Kristina Kazarian:

Welcome to Marathon Petroleum Corporation's Second Quarter 2024 Earnings Conference Call. The slides that accompany this call can be found on our website at marathonpetroleum.com under the Investor tab. Joining me on the call today are Maryann Mannen, CEO; John Quaid, CFO; and other members of the executive team. We invite you to read the safe harbor statements on Slide 2. We will be making forward-looking statements today. Actual results may differ. Factors that could cause actual results to differ are included there as well as in our filings with the SEC. With that, I'll turn the call over to Maryann.

John Quaid:

Thanks, Maryann. Slide 5 shows the sequential change in adjusted EBITDA from first quarter 2024 to second quarter 2024 as well as the reconciliation between net income and adjusted EBITDA for the quarter. Adjusted EBITDA was higher sequentially by $133 million, driven by increased results in both our Refining & Marketing and Midstream segments. The tax rate for the quarter was 16%, resulting in a tax provision of $373 million. The second quarter tax rate largely reflects the earnings mix between our R&M and midstream businesses. Moving to our segment results. Slide 6 provides an overview of our Refining & Marketing segment for the second quarter. Following significant turnaround activity in the first quarter, our refineries ran at 97% utilization, processing nearly 2.9 million barrels of crude per day. Refining operating costs were $4.97 per barrel in the second quarter, lower, sequentially, primarily due to higher throughputs, lower project-related expenses associated with reduced turnaround activity and lower energy costs. In our largest region, the U.S. Gulf Coast, our operating costs were $3.73 per barrel, demonstrating our cost competitiveness. Sequentially, per barrel margins were down primarily due to lower crack spreads. Slide 7 provides an overview of our Refining & Marketing margin capture of 94% for the quarter. Capture in the quarter reflected tailwinds from gasoline margins, offset by increased headwinds from secondary product pricing, which was driven by high refining industry utilization. Gasoline margins were supported by a falling price environment during the quarter and, in addition, our integrated system and realized demand across our multiple sales channels was a competitive differentiator to our capture performance. Slide 8 shows the changes in our Midstream segment adjusted EBITDA versus the first quarter of 2024. Our Midstream segment is generating strong cash flows. This quarter, MPLX distributions contributed $550 million in cash flow to MPC. The 2 midstream transactions Maryann discussed earlier further enhance our Permian value chains for both natural gas and NGLs. Through organic growth and disciplined investments, MPLX continues to provide growing cash flows to MPC. MPLX is a differentiator in the MPC portfolio and remains a source of durable earnings growth. Slide 9 presents the elements of change in our consolidated cash position for the second quarter. Operating cash flow, excluding changes in working capital, was $2.7 billion in the quarter, driven by both our refining and midstream businesses. Working capital was a $541 million source of cash for the quarter, primarily driven by the decrease in refined product prices. This quarter, capital expenditures and investments were $541 million. And during the second quarter, MPLX issued $1.65 billion in tenured senior notes, the proceeds of which MPLX expects to use to retire senior notes maturing in December of this year and February of next year. MPC returned $2.9 billion through share repurchases and $290 million in dividends during the quarter. And in July, we repurchased just over $900 million of MPC shares, leaving $5.8 billion remaining under our current share repurchase authorizations and highlighting our commitment to superior shareholder returns. At the end of the second quarter, MPC had approximately $6 billion in consolidated cash and short-term investments, excluding cash at MPLX. Turning to guidance. On Slide 10, we provide our third quarter outlook. We are projecting crude throughput volumes of just over 2.6 million barrels per day, representing a utilization of 90%. Planned turnaround expense is projected to be approximately $330 million in the third quarter, with activity focused in the Mid-Con and Gulf Coast regions. Turnaround expense for the full year is anticipated to be approximately $1.4 billion. Operating costs are projected to be $5.35 per barrel in the third quarter. Distribution costs are expected to be approximately $1.55 billion and corporate costs are expected to be $200 million. In summary, our second quarter results reflect strong cash generation and disciplined capital allocation. The R&M segment generated $2 billion of adjusted EBITDA and MPLX distributed $550 million to MPC. This supported investments of over $500 million and capital return of approximately $3.2 billion. With that, let me pass it back to Maryann.

Kristina Kazarian:

Thanks, Maryann. As we open the call for your questions, as a courtesy to all participants, we ask that you limit yourself to one question and a follow-up. If time permits, we will reprompt for additional questions. We will now open the call. Sheila?

Manav Gupta:

Congratulations on a very strong start. And looking at all these very attractive projects that you're doing in midstream, Maryann, like BANGL and Whistler and now Blackcomb. And looking at the way the distribution is growing at MPLX, like is the thought process somewhere here to try and grow the distribution at MPLX for 10%. And even if you can do it for 2 more years, that distribution to MPC jumps to like 2.7-plus, at that point, is covering your full CapEx and full dividend. So technically, you are a recession-proof refiner.

Manav Gupta:

Perfect. And a very quick follow-up is, looking at the Gulf Coast OpEx, I think, $3.72 is the lowest in the business. It's like probably the lowest. Help us understand what's been the drivers of this because probably 3 or 4 years ago, you were not the lowest cost Gulf Coast operator. Looks like you've now gotten there. So help us understand some of the initiatives? And can this be sustained here?

Rick Hessling:

Yes. So on the Gulf Coast, I will share that with utilization where it's at. We believe it to be a highly constructive market going forward and continue to rebound, Manav.

Neil Mehta:

Maryann, I wanted to kick off with you. As you take on the reins of the business in the CEO role. Can you talk about the first 6 months on the job. What are your key objectives? And what are you focused on here?

Neil Mehta:

And if I can drill down on one specific item. Over the last couple of years, the business and the value has really been created largely organically. There are some questions about whether you pursue M&A in the renewable diesel space. There was some trade articles around Neste in particular. So just love your comments on how do you create value in that business and any thoughts around that specifically?

Operator:

Our next question will come from Paul Cheng with Scotiabank.

Maryann Mannen:

Paul, thank you. So on TMX, first and foremost, I think we've been talking about this for the last several quarters. And what I would share with you is the start-up of TMX has largely happened as we anticipated and the results of that very similar to the way that we believe that would play out in the marketplace. So pretty consistent as we've shared. I'm going to pass it to Rick and allow him to give you some incremental color in particular on what's happening in the West Coast.

John Quaid:

Paul, it's John. On the other margin change you see for R&M, not all of it, but it primarily relates to us finalizing our insurance claim for the Galveston Bay reformer. So we would have finalized that, recognize that income in the first quarter and then receive the cash proceeds in Q2. So you have that recognition in Q1, but again, it's the final one. So there's really nothing to offset it in Q2. That's what's driving the change you're seeing there.

Roger Read:

Congrats, Maryann on everything. I'd just like to maybe take a couple of shots at some of the macro stuff here. As we think about the let's -- what we call better than mid-cycle, but whatever new mid-cycle, how you're looking at the structure of the market? And then how that fits in with what's generally been higher utilization throughout the industry, putting a little pressure on cracks here at least for a few months this summer. How maybe you think that works out as we look out over the next, call it, 6 to 12 months?

Rick Hessling:

Yes. Roger, just a few more comments. So when you look, S&D is really in line with our expectations. It's really what we -- what and where we thought it would be. But when you drill down even further and look at utilization closer to home domestically over the last couple of weeks, even domestic utilization is off some 4%, ironically, bringing us to this 90% utilization level, which is where our guidance is going forward. So we see that as continuing to be very constructive. And then I'll just spend a moment talking about our demand. Our demand within MPC, both domestically and from an export perspective is very steady on the gas and diesel side, and we're seeing really strong signals on the jet side. So we believe those tailwinds, combined with the supply and demand picture, that's truly in balance further backs up our mid-cycle plus thoughts going forward.

Operator:

Our next question will come from John Royall with JPMorgan.

John Quaid:

John, it's John. I'll take that to start. You're spot on with the turnaround comment really largely what you're seeing, right, we've got activity, as I mentioned, in the Mid-Con and the Gulf Coast, that's going to affect what we're going to be able to run. And then I'll make an initial comment, turn it over to Rick if he has any further. But really, we're going to continue to run our assets optimally to meet the demand in the market.

John Royall:

Great. And then I was just hoping for a little color operationally on how Martinez is running and ramping towards the target of getting to full by year-end. And relatedly, do you have any concerns about the price of feedstocks getting driven up by a combination of Martinez ramping back to full and Rodeo coming on and ramping its runs of lower feedstocks.

Operator:

Next, you will hear from Jason Gabelman with TD Cowen.

Maryann Mannen:

Jason, thanks. With respect to buyback, I appreciate the comment on the second quarter, you could see $2.9 billion in the quarter. We continue to see share buyback as an appropriate return of capital, particularly when you look at the current equity price of MPC and what we believe to be over the long term, the growth and opportunity in this equity. So you'll continue to see us use cash to buy back stock. Again, no change to that view as we look at that. Part of the reason you saw that change in net debt, obviously, is quarter-over-quarter. You saw the drawdown in cash. We've talked about what looks like a reasonable place for us to be in terms of the cash position. I can have John share a little bit more about that with you. But we're not near there. So we continue to believe in buybacks, and we'll go forward with that.

Rick Hessling:

Jason, it's Rick Hessling, so no onetime items. What I would tell you is we believe a competitive advantage of our assets in the Mid-Con is our fully integrated system. We've been working for many years to create optionality from what we call cradle to grave when you think refining all the way through our end consumer. And we believe this is and will continue to pull through on our results.

Carlos Escalante:

This is Carlos. Doug sends his apologies. First of all, congrats on the quarter end. I suppose we would like to know what the appropriate dividend growth policy would be a resumable buyback slowdown, especially considering how strong your MPLX distribution is insofar as providing coverage for you guys in that end.

Carlos Escalante:

And you actually -- that's a good segue for my follow-up question, which is, in the software market, where would your priority be on that same balance of buybacks over balance sheet? And would you consider relevering the balance sheet and to what extent if that's what you choose to do?

Operator:

Next question will come from Matthew Blair with TPH.

Rick Hessling:

Matt, it's Rick. So the yields were really an impact of the feedstock input. And I would tell you that the ultimate capture though was enabled by our ability to capture higher margin with our specific commodities. So it's again an a testament to the team working from cradle to grave to maximize the margin irrespective of the yield percentage.

Rick Hessling:

Well, it's a great call out. This is Rick again. Yes, so the market is tight right now. There have been some notable disruptions in the Midwest that are straining supply and demand, Matt. And that's definitely been a benefit to us. While it has widen significantly as you've outlined. I would say we do expect a slight pullback to stay where it's at, probably is overly optimistic. But with that being said, constructively right now, the Midwest is tight.

Theresa Chen:

Just a quick follow-up on your midstream strategy as it complements R&M. So as you grow that wellhead-to-water footprint in Permian to the Texas Gulf Coast. Is your preference still to keep the commodity exposure at MPC such that if you get that final piece in market LPGs across the water, as your Midstream competitors do and R&M keeps that piece of the earnings. Could that structurally augment R&M capture?

David Heppner:

Yes, Theresa, I think as we look at building out our wellhead-to-water strategies, one thought through it is from an MPLX lens and building that industry solution, both for MPC and other shippers on the system. And the second piece of the equation as we look at it from an enterprise perspective, where can we complement the MPC, MPLX relationship to create that incremental value. But also, as Maryann touched on, maintaining the commodity risk of that marketing and trading activity more on the MPC books. I hope that helps.

Kristina Kazarian:

All right, Sheila, if there are no other questions. Thank you for your interest in MPC. If you guys have additional questions or would like a clarification on the topics discussed this morning, please reach out and the Investor Relations team will be available to take your calls. Thank you for joining us today.

Kristina Kazarian:

Welcome to Marathon Petroleum Corporation's First Quarter 2024 Earnings Conference Call. The slides that accompany this call can be found on our website at marathonpetroleum.com under the investor tab.

Neil Mehta:

I had two questions. The first one, more of an industry one, which is your perspective on the West Coast, we've seen as [ Rodeo ] has shut down in Martinez, West Coast margins have really strengthened here, particularly for gasoline. So what's your outlook as we go into the summer and your thoughts on doing business in California, broadly?

Rick Hessling:

The market really in California is fundamentally short and it's long diesel. That's kind of the thesis as we look out there. And an example of that is if you look at gasoline inventories, especially right now, they're tight.

Neil Mehta:

And then the follow-up is just on the return of capital cadence. The buyback this quarter, the $2.2 billion was a little bit lighter than what I think many on the street were modeling. Just any thoughts on what, was that a reflection of some of the onetime working capital and M&A dynamics or valuation sensitivity? And how should we think about that over the course of the year?

Manav Gupta:

Guys, in your introductory comments, you did mention that some global capacity was supposed to come on. It's challenge, it's not really come on, I'm trying to understand here, once we go past 2024, like 2025, there's limited capacity expansions that we are aware of. And at this point, I think we understand that 2024 will be above mid-cycle. But based on your commentary, would it be fair to say even Rodeo shutdown and other Houston refinery shutting down, you could well see 2025 also as a year where cracks are well above the mid-cycle levels.

Rick Hessling:

So I will echo Mike's comments and share what you know and what you're reading is what we're seeing and hearing in the marketplace as well that the expansions appear to be continuously delayed. And with that, Mike mentioned in his opening remarks, we see demand growing by 1.2 to upwards to 2 million barrels a day. So pick a number even in between there and that exceeds Manav, the expansions that may come online, end of year, this year or sometime in 2025. So even with those expansions coming online, we see demand outpacing those expansions and thus, why we're so optimistic on this mid-cycle plus environment lasting.

Manav Gupta:

Perfect. My quick follow-up here is, I don't think I remember any time when I've seen a $650 million turnaround expense in a single quarter. So this quarter was truly exceptional in the amount of downtime you took.

Maryann Mannen:

It's Maryann. Let me start. So you're absolutely right. We tried to share, as we were on our call last quarter that we expected to have really the largest turnaround in MPC's history in the first quarter, and we did. We had four of our largest assets in turnaround. We think that's important as you well stated, given getting that work done ahead of summer driving season, we think we are well poised for that.

Manav Gupta:

And just to quickly follow up, like the higher throughput also results in higher MPLX earnings for the next quarter, right?

Michael Hennigan:

Manav, it's Mike. I just want to add. I think the takeaway is, as Maryann said is, we chose to use the first quarter to take down four of our most profitable refineries. It's a lower demand period in the U.S., et cetera. And our thought process there was spend that money, increase the reliability, get ourselves ready so that we're able to perform in the second and third quarters as we progress out the year. So we think we've positioned ourselves very well despite a heavy spend in the quarter. We're happy that we've done it. We think the assets are in really good shape, and we're looking forward to the rest of the year.

Paul Cheng:

I guess that maybe different answer. If we look at comparing to your guidance from last quarter, your throughput is lower, OpEx and turnaround expenses are higher than the guidance. Is it all contributed by what you characterized that some of these quick-hit projects that is not originally in the guidance or that something else has contributed that? That's the first question.

Rick Hessling:

Yes, Paul. Thank you for the question. So on the West Coast specifically, let me maybe back up and share what is public. We do have a TMX commitment on the line and we believe we will be a significant beneficiary because we will receive incremental Canadian advantaged crude not only into Paul, our Pacific Northwest system, but also our West Coast system.

Paul Cheng:

[ Rich ] can you share that how much WCS you think you may be able to run?

Operator:

Next, we'll hear from John Royall with JPMorgan.

Michael Hennigan:

Yes, John, this is Mike. I'll start off by saying we've been fortunate enough to continue to generate cash. That's been a good story for us. Back to Neil's first question, we want to make sure there's no ambiguity. We're committed to returning capital.

Michael Hennigan:

Yes, John, I can't help myself to jump in here. I know this capture metric gets a lot of discussion. And Kristina has been steadfast that we need to report on it. I just want to caution, as I always do, that there's a lot of factors, market factors, et cetera, that hit on that. The market should know we're committed to improving our commercial performance. That's obviously a goal here. But the metric that I want is to look at the most is cash.

Operator:

Our next question will come from Jason Gabelman with TD Cowen.

John Quaid:

Great. Jason, it's John. 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've seen it in 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 in our second quarter guidance, we do not have any cost yet included in that second quarter. 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.

Maryann Mannen:

It's Maryann. 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.

Operator:

Our next question will come from Roger Read with Wells Fargo.

Rick Hessling:

Roger, it's Rick. 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.

Roger Read:

Yes, that makes sense. 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've been running at either Galveston Bay or Garyville?

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?

Operator:

Our next question comes from Matthew Blair with TPH.

Rick Hessling:

Yes, Matt, it's Rick again. So I will tell you, good call out. We're seeing octane values being 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.

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.

Theresa Chen:

When we think about your marketing margins 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?

Theresa Chen:

Sure, Rick. Related to your marketing margins and the move of the flat wholesale [ gasoline ] prices benefiting Q4 as prices declined and then acting as a headwind as they came up on how much is that can really bring noise to the R&M capture quarter-to-quarter?

Theresa Chen:

Got it. 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?

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 and the IR team will be available to help with your call today. Thank you for joining us.

Kristina Kazarian:

Welcome to Marathon Petroleum’s fourth quarter 2023 earnings conference call. The slides that accompany this call can be found on our website at marathonpetroleum.com under the Investor cab. Joining me on the call today are Mike Hennigan, CEO; Maryann Mannen, President; John Quaid, CFO and other members of the executive team. We invite you to read the Safe Harbor statements on Slide 2. We will be making forward-looking statements today. Actual results could differ. Factors that cause actual results to differ are there as well as in our SEC filings. References to MPC Capital during the prepared remarks today reflects standalone MPC Capital, excluding MPLX. With that, I will turn the call over to Mike.

