remains committed to high performance and achievement. And with that, John, I'll 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 7 of the financial table that accompany our release, we are at $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 by lower discounts for sweet 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 administrators 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 U.S., the biodiesel blender's 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 liquidity in addition to cash, including VLP's $300 million of available liquidity. Cash flows in the fourth quarter included $857 million in 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 returned 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 same business capital and $1.15 billion for growth investment, and this excludes $150 million for 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 in 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; and 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 cost 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 $449 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.

[Operator Instructions] Your first comes from Chi Chow from Tudor, Pickering, Holt.

I've got a couple of questions regarding your very strong performance in the Gulf Coast region. I guess, first, can you explain the gross margin adjustments you've shown in the back of the table, in particularly that blender's tax credit and how that's going to be sustainable going forward? And then secondly, even with the adjustments, it looks like your capture rate was very strong sequentially versus 3Q, when all the indicated cracks were down. And just wondering if you could explain some of the factors that were coming into play versus the indicated?

The blender's tax credit, that was passed into the law in December for 2014, so it was available to us last year. At this point it's not hatch for 2015, so we would not have that in our earnings going forward.

And on the margin capture, Gary, you want speak to that.

Yes. I would say, in the Gulf Coast margin capture is largely attributable to great performance from the hydrocrackers in terms of refinery operation. And then we also begin to see some good advantages on running some of the South American heavy sour crude again in our Gulf Coast system in fourth quarter.

How much impact was there, just with the decline in crude prices? And is that something that if crude prices stabilize or eventually increases kind of the capture rate going to switch there versus what we saw in the fourth quarter?

We definitely see some benefits in terms of capture rate and a lower flat price. It's mainly the other products that we produce, the sulfur and coke, LPG, those types of things. Now, when the flat price is lower we tend to have higher capture rate, because those products tend to be a little sticky with crude.

I guess one final question on the Gulf Coast. Looks like the Maya light/heavy differentials is pretty wide here in the first quarter so far on percentage basis. How has your crudes slate changed versus 4Q? It looks like you ran a lot of light crudes in the fourth quarter. Has that change here going forward? And do you have any sort of earnings sensitivity for the Maya spread?

Yes. I guess to answer the question on our crude diet, we tend to buy crude out quite a ways. So probably the first month you start seeing a significant change in our crude diet would be large. And we have started to move in the direction that exactly what you talked about as several of our Gulf Coast refiners were backing down on some of the light domestic type crude 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.

So do you have any sort of EPS sensitivity to changes in the light/heavy?

No, actually we don't.

The next question comes from Brad Heffern from RBC Capital Markets.

You all announced a pretty substantial dividend increase last week I think. Has that changed your thoughts at all on the buyback? And how do you think about dividend versus buyback in general and then versus capital projects or acquisitions?

Mike, you want to?

Yes. We're working really to returning more of our cash to our stockholders based on our analysis of the market data and capital allocation scenarios. We are still interested in higher return projects, but our capital is down, projected as we disclosed, so we thought it was appropriate to increase the dividend at that level. So we're going to be looking at exceeding our payout ratio going forward in 2015 on what we've had the last couple of years.

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. And so this type of move was something to get us more aligned with the other guys. It is also something that we view as being non-discretionary when we look at our use of cash going forward. The share repurchases, we are committed to trying to achieve a metric that we 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.

And then looking at refined product exports for the fourth quarter, do you have a figure that you can provide us how much you exported? And can you also talk about how demand is looking for those exported barrels?

Yes. In the fourth quarter we did 139,000 barrels a day of gasoline exports. On the distillate side, ULSD, we did 280,000 barrels a day. In addition to the ULSD, we also exported kerosene and jet, and 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 are through strength in the Gulf, there is not a lot of incentives to do much distillate export in the current market.

The next question comes from Phil Gresh from JPMorgan.

Just a follow-up on the capital allocation question. You talk about having a payout ratio that exceeds 50% of net income for 2014. Consensus actually has EPS down year-over-year. You also have some excess cash. You have just accelerated drop program. So I was just trying to calculate how high you're comfortable going in 2015 as a percentage of net income, if indeed consensus is right?

