Valero Energy Corporation (VLO) Q4 2010 Earnings Report, Transcript and Summary

Good morning, my name is Andrea, and I will be your conference operator today. At this time, I would like to welcome everyone to the Valero Energy Reports 2010 Fourth Quarter and Annual Results Conference Call. [Operator Instructions] Mr. Ashley, you may begin your conference.

Thank you, Andrea, and good morning, and welcome to Valero Energy Corporation's Fourth Quarter 2010 Earnings Conference Call. With me today are Bill Klesse, our Chairman and CEO; Mike Ciskowski, our CFO; Joe Gorder, our Chief Commercial Officer; Kim Bowers, our Executive Vice President and General Counsel and John Bernier, our Executive Vice President. 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 me after the call. Before we get started, 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 described in our filings with the SEC. Now I'll turn the call over to Mike.

Thanks, Ashley, and thank you for joining us today. As noted in the release, we reported fourth quarter 2010 income from continuing operations of $180 million or $0.32 per share. This number includes a $36 million after-tax gain or $0.06 per share on the sale of our interest in the Cameron Highway oil pipeline and an after-tax loss of $80 million or $0.14 per share from the mark-to-market impact of positions related to the forward sales of refined products. Excluding those items, our results would've been $0.40 per share. I should note that the loss from discontinued operations shown in the financial tables relates to the Delaware City refinery that was sold in the second quarter of 2010 and the Paulsboro refinery that was sold in the fourth quarter of 2010. The fourth quarter 2010 results from discontinued operations include a non-cash pretax charge of $980 million related to the Paulsboro refinery. Fourth quarter 2010 operating income was $378 million versus an operating loss of $135 million in the fourth quarter of 2009. The $513 million increase in operating income was mainly due to higher margins for diesel and gasoline, plus better discounts for low quality feedstocks, all of which contributed to a 49% increase in refinery throughput margins compared to the fourth quarter of 2009. Looking at the Gulf Coast margins versus WTI, the ULSD margin more than doubled from $6.33 per barrel in the fourth quarter of 2009 to $13.22 per barrel in the fourth quarter of 2010. The Gulf Coast gasoline margin increased nearly 50%, from $3.90 per barrel in the fourth quarter of 2009 to $5.76 per barrel in the fourth quarter of 2010. Looking at the feedstock discounts, the Maya heavy sour crude oil discount to WTI expanded 40% from $6.72 per barrel in the fourth quarter of 2009 to $9.40 per barrel in the fourth quarter of 2010. Another way to look at this is as a percentage of WTI, so the Maya discount increased from 8.8% of WTI in the fourth quarter of 2009 to 11.1% of WTI in the fourth quarter of '10, which is a 26% improvement year-over-year. So far in the first quarter of 2011, benchmark margins and heavy sour feedstock discounts versus WTI have been strong for this time of year. Compared to January 2010, Gulf Coast gasoline margins are up 75%, ULSD margins are up 152% and Maya discounts on an absolute basis are up 8%. I should point out that while margins and heavy sour crude discounts versus WTI have improved from this time last year, WTI has been trading in a discounted range when compared to other light sweet crudes in the medium sour. Our fourth quarter 2010 refinery throughput volume averaged 2.2 million barrels per day, an increase of 205,000 barrels per day or 10% compared to the fourth quarter of 2009. Refinery cash operating expenses in the fourth quarter of '10 were $3.64 per barrel. Cash operating expenses were lower than the third quarter and guidance, primarily due to a decline in energy costs. Our Retail and Ethanol segments also performed well and turned in excellent full year results. U.S. retail had $19 million of operating income in the fourth quarter and $200 million for the year, making it the second-to-best year for our U.S. Retail segment. Canada retail had $42 million of operating income in the fourth quarter and $146 million for the year, a record high for the Canada operation. Our combined retail operating income of $346 million for the full year 2010 is the second-highest year for our Retail segment. Something I should note in Retail is that we have changed how we report our credit card transaction processing fees. To reduce the volatility in our expenses, these fees have been reclassified from operating expenses to cost of sales. This change decreases fuel margin and lowers operating expense, but does not affect the operating income. The U.S. and Canada retail operating highlights presented in our financial tables have been updated to reflect this reclassification. Our Ethanol segment earned $70 million of operating income in the fourth quarter, making it the best quarter in 2010. We also achieved our highest quarterly production rate at 3.25 million gallons per day. For the year, the Ethanol segments set a record high, with operating income of $209 million. Since the initial acquisition less than two years ago, our Ethanol business has generated a total of $373 million in operating income and $427 million of EBITDA, which is 56% of the plant's total purchase price. In the fourth quarter, general and administrative expenses, excluding corporate depreciation were $164 million. The $25 million increase in G&A expense compared to the third quarter was mainly due to a $21 million increase in environmental reserves. Fourth quarter depreciation and amortization expense was $362 million, and net interest expense was $121 million. The effective tax rate on continuing operations in the fourth quarter was 46%, which was higher than the third quarter and our guidance due to the tax depreciation change that resulted in an unexpected tax loss, which required the reversal of previously recorded tax deductions. With respect to our balance sheet at the end of December, total debt was $8.3 billion. We ended the quarter with a cash balance of $3.3 billion, and we had nearly $4 billion of additional liquidity available. At the end of the fourth quarter, our debt-to-cap ratio, net of cash, was 25%. Regarding cash flows for the fourth quarter, we paid $28 million in dividends and received $877 million in cash proceeds from the sale of our interest in Cameron Highway and the Paulsboro refinery. I should also point out that we received a $160 million note from PBF for the Paulsboro refinery that is due in December of this year. Also in the fourth quarter, we issued $300 million of tax-exempt bonds related to the St. Charles refinery and capital spending was $629 million, which includes $125 million of turnaround in catalyst costs. For 2010, our capital spending was $2.3 billion. Within this amount, we completed two major regulatory spending programs. One was the newly installed scrubber for the cat cracker and coker Benicia, which also included energy efficient heaters for the crude and vacuum units. The other regulatory program was to reduce benzene levels in our gasoline pool for the federal MSAT II rule that began this year. For 2011 spending, our preliminary estimate is $2.9 billion, which reflects our decision to accelerate the Hydrocracker projects at Port Arthur in St. Charles to more quickly capture their economic benefits. The 2011, capital spending estimate incorporates significant turnaround activity in the first quarter and the early part of the second quarter at several of our refineries. The work includes significant reliability investments for a revamp of the St. Charles cat cracker and replacement of the Port Arthur coke drums. Following these turnarounds, we expect improved plant performance. Our companywide focus on cost savings continued to yield results. In 2010, we achieved $225 million in pretax cost savings, far surpassing our original goal of $100 million, and bringing our cumulative cost savings over the past four years to $619 million. Our 2011 goal is an additional $100 million in pretax cost savings. These efforts provide a valuable offset to increases and other costs that are a normal part of our business. In summary, we made significant progress over the last year on our strategic priorities of managing costs, maintaining our investment grade credit rating, optimizing our portfolio and advancing our economic growth projects. In 2011, our focus continues on safely operating our assets, improving reliability, capturing more cost savings and continuing to evaluate opportunities to improve the competitiveness of our portfolio. Now I'll turn it over to Ashley to cover the earnings model assumptions.

