Valero Energy Corporation
Q2 2007 Earnings Call Transcript

Published: 31 Jul 2007

[Operator:]

At this time I would like to welcome everyone to the Valero Energy second quarter 2007 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star and then the number one on your telephone keypad. If you would like to withdraw your question, press star and then the number two on your telephone keypad. Thank you. Mr. Ashley Smith, you may begin your conference.

[Ashley Smith:]

Thank you Julie Ann. Good morning and welcome to Valero Energy Corporation’s second quarter 2007 earnings conference call. With me today are Bill Klesse our Chairman and CEO, Mike Ciskowski our CFO and other members of our executive 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. There are also tables attached to the earnings release that provide additional financial information on our business segment. If you have any questions after reviewing these tables, please feel free to contact investor relations after the call. Before we get started, I would like to direct your attention to the forward-looking 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 managements expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provision under federal security laws. There are many factors that can cause actual results to differ from our expectations including those we’ve described in our filings with the SEC. Now, I’ll turn the call over to Mike.

[Michael S. Ciskowski:]

Thanks Ashley, and thank you for joining us today. As noted in the release, our second quarter earnings came in at $3.89 per share, which is the highest we’ve ever achieved in any quarter. These earnings are a 31% improvement over the $2.98 per share we earned in the second quarter of 2006, which was our previous record. You should note that these results include the operations of the recently divested Lima, Ohio refinery, which are classified as discontinued operations in the financial tables that accompany the earnings release. Given the strong margin environment in the second quarter, Valero’s throughput margin for continuing operations was $18.14 per barrel or 16% higher than the $15.59 per barrel earned in the second quarter of 2006. Regarding operation, mid-continent throughput levels increased over the first quarter due to the return of our McKee refinery to limited operations in mid-April at around 80,000 barrels a day. As more units were brought online, rates increased to approximately 150,000 barrels per day by the end of the quarter. We plan to run at this level until the propane de-asphalting unit is repaired, which we expect to occur late in the fourth quarter. Going through some of the key numbers in the second quarter; cash operating costs at the refineries were $3.87 per barrel, a $.09 per barrel increase over the first quarter was primarily due to higher energy and reliability expenses which were partially offset by an increase in throughput volume. General and administrative expenses excluding corporate depreciation were $177 million. The $32 million increase form the first quarter was mainly due to an increase in charitable contributions and charges related to the cancellation of a services agreement with New Star Energy. Total depreciation and amortization expense was $337 million and interest expense, net of capitalized interest was $83 million. The $25 million increase in net interest expense from the first quarter was primarily due to the financing associated with the accelerated share repurchase program or the ASR. Our effective tax rate on continuing operations was 33.8% in the second quarter, which was in line with our guidance on the last earnings call. Capital spending during the second quarter was $592 million, which includes $101 million of turnaround expenditures. As to our stock repurchase program, as you recall in April, we entered into an ASR with an affiliate, J.P. Morgan. That allowed us to immediately purchase 42.1 million shares of common stock for an up front payment of $3 billion. As mentioned on the last earnings call, the final price for the share’s purchase would be determined based on a discount to the volume weighted average trading price during the period it took J.P. Morgan to fulfill their requirements under the ASR. J.P. Morgan recently completed their requirements, which resulted in Valero settling the contract with a cash payment to J.P. Morgan of $94.5 million. So at the end of the day, the 42.1 million shares we purchased in April cost us $3.1 billion instead of the 3 billion. Included in the ASR, we have utilized nearly 4 billion of the 6 billion authorizations so far this year. Over the remainder of this year, we intend to purchase an additional $2 billion of our shares in the open market. With respect to our debt position, at the end of June, our total debt stood at $6.9 billion, which compares to $4.9 billion at the end of March. We’ve paid down $230 million of maturing debt in April, and we borrowed $3 billion on a bridge loan to fund the ASR program. Later in the second quarter, we repaid the bridge loan with $750 million of cash on hand, and the $2.25 billion of notes. We ended the quarter with a cash balance of just over $2.3 billion. Subsequent to the quarter end, we closed the sale of the Lima refinery. Proceeds after taxes, and other related expenses, are expected to be approximately $1.8 billion. As to our third quarter operations, turnaround activity is relatively light, so for modeling purposes, you should expect to see Gulf Coast refinery throughputs of approximately 1.55 million to 1.6 million barrels per day. Mid-continent throughputs should be around 450 thousand barrels per day, which is lower than the usual guidance for this region, due to the Lima sale. West Coast throughput should average between 280 and 290 thousand barrels per day, and our Northeast system should average in the range of 550 to 570 thousand barrels per day. Refinery cash operating expenses are expected to be slightly lower than the second quarter levels, at about $3.65 per barrel, mainly due to higher expected throughput volumes, and lower expected energy costs. With respect to some of the other items in the third quarter, we anticipate G&A expense to be around $160 million, which is $17 million lower than the second quarter, due to the non-recorded charges in the second quarter that I mentioned earlier. Net interest expense should be around $93 million, which is expected to increase from the second quarter, due to a full quarter effect of the ASR financing. Total depreciation and amortization expense should be around $345 million. And then, finally, for the third quarter, you should be using a 33% tax rate for your modeling purposes. Now I’ll turn the call over to Bill.

