Good afternoon, everyone, 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. Thank you. Good afternoon, everyone. Welcome to Montauk Renewables Earnings Conference Call to review the Q2 2023 financial and operating results and developments. I'm John Ciroli, chief legal officer and Secretary at Montauk. Joining me today are Sean McClain, Montauk's president and chief executive officer, to discuss business developments, and Kevin Van Asdalan, chief financial officer, to discuss our Q2 2023 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 or implied by such forward-looking statements. These risk factors and uncertainties are detailed in Montauk Renewables SEC filings. Our remarks today may 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 reconciliations to the most directly comparable GAAP financial measures, can be found in our slide presentation and in our Q2 2023 earnings press release and form 10-Q, issued and filed this afternoon, which are also available on our website, ir.montaukrenewables.com. After our prepared remarks, we will open the call to questions. We ask that you please keep to one question to accommodate as many questions as possible. With that, I turn the call over to Sean. Thank you, John. Good day, everyone, and thank you for joining our call. On June 21st, 2023, the Environmental Protection Agency announced final rules for the renewable fuel standard for the 2023 through 2025 years. While the final rules did not finalize the eRIN program, it did set final volumes for cellulosic biofuel at 838, 1,090 and 1,376 million RINs for the years 2023, 2024 and 2025, respectively. Though noting the delayed eRIN program, the finalization of the rules had an appreciable impact on the D3 RIN index price. The average D3 RIN index price from June 22nd through June 30th was approximately 31% higher than the index price average from June 1st through June 21st. As planned, we monetized a significant number of RINs after the announced final rules, prioritizing obligated parties and benefiting from the notable rise in D3 RIN index price. We monetized all RINs generated and unsold as of June 30, 2023, and committed the majority of our expected 2023 Q3 RIN generation. We have not yet entered into forward sale commitments beyond the Q4 of 2023 RIN generation. The average realized price of these July 2023 commitments were priced at or above the July 2023 average D3 RIN index price. The final rule also included significant changes to the existing RFS program, referred to as biogas regulatory reform, requiring the RNG industry to modify how all RINs are generated. New RFS participating facilities that register on or after July 1st, 2024, will have to meet the Biogas Regulatory Reform provisions beginning July 1st, 2024. Existing RFS participating facilities that registered prior to July 1st, 2024, will have until January 1st, 2025, to come into compliance with biogas regulatory reform. For existing registrants, registration updates must be submitted by October 1st, 2024. On January 1st, 2025, all RFS participants must comply with biogas regulatory reform provisions. The EPA finalized a limitation that biogas from one facility has a single use under the RFS as proposed. The EPA clarified that this does not preclude non-RFS uses at the same facility. Over the last few quarters, we have announced a series of development projects that, in the aggregate, are expected to materially contribute to the growth of the business. During the Q3 of 2022, we announced our second facility at the Apex site. We expect this plant to increase daily production by approximately 2,100 MMBtus per day at commissioning during the second half of 2024. During the Q1 of 2023, we announced our expansion into South Carolina with our planned blue granite RNG facility. We expect this plant to increase daily production by approximately 900 MMBtus a day at commissioning in 2025. Last but not least, in June 2023, we announced our planned development of a landfill gas to RNG project in Irvine, California, at the Frank R. Bowerman Landfill. This project is anticipated to process the large and growing volumes of biogas in excess of the existing capacity of our renewable electric generation facility. With a targeted date in 2026, we currently expect the capital investment of the new RNG facility to range between $85 million-$95 million, with a production nameplate capacity of approximately 3,600 MMBtus per day, assuming currently forecasted biogas feedstock volumes that are projected to be available from the host landfill at the time of commissioning. Next, I would like to provide an update on our Pico Dairy Cluster project in Idaho. As a result of the public comment period ending March 14, 2023, without any significant comments, CARB certified our tier two application and certified CI value of -260.56, that will be used to report and generate LCFS credits. We released the remaining gas from storage in the Q2 of 2023. Related to our Pico Energy feedstock amendments, which increases the amount of feedstock supplied to the facility for processing over a three-year period, the dairy has delivered the first two increases in feedstock, and we have made the corresponding contractual payments. The efficiencies and improvements to both our feedstock digestion and water management have enabled us to process the increased feedstock volumes from the dairy. As we previously disclosed, we completed the design