Title

Presentation

Calumet Specialty Products Partners, L.P. beats earnings expectations. Reported EPS is $-0.47, expectations were $-1.06.

Operator: Good morning, and welcome to the Calumet, Inc. Fourth Quarter and Full Year 2024 Results Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. 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, David. Good morning, everyone. Thank you for joining our call today. With me on today’s call are Todd Borgmann, CEO, David Lunin, EVP and Chief Financial Officer, Bruce Fleming, EVP, Montana Renewables and Corporate Development, and Scott Obermeier, EVP Specialists. 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.

Todd Borgmann: Thanks, John, and thank you for joining the full year 2024 earnings call. This past year has been the company’s most active and strategically imperative time period as we’ve executed our strategy by converting our company structure from a master limited partnership to a C-Corp, funding the DOE loan across two administrations, proving out and derisking the operations of Montana Renewables, and widening our competitive moat in the specialties business. With the new company structure and our cash debt service reduced by roughly one-third, we pivot forward to a new time in our company. With two fully operating competitively advanced businesses focused on the fundamentals of deleveraging our balance sheet and growing our cash flow.

The foundation that is now in store provides the ability to pursue these two objectives simultaneously. And from where we stand today, we see tremendous value in achieving these concurrent objectives. Turning to slide 4. I’ll note this morning, we announced the sale of our Royal Purple Industrial business for $110 million. And this accretive deal accomplishes the joint objectives we just laid out by reducing our debt and fortifying our specialty strategy. The industrial Royal Purple business is a great business with fabulous people, but as an ultra-premium synthetic niche, it isn’t a business that is force multiplied by Calumet’s extensive specialties network and thus the logical step to monetize. With this new cash delever and $80 million of annual cash savings starting last week as our MRL financings were paid, we’re excited about the start in 2025.

Now let’s flip to slide 5, and I’ll take a few moments to hit on some of the foundational milestones achieved over the past 12 months. Let’s start today’s webcast with day-to-day business execution. Commodity markets will fluctuate, volatility for event-based trading will revert to fundamentals and with the DOE loan behind us, it’s reducing our leverage and continued demonstration of earnings growth that will increase the value of our company. We continue to see immense value from advancing our commercial and operational excellence objectives and execution in these areas, particularly in safety and reliability, improved noticeably. Commercial growth within our specialties business has been a meaningful competitive moat at Calumet for decades, and it has widened substantially over the past few years.

In 2024, our commercial team sold the most volume that we’ve seen through our existing portfolio. Our specialty products and solutions teams grew volume 7% year-over-year or roughly 1.4 million barrels. You might remember that we integrated our performance brands segment and SPS segment into one specialties business two years ago as we believe there were synergies here, both in commercial optionality from integration and in leveraging our broader specialties commercial approach. In 2024, Performance Brands volumes grew 22% and delivered $51 million of adjusted EBITDA after adjusting out insurance proceeds. Operations is an area that we haven’t spent as much time on publicly as some others, but it receives an enormous amount of time here internally, and it’s a core enabler of our high-touch commercial approach.

Our operations are flexible and integrated and we do a lot of things either as well to satisfy our customers. In 2024, operations also got safer and more reliable, while simultaneously reducing our operational costs and capital expenses. Last year, our company saw its lowest number of safety recoverable with a TRIR of 0.47. Our number one priority every day here at Calumet is that everyone who shows up to work goes home safely and last year’s major improvement is a credit to the team’s efforts. Good safety performance typically goes hand in hand with strong operations, and we saw that in 2024. Going back three years, we announced a capital program aimed at Northwest Louisiana, which was matched for the full court press on adding critical talent.

We’re seeing the benefits of that at Shreveport ran exceptionally well in the second half of last year setting specialty production records in both the third quarter and the fourth quarter. The story is not just a Shreveport now. For example, our Princeton facility operated exceptionally and could have sold even more as demand for transformer oil source with global power demand. While volumes increased, our specialty operations team was able to drive fixed cost down. And for the 2024 full year, our out costs were more than $1 a barrel less than prior year on 60,000 barrels a day plus that’s substantial improvement. We’re committed to continuing the progress, and we have taken the next level of cost reduction actions that will reduce combined fixed cost in our specialty business by another $20 million compared to 2024.

Next, let’s talk about Montana Renewables operations. The improvement there was both expected and dramatic given the early-stage nature of this business. And while I take a few more months than we originally planned, our Montana Renewables ops team ended 2024 by achieving the targets laid out a year ago. We began the year operating with a cost structure of about $1.30 a gallon, which improved ratably as our team ran up the learning curve on renewable feeds learn to optimize our pre-treatment unit and reduce our — water output by over 70%. In December, we reached our target cost level of $0.70 per gallon. To be clear, the $0.70 a gallon is fully loaded with SG&A. Our insurance commercial team overhead and all costs to run Montana Renewables are in that $0.70.

