Welcome to the Valero Energy Corporation reports third quarter 2011 earnings conference call. My name is John, and I will be your operator for today's call. At this time, all participants are in a listen only mode. Later, we will conduct a question- and- answer session. Please note that this conference is being recorded. I will now turn the call over to Mr. Ashley Smith, Vice President of Investor Relations. Mr. Smith, you may begin.
Thank you, John. Good morning and welcome to Valero Energy Corporation's third quarter 2011 earnings conference call. With me today are Bill Klesse, our Chairman and CEO, Mike Ciskowski, our CFO, Gene Edwards, our Chief Development Officer, Kim Bowers is Executive Vice President and General Counsel, and Jean Bernier, 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. I will turn the call over to Mike.
Thanks, Ashley, and thank you for joining us today. As noted in the release, we reported third quarter 2011 net income from continuing operations of $1.2 billion or $2.11 per share compared to $0.53 per share in the third quarter of 2010. Our third quarter 2011 operating income was $2 billion versus operating income of $590 million in the third quarter of 2010. The third quarter refining throughput margin was $13.24/bbl , which is a 63% increase over the third quarter of 2010.
The increase in throughput margins over the third quarter of 2010 was due to higher margins for diesel, jet fuel, and gasoline, plus wider discounts for heavy- sour crude oil, residual feedstocks, and light sweet crude oils in the Mid-Continent and in South Texas. In the third quarter of 2011, the Gulf Coast gasoline margins per barrel versus LLS increased 89% to $8.20 from $4.35 in the third quarter of 2010. The Gulf Coast ULSD versus LLS margins per barrel increased 56%, from $9.12 in the third quarter of 2010 to $14.19/bbl in the third quarter of 2011.
So far in the fourth quarter, Gulf Coast margins have moved lower, averaging around $1/bbl for gasoline and nearly $13/bbl for ULSD. The Maya heavy sour crude oil discounts versus LLS increased to 22%, from $11 in the third quarter of 2010 to $13.48/bbl in the third quarter of 2011. The Maya discount has narrowed some in the fourth quarter, with the average down to around $12/bbl .
These discounts are important in our Gulf Coast region, where we have significant capacity to process heavy sour crude oils. Another benefit for Valero came from Mid-Continent and Eagle Ford crudes pricing at a substantial discount to LLS. Over the last year, the WTI discount to LLS has increased by nearly $20/bbl , from $2.58 in the third quarter of 2010 to $22.47 in the third quarter of 2011. The WTI discount significantly enhanced the profitability of our McKee and Ardmore refineries, both of which process WTI or cheaper crude oils.
The fourth quarter WTI discount to LLS has averaged around $25/bbl . But recently, the spread has narrowed, and yesterday closed at less than $19/bbl . We also continued to increase the use of the discounted Eagle Ford crude in our system. During the third quarter, we processed an average of 46,000 b p d of Eagle Ford, primarily at Three Rivers, but also some at Corpus Christi. That is an increase of 9,000 pd over the second quarter and an increase of more than 40,000 b p d since 2010.
This local crude replaced more expensive imported sweet crude, saving Three Rivers and Corpus around $15/bbl in the third quarter. We also took delivery and ran discounted sweet crudes from the Strategic Petroleum Reserve in the third quarter. Valero purchased 6.9 MMbbl at a discount of over $5/bbl to LLS, providing $35 million in additional refinery throughput margin in the third quarter. At our Aruba refinery, operational improvements combined with better commodity prices resulted in Aruba generating an operating profit this quarter.
In the North Atlantic region, we had a smooth transition with the addition of the U.K. and Ireland businesses, including the Pembroke refinery. The refinery has run well, and we continue to integrate the businesses into our operations. On the West Coast, our throughput margins versus benchmark cracks performed well, mainly on wider crude discounts and increasing the use of such crudes. In addition, operational improvements at our West Coast refineries helped to enhance our liquid volume yields. One final comment on refining margins is that international demand, particularly in the developing markets, has been the key driver for growth in 2011 and helped to elevate the margins to the levels we have seen so far this year.
Our cost-efficient refining portfolio will continue to take advantage of both domestic and international opportunities available in the marketplace. Our third quarter 2011 refinery throughput volume averaged 2.6 MM b p d, up 389,000 b p d from the third quarter of 2010. The increase in throughput volumes was due to a combination of economic incentive from stronger margins, the addition of capacity from the acquisition of the Pembroke Refinery on August 1, and the restart of operations at the Aruba Refinery.
Refining cash operating expenses in the third quarter of 2011 were $3.65/bbl , which was lower than the second quarter of 2011, and our guidance, mainly due to higher throughput volumes. Our ethanol segment reported record-setting quarterly earnings with $107 million in operating income in the third quarter, which was up $60 million from the third quarter of 2010 and up $43 million from the second quarter of this year on higher gross margins.