[William Klesse:]

Thank you Mike, and good morning. As Mike said, we had a terrific first half to the year, as strong demand continues to [supply issues] throughout the refining industry, tighten gasoline and diesel balances, and kept refining margins high. We’ve seen DOE data report record gasoline demand this driving season, despite retail prices being around $3.00 per gallon. At the percentage of disposable income, gasoline purchases are still low, about 50% of the late 70’s and early 1980’s level. As to Valero’s strategy, you can see that we are doing exactly what we have said we would do. With respect to our refining system, we said we would consider optimizing our refining portfolio. The Lima refinery was sold because it was not cored to our overall strategy. Going forward, we will continue to look at our portfolio of assets. Even though we have certainly had our share of operating issues and unplanned downtime, we have been investing in our plants to make the safer, more reliable, and more efficient. This year, our CapEx budget remains $3.5 billion. Over the next few years, we have several sizeable projects planned for our large Gulf Coast refineries, which will make those refineries more competitive and more profitable on a long-term basis. Also, as Mike said, we intend to purchase an additional $2 billion of our shares this year to complete the board-approved program. We are in a great refining environment of strong product demand, favorable discounts for low-quality feedstocks, and tight refining capacity worldwide. We see many of the underlying supply and demand factors in place for many more years, which makes us bullish about our future. Throughout our industry, projects are costing much more, are taking much longer to complete than originally envisioned. Some are being cancelled, many are being delayed. Of course, our business will continue to be seasonal, with plenty of volatility, as we’ve seen lately. However, please note, even with the recent margin fall, on any long-term historical basis, we still have excellent [cracks]. For Valero, our stock remains the best value in the refining sector when you look at the valuations for other complex refining outfits. This management team is committed to improving our performance and increasing our shareholder value for the long run. With that, we’ll go ahead and open it to Q&A.

[Operator:]

Thank you. (Operator Instructions) Your first question is from the line of Mark Flannery with Credit Suisse.

[Mark Flannery:]

Hi, I’ve got a question about the large amount of ethanol capacity coming on stream in the second half of 2007. Are you making any specific plans to try and accommodate that? Are you building out any infrastructure to convert over markets to allow you more discretionary blending? What do you think will be the impact of the new ethanol between now and the end of the year?

[Joseph W. Gorder:]

Hey Mark, this is Joe. You know, our forecast is that by year-end capacity will be about 560 thousand barrels a day. And really, to answer the question, from an infrastructure perspective, we’re really not doing anything to accommodate it. We’re blending 20-22 thousand barrels a day right now, on average, of ethanol, and frankly the infrastructure isn’t in place, and many of the markets we’re marketing it to accommodate it today. So we’ll do it, economically, where it makes sense, and where we can do it, but otherwise we’re not pushing it.

[Mark Flannery:]

Great.

[William Klesse:]

I want to add to that Mark. If you actually look at some of the numbers, even though ethanol price is falling significantly, if you take a vapor-pressure hit we’re getting here, at least in the summertime, relative to some of the other blending components and their values, come of the discretionary blending are still not economic. People think it is because they see the price of ethanol, but when you look at our full cocktail, it’s not necessarily so. So, just adding to Joe’s comments for you.

[Mark Flannery:]

That applies more to the summer then?

[William Klesse:]

I’m sorry, go ahead?

[Mark Flannery:]

That applies more to the summer than the winter.

[William Klesse:]

That’s absolutely right, but just remember the tradeoff in the winter is in fact the vapor pressure versus butane, and I’m sure you’ve looked and seen the butane price.

[Mark Flannery:]

Great.

[William Klesse:]

So, all I’m saying is these tradeoffs, you have to look at the whole cocktail. When you look at the price, it looks like it should work. But it’s a much tighter blend than you think.

[Mark Flannery:]

Okay that’s very helpful, thank you.

