PBF Energy Inc. (NYSE:PBF) Q2 2023 Earnings Call Transcript

PBF Energy Inc. (NYSE:PBF) Q2 2023 Earnings Call Transcript August 3, 2023

PBF Energy Inc. beats earnings expectations. Reported EPS is $2.29, expectations were $2.22.

Operator: Good day, everyone, and welcome to the PBF Energy Second Quarter 2023 Earnings Conference Call and Webcast. [Operator Instructions]. It is now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may begin.

Colin Murray: Thank you, Debbie. Good morning, and welcome to today’s call. With me today are Matt Lucey, our President and CEO; Tom Nimbley, our Executive Chairman; Karen Davis, our CFO; and several other members of our management team. Copies of today’s earnings release and our 10-Q filing, including supplemental information are available on our website. Before getting started, I’d like to direct your attention to the safe harbor statement contained in today’s press release. Statements in our press release and those made on this call that express the company’s or management’s expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws.

There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC. Consistent with our prior periods, we’ll discuss our results today, excluding special items. In today’s press release, we described the special items included in our quarterly results. The cumulative impact of these special items increased second quarter net income by an after-tax amount of approximately $729 million or $5.59 per share. And this relates primarily to the gain realized on the formation of the St. Bernard Renewables equity method investment. Also included in today’s press release is further guidance related to our 2023 operations. For any questions on these items or follow-up questions, please contact Investor Relations after today’s call.

For reconciliations of any non-GAAP measures mentioned on today’s call, please refer to the supplemental tables provided in today’s press release. I’ll now turn the call over to Tom Nimbley.

Thomas Nimbley: Thanks, Colin. Good morning, everyone, and thank you for joining our call. Refiners follow the markets and respond to consumer demand. We continue to hear calls for higher refining utilization, and see a market supported by low inventories and sustained customer demand. Crude differentials narrowed over the quarter. It is common to have narrow crude dist during peak summer runs. The narrows is amplified by the production policies of OPEC Plus and to a lesser degree, recent SBR restocking activity. We believe crude markets are near the peak of the narrowness and would expect crude dists to relax post summer, as the industry heads into full turnarounds that are forecasted to be higher than seasonal norms. PBF’s refining system is well positioned to manage these market dynamics.

We have a complex conversion, ample reforming capacity, shorten asset and our long-life octane. We like our yield profile and that puts the company in an advantageous position. Refinery margins remained well above historical mid-cycle, and we have seen a recent rebound from the relative lows experienced during the second quarter. I say relative because those lows were still above mid-cycle. A key theme for 2023 is the recovery in the demand for jet fuel and gasoline, partially offset by a decline in distillate demand as industrial production has slowed. Diesel inventories are up, yet still remained below 5-year averages. However, at this time of the year, we expect to see distillate inventories building into the coming agricultural season and winter.

The fact that we are not seeing this normal seasonal activity provides some support for potentially stronger distillate markets ahead. The markets will continue to be volatile. Predicting the timing of and the future moves in the commodity markets is challenging. At the same time, we are seeing stable to growing demand for our products at our refinery gates, thereby continuing the call for high utilization from our assets. With that, I will turn the call over to Matt.

Matthew Lucey: Thanks, Tom. Before commenting on the quarter, I thought I’d take a moment to give you my perspective of the company that I take on the role of CEO. First, I can say with absolute confidence that today, PBF is in its strongest position ever as an operating company. As I reflect on PBS time as an operating company, which began 2010, I break our history into 3 distinct periods. The first 5 years from ’10 to ’14, we set the foundation of the company and established our refining platform. The second 5 from ’15 to ’19, we focused on growth. We doubled our refining capacity, increased our logistics footprint and geographic diversification. The 3 years from ’20 to ’22, we navigated the most volatile marketplace oil markets ever experienced, maintaining consistent, safe and reliable operations through the lows allowed us to fully capitalize on the robust market recovery to generate record financial performance, which brings us to today.