Our retail segment reported a solid third quarter with $97 million of operating income. U.S. retail had $59 million of operating income in the quarter, and the Canadian retail operation earned $38 million of operating income. In the third quarter, general and administrative expenses, excluding corporate depreciation, were $161 million. Depreciation and amortization expense was $390 million. Net interest expense was $88 million, and the effective tax rate on continuing operations in the third quarter was 36.4%.
Regarding cash flows in the third quarter, capital spending was $684 million, which includes $69 million of turnaround and catalyst expenditures. Also, in the third quarter, we paid $28 million in dividends and $268 million to purchase 13.5 million shares of our common stock, or 2% of outstanding shares. We also spent $1.6 billion to acquire the Pembroke Refinery and related marketing assets, which included approximately $900 million for working capital and other assets. With respect to our balance sheet at the end of September, total debt was $7.6 billion, cash was $2.8 billion, and our debt to capitalization ratio net of cash was 22.4%.
At the end of the third quarter, we also had over $4 billion of additional liquidity available. As referenced in the release on October 1st, we acquired the Meraux Refinery and related logistics assets for $586 million in cash. This payment included approximately $260 million for a preliminary estimate of inventories and other assets. We do expect to receive in the fourth quarter a favorable true-up adjustment that will reduce our price by approximately $40 million. Our completed growth projects are beginning to add to our earnings power.
We realized the benefits from our St. Charles FCC revamp project during the third quarter, its first full quarter of operation. These benefits included improved liquid volume yield, lower energy costs, lower catalyst costs, and reliability benefits. Using third quarter 2011 prices, we estimate the annualized EBITDA benefit from this project is approximately $150 million. Our remaining growth projects remain on budget and on time to complete in 2012, and we expect these projects to generate significant earnings and cash flow growth when started up.
The hydrogen plants at Memphis and McKee should be completed by the end of 2011. Our two hydrocracker projects at Port Arthur and St. Charles are set to finish in the second half of 2012, along with the Montréal Products Pipeline and the Diamond Green Diesel joint venture. Most of the projects were designed to capitalize on high crude oil and low natural gas prices while producing diesel and gasoline to meet the growing global demand. In summary, we had an excellent third quarter. We took the opportunity to return cash to our shareholders via stock buybacks, and last week, our Board of Directors tripled our quarterly dividend rate to $0.15 per share.
These decisions are a result of our strong financial performance, favorable industry conditions, and the significant contribution that we expect from our major growth projects that are scheduled for completion next year. Regarding strategic activities, we added another quality asset to our portfolio and then further improved our earnings power with the acquisition of the Meraux Refinery. This is a flexible, high-quality asset with a distillate-focused conversion capacity, including a 34,000 bpd hydrocracker.
This first quartile refinery fits well into our Gulf Coast system and has excellent potential for synergies with our nearby St. Charles refinery. We have also restarted a formal process to seek strategic alternatives for our Aruba refinery. In conclusion, the significant contributions expected from our major growth projects, which are independent of the WTI-priced crude discounts, selective strategic acquisitions that improve earnings power, our strong financial position, and our investment-grade credit rating provide an excellent combination for future earnings and cash flow growth. Now I'll turn it over to Ashley to cover the earnings model assumptions.
Okay. Thanks, Mike. For modeling our fourth quarter operations, you should expect the refinery throughput volumes to fall within the following ranges. The Gulf Coast should be somewhere between 1.52 MMbpd- 1.56 MMbpd , Mid-Continent at 430,000 bpd- 440,000 bpd , the West Coast at 270,000 bpd- 280,000 bpd , and the North Atlantic at 440,000 bpd- 460,000 bpd in the fourth quarter. Refining cash operating expenses are expected to be around $3.85/bbl in the fourth quarter.
Regarding our ethanol operations, we expect total throughput volumes of 3.4 million gallons per day, and operating expenses should average approximately $0.36 per gallon, including $0.04 per gallon for non-cash costs such as depreciation and amortization. With respect to some of the other items for the fourth quarter, we expect G&A expense, excluding depreciation, to be around $175 million. Net interest expense should be around $85 million. Total depreciation and amortization expense should be around $390 million, and our effective tax rate should be approximately 36%. We'll now open the call for questions. John?
Thank you. We will now begin the question-and-answer session. If you have a question, please press star then one on your touchtone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touchtone phone. Standing by for questions. Our first question comes from Doug Terreson from ISI Group. Please go ahead.
Good morning, everybody, and congratulations on your great results.
Thanks, Doug.
Mike, you mentioned something just a second ago about some type of a strategic review process at Aruba. I may have misunderstood, but I wanted to see if we could get clarification on what you said and also what you meant by that statement or that point.
Okay. We have started a process of looking for strategic alternatives for our Aruba refinery.
Okay.
