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Presentation

Calumet, Inc. misses on earnings expectations. Reported EPS is $-1.7 EPS, expectations were $-0.44.

Operator: Good day, and welcome to Calumet Inc.’s Second Quarter 2025 Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to John Kompa, Investor Relations for Calumet. Please go ahead.

John Kompa: Thank you, Steve. Good morning, everyone. Thanks for joining our call today. With me on today’s call are Todd Borgmann, CEO; David Lunin, EVP and Chief Financial Officer; and Scott Obermeier, EVP of Specialties. Please note, Bruce Fleming, EVP, Montana/Renewables and Corporate Development, has an unavoidable company obligation today. Todd Borgmann will address questions regarding Montana/Renewables in his absence. You may now download the slides that accompany the remarks made on today’s conference call, which can be accessed in the IR section of our website at calumet.com. Also, a webcast replay of this call will be available on our site within a few hours. Turning to the presentation on Slide 2, you can find our cautionary statements.

I’d like to remind everyone that during this call, we may provide various forward-looking statements. Please refer to our press release that was issued this morning as well as our latest filings with the SEC for a list of factors that may affect our actual results and cause them to differ from our expectations. As we turn to Slide 3, I’ll now pass the call to Todd.

Louis Todd Borgmann: Thanks, John. Good morning, and welcome to our second quarter 2025 earnings call. This quarter was one of sound execution paralleled with foundational and supportive steps taken on the regulatory front, both of which we’ll walk through on today’s call. Calumet earned $76.5 million of adjusted EBITDA with tax attributes during the second quarter. This result was a function of continued execution of our near-term initiatives on reliability, cost discipline and commercial excellence across the company. $8.3 million of our quarterly result was earned at Montana/Renewables, which we’ll touch on more momentarily, leaving the lion’s share of the quarterly result being earned in our specialties business despite a full month turnaround at our largest facility in Shreveport.

Specialty margins continue to prove resilient overall and our product and market diversification has been critical to this as pockets of weakness in the more commoditized paraffinic lube space have been more than offset with continued strength across our specialized lines of naphthenics, solvents, waxes and food-grade in pharmaceutical products. Further, specialty sales volume within our SPS segment marked the third straight quarter over 20,000 barrels a day. And despite a late start to the outdoor lawn and garden season, our Performance Brands segment posted its second highest quarterly sales volume in its modern form, second only to this quarter last year. These results are a combination of continued deployment of our integrated specialty strategy in the industrial lubricants and separately, rapid growth of our TruFuel brand.

One area we haven’t talked about much when it comes to commercial excellence is the impact of our program outside our core specialties offering. Specifically, I’ll note the results from the change in our approach to our Southern asphalt margin. This is a fairly commoditized space, but with 3 crude fed refineries in northwest Louisiana, we have a number of streams to choose from and have proven the ability to more intentionally blend products and offer a broader offering in a market that changes rapidly between seasons. Asphalt is yielding improved margins to the tune of $5 million plus per year, which as a singular item isn’t a game-changing scale, but represents a great example of the type of continuous optimizations that add up as we deploy the strength of our product diversity, innovative mindset and commercial excellence engine across our business.

Next, the cost and reliability initiatives rolled out to begin this year continue to track ahead of plan. Company-wide, our operating costs have been reduced $42 million through the first half of the year versus the first half of last year despite a $7 million increase in the cost of natural gas and electricity, our largest variable expenses. Further, through the halfway point, company-wide production has slightly increased year-over-year despite the full month turnaround at our largest plant. I want to thank our teams on the ground who are leading these efforts and continue to deliver on the challenge to fortify our operation. Flexibility and customer centricity don’t have to come at the expense of efficiency and reliability. We can be both and the 1,000-plus men and women in our operations team are proving that daily.