We have repaid over $3 billion in debt, repurchased PBF Logistics and PBF Inventory Intermediation Agreements, reduced our environmental credit payables by about 40% since the beginning of the year, and to the renewable fuels business with a world-class partner in Eni, restart paying a dividend and commenced in executing a share buyback program where we bought about 8% of the shares. Moving forward, our focus is on capital allocation. Our repositioned balance sheet will buttress the company against future market disruptions, which are inevitable in this cyclical industry or any cyclical industry for that matter. Our goal is to further strengthen our business, cash flows and balance sheet and to work with the rating agencies to highlight these improvements with the intention of eventually becoming an investment-grade company.

On that front, we have recently been upgraded by S&P, Moody’s and Fitch. We will continue to invest and innovate in each of our refineries to maintain and improve our reliability and competitive positioning. We will evaluate growth opportunities that leverage our expertise and large industrial footprint into high-quality business opportunities that diversify our cash flows beyond refining. Similar to the renewable diesel business we developed at Chalmette. Most importantly, we will weigh potential investments in growth against returning capital to shareholders with the goal of maximizing long-term value. By definition, any returns associated with any future potential growth opportunities must be and will be superior to buybacks and dividends.

Our process will continue to be rigorous and disciplined and will ensure competition for capital, so that funds will flow to the highest and best use. PBF is committed to driving long-term value for shareholders. This obviously begins with working safely and operating reliably and responsibly. On that note, in the second quarter, our refineries operated reasonably well with system-wide throughput in line with our expectations. We completed a turnaround of the Delaware City coker and minor work on the hydrocracker in Torrance. There will be a larger FCC and outpacing units around in the fourth quarter at Torrance. As mentioned in our press release this morning, the St. Bernard renewable joint venture transaction closed in June. We are more than pleased to have gotten to this point and look forward to operating this venture alongside Eni sustainable mobility.

The operations of SBR are progressing as planned. We successfully started up both the RD unit and the PTU. The facility is running well. We continue to line out operations and we sold our first commercial cargoes in July. We are more than halfway through the year, and market conditions have provided PBF with the opportunity to generate exceptional results. While the work to maintain the strength of our balance sheet is ongoing, the major efforts to improve it have largely been completed. We will continue to focus on our robust balance sheet with a simplified and transparent capital structure. We intend to demonstrate the durability of our transformation and our through-the-cycle financial strength. Our goal is to generate long-term value for our investors through solid operational performance, and disciplined capital allocation.

With that, I’ll turn the call to Karen.

Karen Davis: Thank you, Matt. For the second quarter, we reported adjusted net income of $2.29 per share and adjusted EBITDA of more than $560 million. As mentioned at the opening of the call, adjusted net income excludes the gain on the investment in St. Bernard Renewables. We closed on the joint venture partnership at the end of June and going forward, we will account for our 50% interest using the equity method. The fair value of the SBR business was approximately $1.72 billion at closing, excluding working capital. In the second quarter, we recorded a gain of approximately $969 million relating to the formation of the joint venture. The gain represents the difference between the value of the consideration we received, which includes the fair value of our 50% noncontrolling interest in the partnership, plus the cash contributed by our partner, and the carrying value of the related assets we contributed.

On June 28, upon closing of the transaction, we received $431 million and on August 2, just yesterday, we received an additional $415 million subsequent to the successful commercial start-up of the PTU in July. In total, PBF has received $846 million relating to its investment in SBR. PBF is entitled to potentially receive up to an additional $30 million of contingent consideration if certain performance conditions are met. While we exclude this onetime gain from the discussion of our second quarter results, this transaction generated real equity value for PBF and holds potential future value through additional opportunities, we look forward to exploring with our new partner, Eni. With our results from operations and the cash provided by the successful closing of the SBR equity investment, we continued our work to improve the financial position of the company, strengthen our balance sheet and reward shareholders.