Maryann Mannen:

Thanks Mike. Solid execution of our three strategic pillars remains foundational. We believe the improvements we’ve made to our cost structure, portfolio and commercial execution have driven sustainable structural benefits, irrespective of the market environment. We will continue to build on this strong foundation to recognize value throughout our business. Our refining utilization in 2023 was 92% as we operated our portfolio to meet consumer demand. Recently, we have said we believe our average capture over longer periods of time is approaching 100%. And in 2023, our full year capture was 100%. This commitment to commercial excellence is foundational and we expect to continue to see these results. While our capture results will fluctuate based on market dynamics, we believe that the capabilities we have built over the last few years and expect to enhance further will provide a sustainable advantage. Turning to our operations. In the Gulf Coast, the Galveston Bay reformer repairs progressed as planned. We started the unit back up in mid-November and returned to full operating rates by mid-December. At our Martinez facility, we will be operating at approximately 22,000 barrels per day in the short-term. We have been working closely with the regulators to proceed with repairs to ensure safe and reliable operations. Let me move to Slide 7, which shows our capital investment plan for 2024 in a bit more detail. MPC’s investment plan, excluding MPLX, totals $1.25 billion. The plan includes $1.2 billion for Refining & Marketing segments. Our growth capital plan is approximately $825 million between traditional projects and low carbon. We are investing primarily at our large competitively advantaged facilities to enhance shareholder value and position MPC well into the future. Within traditional Refining & Marketing, $100 million is associated with a multiyear project to increase finished distillate yields at the Galveston Bay refinery. $375 million is focused on smaller projects targeted at enhancing yields at our refineries, improving energy efficiency and lowering our cost as well as investments in our branded marketing footprint. Within low carbon, approximately $330 million is allocated to a multiyear infrastructure investment at our Los Angeles refinery, which will improve energy efficiency and lower facility emissions and $20 million for smaller projects focused on emerging opportunities. Slide 8 provides an overview of the multiyear investment at our Los Angeles refinery. The Los Angeles refinery is the core asset in our West Coast value chain and is one of the most competitive refineries in the regions. This investment, once completed, is expected to further enhance its cost competitiveness by integrating and modernizing utility systems, which will improve reliability and increase energy efficiency. Additionally, a portion of this improvement addresses a new regulation mandating further reductions in emissions. This regulation applies to all Southern California refineries. The improvements are expected to be completed by the end of 2025. We expect to generate a return on our investment of approximately 20%. Turning to Slide 9. At Galveston Bay, we are investing to construct a 90,000 barrel per day high-pressure distillate hydrotreater. This project is planned to strengthen the competitiveness of the refinery through increased production of higher value finished products. Once in service, the new distillate hydrotreater will upgrade high sulfur distillate to ultra-low sulfur diesel, eliminating the need for third-party processing or sales into shrinking lower value high sulfur export market. This strategic investment ensures we provide the clean burning fuel of the world demand and further enhances the competitive position of our U.S. Gulf Coast value chain. The project is expected to be complete by year-end 2027 and generate a return of over 20%. Turning to our low carbon initiatives, we challenge ourselves to lead in sustainable energy by setting meaningful targets to reduce greenhouse gas emissions, methane emissions and fresh water intensity. Targets, which we believe we can demonstrate a tangible pathway to accomplish. In our 2024 capital outlook, we are investing to significantly lower energy intensity and emissions at Los Angeles, one of our largest refineries. Additionally, we are investing in smaller amounts of capital in early-stage developments like RNG which could significantly aid in greenhouse gas emission reductions in the future. Overall, we are taking disciplined steps to advance our goal to lower the carbon intensity of our operations and the products we manufacture, while continuing to supply a growing and evolving market by safely operating our current asset base with the objective to deliver superior cash flow. Let me turn the call over to John.

Mike Hennigan:

Thanks, John. We’ve delivered strong execution on our strategic commitments again this year. This includes running reliably with high utilization, structural improvements to our commercial performance, fostering a low cost culture and strengthening the competitive position of our assets. At MPLX, the partnership has continued to grow, increasing its cash flow and its cash distribution MPC. We have invested capital to grow earnings while exercising strict capital discipline. This has resulted in superior cash flow generation and supported the repurchase initiatives. Looking forward, we will continue to prioritize capital investments to ensure the safe and reliable performance of our assets, and we will also invest in projects where we believe there are attractive returns. We believe our focus on safety, environmental, I’m sorry, operational excellence and sustained commercial improvement will position us to capture this enhanced mid-cycle environment, which we expect to continue longer-term, given our advantages over marginal sources of supply and growing global demand. MPC’s Midstream segment, consisting primarily of MPLX has grown EBITDA by $1.3 billion since 2019, which is a 6% compound annual growth rate over the last 4 years. As MPLX continues to grow its free cash flow, we believe it’s in a strong position to continue to consistently grow its distributions. As a result of MPLX increase against distribution 10% of reach in the last 2 years, and MPC expects to receive $2.2 billion of cash distribution, which reflects a $400 million increase since 2020. Each 10% distribution increase is approximately $200 million of additional cash flow that MPC receives through its ownership in the partnership. In summary, this year, we generated $14 billion of cash from operations. We increased our dividend 10%, repurchased $11.6 billion of shares, resulting in a 92% payout ratio. In 2023, MPC’s total shareholder return was 31%. We believe MPC is positioned as the refinery investment of choice with the strongest through-cycle cash generation and the ability to deliver superior return to our shareholders. With that, let me turn it back over to Kristina.

Operator:

Thank you. [Operator Instructions] Our first question will come from Neil Mehta with Goldman Sachs. Your line is open.

Maryann Mannen:

Hey, Neil, good morning. It’s Maryann. Thanks for the question. So first and foremost, as you know, commercial performance has been and will continue to be a foundational pillar for us in terms of delivering outstanding execution and meeting the goals and objectives that Mike shared with you around delivering best through cycle cash flow throughout the cycles. In the quarter, we generated about 122% capture as we shared. Overall, as you know, we’ve been talking about our ability to continue to drive toward 100%. Over the last couple of quarters, Rick and Brian have been sharing with you some of the key elements around structural changes that we believe are sustainable, and then Mike announced this morning a couple of other changes, which we think will continue to drive our ability to identify and deliver against that foundational principles. In the quarter, we had a couple of benefits that delivered the 122%. So first of all, strong light product margins and frankly, a more favorable secondary products impact. This is not abnormal for this period of time. Having said that, we also saw stronger jet fuel premiums to diesel and the benefit of diesel blending, excuse me, of butane blending in the quarter as well. To your question, how much of this is repeatable? Obviously, some of those things are not repeatable, particularly when we look at the sharper drop in crude oil and refined product prices. We also did have the ability of having, as I shared with you, our reformer at GVR and other benefits of projects that we completed fully operating in the quarter. So let me pause there and see if that helped to answer your question at all.

Mike Hennigan:

Yes, Neil, it’s Mike. Yes, I think we said in our prepared remarks that our turnaround spend this year is about the same as last year. But the way you should think about it is, as Maryann mentioned, in the first quarter, we’re pretty heavy at four of our largest facilities, our largest financial generating facility. So we’re taking advantage of the fact that margins are down in the first quarter. So we’re spending $600 million in the first quarter, which is a high number, relative to the full year. And I know we don’t traditionally give quarter-to-quarter, but I’ll just tell you that next quarter, the turnaround number drops down to like $200 million or so, somewhere in that range. So we’re being opportunistic in some regard. A lot of the activity does get planned, but at the same time, we want to take advantage of the fact that the margin environment now is constructive for us to be off-line so that when margins, we think, are going to be a lot stronger in the second quarter, we will have our four largest facilities turn around and ready to deliver results.

Mike Hennigan:

You are welcome, Neil.

Manav Gupta:

First of all, congrats guys. I know one of the goals was to get to 100% capture, although Mike always stays focused on EBITDA per barrel margin and free cash. I know one of the goals was to get to 100% capture. So congrats on overshooting that mark. My question here is on the two growth projects. Los Angeles. Some of the people out there are looking to exit the state given the tougher laws, you were actually going back and investing in this project. So help us understand what’s driving that? And again, on the Galveston Bay moving from upgrading high sulfur to ULSD, what kind of realization uplift could you get if you do execute this project?

Manav Gupta:

Perfect. My quick follow-up here is you were looking to ramp towards the nameplate capacity at your renewable diesel project on the West Coast. If you can give us some update over there, how is that project progressing?

Manav Gupta:

Thank you so much.

Operator:

Thank you. Next, we will hear from Doug Leggate with Bank of America Securities. You may proceed.

Rick Hessling:

Yes. Hi, Doug, this is Rick. So I’ll take a stab at that. So we are significantly I would say every day, Doug, we are optimizing our slate. And we look at this regionally. We look at this by plant. But in the end, Doug, I think what we do better than others in the industry, is we optimize for the betterment of our total return at the end of the day. So we are not, we could suboptimize one plant for the benefit of another, and we have worked years, decades, as a matter of fact, to give ourselves optionality within our Mid-Con system. We are currently juggling optionality with TMX and our West Coast and Pacific Northwest system as well as we’ve worked on it for quite a while on the Gulf Coast. So you are onto something from a crude slate perspective. It’s constantly changing. We’re constantly pushing the norm on what we should run, what crudes we look at, what assays we look at, updating our system. So this is just an ongoing exercise that’s been happening now for several years now. And I’ve said it before, we’re unpacking everything from A to Z, Doug, we’re leaving no rock unturned in terms of capturing value. And that not only goes certainly on the crude slate side, but it goes throughout our entire value chain.

Doug Leggate:

LPs are a complicated beast and you guys seem to have figured it out. So thank you for the answer, guys. My follow-up is probably for, it might be for Maryann. I’m not sure. Congratulations to everyone on the new roles. But Maryann, if I look at Slide 21, you’re showing your debt maturity profile at the MPC level. Obviously, sitting with a net cash position at the MPC level, what are your thoughts on where you want your balance sheet to be as those debt maturities come due?

Doug Leggate:

I wasn’t sure if you take or not. Thank you.

Doug Leggate:

And John, remind me, is that consolidated for MPLX or stand-alone?

Doug Leggate:

Okay, thank you.

Doug Leggate:

Thank you very much.

Paul Cheng:

Hey, guys. Good morning.

Paul Cheng:

Mike, I think in the past, you have shown that you are not really interested in acquisition of refining assets. But one may argue that, I mean, given how well you are running your facility, do you think that there is a value to be added to have some additional assets to your platform so you can apply your technical know-how to even a bigger profile. And also in the Gulf Coast, you have two huge refineries. If we add additional facility, would that further diversify and reduce the operating risk, having multiple facilities and also, frankly, that will perhaps even increased commercial and optimization opportunities. So just want to see that, I mean, how you guys look at that question internally?

Paul Cheng:

Absolutely. Can I just go back into the commercial question? In the fourth quarter, you guys definitely done well in the [indiscernible]. And if we’re looking at versus the margin capture of 100 additional 22%, is there a number that you can share how much of them is coming from the commercial side of the business that you have done really well? And that’s why that you are seeing that much better in the capture. And also that I think in the past, you’re saying that one of the maybe Holy Grail for commercial operations is that you will be able to optimize based on breakdown the [indiscernible] and optimized based on the total company. Where are we in that process? Do you think that you are already there or that you are just still stretching the surface on that process?

Paul Cheng:

Thank you.

Maryann Mannen:

Hey Paul, it’s Maryann. I just might try to add a bit more around some of the things that we are doing specifically around commercial performance without necessarily trying to give you a percentage. But we have been talking over the last several quarters about the capabilities we have built regionally, obviously, at Houston office and Singapore office or London office. That has helped us. That was laughingly saying to Mike about cracking the code on linear programming. But some of the capabilities that Rick and Brian and their respective teams have built historically give us very robust tools and data analytics that allow us to assess the decisions that we have made and know how good or bad those decisions were and what we might do with that to change it. So, it is building. These capabilities are building sustainable learnings and capabilities in the organization that we think will continue to drive our performance. I hope that’s a bit more helpful, too.

Operator:

Next, you will hear from Roger Read with Wells Fargo. You may proceed.

Mike Hennigan:

Thank you, Roger.

Mike Hennigan:

Yes. Roger, I will start off with, the changes are driven by two things. Results, one of the things that I feel my responsibility is to reward the results that we are getting because the team has done a very nice effort across the whole team. And the second part is development, putting people in positions such that they grow more personally so that they can contribute to the team. So, both of those factors, I think played into a lot of these assessments that occurred at the executive level, but it’s also occurring below that and not everybody gets to see. So, I am a big believer in the team approach, practically all decisions that we make, all of our team is involved in. So, there is a heavy component of development on top of the results that have occurred in the last couple of years. As far as me, personally, I think you have heard in the past, that’s a Board decision. The Board is very aware of that. That will play itself out in time. But Board’s, if it’s not their top priority, it’s obviously at the very top of the first couple is what their responsibility is. So, that’s just work in progress. It’s been in progress for quite some time, and it will play itself out as time goes by.

John Quaid:

Hey Roger, it’s John. You read through my subtle comments very, very well. And certainly, the other part of that equation, right, is what we are doing on the equity side. So, that was my comment, hey, we think our gross levels of debt are appropriate as we look forward, because that will be part of the math. We will take a look at that, but I think you are pretty spot on. I am not sure I can add much from what you said to be honest.

Roger Read:

Thanks.

Operator:

Thank you. Our next question will come from John Royall with JPMorgan. Your line is open.

John Quaid:

Yes. Hi. Good morning John, it’s John here. I will take that one and let Mike add some other comments as well. But let me just start by saying, as I roll into the seat, I want to be clear, there is no change in how we are viewing return of capital, as you heard even in Mike’s prepared remarks. Again, really strong performance last year, again, as we are looking to drive strong returns to our investors, and that will continue to be a key part of our capital allocation priorities in 2024. And as we look at that, we are going to look at lots of things. One, we want to be opportunistic in the overall capital allocation and we will consider the refining macro environment along with lots of other items, but – and the balance sheet and where it is. But ultimately, I just want to be clear, we are going to be steadfast in our commitment to return of capital.

John Royall:

Great. Thank you. And then I apologize ahead of time to Mike for this, but I do have another question on capture. But the commercial stuff aside, can you help us think about some of the moving pieces in the first quarter? And particularly, how should we think about the impact of the heavy maintenance in the quarter? Is this still a potential to be 100% maintenance, given you have so much maintenance and any other moving pieces that we should think about that might move you away from that 100% either direction in 1Q?

John Royall:

Great. Thank you very much.

Operator:

Our next question will come from Theresa Chen with Barclays. Your line is open.

Rick Hessling:

Hi Theresa, this is Rick. I will attack the new refining capacity first. So, we see that coming on later versus sooner. And when I say later, I would say second half of this year and then some over the years, when you bring on new greenfield facilities, which are being brought on, it’s been proven difficult to bring them on in a timely fashion. And these specific facilities like others, we will face challenges with logistics and supply. So, I won’t specifically comment on the 1.5 million barrels, but I will say we believe it will be later versus earlier. And then for the demand piece specifically, certainly, you have seen, as you referenced, utilization even here recently down 7% in the last week due to turnarounds and weather-related events. When we look at that and look going forward, we are continuing to see steady demand. As Mike mentioned in his opening remarks, our export book on gas and diesel has been very solid. It was solid in 2023, and we are off to a very good start in ‘24. So, when we look at all of this together, we see it setting up very well, Theresa, for a very supportive spring and summer season.

Theresa Chen:

Thank you.

Operator:

Thank you. Our next question will come from Ryan Todd with Piper Sandler. Your line is open.

Rick Hessling:

Yes. Ryan, it’s Rick. So, for U.S. advantages, they are quite significant. Mike touched on early on in his prepared remarks, we have a feedstock advantage here in North America with feedstock at our doorstep, and we have access to crude from around the world. So, we believe that’s a significant advantage. And it’s been very well documented. We have an energy advantage with the U.S. being extremely long in nat gas, and we have cheap nat gas prices. But in addition to that, when we look at our workforce, at our assets and our refinery complexity, when you start layering all of those on top of one another, Ryan, it adds up significantly to an advantage, which is why Mike referenced earlier, we believe in an enhanced mid-cycle. Now, when you think of it from our perspective, this is where our scale really comes into play. So, we run a 1 billion barrel of system, a 1 billion barrel system annually. So, you can pick the number. We won’t give you a number, but it’s easy math. If it’s mid-cycle plus $1, that adds $1 billion to MPC’s bottom line, a $2 incentive or enhancement over mid-cycle, $2 billion. So, that’s where our scale really comes into play. Now, we are bullish because of a lot of the reasons Mike mentioned. Global demand, we believe will hit a record consumption in ‘24. ‘23 was a record, we believe ‘24 will be a record. IEA believes ‘24 will be a record. In fact, IEA continues to revise up their demand forecast month-after-month and have done so for the last three months. In addition, we referenced turnarounds. Globally, turnarounds are high. When you are looking at history and we are set up well here for a strong spring and summer. I hope that helps you.

Operator:

And we do have time for just one more question. Our last question will come from Jason Gabelman with TD Cowen. Your line is open.

Mike Hennigan:

So, Jason, on your first part, there is nothing that you said was avoiding costs, however. So, nothing is related to that. So, it’s a – think of it as a reliability project, a modernization project, an efficiency project, a lower-cost project, and reducing greenhouse gas, which we need to do out there. There is regulations out there that are going to occur over time. We could have made the choice to wait until that regulatory requirement was there, but we saw an opportunity to enhance the facility ahead of time. And we have kind of disclosed already, we think there is greater than 20% return there. How do we get comfortable in the overall macro, there is going to be a tough environment for California, if things get more and more competitive out there. But we think we have a very competitive asset. So, we think we are in it for the long-term. We don’t think all the facilities out there will survive the long-term, but as that volatility occurs out there, we want to have a really strong, competitive, reliable, efficient, low-cost facility.

Kristina Kazarian:

Alright. And with that, thank you for your interest in Marathon Petroleum Corporation. Should you have additional questions or like clarification on any of the topics discussed this morning, please reach out and a member of the Investor Relations team will be here to help you. Thank you for joining us.

Kristina Kazarian:

Welcome to the Marathon Petroleum Corporation third quarter 2023 earnings conference call. The slides that accompany this call can be found on our website at marathonpetroleum.com under the Investors tab. Joining me on the call today are Mike Hennigan, CEO; Maryann Mannen, CFO and other members of the executive team. We invite you to read the Safe Harbor statements on slide 2. We will be making forward-looking statements today. Actual results may differ. Factors that could cause actual results to differ are included there as well as in our filings with the SEC. References to MPC’s refining utilization for the third quarter, as well as fourth quarter guidance now include the addition of approximately 40,000 barrels a day of capacity related to STAR in our Gulf Coast region. And with that, I’ll turn the call over to Mike.

