EDGAR 10-K Filing

Company CIK: 1826600
Filing Year: 2025
Filename: 1826600_10-K_2025_0000950170-25-039495.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS.
Unless the context requires otherwise, references to “Montauk,” the “Company,” “we,” “us” or “our” refer to Montauk Renewables, Inc. and its consolidated subsidiaries.
Overview
We are a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources to beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply renewable fuel into the transportation and electrical power sectors. We are one of the largest U.S. producers of RNG, having participated in the industry for over 30 years. We established our currently operating portfolio of eleven RNG and two Renewable Electricity projects and development projects through self-development, partnerships, and acquisitions that span seven states.
Corporate History
On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange (the “Equity Exchange”) and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by Montauk USA, and Montauk Renewables became a direct wholly-owned subsidiary of MNK. Prior to the Reorganization Transactions, MNK’s business and operations were conducted entirely through Montauk USA and its U.S. subsidiaries, and MNK held no substantial assets other than equity of Montauk USA. The Company had no significant operations or assets prior to January 4, 2021, when it engaged in the equity exchange with Montauk USA and MNK.
After completion of the Reorganization Transactions, (i) Montauk USA ceased to own any substantial assets and (ii) all entities through which MNK’s business and operations were conducted became owned, directly or indirectly, by the Company. MNK adopted a plan contemporaneously with the completion of the Reorganization Transactions that authorized the future liquidation and dissolution of MNK.
On January 15, 2021, MNK sold the membership interest of Montauk USA to a third party. On January 26, 2021, MNK distributed all of the outstanding shares of the Company’s common stock as a pro rata dividend to the holders of MNK’s ordinary shares (the “Distribution”), subject to any tax withholding obligations under applicable South African law. Each ordinary share of MNK outstanding on January 21, 2021, the record date for the Distribution, entitled the holder thereof to receive one share of the Company’s common stock.
On January 26, 2021, the Company closed the initial public offering of its common stock on the Nasdaq Capital Market (the “IPO”) with the shares traded under the symbol “MNTK.” Montauk Renewables issued 2,702,500 shares at $8.50 per share and received gross proceeds of $22,971. The Company’s common stock was also secondarily listed on the Johannesburg Stock Exchange under the trading symbol “MKR.”
On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (as amended, the “Promissory Note”) with MNK. MNK is currently an affiliate of the Company and certain of the Company’s directors are also directors of MNK. Pursuant to the Promissory Note, the Company initially advanced a cash loan of $5,000 to MNK for MNK to pay its dividends tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended (the “South African Income Tax Act”). The current principal balance of the Promissory Note is $10,690 and the maturity date is December 31, 2033. The Company holds a security interest in 976,623 shares of common stock of the Company held by MNK. MNK is required to use the proceeds of any sale of the shares to repay the Promissory Note. The Promissory Note has default provisions pursuant to which MNK will deliver any unsold shares of the Company back to the Company to satisfy repayment of the Promissory Note.
MNK was delisted from the JSE on January 26, 2021. The MNK Board of Directors and Shareholders held its annual general meeting in March 2023 and voted to take MNK private.
Products Sold
The revenues Montauk receives from selling renewable energy consist of two main components. The first component consists of revenues from the commodity value of the natural gas or electricity generated, which we sell through a variety of term-length
agreements. The second component consists of revenues from the Environmental Attributes derived from the production of RNG and Renewable Electricity.
Our current operating projects produce either RNG or Renewable Electricity by processing biogas from landfill sites or agricultural waste from livestock farms. Biogas is produced by microbes as they break down organic matter in the absence of oxygen (during a process called anaerobic digestion). Our two current sources of commercial scale biogas are LFG or ADG. We typically secure our biogas feedstock through long-term fuel supply agreements and property lease agreements with biogas site hosts. Once we secure long-term fuel supply rights, we design, build, own, and operate facilities that convert the biogas into RNG or use the processed biogas to produce Renewable Electricity. Once collected, biogas can be processed into pipeline-quality RNG or converted into electricity. The conversion facility is typically located on landfill property away from the active fill operations where additional waste is added to the landfill site. Because we are capturing waste methane and making use of a renewable source of energy, the RNG and Renewable Electricity we produce also generates valuable Environmental Attributes which we can monetize under federal and state renewable initiatives.
RNG
The RNG we process is pipeline-quality and can be used for transportation fuel when compressed or liquefied. Virtually all of the RNG we produce is used as a transportation fuel because this market generally provides the most value for our RNG production. CNG has been the most common fuel used by fleets where medium-duty trucks are close to the fueling station, such as city fleets, local delivery trucks and waste haulers. Additionally, landfill gas and gas from livestock digesters can be processed into pipeline-quality RNG by removing the majority of the non-methane components including carbon dioxide, water, sulfur, nitrogen, and other trace compounds.
RNG, like traditional natural gas, is traded nationally. Once in an interstate pipeline, RNG can be transported to vehicle fueling stations to be used as a transportation fuel, to utilities to generate power, or for use in generating fuel cell energy anywhere within the North American pipeline system. This flexibility enables us to capture value from the renewable attributes of biogas by delivering RNG to markets and customers that place a premium on renewable energy. Although RNG has the same chemical composition as natural gas from fossil sources, government incentive programs assign unique Environmental Attributes to it due to its origin from low-carbon, renewable sources, which we also monetize.
RNG is priced in-line with the wholesale natural gas market, based on Henry Hub pricing, with regional variation according to demand. We sell the RNG produced from our projects under a variety of short-term and medium-term agreements to counterparties, with tenures generally varying from three to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. We also share a portion of our Environmental Attributes with certain pathway providers as consideration for the counterparty using our RNG as a transportation fuel.
Renewable Electricity
Renewable electricity is generated using gas-fueled engines or turbine-driven electrical generators, which are designed to operate efficiently on medium-Btu gas. As such, electricity generation typically involves producing medium-Btu gas, which is then pumped into a generating facility. Electricity is a commodity that trades and is priced on a regional basis in and among regional control areas. Pricing for commodity-sold electricity can be based on day-ahead prices for scheduled deliveries or hourly, real-time prices for unscheduled deliveries. Prices vary across the country based on weather, load patterns and local or regional power and transmission restrictions. The Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price with escalators. The terms of these contracts range up to 19 years, excluding renewal periods, with a weighted average remaining tenure of 17 years, based on 2024 electricity production.
Environmental Attributes
When used as a transportation fuel or to produce electricity, RNG can generate additional revenue streams through the generation and sale of Environmental Attributes under various programs, including the national renewable fuels standard and state-level California LCFS. The Environmental Attributes that we generate and sell are composed of RINs and LCFS credits, which are generated from the conversion of biogas to RNG that is used as a transportation fuel, as well as RECs generated from the conversion of biogas to Renewable Electricity. In addition to revenues generated from our product sales, we also generate revenues by providing various value-added services to certain of our biogas site partners. In 2024 and 2023, our projects generated approximately 6.2% and 7.7%, respectively, of all CNG and LNG D3 RINs in the United States. During 2021, we entered into an agreement to sell a portion of our production as a renewable component of refinery fuel exports into the European Union’s Renewable Energy Directive from certain RNG production facilities that have achieved International Sustainability & Carbon Certification registration. This diversification strategy accounted for approximately 1.1% of the reduction in generation of D3 RINs in 2024. We continue to sell a portion of our production as a renewable component of refinery fuel exports.
We seek to mitigate our exposure to commodity and Environmental Attribute pricing volatility. Through contractual arrangements with our site hosts and counterparties, we typically share pricing and production risks while retaining our ability to benefit from potential upside. A portion of the RNG volume we produce is sold under bundled fixed-price arrangements for the RNG and Environmental Attributes, some of which include a sharing arrangement where we benefit from prices above certain thresholds. For our remaining RNG projects, our partners may receive a cash payment instead of in-kind sharing arrangements where our partners receive the Environmental Attributes, thereby sharing in Environmental Attribute pricing risk.
On the electricity side of our business, all of our products and related Environmental Attributes are sold under fixed-price contracts with escalators, limiting our pricing risk. Finally, our contracts with site hosts often require payments to our site hosts in the form of royalties based on realized revenues, direct development contributions, or, in some select cases, based on production volumes.
D3 RINs
RNG has the same chemical composition as natural gas from fossil sources, but has unique Environmental Attributes assigned to it due to its origin from organic sources. These attributes qualify RNG as a renewable fuel under the federal RFS program, established pursuant to the EPACT 2005 and EISA, allowing RNG to generate renewable fuel credits called RINs when the RNG is used as a transportation fuel.
RINs are saleable regulatory credits that represent a quantity of qualifying fuel and are used by refiners and importers to evidence compliance with their RFS obligations. Given that the RFS is a national program, the price of a RIN is the same anywhere in the United States. The RFS program originally contemplated 1.75 billion gallons of fuel from cellulosic biofuels by 2014, the use of which would be tracked through D3 RINs. However, cellulosic biofuel production grew slower than expected and prompted the EPA to expand the definition of biofuels that could qualify for D3 RINs to include fuels from cellulosic biogas, including biogas from landfills, livestock farms, and WRRFs. This significantly increased the quantity of D3 RINs produced, with production increasing to approximately 33 million net RINs in 2014 and approximately 704 million net RINs in 2023. In addition, given the historic shortage in supply of D3 RINs to meet blending requirements, the EPA allows obligated refiners to satisfy RFS compliance obligations for D3 RINs by either purchasing CWC plus D5 RINs or by purchasing D3 RINs. CWC prices were set annually and were typically published by the EPA each November. Historically, the value of a D3 RIN is therefore a derivative of the market price for D5 RINs and CWCs, which in turn, are inversely linked to the wholesale price of gasoline. On July 12, 2023, the EPA issued final rules in the Federal Register which indicated that it will not be utilizing its cellulosic waiver authority to reduce cellulosic biofuel volume for 2023-2025, thus CWCs will not be available unless actual production is lower than the RVO. On December 5, 2024, the EPA proposed rules to partially waive the 2024 cellulosic biofuel volume requirement using the general waiver authority and revise the associated percentage standard under the RFS. Despite this proposed rule, the EPA has indicated it will not utilize the CWC. This rule has not yet been finalized and, under the current administration’s rollback of climate policies, it is not certain when or if it will be finalized in 2025.
The EPA is still expected to release the 2026 RVO in March 2025, according to the Fall Unified Agenda and Regulatory Plan from the White House Office of Management and Budget, published on Friday December 13, 2024. However, with a new president in office, on February 20, 2025, U.S. oil and biofuel groups banded together to urge the new Trump administration to increase volumes of renewable fuels that must be blended into the nation’s fuel mix in 2026 and beyond.