Well, I figured that you'd probably ask a question like this. And really the target we've set is the one we've stated, it's to exceed the previous year. Now, as I mentioned previously, internally we've got a target that would be higher than that. But I am 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 are dealing with today. Are we're seeing crude go from a $100 late last year to $50 this year. And so for me to give you a committed number right now is something that's probably just wouldn't be prudent to do. So I think for now, if I were you, I would just assume that we're going to exceed the 50% target and go with that.

And that actually keens up my next question, which is just in your general outlook for the market, as we exit '16, it's starting to look like crude oil production growth could actually be down year-over-year. There is talk of increased global refine capacity. So given this dynamic market, I'd love to hear your general big picture views and just how you're thinking about planning for this type of environment?

That's a fine question. Gary Simmons is so very close to this, let us let him go ahead and comment on it.

So overall, I think we see that the crude market will continue to be in a oversupplied position for 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 it will give us good heavy sour differentials as well. So both of those things we think are very supportive in terms of our Valero's performance moving forward. When you turn to the refined product side, I think it's 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 in the past few weeks from the DOE stats. And so as demand increases, that should also be supportive of refining margins.

The next question comes from Paul Cheng from Barclays.

Two questions. First, if I look at your margin capture rate against your Valero index that you posted in your website, it was quite amazing that the last two year, 2013 and 2014 versus the two year before in 2011, 2012, your capture rate actually improved somewhere between 3% to 9% between these two period, with the exception of the West Coast. So wondering if you can have a stat, I'm 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 of that is really based on the better operation, reliability that you guys has been able to improve? And how much is related to the large capital investment in the previous years you guys have made and have subsequently come on stream. The second question -- or that you want to answer that before I go to the second?

Paul, I'd tell you, we'll let Garry speak to this, but just as member of management for last several years, I'd like first to take credit for all of it. That being said, Garry, you want to give your view.

Yes. So I will tell you, Paul, probably you have to look at this regionally. And when you look to the Mid-Continent, some of our improvement 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 and the wider Midland spreads. We're running a lot of Midland barrels to Ardmore and McKee, it 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 at this time.

And how much is the benefit is just coming from the investment that you guys have been making. Is there any way that we can quantify it?

In the recent analyst presentations we've 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 when the capital that's been invested over the last several years, it's 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 is a change in your project investments decision process comparing to the past. Maybe that you can elaborate a little bit more in terms of what condition may have change or what criteria you have changed differently now?

So as you mentioned we're booking them for deliberate gated process, really what we look for are the projects that will enter our gated systems. We don't even look at them unless they have sort of 50% IRR as to gate one. And then also we right now have a tendency to be a little bit more focused towards the stock optimization, and not as nearly as large as maybe some of the projects that we did started in the past.

Our next question comes from Jeff Dietert from Simmons & Company.

There has 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 the strength as a marginal product on the U.S. East Coast? Is it supply by U.S. Gulf Coast via the Jones Act ship? Or what do you think is causing the strength in the Atlantic Basin?

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 is flowing in there to set the price, it's either a barrel from the U.S. Gulf Coast on Jones Act ship or a barrel from Western Europe, and so to incentivize imports and incentivize the flow off with Jones Act ship from the Gulf, the harbor market had to strengthen.

So 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? Rents prices have risen with the uncertainty that's been created there. Could you comment on that issue?

Yes. So we're still waiting for the final numbers for '14 and the numbers for '15 to come out from the EPA. We're hopeful we'll have something by the end of March, that's kind of what we're hearing and as you pointed too. Until those numbers are set, we see the red market as being very volatile. And so we're hopeful, we'll get some direction here pretty soon from EPA.

The next question comes from Blake Fernandez from Howard Weil.

My questions on the VLP drop. Appreciate the more aggressive strategy. The way I had kind of envisioned this in the past was kind of progressive increase over time. So I'm just curious, do you think the $1 billion in '15 kind of sets a baseline to where we should expect progressive increases into '16, '17, et cetera?