We further reduced our outstanding environmental payables by approximately $250 million for a total of approximately $570 million year-to-date. Our environmental credits payables have now been reduced from over $1.3 billion at the end of last year, to just under $800 million at the end of June. Continuing with our efforts to streamline our balance sheet, in July, we exited our Inventory Intermediation Agreement at a total cost of approximately $270 million, including the cost of repurchasing the inventory and transaction fees. This arrangement had been our highest cost of capital. For the first time in our history, the company now owns and controls all of its inventory, a milestone event in the development of PBF. We continue to purchase PBF shares and through today, we have repurchased almost $440 million worth of PBF shares, including $100 million in the second quarter.

For the life of the program to date, we have repurchased over 11 million shares and reduced our total share count to just under 124 million shares. Our G&A expenses for the second quarter came in at $104 million, which includes our base G&A expense and amounts related to the company’s incentive and equity-based compensation plans. For the sake of clarity, PBF’s annual base and G&A expense should continue to be in the $200 million to $250 million range. Depending on financial and operational performance on top of this, there could be approximately $100 million in incremental G&A expense related to our compensation programs. This incentive component of G&A is variable and dependent on a number of factors, the most important of which is our financial performance.

If the company does well, so do our investors and our employees. Consolidated CapEx for the second quarter was approximately $367 million, which includes $260 million for refining, corporate and logistics and approximately $107 million related to SBR. Our refineries should continue to demonstrate durable earnings power, and we are adding diversified earnings streams as SBR comes online. For the second quarter, SBR was not a contributor to the earnings of our system, as we did not fully start up until July. As of today, we have reached planned throughput rates and expect to continue operating in the 20,000 barrel per day range. We have previously mentioned our EBITDA per gallon expectations on a steady-state basis, but we do not expect to reach that run rate until we receive all of the required regulatory approvals for our pathways and products, which could be into the first half of 2024.

We ended the quarter with over $1.5 billion in cash and approximately $1.44 billion of gross debt. We continue to focus on the strength of our balance sheet and ensuring that the needs of the business are satisfied. We believe our sector-leading balance sheet needs or exceeds many investment-grade credit metrics, and we will continue to exercise balance sheet discipline and sound financial policy. Operator, we have completed our opening remarks, and we’d be pleased to take questions.

Q&A Session

Operator: [Operator Instructions]. Our first question comes from the line of Roger Read with Wells Fargo.

Roger Read: I guess let’s — well, first off, Matt, congrats on CEO and all. But can we take a hard look at the diesel markets and your comments, right? So diesel demand has been relatively weak, diesel inventories haven’t done anything very extraordinary in terms of building. And as we look to the fall and winter, let’s say, even a normalized economy next year on the industrial side, what’s your view of the ability to deliver enough diesel into the market, and what this may mean for margins going forward?

Matthew Lucey: I’ll start and maybe pass it over to Tom, who made a couple of comments on that I think are on point. Diesel was a bit softer. But we also, you bring it back to last year, it’s the same pattern we’ve seen maybe in sort of longer duration. But gasoline was much stronger than — in the first part of the year than diesel. As a result, we made more gasoline and the diesel yield decline. There’s always unintended consequences. And so you’re exactly right. Over the last couple of weeks, we’ve seen a tremendous rebound in the diesel crack. And that’s partially because at this time of the year, we’re still well below historical norms for diesel inventories. And so the market has to create the incentive to make the diesel going into the agricultural season and weather turning.

So I have no doubt that we’ll be able to — the marketplace will figure out a way to make the diesel to provide the marketplace with sufficient diesel. But all these questions always come back to the same answer, which is refined capacity is tight. Supply is coming on, but that supply is needed. And so we view it as being very constructive and the marketplace is reasonably well to be — exceed what is historical norms for mid-cycle margins. Tom, you have?