Yeah. If I can add to this, Doug. Our operations have improved a lot. Our people are doing a fine job. We have several excellent cost reduction efforts underway.
Okay.
For Valero, we used it really as we are looking at the refinery going forward as a feedstock source to our big conversion operations along our large conversion operations along the Gulf Coast. So in a way, it is a front end for us. We are looking at some reconfiguration as to where we actually do hydrotreating. But the facts are, we are still very interested in finding a partner or some relationship that allows us to process very sour, heavy crude or high- TAN crude, which the refinery can do.
Okay. And Bill, you have been a leader for the industry on the regulatory front over the last several years. Over the past, or maybe longer than that, but over the past several months, there have been some commentary on new rules for U.S. gasoline for 2012, which I believe they are calling tier three and resemble those in California with the entire United States. My question is, do you have any insight into these new rules, specifically whether this movement appears to be significant? What, if any, implications there might be for Valero?
Well, I don't know if I have any insight. What's going on is, under the Clean Air Act Amendments of 1990, there is a certain protocol passed by when the Clean Air Act was passed by Congress.
Sure.
The EPA when it looks at ethanol being added to fuels and other p rimarily ethanol reflected then in vapor pressure and the emissions.
Right.
Feels like they need to drop the sulfur to honor the commitment of the Clean Air Act and drop it to 10 ppm average.
Right.
What is under debate still, the whole issue is, but the ceiling as to whether it is going to be a 30 ppm max or an 80 ppm max. Today, we have an 80 ppm max, 30 ppm average, and then tier three will have different numbers. It is all being discussed. Our industry is against it.
Yep.
It will raise the cost for the consumer, and we think it is an extremely marginal benefit, if any benefit at all.
Okay, great. Thanks a lot, guys.
Our next question comes from Paul Cheng from Barclays Capital. Please go ahead. Paul, your line is now open.
Hi.
Morning, Paul.
Yep, good morning. Just a number of quick questions. Mike, can you give me what is the working capital, the market value of the inventory in excess of the book, and that of the total debt, what is the long-term debt component?
Okay, sure. Total current assets are $15.9 billion. Total current liability is $11.7 billion. Market value in excess of LIFO value is $7.1 billion. Our long-term debt in capital leases is $7.6 billion.
The $15.9 billion current asset, I presume that is including cash, right?
Includes $2.8 billion of cash. Yes.
Perfect. Mike, in your result, is there any trading gain or loss? Also, do you have any future hedging position?
The trading gain in the third quarter was very minimal. It is about $3 million.
Mm-hmm. Any hedging position for the next several months?
No material positions.
Bill, maybe can you share with us what is the major turnaround you guys going to do in the first half of next year?
I'm going to let Lane Riggs answer you.
Hey, Paul, this is Lane Riggs. Our major turnarounds are in Wilmington on the West Coast. It's a crude vac coker, naphtha hydrotreater, CCR, so essentially half the refinery. St. Charles, in February, which is a crude coker diesel hydrotreater, ultra-low sulfur diesel and SRE. So again, similar type turnaround including the SEC. Houston, we have an FCC alky in February, and then finally in March, we have Memphis, which is a crude and diesel hydrotreater unit turnaround.
How many days are those?
Let me add to this. The February 1 at St. Charles is a huge turnaround for us. We are going to replace the coke drums. Many of you that follow us know we have had this coke drum issue at Port Arthur and at St. Charles, which was an engineering design. What we are doing is replacing the coke drums. We did it at Port Arthur this year. Next year, we are going to do it at St. Charles. To do this lift at St. Charles extends this turnaround. I think we released it this morning, and it is 70 days. It is a very large turnaround for us at St. Charles. That will then put these issues we have had with the cokers except for some vapor lines behind us.
Perfect. For Wilmington and Houston, how many days are we talking about?
On Wilmington, it is about 20-- a month, and Memphis is also about a month.
Memphis is also a month. How about Houston?
It is 37 days.
Okay. Houston is 37 days. Mike will you be able to share with us how much you make in Europe for the two months in the quarter?
Let me just f inish in turnarounds, we announced that this morning, and the release went out as to our turnarounds and the schedule.
Yeah, if you are interested in looking at the details on those turnarounds and the timing, you can find those on our website.
Oh, perfect. Thank you. Mike?
Yes.
Will you be able to share with us how much you made in Europe for the two months you owned in the quarter?
Yeah, we made a little over $53 million in the first two months.
And then a final one, Bill, for the M&A market, can you share with us what you are seeing? Is the pricing condition, in terms of acquiring asset, the pricing condition become better or become worse over the last several months for you guys? Or what you can see out there?
Well, I do not know if I can speak to the pricing conditions, but there is certainly several refineries for sale. We believe we bought the two refineries we purchased here recently at very, very good numbers. They fit into our portfolio strategically too. We wanted to step out some, so we have done that. When you look at where Valero trades relative to what we purchased these refineries, we actually purchased them for less than what we trade.