Maryann Mannen:

Thanks Mike. Moving to third quarter highlights, slide 5 provides a summary of our financial results. This morning, we reported adjusted earnings per share of $8.14. This quarter’s results were adjusted to exclude a $106 million gain on sale of MPC’s 25% interest in the South Texas Gateway Terminal, as well as $63 million of response costs associated with our unplanned outage at Garyville. These adjustments reduced our reported adjusted earnings by $0.14 per share. Adjusted EBITDA was $5.7 billion for the quarter. And cash flow from operations, excluding favorable working capital changes, was over $4.3 billion. During the quarter, we returned $297 million to shareholders through dividend payments and repurchased over $2.8 billion of our shares. And from May 2021 through October 27th, we have repurchased 285 million shares or approximately 44% of the shares outstanding. Slide 6 shows the reconciliation between net income and adjusted EBITDA as well as the sequential change in adjusted EBITDA from second quarter 2023 to third quarter 2023. Adjusted EBITDA was higher sequentially by approximately $1.2 billion, driven by higher R&M margins. Corporate expenses were higher sequentially by $40 million, primarily due to a charge related to valuation of existing performance-based stock compensation expense. The tax rate for the third quarter was 22%, resulting in a tax provision of approximately $1 billion. Moving to our segment results, slide 7 provides an overview of our Refining & Marketing segment. Our refining assets ran at 94% utilization, processing nearly 2.8 million barrels of crude per day at our 13 refineries. Sequentially, per barrel margins were higher across all regions driven by higher crack spreads. Capture was 93%. Refining operating costs were $5.14 per barrel in the third quarter, flat sequentially. We did have unplanned downtime during the quarter, impacting our two largest refineries, which resulted in lost crude throughput of 4.7 million barrels due to the Galveston Bay reformer outage and 2.1 million barrels at Garyville. Additionally, this downtime resulted in a headwind to our overall capture. We began construction activities on the reformer repair about three months after the event, once regulators gave us clearance and we were able to finalize the required repairs. Since then, repairs have progressed as planned and during this outage, we pulled forward turnaround work into the third and fourth quarters, which had been scheduled in the first quarter of 2024. Slide 8 provides an overview of our Refining & Marketing margin capture this quarter, which was 93%. Our commercial team executed effectively, despite weak secondary product pricing and refinery downtime, which weighed on capture this quarter. Capture results will fluctuate based on market dynamics. We believe that the capabilities we have built over the last few years will provide a sustainable advantage. This commitment to commercial performance is foundational and we expect to continue to see the results. Slide 9 shows the change in our Midstream segment adjusted EBITDA versus the second quarter of 2023. Our Midstream segment delivered strong third quarter results. Segment adjusted EBITDA was flat sequentially and 3% higher year-over-year, primarily due to higher throughputs and rates. Year-to-date, our Midstream segment EBITDA is up 6% compared to the prior year period. As Mike mentioned earlier, the growth of MPLX’s earnings supported its decision to increase its quarterly distribution by another 10% to $0.85 per unit, and MPC expects to receive $2.2 billion in cash from MPLX on an annual basis. Our Midstream business continues to grow and generate strong cash flows. We are advancing high-return growth projects anchored in the Marcellus and Permian basins. Slide 10 presents the elements of change in our consolidated cash position for the quarter, operating cash flow, excluding changes in working capital with over $4.3 billion in the quarter. Working capital was a $609 million tailwind for the quarter, driven primarily by increases in crude oil prices. Year-to-date, working capital has been $1.4 billion worth of cash. Capital expenditures and investments totaled $486 million this quarter, consistent with our 2023 outlook. MPC returned nearly $3.1 billion via share repurchases and dividends during the quarter. This represents an approximately 72% payout of the $4.3 billion of operating cash flow, excluding changes in working capital, highlighting our commitment to superior shareholder returns. As of October 27th, we have approximately $8.3 billion remaining under our current share repurchase authorization, which includes the additional $5 billion approval announced last week. At the end of third quarter, MPC had approximately $13.1 billion in consolidated cash and short term investments. This includes approximately $1 billion of MPLX cash. Turning to guidance, on slide 11, we provide our fourth quarter outlook. We expect crude throughput volumes of over 2.6 million barrels per day, representing utilization of 90%. Utilization is forecasted to be lower than third quarter levels due to turnaround activity having a higher impact on units in the fourth quarter. In the Gulf Coast, with respect to the Galveston Bay reformer, repairs have progressed as planned. We anticipate starting the unit back up in mid November. Production is expected to ramp over the next several weeks. And guidance anticipates returning to full operating rates by mid-December, following advanced turnaround activity. And as I mentioned earlier, during this outage, we plan to continue progressing and complete turnaround work that was previously scheduled for 2024. As a result, planned turnaround expense is now projected to be approximately $300 million in the fourth quarter. Operating costs per barrel in the fourth quarter are expected to be $5.60, higher sequentially due to higher energy cost, particularly on the West Coast, as well as higher project-related expenses associated with planned turnaround activity. Distribution costs are expected to be approximately $1.4 billion for the fourth quarter. Corporate costs are expected to be $175 million, representing the sustained reductions that we have made in this area. With that, let me pass it back to Mike.

Kristina Kazarian:

Thanks, Mike. As we open the call for your questions and as a courtesy to all participants, we ask that you limit yourself to one question and one follow-up. If time permits, we’ll re-prompt for additional questions. And with that, Sheila, we’re ready for them.

Manav Gupta:

When we look at the refiners, they look at themselves and perform -- on different performance metrics, some look at refining capture. You guys really focus on EBITDA margin per barrel. And when we look at that metrics, it looks like for a second year in a row, you’ll be on top of that table, outperforming your peers. So, help us understand a little better what’s allowing you to drive this outperformance and deliver such strong results when it comes to EBITDA margin per barrel in your refining system?

Mike Hennigan:

Manav, it’s Mike. The only thing I would add to what Rick said is, we start with EBITDA per barrel. We want to make sure we’re generating as much earnings as we can as we run our assets. Ultimately, though, I care the most about cash generation. I mean, it starts with EBITDA per barrel, but the bottom line is, are we generating significant amount of cash to give us the flexibility to drive shareholder returns. So, I think you hit the starting point with EBITDA per barrel. The ending point is generating cash and then having that flexibility.

Maryann Mannen:

Yes. Thank you, it’s Maryann and thanks for the question. You’re right. As we shared with you, we did have a couple of unplanned downtime events in the quarter that impacted the Gulf Coast. One, the most significant in terms of its contribution is the Galveston Bay reformer, and then, obviously, we had our, Garyville. Had we not had those two impacts, I’m happy to share a little bit more about those in a moment here, our capture would have been 6% higher than what we reported with the lion’s share of that capture event obviously being the reformer. As I mentioned, 4.7 million barrels in the quarter that we lost, and then on Garyville, it’s about 2.1 million barrels as we operated about half rate for just under a week. It took us about -- just back to, Galveston Bay for a moment. It took us about three months before, we were able to begin our work as we -- as the regulators got through their work and then we determined where all the repairs needed to be. So we were about three months, to the start of getting those, activities launched. I hope that answers the question.

Doug Leggate:

Well, first of all, thank you for taking my questions. Maryann, that last response was actually one of the key things we wanted to hit. So, let me try two more if I may. First of all, Mike, in your opening remarks, you talked about demand in your system is pretty strong. I wonder if I could ask you to isolate that to export demand, because obviously that’s a fairly big swing factor for the U.S. market in particular. How does that look in your system?

Brian Partee:

So really, our theme on demand, both domestically and internationally is stable and steady. It’s been that way really throughout the year. In the quarter, we exported roughly 250,000 barrels a day out of our system in the Gulf Coast, despite some operational challenges, as noted. About two-thirds of that is distillate, the balance of course is gasoline. The demand center in Latin America and the Caribbean really has been strong and resilient and growing throughout the year. They import roughly 2.3 million barrels a day into the system. The U.S. has been about 65% of that. We have come off a little bit in terms of our share into Latin America and the Caribbean in exchange for share into Europe. So, we are seeing growth in European imports as you’ve probably seen as well, roughly 200,000 barrels a day in the quarter from the U.S. into Europe. The one cautionary tale there, it is the one weakest spot that we see throughout our network, which is distillate demand in Europe. Our team sees it as roughly 4% to 6% off year-to-year with expectations and a bit of hope that as we get into the colder weather season here later this year, we’ll see a pickup in demand in Europe, but that is the one soft spot that we’re seeing.

Mike Hennigan:

I’m going to let Dave start, and then I’ll come back afterwards.

Operator:

Our next question will come from Paul Cheng with Scotiabank.

Brian Partee:

Yes. Paul, good morning. This is Brian. I’ll take that one. Really very limited impact in the quarter from our marketing business on the West Coast. We actually saw prices increase pretty substantially on the West Coast in the quarter due to some unplanned outages in the system. And when that occurs, we actually see just the opposite. We see a lot of pressure on the margin out in the West Coast and other markets. So, not a big contributor there in the quarter. Now, as we look ahead to 4Q, as market comes off, we would expect to see some recovery and some margin expansion in the fourth quarter. But to your other question, we are absolutely actively engaged in growing and continuing to grow that network. We’ve put up really good numbers last year and this year and look at it as a strategic component of our position out in the West Coast.

Brian Partee:

Really don’t want to forecast a station growth expectation, Paul. We’re really focused on value growth. So it’s really it’s a PV optimization looking at volume and margin, so it’s not driven by station growth or volume alone.

Maryann Mannen:

Sure, Paul. It’s Maryann. Let me talk a little bit about CapEx in general and then I’ll pass it to Mike and he’ll share some incremental thoughts as well. But as you know, one of our principles, if you will, our strategic pillars is strict capital discipline. And I think that has -- hopefully you’ve seen that we have implemented that principle well over the last few years. When you look at 2017 to 2020, our consolidated CapEx averaged about $3.5 billion. And as you look ‘21 to ‘23, that’s averaged $2.1 billion. So again that premise of strict capital discipline ensuring that we’re delivering the returns has been an important piece of the work that we’ve been doing. I think in refining, we continue to look for cost reduction type projects, those that can enhance reliability, margin enhancement type projects, then that we would be continuing to evaluate, and there are several of those projects that we’ll evaluate. In terms of the timing, we’re a bit early for 2024, frankly, even 2025 guidance. But let me pass it to Mike because I think he wants to give you some incremental color on how he’s thinking about it.

Operator:

Our next question comes from Sam Margolin with Wolfe Research.

Maryann Mannen:

Sam, it’s Maryann. Let me give you a few thoughts on that, and I can pass it to Mike in case he’s got some added value. I mean, there are several things that we look at as we are making decisions about the level of share buyback. And certainly, when we’re looking at intrinsic value, there’s a couple of approaches. So we’ll look at some of the parts. We’ll look at discounted cash flows. We use a series of reviews, obviously, looking at our EBITDA multiples of their respective businesses. But typically, when we are making the decision about an MPC buyback, that intrinsic value assumes the discounted cash flows, as I just shared. There are several constraints as we look at that that we evaluate each time we go to buy back stock, none the least of which obviously is market, cash flows, where we think the quarter is going to be, where we think our cash balances are. And we’ve worked pretty diligently to try to outperform the market here. Hopefully, you’ve seen that over the significance of the buyback that we’ve done. But we do look at it in a holistic approach. Let me pass that back to Mike and see if he wants to add any color.

Sam Margolin:

Yes, very much so. Thanks. And my follow-up is just more of a straightforward ops question, but it’s about the West Coast. And TMX has been delayed. But once it starts up, it might be impactful to fundamentals on the West Coast. And it seems noteworthy because of your comments about how the Midwest is this integrated system with shipper status for WCS and you’re able to move things around. And so I wonder in the context of TMX, if there’s -- if you see any analogs there with building out sort of a full value chain or commercial integrated platform.

Operator:

Next, you will hear from Roger Read with Wells Fargo.

Jim Wilkins:

Roger, this is Jim Wilkins. We’re working with the county on one issue related to our land use permit. That issue, we expect will get resolved in the upcoming months, and it’s related to our odor mitigation plan. The resolution of that matter won’t impact our ability to construct or operate the facility.

Jim Wilkins:

No.

Jim Wilkins:

No, Roger. So, we actually have an approved odor mitigation plan with the Air Quality Division. And actually, what we’re doing is circling back to the land use permit where we said we’d develop an order mitigation plan and embedding the plan that’s already been approved.

Jim Wilkins:

Correct.

John Royall:

So I had -- my first one is a follow-up on the buyback. You’ve now gotten through another quarter with a really solid crack environment in 3Q and another quarter where you aren’t drawing any cash. And in fact, you build cash by about, I think, $1.5 billion which I wouldn’t characterize as a problem by any stretch, but you’ve talked about getting that cash balance down closer to $1 billion longer term. And Mike talked about the constraints to doing more on the buyback. And now, we’re seeing a worsening environment in 4Q. So, my question is, given all your excess cash, should we think about the buyback as not particularly sensitive to the crack environment? And would you expect to start drawing cash from here?

John Royall:

Great. Thank you. And then Maryann called out some turnaround work pulled in from next year to the second half of this year. And so just thinking about next year, any early look on what 2024 could look like from a turnaround perspective. I think you had some catch-up over the past two years, and now this work pulled into ‘23. So, is it reasonable to think it might be kind of a below average year?

Operator:

Our next question comes from Jason Gabelman with TD Cowen.

Mike Hennigan:

Jason, it’s Mike. I’ll start, and I’ll let Mary jump in. Yes, I think what you’re referring to is we had a bigger increase before because the way we looked at it is most in our industry kind of paused around COVID during that tough year of cash. So, we made a bigger jump. And now what we’re showing this year is we’re trying to show the market that we believe in a growing dividend that is part of our capital allocation. We want it to be competitive. But at the same time, I often say that it’s more tax efficient to go return capital through share repurchases. And the sheer quantum of dollars in each case is pretty different. So overall, we want the market to know, yes, we’re going to grow the dividend. We’re going to consistently do that. We want it to be competitive. We want to show that we’re going to grow earnings, that comes back to investing capital and all the self-help that we can do. But at the same time, we’re going to err more on the side of share repurchases because we think it’s more tax efficient and a better way to return capital.

Jason Gabelman:

Got it. Thanks for that. And then my follow-up is on one of the growth projects that I think you have for next year, the hydrogen hub project that was selected for funding from the DOE. I was hoping just to get more color on exactly what Marathon’s participation is in that project, how it could benefit the Company? Any thoughts around capital spending that you would have to contribute there?

Jason Gabelman:

Okay. When should we see those benefits start to accrue when do the projects come on line?

Operator:

Our next question comes from Theresa Chen with Barclays.

Rick Hessling:

Yes. Hi Theresa, it’s Rick. So on the first part of your question, I’m just really not in a position to comment on the toll or speculate what it may end up at. On the second part of your question, the guidance I’d give you is as we look at the forward curve on WCS, so today, WCS sits at about a $26 discount. In Q1, it’s plus or minus $25. And in Q2, if TMX comes online there, and I think the market is still questionable on that. The forward curve is $15 to $18 discount. So still a pretty significant discount. And we’ll just have to see where it goes from there.

Dave Heppner:

Yes. Theresa, this is Dave again. I’ll touch on that. So yes, the LF Bioenergy investment, that joint venture is progressing as we planned. We are building out the facilities. The plan is to build out 13 of those RNG facilities collecting a very low CI dairy RNG and then monetizing that, again, as I touched on a little bit with the hydrogen hub taking that RNG into our renewable diesel facilities such as Dickinson and Martinez, will lower the CI of that base renewable diesel product coming out. So relative to the relationship and the investment, we’re very happy with the investment, the management team there, the projects we’ve -- that they’re identifying, they’ve got a good runway of portfolio projects and they’re coming on line as planned. And the second part of your question, is this a one-off or a foundation for subsequent investments in renewable diesel space or the renewable natural gas space. So, we continue, as I said earlier, we look at a lot of stuff. There are some opportunities out there. But we -- the key to this one was we got in early and didn’t overpay for a built-out system. So when we think of subsequent investments, I think of them that way. If there’s one that we can step in early and participate in the build-out of the infrastructure and integrate it with our business rather than paying for a built-out system, we’ll continue to evaluate those opportunities.

Matthew Blair:

Maybe sticking with the renewables. For some operators, the next leg of the RD story is moving into SAF, is that an option for Martinez? And if so, any thoughts on timing or cost to add that flexibility?

Mike Hennigan:

Hey Matthew, it’s Mike. I’ll just add to your and to Theresa’s question. I think what you’re trying -- or hopefully, what you’re seeing from us is we’re attentive to this whole low-carbon world, whether it’s investment in RNG, like Theresa talked about or as Dave just mentioned, SAF, in my opinion, is going to happen at some period. As Dave said, there’s a little bit of wrangling around the economics of it at this point. But when those opportunities present themselves to us, we’ll continue to optimize our portfolio. So, I think if you take a stair step over time, you’re going to see us continue to be conscious of that, at the same time, recognizing that the base business is still the majority of what we do. But over time, we’re going to continue to look, whether it’s RNG, whether it’s SAF, whether it’s continued build-out in some other areas, those are things that we continue to evaluate. Dave and his team is constantly looking at it, and we’ll make some investment there. But we’re not looking for the big splash of a major investment, as Dave just said. We’re not looking to buy something that’s already been proven out. We’re looking to get ourselves in and grow with those opportunities.

Maryann Mannen:

Hey Matthew, it’s Maryann. Yes, I think it’s hard for us to project capture. But when you talk about the things you did, obviously, as we shared, the reformer we expect will begin to come back up mid-November, our guidance reflects the fact that it will be operational at planned rates mid-December. We talked about some secondary headwinds. We talked about marketing margins changing. You heard Brian talk about that as well. Those things clearly have a positive influence on capture. But as you know, it’s difficult to predict where capture would otherwise go. But certainly, those things point to improving capture from the third quarter.

Ryan Todd:

Maybe if I could I have one follow-up on the Martinez conversion project. Can you talk about where you are from an operational point of view there? Maybe how much throughput you had in -- during the third quarter from Phase 1 of the project? And maybe as we think about startup of Phase 2 of that project by the end of this year, is there any ramp that we should associate with it, either in terms of total throughput or in terms of the type of fees that you anticipate working their way into the system? So, how should we think about the progress from an operational point of view from -- for that asset?

Kristina Kazarian:

All right. With that, thank you so much, everyone, today 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, and our team will be available to take your calls. Thanks so much for joining us.

Kristina Kazarian:

Welcome to Marathon Petroleum Corporation’s second quarter 2023 earnings conference call. The slides that accompany this call can be found on our website at marathonpetroleum.com under the Investors tab. Joining me on the call today are Mike Hennigan, CEO; Maryann Mannen, CFO and other members of the executive team. We invite you to read the Safe Harbor statements on Slide 2. We will be making forward-looking statements during the call today. Actual results may differ. Factors that could cause actual results to differ are included there as well as our filings with the SEC. And with that, I will turn the call over to Mike.

