Operator: Good afternoon everyone, and thank you for participating in today’s conference call. I would like to turn the call over to Mr. John Ciroli as he provides some important cautions regarding forward-looking statements and non-GAAP financial measures contained in the earnings material or made on this call. John, please go ahead.

John Ciroli: Thank you and good day everyone. Welcome to Montauk Renewables Earnings Conference Call to review the Full Year 2024 Financial and Operating results and development. I’m John Ciroli, Chief Legal Officer and Secretary at Montauk. We are changing the cadence of our SEC filings and earnings calls beginning with our full year 2024 earnings to better align our primary NASDAQ and secondary JSC markets. Joining me today are Sean McClain, Montauk’s President and Chief Executive Officer, to discuss market and business developments, and Kevin Van Asdalan, Chief Financial Officer, to discuss our full year 2024 financial and operating results. At this time, I would like to direct your attention to our forward-looking disclosure statement.

During this call, certain comments we make constitute forward-looking statements and as such involve a number of assumptions, risks, and uncertainties that could cause the company’s actual results or performance to differ materially from those expressed in or implied by such forward-looking statements. These risk factors and uncertainties are further detailed in Montauk Renewables SEC filings. Our remarks today might also include non-GAAP financial measures. We present EBITDA and adjusted EBITDA metrics, because we believe the measures assist investors in analyzing our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance. These non-GAAP financial measures are not prepared in accordance with generally accepted accounting principles.

Additional details regarding these non-GAAP financial measures, including reconciliation to the most directly comparable GAAP financial measures can be found in our slide presentation in our full year 2024 earnings press release issued and filed March 13, 2025, which is also available on our website at https://ir.montaukrenewables.com. After our remarks, we will open the call to questions. We ask that you please keep one question to accommodate as many questions as possible. With that, I will turn the call over to Sean.

Sean McClain: Thank you, John. Good day everyone and thank you for joining our call. On March 7, 2025, the EPA announced its delay of the 2024 RIN compliance deadline for all categories. The EPA has yet to decide on a proposed partial waiver of the 2024 cellulosic biofuel volume requirements or the timing of its decision on this matter since its origination in their December 5, 2024 EPA announcement. Montauk has sold 100% of its 2024 D3 RINs and it has zero exposure to the timing and resolution of this issue. We entered 2024 with approximately 6.8 million 2024 vintage RINs unsold. During the fourth quarter of 2024, the D3 RIN market exhibited measurable price volatility with indices ranging from a high of $3.50 to a low of $2.08 and significantly muted purchasing activity by obligated parties.

So, these market conditions contributed to our decision to hold a higher balance of D3 RINs at the end of the year. All 2024 vintage D3 RINs have been subsequently sold as obligated parties re-entered the market during the first quarter of 2025. The volatility continues to impact the renewable natural gas industry in a variety of ways. Montauk’s strategy remains steady to seek out and invest in projects with quality host businesses that exhibit feedstock growth potential, to diversify our sources of feedstock, our product offerings, and our monetization structures, and to ensure the long-term economic viability of our projects in a wide range of production and pricing scenarios. In 2018, Montauk took its first significant stride towards feedstock diversification through our Pico acquisition.

We continue to leverage that diversification through our Pico digestion capacity increase and feedstock amendment with a high quality, high volume dairy agriculture host. Our feedstock diversification strategy is poised to further expand in 2026 with the commissioning of our swine waste energy project in Turkey, North Carolina. Our North Carolina development initiative not only demonstrates our commitment to feedstock diversification, but also our commitment to product diversification. The majority of our production revenue from this project will be derived from renewable power generation, which when combined with state-based renewable electricity credits, will meaningfully increase our existing REG business segment. In addition to a rebalancing of power generation in our portfolio, our North Carolina development project increases our revenue from commodity-based products whose market value is not directly influenced by traditional federal or state attribute programs.