On a site op cost, we operate in the mid $0.40 per gallon, and we expect that number will be reduced to $0.40 a gallon this year. As we scale up our facility, these unit costs will decrease further and we’ll compare with the larger plants in industry. Further on operations, Mountain Renewables reliability improved substantially throughout the years and worked out the case. We met our 30 million gallon annual run rate for SAP in the third quarter and have demonstrated a capacity 60% higher than that. The combination of our competitive cost structure, unique logistical advantage and our SAF early mover advantage, positioned Montana Renewables with a lasting competitive edge. And as the planting SAF capacity grow, we expect this advantage to grow alongside.

Now I’ll turn the call over to David, and then I’ll come back and close with some more color on our renewable diesel and SAF markets and our 2025 key objectives.

David Lunin: Thanks, Todd. I’ll review our financials by segment and our efforts over the past year have really simplified and derisked our business while providing an exceptional growth platform going forward. Turning to Slide 6. Our Specialty Products segment generated $43.4 million of adjusted EBITDA during the quarter and $193.6 million for the full year. We continue to see strong volumes, particularly among our more specialty products lines, reflecting our commercial excellence programs and improving operational reliability. Our commercial excellence programs remain focused on aligning sales, procurement and operations to maximize the value of our products and place them into the right markets. Specialty margins were in line with our improved mid-cycle expectation of $60 per barrel, reflecting our customer and application diversity as well as the incremental value earned through our integrated network.

Year-over-year results were hampered by a weakened commodity environment driving the decline in the Gold Coast industry fuel margins. We’ve seen some improvement already in the first quarter of 2025, which is encouraging. Offsetting the weakened commodity environment was strong sales volume performance, which came in a more challenging market environment than we have seen in the past few years as demand softened and global inventories levels increased. The last time we saw a commodity price environment like the past years was over five years ago and specialty margins were approximately $20 a barrel lower in that environment. Many may remember that at the peak of margins a little over a year ago, we said that half of the improvement was market related and half was our commercial excellence focus, and we saw that play out in 2024.

Although, keeping this margin improvement in a tough market is an accomplishment, but also on placing more volume. Looking ahead, we expect to continue to produce specialty margins over $60 a barrel in our specialty products and Solutions segment, even in tougher current market conditions. Moving to Slide 7 and our Performance Brands segment. We posted strong quarterly results of $16.3 million, reflecting a 15% period-over-period volume growth and continued commercial improvement in the business. For the year, we produced $57.4 million in adjusted EBITDA. 2024 was the second year of our transformation work in this segment based on a fully integrated specialty strategy and our commercial excellence programs. We are seeing a positive result as volume rose 22% in 2024 versus 2023.

We saw some insurance proceeds throughout the year that contributed a few million to our full year results. And the insurance adjusted EBITDA number is roughly $52 million, and we expect continued growth in 2025 as we are beginning some supply chain and operational efficiency programs in addition to our commercial framework. Earlier in the call, Todd discussed the sale of our industrial portion of Royal Purple. This sale was completed at a roughly 10 times EBITDA multiple, and we believe through operational and supply chain efficiencies, this transaction unleashes will be able to recapture the majority of the EBITDA we’ve sold over the next two years. On Slide 8, our Montana/Renewables segment, generated $10.9 million of adjusted EBITDA in the fourth quarter compared to a negative $25.8 million in the prior year period and $16.7 million for the full year.

Our results in the quarter reflected a strategically planned turnaround that was successfully completed on time and on budget in November. Our renewables business drove adjusted EBITDA of $18.2 million attributable to our proportional 86% ownership in the business in the fourth quarter, or $21.2 million on a 100% basis. The fourth quarter was unique for a couple of reasons. First, results included $20 million of insurance proceeds from the downtime related to our cracked steam drum experienced last year. Second, the turnaround meant we were down essentially all of November, so we lost approximately one-third of our production during the quarter. We also intentionally did not sell any SAF in December as the change in regulation at the end of the year meant that SAF shipped in December and not received until January would not be eligible for the environmental credit.

Now that the BTC PTC changeover has occurred, January 2025 SAF shipments have resumed normally. Finally, the industry was going through a change as imports were back out of the market as those imports are no longer eligible for tax credits this year. Over time, the switch to PTC from BTC will reward feedstock flexibility, end market diversity and end product flexibility, all of which are the core of Montano Renewables competitive differentiation. In the meantime, the industry awaits clarity from the administration on final rules to be implemented. As I reflect on the year, despite challenging market conditions, we’ve harvested our geographic and cost advantage and proven our ability to steadily post positive EBITDA. In this trough industry environment, we steadily drove our cost down from $1.30 a gallon in the beginning of 2024 to the point where our costs have firmly stabilized at $0.70 a gallon, which we expect to maintain going forward in 2025.