Obviously, there is quite a few assets on the market. Then just to anticipate the next question, because I cannot speak to the pricing except that I have said a couple of times, it is a buyer's market, and it continues to be that way as a general statement. But in Valero's particular case, we are only interested in acquisitions that fits us strategically and that is accretive. It has to be both. If it is not fitting us strategically, we are not interested, and there is no case I can think of that we would issue any equity on any situation that is out there.
Bill, you guys already did a little bit of the share buyback in the third quarter. In terms of the cash you generate, the free cash, over the next several quarters, are you going to become more aggressive in your share buyback given how cheap the stock may be?
Well, I think as you look at us, which is a general cash question, in the volatility we see in the markets today, we will hold more cash than we would've historically, and I've said that consistently. But when you have crude oil price move $5- $8 in about a three day span, we just think you have to do that today. Now, what is happening with us is obviously we're having much better financial performance this year. We think many of the things that contributed to this year's financial performance are going to continue next year, and we're anticipating a good year next year as well.
Then we have a very high capital spending, but those strategic projects are coming to an end, and we can see the light at the end of the tunnel. When you begin to combine our performance, our cash balances, that our strategic projects will be completed, some, as Mike said, right now, some, the big hydrocrackers next year. Clearly, we have more cash available. Then you take the next step, and we've demonstrated it here, just in this quarter and going into the fourth.
We expect to pay one of the highest dividends among our peer group going forward. We will buy our stock periodically, especially as we think the stock is undervalued, and we, as management, clearly think our stock is undervalued. As a little side issue or side comment, the Reliance discussion, this rumor that was out there, one of the benefits has been to point out to the investment community the earnings power of our portfolio and our company. So that was actually a benefit here of a rumor. But we have lots of earnings power. Our projects are coming to an end, and we think our stock is terribly undervalued.
Thank you.
All right. Great. Thanks, Paul.
Our next question comes from Faisel Khan from Citigroup. Please go ahead.
Hi. Good morning. It's Faisel from Citi.
Hey, Faisel.
Hey. Just back to the Aruba statement. If you can't find a strategic partner or an alternative for Aruba, what's the next option after that?
Well, this is Klesse. We continue to improve the operation. We have several things that will reduce our cost, but it is a very good front end of a refinery that can run very, as I said, heavies and high- TAN crudes. We'll continue to improve the operation, and it'll feed then that refinery, when we run around 200,000 bpd , makes about 70,000 bp d of VGO, and we'll charge that to our hydrocrackers that come on next year. For us, we see improving its cost structure and using it as a front end of a refinery. There's 200,000 bpd of crude vacuum coking there that can feed our operations.
Okay. I think I understand that. Going to your Memphis and McKee hydrogen plants. As those come online at the end of this year, what should we expect from the uplifts going into the first quarter of next year from those plants? What are they going to do to the performance of those two plants?
They're completed by the end of the year, then we'll start them up in the first quarter. We have a table we give you, and we're looking for it here. Ashley?
Yeah. Faisel, depending on which price deck you use, we've given pretty much every slide deck for the past nearly year. We've given example economics based on different price decks.
Okay.
If you use 2010 pricing, it's an extra $105 million a year of EBITDA. If you use 2011 pricing, including in a four curves for the last couple of months, it's $150 million of EBITDA.
Okay.
That's incremental. It's basically because you're making your hydrogen out of natural gas instead of destroying expensive oil to do so. You'll see margin uplift, and it basically will drop down to EBITDA.
And that table has been in the appendix of our handouts.
Yeah.
Okay.
Our typical slide decks, which are publicly available to everyone and have been.
Okay, thanks. I will take a look at that.
Okay.
On the ethanol segment, you performed pretty well in ethanol despite crush spreads coming down over the quarter. What caused margins to go up even though crush spreads came in?
Well, the crush spread is not necessarily how you get to the EBITDA, because our margins are a little bit different because of the distiller grain and some byproducts you make. We look at our average margin on an EBITDA basis being about $0.35 a gallon over the quarter, for the entire quarter. I think if you just look at the financial, I mean the markers with corn, ethanol, and distiller grain, it would have been more like $0.30. But I think as corn prices dropped, we got a little bit of extra benefit there just on our corn position. So net we made, if you look at the summer gallons we made and the number that Mike told you earlier, is right at $0.35 a gallon.
Okay. As the subsidy expires at the end of this year, what do you guys expect will take place with your operations going into next year?
Well, remember, ethanol is still mandated. We are blending ethanol is at about 91% of the total U.S. gasoline right now. I think that is going to continue. Ethanol is trading above gasoline now for about probably the first time this year, as it turns out. We are about $0.35 a gallon over gasoline. So the worst case I look at right now is if you go back to paring the gasoline, our current EBITDA on our plants is rough $0.69 a gallon. So if we lost $0.35 to that, we would still have a very positive margin. But like I said, it is driven by a mandate.