The biochar commodity produced by our patented reactor process will help insulate the company from volatility experienced in markets underpinned by federal and state programs such as the renewable fuel standard and California’s low carbon fuel standard. Montauk’s commitment to diversification through its product offerings is further illustrated in its previously announced agreement with European Energy North America for sales of biogenic carbon dioxide. This initiative is being prioritized across our portfolio as the company seeks to extract increased value from its existing projects along the rising demand for and the market price of industrial and food grade CO2. We believe our historical discipline of seeking out and investing in projects with quality host businesses combined with these diversification initiatives will position Montauk to successfully navigate the continuingly changing landscape of the renewable natural gas industry.

With its commissioning in 2024, this will be one of our last updates regarding our Pico Digestion capacity increase. In 2025, we will receive the third and final increase in feedstock under the amendment to our feedstock agreement, and we expect to make that final payment related to this amendment during 2025. We are pleased to report that the production from our Pico facility during 2024 delivered an increase of over 70% versus 2023. We anticipate commissioning our second facility at our Apex site during the second quarter of 2025. As previously discussed, throughout 2024, we continue to expect a period where we have excess production capacity while the landfill host increases available feedstock. With our previously announced Blue Granite project during February 2025, we received notice from the interconnection utility of their intention to not accept RNG into their distribution system from any project.

As a result, we have indefinitely delayed COD and corresponding capital spend as we both work with the host landfill and prospective stakeholders to evaluate alternative RNG interconnection strategies, both physical and virtual, as well as alternative commodity production opportunities from traditional RNG production. We are pleased to announce our initiative to convert our Tulsa, Oklahoma Renewable Electric Generation facility project through the design and construction of a renewable natural gas facility. With a variable inlet capacity design and a corresponding average nameplate capacity of approximately 1,500 MMBtus a day, this new facility will be designed to beneficially process all of the available and growing inlet gas feedstock from its host landfill.

We expect that project capital investment to range between 25 million and 35 million and a targeted commissioning date in the first quarter of 2027. We have prioritized the first of our biogenic CO2 projects related to our previously announced agreement with European Energy and expect to commission a facility at our Atascocita project during the second quarter of 2027. We expect to begin monetization of approximately 60,000 metric tons per year of food grade CO2 in advance of the commencement of our off-take agreement at commodity prices. We continue to progress with our design and equipment selection and construction plans in our other Houston facilities to meet our requirements with European Energy North America to supply their biogenic CO2.

Additionally, we are progressing with our design and construction plans to incorporate food grade CO2 processing into our Rumpke RNG project with an expected commissioning of Q3 2027 and expected volumes of approximately 50,000 metric tons per year of food grade CO2. In December 2024, the state of North Carolina approved a change in laws governing the generation of RECs from swine waste under its renewable energy portfolio standards. For qualifying projects meeting specific eligibility criteria, swine REC regeneration is enhanced by awarding an additional 2 enhanced swine credit RECs for each swine REC generated, a ratio of 3:1 for a period of 8 years, followed by a ratio of 2:1 for a subsequent 6-year period. The company is in various stages of negotiations with other obligated parties to expand REC sales beyond our previously announced agreement with Duke Energy.

We now have over 40 separate farming locations secured under long-term agreements to provide access to waste from no less than 200,000 hog spaces in support of our expected processing needs for the first phase of our Turkey, North Carolina facility commissioning in early 2026. And with that, I will turn the call over to Kevin.

Kevin Van Asdalan: Thank you, Sean. I will be discussing our full year 2024 financial and operating results. Please refer to our earnings press release in the supplemental slides that have been posted to our website for additional information. Our profitability is highly dependent on the market price of environmental attributes, including the market price of RINs. As we self-market a significant portion of our RINs, a decision not to commit to transfer available RINs during a period will impact our revenue and operating profit. At December 31, 2024, we had 6.8 million RINs available but unsold. We have since entered into commitments to transfer all of these RINs. Additionally, we have entered into commitments to transfer all RINs from 2024 RNG production, which generated RINs in 2025.

In total, in 2025, we have transferred approximately 9.9 million RINs from the 2024 compliance year at an average realized price of approximately $2.45. We have no additional 2024 compliance year RINs remaining to be transferred. We have not entered into commitments to transfer a significant portion of RINs from 2025 RNG production. Total revenues in 2024 were 175.7 million, flat compared to 174.9 million in 2023. There was a decrease in the number of RINs we self-marketed during 2024 due to a decision to not commit [indiscernible] RINs in the fourth quarter of 2024. The 2024 average realized price of $3 — average realized RIN price of $3.28 increased approximately 21% compared to $2.71 in 2023. The natural gas price decreased approximately 17.2% during 2024, moving from $2.74 in 2023 to $2.27 in 2024.