of the digestion capacity increase in the Q3 of 2022, and began incurring capital expenditures related to the completed design of our digestion expansion construction of the project. We continue to expect the digestion expansion project will be functionally complete during the Q3 of 2023. We also expect the dairy to begin delivering the third and final tranche of increased feedstock volumes in 2024. As to our swine waste to renewable energy development initiative in North Carolina, we continue to work with our engineer of record through the optimization and deployment of improvements to the patented reactor technology at our Turkey Creek, North Carolina location. In July 2023, we signed a renewable energy certificates agreement with Duke Energy, under which Duke will purchase the swine waste RECs from the conversion of swine waste feedstock into renewable energy at the Turkey Creek, North Carolina location. Once fully commissioned, we expect the facility to sell up to 47,000 RECs per year to Duke annually to meet the terms of that agreement. As a reminder, in the Q1 of 2023, we executed a receipt interconnection agreement with Piedmont Natural Gas for the Turkey Creek, North Carolina location. This agreement is structured to coincide with the development timeline at the Turkey Creek, North Carolina location. Lastly, I would like to highlight a recent announcement regarding our potential development opportunity to create a beneficial use of otherwise waste biogenic carbon dioxide. In July 2023, we entered into a letter of intent with a North American subsidiary of Denmark-based European Energy, which reserves the use of the CO2 for our Texas facilities. Under the terms of the LOI, we expect to contract CO2 volumes from facilities to European Energy, sufficient for their large-scale production of E-methanol. Upon final agreement execution, the delivery term is expected to last up to 15 years, with first delivery in 2026. The LOI terms allow for our capital commitments to be based on choosing technology that is most suited for the optimal delivery of the CO2 volumes to European Energy. The planned delivery is expected to prevent critical amounts of biogenic CO2 from entering the atmosphere, put it to beneficial use, and create a new fixed price commodity revenue stream for Montauk. With that, I will turn the call over to Kevin. Thank you, Sean. I will be discussing our Q2 of 2023 financial and operating results. Please refer to our earnings press release and the supplemental slides that have been posted to our website for additional information. Total revenues in the Q2 of 2023 were $53.3 million, a decrease of $14.6 million, or 21.5%, compared to $67.9 million in the Q2 of 2022. The decrease is primarily related to a decrease in pricing of gas commodity indices and average realized RIN pricing during the Q2 of 2023 compared to the Q2 of 2022. Gas commodity indices decreased 70.7% during the Q2 of 2023 compared to the Q2 of 2022. Realized RIN pricing decreased during the Q2 of 2023 to $2.16, as compared to $3.38 in the Q2 of 2022, which also contributed to the decrease in total revenues. Contributing to the decrease was the expiration of the gas commodity hedge and the elimination of our counterparty sharing agreements. We recognized gains in the Q2 of 2022 of $1.6 million related to a gas commodity hedge program. We reported the impacts of our gas commodity hedge program within our corporate segment. We have not currently entered into any gas commodity hedge programs for 2023. We also recognized revenues of approximately $1.1 million in the Q2 of 2022 under our previous counterparty sharing agreements. Total general and administrative expenses for the Q2 of 2023 were $8.7 million, which was flat as compared to $8.7 million for the Q2 of 2022. Increased rental expense and stock-based compensation expense as a result of stock option grants to our executives in the Q2 of 2023, and the 2022 amendments to the Montauk Ag Renewables acquisition stock awards, were offset by the forfeiture of restricted stock and lower professional fees. The 2023 option awards vest ratably over a period of 3 to 5 years. Turning to our segment operating metrics, I'll begin by reviewing our renewable natural gas segment. We produced 1.4 million MMBtu of RNG during the Q2 of 2023, a decrease of less than 0.1 million compared to 1.4 million MMBtus produced in the Q2 of 2022. Our Rumpke facility produced approximately 0.1 million less MMBtu in the Q2 of 2023 compared to the Q2 of 2022, as a result of process equipment failure in the Q2 of 2023, which temporarily impacted production. The process equipment which failed, has been repaired. Our Pico facility produced approximately 0.1 million less MMBtu in the Q2 of 2023 compared to the Q2 of 2022, due to feedstock processing challenges. Our Galveston facility produced less than 0.1 million more MMBtus in the Q2 of 2023 compared to the Q2 of 2022, as a result of process equipment modifications. Revenues from the renewable natural gas segment in the Q2 of 2023 were $48.6 million, a decrease of $16 million or 24.7% compared to $64.6 million in the Q2 of 2022. Average quantity pricing for natural gas for the Q2 of 2023 was $2.10 per MMBtu, 70.7% lower than the Q2 of 2022. During the Q2 of 2023, we self-monetized 17.4 million RINs, representing a 3 million RIN increase or 20.8% compared to 14.4 million RINs in the Q2 of 2022. Average realized pricing