This drop, as you mentioned, is really much larger than we have previously planned. But we have quite a portfolio of logistics assets, which we've mentioned and obviously this level of drop is based on the EBITDA that we have in the system will 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 to support the refining operations, and then Mike Ciskowski and his team are evaluating additional sources of qualifying EBITDA, so to get 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 stated in our plans were to increase the distribution 20% to 25% a year. And 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.

Second question, the OpEx guidance you have of $420 a barrel, if I'm not mistaken that seemed a little bit higher than where we've been trending last year. And I'm just curious if there is anything in there that's driving that? And maybe if you could tie in with that as we kind of move more towards heavy sour runs. Should we expect that to kind of create some upward pressure on the operating cost?

So the guidance really, as a function, that we have some turnaround activity that's going to occur here late in the first quarter, so our volumes are a little bit lower. And then, I would also say, that the outlook is pretty consistent in terms of our natural gas price from the fourth quarter to the first quarter, so that's sort of the reasons we have the guidance where it is.

And if you don't mind, just any comments on, again with the heavy sour coming back in the favor, should we think would that have kind of upward pressure on operating cost moving forward?

No. Not really.

The next question comes from Evan Calio from Morgan Stanley.

My first question is it's a different take on the prior question on the outlook. And you addressed the souring and heaving crude oil global slate with higher OPEC market share growing over Mexico and Canadian production. 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?

Really the contango market structure is yet a good indication that the crude market is over supplied. And so as a buyer of crude, Valero benefits from the competition from producers to gain market share. So we think this is supported for us for at least the next couple of years.

Can you quantify how much you're hedging on PI to avail 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?

So 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'll continue to see Cushing builds. I read something this morning. They expect Cushing to continue to build about 1.5 million barrels a week until through April. In terms of us, particularly we do some of that. We don't do a lot of it. When we choose to put barrels in storage and take advantage of contango, it's also for other reasons. So we may see an opportunistic barrel that we think has a good discount. We might not be able to fit it into our systems. So then we'll 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.

And just second one for me, maybe more a request for detailed information, if you don't that data. But can you break down the $900 million of MLP-able EBITDA into any sub categories? And I guess, I raised a question in the sense of, one of the subcategories of recent spending in rail, and also has some commodity price exposure to that sub segment. Yet I know, however, you use a significant portion of that rail fleet to move product under ethanol, which should have relatively higher utilization tariff. Any break down or help us in the composition of the EBITDA and/or -- sorry to make this multiple question, I didn't intend to -- or any break down in just that rail segment, how much is product in ethanol?

That's fine. Well, because it's a multi-part question, we'll let Rich and Martin Parrish answer it. Obviously, Rich is the President of the VLP, and Martin runs the ethanol business, the renewable business. So why don't we let those two guys speak to this, and see if we can get you some color here.

So on the rail cars just to kind of break that down a little bit. So obviously they are qualifying to dropdown to VLP. We've created a company to hold these cars and our intent is to drop these cars down and trying to over time. But if you look at the cars that we have, there is a general purpose and they're coiled and insulated cars. The coiled and insulated cars, obviously, fit well into the ethanol business and coiled 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.

We have about 3,000 cars in ethanol service, the 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 will be highly utilized in a good fit for VLP.

So now to the broader question on the $900 million, Rich, you want to provide a little more.

So if you kind of break down broadly the $900 million of EBITDA. So when we were out on the road a year ago, we talked about our retained assets. It's not about $620 million EBITDA and pride upstairs at the parent level. And from '13 and '14 we've got about $140 million [indiscernible] billion capital spending, which is mostly complete. So that would generate roughly another $140 million of EBITDA. So that kind of gives you to an 800 number. And then in '14 we've got another $400 million of capital spending, which generates another $40 million in '16 and '17. We got large spending on our, what we've talked about in the past, the diamond pipeline and some other pipeline projects. So kind of through '17 the capital spending will get you to about $900 million of EBITDA.

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?

We can sure do that. I mean obviously in this case the bulk of this is logistics assets. The number that we're scoring doesn't include anything that will be associated with the fuels marketing business.

Our next question comes from the Roger Read from Wells Fargo.