On the Montana asphalt side, the business continued to reflect significant commodity headwinds. The WCS differential in Rocky Mountain fuel cracks softened during Q4 2024, reflecting both asphalt and fuels regional seasonality on top of structural softer fuel cracks. We continue to carefully manage inventories as we move through the winter season as commodity headwinds carried over into 2025 beyond normal seasonal weakness. Before I turn things back over to Todd, I’d like to talk about capital spending. Our 2024 company-wide capital spend was $90 million, including $28 million at Montana Renewables. This was lower than the recent history as the Shreveport capital initiative wound down and Montana Renewables reached normal operations. As we look forward to 2025, we expect capital spend to be in the $60 million to $90 million for the entire company before accounting for spend related to MaxSAF expansion.

We’ve already disclosed that MaxSAF CapEx in 2025 is expected to be $40 million to $60 million, with 45% of that to be funded by Montana Renewables operating cash flow and the other 55% to be drawn down from the DOE loan. Also, as we look to 2025, we’re considering changes to how we report adjusted EBITDA to better reflect true operations of our business. One change will be including an add-back related to our RINs incurrence. We continue to prevail in the courts successfully in both the Fifth Circuit and DC circuit regarding our small refinery exemption. The treatment — the current treatment has been a confusing point for investors and showing the cash flow better and showing the adjusted cash flow better reflects the generation capability of the business.

Similarly, the changeover from BTC to PTC has slightly different treatment. It’s our intention to show in 2025 the value of the PTC generation adjusted EBITDA, although they will be sold to third parties for cash as we are currently not a cash taxpayer. Turning things back over to Todd.

Todd Borgmann: All right. Thanks, David. Looking ahead to 2025, Calumet’s key value creation priorities, as you’ve heard a few times today, are deleveraging and demonstrating the next level of cash flow generation at Montana Renewables. Both these initiatives were recently catalyzed by the funding of our DOE loan. This was the first DOE loan closed in the new Trump administration and a clear testament to the bipartisan support for our business. Let’s turn to Slide 9 and I’ll remind us of the elements of this transaction. First, a couple of weeks before the funding, Calumet made a cash investment into Montana Renewables to satisfy the DOE’s $150 million equity requirement. When we received the $782 million on February 18, the first thing that was done with the proceeds was repurchasing our assets from Stonebriar and removing the expensive project financing debt that had been put in place back during the construction.

In total, the interest rate on the outgoing instruments, were roughly 13% and they’ve been replaced with 15% — 4.88% paper. Maybe even more importantly, the old project financings required roughly $80 million of annual cash to make principal and interest payments. That’s been reduced to zero under our DOE loan for the next four years, while the MaxSAF project is underway. The next thing we do with the cash at MRL was to repay $188 million of intercompany due to Calumet. This leaves roughly $350 million of intercompany remaining up on Montana Renewables, which will generate cash flow for Calumet in one of two ways. First, approximately $27 million per year of cash interest is expected to be paid from MRL to Calumet on Uner [ph] Company.

In fact, these are the only cash interest payments MRL will have with its new balance sheet. The other potential option is that we have the ability to raise Perry secured debt at Montana Renewables, which could pay down the intercompany more rapidly. The last piece of proceeds was simply leaving the cash on the MRL balance sheet. In total, we have roughly $190 million of cash on hand at Montana Renewables, which funds operations in addition to funding any necessary reserves. Having reduced our annual cash debt charges by roughly a one-third, this transaction greatly increases free cash flow available for both total company deleveraging and investing in our MaxSAF growth project. With an exciting project like this and a high level of interest in underlying renewable diesel and SAF, let’s turn to Slide 10 and review these markets.

First, let’s start with a quick review of the fundamentals of the renewable diesel industry. We’ve discussed this before, but as a quick summary, this graphic uses an assortment of industry data to group the types of producers to create D4 biobased REM and sets them by relative breakeven industry index margin levels. The breakeven relative to the industry index margin, which is soy based, is a function of operating costs, product mix, actual feed slate, yield loss and transportation costs. At the current RBO, which is roughly equivalent to 4.5 billion gallons of annual biomass based diesel, today’s margin setting mechanism would be large biodiesel producers. This group has an estimated average breakeven index margin of roughly $1.50 per gallon.

Thus, if everyone had the same long term expectations, producers with a higher breakeven would be expected to lose money and rationalize production and anyone with a breakeven index margin below $1.50 would earn a profit. However, we saw industry index margins well below the fundamental level throughout most of last year. The reason is that the market had not shut down enough capacity to balance the market and imports were flooding the country to take advantage of the blender’s tax credit. Thus, more than enough D4 RINs were produced to satisfy the RPO requirement, so the price of the D4 RIN did not have to increase to incentivize production. Similarly, with feedstock runs high, the price of the feed did not have to decrease to incentivize production.

