Jason Gabelman: I wanted to first ask about the Martinez biofuel projects. It looks like the other income line was close to, in refining was close to $200 million this quarter. I think that includes the impact from Martinez. So I was hoping to get an idea of how much that contributed to earnings this quarter and then how you think about the ramp up in capacity to 100% from current 50%?
John Quaid: Let me take the first part of that and then I’ll turn it over to Maryann. But just to clarify, that other that you’re seeing on the R&M walk, it is not related to Martinez. Largely, what you’re seeing there are and you see in the prior quarters are some of the insurance proceeds we’ve recognized in regards to a claim we had at some of our refineries. But I’ll turn it over to Maryann to talk about Martinez, but I want to clarify it’s not in that bar.
Maryann Mannen: So let me give you an update on Martinez. As you stated, we are currently operating at about 50% of our nameplate capacity. In November, we had a heater tube failure at Martinez. And as I shared with you last quarter, we continue to work with all the regulators to align on what repairs are necessary and ensure safe reliable operation going forward. We would expect to continue to operate at 50% for the second quarter. And then somewhere mid third quarter, we would expect to see our capacity increase to about 75% of that nameplate. And again, when I talk about nameplate, I’m talking about 48,000 barrels a day, by the way, just for clarity. And then we do expect to ramp up to full capacity on Martinez by year-end. So again 50% second quarter, ramping to 75% mid third quarter with full rate capacity by year-end.
Jason Gabelman: And that means, I guess, that you got approval for the fixes that you need to make in the unit? And then is there any cost, OpEx associated with the improvements you need to make at the plant?
Maryann Mannen: So in our second quarter guidance, we do not have any cost yet included in that second quarter guidance. Sorry about that. Yes, we continue to work with regulators to align on the path forward. So we believe again, continue to work with them, but we believe we understand the work that needs to be done and we are aligning with our regulators to achieve that.
Jason Gabelman: And then my other question is sorry, Mike, I’m going to go back to this capture metric. And you include just $392 million headwind on Slide 8 of capture impact. Some of that is from product inventory and derivatives. I’m wondering if that amount, if you could share what that is and if that reverses in 2Q?
Maryann Mannen: So you’ll notice that we try to give you on that slide we show you the impact that is from crude and the impact from product. And what you saw this quarter is what was normally a very positive impact from product margins really narrowed quite a bit in the first quarter. Alternatively, that crude is typically a key driver. It always pulls capture and that will ebb and flow just depending on a series of things. But the key driver in this first quarter, as you see, were product margins and the inventories. We made some commercial decisions, which we think were the right ones and we made those decisions sort of late in the quarter. But as those market dynamics change, we’ll be able to share that with you going forward.
Operator: Our next question will come from Roger Read with Wells Fargo.
Roger Read: I guess I’d like to dig into here maybe your expectations on crude. We’ve heard from some of the other companies what’s going on in terms of available barrels out there. And you’ve talked a little bit about the positives on the West Coast. But how should we think about the impact in the Mid-Con down to the Gulf Coast, Mid-Con thinking the WCS going west instead of south and then along Gulf Coast, just what you’re seeing in terms of available barrels on the heavy medium to heavy side and thoughts on the light heavy spreads?
Rick Hessling: So I’ll start with light heavy spreads. We continue to see them right about where they’re at today. Obviously, we’ve seen the WCS spread come in a few bucks. And ironically, if you look out on the forward curve towards the end of this year, it actually starts to move back out $2 to $3 due to strong Canadian production and diluent blending. So we see this as a little bit of a near term blip. Specifically in the Mid-Con, I do believe there is a misconception that the Mid-Con will be short and heavy. We don’t believe that to be the case. As you know, we’re a big buyer in the Mid-Con. And when we look at TMX coming online, we believe the marginal Canadian barrel that’s going to get backed out of the system first is the U.S. Gulf Coast export barrel. And so with that being said, when we’re looking forward here and whether it’s PADD 2, 3 or 5, we expect to generally run about the same mix of Canadian barrels that we have run here the past several quarters.
Roger Read: And I guess if we do see fewer barrels on the Gulf Coast, Canadian or otherwise, what’s your anticipation there relative to what you have been running at either Galveston Bay or Garyville?
Rick Hessling: Yes, we don’t see it changing a lot. I will tell you when we look at Brazilian growth, when we look at Guyana production and then Canadian even with some barrels getting backed out, we don’t see our mix changing that much Roger. And then we certainly have barrels that could potentially come from the Middle East if we get the right economic signals. So I would say, all in, I really don’t expect a significant change.
Roger Read: One final clarification on the West Coast. We’ve heard some say that the acidity of the WCS barrel could be a headwind for running some. And I think when people ask about your ability to run max barrels of WCS, maybe that’s what they’re getting at. Is there any limitation from a metallurgic kind of physical capacity issue for you on the West Coast?