Maryann Mannen:

Thanks Mike. Moving to second quarter highlights, Slide 5 provides a summary of our financial results. This morning, we reported earnings per share of $5.32. Adjusted EBITDA was $4.5 billion for the quarter and cash flow from operations excluding favorable working capital changes was over $3.1 billion. During the quarter, we returned $316 million to shareholders through dividend payments and repurchased $3.1 billion of our shares. Slide 6 shows the reconciliation between net income and adjusted EBITDA as well as the sequential change in adjusted EBITDA from the first quarter of 2023 to the second quarter of 2023. Adjusted EBITDA was lower sequentially by approximately $700 million as higher refining throughput was more than offset by lower market crack spreads. Corporate expenses were roughly in line with our guidance. And despite general inflationary pressures, we have maintained cost discipline since taking $100 million out of our corporate cost since 2020. The tax rate for the second quarter was 18.4%, resulting in a tax provision of approximately $583 million. Our tax provision included a $53 million discrete benefit related to prior years. Moving to our segment results. Slide 7 provides an overview of our Refining & Marketing segment. Refining utilization increased 4% to 93% despite significant turnaround activity as plan work had a lower impact on crude units in the second quarter. During the quarter at Galveston Bay, an incident occurred at one of the refineries catalytic reformers. This unit has been out of service since May 15. This resulted in approximately 2.5 million barrels of crude throughput reduction and an approximate 1% reduction to capture. Sequentially, per barrel margins were lower in the Gulf Coast and Mid-Con regions driven by lower crack spreads and our sour crude differentials. Capture was 97%, reflecting a strong result from our commercial team, particularly given the extensive turnaround activity early in the quarter. Refining operating costs were $5.15 per barrel in the second quarter, lower sequentially and due to higher throughput and lower energy costs. Slide 8 provides an overview of our refining and marketing margin capture this quarter, which was 97%. Our commercial team executed effectively and achieved a strong capture result, considering a significant amount of planned and unplanned refinery downtime. Gasoline and distillate margin tailwinds were balanced against weaker secondary product pricing. We are also seeing incremental product yield and crude mix benefits from recent major capital projects. Capture results will fluctuate based on market dynamics. We believe that the capabilities we have built over the last few years will provide a sustainable advantage. This commitment to commercial performance has become foundational, and we expect to see the results of this emphasis. Slide 9 shows the change in our Midstream segment adjusted EBITDA versus the first quarter of 2023. Our midstream segment delivered strong second quarter results. Segment adjusted EBITDA while flat sequentially was 5% higher year-over-year. Our midstream business continues to grow and generate strong cash flows. We are advancing high-return growth projects anchored in the Marcellus and Permian basins. These disciplined capital investments, along with our focus on cost and portfolio optimization are expected to grow our cash flows. This will allow us to reinvest in the business and return capital to unitholders. Slide 10 presents the elements of change in our consolidated cash position for the second quarter. Operating cash flow, excluding changes in working capital, was $3.1 billion in the quarter. Working capital was an $854 million tailwind for the quarter, driven primarily by changes in crude oil and refined product inventories. Capital expenditures and investments totaled $570 million this quarter, consistent with our 2023 outlook. MPC returned nearly $3.4 billion via share repurchases and dividends during the quarter. This represents a 100% payout of the $3.1 billion of operating cash flow, excluding changes in working capital, highlighting our commitment superior shareholder returns. And as of today, we have approximately $6.3 billion remaining under our current share repurchase authorization. At the end of the second quarter, MPC had approximately $11.5 billion in consolidated cash and short-term investments. Turning to guidance, slide 11. We provide our third quarter outlook. We expect crude throughput volumes of roughly 2.7 million barrels per day, representing utilization of 94%. Utilization is forecasted to be higher sequentially due to lower planned turnaround activity in the third quarter, and enhance mid-cycle margins, continue to incentivize high refining utilization. While we have not confirmed a start-up date, our throughput guidance assumes the reformer at the Galveston Bay refinery will be down for the entire quarter. Planned turnaround expense is projected to be approximately $120 million in the third quarter. Operating cost per barrel in the third quarter are expected to be $5.10, as we expect to see benefits from higher throughput and lower costs, given we have completed the significant portion of our turnaround and project activity. Distribution costs are expected to be approximately $1.4 billion for the third quarter. Corporate costs are expected to be $175 million, representing the sustained reductions that we have made in this area. To recap, our second quarter results reflect our team’s execution against our strategic pillars across the company. Our capital allocation framework remains consistent. We will invest in sustaining our asset base while paying a secure competitive dividend with the potential for growth. We want to grow the company’s earnings and we will exercise strict capital discipline. Beyond these 3 priorities, we are committed to returning excess capital through share repurchases and to meaningfully lower our share count. With that, let me pass it back to Mike.

Kristina Kazarian:

Thanks Mike. [Operator Instructions] And now, we will open the call. Sheila?

Doug Leggate:

Thanks. Good morning, everyone. Thanks for having me on. Mike, I want to pick up on one of the headlines from your press release, which seems to becoming a bit of a recurring theme, sustained commercial improvements. And I guess it’s a capture rate question, but can you just walk us through what’s going on in your capture? Because it looks like we are – as I look back pre-COVID, for example, leaving the distortions of COVID out of it for a minute, your capture rate seems to have stepped up. Is that portfolio management? Is it something else? Is it trading? What’s going on to have addressed that issue on capture rate?

Rick Hessling:

Yes, Doug, first off, very perceptive question. I think it’s a good call out and warranted. We do believe the structural change is something that’s going to stick. In fact, we continue to improve and we are never going to be done improving in this category. So it’s something that we focus on daily. So in giving you an answer, I think you will respect that I will have to be broad as to not give away what I would call true competitive advantages. But it’s all the buckets you’ve touched on, it’s optimization, it’s trading, it’s all of the above. And the best way I can say it, Doug, it’s a holistic change in our mindset on everything we do to optimize our assets around our size, our logistics system, our knowledge, our expertise, and it’s driving incremental value throughout our entire system from feedstocks to products. And there isn’t anyone in the company that’s not engaged. I mean I can’t say enough. Our goal is to be the best cash flow generator through cycle and this just isn’t a one-and-done exercise. This is the mindset that not only our commercial team, but our entire company is attacking everyday with.

Maryann Mannen:

Hey, Doug. Good morning. Maryann. Thanks for the question. From a capital allocation framework perspective and hopefully, even from the comments that Mike and I have both made here this morning, we remain committed to superior returns and remain committed to our capital allocation as we have defined it. As it relates to the back – as you know, each quarter now, we are trying to look as best as we can. We take a series of things into consideration. We look at market. We look at our cash flows and we try to do the best job we possibly can to maximize our ability to perform in a given quarter, as you have seen $3.1 billion in the quarter. When you look from month to month, you see that visibility as you get our quarterly documents, you see a bit of variability there. But again, we remain committed. We think share repurchase is a very efficient return of capital. As it relates to the dividend, again, an important part of our capital allocation framework, as we have shared in the past, we remain committed to that. We want it to be sustainable. We certainly want to be competitive and the opportunity to grow that as well. I hope that answers your question.

Maryann Mannen:

Again, Doug, we try to be as opportunistic as possible as we can in the quarter. So we hope that that’s the – what you are seeing from our approach to that. So yes, we continue to buyback stock as you have seen.

Mike Hennigan:

Let me just add a couple of comments to it. As I just said to your first question, the number one concentration is to generate cash. And then I am a believer that this business has both return on and return of capital as its requirements. So on the return on, we are investing capital to improve our earnings and grow our cash flows over time, but we are also committed to return of. So we used the word strict capital discipline. We set our programs such that we are going to be able to participate in both sides of that, because I am a big believer in both. We got to show the market that we can invest capital wisely to grow our earnings, and we also want to show the market that we’re returning capital to the owners. So that’s a program that we’ve been on for a while here a couple of years. We’re going to continue in that mode. And I just want to give you a little bit more flavor as to how we look at it, but it all starts with generating cash and then optimizing return on and return of.

Mike Hennigan:

You are welcome.

Neil Mehta:

Yes. Good morning, team. I want to get your perspective on the product market. So we’ve really seen a firm up here across the crack. And so any perspective you have on the strengthening – recent strengthening of margins? And then what are you seeing from a demand perspective in your own system for diesel, jet and gas?

Neil Mehta:

Thanks, it’s been notable. The follow-up is just around the dividend. It’s down to about 2% given how strong stock has been perspective and just your perspective on, is there headroom to raise the fixed dividend and remind us again when you typically would do that.

Neil Mehta:

Thans, Maryann.

Manav Gupta:

Good morning, guys. My question is like this year, you are bringing to conclusion two of your big mega projects, the Galveston as well as the Martinez RD. At this point, you haven’t indicated another mega project. So should we assume in the year 2024, more of your CapEx would be dedicated to quick hit projects, which generally are not that expensive. And that can mean that year-over-year, 2024 CapEx could be down versus 2023, unless you pick up a mega project at this stage?

Mike Hennigan:

Manav, this is Mike. I just want to add. It’s just a little early in the year. We obviously have some insight as to what we’re planning to do in ‘24, but we will talk about that in subsequent quarters as opposed to now.

Brian Partee:

Yes, Manav, this is Brian. Certainly, you got it pretty dead on there in terms of the strategy and the strategic relationship we have with Neste. Just a couple of things to mention around your question, though, that we are on start-up diet here. So as mentioned, we’ve got our pretreatment facility coming online and really full horsepower of this facility really enters in the back half of this year, but we’re quite confident in our ability with our relationship with Neste that really is looking beyond just Martinez. This is just the beginning of our relationship. But one point of view that I will share with you, not Martina specific, but to give just a little bit of perspective, we just exited July with our operation up in Dickinson, and we ran a 74% advantaged feed slate out of our facility up in Dickinson. And its start-up design was very similar to Martinez. So hopefully, that frames things up for you a little bit better of what to expect when we get Martinez up to full rate later this year.

Manav Gupta:

Thank you so much.

Operator:

Next, you will hear from Paul Cheng with Scotiabank. Your line is open.

Mike Hennigan:

Paul, it’s Mike. I’ll start on the first one, I’ll let Rick take the second one. Similar to Manuv’s question is – we’ll give a little more color on 2024 capital in the next couple of quarters. We do have some projects that we think will continue to optimize our portfolio and improve upon it. But like I said a few minutes ago, it’s a little early to talk about that capital at this point. So if you can just hold your thought, we’ll give a little bit more on the next quarter and start to give you a little bit more insight as to what we’re thinking in ‘24.

Paul Cheng:

Where can I clarify on that because the reformer was done since in mid-May – and so this is only going to be I think maybe half of our quarter of the down timing. So that what dropped you 30,000, 40,000 barrels per day in total throughput. So – and it still is a really be surprised that the book level is not higher on the guidance for third quarter.

Paul Cheng:

Okay, thank you.

Sam Margolin:

Hi, everyone. Thanks for calling my name. This is a macro question, and I want to harken back to a call, a Marathon call from earlier this year. I think it was Brian made the prediction that the Russian sanctions first diesel cracks will go down and then they would go up again. And that’s sort of exactly what happened and it has to do with the destock pattern and then later on, specification issues. And so I just want to bring that comment back to the service here and see if it is part of the reason for the strength we’re seeing in diesel cracks now and if you see in your export markets, for example, if you see a shortage of on-spec products that’s driving some of the strength there?

Sam Margolin:

Okay, thanks. And then this is an operational follow-up, but we’ve seen heavy intermediate differentials compress and it seems to correspond to a bunch of different factors, maybe starting up as one of them, but – there’s a couple of other similar new conversion units and new refining capacity starting up concurrently. And then you have the OPEC cuts. And so just on this heavy light set up and specifically on high-sulfur fuel oil, this is the tightness here just a function of all of these things happening at once. And then over time, the market will adjust and we might see just if I go back towards where it was? Or is this kind of the normalization with all the new capacity? Thanks.

Sam Margolin:

Thanks so much.

Sam Margolin:

Got it. Thank you so much.

Operator:

Next, we will hear from Jason Gabelman with TD Cowen. You may proceed.

Mike Hennigan:

Yes, Jason, it’s Mike. I’ll start, and then I’ll let Rick jump in. What I was saying in the prepared remarks is we as a company have gone through four quarters of pretty heavy turnaround. And so we’re later into the rest of the year, compared to what we see as the industry, and we’ll have to see how it plays out, but it looks like the industry has a lot more activity into the rest of the year. So that’s what I was trying to say as far as the difference between where we are and where we think the rest of the industry is.

Jason Gabelman:

Okay. Great. And my follow-up is on the Martinez biofuels projects. I just wanted to confirm because it’s tough to tell. It sounds like everything is going according to plan, but we’ve heard from industry sources that there are some court challenges that you’re having to address. Is that fair in terms of what’s going on? And is there any risk that any of these court challenges could impact the ramp up of the project to the full 730 million gallons?

Jason Gabelman:

To clarify, you need – can you ramp up while that court is ongoing, while our case is ongoing or would you need that to be resolved before you ramp up capacity?

Jason Gabelman:

Great. Thanks a lot.

Roger Read:

Thank you and good morning. I’d like to follow up as well on Martinez. Maybe just if you can help us out with understanding some of the milestones we should watch. We know that the industry has been challenging times to get these facilities to start up cleanly. You have obviously put out a goal of full run rate by the end of the year. So, as we think about this point in late October, looking back at the third quarter, where would you expect to see that unit? And when would you anticipate that it becomes a positive contributor in terms of EBITDA, cash flow, earnings?

Mike Hennigan:

And Roger, it’s Mike. To your question, financially, you got to be thinking into ‘24. As Tim said, we are ramping, we are starting up. We are going to bring on the additional units and if all goes well, we will be on by the end of the year. So, you will start to see the financial performance more in ‘24 on a go-forward basis.

Maryann Mannen:

Thanks for the question, Roger. As you said, as it relates to Dickinson first, we have been operating for about 2 years and consistent with the way we have expected profitability there. Although some of the moving parts are different, we continue to see the performance of that consistent with what we thought. Mike just shared with you when we should expect to see real contribution from Martinez. So, we will evaluate both Dickinson and Martinez in terms of their total contribution. As you know, we have said for 2023, we are not planning to break that out. But we will come back to you as we continue to move along our path of profitability for both Dickinson and Martinez.

Roger Read:

Well, I will just leave you with my final thoughts on it, which is we haven’t really put a lot in valuation uplift because it’s difficult to know exactly what some of the contributions will be and where. So, I think more disclosure will be a positive for you.

Maryann Mannen:

Thank you.

John Royall:

Hi. Good morning. Thanks for taking my question. So, my first question is just coming back to the Galveston Bay reformer. Is there an update on when we could see that coming back? I know you are assuming out for the full quarter with 3Q guidance, but maybe just a little bit of color on where you are in that restart process beyond just that assumption in your guidance.

John Royall:

Okay. Fair enough. And my next question is on tax. You had a very low rate in 2Q. You called out a $50 million-ish of that looks non-recurring. But even when I adjust for that, it’s still trending down the past couple of quarters. Is that just on the mix of non-taxable MPLX versus refining, with refining coming down past couple of quarters? Are there any other moving pieces to think about in the tax rate?

John Royall:

So, if I adjusted out the $53 million in this quarter, that’s a decent run rate to think about going forward?

John Royall:

Thank you.

Theresa Chen:

Hi. Thank you for taking my question. I just had a quick follow-up related to the discussion of the Martinez ramp up and your renewable diesel outlook in general. Related to the economics of LCFS, it seems that the final draft of the proposed changes will be submitted to CARB over the next couple of months. And I would love to hear your thoughts and expectations on where you see that landing and your general outlook for pricing from here?

Theresa Chen:

Thank you.

Matthew Blair:

Hey. Good morning. Thanks for taking my questions here. Chicago diesel cracks were quite weak earlier in July, even related to other PADD 2 markets like Group III. Do you have any color on what was going on here? It looks like they recovered so far, but any color as to why Chicago Diesel at one point was negative on an RBO adjusted basis?

Matthew Blair:

It sounds good. And then on the CARB data posted last night, it showed that in the first quarter of this year, California diesel consumption was 49% RD and up to 8% be the – for your Los Angeles refinery, are you having any problems placing your petroleum diesel volumes in that California market? And are you having to export new volumes to Singapore or Mexico? Do you consider that a risk down the road?

Matthew Blair:

Great. Thank you.

Operator:

Thank you. We do have time for just one more question. Our last question comes from Ryan Todd with Piper Sandler. Your line is open.

Maryann Mannen:

Yes. Thanks for the question, Ryan. It’s Maryann. Let me try to give you a little bit of color. When you look at Q1 to Q2 performance, keep in mind in the U.S. Gulf Coast, as you stated, we were under turnaround in the first quarter and obviously ramping up. So, you saw the benefits of that, obviously, in the second quarter despite the fact that we did have the reformer down for just a portion of the month. As I was commenting on, it’s only about a 1% impact for the second quarter that will get a little bit larger, as I shared, given the fact that we are assuming it to be down. I think the other thing to keep in mind is typically when we look at cost in the quarter, when we are doing heavy turnarounds, as we did in the first quarter, we are typically doing other maintenance work and that was much lighter in the second quarter as well. As it relates to STAR, as you know, we were ramping up our comments as we have been sharing STAR was ramping up through the second quarter. So, minimal impact with respect to STAR, but you will begin to see that now as we have reached the completion of that project.

Mike Hennigan:

Yes, Ryan, it’s Mike. I like the word energy evolution more than energy transition. I know a lot of people use energy transition, but I think it’s going to evolve over a longer period of time than most have written about. So we’re trying to be very thoughtful. We will using the word evolve. We will evolve the company over time. As you pointed out, 2 of our facilities now are renewable diesel. We made a small investment in an RNG facility. So Dave and his team are looking at all those opportunities. We talked on the call today about we’re active in some of the DOE hydrogen hubs, and we’ll see how that plays out over time. So think of us as going to be very thoughtful. We try to use the word strict capital discipline. We do want to invest as opportunities present themselves, but we are committed to getting solid returns. So overall, I’d say you’re just going to see us chip away at little activities over time and constantly evolve it to your point about, what are we going to look like in 10 years? And 10 years, 20 years or whatever Marathon has been around for 130 years. We plan to be around for 130 more. So we’ll evolve the company as the market dictates. And obviously, consumer preferences, regulatory impacts, all those things are going to drive what happens and we’ll be very attentive to it and we’ll look to deploy capital as we see the opportunities.

Operator:

Thank you. That does conclude today’s conference. Thank you once again for your participation. You may disconnect at this time.

Kristina Kazarian:

Welcome to Marathon Petroleum Corporation's First Quarter 2023 Earnings Conference Call. The slides that accompany this call can be found on our website at marathonpetroleum.com under the Investor tab. Joining me on the call today are Mike Hennigan, CEO; Maryann Mannen, CFO; and other members of the executive team. . We invite you to read the safe harbor statements on Slide 2. We will be making forward-looking statements today. Actual results may differ. Factors that could cause actual results to differ are included there as well as in our filings with the SEC. And with that, I'll turn it over to Mike.