We have been active in the RFS program since 2014 and expect to remain a significant contributor to the overall generation of RINs from RNG. We monetize our portion of the RINs, directly, at auction or through third-party agents or marketers.
CA LCFS
CA LCFS credits are environmental credits generated in California in order to stimulate the use of cleaner, low-carbon fuels. This program encourages the production of low-carbon fuels by setting annual CI standards, which are intended to reduce GHG emissions from the state’s transportation sector. One of the key aspects of the program is that it encourages the use of low-carbon transportation fuel, such as CNG, in vehicles instead of gasoline. This program further encourages use of renewable fuels in vehicles over CNG from fossil fuels.
The value of an CA LCFS credit varies according to the CI value of the fuel source as determined by CARB. Fuels that have a lower CI score benefit from a higher percentage of a CA LCFS credit. RNG from LFG and livestock digester biogas that are used as a transportation fuel both qualify for CA LCFS credits. The number of CA LCFS credits for RNG from livestock digesters is significantly higher than the number of CA LCFS credits for RNG from landfills, due to the relative CI scores of the two fuels. Fuel that is eligible for RINs can also receive CA LCFS credits. As a result, CA LCFS credits represent a revenue stream incremental to the value RNG producers receive for RINs. For livestock digester RNG projects, CA LCFS credits are a substantial revenue driver. We have four projects that are currently approved and eligible to earn CA LCFS credits, one of which is a livestock digester RNG project. Because of the growth in the number of RNG projects developed in 2023-2024, the CA LCFS program has been saturated in credits. As a result, the lower CI score projects (e.g. livestock digester RNG projects) have the financial advantage of being accepted into the
LCFS program. We expect the revenue generated by CA LCFS credits to increase as we continue to develop and bring additional livestock digester projects online over the next few years.
On January 3, 2025, CARB submitted to the State of California Office of Administrative Law ("OAL") proposed amendments to the LCFS regulations. On February 18, 2025, the OAL notified CARB that it disapproved the proposed regulatory action pursuant to the Administrative Procedure Act ("APA"). In referencing the APA, the OAL found that the language of many of the proposed regulations was unclear and confusing to persons who must comply with the regulations. CARB may rewrite and resubmit the amendments to OAL within 120 days of its receipt of OAL’s written decision (by June 2025), which CARB has said it plans to do.
Several states in the United States also have or are considering adopting this model. Oregon’s Clean Fuels Program, enacted in 2009 and implemented in 2016, operates using a credit system similar to the CA LCFS program. Washington’s Clean Fuel Standard was passed in 2021 and implemented in 2023 utilizing a similar credit system as Oregon and California. New Mexico’s Clean Fuel Standard was passed in 2024 with plans to finalize implementation in 2026. Similar to RINs, LCFS credits can be sold separately from the RNG fuel sold, allowing us to monetize LCFS credits for fuel produced and purchased outside of states that have LCFS programs.
RECs
The primary Environmental Attributes derived from the production of electricity from renewable resources are RECs, which translate into additional revenues for units of Renewable Electricity produced. Biogas is considered to be a renewable resource in all 37 states that encourage or mandate the use of renewable energy. Thirty states, the District of Columbia, and Puerto Rico have RPS that require utilities to supply a percentage of power from renewable resources, and seven states have a Renewable Portfolio Goal that is similar to RPS, but it is an objective or goal and not a requirement. Many states allow utilities to comply with RPS through tradable RECs, which provide an additional revenue stream to RNG projects that produce electricity from biogas.
The value of a REC is dependent on each state’s renewable energy requirements as mandated by its RPS. REC values are higher in states that require a percentage of total electricity to come from renewable resources. In states with no renewable energy requirements, RECs can have no value at all. In some markets, we have entered into PPAs under which we sell RECs bundled with the power being sold at a combined price. This occurs where the utility off-take counterparty offers a combined rate for the renewable energy it needs to satisfy RPS or other business requirements that is the best combined price for one of our projects.
Strategic Overview
Our business strategy focuses on the following three areas that we believe present the greatest growth opportunities for the Company at this time.
•Continued Expansion into Agricultural Feedstocks for RNG Production
•Optimize Existing Assets and Project Portfolio and Opportunistically Develop New Projects
•Valued-added Service Offerings
Continued Expansion into Agricultural Feedstocks for RNG Production
As part of our long-term strategy, we are focused on diversifying our project portfolio beyond LFG through expansion into additional methane producing assets, while opportunistically adding third-party developed technology capabilities to boost financial performance and our overall cost competitiveness. We are commercially operating our first agricultural waste project (dairy manure), actively pursuing new fuel supply opportunities in WRRFs, and looking at long-term organic waste and sludge opportunities for the generation of biogas.
We view dairy farms and other forms of organic agricultural waste as a significant opportunity for us to expand our RNG business, as processing biogas from dairy farms and from other forms of organic agricultural waste requires similar expertise and capabilities as processing biogas from landfills. Many of the existing biogas processing in these industries is for electricity production, which creates additional opportunities for acquisition and conversion to higher-value RNG facilities.
Pico Facility
We undertook an agricultural project when we closed on the acquisition of Pico, the anaerobic digester and two Jenbacher engines at the Bettencourt dairy farm in Jerome, Idaho in September 2018. The project sources manure from a dairy farm with up to approximately 18,500 milking cows. While Pico was initially a Renewable Electricity site, we brought an RNG facility at that location online in 2020. The facility sells transportation fuel into the California transportation market. The collection of the fuel supply is potentially easier at dairy farms than at landfills due to higher quality, more uniform feedstock, and potentially less volatility in inlet
gas and biogas collection in a more controlled environment. During the second quarter of 2021, we amended our Pico feedstock agreement (“Pico Feedstock Amendment”). The amendment increased the amount of feedstock supplied to the facility for processing over a four-year period.
As part of our overall capacity expansion at the Pico facility, in 2021 and 2024, we undertook significant efforts to improve the performance of the existing digestion process at our Pico facility. We temporarily idled RNG production at this facility in order to clean out settled solids in the digester, replace the cover of the digester, and make various other efficiency improvements. The dairy began delivering the first and second increases in feedstock during the third quarter of 2022 and we have made two payments to the dairy as required in the Pico Feedstock Amendment. The improved efficiencies of our existing digestion process and the water management improvements have enabled us to process the increased feedstock volumes. We completed the design of the digestion capacity expansion project in 2022, commenced construction of the digestion expansion, and commissioned the digestion expansion project in 2024. We currently expect the dairy to begin delivering the final increase in feedstock volumes during 2025 when we will make the final payment to the dairy as required under the Pico Feedstock Amendment.
CARB finalized in the first quarter of 2023 Pico's initial CI Score Pathway model. We have been recognizing revenues from RINs and LCFS credits since the fourth quarter of 2022.
Montauk Ag Renewables
In 2021, through our wholly owned subsidiary, Montauk Ag Renewables, we completed an asset purchase related to developing technology to recover residual natural resources from waste streams of modern agriculture and to refine and recycle such waste products through proprietary and other processes to produce high quality renewable natural gas to generate renewable electricity, to generate North Carolina swine RECs, and to produce micronutrient organic fertilizer alternatives (the "Montauk Ag Renewables Acquisition”). The assets acquired include real property, intellectual property, mobile equipment, and other equipment related to operating the business and real property of an approximate 9.35 acre parcel in Magnolia, North Carolina. We subsequently closed on a transaction to acquire approximately 146 acres and an approximately 500,000 square foot existing structure in Turkey, North Carolina where we plan to consolidate and expand the production processes purchased in the Montauk Ag Renewables Acquisition. In February 2024, we purchased approximately 41 acres of undeveloped land contiguous to our already existing acreage at our Turkey, North Carolina location.
While these project developments continue, we continue to engage with regulatory agencies in North Carolina related to the resulting power generation derived from swine waste to confirm its eligibility for RECs under North Carolina’s Clean Energy and Energy Efficiency Portfolio Standards ("CEPS") in anticipation of commercial production. The Turkey location was approved to participate in the Piedmont Natural Gas Renewable Gas Pilot Program which is a step towards obtaining the New Renewable Energy Facility (“NREF”) designation under the North Carolina Utilities Commission ("NCUC"). In January 2024, we received notification from the NCUC that the Turkey, NC location was approved for an NREF and Certificate of Public Convenience and Necessity. In October 2024, our amended NREF application was approved.
In 2024, the North Carolina legislature approved a statutory change to its CEPS governing the generation of RECs from swine waste that established a REC multiplier for swine waste produced in a Tier 1 county. Our Turkey, NC location is located in Sampson County, NC, which is a Tier 1 county. The implementation of this change continues and is subject to limitations, including but not limited to, the annual generation of swine RECs. We signed a receipt interconnection agreement with Piedmont Natural Gas Company, Inc. ("Piedmont") for the Turkey, NC location, with the agreement structured to coincide with the development timeline at that location, which has been accepted into the Piedmont RNG Pilot Program.
We continue to develop the opportunities associated with Montauk Ag Renewables and can give no assurances that our plans related to this acquisition will meet our expectations. Utility interconnection, both inbound to and outbound from our centralized Turkey, NC processing facility is dependent on factors outside of our control. Regulatory development and offtake negotiations could delay our ability to fully optimize or meet the timing expectations related to revenue producing activities. We continue to design and plan for the development of the Turkey, North Carolina facility to be used for commercial production. We do not currently expect commercial production to commence until 2026 based on the current development timeline. We intend to contract with additional farms to secure feedstock sources, as we commission commercial production and increase our production capabilities, which we anticipate will secure additional feedstock for future production processes.
Other Opportunities
Other industries that present opportunities of scale for biogas conversion include swine farms and WRRFs. Biogas production from swine farms is a nascent biogas industry with great growth potential because swine manure is the second largest source of manure methane from livestock and only a small percentage of farms currently have biogas conversion capabilities. Additionally, while a larger percentage of WRRFs have biogas processing facilities, many process biogas for electricity production creating
additional opportunities for acquisition and conversion to RNG facilities. As with LFG and dairy farms, biogas from both swine farms and WRRFs qualify for D3 RINs under the RFS program. We believe our demonstrated versatility to operate processing facilities using multiple fuel supply sources will give us a competitive advantage in these markets relative to other new entrants who have only demonstrated capabilities with one fuel supply source. The drive toward voluntary and most likely regulatory-required organic waste diversion from landfills is of particular interest as we leverage our current experience base. As our biogas processing technology continues to improve and the required energy intensity of the RNG and Renewable Electricity production process is reduced, we expect that we will be able to enter new markets for our products.