Total general and administrative expenses were 36.3 million for 2024, an increase of $1.9 million or 5.5% compared to 34.4 million in 2023. Employee-related costs, including stock-based compensation were 23.1 million in 2024, an increase of 3.4 million or 17.1% compared to 19.7 million in 2023. The increase was primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee. Our professional fees decreased approximately 1.6 million or 35.3% in 2024 compared to 2023. Turning to our segment operating metrics, I’ll begin by reviewing our renewable natural gas segment. We produced approximately 5.6 million MMBtu of RNG during 2024, an increase of 0.1 million as compared to 5.5 million in 2023.

Well field optimization operational enhancements, as well as plant processing equipment improvements contributed to the increase, notably at our [costal] [ph] facility which produced 111,000 MMBtu more in 2024 compared to 2023. Our Pico facility produced 76,000 MMBtu more in 2024 compared to 2023 as a result of commissioning our dairy digestion expansion project. Our Galveston facility produced 59,000 MMBtu more in 2024 compared to 2023 as a result of previously disclosed 2023 dry weather conditions impacting gas feedstock availability. Offsetting these improvements were unrelated well field quality issues and weather anomalies, which lowered production at our Rumpke facility producing 159,000 fewer MMBtu in 2024 compared to 2023. Revenues from the renewable natural gas segment in 2024 were 158 million, an increase of 1.5 million or 1% compared to 156.5 million in 2023.

Average commodity pricing for natural gas for 2024 was 17.2% lower than the prior year. During 2024, we self-marketed approximately 36.6 million RINs, representing an 8.3 million decrease or 18.5% compared to 44.9 million in 2023. The decrease was primarily related to market conditions and a decision to not market 6.8 million RINs generated and available for sale in the fourth quarter of 2024. Average pricing realized on RIN sales during 2024 was $3.28 as compared to $2.71 in 2023, an increase of 21%. This compares to the average D3 RIN index price for 2024 of $3.12 being approximately 18.6% higher than the average D3 RIN index price in 2023 of $2.63. At December 31, 2024, we had approximately 291,000 MMBtu available for RIN generation and had approximately 6.8 million RINs generated and unsold.

We had approximately 358,000 MMBtu available for RIN generation and approximately 108,000 RINs generated and unsold at December 31, 2023. We have entered into commitments and transferred all of our RINs and inventory related to our 2024 RNG production. Operating and maintenance expenses for RNG facilities in 2024 were 53.4 million, an increase of 5.5 million or 11.5% compared to 47.9 million in 2023. Our Rumpke facility operating and maintenance expenses increased approximately 1.8 million as a result of increased media change-out and gas processing equipment maintenance costs. Our McCarty facility operating and maintenance expenses increased approximately 1.2 million as a result of a well field operational enhancement program and increased gas compression system maintenance costs.

Our Pico facility operating and maintenance expenses increased approximately 0.9 million as a result of non-capitalizable costs associated with the digestion capacity increase project, as well as expenses associated with efficiency improvements with the existing digesting capacity. Our Atascocita facility operating and maintenance expenses increased approximately 0.6 million, primarily driven by increased utility expense. Our Apex facility operating and maintenance expenses increased approximately 0.3 million, primarily related to increased gas processing equipment maintenance costs. We produced 186,000 megawatt hours in renewable electricity in 2024, a decrease of approximately 8,000 megawatt hours or 4.1% compared to 194,000 megawatt hours in 2023.

Our security facility produced 9000 megawatt hours less in 2024 compared to 2023 as a result of us ceasing operations in connection with the first quarter of 2024’s sale of the gas right back to the landfill host. Revenues from renewable electricity facilities in 2024 were 17.8 million, a decrease of 0.6 million or 3.8% compared to 18.4 million in 2023. The decrease is primarily driven by the decrease in our security facility production volumes. Operating and maintenance expenses for our renewable electricity facilities in 2024 were 12.8 million, an increase of 1.1 million or 8.6% compared to 11.7 million in 2023. The primary driver of the increase were operating and maintenance expenses related to the Montauk Ag Renewables development project, which increased approximately 1.1 million as a result of non-capitalizable costs.