Maryann Mannen :

Thanks, Mike. Moving to first quarter results. Slide 5 provides a summary of our financial results. This morning, we reported earnings per share of $6.09. Adjusted EBITDA was $5.2 billion for the quarter, and cash flow from operations, excluding unfavorable working capital changes, was nearly $4.2 billion. During the quarter, we returned $337 million to shareholders through dividend payments and repurchased nearly $3.2 billion of our shares. Slide 6 shows the reconciliation between net income and adjusted EBITDA as well as the sequential change in adjusted EBITDA from fourth quarter 2022 to first quarter 2023. Adjusted EBITDA was lower sequentially by approximately $600 million. This decrease was driven by Refining & Marketing as refining margins per barrel were down quarter-over-quarter. As we indicated last quarter, throughputs were lower primarily due to the significant planned turnaround activity. Corporate expenses were roughly in line with our guidance. And despite general inflationary pressures, we have maintained cost discipline since taking $100 million out of corporate costs since 2020. The tax rate for the first quarter was 21%, resulting in a tax provision of approximately $800 million. Moving to our segment results. Slide 7 provides an overview of our Refining & Marketing segment. Like many in the industry, several of our refineries were impacted by winter storm Elliot at the end of December. These impacts carried into the first quarter, reducing our crude throughput by 3 million barrels. Winter Storm Elliott and higher planned maintenance in the Gulf Coast region reduced overall refining utilization, which was down 5% to 89%. Sequentially, per barrel margins were lower in all regions compared with the fourth quarter. Capture was 98%, reflecting a strong result from our commercial team, particularly given the extensive turnaround activity this quarter. Refining operating costs per barrel were roughly flat sequentially in the first quarter at $5.68. Lower throughput compared to the fourth quarter impacted operating cost per barrel. This was partially offset by lower energy costs, primarily in the Gulf Coast and Mid-Con regions, although we experienced higher natural gas prices in the West Coast. We expect operating cost per barrel to be lower in the second quarter as reflected in our guidance. Slide 8 provides an overview of our Refining & Marketing margin capture this quarter, which was 98%. Our commercial teams executed effectively in a volatile market environment. Light product margin tailwinds were balanced against impacts associated with inventory builds and planned maintenance activity. Capture results will fluctuate based on market dynamics. Still, we believe through our commercial efforts, our capture baseline has moved closer to 100%. As our strategic pillar indicates, we have been committed to improving our commercial performance and believe that the capabilities we have built over the last 18 months will provide a sustainable advantage, we have meaningfully changed the way we go to market from a commercial perspective throughout our entire company. We believe these capabilities will provide incremental value beyond what we have realized to date. Slide 9 shows the change in our Midstream adjusted EBITDA versus the fourth quarter of 2022. Our Midstream segment delivered resilient first quarter results. Adjusted EBITDA was 9% higher year-over-year, reflecting business growth. Our Midstream business continues to grow and generate strong cash flows. We are advancing our capital plan with projects anchored in the Marcellus, Permian and Bakken basins. These disciplined investments in high-return projects, along with our focus on cost flow optimization, are expected to grow our cash flows. This will allow us to reinvest in the business and return capital to unitholders. This quarter, MPLX distributions contributed $502 million in cash flow to MPC. MPLX remains a source of durable earnings in the MPC portfolio and is a differentiator for us compared to peers without Midstream businesses. Slide 10 presents the elements of change in our consolidated cash position for the first quarter. Operating cash flow, excluding changes in working capital, was nearly $4.2 billion in the quarter. Working capital was a $98 million headwind for the quarter, driven primarily by increases in crude and product inventory, offsetting benefits from a decrease in refined product receivables related to lower product sales. Capital expenditures and investments totaling $664 million this quarter. We saw consistent spending in refining in the first quarter as were progressed on the Martinez renewable fuel facility conversion and the completion of the Galveston Bay STAR project. MPC returned over $3.5 billion via share repurchases and dividends during the quarter. This represents an 85% payout of the nearly $4.2 billion of operating cash flow, excluding changes in working capital, highlighting our commitment to superior shareholder returns. We now have $9 billion remaining under our current share repurchase authorization which includes the additional $5 billion approval announced today. At the end of the first quarter, NPC had approximately $11.5 billion in cash and short-term investments. Turning to guidance. On Slide 11, we provide our second quarter outlook. We expect crude throughput volumes of roughly 2.6 million barrels per day, representing utilization of 91%. Utilization is forecast to be higher than the first quarter levels due to planned turnaround activity having a lower impact on crude units in the second quarter. Planned turnaround expense is projected to be approximately $400 million in the quarter, with activity primarily in the Mid-Con and West Coast regions. We expect turnaround activity to be front-half weighted in 2023. By the end of the second quarter, we expect to spend roughly $760 million on turnaround in 2023 and anticipate the full year turnaround spend to be comparable to the level of spend in 2022. Operating cost per barrel in the second quarter are expected to be lower at $5.20 as we expect to see benefits from higher throughput and lower energy costs. As we look further into 2023, we anticipate our operating cost per barrel would decline and trend towards a more normalized level of $5 per barrel as we complete turnaround and project activity. Distribution costs are expected to be approximately $1.35 billion for the second quarter. Corporate costs are expected to be $175 million, representing the sustained reductions that we have made in this area. To recap, our first quarter results reflect our team's strong operational and commercial execution across the company. Our capital allocation framework remains consistent. We will invest in sustaining our asset base while paying a secure competitive dividend with the potential for growth. We want to grow the company's earnings and we will exercise strict capital discipline beyond these three priorities we are committed to returning excess capital through share repurchases to meaningfully lower our share count. With that, let me pass it back to Mike.

Kristina Kazarian :

Thanks, Mike. As we open the call for your question, as a courtesy to all participants, we ask that you limit yourself to one question and a follow-up. If time permits, we will re-prompt for additional questions. Sheila, we are ready for them.

Neil Mehta :

Congrats on a great first quarter. I had a couple of questions here. The first is around the West Coast. We're all watching Singapore margins right now and they continue to trade very weak. And just your perspective of, do you think the weakness in Asia is a reflection of demand? And do you see risk that, that product comes to the West Coast at which point there could be some downward pressure on PADD 5 margins?

Brian Partee :

Yes. Thanks, Rick, and Neil. Just a quick data point. Very good question. We are seeing some fundamental shifts in global trade flows as a result of economic activities and product sanctions, et cetera. Rick did mention the marginal barrel coming into the West Coast has traditionally been for many years, an import coming from the Far East. So just on order of magnitude, we're looking at 250,000 barrels a day to balance the system, primarily gas and jet fuel, and we expect that balance to continue to trend in terms of favoring more imports as we go forward as more facilities are converted to RD on the West Coast. Other data point, I think that's relevant in terms of penetrating the West Coast market and from the Far East, is also the tanker rates and availability of the foreign fleet. Current rates out of South Korea into the West Coast are about $8 a barrel. That's about 2x of what historically we've seen in the market. And the other two components that make it a little bit tricky to push incremental barrels into the West Coast or, of course, in California, you meet the spec. And then just logistics constraints in terms of docs and tankage, which are also being further constrained by some of the RD penetration that we're seeing in the West Coast market.

Maryann Mannen :

Neil, thanks for the question. It's Maryann. So look, first of all, as you know, we've got a little over $11.5 billion of cash sitting on the MPC balance sheet. And you've heard from the team, and Mike this morning, our views on the balance of the year. We do take into consideration each time we make our decisions what the share repurchase will look like, and we do that quarterly. We look at the macro conditions. We look at our cash positions. Obviously, having a strong balance sheet is foundational for us to be able to execute our capital allocation program as we just shared with you. But we do take a look at it quarterly. It is not something that we set for a long period of time. We have the ability to evaluate all of those things, as you just outlined for us.

Kalei Akamine:

This is actually Kalei on for Doug. My first question is just on the macro and how you're positioned here for the second quarter. So your peers are seeing really solid demand numbers and your opening commentary was quite constructive. Yes, the throughput guidance put out for the second quarter looks a bit conservative. So at a high level, can you share any insights on demand from your own system and maybe elaborate a bit more on your outlook near term?

Kalei Akamine:

So I guess, on balance, it sounds quite positive. My second question is for Maryann. The buyback is obviously something that separates you from your peers, and we appreciate the visibility provided by the $5 billion expansion today. But I want to ask about the ordinary dividend. In our view, refining is not contributing to that dividend today as it's more than covered by the distributions from MPLX. So as you close out spending on the STAR project and consider what we think is a reset in the mid-cycle, it looks like the dividend has a lot of capacity to increase here. So how are you thinking about that piece of your value proposition?

Michael Hennigan :

I just want to add to that. Thanks for noticing that. One of the things that we think is unique in our value proposition is the $2 billion-plus that we're getting from MPLX. And if you listen to the call earlier, MPLX had a very strong quarter. We continue to grow the cash flows at MPLX. We'll have a similar distribution increased discussion later in the year. But I think it's pretty important to understand that $2 billion-plus coming in, as you mentioned and I mentioned in prepared remarks, covers the dividend and a good portion of the capital. So I think it's a pretty important point as to the way we think about all the cash flows within the portfolio. So thanks for pointing that out, and it does come into our thinking as we advance both dividend and repurchase activity.

Manav Gupta :

See, I quickly just wanted to focus a little bit on Galveston-based STAR project. I think it's not as well understood. And if you could help us understand how to model it little more accurately? I mean, 40,000 barrel day increase we can model more accurately. But how does the 17,000-barrel resid processing capacity, what are the spreads we should watch for that so we can give you full credit for this project because I honestly don't think you're getting too much credit for this project in your numbers?

Tim Aydt:

Yes, Manav, this is Tim. Thanks for the question. I would say that you have to keep in mind is, first off, I think, that we completed this project in phases. So really a good amount of the STAR scope has already been completed and has been put in service previously. So it's already earning a return. I think the remaining STAR project is really around this resid portion of the room. So that is indeed finished up during the mechanical completion during the first quarter turnaround and then we've been in start-up during April. So that's all looking good from that standpoint. I think the other thing that I would say is that we ended up expanding the -- hydrocracker instead of the GBR cokers -- and that's really because of the better conversion and the liquid volume expansion that you get with the addition of the hydrogen. So that can maybe be explained a little bit if you -- if you look at a comparison between a coker and the RHU unit, if you put 100 barrels of liquid into the coker, you get about 80 barrels of liquid out and the rest is coke. That's lower value. If you put that same 100 in the RHU unit, you get 107 barrels of liquids out. So obviously, that 27 barrels is about 34% increase in liquids, which are higher valued. So that's why we made that decision. I would also point out that GBR is unique and this got the only operating resid hydrocracker unit in the U.S. So that's what made that beneficial. And we had a pretty capital-efficient project there to make the modifications to the RHU as opposed to starting with another greenfield coker. So hopefully, that's helpful.

Tim Aydt:

Okay. Manav, I'll start with maybe just giving an update on the schedule. So you are correct. The Martinez has reached the full Phase I production of 260 million gallons per year back in -- earlier in the first quarter. Facility did ramp up to the design rates as planned and as scheduled. We're happy to report that the remaining construction activities at Martinez are on schedule. Regarding the pretreatment unit, that's scheduled to come online in the second half of 2023. And then by the end of the year, we're looking to have the full rate of production of renewable diesel at 730 million gallons per year by the end of December. And now I'll turn it to Maryann relative to the second part of your question.

Operator:

Our next question comes from Paul Cheng with Scotiabank.

Michael Hennigan :

Yes, Paul, I think you hit it on the head. It just gives us more ability to run heavy crudes. So that's at the front end and the incremental coming out the back end is distillate. The project itself coming out of the resid hydrotreater, it's unfinished distillate, but that's why I was trying to answer Manav's question on how to model it. The easiest way to think about it is heavy crude to unfinished distillate. That's the crack spread of the incremental change.

Michael Hennigan :

No, no, it's the 40,000 Manav -- I'm sorry, Paul. I'm saying just like I answered to Manav is, it's 40,000 barrels a day of crude that comes into the plant, heavy crude, what comes out of the plant is untreated distillate.

Michael Hennigan :

We haven't given that specific -- that particular unit itself specifics.

Maryann Mannen :

Sure, Paul. So in the quarter, as I was trying to share capture in the quarter was 98%. There were a couple of key factors that actually impacted our performance. One of those, as I mentioned, was planned turnarounds. Obviously, that impacted throughput, Galveston Bay. And as you know, we took Galveston Bay -- we took that opportunity to complete STAR as well. And there was also turnaround in the Mid-Con as well. The second driver was inventory impacts. And you may remember from the fourth quarter, we actually had a tailwind. We built some inventory in the quarter. We wouldn't expect necessarily that inventory to impact the second quarter as well, but those things are volatile. And then one of the key benefits in the quarter was actually light product margins. In the second quarter, we gave guidance. But remember, we are very much front-half-weighted from a turnaround perspective. Actually, our guidance for Q2, roughly $400 million is above the first quarter actual turnaround expense. This will be for us four quarters of heavy turnaround somewhat unprecedented. We made what we think were some good decisions in early 2022 to delay turnaround to be sure that we did not have lost opportunity with respect to the heavy driving season and the increased demand. And similarly, when we think about the second quarter, we would expect that the months of May and June would see benefit as we look at the turnaround expense there. So I will pause there and see if maybe Rick and/or Brian want to add any incremental color with respect to the performance in the quarter.

Maryann Mannen :

No, Paul, sorry about that. It is actually a negative impact in the first quarter. We actually built inventory in the quarter.

Maryann Mannen :

Paul, we normally don't give that level of detail. It was not, however, the -- of those three elements, it was not the single largest driver.

Maryann Mannen :

Yes. We had inventory builds across all regions, Paul.

Sam Margolin :

This one is on diesel. It connects to some of your comments earlier about the heating impact and maybe some timing-related factors in the market. But there was an expectation that as jet fuel recovered that it would benefit the diesel market because there was some overblending of jet components into diesel and we ran into sort of tough demand comps around both price and weather. And so maybe that benefit didn't necessarily filter through, but I was wondering, since you're so you guys are pretty indexed heavily to the jet market probably see things that other operators don't. If you think that, that benefit is maybe coming just a little bit on a lag, particularly given some of your comments around demand on the jet side, which seems to be performing as expected

Sam Margolin :

Okay. Yes, that makes sense. We saw the same thing in crude, I guess. Sorry, go ahead.

Sam Margolin :

Okay. And as a follow-up, this is sort of a redo on Neil's question about the balance sheet structure and capital allocation, but I'll put it in a different way. I think a lot of people are aware now that the MPLX distribution more than covers the MPC dividend, but what's interesting now is that your interest income on your cash balance covers like half of the MPC dividend or almost. And it's -- there's a matter of uncertainty in the economic environment, but then there's also sort of what's going on with rates and the optimal capital structure around that. So I'm just wondering if -- maybe there's a change to kind of the mid-cycle cash balance that I think was $1.5 billion that you were targeting?

Maryann Mannen :

I think Mike has covered it well. We talked about ultimately carrying $1 billion. We've had some real life during COVID stress testing of that. We remain committed to our $1 billion. Your comment around interest, I think, is a real fair one. When you look at the -- our total interest and other financial costs. You can see over the last several quarters, the impact of the benefit of interest income on those cash balances as well, Sam. So I hope we've covered your question well.

Jason Gabelman :

I wanted to first ask -- I want to first ask on the light heavy spreads. They've come in quite a bit. It looks like Brent is now below $12. Can you just talk about what you're seeing in the market? Why that tightening is occurring? And if we were setting back to maybe something that's a more typical light-heavy spread versus where we've been the past 6 months or so?

Jason Gabelman :

Great. I appreciate that outlook. My second question, I wanted to follow up on prepared -- on the prepared remarks you made around the low carbon business. And it seems like you may have aspirations to grow this business well beyond the Martinez renewable diesel plant. You talked about partnerships with a few counterparties, you purchase -- or you bought into the small RNG business. Can you just -- and then I guess the other thing is you have exposure to natural gas sourcing via MPLX. So I was just hoping if you could discuss maybe broadly, how you see this business evolving over the next few years? How big it could get? What the areas of growth you're focused on, particularly in light of the Inflation Reduction Act?

Kristina Kazarian:

Sheila, I think we are ready for the next question.

Roger Read :

Coming back to commentary on the gasoline markets. Just kind of maybe dig in a little deeper where you see the bigger issues, be it gasoline supply itself, whether it's components and then as we think across the 5 PADDs, the stress is not evenly distributed, right? I mean PADD 3 doesn't look all that bad on its own, the PADDS 1, 2 and 5 also kind of different issues. So between the regional things you're looking at, the underlying demand trends and then anywhere else, there's octane components or something else? Can you walk us through where you think the biggest challenges will be for supply?

Michael Hennigan :

And Roger, it's Mike. Brian gave a lot of specifics. I'll just give you my simplistic view is gasoline inventories, like you said, are spread around in the different regions, but there's still 10 million barrels below last year, 17 million barrels below the 5-year average. The demand numbers are strong relative to last year, if you look over a longer period of time. So at least in our view, we think it's a very constructive time for gasoline at this time of the year as we're heading into which is more of the higher demand time as we head into the summer. So we're more constructive, I'll say, than maybe some people out there. And as I mentioned earlier, I know there's some concern around distillate, but we think Jet is going to continue to recover as well. And for the first time in whatever it is, 18 months, gasoline is now over distillate. That's a change in the environment going into this summer that wasn't there last summer. So we still think it's a very constructive environment for us, and we'll see how it plays out.

John Royall :

So I just had a follow-up on capture rates. Just any thoughts on the moving pieces directionally in 2Q from the 98% in 1Q? It's another heavy maintenance quarter, but you have the non-recurrence presumably of inventory impact. So should we center around maybe the 100% level as a starting point, maybe a little lower due to maintenance or any other moving pieces we should think about?

Rick Hessling :

John, it's Rick. So I'll just double-click on really the last item Maryann touched on. I can't emphasize enough under Mike's leadership, we've unpacked and changed everything we do commercially from A to Z, from feedstocks through finished products, there isn't anything that hasn't been looked at under the covers and redesigned where it needs to be redesigned. So as we look forward, a lot of people say, are you done? And Brian and I will say, will never be done. And Mike would tell us that on a daily basis rightfully. So with that being said, we do expect to continue to get incremental value by region going forward in every region we operate in. We're continuing on this journey and it's a journey that won't end. And it's quite the change for us corporately as we improve collaboratively from refining all the way through commercial. So if you can't tell, we're quite excited about it. And without giving too much detail, we would encourage you to stay tuned and continue to look at our results. Our boss tells us our results speak for themselves, and that's the mantra we live by and feel good about in this metric as you've seen over the last year or so.