Optimize Existing Assets and Project Portfolio and Opportunistically Develop New Projects
Expanding Operations at Existing Project Sites. We monitor biogas supply availability across our portfolio and seek to maximize production at existing projects by expanding operations when economically feasible. Most of our landfill locations continue to accept waste deliveries and the available LFG at these sites is expected to increase over time, which we expect to support expanded production. In 2024, this has allowed us to maintain average production availability of approximately 92% at our RNG projects and 93% at our Renewable Electricity projects.
We treat our existing assets as an integrated portfolio rather than a collection of individual projects. This allows us to utilize any new business practices or technologies across our entire project portfolio quickly, including advances with respect to troubleshooting, optimization, cost savings, and host site interaction. Our integrated, pro-active and value-add approach helps us maintain strong relationships with our partners, which we seek to leverage to optimize the performance of our existing projects.
In addition to monitoring biogas supply, we are incorporating similar collection and processing used for our biogas supply to our byproduct streams to capture, clean, and liquefy biogenic carbon dioxide at our existing projects. In February 2024, we announced our first agreement for certain of our Texas facilities related to biogenic carbon dioxide collection.
We also experience organic growth in production at our existing projects as a result of increases in biogas supply at our projects and on-going optimization initiatives. We size our projects to account for this increase in the biogas supply curve over time. For example, at many of our newer projects, such as Apex and Galveston, we expect gradual increases in production as those landfill sites continue to grow. Additionally, many of our capacity expansion efforts to date, such as those at McCarty, Rumpke, and Pico, have helped to optimize our project capacity to take advantage of excess biogas at older landfills that are still open and growing. Not only have our projects achieved an initial increase in production following the capacity expansion project, but we also expect to see continued gradual increases in production over time.
Converting Existing Renewable Electricity Projects to RNG. We periodically evaluate opportunities to convert existing projects from electricity generation to RNG production. These opportunities tend to be attractive for our merchant electricity projects given the favorable economics for RNG plus RIN sales relative to merchant electricity rates plus REC sales. To date, we have converted two projects from LFG-to-electricity to LFG-to-RNG and a third project from ADG-to-electricity to ADG-to-RNG. We will continue to explore the feasibility of other opportunities across our remaining Renewable Electricity portfolio.
Opportunistic Development of New RNG Projects. We apply a financially disciplined model toward new project development that considers the relative risk of a given project and associated feedstock costs, offtake contracts and any other related Environmental Attributes that can be monetized. We are currently developing two project expansion opportunities at existing project sites and one project at a new project site. We regularly analyze potential new projects that are at various stages of negotiation, engineering design and financial review. The potential projects typically include a mix of new project sites and strategic acquisitions. Currently, no new potential projects are subject to definitive agreements and each potential opportunity is subject to competitive market conditions.
Developing LFG to Renewable Electricity Projects. We continue to analyze for future development to include sites from which we would generate renewable electricity. This evaluation of potential new renewable electricity projects would be reviewed with the same financially disciplined model we use to evaluate new LFG-to-RNG projects.
The RNG industry remains highly fragmented. We believe continued industry fragmentation presents an opportunity for further industry consolidation. We are well-positioned to take advantage of this consolidation opportunity because of our scale, operational and managerial capabilities, and execution track record in integrating acquisitions. Over the last ten years, we have acquired 13 projects and members of our current management team have led all of those acquisitions. We expect that as we continue to scale up our business, our increased size, capabilities and access to capital will provide us with increased strategic acquisition opportunities.
Valued-Added Service Offerings
Over our three decades of experience, we have developed the full range of RNG project related capabilities from engineering, construction, management and operations, through EHS oversight and Environmental Attributes management. By vertically integrating across RNG services, we are able to reduce development and operations costs, optimize efficiencies and improve operations. Our full suite of capabilities allows us to serve a multi-project partner for certain project hosts across multiple transactions, including through strategic transactions. To that end, we actively identify and evaluate opportunities to acquire entities that will further our vertically-integrated services.
Our Current Operating Portfolio
We currently own and operate 13 projects, 11 of which are RNG projects and two of which are Renewable Electricity projects. We are currently in the process of expanding two RNG project from LFG. We are also working on other projects which will repurpose equipment from existing biogas facilities for use at new project sites. The below graphic does not include the Montauk Ag project, which is currently under development.
Renewable Natural Gas
Site
COD(1)
Capacity
(MMBtu/
day) (2)
Source
Rumpke
Cincinnati, OH
7,271
Landfill
Atascocita
Humble, TX
2002*/ 2018
5,570
Landfill
McCarty
Houston, TX
4,415
Landfill
Apex
Amsterdam, OH
2,673
Landfill
Monroeville
Monroeville, PA
2,372
Landfill
Valley
Harrison City, PA
2,372
Landfill
Galveston
Galveston, TX
1,857
Landfill
Renewable Electricity Generation
Raeger
Johnston, PA
1,857
Landfill
Site
COD (1)
Capacity
(MW)
Source
Shade
Cairnbrook, PA
1,857
Landfill (3)
Bowerman
Irvine, CA
23.6
Landfill
Coastal
Plains Alvin, TX
1,775
Landfill
AEL
Sand Spring, OK
3.2
Landfill
Pico
Jerome, ID
Livestock
(Dairy)
Total Capacity (MW)
26.8
Total Capacity (MMBtu)
32,922
= Renewable Natural Gas Project
= Renewable Electricity Project
(1)“COD” refers to the commercial operation date of each site.
(2)This is equivalent to the project’s design capacity and assumes inlet methane content of 56% for all sites other than Pico, which assumes inlet methane content of 62%, and process efficiency of 91%.
(3)All of our landfill sites are accepting waste except our Shade site. Our Shade site is closed to accepting new waste, but is currently expected to continue to generate a commercial level of RNG for an additional ten years. Our operating RNG projects have an average expected remaining useful life of approximately 18 years.
We have a long history of operating our projects with partners, with our oldest relationship going back nearly 50 years. On average, we have had an approximate 20-year history with our current project site owners. As of December 31, 2024, our operating RNG projects have an average expected remaining useful life of approximately 18 years and our operating Renewable Electricity projects have an average expected remaining useful life of approximately 34 years, including renewal periods.
Approximately 69% of our 2024 RNG production has been monetized under fuel supply agreements with expiration dates more than 15 years from December 31, 2024. Approximately 92% of our 2024 Renewable Electricity production has been monetized under fuel supply agreements with expiration dates more than 15 years from December 31, 2024. Concurrent with our fuel supply agreements, we typically enter into property leases with our project hosts, which govern access rights, permitted activities, easements and other property rights. We own all equipment and facilities on each leased property, other than equipment provided by utility companies providing services on-site. Lease termination typically requires the restoration of the leased area to its original condition. We have successfully ended leases on six of our former facilities.
Our RNG projects currently utilize three of the four proven commercial technologies available to process raw biogas into RNG, including: pressure swing absorption (“PSA”), Membrane Filtration and solvent scrubbing. We are capable of working with virtually all available biogas processing technologies at our sites. We attend industry conferences and maintain an ongoing dialogue with key equipment providers to ensure we stay informed of the latest technology that could be deployed at our current and future facilities.
Stated capacity reflects the design capacity of each facility. Several of our projects have reserve capacity when comparing design capacity to available biogas feedstock. Several previous acquisitions are gas limited and therefore do not operate at their design capacity. Our larger projects have expansions planned or are being evaluated for future expansions dependent on the availability of excess biogas feedstock.
RNG Projects
We currently own and operate 11 RNG projects across four states: Ohio (two), Pennsylvania (four), Texas (four) and Idaho (one) which, in the aggregate, have a total design capacity of approximately 32,922 MMBtu/day.
RNG Projects
Site
Location
Capacity*
Rumpke
Cincinnati, OH
7,271 MMBtu/day
Atascocita
Humble, TX
5,570 MMBtu/day
McCarty
Houston, TX
4,415 MMBtu/day
Apex (1)
Amsterdam, OH
2,673 MMBtu/day
Monroeville
Monroeville, PA
2,372 MMBtu/day
Valley
Harrison City, PA
2,372 MMBtu/day
Galveston
Galveston, TX
1,857 MMBtu/day
Raeger Mountain
Johnstown, PA
1,857 MMBtu/day
Shade
Cairnbrook, PA
1,857 MMBtu/day
Coastal Plains
Alvin, TX
1,775 MMBtu/day
Pico
Jerome, ID
903 MMBtu/day
Total
32,922 MMBtu/day
(1)	The capacity for Apex will increase to approximately 5,273 when we commission the second facility in the second quarter of 2025.
*	Assumes inlet methane content of 56% for all sites other than Pico, which assumes inlet methane content of 62%, and process efficiency of 91%.
Renewable Electricity Projects
We currently own and operate the following two Renewable Electricity projects in California and Oklahoma, which, in the aggregate, have a total design capacity of approximately 29.1 MW. Our Renewable Electricity projects utilize reciprocating engine generator sets to generate electricity at landfills. This does not include the Montauk Ag Renewables project in North Carolina, which is not yet operational.
Renewable Electricity Projects
Site
Location
Capacity(1)
Bowerman Power
Irvine, CA
23.6 MW
Tulsa/AEL
Sand Springs, OK
3.2 MW
Pico(1)
Jerome, ID
2.3 MW
Total
29.1 MW
(1)Beginning in October 2020, we began reporting the result of operations of Pico within RNG, but Pico continues to generate electricity.
* Assumes inlet methane content of 56% and process efficiency of 91%,
A critical component of our business is our ability to negotiate and maintain long-term fuel supply agreements at our project sites. We have developed strong working relationships with our landfill site owners, including eight of 13 operating projects and other potential development projects each with Waste Management and Republic Services, the two largest waste companies in the United States, and actively seek to strategically extend our tenure at our project sites.
Our projects provide our landfill and agricultural partners a solution to monetize biogas from their sites, support their regulatory compliance and provide them with environmental services. We have had working relationships with Republic Services since 1986 and with Waste Management since 2004 and we enable monetization of their biogas while maintaining regulatory compliance. We seek to differentiate ourselves from our competitors through our extensive experience across a variety of commercialized beneficial uses of processed biogas, including pipeline-quality natural gas, power generation and boiler fuel gas products. To date, we have not had any fuel supply agreement terminated by any site partner once we have established a facility on the site, which we believe serves as evidence of our operational expertise, reliability and consistent value delivered to our site partners. The table below is a summary of the expiration periods of those agreements. We are consistently reviewing and pursuing extensions for all of our fuel supply agreements well before their expirations and for future agreements, we continue to target contracts with expirations of 20 years from commencement of operation with options for extension.