We calculated and recorded impairment losses of 1.6 million for 2024, an increase of 0.7 million or 75.8% compared to 0.9 million for 2023. The impairment losses in 2024 primarily related to the remaining net value of asset at the security facility. Various RNG equipment that was deemed obsolete for current operations and REG assets that were impacted under initial start-up testing for one of our REG construction work in progress sites. The 2023 impairment losses relate to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use. None of the 2024 or 2023 impairments were associated with our expectations for our operations to generate future cash flows from operations. Other expenses in 2024 were 3.9 million, a decrease of 1.4 million or 25.2% compared to 5.3 million in 2023.

The decrease was primarily related to proceeds of 1.0 million received from the sale of gas rights ahead of the fuel supply agreement expiration at our security facility and decreased interest expense of 0.5 million. Operating profit in 2024 was 16.1 million, a decrease of 7.5 million, or 31.8% compared to 23.6 million in 2023. RNG operating profit for 2024 was 56.0 million, a decrease of 3.3 million or 5.5% compared to 59.3 million in 2023. Renewable electricity generation operating loss for 2024 was 2.8 million, an increase of 2.2 million compared to 0.6 million in 2023. Turning to the balance sheet. At December 31 2024, 56.0 million was outstanding under our term loan. As of December 31, 2024, the company’s capacity available for borrowing under the revolving credit facility remained at 117.8 million.

As of December 31, 2024, we generated 43.8 million of cash from operating activities, an increase of 6.7% compared to 41.1 million as of December 31, 2023. Based on our estimate of the present value of our Pico earnout obligation, we recorded a decrease of 1.7 million to the liability as of December 31, 2024. This decrease was recorded through our RNG segment royalty expense. During 2024, we incurred approximately 62.3 million in capital expenditures, of which 27.8 million was from Montauk Ag Renewables, 12.6 million was for the second Apex facility, and 8.8 million was for the Bowerman RNG project. In 2023, our capital expenditures were 63.1 million, of which 18.6 million was for Montauk Ag Renewables; 13.7 million was for the Pico facility digestion capacity increase, and 13.1 million was for the second Apex RNG facility.

In 2025, we expect our non-development capital — our non-development 2025 capital expenditures to range between 14 million and 17 million. Additionally, we currently expect that our existing 2025 development capital expenditures will range between $100 million and $150 million. As of December 31, 2024, we had cash and cash equivalent of approximately 45.6 million and accounts and other receivables of approximately 8.2 million. We don’t believe we have any collectability issues with our receivables balance. Adjusted EBITDA for 2024 was 42.6 million, a decrease of 3.9 million or 8.3% compared to 46.5 million for 2023. EBITDA for 2024 was 41 million, a decrease of 4.3 million or 9.5% compared to EBITDA of 45.3 million for 2023. Net income in 2024 was 9.7 million compared to net income of 14.9 million in 2023, a decrease of 5.2 million or 34.9%.

On January 26, 2021, we entered into a loan agreement and secured promissory note, the initial promissory note with Montauk Holdings Limited, MNK. MNK is our affiliate and certain of our directors are also directors of MNK. Pursuant to the initial promissory note, we advanced a cash loan of 5 million to MNK for MNK to pay its dividend tax liability arising from the reorganization transactions under the South African Income Tax Act of 1962 as amended. As a result of several amendments, the current principal balance of the loan was $10.7 million. The due date is December 31, 2033, and the security interest is 976,000 shares of our common stock held by MNK — the fifth amended promissory note. In December 2021, [River Props] [ph] 47 Proprietary Limited, RP47, entered into an agreement to loan MNK up to 10 million South African rand, the RP47 loan.