We believe more possible when it comes to operational excellence, but the team is strong out of the gate, and we look forward to building on the successes thus far. Let’s turn to Slide 4 and talk more about the recent developments at Montana/Renewables as the second quarter was a busy one on the regulatory front. While the Renewable Diesel industry saw its lowest quarterly index margin to date, Montana/Renewables was able to generate a positive $8.3 million of adjusted EBITDA with tax attributes. Our ability to remain positive in this brutal market is a function of our advantaged feed flexibility, leading SAF position, ultra- competitive costs and the highest throughput volumes we’ve achieved yet. More simply, Montana/Renewables has firmly established itself as one of the most competitively advantaged producers in the space.

Dave will take you through these quarterly results shortly. But before that, I’d like to take a moment to hit on the continued strategic progress we’re making around our streamlined MaxSAF 150 project and the regulatory outlook, which came more clearly into focus in the second quarter. With the advantaged operational and commercial position of Montana/Renewables proven out, the remaining critical steps prior to potential monetization are margin recovery, which requires regulatory clarity and taking the next step in our SAF leadership journey. Starting with our MaxSAF 150 project, we remain on track to start up in the first half of 2026. When we expect to generate 120 million to 150 million annual gallons of SAF for a capital cost of $20 million to $30 million.

With the purchase order for the catalyst placed and engineering underway, we’re excited for this next milestone, and we’ve begun the SAF marketing cycle. Earlier in the quarter, there was plenty of speculation around SAF demand as the big bill legislation was negotiated, and we saw a temporary pause as market participants awaited the legislation. With that behind us, conversations are now feeling more normal. As we’ve discussed in the past, the SAF market is close to balance now, and the world is gearing up for the next step in mandated demand that we’ll see in international markets in January, and voluntary demand continues to feel robust. We don’t want to do a public play-by-play of each potential contract we’re negotiating. But what I can report is that we have active conversations regarding more potential volume than our increased supply can meet.

We continue to see SAF premiums in the previously reported $1 to $2 per gallon over renewable diesel range, and our customer slate is very likely to include a diversified portfolio, including large middle market aviation fuelers as we’ve had historically, direct airline sales, both large and regional and even some separated direct sales of Scope 3 and Scope 1 credits. As we’ve done with renewable diesel, our SAF portfolio targets a diversified set of geographies, both in the U.S. and Canada, where we can capture maximum value from our location. On the renewable diesel front, we continue to be bullish around the return of industry margins, which are temporarily paused as the industry awaits the finalization of the RVO, clarity on small refinery exemptions and choose through the excess RINs that were created by imports last year, while the blenders tax credit was still in place.

At current margin levels, some of the top players in the industry have reported rate reductions, which tells you empirically what you need to know about the current margin environment being unsustainable. At Montana/Renewables, we continue to run at full rates as the incremental gallon remains positive, but there’s not much room to spare at current margin levels, and we’ll continue to make monthly run decisions based on near-term economic signals we receive from the market. As we know, renewable diesel margins are largely a function of regulatory outlook. And while not perfect, the fundamental drivers became more clear during the quarter. I’m not sure whether or not it’s gotten easier to predict and we’ll see major margin reversal this year or when the new RVO steps up in January and the carry-forward RINs from 2024 are eliminated, but the regulatory actions taken thus far are supportive on balance.

Let me highlight a few of these. The first example was the One Big Beautiful Bill Act. The most important element of the bill to our industry was the extension of the PTC, highlighting that biofuels continue to receive bipartisan support. Of the roughly 20 tax credits established in the 2022 IRA legislation, nearly half were cut or reduced in a new bill. However, the 45Z credit impacting us not only remained intact but was extended through 2029, demonstrating the importance of growth in this space to the ag community, the energy transition and with nearly 7 billion gallons of domestic feedstock produced annually, a meaningful and growing component of American energy dominance. This extension through 2029 will mark 25 years of a blenders tax credit or production tax credit for biomass-based diesel.

Next in the bill, the 45Z credit is transferable. This is important to Montana/Renewables as we’re not yet able to use the full credit to offset taxable income in these early days, and the credit is a critical part of our margin stack. In fact, we have over $50 million worth of PTCs built up on our balance sheet through the first half of the year as the market was waiting for the bill to be finalized to act. Upon completion, the market has picked back up. In fact, we just signed a term sheet on about half of our credits, and we look forward to completing the monetization of these and the rest of the credit portfolio in short order. Also important was the continued language that imported overseas product and feed won’t qualify for the producer’s tax credit.