These dynamics are changing. At the end of last year, we saw index margins increase as the market knew imports would need to dry up given they don’t qualify for the tax credit in 2025. In fact, the industry index margin ended the year at exactly $1.50 per gallon. However, that quickly, and we believe temporarily reversed in early 2025 as uncertainty exists in a PTC. Many suppliers expect the BTC to come back into play and thus have been less willing to reduce prices as they have inventory room and are willing to bet that a change in the rule while keeping prices high. Also, there was no over production last year, but a little bit of RIN carryover exists. So the RIN price is a temporary shock absorber until fears build out as a carryforward is not enough.

Thus, index margins declined as feedstock prices have not decreased enough yet to offset the difference in $1 gallon BTC and smaller PTC. But last week, things changed when the January RINs data was released, which showed January production of 297 million gallons of biomass-based diesel, which is a 34% decline from the 453 million gallon monthly average of 2024. Further, biodiesel production decreased 63% and reached the lowest levels observed in years and imports were non-existent. Interestingly, on a run rate basis, 297 million monthly gallons will lead the industry nearly 1 billion gallons short of its annual RVO mandate. At these levels, D4 RIN prices would be expected to adjust to carry the margin loan. And we’d expect that as vegetable oil inventories increase where we received clarity around the PTC that we would see feedstock prices contributing to a return to industry index margin level supported by fundamentals.

Next, let’s turn to slide 11 and have a look at the current and expected growth of the SAF market, which is one is somewhat opaque and one that we’re quite excited about. SAF has been supply limited market, which is one of the reasons we have seen a meaningful premium, in addition to the generally favorable credit structure relative to renewable diesel. Historically, most SAF demand has been voluntary demand. In addition to that, we’ve seen global mandates start in 2025. These mandates ramp-up to roughly 2 billion gallons by 2030, which far passes most supply expectations even before considering future mandates under discussion, large airline commitments and otherwise growing voluntary demand. The graphic on this slide conservatively pegs base2024 voluntary demand has remained constant throughout the next six years to illustrate the point that its mandates that will drive this market and voluntary demand is an upside scenario, not the other way around.

That being said, as expected in 2025, the market is more balanced than it has been historically. SAF infrastructure takes time to develop as it grows one airport at a time. So when 400 million gallons of new production comes online, it takes some time for the logistics serving the domestic voluntary demand to ramp up. This is the first year for the new EU and UK volume mandates and they generally match the amount of this new supply, which means the market is essentially balanced. Of course, those mandates increase each year. So without additional projects, a largely balanced market today will develop into a larger shortfall each year. Montana Renewables looks forward to stepping into that drilling deficit as our expansion ramps up controllably.

With a $1 to $2 per gallon SAF premium, an incremental 100 million-plus gallons in 2026, an additional 150 million gallons after that when the full project completes, is a tremendous amount of additional margin, which would sit on top of the renewable diesel fundamentals we just spoke about. With the DOE loan complete and no near-term third-party debt servicing, growth in cash flow directly corresponds to deleveraging. We’re not simply counting on improving margins and future SAF delever. Let’s flip to slide 12, and review our holistic path to restricted deleveraging. Fundamentally, this plan consists of three general areas. First, all free cash flow available to Calumet will be used to pay down debt. On a DOE closing analyst call, we held on January 13.

We reviewed the normalized free cash flow generation ability of our business at current debt levels and 2025 CapEx and those slides are in the appendix of this deck. We expect that our restricted group assets, which is largely our specialties business generates $95 million to $115 million of mid-cycle free cash flow available for deleveraging and the current interest and CapEx loans. While fuel and asphalt margins are a bit below mid-cycle at the moment, mid-term fundamentals suggest a very little new refining capacity coming online, a mid-cycle margin expectation is more than supported. Second, Montana Renewables should generate $65 million to $85 million of cash annually at $1.50 per gallon index margin. Of course, this cash flow level is before we consider an increase in industry index margins to distort norms or an increase in SaaS volume.

The debt that previously was absorbing $80 million per year of cash flow has been reduced to zero, and EBITDA generated at MRL is now available to grow our MaxSAF strategy to pay down debt. Free cash flow isn’t the only tool we’ll be relying upon to reduce debt. We previously said, we’re willing to explore non-strategic accretive asset sales that fit someone else’s strategy better than our own, and we demonstrated that today with the Royal Purple Industrial announcement. When that deal closes, we’ll be paying down some of the 2026 notes that step down to par in May, and we also expect to be terminating the ATM program that was announced last month in connection with the von Tacan [ph]. The ATM was never used. Another restricted debt reduction tool available to us is Perry debt on TANNER renewables, which is allowed for a DOE loan.

This would provide the ability to accelerate the repayment of the intercompany and as we mentioned earlier, in any event, Montana Renewable will be paying in our company interest to Calumet. Last and what we expect will be the final tool to achieving our $800 million debt target is monetizing Montana Renewables. This is the plan that we’ve discussed at length and with operations fully derisked, the balance sheet restored and our MaxSAF plans funded, the stage is set to demonstrate the EBITDA potential of this asset as the market recovers. As more clarity comes to the PTC, BTC situation and the market restores itself, the next year’s RVO is reset, will attract all the required boxes to take the next monetization step. With our priorities clear for 2025, we are positioned to execute.