[Operator:]

Your next question is from the line of Neil McMahon with Sanford Bernstein.

[Neil McMahon:]

Hi, I’ve got a few questions. Really the first one is, given the deal of the day, so to speak, what is your overall strategy for potentially refining Canadian crude? It looks like with the Lima divestment, it is very much focused around the Gulf Coast, and sort of bypassing the whole of the Mid-continent. Maybe you could go into that in a bit of detail and I’ve got a few follow ups as well. Thanks.

[William Klesse:]

Well Neil, Lima refinement where it was located for us didn’t really have that great a fit for the Canadian crude. Pipeline has to be built over there; we really needed integrated strategy and that’s why Husky is just a much better fit for them, from the [loam to tomb]. Now for Valero though, we are very interested in runny Canadian crude. While some Canadian crude does come to the Beaumont area today to the extra pipeline, and we’ve actually run some at Port Arthur refinement. Our strategy, though, is to see Canadian crude get to the US Gulf Coast. And we’re talking with all these proposed pipeline projects that are trying to make that happen. And we will encourage those projects by our participation through frequent commitments to them. So that’s our strategy, to do that. We want to see the Canadian crude on the Golf Coast.

[Neil McMahon:]

Is there any particular reason why you’ve taken that approach—it’s very much aligned with what you’d seen Exxon Mobile to, and to be honest, what I think Shell are proposing as well. Is there any reason why you felt that that is the best move for you? I presume it reflects where your asset base is, but also is it because of the greater flexibility with sea-born access?

[William Klesse:]

Neil, that would absolutely be greater flexibility. Also, when we look at building things and as you said, you probably said, more hard weather, where we at Corpus Christie, Texas City, Port Arthur, St. Charles, all having coping capacity for us to do work around those refineries is at a much lower cost, and quite frankly, the U.S. Golf Coast is much more efficient.

[Neil McMahon:]

Maybe just a follow up question after your initial disposal. Are we to presume that portfolio rationalization could continue by looking at these sort of, take for example, a sort of strategy of disposing at below one hundred thousand barrel-a-day refineries and basically the ones that don’t look as strategic maybe are more, might be the next one—you might think about disposal, or are we done for the time being?

[William Klesse:]

We are continuing to evaluate the portfolios, I’ve said. You cannot put the criteria that you tried to put on them. We’re looking at all these assets and quite frankly, with the margins we’ve had, borrowing oil anywhere makes money. So we’re just trying to be certain that we are hanging on to the assets that long term will be the strategic fit for us. But we have not said anything below one hundred thousand doesn’t fit.

[Neil McMahon:]

Just one quick last one from me, you’ve made a great comment there in terms of how you look at your own valuation within the marketplace. I didn’t know if you guys had a look at some the European refineries and their valuations, which do seem above yours and some of your competitors in the US. Any sort of ideas for why that might be the case, or are you as confused as some others are with all that?

[William Klesse:]

Gene is going to answer that because he has looked at that. He runs our development function.

[S. Eugene Edwards:]

Well, we’ve looked a lot at the European assets and you’re exactly right—they traded much higher to earning or measures and our portfolio were both US assets—that’s the reason why we always said we’d be interested in acquiring in Europe. But we can’t, quite frankly, make the valuations work, so I have to have that strategy on hold until relative valuations change.

[Neil McMahon:]

Great, thanks a lot.

[Operator:]

Your next question is from the line of Doug Terreson, with Morgan Stanley.

[Doug Terreson:]

Good morning, guys. The oil industry operating in capital costs in Texas and refining have continued to move higher this year as you suggested in your comments. On this point, I wanted to see whether your expectations for full year capital expenditure have changed and if so, how? And second, I wanted to see how the company performed in relation to plan on the billion dollar income improvement plan during the first half of the year—if you have any information in that area too?

[William Klesse:]

Yes, Doug, I’ll make some comments about that. On the capital program for this year, our budget is $3.5 billion and we expect to be within that budget, fairly confident about that.