Thomas Nimbley: I mean, Matt, the only thing I would add really is kind of coming, we still have to get through the turnaround season, which is active and long and — seemingly right, just the beginning days of hurricane season. So probably a little bit of premium built into it right now in terms of getting it through there. But ultimately, the market will be — and the industry will be switching yields actively over the next several weeks and months as we basically enter into winter gasoline season and distillate certainly expected to maintain market position.

Roger Read: Okay. And then just to pivot to the comments about it — pursuing an IG rating and the inventory change — can — is there a way you can quantify for us or give maybe a couple of key points of what changes for PBF with the change in the inventory control, and then if you are able to achieve an IG rating, how we should think about that as sort of a quantifiable bottom line impact, if you can?

Matthew Lucey: Yes. So in regards to the Inventory Intermediation Agreement and Karen mentioned this, if you go back in our history, when we first began we had suppliers of crude on the East Coast and the suppliers and off-takers of products. We had suppliers of crude in the Mid-Con for our 3 refineries. And so this is a moment for the company, which just happened last — actually earlier this week when it was finally extinguished completely where the company is properly capitalized. There’s no — the financings in which they are, they’re not bad. But it’s simply just the fact that the company didn’t have the proper capitalization to own it all. Now we do, which I think is a good thing. It dramatically simplifies our balance sheet.

It makes it much more transparent. We own the inventory as opposed to renting it and it sort of buried within the balance sheet. It lowers our costs because the Intermediation Agreement you are paying essentially an interest rate was our highest cost of capital. But as I said, it just demonstrates that not only properly capitalized, but now that we own it, and it’s paid for debt free, it deepens the keel of the company. So it’s more wherewithal that we can utilize in terms of liquidity going forward. And so I think it was absolutely the right thing for us to do. Those structures served us incredibly well over the last 12 years. We’re appreciative of the partners that we work with to have them. But where we are in our life cycle right now, it made the most sense to move on, and we’re pleased to do it.

In regards to investment grade, we’re not doing that for any other reason, then we think it will increase the value of our company on a number of fronts. Obviously, it lowers your cost of capital. But in this business, working capital is incredibly important. And so it increases the open credit with counterparties, you’re talking about 1 million barrels a day of crude being purchased and when at $85 crude, open credit is critically important. And so to improve our standing with counterparties adds value. You improve your insurance costs. So costs across the organization go down, but also you potentially improve your shareholder base, and you attract new shareholders as you become a stronger and stronger company. So I do think it’s incredibly important, and it’s something that it’s a goal that we’re chasing.

I think we have a lot of merit to our argument. And it’s slowly being recognized. We did just get upgraded. But for our industry and for what we do, I think it is important, and I think it will add tremendous value to our shareholders.

Roger Read: Great. Good quarter and we’ll catch you on the next one.

Matthew Lucey: Thanks, Roger.

Operator: Our next question comes from the line of Doug Leggate with Bank of America.

Doug Leggate: Tom, great to hear you on the call. Matt, I think you’ve been pretty clear about the different life stages of PBF through its life cycle. But I wonder if I could — just touch on how you see the portfolio today. Is there anything that you would shift at this point, anything you would change any way you want to be that you’re not — and I guess what’s behind my question is the joint venture you have now is going to generate some RINs, I assume. But it remains a sizable headwind for the company. So when you see the likes of Valero with its ethanol business and other ways to mitigate the RIN exposure. I’m just curious if that’s on your mind as to how you address your obligations going forward?

Matthew Lucey: So I’ll go backwards. And unfortunately, way too much of my time has been focused on RIN mitigation. It’s a far away, far and away, the best way to mitigate RINs is to manufacture renewable diesel, which we’re now doing. And so that it is a milestone event for the company. And not only where we have half the entity. So half the RINs are ours, but we’re set up to as not an obligated party. So we’ll procure their share of RINs as well, which is good access simply to acquiring the RINs. But I would quibble with the idea that investing in ethanol is necessarily a good hedge against RIN volatility. The long and short of it and what makes it difficult is the way the program is administered; the beneficiaries are entities that trade at a much higher multiple than refiners.