The current principal balance and accrued interest is 11.7 million rand or approximately $0.7 million. There is no collateral pledge for this loan. This loan became due on December 31, 2024, the maturity date when MNK and RP47 did not extend the maturity of the loan agreement. Based on the transaction implementation agreement between us and MNK, we are obligated to repay the RP47 loan on MNK’s behalf, subject to MNK confirming that RP47 loan maturity was not extended and that MK did not have sufficient funds to repay the loan. As of December 31, 2024, we accrued a contingent liability for the repayment of the RP47 loan under the TIA. On February 2, 2025, after the end of our 2024 fiscal year, but before our 2024 financial statements were issued, our Board of Directors approved the repayment of the RP47 loan under the TIA, and on March 5, 2025, we repaid the RP47 loan as required under the TIA.

The amount repaid is included in the principal balance of the fifth amended promissory note described above. Prior to the RP47 loan repayment, we concluded that RP47, a related party of us through RP47’s ownership of MNK, was the primary beneficiary of MNK under the variable interest entity model. With modification under the TIA and the subsequent repayment of RP47 loan, RP47 retained its power over MNK, but no longer held significant benefits in MNK. Following accounting guidance, we determined that with the amendment under the TIA, substantially all of MNK’s activities were conducted on our behalf as MNK’s only asset is the 976,000 shares of our common stock held as security for the fifth amended promissory note. MNK’s only obligation is it’s loan to us, and thus we are the primary beneficiary of MNK.

We consolidated MNK as of December 31, 2024, and the repayment of the RP47 loan prior to the issuance of our 2024 fiscal year financial statements was determined to be a subsequent event. As of December 31, 2024, we consolidated MNK’s current assets, approximately $52,000, non-current assets approximately $0.6 million, current liabilities approximately $0.6 million, and long-term liabilities approximately $16,000. The fifth amended promissory note became an intercompany loan — and was eliminated in consolidation. MNK’s investment of approximately 10.2 million in the company is also eliminated in consolidation. There is no gain or loss on the initial consolidation of MNK as the transaction is a common control transaction. We recorded a non-cash acquisition of treasury stock of approximately 8.3 million related to the consolidation of these 976,000 shares of our common stock collateralizing the fifth amended promissory note.

MNK remains a separate legal entity with ownership of the 976,000 shares of the company’s common stock. Subject to market conditions in our insider trading policy, as MNK is an affiliate of the company, MNK can sell these shares to repay the loan to the company. With that, I’ll now turn the call back over to Sean.

Sean McClain: Thank you, Kevin. In closing, while we don’t provide guidance to our internal expectations on the market price of environmental attributes, including the market price of D3 RINs, we would like to provide our 2025 outlook. It is important to note that our guidance ranges include internal assumptions that may or may not align with current market trends. Also, our outlook is based on selling RINs up to the quarter after RINs are generated. We expect our RNG production volumes to range between 5.8 million and 6 million MMBtus and corresponding RNG revenues to range between 150 million and 170 million. We expect renewable electricity production volumes to range between 178,000 and 186,000 megawatt hours. Corresponding renewable electricity revenues are expected to range between 17 million and 18 million. And with that, we will pause for any questions.

Operator: [Operator Instructions] And our first question will come from the line of Saumya Jain with UBS. Your line is open.

Saumya Jain: Hey, good morning. So with your RNG facilities, how are you guys looking at things from the data center side of things, any opportunities you’re seeing on [indiscernible] provide some color on that.

Sean McClain: I’m sorry, would it be possible for you to repeat that question? it was a little difficult to hear.

Saumya Jain: Yeah, so with your RNG facilities, how are you guys looking at things from the data center side? Are you seeing any opportunities on that front that you could highlight?

Sean McClain: RNG sales from external businesses such as like data centers, cold storage facilities, these opportunities are in constant development with conversations that we have with entities such as data centers, cold storage facilities, high volume users that are interested in co-locating, we’ve had conversations on a number of our REG facilities specifically just because of how quickly you can provide that electricity. The nuance in looking at those synergies is how you benefit from the renewable electric credits, whether or not that power is still put into the infrastructure of the local utility as opposed to sort of direct supplying those entities that would sort of co-locate geographically to your locations, but it’s definitively an area, call it quasi-voluntary compliance.

It is an interesting alternative to how we diversify the product sales that we have, especially in light of any pending or recent volatility that you see in the federal and state attribute markets.

Operator: Thank you. One moment for our next question. And that will come from the line of Matthew Blair with TPH. Your line is open.