Operator:

And we do have time for just one more question. Our last question will come from Theresa Chen with Barclays.

Brian Partee :

Yes, Theresa, sure. So on the distillate side, yes, we do see ag picking up. Of course, that's a year-on-year comp. So it's hard to get a complete read, but we expect it to be a strong season. We do see, again, as I mentioned earlier, some softness on the transportation side of the business, largely driven through consumption and the curtailment of consumption. So whether it be activity at the ports over the road, fairly consistently with our big customers, we've heard that theme. The positive standout though, I would mention is in the mining business, and we do have a pretty big exposure on the mining side of the industry. And we do see robust activity on the mining side of our business throughout really all regions. But it's really that consumer consumption component that we're watching very closely. As we transition here seasonally, I think it's early. As I stated earlier, to call favorably or unfavorably, which direction things are going to break, but it is something that we're keeping a close eye on.

Operator:

Thank you. That does conclude today's conference. Thank you for participating. You may disconnect at this time.

Kristina Kazarian:

Welcome to Marathon Petroleum Corporation's fourth quarter 2022 earnings conference call. The slides that accompany this call can be found on our website at marathonpetroleum.com under the Investor tab. Joining me on the call today are Mike Hennigan, CEO; Maryann Mannen, CFO; and other members of the executive team. We invite you to read the safe harbor statements on Slide 2. We will be making forward-looking statements today. Actual results may differ, and factors that could cause actual results to differ are included there as well as in our filings with the SEC. References to MPC’s capital spending during the prepared remarks today reflects standalone MPC Capital excluding MPLX. And with that, I'll turn it over to Mike.

Maryann Mannen:

Thanks, Mike. Moving the fourth quarter results. Slide 6 provides the summary of our financial results, this morning, we reported adjusted earnings per share of $6.65. This excludes a $176 million LIFO inventory benefit, as well as $60 million gain related to the Speedway transactions. Adjusted EBITDA was $5.8 billion for the quarter, and cash flow from operations, excluding unfavorable working capital changes, was $4.4 billion. During the quarter, we returned $351 million to shareholders through dividend payments, and repurchased over $1.8 billion of our shares. Slide 7 shows the reconciliation between net income and adjusted EBITDA as well as the sequential change in adjusted EBITDA from the third quarter of 2022 to the fourth quarter of 2022. Adjusted EBITDA was lower sequentially by approximately $1 billion. This decrease was primarily driven by refining and marketing, as the blended crack spread was down over $5 per barrel, reflecting a 20% quarterly decline. Corporate expenses were higher in the fourth quarter driven by a retroactive operating tax assessments for prior periods. We intend to pursue recovery of these multiyear tax assessments. In addition, corporate includes special compensation expenses, which also affected our refining and marketing and midstream segments. We do not anticipate that these costs will structurally impact future corporate cost. The tax rate for the fourth quarter was 22%, resulting in a tax provision of nearly $1 billion and the full year tax rate was 22%. Moving to our segment results, slide 8 provides an overview of our Refining and Marketing segments. Like many in the industry, several of our refineries were impacted by winter storm Elliott at the end of December, primarily in our Gulf Coast in Mid-Con regions. Most of our assets were back online after a short period, and we have not seen structural issues. The crude throughput impact was approximately 4 million barrels, which reduced our crude capacity utilization for the fourth quarter by roughly 2%. Looking to January, we anticipate impacts to throughput of 3.5 million barrels which is reflected in our guidance for the first quarter of 2023. Even with a disruption at the end of the quarter, our refining assets ran at 94% utilization, processing 2.7 million barrels of crude per day at our 13 refineries. Sequentially we saw per barrel margins decline most notably in the West Coast region, while US Gulf Coast margins were relatively flat, supported by export demand. Capture was 109% reflecting a strong result from our commercial team. Operating expenses were lower in the fourth quarter primarily due to lower energy cost partially offset by a special compensation expense of approximately $0.15 per barrel, paid in recognition for our employees contributions. Due to lower throughputs in the quarter refining operating costs per barrel were roughly flat in the fourth quarter at $5.62 per barrel as compared to the third quarter. Our full year refining operating costs per barrel is $5.41 when we compare to 2021 refining operating costs per barrel of $5.02, this increase can be entirely attributed to higher energy costs. We believe the actions we have taken to reduce our structural operating costs are sustainable. Slide 9 provides an overview of our refining and marketing capture this quarter, which was 109%. Our commercial teams executed effectively in a volatile market, light product margin tailwinds improved secondary product prices and favorable inventory impacts all benefited capture. We do not expect all of these tailwinds to be repeatable. And in particular, we would expect the inventory impacts to reverse in the first quarter. As our strategic pillar indicates we have been committed to improving our commercial performance and we believe that the capabilities we have built over the last 18 months will provide a sustainable advantage. Historically, we communicated a captured target of 95%. But over the last few years, the baseline has moved through our commercial efforts closer to 100%. We believe we have built capabilities that will provide incremental value beyond what we have realized to date, and will produce results that can be seen in our financials. Slide 10 show the change in our Midstream EBITDA versus the third quarter of 2022. Our Midstream segment delivered resilient fourth quarter results. We did see lower EBITDA, primarily due to impacts associated with lower NGL prices. This quarter MPLX distributions contributed $502 million in cash flow to MPC. Slide 11 presents the elements of change in our consolidated cash position for the fourth quarter. Operating cash flow, excluding changes in working capital was $4.4 billion in the quarter. Working Capital was a $72 million headwind for the quarter, driven mostly by declining crude prices offset by benefits from inventory impacts. Capital expenditures and investments totaled $1.3 billion this quarter. We saw consistent spending in refining in the fourth quarter as work progress on the Martinez Renewables fuel facility conversion and the STAR project at Galveston Bay. While not reflected in the 2022 capital spend, due to the timing of the JV close, the 50% reimbursement from Neste for Martinez capital spend, was received and reflected in overall cash flows in the third quarter. MPC returned nearly $2.2 billion via share repurchase and dividends during the quarter. We began using the incremental $5 billion share repurchase authorization in November. For the full year, we returned $13.2 billion out of $17.7 billion of our 2022 cash from operations, excluding working capital impacts, representing a 75% payout. This was partially enabled by our commitment to complete our $15 billion capital return program. The outstanding purchase authorization of $7.6 billion, which includes the incremental $5 billion approval demonstrates our commitment to returning capital. At the end of the fourth quarter, MPC had approximately $11.8 billion in cash and short-term investments. Slide 12 provides their capital investment plan for 2023, which reflects our continuing focus on strict capital discipline. MPC’s investment plan, excluding MPLX, totals approximately $1.3 billion. The plan includes $1.25 billion for the refining and marketing segment, of which approximately $350 million or roughly 30% is related to maintenance and regulatory compliance. Our growth capital plan is approximately $900 million split between low carbon and traditional projects. Within low carbon $150 million is allocated for completion of the Martinez conversion. We are also executing a project at our Los Angeles refinery, which will improve energy efficiency and lower facility emissions. This is a multiyear project. In 2023, we expect associated capital spending to be $150 million. And we have allocated $50 million to smaller projects focused on emerging opportunities. Within traditional refining, $150 million is associated with the completion of the STAR project. $200 million is focused on smaller projects targeted at enhancing the yields of our refineries, improving energy efficiency, and lowering our cost. In marketing, we plan to spend $150 million for projects that focus on enhancing and expanding the platform for our Marathon and ARCO brands. This morning MPLX also announced their 2023 capital investment plan of $950 million. Their plan includes approximately $800 million of growth capital and $150 million of maintenance capital. The capital spending plan focuses on adding new gas processing plants and smaller investments targeted at expansion and debottlenecking. of existing assets to meet customer demand. Turning to guidance, slide 13, we provide our first quarter outlook. We expect crude throughput volumes of roughly 2.5 million barrels per day, representing 88% utilization. Utilization is forecasted to be lower than fourth quarter levels due to turn around impacts in our US Gulf Coast region, plan turnaround expense is projected to be approximately $350 million in the first quarter, with a significant level of activity in the Gulf Coast region. The remaining scope of the STAR project, specifically 40,000 barrels per day of crude and 17,000 barrels per day of resid processing capacity is expected to be tied in during the turnaround at Galveston Bay in the first quarter, and should begin to ramp starting in the second quarter of 2023. We expect the level of 2023 turnaround spending to be similar to the level of spend in 2022. However, unlike 2022, we expect turnaround activity to be front half weighted this year, with significant planned work in the first and second quarters. Therefore, we will have executed four consecutive quarters of heavy turnaround work. Operating costs per barrel in the first quarter are expected to be flat at $5.60 per barrel for the quarter. In conjunction with our turnarounds, we anticipate higher project related expenses as we utilize our planned downtime to complete other work plans. We are seeing the benefits from lower energy costs in the Gulf Coast and Mid-Con regions. But given the majority of our turnaround activity is heavily weighted to the Gulf Coast. Our expectations of flat operating costs quarter-to- quarter is driven by our West Coast exposure, where we have not seen a decline in energy costs recently. As we look into 2023, we anticipate our operating costs per barrel would decline and trend towards a more normalized level as we complete this turnaround and project activity. Distribution costs are expected to be approximately $1.3 billion for the quarter. Corporate costs are expected to be $175 million representing the sustained reductions that we have made in this area. With that, let me pass it back to Mike.

Kristina Kazarian:

Thanks Mike. [Operator Instructions] And with that, Sheila, we're ready for questions.

Neil Mehta:

Yes, good morning team and congrats on strong results here. The first question I had was around the magnitude of capital returns. How should we think about the percentage of cash flow or free cash flow you target to get back to shareholders in a given year through buybacks and dividends? And then you talk about a $1 billion being the target level of cash. We've heard some of your peers talk about that number being higher, why is a $1 billion the right number and how long does it take to get there? Given how strong the environment is?

Mike Hennigan:

Neil, it’s Mike. Let me just add to what Maryann just said. So we had been at about $1.6 billion from MPLS, moved up to $1.8 billion, we're now at $2 billion pace, we expect that to continue to grow. If people listen to the MPLX call, we're in a real good position there. But that distribution, let's say at the $2 billion pace, that essentially covers the dividend, and half of the refining capital commitment for refining. So that's part of the reason that we are comfortable with $1 billion on the balance sheet. Now, as you pointed out, we still finished the year with close to $12 billion on the balance sheet. So we still have a lot of financial capability to get to a new normal at some point, but hopefully that helps explain why the $1 billion is the right number. And it has to do with our affiliation with MPLX.

Mike Hennigan:

Yes, Neil, thanks for that question. It's one we've been getting from a lot of people. So it's relatively easy to model. So up until now, the parts of STAR that are in place are in our results. What's not in our results, is 40,000 barrels a day of crude capacity. And the easiest way to model is take that number times the differential between heavy crude, and ULSD. So if you look at that differential, and you multiply it by 40,000 barrels a day, that's the additional EBITDA that we'll get once STAR is online. But STAR is a pretty unique project for us. So I'm going to ask Tim to make a couple of comments on it. So you have the financial side of it, but let me give you a little bit of the background behind it with Tim some details, please.

Operator:

Our next question will come from Doug Leggate from Bank of America.

Maryann Mannen:

Hey, Doug, it’s Maryann. I'll pass it back to Mike here in a second. But as we talked about the dividend, we committed to looking at that dividend annually. We wanted to be sure that it was secure. We wanted to be competitive with the potential to grow. And we will continue to look at that. As we've shared in the past, and obviously, as you stated, we have increased the outstanding authorization to $7.6 billion of share repurchase, we continue to think that share repurchase over dividend is an appropriate return of capital. You'll see us continuing to use that authorization as we did here in the last quarter. So, yes, we'll evaluate that dividend but we continue to see share repurchase as a bit more preferential over the dividend. I'll pass it to Mike.

Doug Leggate:

Okay, I understand, I guess no one is going to complain about the yield, given that your share price is a big part of that. So but I appreciate the answer. My follow up is an operational question, Mike, I think it's pretty well known that you guys had a fair amount of maintenance in the quarter. But the capture rate was still quite strong, at least on our numbers. And I am looking at the product sales relative to the refinery throughput and wondering if that was part of what was going on there. So I'm wondering if you could help us understand the strength of the operating performance, and maybe give us a steer as to how you see your full year ‘23 downtime average because we're hearing from a lot of your peers that ‘23 is going to be a big year for the whole industry. And I'll leave it there. Thanks.

Maryann Mannen:

Sure. Thanks, Doug. As Mike indicated, our strategic pillars remained foundational, and our commercial performance is clearly one that we remain committed to, you may remember in the last set of guidance, we said that we thought our capture could actually be impacted, given what was a higher turnaround, frankly, they are highest one in 2022. But the commercial team did take quite a bit of initiative in the quarter. I'll give you some highlights and then pass it to Brian and Rick, but one of the things that we saw at 109% capture in this quarter, we had strong light product margins, we had favorable inventory impacts. And then also favorable pricing of secondaries. We we don't think necessarily all of these tailwinds would repeat, and certainly depending on where we sell pricing, some of them could actually be a headwind, particularly when we look at our secondary products. And historically, we've talked about a 95% capture rate over the last few years, given the work that the commercial team has been doing. We're moving more toward 100%. So we're going to continue to challenge ourselves to deliver that. And with that, I'll maybe ask Brian and Rick to give you some incremental color on the specifics there.

Doug Leggate:

Honestly, guys, I think that has been overlooked. Sorry, please go ahead.

Doug Leggate:

Guys, I think it is going to surprise a lot of people. I really appreciate the full answer. Thanks so much.

Roger Read:

Yes, good morning, everybody. Yes, another, certainly, I'll give you congrats on the capture there. Well done everything. Maybe to change pace though a little bit. I'd like to ask about the process in Martinez, and how we should think about the upcoming timeline and any particular milestones we should be watching for, and maybe how you think about it contributing at a cash flow basis, whether that's happens meaningfully in ‘23 or we should wait till ‘24.

Mike Hennigan:

Roger, it’s Mike. The only thing that I would add is we feel really good about the project. And the team's execution has been good. But in light of where the refining macro is today it's not the contributor that it would be saying it when we get back to midcycle at some point, it's going to be a meaningful contributor, but obviously, it's dwarfed by what's happening in refining today.

Brian Partee:

Roger, this is Brian. So I'll start in just a little bit of reflection on 2022. Because I think we've as an industry really domestically here in the US exited at a point of inflection as relates to COVID recovery. So globally, really strong year in 2022, when you look at a year-on-year 2.3 million barrels a day of overall oil demand increase, as Mike mentioned, in his prepared remarks, we expect to see continued increases into 2023 and beyond. Domestically from what we're seeing, and this is a bit of a triangulation, I know, there's a lot of dialogue around individual marketing books, EIA, data, mobility data. So you have to be a little bit of a statistician and try to piece it all together to formulate an informed view around actual demand. But from an overall perspective, backing through the back end of COVID, diesel has been resilient throughout. It remains resilient domestically here in the US, gasoline if you remember when we went into COVID, early on a lot of conversations around structural impacts. And we do feel like we've seen some structural implications as a result of COVID. But most of that's been on the gasoline front. And we're kind of at a point now where our call of post COVID demand is off about 3% on the gasoline front from 2019 levels. That's probably pretty sticky. The headwind, there is obviously the work from home a little bit of tailwind. We've seen some decreased use in public transportation offsetting that, but 3% is been about the number that we've seen consistently as we look across our books. And then as it relates to jet, steady rate double recovery as what we've seen the last couple of years, we expect to see full recovery domestically here, as we progress through 2023. So back half of 2023 seeing full recovery. As relates to our book, maybe I'll just kind of wrap it up there. What we found in Q4, gasoline year-on-year, 2%. The bright spot of interest was the West Coast. So we actually saw a 5% increase year-on-year in the fourth quarter in the West Coast. Diesel was up 4% and jet was up 3% on year-to-year basis.

Paul Cheng:

Hi, guys. Good morning. Few questions, if I could. The first one is really simple. Fourth quarter, I think Maryann mentioned that as some favorable inventory benefits. I assume, Maryann, you were referring outside the LIFO impact which you take it as a special item or that's what you refer. If this is not then can you give us some idea, then how big is that number in the fourth quarter? And secondly, I think you guys talking about a continuing investment, that this year $150 million in the LA refinery system? If I didn't get it wrong. Can you maybe give us some idea that what all investment we're talking about? And what all of benefits we could expect from there, is there any changing in terms of the crews lay or energy usage or that product yield? Anything that you could share on that? Thank you.

Paul Cheng:

Yes, Maryann, can you quantify how roughly -- how big is that benefit in the fourth quarter?

Tim Aydt :

Okay. This is Tim, I'll take your second question. Relative to the LAR project that we were referring to in the opening remarks, that's really a project that addresses the next phase of an upcoming regulation that is going to be mandating further NOx reductions. And that's regulation is going to apply to all of the refineries in the LA basin, not just ours, of course. And so there's going to be some significant investment required by the industry in order to comply with this. And we believe we have a very unique opportunity at our Los Angeles refining complex to really modernize our utility systems at both Carson and Wilmington facilities in order to meet this Phase 1 and Phase 2 of these reduction requirements. So that's what's driving it. And I think the other thing that's worth noting is this novel project really goes beyond NOx reductions for us. And it will also reduce our SO2, our particulate matter, or VOCs, and some greenhouse gases. So besides lowering our facility emissions, it's also going to improve our reliability. And it's going to reduce our energy usage, which will significantly lower our operating cost. These cost reductions will come in the form of energy efficiency and lower maintenance spend. And the thing we like about it is that these favorable economics are independent of the light product margin fluctuations that can occur. So this was kind of all around the backdrop of the LA refinery is certainly a core asset for us on the West Coast. And it's part of the value chain. And it's already one of the most competitive refineries in the state. So this project is going to further cement its competitive position in California, which is consistent with our strategic initiative of being the most cost-effective refiner in every market we serve. So we expect the project to be completed in 2025. And in time to meet the initial compliance dates for the new regulation. So hopefully, that's helpful.

Tim Aydt :

Unfortunately, we generally don't get into those specific numbers on individual projects and returns but it's significant in the sense that it's lowering our emissions and providing a payback.

Mike Hennigan:

Hey, Paul, it's Mike, we haven't disclosed the multiyear, we will give more color on that as time goes on. What Tim was trying to say is, it is a multiyear project, and we're going to start off with it. It'll be $150 million this year, and we'll give more color as time goes by.