[Doug Terreson:]

And as to the second part of the question—

[William Klesse:]

Let me go ahead and start, then Rich will add in. In a billion dollars, what we have done is we’re getting our tracking system in place so that we can be right on top of that. A lot of those projects require capital, and so it’s skewed to the latter part of the five-year program that I said. So in the first couple of years, you’ll see some efficiency things, and little benefits that we get from just general improvement and our reliability. Once we get these new coke drums in, you’re going to see reliability improve significantly at St. Charles and at Port Arthur. And then in the latter part you’ll see some stuff that comes in from power recovery and a couple of our caps and those type of projects. But we are getting the tracking system in place so that we can do it. The one thing I can tell you that we have done, is we’re looking at how we do business at all of our refineries. And between our controller, Clay Killinger and [Reg]—they have gone ahead and changed the business model on our yield accounting and procurement effort and we’re going to bring that in—it’s little when you look at the scheme of things—we’ll save $10 million a year by bringing this into corporate. But what we’re going to also get is a much great focus on procurement as you can imagine our spend is tremendous. We’ll get that. And the other thing is that we’re trying to get these refineries and the refinery operations to focus on the operation of the refinery, not worry about some of these ancillary things around our business. So all of that is happening. Do you want to add anything, Rich?

[Richard Marcogliese:]

No, I just want to emphasize the point on the billion dollar program, that it’s not a ratable 20% per year over the next five years that it’s probably going to be more back end loaded, because there is a capital component on some of it, as Bill mentioned.

[Doug Terreson:]

Ok, and just quickly. On St. Charles and Corpus Christie, the expansions there, those projects tracking the level you expected in timing as well?

[Richard Marcogliese:]

Yes and, Doug, those are the expansions that are envisioned for St. Charles and Port Arthur, and Doug, just to recap very quickly. We are evaluating a large gas-oil hydro reactor investments for both plants. We’re actually using a unified design, where we are building the exact same units at Port Arthur and St. Charles. The projects will be an access of $1 billion each. At this point we only have advanced approval from our board, to put certain [load lead] equipment on order and we will be reviewing this project with our board prior to the end of the year, for consideration of full funding.

[Doug Terreson:]

Okay.

[Richard Marcogliese:]

The timing of these projects—these would be commissioned in the early 2010 timeframe.

[Doug Terreson:]

Ok, thanks a lot.

[Operator:]

Your next question is from the line of Jeff Dietert, with Simmons.

[Jeff Dietert:]

Good morning. Jeff Dietert with Simmons. You mentioned that your maintenance activity was going to be lighter in the back half of the year, relative to the first half of the year, and I was going to see if you could provide a little bit more detail there, and ask if you had any visibility into labor, parts, and equipment, if your consent, continuing to see cost inflation there.

[William Klesse:]

Sure, Jeff, I’ll make a few comments on that. First of all on the second quarter turnaround activity was pretty light. Really what we worked on was small crude unit turnaround at Paulsborough, hydro reactor in Venetia and the resin-refinery in Corpus Christie. There really isn’t any major maintenance in the third quarter to speak of. We’ll close out the year with some modest activity in the fourth quarter. We have a hundred thousand barrel a day crude unit in Paulsborough that will be down in October. Venetia’s fluid cooker which is at thirty thousand barrel a day unit will be down in October and we’ll have two cat unit outages, one in Texas City and then one at Wilmington down for turnaround in October and November respectively. As far as labor resources for turnarounds—what I would say is that, I think, the cost inflation has plateaued. There aren’t any indications of it abating, however, so I think we’ve just established both a higher plateau of cost. Likewise, we do not see any real changes in productivity, you know productivity is lower by historical standards, and we don’t see that situation changing. Our discussions with the major contractors still emphasize the need that we need to commit early, to lock up contractor availability in advance and it just represents continuing typed market for those types of maintenance and construction services.

[Jeff Dietert:]

Two other things, that it appears OSHA has tightened up its efforts in monitoring operations and procedures and that you’re also dealing with forced reductions in emissions. Could you address those two topics?

[Richard Marcogliese:]

Yea, I can make a comment on the OSHA piece. You know, OSHA is out with a national emphasis program on refining for more rigorous examination of process safety management compliance. We have been tracking these developments with OSHA, and I am glad to say that in line with that, we had our first OSHA star program re-certification just completed in our Houston refinery in July. And our refinery was recommended for re-certification against OSHA’s national emphasis template, so we are prepared for what OSHA is looking for, and in our first opportunity to be evaluated, we were successful.

[Jeff Dietert:]

Thanks Rich

[Operator:]

Your next question is from the line of Paul Chang with Lehman Brothers

[Paul Chang:]

Thank you. Rich, you talk about the fourth quarter turn around, can you give us the number of days on those [unit] that is going to be on the turn around?

[Richard Marcogliese:]

Sure, in general, and these are rounded for simplicity. The Paulsboro crude unit is 100,000 barrel a day unit is going to be a nominal 30-day turnaround. The Benicia [fluid cooker], that’s also going to be a 30-day turnaround. Texas City’s CAT unit and [alkey], its about 80.000 barrel a day CAT capacity, that will be about a40 day turnaround. And in Wilmington’s case, this is 55,000 barrel a day CAT cracker, its going to be a45 day turnaround. In this particular case, the duration is longer because we are going to go through a large retrofit on the associated out relations unit.