Thanks, Mike. For modeling our first quarter operations, you should expect the refinery throughput volumes to fall within the following ranges: The Gulf Coast at 1.31 million to 1.34 million barrels per day; Mid-Continent at 380,000 to 390,000 barrels per day; the Northeast at 190,000 to 200,000 barrels per day; and the West Coast at 210,000 to 220,000 barrels per day. The Gulf Coast rates include major turnaround activity at St. Charles, Port Arthur and Houston, plus it includes the effects of the recently restarted Aruba refinery that is continuing to build to planned rates. The Northeast consists only of the Québec refinery and the West Coast rates include the impact of a plant-wide turnaround at our Benicia refinery. The Mid-Continent rates reflect the impact of the plant-wide turnaround at our Ardmore refinery in March. Refinery cash operating expenses are expected to be around $3.85 per barrel in the first quarter. Regarding our ethanol operations in the first quarter, we expect total throughput volumes of 3.3 million gallons per day and operating expenses should average approximately $0.37 per gallon, including $0.03 per gallon for non-cash costs, such as depreciation and amortization. With respect to some of the other items for the first quarter, we expect G&A expense, excluding depreciation to be around $140 million. Net interest expense should be around $105 million. Total depreciation and amortization expense should be around $375 million. And our effective tax rate should be approximately 35%. Andrea, we will now open the call to questions. Andrea, feel free to prompt that we are opening the call for questions.

[Operator Instructions] Your first question comes from Blake Fernandez [Howard Weil Incorporated].

You mentioned the disconnect between WTI and Brent. And I'm trying to just get a little more color on how you see that potentially benefiting the Valero system and how sustainable you see that and how that plays into the export arbitrage dynamic that's currently in place?