Fuel Supply Agreement Summary
RNG Projects
Fuel Supply Agreement Expiration Dates
Current Sites as of December 31, 2024
% of 2024 Total RNG Production
Within 0-5 years
7.8
%
Between 6-15 years
32.3
%
Greater than 15 years
60.0
%
Renewable Electricity Projects
Fuel Supply Agreement Expiration Dates
Current Sites as of December 31, 2024
% of 2024 Total
Renewable
Electricity
Production
Within 0-5 years
-
3.4
%
Between 6-15 years
-
-
%
Greater than 15 years(1)
91.9
%
(1)Our Pico project continues to generate both RNG and Renewable Electricity and is accounted for above in the RNG Projects summary.
Customers
Our customers for RNG and RINs typically include large, long-term owner-operators of landfills and livestock farms, local utilities, and large refiners in the natural gas and refining sectors. Royalty structures included in our agreements, as well as the large size of our counterparties, limit their credit risk. Valero, GE Warren, Exxon and Mercuria represented approximately 17.6%, 15.7%, 13.8% and 11.8%, respectively, of our operating revenues in 2024 from the sale of Environmental Attributes. We sell RINs to numerous RIN off-take parties and our largest RIN off-taker as a percentage of revenue can vary year to year given the short-term nature of these contracts. In addition to revenues from sales of RNG and RINs, we also share a portion of our Environmental Attributes with our pathway providers as in-kind consideration for the counterparty using our RNG as a transportation fuel.
Our customers for electricity typically include investor-owned and municipal electricity utilities. For the sale of Renewable Electricity and RECs, the City of Anaheim represented approximately 9.3% of our operating revenues in 2024. These sales occurred under a PPA between us and the City of Anaheim, in which electricity and RECs are sold at fixed prices. In 2024, we converted 100% of the monetization of our Renewable Electricity production and Environmental Attributes under fixed-price agreements. For our electricity sales, all of our customers with whom we have off-take agreements are investment-grade entities with low credit risk.
No other single customer represented more than 10% of our total 2024 operating revenues.
Suppliers and Equipment Vendors
The major technologies used by our projects for gas processing include solvent scrubbing PSA and membrane separation. For electricity generation, we use reciprocating engines. This affords Montauk experience with substantially all major vendors in the sector, and technical expertise in numerous technologies.
We source equipment from a variety of major suppliers with specialties in each technology. We enter into written ordinary-course agreements with suppliers to obtain industry-standard equipment for use in our operations. The contracts generally do not include any intellectual property rights other than for the intended use of the equipment. Membrane separation equipment is primarily provided by UOP and Air Liquide. PSA equipment is primarily provided by Xebec, Guild, Air Products, and BioFerm. Solvent scrubbing is primarily provided by Selexol. RNG ancillary constituent removal is done using equipment provided by Iron Sponge, MV Technologies, Thiopaq, Guild Associates, and PSB Industries. Electricity generation equipment is provided by Solar Turbines, Caterpillar, and Jenbacher.
We have made substantial investments in a centralized Enterprise Resource Planning (“ERP”) system (Microsoft Dynamics) to better integrate operations across our projects. This system centralizes maintenance operations across all of our projects. Our proactive approach to maintenance, corrective maintenance, root cause analysis, failure reporting, project management, and budgeting are all completed using the ERP system. We are currently in the process of migrating our ERP to the latest version of the Microsoft Dynamics system. We anticipate having this system migration complete in 2025.
Competition
There are several other companies operating in the renewable energy and waste-to-energy space, ranging from other project developers to service or equipment providers.
Our primary competition is from other companies or solutions for access to biogas from waste. Evolving consumer preferences, regulatory conditions, ongoing waste industry trends, and project economics have a strong effect on the competitive landscape and our relative ability to continue to generate revenues and cash flows. We believe that our status as one of the largest operators of LFG-to-RNG projects, our 30-year track record of operating and developing projects, and our deep relationships with some of the largest landfill owners and dairy farms in the country position us very well to continue to operate and grow our portfolio, and respond to competitive pressures. We have demonstrated a track record of strategic flexibility across our 30-year history which has allowed us to pivot towards projects and markets that we believe deliver optimal returns and stockholder value in response to changes in market, regulatory and competitive pressures.
The biogas market is highly fragmented. We believe our size relative to many other LFG companies and our capital structure puts us in a strong position to compete for new project development opportunities or acquisitions of existing projects. However, competition for such opportunities, including the prices being offered for fuel supply, will impact the expected profitability of projects to us, and may make projects unsuitable to pursue. Likewise, prices being offered by our competitors for fuel supply may increase the royalty rates that we pay under our fuel supply agreements when such agreements expire and need to be renewed or when expansion opportunities present themselves at the landfills where our projects currently operate. It is also possible that more landfill owners may seek to install their own LFG projects on their sites, which would reduce the number of opportunities for us to develop new projects. Our overall size, reputation, access to capital, experience and decades of proven execution on LFG project development and operation leave us well-positioned to compete with other companies in our industry.
We are aware of several competitors in the United States that have a similar business model to our own, including Clean Energy Fuels Corp, Opal Fuels, U.S. Gain, Brightmark, Gevo Inc., and AMP Energy, as well as companies with biogas-to-energy facilities as a segment or subsidiary of their operations, including DTE, Ameresco, and British Petroleum (bp, acquired Archaea Energy in 2022). In addition, certain landfill operators, such as Waste Management, have also chosen to selectively pursue biogas conversion projects at their sites. Finally, Republic has entered into a joint venture with bp (formerly through Archaea Energy) to develop certain of its LFG locations.
Government Regulation
Our projects are subject to a range of federal, state and local environmental, health and safety laws and regulations, depending on the nature and configuration of the project, as well as where the project is located. We have established processes and procedures to comply with laws and regulations applicable to our operations, and have partnered with external experts, as needed, to meet applicable compliance requirements. As a renewable energy company, we are committed to being good stewards of the environment and to positively impacting the communities in which we operate.
All of our current Renewable Electricity projects are QFs. As a result, the facilities are exempt from rate regulation under Sections 205 and 206 of the Federal Power Act. We are required to document the QF status of each of our facilities in applications or
self-certifications filed with FERC, which typically require disclosure of upstream facility ownership, fuel and size characteristics, power sales, interconnection matters, and related technical disclosures. Failure to maintain QF status may subject the project to additional regulatory requirements and may require the payment of refunds to customers and other costs or penalties.
We are subject to the Clean Air Act, which regulates the emissions of air pollutants to protect the environmental and public health. The combustion of biogas results in emissions of carbon monoxide, oxides of nitrogen, sulfur dioxide, volatile organic compounds and particulate matter. Federal, state and local laws may require us to obtain permits or impose other burdens, including monitoring, testing, recordkeeping and reporting by us in order for us to conduct operations. In addition, our operations and the operations of landfills may be subject to additional air emissions laws and regulations, such as those designed to address the emission of methane, a potent GHG.
Among other laws, we are subject to Subtitle D of the Resource Conservation and Recovery Act and other federal, state and local laws, which impose conditions on the handling of hazardous and non-hazardous waste, including the emission of methane in landfills. Likewise, we are subject to the Comprehensive Environmental Response Compensation and Liability Act of 1980 and other federal, state and local laws, which govern the investigation and cleanup of sites contaminated with hazardous substances. We have not been identified as a potentially responsible party with respect to environmental remedial costs at any site to date. We also may be required to obtain permits to discharge wastewater and stormwater pursuant to the Clean Water Act’s National Pollutant Discharge Elimination System and other federal, state and local laws governing such discharges.
Our RNG projects are subject to federal RFS program regulations, including the Energy Policy Act of 2005 and the Energy Independence and Security Act. The EPA administers the RFS program with volume requirements for several categories of renewable fuels. The EPA’s RFS regulations establish rules for fuel supplied and administer the RIN system for compliance, trading credits and rules for waivers. The EPA calculates a blending standard for each year based on estimates of gasoline usage from the Department of Energy’s Energy Information Agency. Separate quotas and blending requirements are determined for cellulosic biofuels, BBD, advanced biofuels and total renewable fuel. Further, we are required to register each RNG project with the EPA and relevant state regulatory agencies.
We qualify our RINs through a voluntary Quality Assurance Plan, which typically takes from three to five months from first injection of RNG into the commercial pipeline system. Further, we typically make a large investment in the project prior to receiving the regulatory approval and RIN qualification. In addition to registering each RNG project, we are subject to quarterly audits under the Quality Assurance Plan of our projects to validate our qualification.
Our RNG projects are also subject to state renewable fuel standard regulations. The CA LCFS program requires producers of petroleum-based fuels to reduce the CI of their products, beginning with a quarter of a percent in 2011, a 10% total reduction in 2020, and a 30% total reduction in 2030. Petroleum importers, refiners and wholesalers can either develop their own low-carbon fuel products, or buy CA LCFS credits from other companies that develop and sell low-carbon alternative fuels, such as biofuels, electricity, natural gas or hydrogen. We are subject to a qualification process for CA LCFS credits that is similar to that for RINs, including verification of CI levels and other requirements.
Our RNG projects are also impacted by state and federal gas quality standards. State regulators determine whether RNG may be purchased by the state’s local gas utilities, and whether a site operator may directly sell gas to a retail, or direct end-use, customer. FERC regulates the natural gas pipelines that transport gas in interstate commerce, and specifies or approves a gas pipeline’s tariff that sets the rates, terms and conditions, gas quality, and other requirements applicable to transportation of natural gas on the pipelines, including shipping RNG. Our sites are not permitted, and may not be physically able, to deliver RNG to a FERC regulated pipeline unless the pipeline’s receipt of the gas is consistent with the standards adopted in the pipeline’s FERC tariff. RNG-related gas quality standards may vary by pipeline and may be revised at any time, subject to all required regulatory approvals. We routinely test the RNG produced at our facilities in order to ensure compliance with applicable pipeline gas quality standards.
We monitor regulatory trends and developments in the U.S. regarding the regulation of greenhouse gas emissions. The EPA published final regulations for methane emissions, a greenhouse gas, from oil and gas facilities in March 2024. The regulation does not apply to our operations and could, combined with another public policy and private sector initiatives, increase interest in developing more renewable energy projects in the U.S. We will continue to monitor greenhouse gas regulatory initiatives in the U.S. and assess their potential relevance to our business and operations.