I guess maybe I had a couple questions here. You've done a fairly phenomenal job in last several quarters of outperforming volume expectations, particularly in the Gulf Coast. Clearly from guidance here you're expecting descent amount of turnarounds in the first quarter. Well, could you just sort of give us a -- is it strictly market conditions or have there been other things that have allowed you to outperform sort of volume expectations? And I'm thinking you made comments earlier about the hydrocrackers having run very well in the fourth quarter. Could you just sort of walk us through that maybe how that could imply the 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 opportunities and we're constantly seeking opportunity, as crude prices or as product prices change, we try to optimize. And if we have the opportunity to go after extra barrels, we'll do it, and that's kind of what you've seen in the last, beside what you talked about here.

Well, that's the fact, and then 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 in our commitment to continuing to maintain the high levels of our 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 then the capabilities of this management team to execute to optimize the slates in, the movement of products out, and then the day-to-day operation to the refineries.

And then coming back to the other side of that, the comment earlier about distillate exports, not exactly being incentivized in this environment, there's all kinds of seasonal factors and other things going on. But are you seeing anything particularly different on just general volume demand sides here in the U.S.? We've seen descent data, although obviously somewhat we have to be skeptical of exactly what we see on the EI and API on a weekly basis, but look like gasoline demand is better here. And 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?

Roger, so I would tell you that we have definitely -- since the flat prices have fallen off, we see greater demand for refined products on gasoline and liquid side. That's some of the reason why the Gulf has been supported. And when the Gulf has supported then we might not see quite the incentive to export, if we do. I would tell you we're still sending distillate to South America, so we still see good export demand, not necessarily quite the demand in Europe. And some of the reason for that is that just they've had mild weather in Europe, and to distillate demand has moved down there.

And then, just a last question is the North Atlantic margins, if you were to -- I know you don't like to do this, but if you were to break down sort of how Pembroke performed versus how Canada performed. Was there an unusual item? Both units were better, one was better and then other, just any granularity you can offer there?

I mean you kind of preface the question by the fact that we work and answer it. So we appreciate you doing that. I mean, both refineries are performing well. And obviously, our Canadian operation, it's a very strong operation, but beyond that I don't think we want to try to get into that detail.

The next question comes from Doug Leggate from Bank of America.

It's actually Jason Smith on for Doug. Just a follow up on refining projects and being a bit more selective, can you just update us as to where the Benicia unloading facility is, first in the permit process? And then is there incentive on your end moving forward, given the recent narrowing in spreads?

So we are still working with the city to try to address all the comments that came out. We have only submitted EIR for review, and we're in the process with their folks to continue to push this forward. We're still pretty optimistic we'll get the permit. Timing at this point is a little bit difficult for us to project. I'd say some time early next year would be when we would actually get started putting the crude-by-rail project in place. And I'll let Gary speak to the economics of crude-by-rail right now.

So I would say, definitely over the last few weeks, whatever Brent TI was, we wouldn't be incentivized there to move crude-by-rail from Benicia. But we're starting to see that arc widen back out, and our view is that we'll see a wider Brent-TI than what we've seen over the last few weeks, and that we believe that we'll have an economic incentive to move the crude to Benicia.

Is there anything in your '15 or '16 budget for that project at this time or is there anything else in your budget for '15 and '16 that could potentially get cut more beyond the methanol project that you guys obviously are slowing down on?

There is money budgeted in the 2015 budget to forward crude-by-rail.

And then slowing down?

Literally, that will mean that we'll slow that spend down versus the budget, but we are least succeeded right now.

And just one quick follow-up on the splitter projects, and you guys had talked about $500 million EBITDA in a 2014 environment. Can you give me the frame what those look like in the current environment?

So you're talking about the crude topper projects.

Yes.

Well, what I would do is refer you to our investment on our slides, we have sensitivity. So again, if you're right, the $500 million of EBITDA is based on 2014 prices. In the neighboring next phase right there, we have this whole set of sensitivity from drivers that affect the economics of that project.

The next question comes from Sam Margolin from Cowen & Company.