So supply, demand. Exports have been strong into Brazil, into Europe as well, so that is supporting the price. I think it is the supply, demand says that all plants need to run right now, including some of the peripheral plants that do not have as good a corn logistics. So we think that we will have good margins at our plants because they are well-situated on the corn supply.
Okay, great.
Right now, margins are just excellent, though.
Okay, thanks. Last question from me is, in theory, if Libya continues to ramp up, do you guys have an outlook for the heavy light spreads going into next year?
Yeah, I think they're going to continue to be somewhat similar to this year.
Okay, great. Thank you.
Our next question comes from Blake Fernandez from Howard Weil. Please go ahead.
Guys, good morning. Congratulations on the results.
Thanks.
One, I wanted to ask, what is the current authorization on the share repurchase program?
Okay, we have a Board-approved program that is $3.46 billion of authorization.
Okay. Secondly, I wanted to ask about Pembroke. With so much capacity on the East Coast potentially at risk of closure, I guess my general thought is that that could be a direct benefit to Pembroke with the transatlantic arbitrage. Am I thinking about that correctly?
Yeah, I think you are. This is Gene. Obviously the European barrels do flow to U.S. East Coast, and having that capacity shut down is going to create opportunity. However, it's a whole Atlantic basin market, and the marginal refineries are going to be under pressure just like they have been this year. But it does give an advantage to well-situated refineries in Europe. We think Pembroke fits that category.
Okay, great. The last one for you. I know the growth projects, it was stated that they're all on budget and on time. As I look at first call estimates into 2012 and 2013, it does not really seem like the Street is reflecting the incremental, call it $2 a share of incremental earnings from these projects. Is there anything in the macro that you see today that puts at risk that number? I mean, are we still pretty much on track for an incremental $2 a share from all these projects?
Yeah, I think the main factor is just with crude in the $100 range and natural gas are in the $4 range. It gives these projects a good uplift because it is basically a gas to a liquids type project as far as the majority of the benefit. The distillate crack is kind of secondary as compared to the volume lift you get from natural gas.
Great. Thank you very much.
Our next question comes from Doug Leggate from Bank of America. Please go ahead.
Thank you. Good morning, everybody.
Morning, Doug.
A quick one for us on Meraux. Can you just talk about exactly how you're operating that facility, how you plan to integrate it? I guess really are you trying to actually run the crude unit there or just use the upgrading units? I have a quick follow-up, please.
Yeah, this is Gene again. We're basically operating how Murphy was operating before, but we are starting to capture some synergies. We've integrated in with our feedstock supply, so we pick up some synergies there. Also, the products there, a lot of Murphy was using to supply their Florida business. We're just using and optimizing our overall system.
We find the high cetane of the diesel that's produced there off the hydrocracker. We're finding some synergies on blending that with St. Charles diesel. Procurement side, I think we'll see some advantages on our purchasing power going forward. So in that effect, we're kind of running it as is today, pretty much the way Murphy did, just trying to pick up on some synergies.
Are you planning to do it on
Doug, you must be on a cell phone and you're breaking up.
Any better?
Yes, much better.
Okay. I'll just try one quick one then. Are you planning to change the feedstock at Meraux in terms of, you've talked about Three Rivers and Eagle Ford and so on. Is there anything you can do to actually change the feedstock there or not? I'll leave it at that.
Yeah. Right now, we can run medium sour crude. It runs about 1/3 of sweet crude. So we will always try to optimize that based on where the sweet spreads are. We can go to 100% sour to sweeten up even more if the economics say so. Right now, we are pretty much in this 2/3 sour, 1/3 sweet still.
All right. I will leave it there. Thank you.
Our next question comes from Mark Gilman from Benchmark. Please go ahead.
Guys, good morning. A couple of things if I could. Hey, Mike, did you book any goodwill on the Pembroke deal?
No, we did not.
The $53 million that you quoted previously in terms of the contribution in the quarter, I assume that that's an operating profit number?
Yeah. Operating income. Yeah. Operating profit. Operating profit. Sure. After DD&A.
How much of that buyback authorization is remaining?
The number that I gave you, the $3.46 billion, is what's remaining. In addition to that, we can purchase dilution under our benefit plans.
Just one more from me. It made reference to discounted West Coast crude feedstocks. San Joaquin, Canadian Light, both? Be a little more specific if you could, please.
Yeah. It's typical grades we run out there. It's SJV, KLM, some South American grades like Oriente, Napo, Castilla. All those things actually had better pricing versus ANS. Versus ANS is the key there, Mark.