Matthew Blair: Great, thanks for taking my question and good morning Sean and Kevin. I had a few questions on the 2025 RNG revenue guidance of 150 million to 170 million, so I know you don’t provide the underlying RIN assumption, but can you tell us, does that revenue guidance assume that all of your RINs will be monetized in 2025? And then also, would you expect to still receive a premium to benchmark RIN prices in 2025, the past couple of years, you have been able to monetize your RINs at higher than benchmark prices and is that a trend that you think will continue?

Kevin Van Asdalan: Thanks Matthew. In regards to expectations on achieving premiums over the existing D3 index price, I believe we’ll continue — we expect to continue our historical trends of success with selling RINs at advantageous — during advantageous RIN pricing opportunities. In regards to our forward guidance for 2025 and our expectation associated with when we will transfer and recognize revenues on those RINs. Associated — generally as we commented, our expectations are that we will commit to transfer available RINs up to the next quarter available to be transferred. Associated with the last handful of quarters, we have provided information and we’ll continue to provide information about the timing of those RINs that we keep in inventory that may or may not correspond to that quarter.

Additionally, as we continue to move through 2025, here being the first quarter, though we are understanding and working through the [indiscernible] regulatory reform, we do anticipate that that regulatory reform may have an impact on the timing of those RIN sales as well.

Operator: Thank you. One moment for our next question. And that will come from the line of Tim Moore with Clear Street. Your line is open.

Tim Moore: Thanks, I have a 2-part question that are somewhat related. You had some commentary in November about the landfill operators delay impact, there’s some capacity slowness there. Can you maybe comment on that? And then I just want to check that I understood maybe your earlier comment and prepared remarks, I think you said $2.45 might have been the average RIN price transfer this year. I’m just wondering if that’s indicative of the D3 RIN pricing, because the EPA website stopped posting that after inauguration day, I’m just kind of curious what you’ve seen on pricing in the last few weeks.

Sean McClain: Yeah, Tim, I can take both of those. With respect to landfills delays in projects, we’ve talked in the past, landfills historically have been a little more synergistic in their willingness to allow for you to sort of infiltrate their open face areas where they’re placing waste that allows for you to accelerate the volume increases that you would expect from well field initiatives, horizontal vertical drillings, anything that would improve the volumetric size of your well field collection system. We do continue to see hesitation on the landfill side due to the challenges that they are communicating that they present with their staff. So, the intricacies of trying to place waste as their primary business, competing against the delicacy that they need to navigate around collection systems and the time that they then lose to have to remediate those damages as they’re incurred has been something that has been more communicated from them over the last few quarters, it’s not fatal in the sense that the collection infrastructures are committed to be increased not only from an environmental NSPS compliance standpoint, but also from the standpoint that they want the additional gas, they want to see the additional royalties.

The timing of it is still at times slowed, because they’re trying to create a little bit of a better divide between when they are high activity in the open face waste placement and when the collection systems come in and start to pull off of that more recently placed waste. With respect to pricing, other than the standard disclaimers that we don’t opine on what we expect pricing to be, it’s difficult to say if that price is indicative of what we’ll see in 2025. As we sort of mentioned at the beginning of this call, the EPA has floated the idea of a postponement or an adjustment down of the volume obligations for 2024. They haven’t indicated any change to 2025. The way that we look at pricing is more of a function of who we sell to. The majority of our attributes we place directly in the hands of obligated parties.

Our decision to hold those volumes at the end of 2024 are not a direct reflection of our view of pricing, is it the right time to pull and monetize? It’s the purchasing parties that are in the market. We saw a significant reduction in the obligated parties’ purchasing activity in the marketplace as we see that picking up in the first quarter, that’s when we monetize the remainder of those 2024, so it’s a very roundabout way of explaining that we’re more focused on the health of the renewable fuel standard program of selling our attributes into the hands of the parties that need to buy them and retire them, as opposed to sort of factoring them on an interim basis to folks that are willing to purchase them and ultimately sell them to obligated parties, which we believe creates the most disturbing price volatility that you can try to manage through, but it would be difficult at this time to say if $2.45 or something significantly higher or significantly lower is a good indicator to expect what RIN pricing is going to be for 2025 vintage.