This supports domestic ag and highlights the administration’s focus on American energy dominance and independence. We estimate roughly 1 billion gallons of imports drove surplus and D4 RINs last year, and that surplus has been carried forward this year. But going forward, foreign production will not be incentivized to be dumped here again. One regrettable component of the bill was the SAF PTC, whose formula is now equal to the renewable diesel PTC formula. Whereas previously, SAF generated a larger PTC than renewable diesel. It’s now the same. For Montana/Renewables, this means the value of the PTC associated with our SAF production will be reduced by approximately $0.40 to $0.50 per gallon at our current carbon intensity. While we do expect that this will influence the SAF premium, we continue to see strong premiums to renewable diesel in the marketplace, which remain within our historically discussed $1 to $2 per gallon range.

Interestingly, the changes to tax credits for SAF may also have the unintended consequence of reducing future supply in a market which looks solidly at a deficit as global mandates ramp up. Next, let’s switch from the One Big Beautiful Bill Act to the renewable volume obligation, where we received the first insights into the 2026 RVO from the Trump era. I’ll start by saying the new administration at the EPA inherited a real mess between the 6 year backlog of unresolved SREs combined with a 2023 to 2025 RVO that’s decimating the biodiesel industry. After some initial confusion around the demand generated by the RVO proposal, most now expect the proposed RVO would equate to roughly 4.5 billion gallons of biomass-based diesel. This is a nice 30% increase from the approximately 3.5 billion gallon D4 RVO that exists today and industry margins should react positively as industry capacity utilization increases.

We see the impact of these levels to the chart on the right, where we combine the D4 RVO just discussed with roughly 1 billion gallons of additional D4 demand that’s required to meet the D6 RIN shortage to arrive at the total expected biomass-based diesel demand, both at today’s and the proposed levels. What this chart does not include is the 1 year carry-forward RINs from the 2024 surplus, which practically offset significant 2025 demand. The massive shutdowns we’ve seen in biodiesel and even some renewable diesel are a direct result of the 2023 to 2025 RVO being set too low. That all being said, we believe the new RVO should be much higher. North America is capable of producing roughly 7 billion gallons of biomass-based diesel feedstocks.

And including biodiesel production, there’s at least 7 billion gallons of industry capacity to process this domestic feed into product. This idea that 1 billion gallons of foreign feed will be required to generate the mandated RIN count is not supported by the data. In fact, we’re exporting nearly 1 billion gallons of soybean oil alone. In addition to that, and specifically to China exports, we’re exporting over 22 million tons of soybeans to get crushed into well over 1 billion gallons of potential feed offshore. We have enough feed right here at home to dramatically increase the supply to our growing industry today and in addition, for future crush investment here in the U.S. that will serve a future step up. The mandate can be increased to match capacity as we’ve done historically every year until the 2023 set rule under the Biden administration.

The open comment period on the Trump EPA set 2 rule closes today, and we hope the D4 RVO level will be revisited to incentivize the continued growth of American energy, American jobs and the American farmer. With that, I’ll turn the call over to David to take us into the quarterly results. David?

David A. Lunin: Thanks, Todd. It’s great to see the progress in Montana on all fronts as monetization of that asset continues to be the final step in our deleveraging strategy. Before I go through each of the segments, I’d like to highlight some recent activity as our deleveraging and maturity management strategy continues to unfold. Last week, we announced a refresh of our Shreveport terminal assets financing, which was a nice optimizer within our broader plan. We had previously sold these assets to Stonebriar for $70 million back in 2021. And given the improvements in Shreveport production, the truck rack and related assets value increased to $120 million. Instead of repurchasing the asset in 1.5 years, we were able to add $80 million of new cash to the existing $40 million of principal and call another $80 million of our 2026 notes, reducing the outstanding balance to a manageable $124 million.