Blake, good morning. This is Joe. Well, it is a little crazy out there, isn't it? I mean this morning, with the stats that we got, the already wide Brent WTI spread has increased a bit further. It's up at 1030 in the prompt month, so we continue to see a divergence there. If you look at what's going on, we've got high inventories of crude in Cushing, which are putting pressure on WTI, and then we've got strong demand for Brent, both from the Far East and it's pulling not only the Brent barrels, but also West African barrels. There's a high desolate yield in that crude and they've had a cold winter and so they're pulling those barrels. So there's been strength there. Now what we expect going forward a bit is that as the winter winds down, Chinese buying is going to pause for the lunar New Year and there’ll be some seasonal turnarounds and so we expect the Brent prices to decline here a little bit. However, the length in Cushing is going to continue to push WTI. Now if you look at what we're doing specifically, we’re running as much WTI as we can, and we're doing that at McKee, Ardmore and then we have barrels in Three Rivers at price off at WTI. So when I looked at what we did in the quarter, there was maybe around 300,000 barrels of WTI base crude that were running. So we're running as much as we can. And other than doing that, there's not much change to our crude slate.

My second question was on M&A. Just want to confirm that I'm kind of looking at this correctly. I know you state you have over $3 billion of cash on hand at the end of the year. It seems to me that any kind of potential acquisition would be fairly easy to put together an accretive deal, given that, that cash is sitting there earning money market rates. Is it fair to believe that you would be using that cash balance in order to potentially put together a deal?

This is Klesse. If we did a deal, that will be true up to a certain size obviously.

Your next question comes from Mark Gilman.[The Benchmark Company]

Eli Bauman for Mark Gilman. You expect to blend ethanol up to the 15% level at 2011. And given your expectations, where do you expect REN charges to be versus 2010?

This is Klesse again. We do not expect to blend up to the 15% level until there's a much clearer picture, as to -- like the whole product identification, car warranties, and so frankly, we want some regulatory cover on that. We learned our lesson with MTBE. As to RENs, the future is our guess is as good as yours. However, today, it's still economic to blend ethanol. And that obviously impacts the value of RENs.

Your next question comes from Evan Calio with Morgan Stanley.

A question on the CapEx. I know you gave a range -- but I believe you mentioned you expect to accelerate the spending with that $300 million being in the strategic economic growth category. If you did spend to that 29 level, does that change the estimated completion dates or move those forward for Memphis, St. Charles or if you could talk maybe a little bit more about where the acceleration might be within your projects?

It's a good question. The acceleration is basically on our hydrocrackers at Port Arthur and St. Charles. Our plan has been to complete the Port Arthur hydrocracker by the end of '12, and what we're trying to do is move it up into the mid year. And then the other piece of it is to complete the St. Charles hydrocracker by the end of 2012. We've mentioned many times that we have now approximately $600 million invested in each project and to complete the hydrocracker only at St. Charles is another $600 million and to complete the one at Port Arthur is about $800 million and then there's some other stuff that goes around it so that you add about another $200 million at each site. So that ties out to the table that Ashley has given you all, but yes, it's to accelerate those projects and have them both done by the end of '12. It's not on the hydrogen plants we’re doing at Memphis and at McKee. We've had fast track the whole time in the first quarter kind of March of next year, we should have those done and operating.

If we think about the cash balance question at 3.3. I mean, should we expect to -- if there's no acquisition to carry that cash balance as you know, the asset market really remains open and expanding? Or when would you consider returning to shareholders or either a buyback or even other internal projects? How should we think about that, as we move through 2011?

Well, we consider that all the time, as to the best use of our cash in the sense of a long-term shareholder value. So that's always on the radar screen. We're always looking whether we should increase dividend or buy shares or invest in our assets, but we are driven on long-term and that is a key part of our strategy. But generally speaking, we are holding higher cash, as I've stated many times, and we will tend to hold a higher cash balance than we have in the past. Now all that said, obviously we've been very open that we're looking at some of these assets that are on the market, and we intend to continue to do that because we do believe we can improve our overall competitiveness. This is a refining business. We get better access to the Atlantic Basin, with assets in Western Europe, so we're doing all of the things that we have talked about in the past.

Your next question comes from Jeff Dietert with Simmons. Jeffrey Dietert - Simmons & Company: It appears that you've sold some product forward and could you talk about your forward hedging and how much volume you've hedged of gasoline or diesel or how you've approached that?