Rick Hessling: It is something that will balance, Roger. I believe I said earlier, ANS, the biggest difference is ANS. It has about 5x lower sulfur than WCS. So that’s why we believe there will be a lot of blending going on, on the West Coast. But I do believe, in general, you will see it limit other’s toolkits on what the amount is that they can run but we’ve yet to see — we need to see that play out.
Operator: Our next question comes from Matthew Blair with TPH.
Matthew Blair: We’re seeing octane spreads at record levels. Is that a function of the Tier 3 low sulfur gasoline specs and perhaps any dynamics in the NAFTA market? Could you talk about the drivers here? And how much of MPC’s gasoline production is high octane?
Rick Hessling: Yes, Matt, it’s Rick again. So I will tell you, good call out. We’re seeing octane values be extremely high. And as you know, we have a lot of reforming capacity. So we are a large octane producer, so we’re seeing the benefit. Certainly, you hit on a couple of the reasons. Specs is certainly a region. But I will also tell you, we’re seeing strong signals on the export side. And when you think about the export market, we’re sending over volume there that generally does not have ethanol in it. So that is eating up a lot of octane long product. And then there is persistent length in the NAFTA market due to poor petchem margins. So that’s helping us out on the octane side. And then lastly, more recently here, you’re certainly seeing the impact of high turnarounds, just taking octane off the market here in Q1, and it’s carrying into Q2, and we see it persisting for a while, Matt.
Matthew Blair: And then circling back to an earlier question, I think you mentioned you were long diesel in California. Is that a function of RD share approaching 60% or so? And if so, what do you do with those extra diesel barrels? Are they exported to like Mexico or Canada or Asia?
Rick Hessling: Yes. So great comment. And my comment earlier, the industry, I would say, is long diesel, and we’re not alone in that category, we are as well. And you’re right, we’ve got to find export opportunities, Matt, whether anything waterborne where we can find a home to clear the product is what we and others are doing.
Operator: Our last question will come from Theresa Chen with Barclays.
Theresa Chen: When we think about your marketing merchants within R&M, the direction of wholesale gasoline prices benefiting Q4 as they came off and then acting as a headwind in Q1 as prices shot up, how can that move the broader R&M capture quarter-to-quarter or the cash generation from the segment and how should we think about the [indiscernible] into second quarter?
Rick Hessling: Theresa, can you restate the back half of your question, I’m not sure I caught that part, please. This is Rick.
Theresa Chen: Sure, Rick. Related to your marketing margins and the move of the flat wholesale plain prices benefited sitting Q4 as prices declined and then acting as a headwind as they came up on how much of that can really bring noise to the R&M capture quarter-to-quarter?
Rick Hessling: Yes, good question. So it can be significant. And depending on the region it’s just tough, as you pointed out, in an upward market. If you look at Q1 to your point, Theresa, I think we had a $14 flat price increase throughout the quarter. So it definitely was a headwind, and it can be significant. We, amongst all of our competitors need to be competitive at our racks and in an up market, it continues to be a headwind. So I don’t have a specific number that I can share with you. But it’s definitely a factor in our capture.
Theresa Chen: And Mike, going to your earlier comments about MPLX as a strategic investment and with the announcement at the partnership over the past few months and just migration of more and more third-party cash flows, do you have a long-term target for the breakdown of third-party to GP driven EBITDA cash flows over time? And would a shift towards more third-party cash flows help MPC possibly have more flexibility in the upcoming contracting events to take place over the next few years?
Mike Hennigan: Yes, Theresa, we don’t have a target per se using that term. We do have the goal of generating increasing cash flows from third parties as well as optimizing within our own system as well. The point I was trying to make is where we stand today, that distribution from MPLX covers the MPC dividend and more than half of the capital. But going out, and again, this isn’t guidance, but if you look at the trend, we’re going to continue to increase the MPLX distribution over time. And as you see that occurring and depending on the capital needs at the refining side of the business, the statement I said was there’ll be a point where MPLX’s distribution will cover the dividend and all of the capital and still have excess cash.
That’s how unique the competitive advantages of that business. And we’ve been bullish natural gas growth for a long time. And I always caution, I’m not saying natural gas price, I’m saying natural gas growth volume. We continue to believe that, that has tailwinds behind it whether it’s all the topics that have been talked about recently. But as that continues to occur, that ability for MPLX cash generation increase will just continue, and it will get to a point where it’s covering the dividend at MPC, the capital at MPC and still generate excess cash. That’s where we’re headed. So I don’t know that we have a target other than that target, and we’ll try and keep growing that.
Kristina Kazarian : All right. With that, thank you so much for your interest in Marathon Petroleum Corporation. Should you have additional questions or would you like clarification on topics discussed this morning, please reach out in the IR team will be available to help with your call today. Thank you for joining us.
Operator: Thank you. That does conclude today’s conference. Thank you once again for your participation. You may disconnect at this time.