Add this to the accretive Royal Purple industrial asset monetization and deleveraging that occurred earlier this year, and we now will have called $230 million of the 2026 notes in the last few months. With our revolver capacity and approximately $50 million to $60 million of cash flow expected in the restricted group through the rest of the year, we shift our near-term strategic focus to broader deleveraging and managing the 2027 notes. With improving cash flows from the business and the renewable regulatory outlook solidifying, we remain confident in our plan to reach our ultimate goal of $800 million of restricted group debt. Further, the broader strategic activity that we’ve mentioned previously continues to progress well, and we’ll discuss that more at an appropriate time.

Turning to Slide 6. Our Specialty Products & Solutions segment generated $66.8 million of adjusted EBITDA during the quarter. We continue to see strong performance, particularly among our specialty product lines, reflecting our commercial excellence program. In fact, this was the third consecutive quarter that our specialty products posted sales volume exceeding 20,000 barrels per day, reflecting our customer and application diversity and improved reliability. Further, we saw margins in our specialty products increased to more than $66 per barrel. These accomplishments made despite a full month turnaround at Shreveport in June. The team also successfully managed through a major disruption in service from a key rail provider that had issues across their network.

The rail service provider is a major transporter for our network and Calumet incurred meaningful costs as the team went above and beyond to arrange alternative logistics to keep our customers supplied. Thankfully, the railway is reporting that the worst of that is now behind us, and we’re seeing service normalize. Regardless, Calumet will always do everything we can to deliver service to our valued customers. Looking ahead, we continue to expect to operate at mid-cycle margins even amidst an industry backdrop that is below mid-cycle, highlighting our commercial advantage. Our operational improvement trend also continued in the second quarter as we reduced our fixed cost by approximately $10 million in the first half of 2025 compared to the prior year.

Interestingly, strong operations not only increase volume and reduces costs, but increases margin as well as it allows our commercial team to place more volume to secure contracted homes at higher margins rather than keeping volume available for the spot market. With the downtime associated with the turnaround, our quarterly results included only $11 million of total restricted group adjusted EBITDA plus tax attributes in June. The plant is now back online and successfully generating full revenue. Looking ahead, we expect and already have begun to see the unwind of approximately $30 million in the third quarter of 2025 from working capital build associated with the turnaround as we have no more turnarounds planned for the rest of the year and are running at full rates.

Finally, as tariffs have been topical again, I wanted to remind our shareholders that we do not believe they are impactful to our specialties business considering our U.S.-based manufacturing and feedstock supply footprint, customer base product diversity and the fact that nearly all of our sales in feedstock are domestic or protected by USMCA. Moving to Slide 7 and our Performance Brands segment. We are now firmly in the third year of our revised strategy that leverages commercial excellence and integration optionality across our specialties business. We posted strong quarterly results of $13.5 million, reflecting continued volume growth and ongoing commercial improvements in the business. As a reminder, we completed the sale of the industrial portion of the Royal Purple business, and this is the first quarterly period to not include Royal Purple industrial results following the divestiture.

Our second quarter results reflected strong volumes and margins across the business, particularly for our TruFuel brand. Moving to Slide 8. Our Montana/Renewables segment adjusted with tax attributes generated $16.3 million in the second quarter compared to $8.7 million in the prior year period. Montana/Renewables specifically generated adjusted EBITDA with tax attributes of $8.3 million, making the 87% attributable portion to Calumet worth $7.2 million. Montana/Renewables continued ability to generate positive EBITDA with tax attributes even in the lowest industry margin we’ve ever seen is representative of our competitive position and reflects our unique assets, logistical advantage and strong customer relationships. In addition, as we previously disclosed, we continue to expect to monetize the value of the production tax credits.