Yeah, no, I mean, ANS is out of the market. All those other crudes seem to be in the market. So is it really discounted?
Well, I mean, if you compare it to ANS, yes. It depends on what your benchmark is.
Okay. Just let me sneak one more in. Byproduct benefits in the ethanol side, in terms of the grains, seems like they are very substantial. Can you help over and above what Gene had to say a few minutes ago?
Well, the distillers grain, only about 2/3 of your corn is converted. About 1/3 of it ends up as distillers grain, and that has been a pretty strong market. I do not have the exact numbers in front of me, but that is the primary byproduct you are producing.
Okay, guys. Thanks very much.
Thanks, Mark.
Our next question comes from Rakesh Advani from Credit Suisse. Please go ahead.
Hi. Thanks. Just a quick question on Meraux. Have you guys ever put out any, what kind of EBITDA contribution you think can come from that facility?
We have not yet, Rakesh. We have not disclosed its historical financials.
We closed October 1st, so probably that's a question for the first quarter.
Okay. And just for the two hydrocracker projects that are coming on stream next year, can you guys talk about how much disruption there will be to tie in the two projects into your existing facilities?
So-
Which kind of quarters it will take place in?
Okay. The Port Arthur hydrocracker will be finished mid-year. So we are saying third quarter, with start-up then third, fourth quarter. And the St. Charles hydrocracker will be finished by year-end, with start-up then occurring then, and then in the first quarter.
Okay. How many days would we assume for the facility to go down or to tie them in? Should we just go over like 30 days or something like that?
We will not go down to tie them in. Everything will be wherever we have tie-ins, valves are hung or things are hung, wherever there are tie-ins. Now, if you are asking how long to start up, these are huge projects.
Anywhere from two weeks to one month, probably, to start up.
Okay. Two weeks to a month.
The base operations are generally going to be unaffected.
Right.
Okay, perfect. Thank you.
Not like taking a big turnaround or something. It will be incremental.
Okay. Thank you.
Sure.
Our next question comes from Jacques Rousseau from RBC. Please go ahead.
Morning.
Morning, Jacques .
Just wanted to ask you on, if I heard correctly, the guidance for the Midwest volumes for the quarter. I believe you said 430,000 bpd- 440,000 bpd?
That is correct.
Cool. I was just curious. That looked like a high number, probably the highest quarter since you had since 2008. I guess if you could give a little color on what's improved there.
There's still economic incentive to run. But also, the last couple of quarters, we've either had turnarounds or other unplanned outages, like Memphis had some issues in the third quarter. It probably would've been up around that level, and that was the original guidance range until Memphis had a fire that affected the crude heater, I believe. Otherwise, it's what we would've expected.
Great. So outside of the maintenance that you've talked about, this is probably a normal run rate going forward?
That's correct.
Great. Thank you.
Our next question comes from Jeff Dietert from Simmons & Company. Please go ahead.
Good morning.
Morning, Jeff.
I was wondering, you mentioned the start-up at Pembroke and gave some contributions for the quarter. Could you talk about operations there, if there is anything that surprised you. Anything that you are doing differently than the way you perceive Chevron from operating the plant? I think many majors focus on maximizing throughput rather than maximizing profitability. Any comparisons you can make there?
I think that we will put our own spin into the plant. We're profit-focused. We're in this business to make money. But as far as a statement of we run different than Chevron, for instance, Chevron's a very well-run company. I would tell you, "Hey, you're going to see our spin because we intend to make money.
Great. Any discussion on exports? I know when we look at the DOE statistics, both gasoline and diesel exports were at records in the most recent months. You're continuing to see gasoline and diesel exports increase. What those volumes look like in 3Q, and are there any constraints to your ability to export both products?
We see the export market continuing to be very strong, and Ashley will give you some numbers here.
Yeah. In the third quarter, we were up a little bit for gasoline versus prior quarters, up around 75,000 bpd- 80,000 bpd . On the diesel side, it was again up from the second quarter up to about 165,000 bpd of diesel exports. The gas has been going where it has been going pretty much south of the border to Mexico or other parts of Latin America. The diesel's been going split between Europe and Latin America.
Hey, Jeff, this is Gene. Obviously, those are Valero's export numbers. The industry numbers are about 900,000 bpd of diesel and about 500,000 bpd of gasoline if you look at the DOE numbers.
Any restrictions in your ability to export more if the market demand's there?
No. Like I mentioned earlier, we're finding some synergies with Meraux and St. Charles, which typically in the past did not export European grade. But by putting those streams together, we're finding out we can make an EN 590 or European spec. We're looking to see what we can do there.
Thanks, guys.
Sure.
Our next question comes from Paul Sankey from Deutsche Bank. Please go ahead.