So it’s a difficult task to take on that well, I’m just going to buy my way through the RIN market because much of that benefit will flow to wholesale marketers that retail businesses that trade at different valuations in refining. So I don’t think there’s any glorying going that way. But we — like I said, we’re now manufacturing 500 million RINs a year, and that dynamically changes our position. And so we look forward to operating SBR safely and reliably and delivering those RINs. In regards to our portfolio, I talked a little bit of our history. If you go back to the last cycle, 2010 to 2019, I would oversimplify the cycle by comparing it to residential real estate, which was location, location, location and everything else was secondary or not important.

It didn’t really matter what your size was, what your complexity was, your ability — process our grades. It was, are you near the crew renaissance and do you have access to cheap crude for a whole host of reasons, I think our portfolio, which we put together very specifically on the back of complexity and access to coastal markets. Our portfolio, I think, is much better positioned going forward. Well, why is that? I think there’s been a number of closures in the industry, and that impacts everyone. I’m not sure it impacts anyone as directly as it does PBF. As you look at where the closures have occurred, they happen to be all our neighbors on the East Coast, PES. You could see that from Paulsboro to a lesser extent, certainly not our neighbor, but come by chance in Hovensa or direct East Coast participants.

And when you go to the Gulf Coast, it was really the Eastern edge of the Gulf Coast, where Chalmette and the Lynn shutdown, which are neighbors to Chalmette. And there, you have not only benefits from less refined products being produced, but also on crude procurement because they’re buying very similar crude to us. And then you go out to the West Coast, Marathon, Martinez, Scott, San Maria is down, and Phillips 66 announced yesterday that Rodeo will be converting in the first quarter. So all direct and local competitors to Martinez. So I think the closures impact us directly, but stepping back more broadly than that, you have obviously the disruption in Europe, which natural gas is now a major headwind for the refining sector in Europe. You obviously fire boilers and heaters with natural gas, but you also desulfurize your products with hydrogen that comes from natural gas.

And so if you’re paying 4 or 5x natural gas than we are in the U.S., that’s a big headwind and a big competitive advantage for us. And obviously, you have the disruption from the Russian-Ukraine ground war, and that creates other distortions that I think accrued to the benefit of our coastal refining network. And then obviously, something we talked about for years and years and years was IMO, and it became move when the pandemic struck, but it is now the law to see. And I — its impact is embedded in everything else. As we look forward, we’ve got our footprint. We’re very, very pleased. We’re very pleased. We’re just at the beginning stages with Eni and SBR and then we’re looking to get into new businesses like hydrogen, we’re working with the federal government.

I think the company is very well positioned to be potential hydrogen hub going forward. And so we’ve got our refining footprint. We’ve got our renewable footprint that is established and potentially growing. And there are other opportunities with our industrial footprint that I think we’ll be able to capitalize on.

Doug Leggate: Very thorough answer. I guess my follow-up is a quick one on the West Coast. It seems to me last December; I think we saw $100 cracks at one point when refineries went down for maintenance. Obviously, Rodeo is still too close and you’re going to have your FCC off-line, as you pointed out. I guess my question is, how do you see the dynamics in the West Coast now? It seems to me we’re back to sort of 2005 type volatility, incremental imports setting the incremental price. I’m just curious if you can characterize how, you see the West Coast dynamic going forward, and I’ll leave it there.

Matthew Lucey: Yes, I think it’s going to be very tight. And you went through some of the reasons. I’ll ask Paul Davis to comment. He works in California every day.

Timothy Davis: Actually, Doug, I would say you probably nailed it, right? The market is going to have to price a steady flow of imports as we have experienced refineries shutting down, and we have more in pending that are going to shut down. The gasoline markets on the West Coast, including the whole pad are short, it’s going to have to price accordingly, and you’re going to see a lot of volatility going forward. That’s what we see.