And as Todd mentioned earlier, our monetization efforts are in advanced stages of discussion. Despite the worst margin environment, the primary driver of the year-over-year improvement in this segment continues to be with the tremendous cost savings we’ve made in the business and improvements in operations. You can see in the lower right-hand side of the renewable slide, we have reduced op costs and SG&A down well north of $1 a gallon to current levels. Focusing just on operating costs, we recorded $0.43 a gallon. This represents our seventh consecutive quarter of operational cost improvement trend, excluding the turnaround in the fourth quarter of 2024. When factoring in our lean SG&A position, we posted operating plus SG&A costs of approximately $0.51 per gallon, also a record low for the business and proves our low-cost position in the industry.

Our plans also remain on track for our MaxSAF expansion as we expect to bring on 120 million to 150 million gallons of annual SAF production in the second quarter of 2026 for an investment of $20 million to $30 million. So there is no change to what [ prequel ] was previously announced, and we’re excited to continue this exciting step. On the Montana Asphalt side, the business saw a $6.5 million year-over-year improvement. The same discipline and rigor that we’ve deployed with MRLs is also being applied in the asphalt side on costs and is generating these improved results. Thank you for your time today. With a strong quarter, meaningful progress on the regulatory front, thoughtful maturity management and a clear expectation of meaningful free cash flow generation in the business, we look forward to the major value-creating opportunities that rest ahead for our shareholders.

With that, I’ll turn the call back to the operator for questions.

Operator: [Operator Instructions] The first question comes from Alexa Petrick with Goldman Sachs.

Alexa Petrick: First one, just wanted to ask on renewable diesel. We appreciate we’re in a challenging macro right now, just given the uncertain regulatory environment. But would love your updated thoughts on what mid-cycle earnings looks like for the business? And then what do we need to see in the industry to get to more normalized earnings?

Louis Todd Borgmann: Alexa, it’s Todd. Good question. Like you said, it’s obviously a tough environment out there right now. And we think the driver of that is really just the market waiting for news on the permanent RVO and the SRE to respond plus working through that backlog of RINs that was carried forward from 2024. So I’d point to those as kind of the key drivers for recovery. We provide that chart every quarter that talks about the supply stack, the biomass-based diesel supply stack. And basically, what we see is at the proposed RVO levels, you should see D4 demand of basically 5.5 billion gallons or so, which would suggest that you need a good chunk of biodiesel to run and meet that demand. That puts you in that $1.50 to $2 a gallon index margin range.

We’re ways away from that right now. But really, that’s the range that we’ve seen throughout history up until kind of the 2023 RVO change things. So at those levels, I think we put some information out in the past that says at $1.50 a gallon index margin, Montana/Renewables should be making around $140 million, $150 million a year of adjusted EBITDA with tax attributes. So I kind of point to that. And then obviously, if you increase back up to the historic $2 a gallon level, you’re meaningfully higher than that. That’s at our current yields. The other thing I’d point out is adding the SAF flexibility that we are really provides a meaningful kick to those margin numbers. When you’re talking an extra $1 to $2 a gallon premium on an incremental 90 million to 100 million gallons or 120 million gallons of SAF, it’s a pretty meaningful bump in margin, which is why we’re so excited to be able to streamline this MaxSAF 150 project and move that forward.

You talk about $1 a gallon plus on 100 million gallons. Obviously, that’s the math. And we stack that on top of the core renewable diesel EBITDA that we just talked about.

Alexa Petrick: Okay. That’s great. And then my follow-up, just on the balance sheet. It’s nice to see the partial redemption of the ’26 notes. Can you talk about the path to further debt paydown? And then particularly, what considerations do you guys think about for potential future divestitures?

Louis Todd Borgmann: Yes. Good question. The — like David said, there’s not too much remaining on the 2026 is after we called the $230 million so far this year. So really nice progress on that front. I think if you look at that, you could say we have enough availability in free cash flow in the second half of the year to manage that in itself. So we kind of look forward and say what next on the 2027. We’ve talked about potential strategic asset sales. I don’t want to get too far into that. But I can tell you that’s certainly an option. We’re expecting meaningful cash flow next year and throughout the rest of this year. And then also, you have the Montana/Renewables monetization, which we continue to expect is the ultimate step to reach our final deleveraging target of $800 million.