What we have sold forward is approximately 10% of our estimated 2011 volume. It's not exactly ratable through all of the quarters, as we have different expectations as to each crack spread. And what we've done is sold the crack forward, okay, it's not per se the product. Obviously, we've made the wrong call. I won't deny that. We underestimated the Brent WTI spread. I won't deny that. We had been very successful doing this. I think some of you know this. But over the last five years, we've made over $600 million in what I call discretionary trading. We are marking it to market versus using hedge accounting. That's how we elected to do this and so we have our position. So it will impact our business this year. You can figure it out. These positions were put on last year. Clearly, we've had a much colder winter, so I would say so much for global warming. But the French strikes had a larger impact. As Joe mentioned a few minutes ago, WTI continues to be suppressed. Global demand has been good and so the year is starting out great and yes, we've hedged about 10% of our crack, but everything is looking so darn good. It's wonderful. But we did miss the Brent WTI going this wide. And Joe said that we expected to come down some and we do. There are issues in the market, but the forward curve also indicates it's going to come down quite a bit as well. So that's kind of where we are and I will acknowledge that it got so darn good and we love it but we have a position on, that’s not that great. Jeffrey Dietert - Simmons & Company: You still get the benefit on the another 90%. Joe, on the WTI versus Gulf Coast crudes, what do you think the market reaction might be? Do you think reduction on product going up -- oil going up seaway into Cushing reduction of volume is going up cap line? You anticipate the industry will react to these differentials between WTI and the Gulf Coast and bring that back down? Or is this going to be a long-term issue?

Yes. It's a very good question. I think it's going to be a longer-term issue. What we've got to do ultimately to get WTI back in parity is to have Cushing debottlenecked. And we've got length there today, and you've got more product that's going to be moving into Cushing from Canada. And so that market is going to remain long for some extended period. I think what we've got to do perhaps is quit looking at WTI as the benchmark by which to compare things because it's almost become irrelevant. If you look at the LLS relationship to Maya and Brent relationship to Maya, you maintain very much your normal relationships. It's only when you compare things to TI does it look distorted, and I'll give you an example. In 2010, the WTI, as a percentage of Maya, the discount was 11.6%. Today, it's 6.7%. But if you compare LLS to Maya, it was a 14% discount in '10. It's a 14% discount today. So what we're seeing with TI being so dislocated is cracks to some extent are being overstated. And we're looking at our business on a much broader basis because as I mentioned earlier, TI only really affects us on the three Mid-Continent refineries and we're doing everything we can to take advantage of that. But ultimately, to clean up TI, you're going to have to have Cushing debottlenecked and the crude's going to need to move out.

Jeff, I would add to that, that the industry has a way of taking out these arbs [arbitrage]. And so within the constraints of pipelining or transportation or trucking or railing, as these open up, you will see actions happen. Whether -- Seaway is obviously owned by individuals, Capline, you're going to see things begin to take away the arb, if it were to stay this high. But I would also point out that the forward curve doesn't indicate it's going to stay this soft. Jeffrey Dietert - Simmons & Company: Are you trucking or railing Mid-Continent crude down into the Gulf Coast?

If it will stay over $10, you're going to see a lot of things happening.

[Operator Instructions] Your next question comes from Doug Leggate with Bank of America.

I guess, a little bit of a strategic question going into the maintenance here in the next couple weeks or the first quarter I should say. Typically, this time of year, I guess the industry thinks about coming out of the heating season, doing the turnarounds, then coming out in maximum gasoline mode going into the driving season. But of course cracks are significantly more attractive on distillate right now than they are in gasoline. So I guess my question is how does that impact your thinking as you move into the summer driving season? I guess what's behind this is I'm wondering whether things could actually tighten up in the gasoline front, if folks stay a little bit more skewed towards maximizing distillate. Can you give us some color on how you might think about that? That’d be great.

Well, I think gasoline inventories are adequate and my take on gasoline is we need to get people back to work. We need people driving. If you actually look at the demand numbers for gasoline, we had an uptick -- and I'm talking about the U.S. We had an uptick in the last couple weeks of December, but gasoline demand in and of itself is very comparable to last year. So it's going to come up a little bit, as the economy keeps improving, but we don't necessarily see gasoline and I've never represented to any of you that gasoline looks that great. Distillates look a lot better because it's being pulled so heavily from the world, and even with gasoline, there's been more export opportunities. But I think you were also asking, Doug, about turnarounds per se and yes, there's quite a few cat cracker turnarounds going on here in the first quarter but a lot of them end as you get into April. So those facilities are back in operation by then and then it's also for all of us in the industry, we schedule cranes, we schedule workforce, we schedule things like that. So even though we have very good cracks for instance, today, at least relative to WTI, the schedule implies that you just got to stick to it. And it's time for maintenance anyway.