We routinely conduct compliance audits on our projects to proactively identify and correct potential compliance deficiencies or risks. Additionally, we closely monitor emerging regulatory developments that may impact our operations or business strategy. Montauk also participates in industry trade groups, such as the RNG Coalition and American Biogas Council, to advocate policies and regulatory frameworks that support continued expansion of renewable energy in the United States.
The operation of our business may expose us to certain liabilities and compliance costs related to environmental matters. These liabilities or compliance costs did not have a material effect on our capital expenditures or competitive position for fiscal 2024, nor do we expect them to have a material effect in the future. We believe we are in material compliance with all environmental regulations applicable to our operations.
Inflation Reduction Act. The Inflation Reduction Act ("IRA" or the "Act") will be administered by multiple federal agencies including EPA, U.S. Department of Energy and the Internal Revenue Service of the U.S. Department of the Treasury. The goals of the IRA include incentivizing the development and production of renewable energy. We cannot speculate on exactly how the IRA will be implemented; however, the Act does contain numerous incentives for the production of clean energy which may impact our products. President Trump signed Executive Order 14154 on January 20, 2025, which immediately paused the disbursement of funds under the IRA. The funding pause has been challenged by several states and the District of Columbia.
Employees and Human Capital Resources
Employee Profile
We employed 166 people on December 31, 2024, located in California, Idaho, Ohio, Oklahoma, Pennsylvania, North Carolina and Texas. Our employee population is comprised of a mix of field operations personnel and office-based professionals. As of December 31, 2024, none of our employees were represented by a collective bargaining unit or labor union. We consider our employee relations to be good across our organization.
Health and Safety
Safety, including the health of our employees, is one of our core values and a priority across our operations. We are committed to developing a strong health and safety culture that reduces injuries and illness whenever possible. Our health and safety strategy is designed to proactively identify, mitigate and eliminate conditions that could result in serious injury or fatality. We also routinely train our employees on health and safety practices applicable to their job function and provide them all necessary personal protective equipment to perform their job in a safe manner.
Our recordable cases and total recordable incident rate (“TRIR”), excluding COVID-19 related incidents, was 2.89 and 0.00 in 2024 and 2023, respectively. The 2023 TRIR national average was 2.4 for all industries. We continue to focus on practices and measures to lower our TRIR.
Employee Development and Training
The success and growth of our business is significantly correlated with our ability to recruit, train, promote and retain talented individuals at all levels of our organization. To succeed in a competitive labor market, we have developed and implemented various recruitment and retention strategies. These include competitive salary structures, bonus programs and competitive benefits, as well as paid time off, sick leave, disability coverage, group term life insurance, and a retirement savings program. We also offer our employees tuition reimbursement for job-related education and training opportunities. We continue to provide leadership and developmental training for our executive, director and manager level employees.
Intellectual Property
We rely on a combination of patent, trademark, copyright and trade secret laws, employee and third-party nondisclosure/confidentiality agreements, non-compete, and license agreements to protect our intellectual property. We acquired certain technology associated with the Montauk Ag Renewables Acquisition for which we received a patent during 2021 with a term of 20 years. In 2022, we filed a provisional patent application pertaining to a combustion-based oxygen removal condensate neutralization technology we developed. The provisional patent covers a new low pH neutralization technology designed to mitigate unfavorable pH condensate that is produced when wastewater is removed from the biogas conversion process. In 2024, we filed a provisional patent application pertaining to a renewable natural gas processing skid that we developed. While we hold patents related to our business, we do not view our patents to be material to our total business.
Segments and Geographic Information
We have two operating segments: Renewable Natural Gas and Renewable Electricity Generation. While our corporate entity is not an operating segment, we discretely disclose corporate entity revenues for purposes of reconciliation of the Company’s consolidated financial statements. For information regarding revenues and other information regarding our results of operations for each of our last two financial years, please refer to our financial statements included in this report and within “Item 7.-Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report.
Corporate Information
Montauk Renewables, Inc. is incorporated in the State of Delaware. Our principal executive offices are located at 5313 Campbells Run Road, Suite 200, Pittsburgh, PA 15205. Our telephone number is (412) 747-8700.
We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.
We also make financial information, news releases and other information available on our corporate investor relations website at www.ir.montaukrenewables.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free of charge on this website as soon as reasonably practicable after we file these reports and amendments with, or furnish them to, the SEC. The information contained on or connected to our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report filed with the SEC.
We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012. As an emerging growth company, we may take advantage of certain reduced reporting requirements that are otherwise applicable generally to public companies. We currently intend to take advantage of several of these reduced reporting requirements, including the extended transition periods for complying with new or revised accounting standards. See “Item 1A. Risk Factors-Emerging Growth Company Risks” for certain risks related to our status as an emerging growth company.
We are a “controlled company” within the meaning of the Nasdaq Stock Market LLC (“Nasdaq”) corporate governance standards. Certain stockholders, which are affiliates of two of our directors, Mr. John A. Copelyn and Theventheran G. Govender, own approximately 52.3% of our common stock and have entered into a Consortium Agreement (the “Consortium Agreement”) whereby the parties thereto will agree to act in concert with respect to voting our common stock, including in the election of directors, among other matters. As a controlled company, we may elect not to comply with certain Nasdaq corporate governance standards. See “Item 1A. Risk Factors-Common Stock Risks” for certain risks related to our status as a controlled company.
This report includes estimates, projections, and other information concerning our industry and market data, including data regarding the estimated size of the market, projected growth rates, and perceptions and preferences of consumers. We obtained this data from industry sources, third-party studies, including market analyses and reports, and internal company surveys. Industry sources generally state that the information contained therein has been obtained from sources believed to be reliable. Although we are responsible for all of the disclosure contained in this report, and we believe the industry and market data to be reliable as of the date of this report, this information could prove to be inaccurate.
Information About Our Executive Officers
Below is a list of the names, ages, and positions of our executive officers, and a brief summary of the business experience of our executive officers (ages as of March 1, 2025).
Name
Age
Position
Sean F. McClain
President and Chief Executive Officer, Director
Kevin A. Van Asdalan
Chief Financial Officer and Treasurer
James A. Shaw
Vice President of Operations
Michael Barsch
Vice President of Business Development
John Ciroli
Chief Legal Officer and Secretary
Sharon Frank
Vice President of Environmental, Health and Safety
Sean F. McClain. Mr. McClain has served as our President and Chief Executive Officer and a member of our Board of Directors since January 2021. Prior to the Reorganization Transactions, Mr. McClain served as President and Chief Executive Officer of Montauk Holdings USA and as a member of its Board of Directors. From April 2011 until September 2019, Mr. McClain served as Chief Financial Officer of Montauk Holdings USA and Montauk Energy Holdings. Prior to joining Montauk in 2011, he held various management positions with BPL Global Limited, Bayer and Dick’s Sporting Goods and was in public accounting at Arthur Andersen LLP. He is a certified public accountant and has over 25 years of business and financial management experience.
Kevin A. Van Asdalan. Mr. Van Asdalan has served as our Chief Financial Officer and Treasurer since January 2021. Prior to the Reorganization Transactions, Mr. Van Asdalan served as Chief Financial Officer of Montauk Holdings USA and as a member of its Board of Directors. From March 2018 until September 2019, Mr. Van Asdalan served as Controller of Montauk Energy Holdings and Montauk Holdings USA. Prior to joining Montauk in 2018, Mr. Van Asdalan served as a lines of business controller and manager of external reporting at L.B. Foster Company, a manufacturer, distributor and service provider for transportation and energy infrastructure, from July 2011 to March 2018. Prior to L.B. Foster, Mr. Van Asdalan held senior associate accounting positions at PricewaterhouseCoopers LLP and Sisterson & Co LLP. He is a certified public accountant and chartered global management accountant with nearly 25 years of business and financial management experience and holds a Master of Business Administration from the University of Pittsburgh Katz Graduate School of Business.
James A. Shaw. Mr. Shaw has served as our Vice President of Operations since January 2021 and has served as Vice President of Operations of Montauk Energy Holdings since September 2019. He previously served as North Region Manager of Montauk Energy Holdings from May 2016 to September 2019. He was a Site Manager for five Montauk Energy Holdings operating sites from April 2015 to April 2016 and two Montauk Energy Holdings operating sites from June 2010 to March 2015. Prior to joining Montauk, Mr. Shaw was a facility manager for SONY Electronics at the world’s first vertically integrated television manufacturing facilities. Mr. Shaw has more than 25 years of experience in facilities operations and management.
Michael J. Barsch. Mr. Barsch has served as our Vice President of Business Development since September 2023. He previously served as Director of Projects from January to September 2023. From February 2021 to January 2023, Mr. Barsch was Vice President of Construction for BerQ RNG, a renewable energy producer. Mr. Barsch was a renewable energy consultant from March 2019 to February 2021 and Vice President of Projects for Energy Developments Limited, a renewable energy producer, from March 2016 to March 2019. From November 2013 to March 2016, he was Managing Director of Construction for Renewable Energy Trust Capital. Mr. Barsch has over 25 years of experience managing the construction of renewable energy projects.
John Ciroli. Mr. Ciroli has served as our Chief Legal Officer since January 2023. He served as our Vice President, General Counsel and Secretary from January 2021 until January 2023 and in the same role with Montauk Energy Holdings upon joining in July 2020. From July 2016 to July 2020, Mr. Ciroli was the North American Counsel and HR Manager for the North American subsidiaries of FAAC Group, a company that designs solutions for pedestrian and vehicle needs, representing the entities in their American and Canadian portfolio. From 2014 to July 2016, Mr. Ciroli was a Senior Litigation Counsel with the Housing Authority of the City of Pittsburgh. Mr. Ciroli has over 25 years of experience representing and advising domestic and international corporations and government entities in the areas of contracts, mergers and acquisitions, litigation, employment and governmental procurement and regulatory affairs. He was also a professor for Concord Law School, now Purdue Global, in the areas of Contracts, Constitutional Law, Torts and Evidence and is a member of the Pennsylvania State Bar and the bar of the U.S. Supreme Court.
Sharon Frank. Ms. Frank has served as our Vice President of Environmental, Health and Safety since October 2021. She served as our Director of Environmental, Health and Safety from April 2020 until October 2021 and as Manager of Environmental Compliance from June 2007 until April 2020. Prior to joining Montauk, from 2000 to 2007, Ms. Frank was Manager of Environmental Affairs for Duquesne Light Company’s unregulated business group. Ms. Frank has over 30 years of regulatory and environmental compliance experience.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS.