on RIN sales during the Q2 of 2023 was $2.16, as compared to $3.38 in the Q2 of 2022, a decrease of 36.1%. This compares to the average D3 RIN index price for the Q2 of 2023 of $2.16, being approximately 32.9% lower than the average D3 RIN index price in the Q2 of 2022. At June 30th, 2023, we had approximately 0.4 million MMBtus available for RIN generation and had approximately 3 million RINs generated and unsold. At June 30th, 2022, we had approximately 0.4 million MMBtus available for RIN generation and had approximately 1.1 million RINs generated and unsold. Our profitability is highly dependent on the market price of environmental attributes, including the market price for RINs. As a result, at June 30th, 2023, we had approximately 3 million RINs in inventory, an increase of 167.5% compared to June 30th, 2022. As Sean previously noted, we entered into commitments to transfer during July 2023 all of these RINs generated but unsold. Our average realized RIN price for these July 2023 transfers were priced at or in excess of the July 2023 average D3 RIN index price of $3.06. Our operating and maintenance expenses for our RNG facilities in the Q2 of 2023 were $11.7 million, an increase of $0.7 million, or 6.5%, compared to $11 million in the Q2 of 2022. The primary driver of this increase was related to the timing of preventative maintenance expenses during the Q2 of 2023 at our Apex and Atascocita facilities. Contributing to the increase in the Q2 of 2023 were wellfield operational enhancements at our Atascocita and Coastal facilities. We produced approximately 49,000 megawatt hours in renewable electricity during the Q2 of 2023, an increase of approximately 2,000 megawatt hours compared to 47,000 megawatt hours in the Q2 of 2022. Our Security facility produced approximately 1,000 megawatt hours more in the Q2 of 2023 compared to the Q2 of 2022, due to engine maintenance completed in the Q2 of 2022. Revenues from renewable electricity facilities in the Q2 of 2023 were $4.6 million, an increase of $0.3 million or 7.3%, compared to $4.3 million in the Q2 of 2022. The increase is primarily driven by the increase in our renewable electricity production volumes. Our renewable electricity generation operating and maintenance expenses in the Q2 of 2023 were $3.4 million, a decrease of $0.4 million, or 10%, compared to $3.8 million in the Q2 of 2022. The decrease is primarily related to scheduled preventative maintenance at our Bowerman facility, which was approximately $0.7 million higher in the Q2 of 2022 compared to the Q2 of 2023. Our Turkey Creek facility operating and maintenance expenses increased approximately $0.2 million as a result of non-capitalizable costs from Montauk Ag Renewables. We calculated and recorded an impairment loss of $0.3 million in the Q2 of 2023, an increase of $0.2 million compared to $0.1 million in the Q2 of 2022. The impairments in the Q2 of 2023 were for specifically identified RNG machinery and equipment that were no longer in operational use. Other than these discrete events, we did not record any other impairments related to future cash flows. Operating income in the Q2 of 2023 was $13.6 million, a decrease of $10.4 million or 43.4% compared to $24.0 million in the Q2 of 2022. RNG operating income for the Q2 of 2023 was $23 million, a decrease of $12.2 million or 34.7% compared to $35.2 million in the Q2 of 2022. Renewable electricity generation operating loss for the Q2 of 2023 was $0.6 million, a decrease of $0.8 million or 58.7% compared to $1.4 million in the Q2 of 2022. Turning to the balance sheet, as of June 30th, 2023, $68 million was outstanding under our term loan. Our capacity available for borrowing under the revolving credit facility was approximately $117.6 million. During the Q2 of 2023, we generated $6.1 million of cash from operating activities, a decrease of $20.7 million, or 77.2%, compared to $26.8 million of cash provided by, provided by operating activities in the Q2 of 2022. For the Q2 of 2023, our capital expenditures were $29.6 million, of which approximately $9.8 million, $5 million, $6.7 million, and $3 million were related to the ongoing Pico facility digestion capacity increase, our Montauk Ag Renewables development in North Carolina, the second Apex RNG facility, and the South Carolina Blue Granite RNG project, respectively. As of June 30th, 2023, we had cash and cash equivalents of approximately $78.1 million. On June 21st, 2023, we entered into the third amended and restated loan agreement and secured promissory note, by and between Montauk and Montauk Holdings Limited, amending and restating in its entirety the second loan agreement and security promissory note, as amended. The MNK amendment increases the principal amount of the loan from its current balance of $8.9 million to a total of $10 million in the aggregate, and extends the maturity date of the loan from June 30th, 2023 to December 31st, 2023, and increases our security interest from 800,000 shares to 976,623 shares of common stock of Montauk, owned by Montauk Holdings Limited. The terms of the MNK amendment are otherwise substantially similar to the MNK loan agreement. As previously disclosed, we entered into the MNK loan agreement in accordance with our obligations set forth in the Transaction Implementation Agreement, entered into by and among us, Montauk Holdings Limited, and other party in connection with our 2021 initial public