Operator: Thank you. One moment for our next question. And that will come from the line of Ryan Pfingst with B. Riley. Your line is open.

Ryan Pfingst: Hey guys, thanks for taking my question. Can you talk a bit about what you’re seeing in the voluntary market in terms of demand and pricing there.

Kevin Van Asdalan: Ryan, that is one of the more challenging markets that we’re trying to get. I don’t know if I want to say reliable or meaningful data from. We’re working with our internal capacities. We’re working through our external partners. The reliability of getting meaningful voluntary information from volumes that are coming out of the RFS to generate RINs into the voluntary market remains a challenge. That said, we ourselves have entered into what we refer to internally as fixed price or margin share arrangements that generally thus far have not been placed into the voluntary market. They’ve been placed into the RFS transportation space and that’s what we’ve seen through 2024. We have the flexibility either through off-takes at our sites that are coming up for expiration during 2025, or we believe through those existing margin share arrangements that we have in place from 2024 to further divert away from, if necessary, the transportation space and into the voluntary space as the market so dictates.

Related to that is then your evaluation of what is that price associated to a RIN if you could get those volumes into the transportation space versus the fixed price and/or fixed price plus upper spread that you can share in as well as term, all of those items are challenged right now under the ongoing EPA deferral of the rulemaking in the 2024 obligation that was announced in December. The uncertainty, though yet currently unstated impacts to any change in the already existing 2025 RBO; however, also the EPA missing the initial rulemaking periods for the 2026 RBO. Ultimately, as Sean said on his last question, that is a long about way of answering your question of we’re seeing activity in the voluntary market, achieving readily reliable data similar to how we can get reliable historical data in the transportation space from a RIN generation continues to make this evaluation of when and for how long and at what price points to offer off-take volumes is something that we continue to evaluate as we move through 2025 noting all those sort of caveats and items that we’re weighing as we progress through 2025.

Sean McClain: Ryan, the only other thing that I would add to that is our diversification plays feedstock off-take arrangements. They’re also done with a high degree of fiscal responsibility. The diversification that we focus on isn’t voluntary versus obligated party. It’s diversification of commodities versus attributes. When you’re selling attribute-based products, the voluntary market does move up and down based on their projections of what they compete against, which is the attribute market. And when you elect to proceed with the voluntary market, we view it as a nice backstop, so that there is some sensibility in pricing because it’s an alternative, but that alternative comes with a different risk profile associated with the credit worthiness.

Having an attribute going into the market that can appeal and apply to all refiners of petroleum is a much different credit consequence than us going to say the previous question where we’re selling direct to a solitary cold storage facility for voluntary compliance or a data center, there’s a lot more that needs to be understood about the survivability and the longevity of that business, how it is structured, and not to say that it can’t be done. It is something that when you’re being ultra-selective on projects, the natural consequence is you are conservative over some of the more financial aspects of what your off-take looks like and the creditworthiness of those off-takers.

Operator: Thank you. [Operator Instructions] One moment for our next question. And that will come from the line of [Betty Zhang] [ph] with Scotia Bank. Your line is open.

Unidentified Analyst: Hi, good morning. Thanks for taking my question. I wanted to ask about the 45Z. Would there be any impact to Montauk from this production tax credit?

Kevin Van Asdalan: [Betty] [ph], thank you. We already receive production tax credits from our electric generation portfolio, notably our Bowerman facility. In regards to the 45Z production tax credit, the new expanded enhanced one to say that there’s going to be benefit, to say that we’re not investigating or reviewing that benefit, we currently are, in concert with our continued, review and evaluation of the previously finalized ITC credit as well, but we continue to evaluate and look through applicability and availability under those various tax credits enhanced or expanded under the IRA Act.

Operator: Thank you. I’m showing no further questions in the queue at this time. I would now like to turn the call back over to Sean McClain for any closing remarks.

Sean McClain: Well thank you and thank you all for taking the time to join us on the conference call today. We look forward to speaking with you throughout 2025.

Operator: This concludes today’s program. Thank you all for participating. You may now disconnect.

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MONTAUK RENEWABLES INC

Q4 2024

Earnings Transcript

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