Doug Leggate: That was kind of our take as well.

Operator: Our next question comes from the line of John Royall with JPMorgan.

John Royall: So my first one is on working capital. Can you talk about any working capital builds you’re seeing from the start-up of SBR, and we don’t see it in the release, but I assume there was an overall headwind in 2Q. So any of that reverse in the second half? Or just should we be thinking about kind of more ordinary course seasonality for working capital in 2H?

Karen Davis: Thanks, John. Thanks for the question. Yes, in the second quarter, there was a build of inventory related to SBR. In fact, it was $75 million, which was contributed to the partnership. Going forward, all of that working capital requirement will be within the SBR joint venture. So I think you should see in the future return to more normalized working capital.

John Royall: Great. And then on throughput, I think you cut guidance for the full year. Can you talk a little bit about the drivers there? Was it just turnaround dragging a little bit beyond plan in 1H? Or anything with 2H there?

Matthew Lucey: No, I don’t think anything specific. We do have a big turnaround in Q4 at Torrance, the cat [indiscernible] will be down for probably 50 days. So that will certainly impact throughput there.

Operator: Our next question comes from the line of Manav Gupta with UBS.

Manav Gupta: I just have one question, guys. You have 2 complex refining assets on the West Coast. Both of them can process a lot of heavy sour crude barrels. There’s a new pipe, which we can debate if it opens up in 1Q next year or 2Q, but that will deliver close to 500,000 barrels of WCS on the West Coast. I just want to understand how PBF can benefit for it. And if you can help us out a little bit by quantifying it, that would be absolutely great.

Matthew Lucey: Well, I do think it is a tremendously positive story for our West Coast operations, not only bringing new crude into the marketplace. But that crude has to be priced to get to Asia for the U.S. and for our California system. It can be loaded on foreign flagships and we’re dramatically cheaper to deliver it, to Torrance and to Martinez. You’re absolutely right. Our kit out there, we can process the most heavy, the most sour grades of crude out there. And so we’re incredibly well positioned to be able to take that crude, we believe it will be at an economic advantage. And we’re working diligently right now to figure out what most we can run and how we can increase that number, and so we’re actively working in advance of whenever it is, but it is starting out next year that we’ll be able to capitalize on the best way we can.

Thomas O’Malley: Manav, this is Tom O’Malley. We put a little time in the room. But it’s an interesting crude because, yes, it’s a sour heavy crude, but it has day one in it to ship it. And that is not by and large. So we are looking at trying to figure out how to make sure we debottleneck, expand our ability to handle products from that crude at the top of the tower, and we actively have the team working on that, and we can see it as a terrific opportunity for the company.

Operator: [Operator Instructions]. Our next question comes from the line of Matthew Blair with Tudor, Pickering & Holt.

Matthew Blair: I guess starting out on refining. Could you talk a little bit about the capture rates in the East Coast in the second quarter? Seemed a little low. Was that due to the planned turnaround at the Del City coker? And I guess, what would you expect for Q3 here?

Matthew Lucey: Yes, you have it right. The coker impacted — 2 aspects, the coker turnaround, which went into the second quarter certainly impacted capture rates on the East Coast, but also crude differentials are narrowed. And hopefully, the [indiscernible] is upon us. And Tom and Paul can comment on that. We expect crude differentials to now in Del City and Paulsboro have a clean run in regards to turnarounds going forward. Paul, any other comments?

Timothy Davis: No, I think that’s right. We have a pleased slide on work, and we think we’re peaking on the light heavy spreads on crude. So when we take a look at September, October programs are they’re a little more advantageous than July and August.

Matthew Blair: Sounds good. And then could you help us understand a little bit more on your expectations for RD profitability in the back half of this year? I think you mentioned that some of the pathways for I presume like RINs and LCFS might not come through until the first half of ’24. But it sounds like you’re still selling cargoes. I guess 1 question is, is there an opportunity to simply put that R&D into storage and wait for the pathways to fully monetize it? And then I guess second question is, what kind of rough EBITDA range might you expect? And does that $1.25 to $1.50 long-term target still hold?