Last year, Calumet completed setting the foundation for our long-term success. The company’s structure change allows for new investors, the DOE loan reduced our cash debt service by third and funds exciting growth. And that, along with today’s Royal Purple announcement kick-starts our concurrent deleveraging and growth strategy. With that, I’ll turn the call to the operator for questions.

Operator: We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Roger Read with Wells Fargo. Please go ahead.

Roger Read: Thank you. Good morning, gentlemen. Hopefully, you can hear me all right on the — on a cell phone, so I never know for sure about my connectivity. But — I guess, I mean, there’s so much to go after here, but maybe, Todd, some of your comments towards the end there, specifically as we think about balance sheet structure, once you get everything where you want it to be prior to any monetization of MRL. And then you mentioned the ATM. Is that something we can now consider is truly rearview mirror, there’s no need or interest in exercising anything with that?

Todd Borgmann: Yes, I think the ATM was as part of the debt refinancing, we had to show that we had a clear path to pay off for 2026’ I think with today’s Royal Purple announcement, the need for that was replaced with something better. So we’re going to go ahead and terminate that. So I think you can think about that in the rearview there. Of course, we never used it.

Roger Read: Right. And then what is the right way to think about the structures and of the balance sheet? When you’re set and done with this? In other words, the funding has come in from the DOE. The Stonebriar stuff is taken care of – what is the actual pace of the reduction of other debt? Like can we just consider that as fully replaced now? Or we’ve got to wait for certain events to occur or any other restrictions on the ability to retire the other debt?

Todd Borgmann: Yes. No, I don’t think there’s any other restrictions that stay on our way. You could ask the question in two different ways, the next year’s debt, which I think is pretty simple and clear, given that we did the tax before, just had the transaction today, had a DOE close, have free cash flow expected through the rest of the year. But let’s focus more on kind of our ultimate plan to reach the $100 million target that we have. So when you do that, you start with the pairing or Montana Renewables intercompany. So there’s $350 million there. And we’re working against an $800 million deficit between today’s roughly $1.6 billion of restricted debt and the $800 million ultimate target. So if you got to assume that $350 million is going to come back, pay down the other company that gets you to the $1.2 million.

We talked about free cash flow that we’d expect over the next couple of years, particularly in an improving market at Montana Renewables, that’s a few $100 million. We talked about repair as an option to help accelerate the intercompany. We had the asset sale we talked about this morning for $100 million, and that kind of sits us within striking distance with a clear Montane Renewables monetization to reach the ultimate target as soon as we check those boxes that we mentioned on the earnings call, right? So we’re the — if you rewind the clock about a year, we said in order to ultimately achieve our objective with MRL monetization. We need to prove out their operations. We’ve done that. We had fund the DOE and fix the balance sheet. We’ve done that.

Took a little longer than any of us expected or wanted, but that’s done, and we’re thrilled about that. So now we have a proper balance sheet, fully operating asset, hit our operating cost target, hit our staff target, and now we’re just waiting on the market to recover. So we’re waiting on BTC, PTC clarity. We think that gets us to the levels, the fundamental levels we talked about on today’s call. Then we’ll see an RVO reset. And we think that we’ll be in place to go back out and explore and work on that opportunity. So we look forward to taking that step. We’re not sitting around waiting to optimize that forever. At the same time, we’re not going to be forced to go sell something in a downturn environment, because we have plenty of options to deal with kind of the near-term maturity.

So as soon as the market recovers and we check those boxes talked about, we’ll be laser-focused on monetizing Montana Renewables and hopefully that’s sooner than later.

Roger Read: Yeah. I appreciate that. Just one final kind of follow-up on monetization of MRL, is there anything with the DOE loan, that inhibits any version of monetization? Or its financing is financing, and it wouldn’t really matter who it came from. You can proceed as what’s best for Calumet MRL.

Bruce Fleming: Hey Roger, it’s Bruce. So I’ll remind everybody that the loan guarantee agreement is filed in an 8-K. The DOE loan guarantee is financing. The scenarios around who can come in, in an equity position are signaled in there. The deal we basically wants to, know who it is. Now if you think about the size of the transaction, it’s going to be an HSR filing. If a touch is a foreign player, it’s going to be a CFIUS filing. So conformance with the current administration’s priorities in that regard will be part of the equation. But we’re certainly not blocked from bringing in equity. They want us to — it was the essence of this this arrangement that they give us about half is financing 55%, as David said. And we provide the rest is equity.

Roger Read: Thank you.

Operator: And the next question comes from Jason Gabelman with TD Cowen. Please go ahead.

Jason Gabelman: Yeah. Hey, morning. Thanks for taking my questions. A couple on the MRO margin outlook. The PTC rule, as it’s written seems to, disincentivize use of canola oil. I know that was a key kind of feedstock or a key makeup of your feedstock diet. Can you talk about, how the limitations on canola or the economic disadvantage of canola plays into your outlook for margins over the next year and the ability to maybe backfill that?