This Annual Report on Form 10-K contains forward-looking information based on our current expectations. Because our business is subject to many risks and our actual results may differ materially from any forward-looking statements made by or on behalf of us, this section includes a discussion of important factors that could affect our business, operating results, financial condition and the trading price of Montauk common stock. You should carefully consider these risk factors, together with all of the other information included in this Annual Report on Form 10-K as well as our other publicly available filings with the SEC. Although the risks are organized by headings, and each risk is discussed separately, many are interrelated.
Operational Risks
Our renewable energy projects may not generate expected levels of output.
Landfills contain organic material whose decomposition causes the generation of gas consisting primarily of methane, which our RNG projects use to generate power or renewable natural gas, and carbon dioxide. The estimation of landfill gas production volume is an inexact process and dependent on many site-specific conditions, including the estimated annual waste volume, composition of waste, regional climate and the capacity and construction of the landfill. Production levels are subject to a number of additional risks, including a failure or wearing out of our or our landfill operators’, customers’ or utilities’ equipment; an inability to find suitable replacement equipment or parts; less than expected supply or quality of the project’s source of biogas and faster than expected diminishment of such biogas supply; or volume disruption in our fuel supply collection system. Any extended interruption and/or volume disruption in the project’s operation, or failure of the project for any reason to generate the expected amount of output, could adversely affect our business and operating results. For example, certain of our Houston-based operating sites were impacted by severe weather events during the first nine month of 2024 including multiple day extended outages from Hurricane Beryl in July 2024. Furthermore, we produced fewer MMBTu and MWh in the third quarter of 2023 compared with the third quarter of 2022 due to dry weather conditions and higher ambient temperatures. In addition, we have in the past, and may in the future, incur material asset impairment charges if any of our renewable energy projects incurs operational issues that indicate our expected future cash flows from the project are less than the project’s carrying value. Any such impairment charge could adversely affect our operating results in the period in which the charge is recorded.
In addition, in order to maximize collection of LFG, we will need to take various measures, such as drilling additional gas wells in the landfill to increase LFG collection, balancing the pressure on the gas field based on the data collected by the landfill operator from the gas wells to ensure optimum landfill gas utilization and ensuring that we match availability of engines and related equipment to availability of LFG. There can be no guarantee that we will be able to take all necessary measures to maximize collection. In addition, the LFG available to our projects is dependent in part on the actions of other persons, such as landfill operators. We may not be able to ensure the responsible management of the landfill site by owners and operators, which may result in less than optimal gas generation or increase the likelihood of “hot spots” occurring. Hot spots can temporarily reduce the volume of gas which may be collected from a landfill site, resulting in a lower gas yield. Other events that can result in a reduction in LFG output include: extreme hot or cold temperatures or excessive rainfall; liquid levels within a landfill increasing; oxidation within a landfill, which can kill the anaerobic microbes that produce landfill gas; and the buildup of sludge. The occurrence of these or any other changes within any of the landfills where our projects operate could lead to a reduction in the amount of LFG available to operate our projects, which could have a material adverse effect on our business, financial condition and results of operations.
The concentration in revenues from five of our projects and geographic concentration of our projects expose us to greater risks of production interruptions from severe weather or other interruptions of production or transmission.
A substantial portion of our revenues are generated from five project sites. For the years ended December 31, 2024 and 2023, excluding the effect of derivative instruments, approximately 69.1% and 68.4%, respectively, of operating revenues were derived from these locations. During 2024, RNG production at our Atascocita, Rumpke, McCarty and Galveston facilities accounted for approximately 20.3%, 18.9%, 16.4% and 11.0% of our RNG revenues, respectively, and 18.7%, 21.4%, 15.0% and 8.7% of the RNG we produced, respectively. During 2024, Renewable Electricity production at our Bowerman Power LFG, LLC (“Bowerman”) facility accounted for approximately 92.2% of our Renewable Electricity Generation revenues and 82.6% of the Renewable Electricity we produced during 2024. A lengthy interruption of production or transmission of renewable energy from one or more of these projects, as a result of a severe weather event, failure or degradation of our or a landfill operator’s equipment or interconnection transmission problems could have a disproportionate effect on our revenues and cash flow.
Our Atascocita, McCarty, Galveston and Coastal Plains projects are located within 20 miles of each other near Houston, Texas and six of our other RNG projects are located in relatively close proximity to each other in Pennsylvania and Ohio. Regional events, such as gas transmission interruptions, regional availability of replacement parts and service in the event of equipment failures and severe weather events in either of those geographic regions have previously adversely affected, and if the future could adversely
affect, our RNG production and transmission. These impacts are greater than would be if our business was more geographically diverse.
Our projects are not able to insure against all potential risks and may become subject to higher insurance premiums.
Our projects are exposed to the risks inherent in the construction and operation of renewable energy projects, such as breakdowns, manufacturing defects, extreme weather, natural disasters, terrorist attacks and sabotage. We are also exposed to environmental risks.
We have insurance policies covering certain risks associated with our business. Our insurance policies do not, however, cover all losses, including, in some situations, those as a result of force majeure, which is generally defined as events that are beyond the control of the parties. For example, we did not receive any insurance recovery from the shutdowns in Houston in February 2021 due to the extreme cold or from the Bowerman shutdown in October 2020 due to wildfires. Even if insurance policies for some of our projects cover losses as a result of certain types of force majeure events, such coverage is subject to important limitations. Furthermore, insurance liabilities are difficult to assess and quantify due to unknown factors, including the severity of an injury, the determination of our liability in proportion to other parties, the number of incidents not reported and the effectiveness of our safety program. Insurance coverage is not always available on commercially reasonable terms (if at all) and is often capped at predetermined limits. In addition, our insurance policies are subject to annual review by our insurers and may not be renewed on similar or favorable terms or at all. A serious uninsured loss or a loss significantly exceeding the limits of our insurance policies could adversely affect our business, financial condition and results of operations.
Competition Risks
We may face intense competition and may not be able to successfully compete.
There are a number of other companies operating in the renewable energy and waste-to-energy markets. These include other renewable energy companies and service or equipment providers, consultants, managers and strategic investors.
We may not have the resources to compete with our existing competitors or with any new competitors, including in a competitive bidding process. Some of our competitors have significantly larger personnel, financial and managerial resources than we have, and we may fail to maintain or expand our business. Our competitors may also offer energy solutions at prices below cost, devote significant sales forces to competing with us or attempt to recruit our key personnel by increasing compensation, any of which could improve their competitive positions. Moreover, if the demand for renewable energy increases, new companies may enter the market, and the influx of added competition will pose an increased risk to us.
Further, certain of our strategic partners and other landfill or agricultural operators could decide to manage, recover and convert biogas from waste to renewable energy on their own which would further increase our competition, limit the number of commercially viable landfill sites available for our projects or require us to reduce our profit margins to maintain or acquire projects.
Our success depends, in part, on technological innovation to stay ahead of market competitors.
Our success will depend on our ability to create and maintain a competitive position in the renewable energy industry. Other than the patented technology acquired through the Montauk Ag Renewables Acquisition, our internally developed condensate neutralization technology and an RNG processing skid we developed, we do not have any exclusive rights to any of the technologies that we utilize, and our competitors may currently use and may be planning to use identical, similar or superior technologies. While significant to the development associated with our emerging North Carolina Montauk Ag Renewables business, we do not currently consider patented technology material to the total business. In addition, the technologies that we use may be rendered obsolete or uneconomical by technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others.
We may also face competition based on technological developments that reduce demand for electricity, increase power supplies through existing infrastructure or that otherwise compete with our projects. We also encounter competition in the form of potential customers electing to develop solutions or perform services internally rather than engaging an outside provider such as us.
Our use and enjoyment of real property rights for our projects may be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to our projects.
Our projects generally are, and any of our future projects are likely to be, located on land occupied pursuant to long-term easements, leases and rights of way. The ownership interests in the land subject to these easements, leases and rights-of-way may be subject to mortgages securing loans or other liens (such as tax liens) and other easement, lease rights and rights-of-way of third parties
(such as leases of oil or mineral rights) that were created prior to our projects’ easements, leases and rights-of-way. As a result, certain of our projects’ rights under these easements, leases or rights-of-way may be subject, and subordinate, to the rights of those third parties. We may not be able to protect our operating projects against all risks of loss of our rights to use the land on which our projects are located, and any such loss or curtailment of our rights to use the land on which our projects are located and any increase in rent due on such lands could adversely affect our business, financial condition and results of operations.
We may not be able to obtain long-term contracts for the sale of power produced by our projects on favorable terms and we may not meet certain milestones and other performance criteria under existing PPAs.
Obtaining long-term contracts for the sale of power produced by our projects at prices and on other terms favorable to us is essential for the long term success of our business. We must compete for PPAs against other developers of renewable energy projects. This intense competition for PPAs has resulted in downward pressure on PPA pricing for newly contracted projects. The inability to compete successfully against other power producers or otherwise enter into PPAs favorable to us would negatively affect our ability to develop and finance our projects and negatively affect our revenues. In addition, the availability of PPAs depends on utility and corporate energy procurement practices that could evolve and shift allocation of market risks over time. Further, PPA availability and terms are a function of a number of economic, regulatory, tax, and public policy factors, which are also subject to change.
Our PPAs typically require us to meet certain milestones and other performance criteria. Our failure to meet these milestones and other criteria, including minimum quantities, may result in price concessions, in which case we would lose any future cash flow from the relevant project. In addition, we have in the past and, in the future, may be required to pay fees and penalties to our counterparty. We cannot assure you that we will be able to perform our obligations under such agreements, that fees and penalties will remain insignificant, or that we will have sufficient funds to pay any fees or penalties thereunder.
Business Strategy Risks
Our commercial success depends on our ability to identify, acquire, develop and operate individual renewable energy projects, as well as our ability to maintain and expand production at our current projects.
We aim to maintain and grow our position as a leading producer of RNG in the United States. Our specific focus on the renewable energy sector exposes us to risks related to the supply of, demand for and the ultimate price of energy commodities and Environmental Attributes, inflation, taxes, tariffs, duties or other assessments on necessary equipment, the cost of capital expenditures, government regulation, world and regional events and economic conditions, and the acceptance of alternative power sources. As a renewable energy producer, we may also be negatively affected by lower energy output resulting from variable inputs, mechanical breakdowns, faulty technology, competitive electricity markets or changes to the laws and regulations that mandate the use of renewable energy sources by refiners and importers of gasoline and diesel fuel and electric utilities.