Matthew Lucey: Right. So I would characterize it in 3 different buckets. Absolutely, to answer your question, we believe long-term profitability in RD will settle out between $1 and $1.50. You said $1.25 and $1.50, it’s in that range, whether it’s $1 to $1.50 or $1.25 to $1.50. I would characterize the current market is a bit softer than that for a whole host of reasons. But the current market, and if you want to call this the second half of ’23, that’s fine. If you’re fully optimized and getting the full benefit of the LCFS credits, it’s probably $0.75 to $1 at the moment. EBITDA margin per gallon. But what happens when you begin operations, you get an arbitrary low carbon score essentially, and that’s suboptimized to what our reality is as we have a full pretreatment facility, and we’ll be able to run all the low carbon feeds that are available.

So the sort of temporary debit you will [indiscernible] say and that runs for 6 to 9 months from the time we begin operations. That’s nothing PBF-specific, that’s for any new entrant into the marketplace. And so for the remainder of this year, maybe early into next year, you’d probably take $0.25 off what the current market is. So call that $0.50 to $0.75 a gallon of EBITDA. Obviously, the markets are dynamic, and things can change quickly. That’s the current outlook. I don’t think there’s any incentive to store diesel, we’ll be selling actively as we go through the year.

Operator: Our next question comes from the line of Paul Sankey with Sankey Research.

Paul Sankey: Matt, I’m sure you’re delighted to be free of Tom. Matt, you gave an interesting little historical perspective early in the call. And one thing that’s always struck me about PBF is you’ve consistently surprised by your willingness to buy major assets. Now that you’re at 1 million barrels a day capacity and you’re obviously highly pursuing the investment-grade rating. How do you think about cost of capital, future acquisitions, cash return, are you going to pursue a dividend policy of growth? Is there any potential for special dividends? Or do you think it will be a buyback with a lot less on the acquisition front now you fill dates?

Matthew Lucey: Okay. There’s a couple of things there. One, I do think there was tremendous benefits to getting to scale. I think we have scale. One small example, when we are 3 refineries, we didn’t have much of a refining organization, with the 3 plant managers reported into executive management. Now we have a Head of Refining. We’ve got a whole organization under that’s help support it. So our access to expertise and operational excellence improves as we got scale. But to your point, we have scale. As I said in my remarks, the rigor that we will take at looking at all uses of capital going forward, whether it’s for potential expansion in or out of refining, we’ll all be analyzed together and compared and everything will always be brought back to our alternative, which always exists in buying back our shares or dividends.

And up until this point, we’ve been very, very focused on debt reduction. Obviously, that’s sort of extended to the Inventory Intermediation Agreement, which we just took out. We’ve been paying down environmental credits. We’ve demonstrated a fairly aggressive buyback program, and we’re coming up on the anniversary next quarter of restarting the dividend. And so every day, it’s my job, and I’ve got a team with me that works every day to figure out our best uses of capital going forward. There is no need to get bigger. And so everything will be an opportunity, and we’ll weigh it against our alternative.

Paul Sankey: Got it. That’s what I kind of thought you would say, frankly. The — and by the way, Tom, that was a joke. I didn’t hear you well [indiscernible] the Valero laugh is much harder regardless of top average is, but more you guys…

Matthew Lucey: They’re much more generous.

Paul Sankey: Can you — you have a fantastic insight to global markets of oil. Could you just talk a little bit, is my follow-up, obviously, could you just talk about — I mean we just had Saudi across the headlines saying that they’re going to extend cuts into September. Could you talk a bit about trade flows, first, crude, how it’s impacting you, big moves in Canadian diffs and then product flows, whether or not the additional mega capacity that we’re seeing in Asia has perhaps less cost impact or a huge question, but I’d be very interested by your answer.