Bruce Fleming: Yeah. So Jason, it’s Bruce, the reality is we’re feedstock-agnostic. And there’s clear evidence that all of these feeds are armed together on their CI parity. So it doesn’t matter. There’s — the idea of the feed shortage is long gone. It’s not like canola loans still be in the feed pool for the industry. And if it’s not, then you got the weird shuffle where the Canadians are exporting canola oil and somebody’s re-importing something else in the same volume. So quite frankly, the way that the PTC reached model, put their thumb on the scale and started to pick winners and losers in the feed pool, adds to complexity, adds to optimization incentive for somebody like us, we can run any of these speeds and hit six different rules, in six different geographies that are adjacent to us. So I see it as upside. Now final comment is none of that, matters if we take Canadian canola and make Canadian renewable diesel fast.

Jason Gabelman: Yeah. That’s a good point. And actually a segue to my next question. It appears British Columbia is going to restrict use of international renewable diesel to make — or to meet the province’s own targets. Can you talk about how that update maybe impacts your outlook for margins given there’s been — you’ve discussed the advantages of selling your renewable diesel into Canada?

Bruce Fleming: Yes. That will raise margins. Let me walk you through it. Canada has a federal requirement. The balances in BC will pull in all of the Canadian biodiesel and that’s not going to work. It doesn’t work in the winter. But even if it did, now you’ve created a higher cost structure for the country of Canada by making this trade flow go westward into BC. No problem, we’ll backfill the rest of Canada. I trust that’s self-evident. What’s worth noting though, and this is actually, I think, a good signal for where we feel the intermediate term opportunities and developments are going to play out. I’ll give you two examples. So, BC and Tidewater are pretty tight. We like the Tidewater guys. We talk to them a lot. And this makes perfect sense if you’re sitting inside the province and you’re thinking about the equivalent of national competitive advantage.

For my second example, I’m going to draw your attention to Greater Minneapolis St. Paul SAF hub, same bet. So, when you make rules within a local geography that are collectively advantaging your local economy, that actually makes perfect sense. We’re all used to reading the paper and thinking about it at the national level, but quite frankly, in SAF and now in R&D with this BC news, it actually is local. I mean everybody that figure all this out and had all the great spreadsheets and you know exactly where this was going 12 months ago. Mist Illinois and Minnesota. So, now all of the SAF in North America is getting pulled into the Great Lakes region. So, there’s going to be a lot of dynamics. We see a lot of complexity, we see a lot of optimization opportunities.

And I’m going to go back to the map and say we’re best positioned to take advantage of all that, just look where we are, look where the rules are, look where the high speed high freight capacity railroads go, and we kind of like all of this.

Jason Gabelman: Got it. Great. And if I could just sneak one more in. I know you’ve talked about the 45% equity funding at MRL funded from cash flow, but I’m wondering if the asset doesn’t generate the cash flow that you’re expecting for whatever reason, what are the alternative avenues that Calumet has to meet that required equity funding level?

Todd Borgmann: Hey, I don’t think we have to go to kind of the Calumet side of that. When you — we’ve got $190 million of cash on the balance sheet at Montana Renewables. But I think the more important point is the — when you kind of look at the EBITDA that Montana Renewables has generated even in kind of trough industry environments late last year, that’s more than enough to pay for the 45% of the small amount of capital that we’re talking about over the next year.

Jason Gabelman: Got it. All right. Great. Thanks for the answers. I’ll leave it there.

Todd Borgmann: Thank you.

Operator: And the next question comes from Neil Mehta with Goldman Sachs. Please go ahead.

Neil Mehta: Yes. Thanks, Todd and team. First question is just around Royal Purple. Can you talk a little bit about how that asset sale came together, how you identified it as kind of non-core? Is there other opportunities for divestiture? And you gave us a revenue number, but we’re trying to figure out what the EBITDA multiple is. So if you could just round out the Royal Purple discussion?

Scott Obermeier: Neil, Scott Obermeier here. I think for background and context to your question, we’ve been making a lot of progress overall within the Performance Brands business. Todd touched on it during the call, not just the EBITDA and the results more than doubling, but really understanding the business, our right to win and how we can maximize value within the business. And so as we think about the last, call it, six, seven months, we thought about the business now has been running well, and we’ve turned our attention forward around our future planning, how the business and how pieces of the business fit in with our strategy, it’s really centered on integration within the overall specialties business. During that time, I’d say, Neil, we’ve gotten some inbound calls.

I think a lot of people out in the industry understand the value of the brands within the business and the growth opportunities that exist. So with these inbound calls, we — our number one priority is thinking about deleveraging as a company. And so we considered a lot of these — a lot of the interest out there, how it fits into the strategy, how much value that it would generate for us. We have pieces within that business that integrate very well with the specialty strategy. They carry a high hold value for Calumet. But then we’ve got some other pieces such as the Royal Purple Industrial that might not fit our integrated strategy and that are valued more by others. So ultimately, that deal just made a lot of sense for both the buyer and for Calumet overall.