[Paul Chang:]

Thanks a lot. Richard, how about in the first quarter 2008, any kind of insight on how that might look?

[Richard Marcogliese:]

I don’t have the specifics on that at this point, but I don’t anticipate it’s going to be any step out quarter from a maintenance point of view at this point.

[Paul Chang:]

So, will be normal to maybe light?

[Richard Marcogliese:]

Well, let me say it, I’d say that’s a good characterization. Looking forward we’ll have a significant increase in turnaround activity in 2009 and 2010, with a couple of large refinery turnarounds.

[Paul Chang:]

And maybe this is either for Rich or for Mike. Any kind of rough estimate, what is the most in opportunity cause in the second quarter, relate to the planned down time, and also to the unplanned down time.

[Richard Marcogliese:]

Ok, well let me give you some general figures. If we look at all of our unbudgeted down time in the second, you know, including things such as project schedule slipping on new capital projects, you know with the wide margins we have experiences, the impact is about $590 million in the second quarter. For the first half, that number is about $850 million.

[Paul Chang:]

And Rich, those are after tax, right?

[Richard Marcogliese:]

No, those are pretax.

[Michael S. Ciskowski:]

Pretax. And the other thing you said there is it includes where we’ve had projects slip. So our big hydro current on the Gulf Coast where they slipped are included in that number.

[Paul Chang:]

Ok. Mike,

[Michael S. Ciskowski:]

Our earnings power that we have.

[Paul Chang:]

I see. Mike, is any offset sales, gained or lost relate to the [lima] in the in we reported.

[Richard Marcogliese:]

Nothing in the second quarter.

[Paul Chang:]

So they are still up?

[Richard Marcogliese:]

No, all we have done is just shown on the earnings tables, where we separated the plain continuing and this continued operations.

[Paul Chang:]

Right, 187, in other words, that is the actual earnings in the quarter by Nima.

[Richard Marcogliese:]

That’s correct for taxes, that’s correct.

[Paul Chang:]

Ok, a final one, just a quick one. Can you share with us what is the rut for number for Nima in the second quarter, and then realize margin?

[Richard Marcogliese:]

I can, I think throughput was roughly 158,000 barrels a day, and their operating income was $300 million in the second quarter.

[Paul Chang:]

Ok, thank you.

[Operator:]

Your next question is from the line of Arjun Murti with Goldman Sacks.

[Arjun Murti:]

Thank you, I have two questions. First, do you have a fully diluted chair count at the end of the quarter, or whatever recent period you might have?

[S. Eugene Edwards:]

Yea, we do. And fully diluted, ok. For the second quarter on a fully diluted bases, weighted average for the quarter is 578, and then at the quarter end, its roughly 566.

[Arjun Murti:]

Thank you very much. You allude to, in your press release widening, light heavy and sweet sour spreads, and the other few were narrower in the second quarter. I think Mexican production is well documented to be in decline. Do the outlook for light heavy and sweet sour, or really light heavy spreads in particular, should we assume that is dependent on OPEC actually raising their production here over the remainder of this year. And it is noted that WTI has shot up here to $78 a barrel from all these spreads are a little wider, but maybe not as wide as they were in past periods when WTI was this high.

[S. Eugene Edwards:]

You know I think we get a very strange situation the second quarter with TI, right? I mean everybody looks at Maya discounts relative to TI and heavy sour discounts relative to TI, and we know that TI was just dislocated from all the other sweet crude’s, because if you look at Branton LLS, you had a significant divergence from TI. So, when we look at the heavy sour discounts, and we say ok, we averaged 960 Maya discount during the second quarter, what we really would do is look at that number and adjust it to the other suite. So if you had discounts that were probably much more normal than we guess, you know, $14, $15 heavy sour discounts. And Maya itself has been a little bit more expensive compared with some of the other heavy sours also. I mean we are buying, when we are delivering Maya in at $11 off, we can get other heavy sours in at 14+ off. So, you know the light heavy spread, even though it looked off, I think it was really more related to TI than anything.

[Arjun Murti:]

That’s helpful to second quarter. And do you look forward to the rest of this year? Do you think the widening is dependent on OPEC raising productions?

[S. Eugene Edwards:]

Well, that is a good question. I think that if they do raise production, a lot of it is going to be Saudi Arabia, which is building some of the heavier crude’s, which directly puts more pressure on the heavy crude’s discount.