So those are kind of the 3, I’d say, large steps. There is other things that can be done as well and kind of the — just the maturity management mode. But as far as ultimate deleveraging, that’s really what we’re looking at.

Operator: The next question comes from Conor Fitzpatrick with Bank of America.

Conor James Fitzpatrick: This was another quarter where OpEx per gallon was reduced in the renewables business. Cost reductions have had momentum for a while now. But I think it would help us to explain the types of improvements and changes you’ve made in your operations year-to-date that are driving these cost reductions.

Louis Todd Borgmann: Conor, it’s Todd again. Thanks for the question. And you’re right. It’s fundamental really to our success, particularly in this tight market, what we’ve been able to do on costs and really establish ourselves as one of the cost leaders in the space, which stacked on top of our geographic advantage and feedstock flexibility and ability to generate SAF, we’re quite excited about. Specifically, I’d say there are — the primary improvement that we’ve made on cost is real minimization of water. We’ve spent a lot of time and effort understanding water treatment, reducing the amount of water we have to treat in general. That’s been a major step down. And then with smaller amounts, you can obviously treat it more efficiently as well.

In fact, we put out something not too long ago that said as part of the expansion in the future, we — highlighting that on treatment — on-site treatment of water is a piece of that plan, which hasn’t changed. That’s always been the case. So water treatment is the primary improvement. We’ve also just got more efficient with the operation. You learn a lot, and we came up the learning scale really quickly in Montana over the past couple of years. But we had a number of folks on site, third-party contractors, et cetera, to just help us with the learning curve over the last year. And we’ve had a meaningful contractor reduction on site this year. And obviously, in the numbers — the production numbers and the cost numbers, we see that we didn’t need them.

So the teams just done a really spectacular job of getting up to speed, familiarizing themselves with the assets and keeping costs down.

Conor James Fitzpatrick: Great. That’s clear. And then as a follow-up, it looks like there’s a few regions to play for SAF in the United States. The West Coast has LCFS programs and transpacific voluntary and mandatory markets. The Gulf Coast has voluntary and mandatory markets in Europe. And there are several U.S. Midwest states that have purchasers or producers tax credits. And then SAF prices nationally trade at a premium from incremental voluntary demand versus RD and conventional jet. So how would you characterize the attractiveness of the different regions from where you sit? And do you think the proximity to the Midwest will win out versus other regions over time or at least provide a more stable end market?

Louis Todd Borgmann: Yes, great question. The Midwest is a really interesting market just because of the state tax credit, right? So I think you used the word just stability or kind of stabilize the whole outlook. That tax credit goes a long way to do that. So yes, that will be a piece of the solution. California is obviously a big piece as well. Oregon, Washington, we’ve talked about all of these areas. Honestly, just like renewable diesel, we’re pretty flexible on our output, and we take it to whatever areas we’re geographically advantaged in. That’s what we’re doing now with our partners at Shell, and that’s what we expect to do in the future as we add to the portfolio that we’re building on the marketing side. The other thing I wouldn’t forget about is Canada.

We’re right on the border there, and there’s some real ability to partner with the right people in Canada, blend our product and service that market. And there’s a pretty meaningful SAF premium still in Canada. So like always, at Montana/Renewables, the key to our advantage or one of the keys to our advantage is really that end market flexibility. And sitting right there on the BNSF, we can go east to Minnesota and Illinois. We can go west to California, Washington, Oregon, and we can even truck north to Canada. So very flexible, and I’d expect all of those to be part of the solution.

Operator: The next question comes from Gregg Brody with Bank of America.

Gregg William Brody: Nice quarter. It’s nice to see the operations coming together in Specialty. I was — you gave a couple of numbers there on the restricted group that I just wanted to run through to make sure that’s clear. So I think you said the second half of ’25, you expect $50 million to $60 million of cash flow. And then you also mentioned the unwind of some working capital of $35 million. Is that part of that number? Or is that in addition to that?