Good morning, all. We put out a note earlier this week just showing how tight PADD I markets are for distillate. Can you talk a bit about that from your point of view? I am thinking Pembroke, I am thinking Colonial, and I am thinking any other potential you have for going after that market. The analysis we were running was before we had the snow. I assume you would agree that the market looks extremely tight.
I think, Paul, we do not understand your question.
You are looking for comments?
I think we missed a word that must have been missed in the sentence.
Should I just say the whole thing again?
Right. We must have missed a word.
Okay, that is perfect question asking, I should say. Okay, so let us start again. PADD I markets we have analyzed earlier this week look very tight, Northeast distillate markets particularly. I wondered if you generally agreed with that. To the extent they are tight and to the extent the weather is likely to increase that tightness, I was wondering how, from your point of view, you can address that. I am thinking about the Colonial Pipeline, I am thinking about Pembroke and any other access you have, if you like, to that particular area.
Okay, thanks. What we missed was the PADD I.
Yeah, that was an important bit. I apologize.
No, it is okay.
PADD 1 is tight on distillate. If you look at continental Europe, it is also very tight. I think you are going to continue to see the exports from the Gulf Coast going to Europe and PADD I distillate inventories. Yeah, they are dipping well below the five-year average and well below last year. With the refinery that has been recently shut down there, I think that market is going to be tight, which is going to require fairly high utilization rates throughout the winter to supply that market. I think it is going to be a pretty strong market for distillates going forward.
Volume will be shipped in as well as going to Europe into the East Coast.
Yeah. You can ship it obviously from the Gulf to the East Coast, because I'm assuming that pipeline capacity is limited for moving it any other way.
Yes, I am sure Colonial will go under proration.
Right. The knock-on effect, I guess, is likely to be higher distillate margins on the Gulf Coast as well.
Yes, the whole Atlantic Basin market. Like I said, with Europe tight and the East Coast tight, I think there's going to be demand for Gulf Coast barrels to go to both these markets.
Great. Thanks. Just further to the buyback, are you setting 20 as a floor below which you buy back stock, or are you thinking that you are going to, you mentioned that the stock is undervalued in your opinion. Has it just been a 20 floor recently and one that you may think about raising, if you like, under which you will buy stock?
I am not really looking at it that way. It is much more opportunistic, but we did buy 13.5 million shares below 20. We manage our cash, so it is the whole balance.
Yeah. Okay. We can hope for more buyback going forward regardless of the stock price being above 20?
Clearly, we think our stock is undervalued.
Okay, Bill. I get it. Thanks, guys. Sorry about the misunderstanding.
Thanks, Paul.
Our next question comes from Chi Chow from Macquarie Capital. Please go ahead.
Great. Thanks. I want to go back out to the West Coast. That was a pretty good result on realized margins, given where the crack spread trended in the quarter. Was the improvement really just on the differentials you talked about earlier? Did you change up the crude slate at all during the quarter? Mike, you also mentioned the liquid volume yield improvements. Were there operational improvements that you undertook at the plant out there as well?
Sure.
Operations?
This is Lane. Operationally, we just came out of the turnaround Benicia, so its performance in terms of liquid volumes are improved versus prior to the turnaround. Crude selection is essentially unchanged. We haven't really changed what we're running on the West Coast. It's the same crude diet.
We operated better.
Right.
Okay, thanks. California recently finalized their Cap-and-Trade Program regs. Have you had a chance to dig into those details, and how are you thinking about managing that program going forward?
Well, you can rest assured we've dug into it. We have a very good strategic position on the West Coast. We have very good operations. However, we think state policy, AB 32, other fiscal policies, regulations, continue to adversely affect the economy. They adversely affect jobs. They have adversely affected consumer.
We think all these policies seem to turn their back on the negative economic impacts. We are hopeful that the voters, which consumers, will eventually realize that these policies are economically ruining the state. AB 32 was a 12-page bill. CARB has now spent over $100 million trying to develop regulations in five years. It is a go-along policy. The people of California are going to pay. As to us, we're looking at our options.
Do I take that as meaning that the long-term viability is potentially in question on operating refineries in that state?
We're looking at our options.
Okay. Got it. Okay, great. Thanks for that, Bill. One other question on the Eagle Ford. We've noticed recently that the markers that we track, the pricing on the Eagle Ford crude has changed dramatically in mid-October, and it's moved to pricing off of Brent versus previously off WTI. Have you seen this pricing dynamic in the market? If so, has that impacted your decisions on crude slate down there?
Yeah. This is Gene. I think if you look at Eagle Ford, where it's pricing related to Brent, if it's already on the water area where it could be delivered and compete with a foreign barrel, with prices there, I think in the fields, it's still pricing at discounts. Not at par with WTI, but still much less than Brent.
Chi, it's going to depend. I guess the marginal barrel that's on the water, of course, it's probably going to price like Brent at this point. But if you're in the field, or if you have a refinery in the field and you've cut deals, then you've got different pricing. That's how things work.