Todd Borgmann: Yeah. And Neil, it’s Todd. I’ll add a little bit. David noted earlier that multiple is about 10x for the deal. So accretive transaction. We’re super excited about it for all the reasons Scott said. And I think one of the things that excites me more than just the price and the ability to immediately pay down some debt with it and kickstart that is we think through our operational and supply chain synergies that kind of result from the transaction, we can replace most of that EBITDA that we gave up over the next two years. So we’re kind of looking forward to continuing to just optimize our warehouse facilities, our operational facilities, our broader supply chain and I think that there’s quite a prize there to explore as we move forward.

As far as willingness to sell other assets, we’ve said for a long time that we’re always willing to sell something that’s more valuable to somebody else than us, and that remains true. I think this is an example of that. To Scott’s point, you’re most likely to find those in places that aren’t deeply integrated within the business because some of our deeply integrated businesses, it’s just hard to imagine that they would be worth more as a bolt-on than they are to us. But assets like this one, what we found was that people are pretty interested in looking at specific pieces of the business that are really nice strategic bolt-ons for them. So we’re certainly open to exploring other opportunities that would fit those same dynamics.

Neil Mehta: Thank you. And then Todd, can you just round out the conversation on small refinery exemptions. I think I caught your piece about adding back some of the RFS cost to adjusted EBITDA because, I guess, of your outlook around litigation. But just remind us again, how many dollars potentially could be coming back to the organization if you win the CSRE case, where do we stand with that? And what gives you the confidence there?

Todd Borgmann: Yeah. So let me just start and clarify about how we account for RINs today. And so what we do is we kind of recognize an incurrence for RINs cost in our cost to goods sold. And so you can think about it as kind of a non-cash cost. And then in our adjusted EBITDA, we don’t actually add that back. So someone could look on our statement of cash flows, and that will get added back. But I think when we’re out there on the road talking to investors, and people look at our adjusted EBITDA, there’s probably $40 million of cash flow that wasn’t included there for 2024. And as we’ve converted to a C-Corp and broaden out our investor dialogue, it is a tough way to start a conversation with a new investor. Let me talk to you for 40 minutes about what a RIN is and a small refinery exemption.

And why adjusted EBITDA is $40 million light. Also that number is getting a lot larger as we’ve seen RINs shoot up as we’ve talked about on the MRL side of things. So we’ve had success in some of our court cases, and I’ll kind of toss it over to Bruce to talk a little bit about that. But it’s not a change to our business and how we operate, it’s a clarification and a simplification, so we can converse with investors in a way that accurately reflects the cash generation of our specialty business in Montana asphalt business. Bruce?

Bruce Fleming: Yeah. So Neil, part of the question, if I heard it was how much cash is coming back. I trust David spoke to that. And if we line up our EBITDA with our cash generation from the business that’s really the purpose of that metric and $40-ish million for 2024 would be the appropriate higher EBITDA tied to cash flow from ops. The reason we’re prevailing in these court cases is pretty simple, and you can read the very short succinct rulings from the Fifth Circuit. You can read the rulings from the DC Circuit. And under the prior administration, the EPA acted illegally, and the court said, we’re not going to let you do that. So all of our cases are back to EPA to have them do it over and they’ll have to come up with a new decision.

That’s reflected on their website. They’ve moved from denied to pending status and they’re still pending. We expect that will get sorted out and in the long run, let’s just pop back up the national policy for a microsecond. This is domestic energy policy. The more renewables we produce in this country and blend into fuels, the more independent we are of an incremental crude import possibly from an unfriendly source. So we’re supportive of all of that, but the law is clear. You can’t ask the small guys to bear a disproportionate birth. The way the EPA has structured this is a regressive tax. It’s the most preposterous thing I’ve seen. So I’m sure that will get fixed under this administration.

Neil Mehta: Thanks, Bruce. Appreciate the time guys.

Bruce Fleming: Thanks, Neil.

Operator: Your next question comes from Gregg Brody with Bank of America. Please go ahead.

Gregg Brody : Hi, guys. That’s great color. And congrats on getting the deal you’re funding in the door. My first question relates to the second tranche. I think you said you thought you guided until you should have access to this year, the contingencies help us think through how we should think about when you’re able to start accessing that? And then does that also imply that the CapEx at MRL is delayed until that’s available or at least on the MaxSAF expansion?

Bruce Fleming: Hi, Gregg. Thanks for the chance to clear that up because right weird interpretations of this. So let’s be crystal clear. There’s one loan, and we’ve already drawn on it. I can draw it again tomorrow and the story.

Gregg Brody : The second tranche you have access to now? I thought I saw the contingencies.