offering. Adjusted EBITDA for the Q2 of 2023, was $19.2 million, a decrease of $8.4 million, or 30.4%, compared to $27.6 million for the Q2 of 2022. EBITDA for the Q2 of 2023, was $18.9 million, a decrease of $10.2 million or 35.1%, compared to $29.1 million for the Q2 of 2022. Net income for the Q2 of 2023 decreased $18.1 million, or 94.8%, over the Q2 of 2022. This decrease was primarily related to a reduction of revenues due to a decrease in pricing of gas commodity indices and average realized RIN pricing. I'll now turn the call back over to Sean. Thank you, Kevin. In closing, we would like to provide an updated full year 2023 outlook. While we don't provide guidance on our expectations of future environmental attribute pricing, volatility in index pricing does impact our revenue expectations. We continue to expect RNG production volumes to range between 5.7 million and 6.1 million MMBtus, and have increased the corresponding RNG revenues to between $160 million and $175 million. We expect renewable electricity production volumes to range between 195,000 and 200,000 megawatt hours, with corresponding renewable electricity revenues between $18 million and $19 million. With that, we will pause for any questions. Thank you. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please limit yourself to one question and then re queue. Please stand by while we compile the Q&A roster. Our first question will come from Manav Gupta with UBS. Your line is open. Guys, I just want to say, you know, a lot of times we see companies trying to make trading decisions and they completely mess it up. Your decision to not sell RINs in 1Q was an absolute masterstroke. I have never seen a strategy executed so well. Congratulations on that. My question here is: you announced something very interesting, an agreement with Duke Energy. Can you talk a little bit more about why it makes strategic sense, how it adds value over a period of time, and the benefits of this agreement? Sure, Manav. One, thank you very much for the compliment regarding the RIN strategy. The company continues to focus its monetization strategy by prioritizing its sales directly to the obligated parties under the Renewable Fuel Standard. By doing that, and synchronizing the timing at which they satisfy their obligations throughout the year, you know, the timing of the release, the favorable release of the obligations for 2023 through 2025, couldn't have been better matched with the timing of that demand side coming from the obligated parties, so thank you. With respect to the Duke agreement, it's highly beneficial in a number of ways. One, you start to see the advancement of, sort of the regulatory environment in North Carolina, that is starting to acknowledge and prioritize renewable electricity credits coming from the conversion of swine waste into renewable energy. The second, and, and equally as important, for that first project that we are developing with that newly patented reactor technology, is, the fact that it is a fixed commodity price. Businesses, as you indicated through your comment initially, you end up at, some measured degree of volatility in monetizing your attribute pricing. To be able to bolster a phenomenal project, for the environment and for the diversification of our product suite, to be able to do that under a fixed price contract, further underpins the security of the revenue and the EBITDA streams to allow for us to continue our strategy on the floating piece of the business in the form of the timing and to who the off-takers are of our environmental attributes. Thank you. Our next question will come from Craig Shere with Tuohy Brothers. Your line is open. Hi, I'd like to dig in a little more on your comments around the Duke REC agreement. If I recall correctly, the swine opportunity in North Carolina was envisioned as possibly 20 projects over 5 years. How does this kind of, you know, in terms of its size and chunkiness, kind of fit into that? Craig, yeah, that's a, that's a great question. The Duke arrangement represents the first stage of not a 20-project deployment, but a deployment of up to 20 reactors. The primary focus is on the collection and the processing on a per ton basis of swine waste in and around those communities of Eastern North Carolina. The Duke arrangement allows for the first deployment of the tranche of reactors that we're continuing to optimize and increasing the throughput that will continue to create a diversity of environmental projects, products in the form of biochar and natural gas, renewable natural gas, and renewable electricity, and in the RECs. It is an anchor arrangement that starts that monetization process and gives us a line of sight as to when the project will, in turn, contribute to EBITDA. Thank you. Thank you. One moment for our next question. We have a question from Matthew Blair with TPH. Your line is open. Hey, Sean and Kevin, congrats on the strong results. I wanted to just dig in a little bit more on the details of the RIN monetization in Q2. I believe you said that 17.4 million RINs were monetized at the $2.16 price. Is your regular run rate on RIN generation per quarter approximately 12 million? Just doing the math there, the 17 minus 12 times the $2.16, should we think about that extra boost in Q2 as around, you know, $10 million, maybe $11 million of EBITDA? As we look into Q3, it sounded like the remaining 3 million of RIN inventory were