You're talking about Three Rivers versus Corpus then. Is that the difference?
Absolutely.
Got it.
But clearly, your observation is correct. Takeaway capacity's being built in the Eagle Ford. The crude is able to, more of it's moving to the market. We have raised our postings in order to keep it in the area, but it's still discounted relative to the other crudes. It's still, we still think Three Rivers and the volume we're going to run at Corpus are going to be very economic crudes for us. Remember, we used to run all foreign crude at Three Rivers.
Right. Okay, great. Thanks a lot.
Our next question comes from Sam Margolin from Global Hunter. Please go ahead.
Hey, morning, guys. How are you? I don't think you've ever done this before, but can you break out Memphis from the Mid-Con group or give just maybe an assumption of what the Mid-Con realized margin was ex that Memphis portion?
We haven't, and we really don't plan to, Sam.
Oops. All right.
Sorry.
Okay. Well, in that vein, on the last quarter's call, you gave some indication that you were thinking about maybe a big capital project at McKee, an expansion or something on that order. Is there any progress with that line of thought, or still in the evaluative?
Yeah. Sam, we have a project we've engineered at McKee. It's less than a $100 million project, but it does let us run more oil. It's a little bit over the same lines that Ashley talked about, the Eagle Ford crude, where the refinery's in the field. We're seeing more and more crude discovered and available to the McKee refinery. We have a project that would let us do that, and right now we're anticipating doing that project.
However, it takes 18 months to 24 months to get a permit. We're just about to file our permit application or have filed our permit application. Depending on how long that takes, which is a year and a half and then some construction period after that. But the McKee Refinery sits right there in the Panhandle. We're seeing more crude, and this is just a little de-bottlenecking, as I said, it's less than a $100 million project.
All right. Sounds good. That's it for me. Thanks so much.
Okay.
Our next question comes from Evan Calio from Morgan Stanley. Please go ahead.
Hey, good morning, guys. Great quarter. I think you could extend the distillate tightness commentary into China beyond PADD 1 in Europe. My question is a follow-up on Aruba and if other than strategic partnerships on heavy sour crude, is it possible you could find a cheaper fuel source instead of burning, I think it's 14% of crude there? Is floating regas FSRU, is that anything you guys have explored?
Yes. We are working a project in conjunction with the government of Aruba in order to bring in LNG. That project, we've been working on it for many months and we're down into where we're getting solicitations on supply right now. The engineering is largely done. Yes, it has very favorable economics both for our refinery, including reliability, and it also is very favorable to the people of Aruba because of their power costs.
So exactly correct, and we are working that project. On top of that, a little longer term, I believe it's Repsol is looking at spotting a well there because they believe they're going to find natural gas there as well in the water. There's many things changing actually all over the world on the C&P side.
That's great. That's good news. Another question, if I could, just lastly, the Line nine reversal was announced at Enbridge Analyst Meeting. Do you expect down the road you could get a lift into Québec, and how do you think about that? Or any partnership to move crude into that market to benefit that refinery?
Yes, we're interested in the Line nine reversal, and obviously, so is Petro-Canada and others. That only takes the crude oil to Montréal . Then you have to have some agreement to get it over to Portland. Yes, depends on the differentials between WTI and Brent now in this case. Yes, we would think it would give us some advantage if we could get that crude.
Appreciate it, guys. That's it for me.
All right. Our next question comes from Blake Fernandez from Howard Weil. Please go ahead.
Hi, guys. Sorry to pump back in. Bill, I know you've covered the share repurchases, but just one final question on it. Is there a specific goal or a target for the number of shares you're hoping to retire?
No, there is not.
Okay. Thanks a lot.
Our last question comes from Allen Good from Morningstar. Please go ahead.
Good morning, guys. I was just wondering if I could get your current thoughts on your appetite for acquisitions, or should we take the dividend increase, share repurchases, and willingness to hold a high cash balance as a sort of signal that you are done with acquisitions right now?
Well, I thought I was addressing it, but we are a refining company. We also have a marketing operation, ethanol business. Some of the assets are available for numbers that are attractive. If it is strategic, if it is accretive, Valero is still interested or is going to look. The last two acquisitions that we have done, we purchased for less than where Valero was trading. We think we can add value. On the other hand, we are extremely selective, and I have said there is no intent whatsoever of issuing equity.
Is Europe still an area of interest, or is it just sort of a broad geographic area that you are looking at?
Yes. Europe is still of interest. We have been very public in the fact that we now have an established position there, at least in the U.K. We have said there is a refinery nearby that Valero would be interested in. But otherwise, we are not working on anything in Europe.
Okay. Thanks for that.
We have no further questions at this time.
Okay. Thanks, John. I just want to thank our investors for listening to today's call. If you have any questions, just contact me or Matt in the investor relations department. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.