Bruce Fleming: Yes, the CPs are make sure everything is still current and true, yes, that’s the thing to bring down all the representations that — sorry, Gregg, every draw, you bring down all of the representations and make sure they’re still current and true. The loan is now live. The loan is operating. We’ve draw number one. We can draw number two.

Gregg Brody : So are you — I should say to so, with respect to the capital being funded at MRL by the DOE owned by the second tranche. Is that spreading way throughout the year at this point? Is that how we should think about it?

Bruce Fleming: No. I would suggest that’s back-end loaded. We’re — for example, next week, we’re going to our final license or technical selection. And we’ve got a good design laid out by our EPC company, but we’re still tuning and adjusting, that’s going to spend slower, just think construction S curve. And we’ve provided a guidance number of $50 million total. That’s sort of $28 million to the DOE and $22 million to us. But that’s going to happen late in the year. And if anything, that’s a reservation that might be on the high side.

Gregg Brody : How should we think about the staff additions next year in terms of the incremental production, what phase of the year should we expect to start to see that? And how should it ramp?

Bruce Fleming: Yes. That’s interesting, Gregg. We’ve actually got a couple of options technically as to how we can do that. And therefore, we have an optimization opportunity, but we conservatively contracted 30 million gallons to Shell. We’ve run at a run rate of 50 million gallons. We think we can go up a little bit. So we can bring more to the market now. For that to be long-term economic, we wanted to add a second reactor. So you’ve heard us talk about second reactor, here’s a couple of ways to do that. So I can give you resolution more to a calendar quarter as we complete the licensor selection and pick among our choices there. But for the moment, I’d probably just say, it’s going to come online at notionally 150 million gallon a year capability sometime in 2026, but that’s not a big step change. Once that’s pinned down, we’re going to feather into it by spending the existing catalyst faster. So you’re going to see a ramp into the new higher capability.

Gregg Brody: Okay. And then just as we think about sending money out to the intercompany loan at MRL, I think you said the next couple of years. Should we assume that you’re starting to pay that you preferred? When does that start to kick in?

Todd Borgmann: No, those are unrelated. Appreciate the interest. Unless the MRL Board declares a distribution, there’s not a service obligation for the preferred.

Gregg Brody: We shouldn’t expect for you to declare distribution while you’re paying the intercompany or is that that’s what I’m asking?

Todd Borgmann: Yes. So, the positive MRL cash flow is earmarked to go back as the equity component of the project work. So that’s the source of the construction funds on the company side and DOE is the financing on the DOE side.

Gregg Brody: I’ll follow-up off line

Todd Borgmann: Yes. No, we can take it up offline. The cash flow from ops stays in the box. It’s not being distributed out.

Gregg Brody: Maybe just moving on to sort of one of the paths to deleveraging that you mentioned, the peri debt at MRL. Is that something we could see near term? How should we think about the timing of that and the decision tree as to how you move forward on that?

Todd Borgmann: Yes. I think just talk kind of about the whole intercompany and the different options you have. So the amount of intercompany, the $350 million roughly outstanding, there’s an interest component of that that’s just an annual payment back. So that’s roughly just a little bit below $30 million. Then you have cash flow from operations that we make at Montana and Noble. To Bruce’s point, that’s earmarked first for the project and anything in excess of that is available to pay that down. And then last, you have the ability to go raise secured peri debt at MRL that would essentially just replace that intercompany from the MRL perspective. So you would replace intercompany debt with third party debt and the Calumet portion would be paid down.

So, that’s something that we’ll look to explore here pretty quickly. We wanted to get through the DOE process, the roll process year-end, probably get a little bit of clarity around BTC and then go explore that market and really just optimize cost of capital that way and exit restricted deleveraging.

Gregg Brody: Got it. So it sounds like you’re not quite there yet, but it’s something that you are thinking about. Maybe just the last one for me. Could you walk us through the paydown to 2026 with what you’ve received so far? Help me understand the components. How much is trying to be repaid from the DOE loan today or was repaid – is earmarked to repay with the DOE loan, the first tranche that came in, then the bond rate that you did and then today’s asset sale? And just so I understand how much you plan on reducing with free cash flow thereafter.

Todd Borgmann: Yes. So I think if you look everything together, that we’ve done so far. Obviously, any cash that we have does pay down debt immediately just through the revolver. And then we have the step down to in May on the 2026 notes. So there a cost or just the revolver and the interest savings on the 2026 notes. I would say wait until May to call those back. I think with what we pulled in so far, we’d be looking at about a $200 million call, at the May step down time period. And obviously, we’ll learn a lot more from there as far as BTC and Montana cash flows stepping up and the like and increase demand.

Gregg Brody: That’s it for me guys. Thanks for the time.

Todd Borgmann: Thank you.

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

John Kompa: Thanks, David. On behalf of the management team, I’d like to thank everyone for their time this morning and your continued interest in Calumet. Have a great weekend. Thank you again very much.

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