In addition, several other factors related to the development and operation of individual renewable energy projects could adversely affect our business, including:
•regulatory changes, whether as a result of the new presidential administration or otherwise, that affect the demand for or supply of Environmental Attributes and the prices thereof, which could have a significant effect on the financial performance of our projects and the number of potential projects with attractive economics;
•changes in energy commodity prices, such as natural gas and wholesale electricity prices, which could have a significant effect on our revenues;
•changes in pipeline gas quality standards or other regulatory changes that may limit our ability to transport RNG on pipelines for delivery to third parties or increase the costs of processing RNG to allow for such deliveries;
•changes in the broader waste collection industry, including changes affecting the waste collection and biogas potential of the landfill industry, which could impede the LFG resource that we currently target for our projects;
•substantial construction risks, including the risk of delay, that may arise due to forces outside of our control, including those related to engineering and environmental problems, as a result of inclement weather or labor disruptions;
•operating risks and the effect of disruptions on our business, weather conditions, catastrophic events such as fires, explosions, earthquakes, droughts and acts of terrorism, and other force majeure events on us, our customers, suppliers, distributors and subcontractors;
•the ability to obtain financing for a project on acceptable terms or at all and the need for substantially more capital than initially budgeted to complete projects and exposure to liabilities as a result of unforeseen costs or environmental, construction, technological or other complications;
•entering into markets where we have less experience, such as our projects for biogas recovery at livestock farms;
•exposure to liabilities as a result of unforeseen environmental, construction, technological or other complications;
•failures or delays in obtaining desired or necessary land rights, including ownership, leases, easements, zoning rights and building permits;
•a decrease in the availability and timeliness of delivery of raw materials and components necessary for the projects to function or an increase in the costs of raw materials and components due to, among other reasons, inflation, tariffs, duties, taxes or assessments;
•obtaining and keeping in good standing permits, authorizations and consents from local city, county, state and U.S. federal governments as well as local and U.S. federal governmental organizations;
•penalties, including potential termination, under short-term and long-term contracts for failing to deliver RNG in accordance with our contractual obligations;
•unknown regulatory changes RNG which may increase the transportation cost for delivering under contracts in place;
•the consent and authorization of local utilities or other energy development off-takers to ensure successful interconnection to energy grids to enable power sales; and
•difficulties in identifying, obtaining and permitting suitable sites for new projects.
In addition, new projects have no operating history and may employ recently developed technology and equipment. A new project may be unable to fund principal and interest payments under its debt service obligations or may operate at a loss, which may adversely affect our business, financial condition or results of operations.
We may also experience delays and cost overruns in converting existing facilities from Renewable Electricity to RNG production. During the conversation projects, there is a gap in production and relating revenue while the electricity project is offline until it commences operation as an RNG facility, which adversely affects our financial condition and results of operations.
Any of these factors could prevent us from identifying, completing or operating our projects, or otherwise adversely affect our business, financial condition and results of operations.
If there is not sufficient demand for renewable energy, or if renewable energy projects do not develop or take longer to develop than we anticipate, we may be unable to achieve our investment objectives.
If demand for renewable energy fails to grow sufficiently, we may be unable to achieve our business objectives. In addition, demand for renewable energy projects in the markets and geographic regions that we target may not develop or may develop more slowly than we anticipate. Many factors will influence the widespread adoption of renewable energy and demand for renewable energy projects, including:
•cost-effectiveness of renewable energy technologies as compared with conventional and competitive technologies;
•performance and reliability of renewable energy products as compared with conventional and non-renewable products;
•fluctuations in economic and market conditions that impact the viability of conventional and competitive alternative energy sources;
•increases or decreases in the prices of oil, coal and natural gas;
•continued deregulation of the electric power industry and broader energy industry; and
•availability or effectiveness of government subsidies and incentives.
Our fuel supply agreements with site hosts have defined contractual periods, and we cannot assure you that we will be able to successfully extend these agreements at their historic revenue levels or at all.
Fuel supply rights are issued by the landfill owner to operators for a contractual period. As operators, we have already invested resources in the development of existing sites and the ability to extend these contracts on expiration would enable us to achieve operational efficiency in continuing to generate revenues from a site without significant additional capital investments. We cannot assure you that we will be able to extend existing fuel supply agreements at their historic revenue levels or at all when they expire.
Our agreements contain complex price adjustments, calculations and other terms based on gas price indices and other metrics, the interpretation of which could result in disputes with counterparties that could affect our results of operations and customer relationships.
Certain of our PPAs, fuel supply agreements, RNG off-take agreements and other agreements require us to make payments or adjust prices to counterparties based on past or current changes in gas price indices, project productivity or other metrics and involve complex calculations. Moreover, the underlying indices governing payments under these agreements are subject to change, may be discontinued or replaced. The interpretation of these price adjustments and calculations and the potential discontinuation or replacement of relevant indices or metrics have resulted, and in the future, could result in disputes with the counterparties with respect to these agreements. Any such disputes could adversely affect project revenues, expense margins, customer or supplier relationships, or lead to costly litigation, the outcome of which we would be unable to predict.
In order to secure contracts for new projects, we typically face a long and variable development cycle that requires significant resource commitments and a long lead time before we realize revenues.
The development, design and construction process for our renewable energy projects generally lasts from 18 to 36 months, on average. This extended development process requires the dedication of significant time and resources from our sales and management personnel, with no certainty of success or recovery of our expenses. A potential site host may go through the entire sales process and not accept our proposal. Further, upon commencement of operations, it typically takes 12 months or longer for the project to ramp up to our expected production level. All of these factors, and in particular, increased spending that is not offset by increased revenues, can contribute to fluctuations in our quarterly financial performance and increase the likelihood that our operating results in a particular period will fall below investor expectations.
We plan to expand our business in part through developing RNG recovery projects at landfills and livestock farms, but we may not be able to identify suitable locations or complete development of new projects.
We plan to continue to develop new RNG projects at landfills and livestock farms but we may be unable to implement this growth strategy if we cannot identify suitable landfills and livestock farms on which to develop projects, reach agreements with landfill or livestock farm owners to develop RNG projects or arrange required financing for new projects. While the EPA has identified an additional 463 landfills as candidates for biogas projects, we believe that approximately 38 of these sites produce sufficient quantities of LFG to support commercial-scale projects, with 25 of the approximately 38 sites being operated by Waste Management or Republic Waste, with whom we would need to negotiate with to secure sufficient LFG rights to support an RNG project. In the future, additional candidate landfills may become economically viable as their growth increases LFG production and requires installation of LFG collection systems. However, the time and effort involved in attempting to identify suitable sites and development of new projects may divert members of our management from our operations.
Our dairy farm project has, and any future digester project will have, different economic models and risk profiles than our landfill facilities, and we may not be able to achieve the operating results we expect from these projects.
Our dairy farm project produces significantly less RNG than our landfill facilities. As a result, we will be even more dependent on the LCFS credits and RINs produced at our dairy farm project than on the RINs produced at our landfill facilities for the project’s commercial viability. In the event that CARB worsens the CI score that it applies to waste conversion projects, such as dairy digesters, the number of LCFS credits for RNG generated at our dairy farm project will decline. Additionally, revenue from LCFS credits also depends on the price per LCFS credit, which is driven by various market forces, including the supply of and demand for LCFS credits, which in turn depends on the demand for traditional transportation fuel and the supply of renewable fuel from other renewable energy sources, and mandated CI targets, which determine the number of LCFS credits required to offset LCFS deficits, and which increase over time. Fluctuations in the price of LCFS credits or the number of LCFS credits assigned will have a significantly greater impact on the success of our dairy farm project than the value that RINs have on our landfill facilities. A significant decline in the value of LCFS credits could require us to incur an impairment charge on our dairy farm project and could adversely affect our business, financial condition and results of operations.
While we currently focus on converting methane into renewable energy, in the future we may decide to expand our strategy to include other types of projects. Any future energy projects may present unforeseen challenges and result in a competitive disadvantage relative to our more established competitors.
Our business is currently focused on converting methane into renewable energy. In the future, we may expand our strategy to include other types of projects. For example, we have entered into an agreement with European Energy North America under which we supply biogenic carbon dioxide for the creation of e-methanol and have announced a pilot project with Emvolon in which we will recover and convert biogas into green methanol. We cannot assure you that we will be able to identify attractive opportunities outside of our current area of focus or acquire or develop such projects at a price and on terms that are attractive or that, once acquired or
developed, such projects will operate profitably. In addition, these projects could expose us to increased operating costs, unforeseen liabilities or risks, and regulatory and environmental concerns associated with entering into new sectors of the energy industry, including requiring a disproportionate amount of our management’s attention and resources, which could adversely affect our business, as well as place us at a competitive disadvantage relative to more established market participants. A failure to successfully integrate such new projects into our existing project portfolio as a result of unforeseen operational difficulties or otherwise, could adversely affect our business, financial condition and results of operations.
Any future acquisitions, investments or other strategic relationships that we make could disrupt our business, cause dilution to our stockholders or harm our business, financial condition or operating results.
We expect future acquisitions of companies, purchases of assets and other strategic relationships to be an important part of our growth strategy. We plan to use acquisitions to expand our capabilities, expand our geographic markets, add experienced management and add to our project portfolio. However, we may not be able to identify suitable acquisition or investment candidates, reach agreements with acquisition targets on acceptable terms or arrange for any required financing for an acquisition on acceptable terms, any of which would materially impact our present strategy. While we perform due diligence on prospective acquisitions, we may not be able to discover all potential operational deficiencies in such projects. Further, if we are successful in consummating acquisitions, those acquisitions could subject us to a number of risks, including:
•the purchase prices we pay could significantly deplete our cash reserves or result in dilution to our existing stockholders;
•we may find that the acquired companies or assets do not improve our customer offerings or market position as planned;
•we may have difficulty integrating the operations and personnel of the acquired companies;
•key personnel and customers of the acquired companies may terminate their relationships with the acquired companies as a result of or following the acquisition;
•we may experience additional financial and accounting challenges and complexities in areas such as tax planning and financial reporting;
•we may experience delays in construction and development or regulatory approvals impacting, among other projects, the Pico, Apex or Montauk Ag development cycle;
•we may incur additional costs and expenses related to inflation and complying with additional laws, rules or regulations in new jurisdictions;
•we may assume or be held liable for risks and liabilities (including for environmental-related costs) as a result of our acquisitions, some of which we may not discover during our due diligence or adequately adjust for in our acquisition arrangements;
•our ongoing business and management’s attention may be disrupted or diverted by transition or integration issues and the complexity of managing geographically diverse enterprises;
•we may incur one-time write-offs or restructuring charges in connection with an acquisition;
•we may acquire goodwill and other intangible assets that are subject to amortization or impairment tests, which could result in future charges to earnings; and
•we may not be able to realize the cost savings or other modeled financial benefits we anticipated.