David A. Lunin: Yes. It’s part of that number. So we’re already seeing some of that unwind from the working capital, just related to the turnaround and timing of building inventory in advance.

Gregg William Brody: Got it. And then you suggested that you could deal with the remaining $125 million of the [ 26’s ] this year. So the $50 million to $60 million is from restricted group. Should we expect cash from anything from renewable diesel business to be sent out? Or is the rest going to be solved for with possibly strategic actions?

Louis Todd Borgmann: It’s a good question. It’s possible to have cash out of Montana/Renewables. Honestly, the way we plan for it is just the fully controllable in today’s market. So the way we plan for things is just what can we generate in the restricted group. So yes, to your point, you’ve got the $50 million, $60 million of cash flow. I think you said is that — all in the business — there will be additional to that from the $35 million of capital unwind. So I don’t want you to think that there’s only $15 million of free cash flow generated in the core business in the second half plus that $35 million of working capital unwind, right? So it’s $50 million plus the rest. So we are expecting more cash flow in the second half. We do expect some strategic activity to help with that. But I’d also just point to our general liquidity and revolver balance for a very small amount.

Gregg William Brody: Okay. And then just shifting to the PTC monetization. I think you said you had a term sheet for about half of it. Sort of 2 questions there. I think you had mentioned a discount the way to think about it, if I’m remembering like 5% to 7% versus what the book value is? And then just remind us if that’s — if I’m remembering that right, and if that’s sort of a good way to think about it? And then second part of that is, when do you think you’ll address this — the other half of the PTCs? And just in general, based on the way the market is coming together, should we expect that to be a quarterly — to be done quarterly ratably with what your — the actual income is?

Louis Todd Borgmann: Yes. Big Beautiful Bill was signed and provided a little bit more clarity around these PTCs. So we do expect to sell them all in the near future. And after we clear that backlog, yes, we expect it to be a quarterly transaction.

Gregg William Brody: Got it. And one piece in for me. So I was wondering if you have your liquidity as of today, just — or basically what’s on the revolver?

David A. Lunin: It’s just about $200 million.

Operator: The next question comes from Amit Dayal with H.C. Wainwright.

Amit Dayal: Pretty solid execution despite some — and on that front, Todd, are there any particular catalysts we should be looking for with respect to any remaining sort of macro overhangs for you to start hitting your stride, especially with respect to Montana/Renewables. I mean it looks like on the cost side, you’ve already done pretty well in terms of bringing costs down. If some margin improvement starts showing up, I mean, it looks like there’s a lot of operating leverage you could start generating. So any color on maybe this topic would be helpful.

Louis Todd Borgmann: Yes. I think that’s the million-dollar question you’ve nailed it is, is when do we see the reversal in margins. Very comfortable and confident that with the regulatory actions we’ve seen here in the second quarter that it’s a matter of when, not if on these, right? We talked earlier in Q&A about a 5.5 billion gallon RVO without an overhang, you’re at substantially better volumes than prices — margins than we are today just to stay compliant. So we’re very bullish to long-term outlook. I think the big question is just the overhang around when is that RVO going to be finalized. A lot of rumors still flowing around the SREs and how that interacts with the RVO, if at all. And then the market just has to work through this backlog.

There is a year’s worth of overproduction from 2024 RINs that have been carried into 2025. So the market is not acting like it would in a normal environment. When it has those RINs that it has to eat through in the current year, I’ll say just expire, that essentially becomes part of the balance and the market doesn’t have to respond to just normal fundamentals like it would. But that all ends at the end of this year when we step into 2026, those old RINs can’t be carried forward again, and we see the step-up in RVO. So I think the big question in our mind is, do we see margin recovery before that as people get more comfortable with how strong the outlook looks for 2026 and starts to ramp up production or RIN prices start to respond expecting that there’s going to be such an increase in 2026.

So that’s what our eyes are on. I think that’s what most folks in the industry are tracking as well. And long-term, we think the changes that occurred in Q2 are quite bullish for the space. So looking forward to getting there.