John Royall:

Hye, guys. Good morning. Thanks for taking my question. So just to stick with project growth, and looking at your CapEx budget, and your growth program was about $900 million. That number, I assume will be going down close to Martinez and STAR. So looking into the future, where do you think growth capital goes from here? I think we could structurally lower growth CapEx in 2024 plus, or is there maybe another phase of project we'll start hearing about going forward? And I know you've spoken about the LA project, but just wondering beyond that.

John Royall:

Great. That's really helpful. Thanks. And then maybe just talk about how you're thinking about the Russia product sanctions that are going to be hitting here on the certain? And how that maybe -- how that may trickle through the market? And how long do you think it will take for supply chains to adjust? And then relatedly, if you could just remind us the breakdown of Marathon’s export destinations? How much goes to Latin America? How much goes to Europe? And do you expect to increase your exports to Europe after the fifth?

Rick Hessling:

Hey, John, this is Rick, just add on to Brian's comments. So a couple of points to further drive home how we feel about this market going forward. If you look at winter storm, Elliott in December, when it hit the immediate impact, it had on cracks. And it is again taken our life product inventories, especially here in the US down to levels that are five-year type low numbers, when you compound diesel inventories with VGO and the potential impact that the EU ban on Russian exports will have this could just further exasperate cracks to the positive. So more to watch on this. See how it plays out. I think Mike said earlier, it's neutral to positive. We're viewing it as a positive, especially if the cutbacks and sanctions take hold like most people think they will.

Sam Margolin :

Good morning, everyone. Thank you. I'm actually, I'm tempted to ask about commercial and turnaround integration again, because I do think that's probably the most important thing from this call. But I think people got the picture there. Instead of asking about low carbon growth, and specifically SAF. And I'm asking because investors ask about it a lot, because airlines talk about it frequently. And both of your partners in the renewable fuels category are also sort of publicly, very pro SAF. And so it'd be great to get your thoughts on that category. And see if you think there's any opportunity there. Thank you.

Operator:

Our next question comes from Theresa Chen with Barclays.

Rick Hessling:

Yes, Theresa, this is Rick. So we're short VGO, we're out in the market, especially now more than ever, when it’s turnaround season and I will tell you the way we view this is this short and VGO is going to high grade up all capture specifically on Jet, diesel and light products. So we believe will be a recipient of it and that'll show through via the cracks going forward. Specifically, I will tell you as these Middle Eastern refineries come online midsummer, Theresa, they will domestically consume VGO which, in turn will further short the market, which we believe to be a nice shot in the arm, kind of mid-year end year. So more to come on that. Just something to keep your eye on.

Rick Hessling:

Yes, Theresa, it’s a great question. It's one that we look at and try to draw the right corollary too but we do see a degree of flexibility there. Of course, it depends on the market, depends on the extent of the retail prices. We have seen and I commented on the West Coast in my comments earlier, in what I didn't mention, but we got under $5 a gallon on the West Coast in Q4. So that's where we saw my view is we saw nice demand recovery as relates to retail prices. But our forward view is definitely instructed by a moderated view on retail pricing, which we do think will impact demand somewhere in the neighborhood of 2% to 3% depending on the market, but somewhere in the neighborhood of 2% - 3%.

Jason Gabelman:

Yes, good morning. How's it going? I don't think you guys discussed the outlook maybe I missed it, the outlook for light heavy crude quality dips. Clearly, they've been very supportive in the past couple quarters to earnings. And I think many in the market, expect those to come in as refiners consume. The SPR releases, new capacity comes online. OPAC exports have fallen off a bit. Can you just discuss how you expect those differentials to trend throughout the year? Thanks.

Jason Gabelman:

Great, that's helpful and just my follow up. I appreciate the comments on the Martinez project. And operationally, it sounds like everything's going well there. I was wondering from an earnings perspective, how much you expect that project to contribute in 2023, just given the pretreatment unit won't start up until later in the year. And at the numbers we look at, it seems like margins for projects that don't have pretreatments are much more challenged than projects that do. So if you just talk about the earnings in 2023, and the potential step up from the project once that operation units online.

Mike Hennigan:

Yes, Jason, we don't give specific individual facility earnings profiles. I know it's a question and people have been trying to get their arms around. But the best guidance I can give you is if you look at the macroenvironment around the California market, and where each of the subsidies are trading, the key to remember because people ask us about LCFS. But there are other components to subsidy out there that all kind of worked together. And the three of them together have been relatively consistent, even though a lot of them are moving around a little bit. So that should help you a little bit as you model it. And then obviously, look at where feedstocks are trading and diesel's trading.

Operator:

Our next question, and our last question will come from Matthew Blair with TPH.

Rick Hessling:

Yes, Matt, I can comment on the octane, they obviously you're going to move seasonally and quite a bit. But we've seen steady strength in octane spreads, really as a result of running the systems harder. As we look at not just our system, but the global system working to meet demands, and out running our octane capacity to a certain extent as other facilities have been shut down throughout the network. So you kind of have a bullish long-term outlook as it relates to octane spreads and position well around that, based on our octane capacity in our system.

Kristina Kazarian:

All right. With that, thank you, everyone for your interest in Marathon. If you have any additional questions or if you'd like clarification on the topics discussed this morning, please reach out and our IR team will be available to your call. I look forward to speaking with everyone. Thank you.

Kristina Kazarian:

Sounds great. Welcome to Marathon Petroleum Corporation's third quarter 2022 earnings conference call. The slides that accompany this call can be found on our website at marathonpetroleum.com under the Investor tab. Joining me on the call today are Mike Hennigan, CEO; Maryann Mannen, CFO; and other members of the executive team. We invite you to read the safe harbor statements on Slide 2. We will be making forward-looking statements today. Actual results may differ, and factors that could cause actual results to differ are included there as well as in our filings with the SEC. And with that, I'll turn it over to Mike.

Maryann Mannen:

Thanks, Mike. Moving to third quarter results. Slide 6 provides a summary of our financial results. This morning, we reported adjusted earnings per share of $7.81. This quarter's results were adjusted to exclude three items

Operator:

Yes. Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question today comes from Doug Leggate with Bank of America. Go ahead please. Your line is open.

Maryann Mannen:

Thanks, Doug. So as you know, we made a commitment that we would reassess the dividend immediately completing the $15 billion, and we've done so. We wanted three objectives really around the dividend. One was for it to be secure competitive. And then obviously, with the potential to grow dividends in the future, as you said, we believe our increase to $0.75 in the quarter meets all three of those objectives. As you know, we completed that $15 billion share authorization and have a remaining $5 billion new authorization, which both Mike and I had shared on our prepared remarks that we intend to begin to use that very early in the month of November. We continue to think that our equity is undervalued. And when we look at distribution return on capital between dividend and share repurchase, we believe share repurchase remains a more efficient tool in that portfolio. So we'll look at market, we'll look at other growth opportunities, and we'll look at the macro, and we'll continue to use share repurchase absent other growth opportunities as the vehicle to continue to return capital to the shareholders and every decision that we make, obviously, focused on trying to ensure we've got peer-leading returns. I hope that helps, Doug.

Maryann Mannen:

Doug, I'll start off, and I'm sure Mike will want to add incremental comment as well. I think the mid-cycle is an extremely difficult way for us to put a pin in as we stand right now. Certainly, when we look at the market dynamics, as Mike shared as well, we remain pretty bullish on the outlook, not only for the fourth quarter, but certainly as we head into 2023. So a series of factors that we use and we look at to determine when we say we believe that equity is undervalued, and we'll continue to be as opportunistic as we can as we are using share repurchase in evaluating where both the fourth and the first quarter will go and, frankly, longer term. So several factors that we consider, but we certainly look right now at a fairly optimistic outlook for the next several quarters.

Douglas Leggate:

You make significantly higher mid-cycle as what I was looking for. Thanks very much indeed.

Neil Mehta:

Good morning team. The first question is really to build on your comments around commercial. The capture rates have continued to come in very well over the last couple of quarters. And Mike, I know when you came into the role, one of the opportunities you identified was really strengthening your commercial effort. So can you just talk about what specifically has driven sort of that improvement in capture rates? And how much of that is because of those commercial initiatives?

Rick Hessling:

Yes, Neil, it's Rick. Thank you for the question. It's one of these items where we've been looking at the pull through, and we've been seeing it the last several quarters. So it's nice that you're noticing it as well. I would start by saying earlier this year, we changed a lot. We changed processes, we change structure and culture around all things commercial that's been a game changer for us. In terms of details and how competitively, I'll be careful in what I share here, Neil. But if you look at it over were through a broad lens, we've stood up a dedicated what we call VCO team, value chain optimization team that goes from end-to-end, from feedstocks to products from purchasing or procuring to placement and we're relooking at everything we do, the why, the how, all modeling constraints, assumptions, everything was put on the table and relooked at. And so a lot of change and great positive results have come out of that, especially in the midst of the environment we're in. So every win, when you're in an environment like we're in today is exemplified with the high crack and I think you're seeing that. In addition, you're seeing a lot of the re root of global products and feedstocks happening throughout the world. And through this initiative, we've been able to take advantage of a lot of purchasing of feedstock and the placement of our feed -- clean products in a time that has been highly advantageous. So with that, I'll turn it over to Brian for more color on the clean side.

Neil Mehta:

Yes, that's great color. So it's showing up in the numbers. And as the follow-up is just a specific dynamic gravity stock. We've seen WCS really blow out. Historically, you guys have been one of the larger buyers of Western Canadian crude. But do you also see heavy wider in barrels like Maya and high-sulfur fuel oil. So maybe you talk about what's driving the weakness in the heavy crude and product markets and how are you optimizing your refining slate to take advantage of that?

Neil Mehta:

It makes sense. Thank you, team.

Operator:

Our next question comes from Roger Read with Wells Fargo. Go ahead please. Your line is open.

Michael Hennigan:

Good morning, Roger.

Brian Partee:

Yes, Roger, this is Brian Partee. I can take that. There's a couple of different things to unpack there. First on the Mississippi River. We have a really strong and capable Inland River system and team. We've got over 20 tugs and 300 barges. We largely operate on the Ohio River, but also do transit the Mississippi. And the team has been working extremely hard over the last several months making sure the product continues to flow. So I can say there's been no impact, but it's been on the heels of our team working very diligently hard and positioning the right equipment in the lower Mississippi River to make sure that we don't have disruptions. So on that front, things have been going pretty well. As it relates to the ongoing dialog with the administration, we have had frequent engagement and communication, which has been welcomed. I think it's good to share and understand each other's perspective. And as it relates to the export ban, I think that through the dialog, there's been general consensus and understanding that, that likely would be counterproductive the goals and objectives of building inventory and reducing prices. I mean, fundamentally, if you look at our 2.5 million barrels of exports in the U.S., we just don't have enough demand to back it in. We've got grade mixes. We've got logistics disconnect. So I think there's been broad understanding and engagement that, that's not the best course of action. Now all that being said, I just can't speak on behalf of the administration, I think anything is on the table at any time.

Roger Read:

Yes, I follow that, but then see a wish for a windfall profit tax, which would be unlikely to lower prices either based on experience. So you just don't -- never know what they might decide they want to do or feel forced to. I threw a lot into that. So I'll turn it over -- or turn it back over. Thanks.

John Royall:

Hi guys, good morning. Thanks for taking my question. So on the OpEx guidance for 4Q, I'm surprised to see it down from 3Q levels given you have more turn relative to 3Q. So anything to point to there either something from 3Q that's non-repeating or anything in 4Q in particular?

Michael Hennigan:

John, it's Mike. Let me just add to what Maryann just said. So we try our best to give you as good a guidance as we can with the one caveat being where is natural gas price going to be? So we look at the forward curve right before we give the guidance and just reminding you the sensitivity is $0.30 a barrel for every $1 per million BTUs. So where that actually ends up in the quarter is hard to call. So we just take a look at the forward curve ahead of time and put our best number on it. So what I feel good about is the areas that we control on cost. I continue to say we have sustainable reductions that we've seen over the last couple of years, and that's good. As Maryann mentioned, we have a tax dispute that we'll follow up on. And we have this unknown as to where natural gas will actually price itself throughout the whole quarter. Hopefully, that helps.

Maryann Mannen:

Hey John, Maryann, I'll start and then I'll pass it to Rick and Brian to give you any incremental color. But you're right, when I provided guidance on capture for the third quarter, knowing that we had a fairly strong third and fourth quarter, frankly, but third quarter compared to the second quarter turnaround activity, we expected that we would have seen some capture impact as a result. Having said that, there were certainly some offsetting elements in the quarter. First, as you know, we actually saw prices come down a bit and those lower prices actually improved our clean product margins. Pricing actually really did benefit as we looked at the volumetric gains quarter-over-quarter. And then while secondaries were still a headwind in the quarter, they were better than what we had initially projected. Your question was a little bit tough, you were cutting in and out. But as we talk about the fourth quarter, I think, is what you were asking as well. Obviously, it will be, as you've seen from the guidance, our heaviest turnaround month of all -- excuse me, quarter of all four quarters. So we would certainly anticipate that capture in the fourth quarter could be below what we saw in the third quarter for some of those very reasons. But let me pass it to Rick and Brian to give you incremental color. I think Mike wants it too.

Rick Hessling:

John, this is Rick. I'll just add to Maryann's earlier comments and make a comment on secondary product margins. So we're one month into the quarter. We'll see where the next two months go. But secondary product margins have been so volatile and trying to predict where WTI is going to go from here is anyone's guess. I would say that's one of the biggest wildcards on where our capture will end up. So -- more to come there. We'll see how the rest of the quarter plays out. And with that, I'll see if Brian has any color to add.

John Royall:

Very helpful, thank you.

Operator:

Our next question comes from Sam Margolin with Wolfe Research. Go ahead please. Your line is open.

Brian Partee:

Good morning, Sam.

Brian Partee:

Yes, Sam, this is Brian. I'll take that question. It's a great question. So, first, let me just back up and talk a little bit about what we have going on out west with Martinez. So we're well into our prefill strategy. So we've been prefielding since middle of the summer. We're currently buying from over 50 different suppliers. So we forayed into this business two years ago with Dickinson and the team has come up very, very fast in developing those relationships.

Sam Margolin:

Okay. Thanks. And then speaking of optimization on the Refining side, maybe if we could go back in time to the MarkWest acquisition a number of years ago, a big part of that was NGL integration into the refineries or at least there was a contemplated synergy. And now we've got a pretty noteworthy NGL dislocation and specifically butane. And I wonder if that relationship is, as you imagined it at that time or if in the process of your sort of commercial transformation, if you've fenced them off or organize them differently?

Sam Margolin:

Thanks so much. Have a great day.

Operator:

Up next, we have Paul Cheng with Scotiabank. Go ahead please. Your line is open.

Brian Partee:

Yes, Paul, thanks. This is Brian. I understand the question. So first on CI as it relates to soybean oil, UCO and actually even some of the other feedstocks that we look at. I would say that we're at a point or we've been at a point here in the last several months where we like ourselves and others have been in startup mode. So there's been a bit of a surge in demand in acquiring feedstocks as it relates to start-up. And the market broadly is not super-efficient yet. So it's an emerging market. Relationships matter. A lot of the sellers in this space, so whether it's UCO or rendered fats. It's a new business line for them. So there's a lot of exploration ongoing. So I don't think it's a structural change as we've seen here in the last couple of months. But I do think it's just the nature of the market evolving from a CI perspective. But as I said earlier, to Sam's question, I think logistics are going to be key. Those relationships are going to be key to make sure we get the right feedstocks, the most advantaged feedstocks into our facilities. Your second question related to LCFS. Certainly, we've seen the supply and demand of LCFS credits to gap out here over the last 1.5 years or so. The one point I'd make here is we're seeing that in California, that there's other states, other areas, Canada, Oregon that have emerging programs. So that's a new variable that's entering into the equation and calculus for us and others in terms of where you actually place the product. So we reported -- CARB reported a pretty big build for the second quarter. Credit is still a little over 1.3 million credit in the second quarter. So that surplus continues to grow. We do expect CARB, they're going through a scoping assessment now on the LCFS program. We do expect them to make adjustments to the plan going forward to really support the investments needed on the low carbon side of things. I think that will be an opportunity in 2023 to engage and discuss and probably something we see manifest in 2024. Ultimately, the economics as it relates to RV are really founded on several interrelated variables. We've had the positive side of that on the RIN and the Blenders Tax Credit. Certainly, the product pricing in California has been supportive. So that's all been on the positive side. Feedstock pricing, although stable through the third quarter has been towards the higher side as we think about this year. And then as you mentioned, the LCFS have been the lower side. But all that combined considered, we're seeing stable margin production out of our Dickinson facility, and we'd expect the same out in Martinez, just through a variety of different variables.

Paul Cheng:

Sure. Just curious, do you guys have any plan to add additional development plan or now the plan, sales at a next one or two years? Or that you just have the machines going to bump up and you're going to wait until that's fully ramp up. So what type of strategy that you guys have in mind?

Paul Cheng:

No, I'm saying that I hear what you say about the [indiscernible] curious that now you have the renewable diesel plant in that going to come up very soon. And so what is the next step in your strategy? Do you plan to add additional new facility or new development in the area before you fully stand up on the material or that you say, okay, we just have some major investment on the space and that's run it for a couple of years before we look for the next addition?

David Heppner:

Yes, Paul. This is Dave. So I think, as Mike stated, while we have Dickinson up and going, and we're bringing Martinez online, both Phase 1 and Phase 3 even with the Neste JV, part of our strategy, and Brian touched on a lot of it from feedstock all the way to product placement is, I won't say replicating the hydrocarbon value chain, but leveraging our core companies are strengths that we've shown in the commercial value we can extract out of participating up and down that value chain. Probably a little bit of a difference from the hydrocarbon to the renewable is we don't want to get over our skis and maybe outside of our core competencies, and we also want to hedge speed to market. Hence, the reason you're seeing our relationships, our JVs will use them, our partnerships with ADM and Neste, for example. So as Mike stated, we're going to continue to evaluate new opportunities. We look at a lot of stuff, but it needs to be capital efficient. The IRA is -- could be some tailwind as you look at this. But I still think it's a little early to see how some of those variables all play out and the actual mechanics of the IRA before we can make long-term investment strategies. Thank you.

David Heppner:

You're welcome, Paul.

Unidentified Analyst:

Hi, thank you for taking my questions. First, I wanted to touch on your comments about demand across your system. Your earlier comments about being down in 2019. Was that specific to your assets? Or were you talking about the DOE numbers in general? And would love to get some color there. And also on the supply outlook on the product side, just given the multiple variables at play, be it Russian products rerouting ahead of the February 5 new ban or incremental Asian exports in China and ex-China potentially coming to water and hitting PADD 5 and would love to hear your views on how all of that percolates.