So I guess, is it reasonable to assume then if you look at the system-wide, and I guess it’s not just a Valero question, it's an industry question. If you look at the system-wide in the U.S., we're running about 30% distillate yield right now, which is about the highest we've seen in a while. Would you expect any meaningful change in that over the next several months?

I don't think so. You obviously have economics to make diesel fuel.

Aruba, you brought it back on now obviously. Can you give us a kind of update as to how you're thinking about that facility overall? Is it strategic? Or is it really held for sale? And just some color around the operation would be great.

We are bringing it back up. We're not quite all the way, as Ashley stated in the comments. But that asset to us is a very good asset. There's a lot of advantages, excellent tax structure, excellent coking operation, excellent harbors, excellent relationship with the government, so there's a lot of potential there. But we have stated that the refinery needs investment; it needs certain types of conversion units, and what Valero would be interested in is finding a partner to work with us on that facility.

Your next question comes from Chi Chow from Macquarie Capital.

I just wanted to expand a little bit on Doug's question on the distillate market. Bill, how are you viewing the sustainability of the global distillate market strength? And how do you reconcile that with the high inventory levels we're seeing here in the U.S.?

Well, I'll say a few things and then I'll let Joe add anything that he'd like to. Today, we are big exporter of distillates. There's a lot of draw. There's a cold winter. So seasonally, the volumes are generally moving to Europe. We've also sent some jet fuel to Canada, so things like that with the winter season here. What we have seen though, then as we move into our summer, we've had the ability to export volumes to other areas, South America and then down into the lower cone of South America. So the U.S. Gulf Coast refining industry can export and can export diesel and be competitive in the Atlantic Basin and that's what we've been able to do. We've also had gasoline that's primarily been going into the Gulf of Mexico region here export and that's been driven by some of the other refineries in the whole Caribbean, not operating, which has created an opportunity for us. And so, and you know all those places including Curaçao, the Isla refinery, which is still shut down. So we believe that we can export. We've said this for many years and that's why we continue to drive our cost structure down on the Gulf Coast because we think we can do it, but it does move around seasonally. Structurally though, Western Europe is somewhere between 500,000 and 600,000 barrels a day short of distillates. You want to add anything?

No. I mean, I think that's a great answer.

What were your export volumes in the fourth quarter for distillates?

We did slightly over 200,000 barrels a day.

And we produced around 700 in the whole system. So you can see how much we are exporting.

Mike, could you just go over that reclassification, the credit card fees again? I didn't quite catch that.

We moved the credit card fees from selling expenses up into cost of sales. So it's reducing our fuel margin a little bit and then taking out the volatility of our selling expenses.

Your next question comes from Cory Garcia with Raymond James.

Just in sort of relation to crude sourcing, I see you guys have obviously backed off your lighter sour barrels in response to sort of the narrow differential and the blowout in WTIs you guys already referenced. But just hoping you guys will be able to provide any commentary on how you see I guess the supply trend of the sour barrels, particularly in line of what’s happened in the Gulf and sort of Latin American supply. So just sort of pulling back on the lens if there's any structural thoughts, that’d be helpful.

Gulf production and medium sour is somewhat stabilized right now, right? We're not seeing a lot of activity that's going to increase production anytime soon. But if you look at generally production of crude in the Gulf region, you've got a pretty good situation I mean, Pemex heavy sour crude production’s stabilized now. It’s about 1.4 million barrels a day. Colombia’s been increasing their production of heavy sour crudes. Brazil’s increasing its production and then ultimately, we'll have a [indiscernible] (49:28) plan in place, which will bring the crude down from the North. So if we look short-term now on an ongoing basis, things look pretty good. Longer-term, it looks even better for the prospects for heavy sour discounts and sour crude discounts in general to remain pretty good. The medium sours would be affected if we had any kind of increase in Saudi production. And obviously, you read yesterday and so did we that there's been some conversation around the fact that they don't want the prices to get too high, which may increase production to some extent, which then of course would put additional pressure on the medium sour discounts. But we're fairly comfortable with what we're seeing right now with sour crudes.

[Operator Instructions]

Andrea, if there's no other questions, we'll be glad to conclude the call.

There are no questions.

Well, thank you for listening to the call today. Please contact the Investor Relations department if you have any additional questions. Thank you.

This concludes today's conference call. You may now disconnect.