Amit Dayal: Okay. And just on the Montana/Renewables monetization, it’s — I mean, it looks like it’s still on the table. But from a timeline perspective, should we expect any movement on that front in 2026? Or is this a little bit more sort of a future type event for the company now?

Louis Todd Borgmann: Yes, I don’t think 2026 should be thought of as off the table at all. When we rewind the clock a little bit and we say, what do we have to do at Montana/Renewables, we need to get the DOE loan that’s done. We needed to prove out our operation, commercial position that’s done. We needed to demonstrate our cost advantage, that’s done. Right now, we’re ramping up kind of the faster, cheaper first step into MaxSAF. We think that’s a really nice value upside for potential buyers. And then the last thing you need that’s a little bit outside of our control is really just demonstrated margins, which we kind of just talked about. So we think that you get a little bit of margin improvement here late this year, early into next year have a quarter or 2 of really strong earnings, and it’s an active conversation. I don’t want to predict exactly when that happens and the like. But I wouldn’t say 2026 is off the table by any stretch.

Operator: The next question comes from Jason Gabelman with TD Cowen.

Jason Daniel Gabelman: I wanted to get your views on the RVO proposal and specifically the part that talks about half RIN generation for imported feed or products. And I’m wondering if you have a sense of what that does to the market. Does that essentially just double the value for RINs? Or is there some offset on feedstock costs? And do you think that is likely to be included in the final RVO?

Louis Todd Borgmann: Jason, it’s Todd. Great question. I wish Bruce is here to help with it a little bit, but he’ll be back this afternoon and hopefully, by the time we get to connect a little later to chime in more. But the whole half RIN concept is an interesting one. I’d say the most important thing is we don’t see that imported feed is needed to basically meet the RVO as it is. 4.5 billion gallons of domestic feed is what it calls for in the proposal. And we’re generating almost 7 billion gallons of domestic feed in North America now. So big macro, I would start there and say, I don’t know how much imported feed is even in the mix. Now if you go down a little bit, there are certain plants that just logistically would have a really hard time potentially bringing in or would need to just work on their rail, et cetera, to do more around domestic.

And I think that’s something that can be done in time. But they may be in the mix for a little bit. But big picture, we don’t think that imported feed is needed to meet the proposed RVO. If it is temporary, then I think exactly what you said is right. You would look at our supply stack and you would say those folks that are running on imported feed, the RINs basically would have to cover that price. The RIN price in order for them to run and meet the D4 requirement would have to adjust so that at half RIN value, they’d be incentivized to do that. So either the price of the imported feed would have to go down. That’s not going to happen because it’s a global market that has a floor price to it or the price of RINs would have to react. So we see that as a potential.

And I guess it’s an upside possibility. But more practically, I just don’t see that imported feed will be needed to meet the proposed RVO. And we’re hoping that as the group there, the EPA studies deeper into it and closes the comment period today that they’ll come to the same conclusion and increase it.

Jason Daniel Gabelman: Got it. Yes, that’s great color. And my follow-up is just a clarification on the PTC monetizations. And I know you talked about signing some term sheets. Is there anything on regulatory front that needs to be finalized in order to convert those term sheets into final deals? Or is it just normal — more normal course working through the paperwork?

Louis Todd Borgmann: No, I think just normal course working through the paperwork. We’re in that process now. We haven’t come across anything where anybody said that, hey, we need to slow down. So I think it’s just the normal process. It did get delayed a little bit while rumors were swirling around the PTC and the Big Beautiful Bill kind of negotiation. But now that’s behind us, it looks like game on and return to normal. So we’re not seeing anything that would stand in the way. We’re seeing a lot of activity there and expect to have these things sold by the next time we’re talking.

Operator: This concludes our question-and-answer session. I would like to turn the conference back over to John Kompa for closing remarks.

John Kompa: Thank you, Steve. On behalf of Todd and the entire management team, I’d like to thank our shareholders for joining our call today and your continued support. Have a great rest of the day. Thank you.

Operator: Thank you. The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.