Brian Partee:

Yes, thanks, Theresa, for the question. So yes, just a bit of color maybe on the system. First, to address Mike's comments around our data. Mike did quote on the DOE data. Our comps back to 2019 aren't super relevant given that we've shut down a couple of different refineries, we sold off for retail units. So we really look at the year-to-year. And I'll give you just a high-level overview for Q3. So year-on-year, distillate has been steady and strong, very stable across the platform and really flat year-on-year. Jet continues to perform well, and we're seeing that recover year-on-year about 6%, but still below 2019 across the platform. And then gasoline is probably the most interesting. We did -- we were off slightly from 2021 in Q3, about 2% and it really correlates to retail prices. So we'll start in the West and about 4% below Q1 and 2021 out West, so 4% decline that we really correlate directly to retail prices and the elasticity impact of higher retails. Midwest was about 3% and the Gulf Coast was 1%. So overall, about 2%. But kind of going back to Mike's earlier comments, we do remain optimistic as we think about demand. I mentioned October we came out of the chute really strong here for Q4. We're continuing to see COVID demand recovery. Jet travel more broadly, the halo around activity and vacations, not just Jet but marine fuel, diesel, gasoline, et cetera. And we also have moderated retail prices coming off of the summer highs. We're currently around $375 a gallon, well off of our highs in the summer. And demand continues to also be robust in South America and the Caribbean. The economies there are geared a little bit differently. We've got strong agricultural demand globally as well as mining activity. There's been some price subsidization that's occurred in South of the border here, that's also helped to prop up demand. So -- and then we're seeing pulls into Europe as well, for obvious reasons, primarily around energy security and just having access to the fuel going forward as the winter enthuse here. And the last thing I'd mention is on the supply constraint side. We've taken a lot of capacity offline globally, and we do expect a degree of friction around the Russian exports of production, hard to call the ball on how impactful that might be. Everybody is watching very closely, but we don't expect it to be positive for incremental supply. We do expect it to drag just a bit.

Brian Partee:

Yes, as it relates to a lot of -- and you enter a rumor coming out of Asia in terms of export quotas, COVID policies, really difficult for us to call. The one data point I can give you, though, Theresa, empirically on that, is we have not seen where we compete. We have not seen a step change in terms of competing with refineries coming out of Asia, specifically to China. Just it's been steady as she goes, status quo here for the last several months.

Operator:

Our last question today will come from Matthew Blair with TPH. Go ahead please. Your line is open.

Timothy Aydt:

Hey Matt, this is Tim. I'll take the first part of that question. So the remaining scope that we have will indeed increase the heavy crude capacity by about 40,000 barrels a day. It will also improve the resid upgrading by about 17,000 a day. We do still feel really good about the economic drivers of the project. I mean, obviously, you've got the current widening heavy crude differentials and you've got strong distillate cracks that have really kind of improved the project value over our original look. We also made some logistics investments that are being heavily utilized and those further improved product margins in some of these niche markets, be it domestic or foreign and then as I said in the prepared remarks, so the remaining work is going to be tied in during the turnaround in the first quarter of next year. So that's kind of where we're at on the STAR project. So kind of back over to Mike.

Matthew Blair:

Good stuff. Thanks. I'll leave it there.

Kristina Kazarian:

Sounds great there. And then on that operator, I think we are done for today. So thank you, everyone, for your interest in Marathon Petroleum. Should you have any additional questions or would like clarification on topics discussed today, please reach out and our IR team will be available to help you with your questions. Thank you, everyone.

Kristina Kazarian:

Welcome to Marathon Petroleum Corporation's Second Quarter 2022 Earnings Conference Call. The slides that accompany this call can be found on our website at marathonpetroleum.com, under the Investor tab. Joining me on the call today are Mike Hennigan, CEO; Maryann Mannen, CFO and other members of the executive team. We invite you to read the safe harbor statements on Slide 2. We will be making forward-looking statements today. Actual results may differ, and factors that could cause actual results to differ are included there as well as in our SEC filings. With that, I'll turn the call over to Mike.

Maryann Mannen:

Thanks, Mike. Moving to our sustainability efforts. In June, we published our annual sustainability report and our annual perspective on climate scenarios report. We continue to make progress on our greenhouse gas reduction targets. And through 2021, we have achieved a 23% reduction in our Scope 1 and Scope 2 intensity emissions, and an 11% reduction in our absolute Scope 3, Category 11 greenhouse gas emissions. Our perspectives on climate-related scenarios which is aligned with TCFD standards, provides insight into some of the strategic considerations we take to set meaningful objectives, dedicate resources to accomplish them and then hold ourselves accountable and demonstrate results. Our sustainability report shows continued progress on the sustainability goals that we have set for ourselves, which we have been reporting on since 2011. We believe our investors and other interested stakeholders will find that the extensive disclosures in these reports illustrate our company's financial strength, adaptiveness and resilience to climate-related risks. Moving to second quarter results. Slide 5 provides a summary of our second quarter financial results. This morning, we reported adjusted earnings per share of $10.61. This quarter's results were adjusted to exclude a $230 million benefit related to changes in the 2020 and 2021 RVO requirements published by the EPA. Adjusted EBITDA was nearly $9.1 billion for the quarter and cash flow from operations, excluding favorable working capital changes was almost $7 billion. During the quarter, we returned $313 million to shareholders through dividend payments and repurchased approximately $3.3 billion of shares. Through the end of July, we have repurchased $4.1 billion of shares since our last earnings call. Slide 6 shows the reconciliation between net income and adjusted EBITDA, and as well as the sequential change in adjusted EBITDA from first quarter 2022 to the second quarter of 2022. Adjusted EBITDA was higher sequentially and driven primarily by an approximately $6.4 billion increase from Refining & Marketing. Our tax rate for the second quarter was 22%, resulting in a tax provision of $1.8 billion. The tax rate is higher this last quarter due to refining end marketing representing a larger component of earnings in the quarter. Moving to our segment results. Slide 7 provides an overview of our Refining & Marketing segment. During the quarter, our R&M team was focused on supplying transportation fuels to meet market demand. Refining ran at 100% utilization processing approximately 2.9 million barrels of crude per day at our 13 refineries safely and reliably. This is the same level of throughput achieved back in 2019 pre-pandemic before the closures of Gallup and Martinez. Capture was 96%, reflecting a strong result from our commercial team in a volatile market. Operating expenses were higher in the second quarter, driven primarily by natural gas prices, which were approximately $3 per MMBtu higher in the second quarter versus the first quarter. While we have been able to mitigate some of the impact of higher prices, the cost increase we have seen in the first half of the year has been almost entirely driven by higher energy cost. We continue to believe the cost reductions we made to bring our structural operating costs down to approximately $5 per barrel are sustainable. With higher natural gas prices, we would expect operating costs to remain elevated in the third quarter. Distribution costs were modestly higher in the second quarter versus the first quarter due to higher refinery utilization, which resulted in higher system volumes. Turning to Slide 8, which provides an overview of our refining and marketing margin capture this quarter, our capture results this quarter were impacted by a few key factors. Secondary products continue to be a headwind as prices lag higher light product prices. This was partially offset by strong gasoline and distillate margins as well as higher volumetric gain due to higher product prices. Product backwardation created a headwind during part of the quarter. But during this time, we were able to leverage our robust logistics capabilities to translate a portion of our physical barrels into the market on a more prompt basis. And our ability to capture 96% of the market indicator across an incredibly volatile 3 months was in part due to our commercial responses. Slide 9 shows the change in our Midstream EBITDA versus the first quarter of 2022. Our Midstream segment continues to demonstrate earnings resiliency and stability with consistent results from the previous quarter. Performance is underpinned by strong operations and a commitment to strict capital discipline. MPLX remains a source of durable earnings in the MPC portfolio. As MPLX continues to generate free cash flow, we believe it will have the capacity to return significant capital to its unitholders. Today, MPLX announced an incremental $1 billion unit repurchase authorization. Slide 10 presents the elements of change in our consolidated cash position for the second quarter. Operating cash flow was approximately $7 billion in the quarter, which excludes changes in working capital. Working capital was roughly flat for the quarter as we saw benefits from an increase in crude oil payables related to higher refining throughput, offset by a build in crude oil inventories. Since the first quarter of 2021, working capital related to increasing prices has been a source of cash flow. Capital expenditures and investments totaled $546 million this quarter. We continue to spend on our STAR project, which is projected to increase crude capacity at the Galveston Bay refinery by 40,000 barrels per day. This project is expected to be completed early 2023. We are progressing the conversion of Martinez renewable fuel facility and expect the first phase to be mechanically complete by year-end. During the quarter, MPC returned $313 million to shareholders through our dividend and repurchased approximately $3.3 billion worth of shares. At the end of the second quarter, MPC had approximately $13.3 billion in cash and short-term investments. As Mike mentioned earlier, we remain committed to a secure, competitive and growing dividend. Our objective has been to complete the $15 billion repurchase program no later than the end of this year. We remain on track to meet this commitment. Upon completion of the program, we will reassess our dividend level. Since the launch of this program in May 2021, we have repurchased approximately 12.1 billion shares at an average share price of approximately $74 per share. Over this time, we have reduced MPC share count by approximately 162 million shares or over 24%. We've received the Board's approval for a separate and incremental $5 billion share repurchase authorization. We'll work through our capital allocation priorities and continue to assess the market environment to determine how we might execute against this authorization. Turning to guidance. On Slide 11, we provide our third quarter outlook. We expect crude throughput volumes of roughly 2.7 million barrels per day representing 94% utilization. Utilization is forecasted to be lower than second quarter due to higher planned turnaround activity. Planned turnaround expense is projected to be approximately $400 million in the third quarter with activity spread across all 3 regions. As we've mentioned on previous earnings calls, our planned turnaround activity is back half weighted for 2022. Turnaround activity is reflected in our third quarter throughput guidance we expect this elevated level of activity may reduce our light product yields. We'll optimize to minimize the impacts, but we think our capture rate for the third quarter could be lower than the second quarter. In coordinating maintenance work, we'll always try to maximize turnaround and catalyst cycles to the economic optimum, but we also do not compromise on safety or asset integrity and ensure work is scheduled to achieve this balance Total operating costs are projected to be $5.50 per barrel for the quarter. We are expecting higher operating costs in the third quarter. This is primarily driven by the elevated cost of natural gas as well as slightly higher project expense work, which we normally coordinate to occur during turnarounds to limit the impact on throughput reduction. As a reminder, natural gas has historically represented approximately 15% of operating costs. Our natural gas sensitivity of approximately $330 million of annual EBITDA for every $1 change per MMBtu. This equates to a sensitivity of approximately $0.30 per barrel of cost. Distribution costs are expected to be approximately $1.3 billion for the third quarter. Corporate costs are expected to be $170 million representing the sustained reductions that we have made in this area. In closing, we will continue to optimize our system to provide as much transportation fuel to the market as demand requires. We remain committed to advancing our low-cost initiatives and focused on areas to drive continued commercial outperformance, and we will stay steadfast in our plan to execute against our capital allocation priorities to drive shareholder value. Let me turn the call back to Kristina.

Operator:

[Operator Instructions]. Our first question will come from Doug Leggate with Bank of America.

Michael Hennigan:

Yes, Doug, we have talked about this before. I mean we continue to look at it. It's not something that we have off the radar screen. But we continue to come to the same conclusion we have for quite some time that those other situations where people are rolling up their MLPs, we think, are in a much different situation than we are. We're pretty pleased with our MLP's performance, continues to kick cash back to MPC. The structure itself, obviously, it's going out of favor with investors for a little bit, but we think that's starting to turn around as well. So it's something we keep looking at, Doug. But at the end of the day, we're still comfortable with the structure that we have. And we think it works for the Marathon family to have both MPC and MPLX.

Michael Hennigan:

Yes, Doug, it's a good question. And I know some people have been asking us on the last couple of calls where we are on the dividend. I think if I'm right or if I'm wrong, we stated that we were going to maximize the share buyback program and complete that and then reset the dividend. That's still our intention. We're $12 billion through the $15 billion program. Everybody has seen the pace at which we can execute and that's guided by our trading volume and the programs that we have in place. So we're pretty close to talking about that in a more constructive way, we are committed, and we said this in our remarks, we're committed to a competitive dividend. We want to show the market that we'll grow that dividend. It's probably taken a little longer than everybody's patience has been as far as this return program, but it's actually been executing well in our mind. As Maryann said in the prepared remarks, we bought back quite a bit of the shares at $74. So we're feeling pretty good about that in general. And we're not too far off of the releasing to the market where our head is on the dividend.

Neil Mehta:

Really terrific execution this quarter. The first question I had was actually on the crude market. It's obviously been volatile. But we've seen differentials widen out for a couple of different basins, Brent-WTI, Western Canadian crude has opened up as well. Just love your perspective from a commercial perspective of what do you think is driving some of the opening of the differentials? And do you see yourselves as well positioned to capture some of that volatility?

Rick Hessling:

Yes, Neil, really great question because we are seeing a lot of volatility in both of those markets, specifically to TI first. We're seeing strong production in the Permian and both on the WTI and WTL specifically. So if you look at where MPC is positioned and with our pipeline commitments with Galveston Bay really sitting in the backyard of the Permian. There's really nobody better positioned than us to take advantage of TI and TL. And then specifically on WCS, that has widened out to 21-plus under. And that's happening, Neil, for a variety of reasons. One, we believe the SPR barrels have put significant pressure on the medium sour barrels in the Gulf Coast, and WCS needs to clear to the Gulf Coast. So it needs to compete directly with the medium sour barrel, and the early SPR releases were predominantly medium sour. So from an MPC perspective, we have historical space out of Canada. We're able to take advantage of that in all 3 regions, the West Coast, the Mid-Con and now the Gulf Coast. So we feel very good about that macro environment going forward. If those are still open, we'll be as well positioned as anyone to capture those advantages.

Raymond Brooks:

Okay. Neil, this is Ray Brooks, and I'll take your question on that. You're right. There are a lot of moving parts to the economics of renewable diesel some recent headwinds, LCFS price is a little lower than we would have anticipated feedstock prices across the board a little higher. And then there's some tailwinds. We've got a bigger contribution from RIN pricing, a bigger contribution from RD prices. So a lot of moving pieces in the equation. But one thing I'll tell you is when we look at like our Dickinson project, when you take all the puts and takes, the plus and minuses together, we're pretty much on par with where we expected the project to come in. And so that's our experience with Dickinson. We expect the same type of contribution with Martinez going forward. One thing that I would like to add, though, is what we really do is a lot of things I'm talking about outside of our control, whether the regulatory prices, the feedstock price is going to be. I'd really like to focus on what we do and specific to Dickinson, we pay attention to all the feedstocks and we pivoted to the most lowest cost feedstock slate, the lowest carbon intensity slate by optimizing our feedstock acquisition process. The other thing we did is even though that, that project was supposed to be 100% refined bleach deodorized soybean oil, we used our pretreatment facilities at Beatrice, Nebraska and Cincinnati to essentially bring in a fully pretreated feed slate in there. So really concentrate on the things that we can control to deliver the EBITDA. But a lot of moving parts, and we're just doing the best we can with it.

Manav Gupta:

Mike, you bought a lot of capital discipline to MPC. Investors really respect you for that. But we are in a different environment versus when you actually took over MPC. You have the best-in-class midstream footprint in Permian and Northeast, 2 basins where volumes are actually growing materially. We are seeing E&Ps raise CapEx in these regions. My question is for the right opportunity, organic or inorganic, would you be willing to spend more at the midstream level to benefit from the projected volume growth? .

Manav Gupta:

My second and very quick follow-up is, again, very positive operating cost on the Gulf Coast below $4. You -- if you look at last couple of years, it's been trending down, but you actually did not close an unprofitable assets. Sometimes when you close an unprofitable asset, the cost can come down. Your cost has been coming down as the assets -- as the number of assets has remained the same. So help us understand how you're able to push through these lower OpEx numbers?

Rick Hessling:

Yes. So Manav, so hand-in-hand with op costs goes refining margin per barrel. And we have really taken Mike's push on improving the commercial performance. We have an acronym we call CCI, continual commercial improvement, and the Gulf Coast -- and this is -- this goes for all 3 regions, but the Gulf Coast specifically, I think you're continuing to see us separate ourselves and improve quarter-to-quarter. And in simple terms, Manav, what we're doing is we are expanding the crack. We are expanding the margin from feedstocks to products. We're optimizing every day. It's a focus that is relentless within our team, and it's something truly that's been going on for years, but you're now really seeing the dividends of the optionality that the team has created, the logistical flexibility and our ability to take a feedstock into the refinery for raise team, his successful operating metrics that he's shown and proven that he's best in industry for quite some time with his toolkit. And then taking that all the way to the end consumer, I can't stress enough how proud we are of our team and it's an initiative that's very important to us and one that I think you'll continually -- I'll ask you to continually watch because I feel confident in our performance in the quarters ahead as well.

Roger Read:

Yes. Mike, good to hear you on the call, for sure. My question, coming back to the 96% capture in the quarter, your comments about the commercial operations helping. And then looking at where we are thus far in the third quarter. In Q2, we saw between the Gulf Coast and New York Harbor, quite an opening between cash markets for diesel. This quarter, it's cash markets for gasoline. So as we think about those kind of dislocations in the market, the crude diffs mentioned before, what would be a reasonable expectation for kind of capture performance this quarter?

Roger Read:

Okay. And then maybe pivoting back to Martinez and the error permit that's still required. Could you just help us, I mean, the 30 days obviously was provided in the release. But is there any other part of that process we need to watch in terms of other approvals required or an extension or anything like that? I mean is it 30 days and should be good on knowing what to do? Or do we have to watch other events?

Operator:

Our next question will come from John Royall with JPMorgan.

Rick Hessling:

John, this is Rick. So going forward, it's been interesting. I'll back up and just talk about July and then where we're at today. So early in July, we had a little bit of a speed bump in and then around the 4th of July where demand was slightly below where we thought it should be. Ever since then, though, we've seen week-on-week increases and demand is picking up really across the board, but specifically in gasoline, diesel steady. And as Mike said in his opening comments around jet. Jet is 20% over quarter-on-quarter 2Q, anyways of -- from where we were a year ago, and we're getting very strong indicators from the airlines and the travel industry on domestic travel via jet. Specifically, going forward, we're seeing a very resilient consumer with a lot of pent-up demand and the trends look very promising. Now certainly, you have the headwinds of inflation, rising interest rates, et cetera. But right now, I would say the falling street price that has been permeated by the falling WTI market is winning the day. And the consumer is showing us very positive demand signals today, and we view that going forward as well.