Back to the capture rate question. I guess in light of the outperformance, and then some of the comments you just made in general about crude over supply. 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 everyday. You mentioned that South American barrels, but I was also wondering about some domestic areas, so that's Huston, South Texas and maybe even the Bakken wellhead, where you have some real exposure too, if there is 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 LOS related market, in terms of the eastern Gulf, the Houston market is discounted a couple of dollars below that. And then you move further west and you get into the Corpus Christi area market. And again, we see another $2 of discount off LOS for an Eagle Ford type barrel. The same thing if 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 the 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, and that's an optimization we do everyday.

And then switching gears to the dropdown commentary. So the MLP space has obviously been really volatile, VLP has outperformed. So I'm wondering if there is any consideration or any effect on sort of valuation of drop downs in general. There was a question before about the valuation spectrum between types of midstream assets. But I'm just wondering sort of, as a complex, if there has been any impact or as long as VLP is over 10x EBITDA, the dropdown values can stay at 10x EBITDA and there is no real problem.

We haven't seen any change in drop down multiples of the deals that have been occurring here recently. So they're still at roughly 12% pre-tax for VLP.

The next question comes from Mohit Bhardwaj from Citigroup.

The question is on ethanol. You guys just talked about ethanol market in 2015, obviously in 2014 ethanol was a big support and you guys made like $700 million to $800 million in operating margin. Moving to 2015 it looks like the corn prices have kind of held up and ethanol prices are coming down based on the global economics, maybe just talk about that?

Ethanol margins are likely to remain low in the $50 crude environment. And we don't know how long crude is 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 an advantaged location and we know we're not marginal producer. So we expect to weather this time.

And market do you expect to remain in the positive territory or do you think right now you're seeing negative markets in that?

I think it's going to chop around some, but we think overall it will be positive with our fleet.

And it's positive today, yes.

And you guys mentioned crude-by-rail to California, it looks [indiscernible]. Is Port Arthur and St. Charles will be utilizing the rail side or you guys have just been looking at getting heavy cars from Latin America.

So your question is -- can you restate your question?

I was just wondering if economics for crude-by-rail into Port Arthur and St. Charles for heavy Canadian are still working out or is it more profitability to just look for opportunities for Latin American heavy metals right now.

So I would tell you today that barrels that we're bringing to Port Arthur with today's economics would be breakeven versus on my alternative with where the market is today.

And final one from me, just looking at California, the American [indiscernible] and talk about California models improving for them. And California remains the only place where the market has got a lot [indiscernible] value. Are there opportunities as you see to improve margins there?

To improve margins in California?

The only project that we're working on really besides our ongoing optimization efforts, and maybe a real small thing is the crude-by-rail. We believe in the optionality available for us crude from the Mid-Continent ultimately, and because our views, the West Coast is a very challenging environment. We are very careful and very disciplined in how we approach capital into the West Coast versus all our opportunities we have elsewhere in our operations.

The next question comes from Ed Westlake from Credit Suisse.

Congratulations on the earnings. I guess, last year we were talking about LLS, and this year we're 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 that's just sort of a swirl, and then obviously mentioned that diesel demand is a bit weaker, partly due to weather. I mean, 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.

We have a pretty good slide in our IR presentation on how the hydrocracker performed and sensitivities around it. We have sort of basic set of economics on the 2014 price stat. With that said, yes, oil price have fallen and the distillate crack is where it is, but natural gas prices have fallen as well. But I think when you look at it, when you look at these drivers, you just need to take all that in consideration. Today, we still have very good margins on the hydrocrackers.

And was there any wholesale benefit? I mean, obviously, I guess racks in 4Q crude could 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.

I mean is there a way to quantify in dollar millions, I mean just obviously trying to get to sort of a sense of a more steady state level of earnings, appreciate there's lots of volatility in the fourth quarter and still today?

I don't have those numbers.

Any volumes of wholesale products, which perhaps because that stuff which you can sell over the rack where the wholesale margin may not have expanded as much, and then there are other parts to be U.S., I'm thinking, some of these states which don't have refining, where you'd imagine that there would be a greater sensitivity to wholesale. I mean any sort of overall number for production that is sold in rack prices, which is a price to the positive?