sold at $3.06. That'd be roughly a $9 million boost as we look into Q3 on, on top of your regular operations. Is that the right way to think about those moving parts on, on the RIN inventory? Generally, Matthew, yeah, you can look at it that way. Also, don't forget, you're gonna have to account for the carryover RINs exiting the Q1 that would have been sold, recognizing revenues and monetized in the Q2 as well. Into the Q3, yeah, we, we, we, we, we highlighted the D3 index price, but did make a comment that, you know, our, our Q3 commitments of the RINs generated and unsold in July of 2023, were at or above that index price. Generally, how you're getting to your math of contribution from RIN pricing in the Q2 and the Q3, is, is, is generally geographically aligned to what we're trying to convey. Thank you. Our next question comes from Ryan Pfingst with B Riley. Your line is open. Hey, guys, congrats on all the recent developments here. Kind of a higher-level question around the RVO. With it being the first time we've had a multi-year RVO, can you talk about what that might mean for the industry and how it could benefit you guys in particular as a producer? In general, Ryan, we do not comment on pricing speculation for the attributes, but definitively, having a demand range of clarity for multiple years, does and will likely shape the landscape of development opportunities, acquisition opportunities, as folks are starting to determine the level of supply that'll go across the industry. We are active participants in Renewable Natural Gas Coalition, and that information is routinely aggregated for EPA comment as they go through the RVO. There's always a mindset where we are trying to determine what that supply-demand mechanic looks like, particularly in the absence of a formal cellulosic waiver credit. Beyond that, we typically don't focus on guidance or commentary associated with what the pricing outlook could look like for those attributes in this year and beyond. Thank you. Looks like we have a follow-up from Matthew Blair with TPH. Your line is open. Hey, thanks for taking my follow-up. On the swine RNG efforts, you know, you seem to be making good progress. I would say Montauk is certainly a leader in this space. Could you just talk about, you know, what's your competitive edge on, on swine RNG? Is it technology? Is it people? Is it relationships or, or maybe something else? Sure, Matthew. As we have disclosed in previous quarters, our patented reactor technology allows for a very efficient processing of the swine waste in sort of a spoken hub type of fashion, that allows for the optimal conversion of the swine waste into the various elements of biochar, renewable natural gas, and renewable electricity. It is, essentially an opportunity to do what traditional digestion methods do in a fraction of the time, with a more compact, more reliable piece of technology, and demonstrate that with folks like Duke Energy and with other folks, as we look to monetize all of the commodity and attribute streams of that project. In general, that would be our largest competitive advantage. Thank you. We have one more follow-up from Manav Gupta with UBS. Your line is open. Quickly on this carbon dioxide agreement with the European Energy. This is a somewhat newer concept for us. Help us understand some of the benefits of this. I understand the deliveries are starting in 2026, but, help us understand where this can take you and what are the real benefits of delivering this to this European Energy company. Thank you. Sure, Manav. The opportunity for us to take a natural consequence of our operational facilities in the form of biogenic CO2 that is being destroyed in our thermal oxidizer, has routinely only been available for the generation of tax credits, requiring you to be able to utilize those tax credits. Coming out of the Inflation Reduction Act and the evolution of those credits that are also tradable, alongside of that has been the opportunity to actually monetize the CO2, and in this opportunity, partnering with an exemplary business that has been able to utilize that for the creation of E-methanol. The opportunity to look beyond this initial arrangement definitively exists across our entire portfolio and exists in the form of actual CO2 that is destroyed in our thermal oxidation process, but also exists in the form of CO2e, an avoidance that happens at projects similar to what we are doing in North Carolina, where the CO2e would be primarily focused on the generation of tax credits because the equivalent obviously cannot be sold as a commodity. All of our operating facilities are capturing and destroying carbon dioxide, which can be used as a commodity as we start to look across the portfolio. We're very excited for this first opportunity. Again, the benefits to us, similar to the Duke arrangement that we have done in North Carolina, is bolstering the business with fixed price revenue streams and the ability to allow for a stronger, more patient ability to monetize our environmental attributes in the hands of the obligated parties and allow for that timing to unfold throughout the year. Thank you. I'm showing no other questions in the queue. I'd like to turn the call back over to Sean McClain for any closing remarks. 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 on our 2023 Q3 conference call. Thank you. This concludes today's conference call. You may now disconnect.