[Unidentified Company Representative:]

And remember, the Saudi crude’s are basically medium sours, even though they call Saudi it is a medium sour crude, and you have seen mars start to move out a little bit, anyway.

[Arjun Murti:]

Those are great points, thank you very much.

[Operator:]

Your next question is from the line of Doug Leggate of Citigroup

[Doug Leggate:]

Thank you, morning guys. Couple of industry questions really. You mentioned on the press release, some of the issues that had arguably included margins during the quarter. and can downtime be one of them. But production, at least according to the EIA for gasoline is still up year over year. Can you give some colors as to why you think that may be, and I helpful

[S. Eugene Edwards:]

I think a lot of the production being up year over year is the deported bloodstock. In a lot of our bottles its 40 and really shows that the gas link production when it is terminally blood that was ethanol, that’s the way that the deal reports, and when you need blood that’s de-ethanol it shows up as gas rate production, taking it to a US refinery to low and fairly black

[S. Eugene Edwards:]

But with 5% utilization.

[Unidentified Company Representative:]

Well I can tell you, everybody is running conversions, where you had some issues on crude, you’ve been running your catch in reformers because you’ve had such an attractive gas unit enlargement. So when you look at that utilization number, where they talk about crude, it can effect in our conversation of desolate production, but when you look at the gas rate, the conversion units are wrong. Might have a problem, like in the Chicago area, which lead to the entire margins in the upper Midwest

[Doug Leggate:]

Ok, great, I guess a related question that wasn’t quite my follow up, but you mentioned imports there. Imports are down quite markedly from the date for us that we picked up last week, but do you see any dynamics particularly, do you see the imports going in one particular direction over the next couple of months or are you pretty isolated from that?

[S. Eugene Edwards:]

I think there were heavy turnarounds in Asia and Europe earlier in the year, which reduced the buy obviously and the other factor is Mexican demand is up on imports quite substantially versus last year. The latest numbers are around 300,000 barrels per day. Also, imports into Nigeria where oil-refining capacity is down and imports to places like Iran, Singapore and other areas that you know that are just becoming bigger importers of gas than they have been in the past. This takes barrels off the market until you get them to the United States.

[William Klesse:]

Which then causes the prices to have to get higher to attract the imports.

[Doug Leggate:]

I guess where I’m going with that is I’m trying to get an idea of your thoughts longer-term. 2007 was a little more transitory because of these import issues, which arguably is why inventories are so low. Is that something that you think is repeatable or sustainable or do you think it kind of goes back to normal?

[S. Eugene Edwards:]

Well, all the things I’ve mentioned are because of world economic growth. Gasoline demand increasing faster than supply, which leaves fewer barrels left to come to the United States.

[Doug Leggate:]

OK, my follow-up is related to the summer-winter issue. Clearly, there is a little bit of a blend premium associated with the summer blend nowadays. But when do you guys start transitioning back to winter grade? When would you expect to be fully producing winter-grade gasoline again across your system?

[S. Eugene Edwards:]

Usually around mid-September.

[William Klesse:]

And it varies.

[S. Eugene Edwards:]

Northern California is September/October.

[William Klesse:]

Southern California is a month later and then in our other markets it starts in mid-September as Gene said and then we go through a couple of steps so I think that by the end of October, we’re making Winter gasoline in the mid-continent and East.

[Doug Leggate:]

Great, thanks a lot.

[William Klesse:]

If you need to know exactly who gets what, Ashley can give you exact dates by now.

[Doug Leggate:]

I’ll follow up with him. Thanks very much.

[Operator:]

Your next question is from the line of Mark Gilman with Benchmark.

[Mark Gilman:]

Guys, good morning. Can you, I guess I’m following up on a point that either Bill or Rich made, neither of the mild hydro pro-reactors at St. Charles or Houston came on in the second quarter?

[S. Eugene Edwards:]

No, Mark, where we are on those, the Houston unit came up towards the back part of May. So it is in service and running well. And the St. Charles unit is actually in start-up as we speak and it should be full commissioned by next week.

[Mark Gilman:]

OK, thanks. Can you give me a rough or precise idea how much physical WTI/WTS you actually ran in the second quarter both in the mid-continent and the Gulf Coast regions?

[William Klesse:]

We wouldn’t have run any in the Gulf Coast, Mark, WTI or WTS and we’ll see if we can try to get you a number here.

[S. Eugene Edwards:]

We don’t have it broken out by crude at this level. Ashley can follow-up and dig that number out of the system for you.