Well, I mean our wholesale business really consist 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 spot wholesale business. And all of 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, it's just doesn't makes sense to break it out before. And it also tends to vary so much. So 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.

I was just trying to check, when you have surprises like this, you're trying to work out where they came from?

Sure. I understand, but I would tell you that maybe it was a good quarter for wholesale, but it wasn't something that material affected the numbers that we reported.

And then just a tad theory of mine. We're all driving F150s to Disney World this summer. I'm driving from New York it's a long way, I might even take the F350 on the road. How do you think the industry is going to be prepared to make the summer-grade gasoline given that we probably haven't have this type of market for sometime. 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 any thing where I would tell you that we'll have any constraints on being able to produce the gasoline for the summer time market.

So it should just be a normal seasonal trade as we switch out from winter to summer, but nothing exceptional in your view?

Yes.

Our next question comes from Neil Mehta from Goldman Sachs.

Joe, just as a follow-up from a conversation of couple of months ago, obviously Brent TI is tighter. So we're inside this export arbitrage, but now in 2015 the politics Washington are a little bit different. Wanted to get your temperature on the discussion around the crude export band and what discussions in Washington feel like around that right now?

That's a good question. I mean 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 it, and the other issues associated with this as well such as the Jones Act, cross-border pipelines in 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. So we talked to our government relations guys all the time. We know that there is a lot of conversation taking place around crude oil exports, but 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 millions barrels per day, and that's not from Canada. There is additional volumes that are coming from Canada. So you've got crude that's being brought into the country. You've got at market right now that is putting downward pressure on crude prices, and you ultimately will get to who's got the lowest cost to produce to determine who is going to be continuing to produce and provide the supply. So I, honestly, am not sure where you would see domestically produced crude being exported today as it's trying to find its way through refining capacity globally. So issues flare up and then they tend to calm down a little bit. This one is still getting some conversations, but I don't think our perspective has changed from what we've talked about historically.

The other question is around Brent WTI just separately. You made the comment that you think they has the potential to widen out here over the next couple of months. What's driven the widening over the last couple of weeks? What do you guys see in Cushing happening? And then as you think about where that widening could occur, is it on the TI LLS piece of the equation or is it Brent LLS?

Yes. So I would say the team has driven the Brent TI wide, as if you look at the DOE stats over the last two weeks, we had two very large crude bills. So it kind of starts to tell you that as the Saudi start forcing more medium sour barrels into the market, it displays that some of this like light sweetening will begin to light sweet. And as inventory is build then it means we need to wider for EIR in order to start the incentiving refineries to take that light barrel back into the market. So I think that's what's happened. I do think it will get wider to the point where we are incentivized to go back to light sweet. And I would tell you that I would expect that the Brent TI could be a little bit wider and part of that is also due to the fact that we're building all this inventory in Cushing, and so maybe the Brent TI is a little bit wider than the LLS to Brent Spread.

The next question comes Chi Chow from Tudor, Pickering, Holt.

Just a couple of follow-ups there. I guess this is a really question for the second half of year. With the Line 9 reversal, what sort of volumes do you have committed on that line and what sorts of crudes are you expecting to move on? Is it Bakken or Syncrude or some other Canadian barrel?

So I don't think we've talked about our line commitment is. What we've said is when Line 9 comes up, we'll 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 mix of other Canadian light sweet Bakken.

And do those crudes, when you bring them in, are they going to change the yield at all or are they going increase the possibility from product standpoint on yields and volumes.

So 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. And so 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.

And then a couple of questions just for Mike. I guess, you've got to couple of debt maturities this year, what's the timing of those? And secondly, how do you think about sort of a minimum cash balance that you're comfortable operating at.

The timings, there's 400 is due next week. I believe it is. And then we have 75 that's couple of months later is on the timing. And what was the second question?

Just how you think about minimum cash balance? What sort of minimum levels are you comfortable operating at?

I mean we really don't have a minimum cash balance identified, but when you look at our operations, I think, we are comfortable in the range of around $2 billion. End of Q&A

At this moment, we show no further questions. I will like to turn the meeting over to you for any closing remarks.

Thank you, Hilda. We appreciate everyone calling in and those listening today. If you have 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.