Unidentified Company Representative: Paul, it’s a great question. We’ll go backwards on it. I think the capacity additions, they’re real, but they’re not going to be imminent. It’s going to take some time, to be able to get those huge refineries find out. There will be some offset chance for the U.S. There certainly will be with Rodeo going down. And whatever happens with LyondellBasell, if they continue to say — do as they say and look to exit that business, and down in the Gulf Coast. That would obviously not only have a product impact, but it would also have an impact on crude supply because they run a fair amount of WCS. So I think we’re certainly going to watch that. Ultimately, those refineries will get up speed. But at the same time, they’re mostly in Asia, the population growth in the world is going to be mostly in Asia.

And those refineries are being built predominantly down the road, making sure those confidence are self-sufficient by themselves. In terms of trade flows, I think the expert in this room and our team on watching what’s been happening with Russia, et cetera, and even the new refiners coming on as Tom and — Tommy, you have — anything you would add?

Thomas O’Malley: Yes. I mean, let me pull along with that, I mean, I think it’s really kind of the developments that really happen related to the OPEC cuts, right, Atlantic Basin, long crude, Pacific Basin, short crude. So the OPEC cuts have had a more dramatic effect upon the refineries in Asia starting to see an increased trade flow basically barrels leaving the Atlantic Basin, particularly on lights, right? I mean the Western African programs in the prior months, which were sort of softer, and we’re moving sloshing around the Atlantic Basin are now starting to get pulled to the east. And I think that’s probably the biggest change we’ve seen, which is not uncommon, but that’s the change that’s most apparent in front of us today.

Paul Sankey: Yes. Anything on Canada? And I’ll leave it there.

Thomas O’Malley: I don’t think anything that hasn’t already been mentioned on the call.

Unidentified Company Representative: Obviously, it’s tightened up significantly. It looks like it’s winding out a little bit, but I agree with Tom. We’re going to see the big move there will happen when the trans pipeline gets on board.

Operator: Our final question comes from the line of Ryan Todd with Piper Sandler.

Ryan Todd: Maybe just a follow-up on Paul’s earlier question on the use of cash. I mean, you’ve made material progress year-to-date reducing your environmental liabilities as well as staying active in the buyback market. How much further on the environmental liabilities, how much lower would you like to get that before you feel like you’re in a normalized place? And then with the cash in hand, particularly from — I mean, both your organic free cash flow and the cash in hand from closing Eni deal. I guess you mentioned about being aggressive on the buyback. Is there room to lean in even more on the buyback? Or how do you view the kind of the appropriateness of that, I guess, I would say.

Karen Davis: Sure. Ryan, with respect to environmental liabilities, we are at 800 now, down from 1.3, and we would see ourselves getting to a range of, say, 200 to 400 by the middle of next year and would call that 200 to 400 range, normal, more normal. And then with respect to the Eni proceeds, we’ve long been talking that the balance sheet is our first priority, but the list of cleanup items is decreasing. We talked about taking in the Inventory Intermediation Agreement continuing to reduce the environmental liabilities. There is — with respect to the balance sheet, the potential that we might refinance our 2025 notes. And then beyond that, it’s really weighing as Matt said, the alternatives for excess cash, which includes stock buybacks, but — and everything else has to compete against that return.

Ryan Todd: Great. And then maybe just one last quick one. OpEx came in really strong performance on operating expenses there on the refining business came in lower than expectations. Can you talk about some of the drivers there, and how sustainable some of those are as we look through the second half of the year?

Matthew Lucey: Yes. The biggest driver, no question about is natural gas prices. And so I know there was a lot of concentration on OpEx early in the year, and that was primarily on the back of much higher natural gas prices. Natural gas prices come down or OpEx comes in.

Thomas O’Malley: With that, that concludes the call today. We appreciate everyone’s participation, and we look forward to speaking to you next time. Thank you.

Operator: This concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.