[Mark Gilman:]

OK, but zero in the Gulf Coast, TI and TS?

[William Klesse:]

We cannot, we can’t really get it there today, people are looking at a lot of things to try to move this and today you can’t get it down.

[Mark Gilman:]

All right, I’m assuming that there is a pretty large working capital, liquidation number in the quarter from a cash-flow standpoint Mike, is that accurate?

[Michael S. Ciskowski:]

No, no when you look at the items that have been disclosed in our earnings material, they pretty much come to the change in cash flow. A change in cash of $640 million. So we don’t have a huge working capital requirement in the second quarter.

[Mark Gilman:]

OK, and just one final one; any derivative effects of any kind impacting the second quarter results?

[William Klesse:]

Are you talking there about our hedging?

[Mark Gilman:]

Well, Bill, broadly derivative including hedging and anything else.

[William Klesse:]

Well, we still, when we buy crude oil and stuff, we still put paper against that; it’s how a business is run. But I think you’re talking about…

[Mark Gilman:]

Yeah, outside of that.

[William Klesse:]

Outside of that, it’s just a minor, little number.

[Mark Gilman:]

Okay guys. Thanks a lot.

[Operator:]

(Operator Instructions) Your next question is from the line of Paul Sankey with Deutsche Bank.

[Paul Sankey:]

Hi everyone. I think we’ve just about hit all my questions, actually, but one that’s outstanding is the way the curves have shifted. Is there any meaningful impact for you from the moves that we’ve seen to backwardation in crude markets? As a follow up, any observations you could make about the fact that crude inventories, ostensibly, are quite high in the U.S., but we’ve seen obviously very high prices. At the same time, gasoline inventory is not super loose by any means, but a cratering of the price there - any observations you can make on those would be great.

[Unidentified Company Representative:]

Well, I’ll speak to gasoline. Gasoline pries are very low. They’re very low on a historical basis. So the decline that we’ve seen in the margins there isn’t necessarily fundamentally driven. We’re entering the season where we will start blending butanes back in, and so we know that will have an effect on the inventories. Nonetheless, we go into that period with inventories at very attractive levels relative to previous years. On the crude, the change in the market structure just means that we’re not paid to carry it right, so what we’ll do, what we always do, is we aggressively manage the inventory to the market structure, as we’ve done on the product side.

[Paul Sankey:]

Right, so I’d expect to see inventories continuing to fall, but maybe the price, nevertheless, staying high.

[Unidentified Company Representative:]

Yea, I think there’s no incentive to hold the inventories, so your observation there is correct. I will say, because Mark Gilman usually asks this question, on Contango versus backwardation, at least for the Mid-continent refineries, it does increase our effective crude cost into those two clients.

[Paul Sankey:]

There’s been talk of the stocking of gasoline as well. Would you say that (inaudible) the same part of the impact that we’ve seen on gasoline prices?

[Unidentified Company Representative:]

I don’t know if just the de-stocking is an issue, but we certainly have said to our plants, we’re not holding gasoline at the refineries. Right? It’s the end of the July and into August here, so we kind of keep the product moving to the market. And I would assume other companies look at it the same way.

[Paul Sankey:]

Great, that’s great, thanks. And just the final one from me, utilization was very poor in the first half. It was kind of lumpy between companies, but would you argue that perhaps there’s been a secular shift towards a lower available capacity in the U.S.? Or do you think it was just a uniquely rough first half?

[William Klesse:]

I’ll try and answer you, and I’ll ask Rich for some help here, but clearly when you look at crude, you look at the whole system. You have to treat your products, between the [dissolance], which basically we’re taking all the salt around the [dissolance]. If you take a seven PPM, eight PPM at the refineries, you get crude, for gasoline we’re doing the same. So anytime you have a hydrotreater problem in your refinery, you can’t make spec products. And so it does cause you, if your inventories are full, or if you have opponent inventories, you have to cut back. There are no other options. But it is a more complex refining environment now with all this severe hydrotreating. You want to add anything Rich?

[Richard Marcogliese:]

Well yea I would. I think there is an impact in the market associated with the productivity in the maintenance workforce; the quality of the work. Revamps are being done to existing units. We’ve found that even the quality of engineering is not what it was. And I think turnaround durations, directionally, are becoming longer. And I think that’s a factor as well.

[Paul Sankey:]

As a rule of thumb, what would you say is the impact on [percentage] utilization?

[Richard Marcogliese:]

It’s kind of hard to quote an exact number. We know that they’re qualitative factors.

[William Klesse:]

I don’t think, Paul, we would give you any better number than your own. But the things we mentioned to you are the real world that we work in.

[Paul Sankey:]

Okay, thanks guys.

[Operator:]

Your next question is from the line of Nicky Decker with Bear Sterns.

[Nicky Decker:]

Good morning. Most of my questions have been answered as well. Just one on the ARB situation as you see it. Maybe you could give us an update as to where you see as attractive to send product? Well, I mean, the ARB into the US have been largely closed here recently. Primarily our exports are related to distill and those typically go South.

[Nicky Decker:]

Okay. Have you seen any change in the numbers after the Exxon refinery outage in Europe?

[Richard Marcogliese:]

Well, I haven’t seen any change in the numbers, in talking to the guys on the trading floor, though, they’re seeing less barrels loaded to cover this direction. Okay? So they try to keep a close eye, stay in till with the market and look for what might be moving and there hasn’t been length in Europe really to speak of this summer, and it’s certainly not changing now.

[Nicky Decker:]

Okay. If I could just ask one other, on the results. Just looking at the operating costs on the West Coast. That was really a standout in terms of the higher than expectations, and it doesn’t look like its particularly related to volumes. Maybe you could talk about what’s driving up those costs.

[Richard Marcogliese:]

I was going to say. There are two factors associated with that. There is an energy consumption factor, which just related to lower internal plant fueling and more natural gas purchase. This is primarily associated with Venetia. And then there was also a litigation reserve that was established for a labor issue out on the West Coast that impacted the results.

[Nicky Decker:]

So it sounds like part of that we should carry out into future quarters?

[Richard Marcogliese:]

Well, the litigation of course is a one-time issue, and as far as the energy costs go, we make internal market calls based upon the value of propane and butanes, whether they’re better served as internal plant fuel, or whether we should sell them as products. We just track the market and do the most economic thing.

[Nicky Decker:]

Okay, thank you.

[Operator:]

Your next question is from the line of Ann Kohler, with Caris.

[Ann Kohler:]

Good morning, gentlemen. A question on your growth and acquisition strategy. You kind of highlighted before that currently the valuations in Europe are a bit high. It’s my understanding, and correct me if I’m wrong, that you’ve expressed some interest in a South American refinery, and if you could just clarify if that is true, and if so, what your thought process is behind that, I guess would be some new refinery in Central America.

[Unidentified Company Representative:]

We have participated with Pemex/PMI, looking at this refinery in Panama that is being proposed. So we’re taking a look at it, and that’s the extent what our thought is. It’s an opportunity and we’re looking to see what we think as we get into it.

[Ann Kohler:]

And is there any sort of timing on the process for the facility?

[Unidentified Company Representative:]

They have a schedule. There’s a meeting in September, and it drags on. But there’s—if you’re worried, we’re not about to jump into a grassroots refinery that doesn’t have more assurance as to margin, going forward. But it’s an opportunity and Latin America, we already told you, we know that Mexico is importing three hundred thousand barrels a day of gasoline now. We look to Central America, South America—so there are opportunities here.

[Ann Kohler:]

So this is an opportunity to participate in the growth in that particular market versus using the opportunity to basically import products into the US?

[Unidentified Company Representative:]

Right, we wouldn’t do that if the place didn’t import products into the US. That is correct.

[Ann Kohler:]

Okay. Thank you very much.

[Operator:]

Your next question is a follow up from the line of Mark Gilman with Benchmark.

[Mark Gilman:]

Hey, Bill. It looks to me as if some of the ULSD premiums are beginning to tighten up and shrink a bit. Perhaps in response to the industry having overdone it a little bit in terms of supply capability. Do you think there’s any chance as we go toward the winner that we may see ULSD being downgraded from a value standpoint and maybe sold into the aiding oil pool?

[William Klesse:]

My answer to that would be yes. But it has to do with logistics more products available. But people will tend to sell it in the command. If you look at our whole system, that by the end of this year, just to give you an example, we will be able to make ULSD in every single refinery or car diesel in every refinery except the Northeast. So, you can, and I think the industry done that. You want to add something, Gene?

[S. Eugene Edwards:]

I think you’re right. The East Coast is really the only place where they will make high sulphur diesel. It's done in great degree.

[William Klesse:]

So we agree with your observation.

[Mark Gilman:]

Thanks, Bill.

[Operator:]

There are no further questions at this time. Ms. Smith, are there any closing remarks?

[Ashley Smith:]

No, we will just conclude the call. Thank you very much for listening to our call.

[Operator:]

Thank you for participating in today’s conference call. You may now disconnect.