Any of these factors could adversely affect our business, financial condition and operating results.
Our renewable fuel projects may be exposed to the volatility of the price of RINs.
The price of RINs is driven by various market forces, including regulatory action, gasoline prices and the availability of renewable fuel from other renewable energy sources and conventional energy sources. For example, following the EPAs release of the 2023 RVO in December 2022, the market price of a D3 RIN declined from $2.43 on the date of the release to $1.88 in February 2023. Furthermore, refiners are permitted to carry-over up to 20% RINs generated for one calendar year after the RINs are generated to satisfy their RVOs. As a result, we are only able to sell RINs on a forward basis for the year in which the RINs are generated and the following year. We may be unable to manage the risk of volatility in RIN pricing for all or a portion of our revenues from RINs, which would expose us to the volatility of commodity prices with respect to all or the portion of RINs that we are unable to sell through forward contracts, including risks resulting from changes in regulations, general economic conditions and changes in the level of renewable energy generation. We expect to have quarterly variations in the revenues from the projects in which we generate revenue from the sale of RINs that we are unable to sell through forward contracts.
Our revenues may be subject to the risk of fluctuations in commodity prices.
The operations and financial performance of projects in the renewable energy sectors may be affected by the prices of energy commodities, such as natural gas, wholesale electricity and other energy-related products. For example, the price of renewable energy resources changes in relation to the market prices of natural gas and electricity. The market price for natural gas is sensitive to cyclical demand and capacity supply, changes in weather patterns, natural gas storage levels, natural gas production levels, general economic and geopolitical conditions (including the current conflicts in the Middle East and Ukraine) and the volume of natural gas imports and exports. The market price of electricity is sensitive to cyclical changes in demand and capacity supply, and in the economy and geopolitical conditions (including the current conflicts in the Middle East and Ukraine), as well as to regulatory trends and developments impacting electricity market rules and pricing, transmission development and investment to power markets within the United States and in other jurisdictions through interconnects and other external factors outside of the control of renewable energy power-producing projects. Volatility of commodity prices also creates volatility in the prices of Environmental Attributes, which are inversely related to the wholesale price of unleaded gasoline. In addition, volatility of commodity prices, such as the market price of gas and electricity, may also make it more difficult for us to raise any additional capital for our renewable energy projects that may be necessary to operate, to the extent that market participants perceive that a project’s performance may be tied directly or indirectly to commodity prices. Accordingly, the potential revenues and cash flows of these projects may be volatile and adversely affect the value of our investments.
Our off-take agreements for the sale of RNG are typically shorter in duration than our fuel supply agreements. Accordingly, if we are unable to renew or replace an off-take agreement for a project for which we continue to produce RNG, we would be subject to the risks associated with selling the RNG produced at that project at then-current market prices. We may be required to make such sales at a time when the market price for natural gas as a whole or in the region where that project is located, is depressed. If this were to occur, we would be subject to the volatility of gas prices and be unable to predict our revenues from such project, and the sales prices for such RNG may be lower than what we could sell the RNG for under an off-take agreement.
We are subject to volatility in prices of RINs and other Environmental Attributes.
Volatility of commodity prices creates volatility in the price of Environmental Attributes. The value of RINs is inversely proportionate to the wholesale price of unleaded gasoline. Further, the production of RINs significantly in excess of the RVOs set by the EPA for a calendar year could adversely affect the market price of RINs, particularly towards the end of the year, if refiners and other RFS obligated parties have satisfied their RVOs for the year. A significant decline in the price of RINs and price of LCFS credits for a prolonged period could adversely affect our business, financial condition and results of operations, and could require us to take an impairment charge relating to one or more of our projects.
We are exposed to the risk of failing to meet our contractual commitments to sell RINs from our production.
We may sell forward a portion of our RINs under contracts to fix the revenues from such attributes for financing purposes or to manage our risk against future declines in prices of such Environmental Attributes. If our RNG projects do not generate the amount of RINs sold under such forward contracts we may be required to make up the shortfall of RINs under such forward contracts through purchases on the open market or the payment of liquidated damages. Forward selling our RINs could result in realized prices monetized in a year which do not correspond directly to index prices.
The failure of our hedge counterparties or significant customers to meet their obligations to us may adversely affect our financial results.
To the extent we hedge our RNG revenues, our hedging transactions expose us to the risk that a counterparty fails to perform under a derivative contract. Volatility in the market index to which we hedge our RNG revenues could expose us to variability in our commodity based revenues. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by the counterparty to these derivative contracts could adversely affect our business, financial condition and results of operations.
We also face credit risk because we sell our RNG to a limited number of significant customers who do not post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Regulatory Risks
The reduction or elimination of governmental economic incentives for renewable energy projects or other related policies could adversely affect our business, financial condition and results of operation.
We depend on Environmental Attributes, which are federal, state and local government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, rebates, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy. RINs are created through the RFS program administered by the EPA, which requires transportation fuel sold in the United States to contain a minimum volume of renewable fuel and has historically permitted refineries and importers of transportation fuel to satisfy their RVOs by purchasing either (i) D5 RINs and cellulosic waiver credits (“CWCs”) or (ii) D3 RINs. In a December 1, 2022 proposed rule, EPA proposed to not utilize its cellulosic waiver authority for the years 2023-2025. However, if actual production is lower than the RVO, the EPA will have discretion to utilize CWC. This rule was finalized in July 2023. On December 12, 2024, EPA proposed a partial waiver of 2024 Cellulosic Biofuel Volume Requirements due to the projected shortfall of D3 RINs available to meet the 2024 RVO. This proposal is still pending and, with a new presidential administration, it is unknown when this proposed rule will be finalized (if at all) in 2025. In addition, under the RFS, EPA was required to finalize RVO volumes for 2026 by November 1, 2024 but did not meet that deadline. According to the White House Office of Management and Budget’s Fall Unified Agenda and Regulatory Plan, published on December 13, 2024, EPA indicates that it expects in March 2025 to (i) publish a rule finalizing its December 12, 2024 proposed partial waiver of 2024 Cellulosic Biofuel Volume Requirements and (ii) propose RVO volumes for 2026 (which EPA expects to finalize in December 2025). There can be no assurance that EPA will meet its proposed timelines for these actions. RECs are created through state law requirements for utilities to purchase a portion of their energy from renewable energy sources. 74% and 76% of our operating revenues for 2024 and 2023, respectively, were generated from the sale of Environmental Attributes. These government economic incentives could be reduced or eliminated altogether, or the categories of renewable energy qualifying for such government economic incentives could be changed. These renewable energy program incentives are subject to regulatory oversight and could be administratively or legislatively changed in a manner that could adversely affect our operations. Further, the generation of LCFS credits on our dairy farm project is expected to increase the percentage of our revenues generated from Environmental Attributes. Reductions in, changes to, or eliminations or expirations of governmental incentives could result in decreased demand for, and lower revenues from, our projects. Changes in the level or structure of the RPS of a state for electricity could also result in a decline in our revenues or decreased demand for, and lower revenues from, our electricity projects.
We may be unable to obtain, modify or maintain the regulatory permits, approvals and consents required to construct and operate our projects.
Our operations are subject to various federal, state, and local EHS laws and regulations, including those relating to the release, emission or discharge of materials into the air, water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials and wastes, the health and safety of our employees and other persons, and the generation of RINs and LCFS credits.
These laws and regulations impose numerous obligations applicable to our operations, including the acquisition of permits before construction and operation of our projects; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of our activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from the ownership or operation of our properties. These laws, regulations and permits can require expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment.
Numerous governmental entities have the power to enforce difficult and costly compliance measures or corrective actions pursuant to these laws and regulations and the permits issued under them. We may be required to make significant capital and operating expenditures on an ongoing basis, or to perform remedial or other corrective actions at our properties, to comply with the requirements of these environmental laws and regulations or the terms or conditions of our permits. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required environmental regulatory permits or approvals, which may delay or interrupt our operations and limit our growth and revenue.
Our operations inherently risk incurring significant environmental costs and liabilities due to the need to manage waste from our processing facilities. Spills or other releases of regulated substances, including spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws, rules and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. In connection with certain acquisitions, we could acquire, or be required to
provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the EHS impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
New laws, changes to existing laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make significant additional expenditures. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls at our plants under federal or state law. Present and future federal and state environmental laws and regulations, and interpretations of those laws and regulations, applicable to our operations, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial expenditures that could have a material adverse effect on our results of operations and financial condition. In January 2025, President Trump’s Putting America First in International Environmental Agreements executive order withdrew the United States from the United Nations Framework Convention on Climate Change’s (UNFCCC) Paris Agreement, which aims to reduce net greenhouse gas emissions by 61% below 2005 levels by 2030. This order also withdrew the United States from any similar climate-related agreements made under the UNFCCC. The stated purpose of Trump’s Initial Rescissions of Harmful Executive Orders and Actions executive order is to retract certain practices of President Biden, including those addressing public health and the environment, the climate crisis and climate-related financial risks. The order rescinds identified initiatives related to environmental justice, clean energy and electric vehicles, and energy and infrastructure. These executive orders present risks to federal incentives available to promote renewable energy, as can be seen in the Unleashing American Energy executive order signed by President Trump that explicitly calls for an immediate pause of the disbursement of funds under the IRA and the Infrastructure Investment and Jobs Act, both of which contain renewable energy incentives.
Our ability to generate revenue from sales of RINs and LCFS credits depends on our strict compliance with these federal and state programs, which are complex and can involve a significant degree of judgment. If the agencies that administer and enforce these programs disagree with our judgments, otherwise determine that we are not in compliance, conduct reviews of our activities or make changes to the programs, then our ability to generate or sell these credits could be temporarily restricted pending completion of reviews or as a penalty, permanently limited or lost entirely, and we could also be subject to fines or other sanctions. Moreover, the inability to sell RINs and LCFS credits could adversely affect our business.
In order to construct, modify and operate our projects, we will need to obtain or may need to modify numerous environmental and other regulatory permits, approvals and consents from federal, state and local governmental entities, including air permits, wastewater discharge permits, stormwater permits, permits or consents related to the management of municipal solid waste landfills and permits or consents related to the management and disposal of waste. A number of these permits, approvals and consents must be obtained prior to the start of development of a project. Other permits, approvals and consents are required to be obtained at, or prior to, the time of first commercial operation or within prescribed time frames following commencement of commercial operations. Any failure to successfully obtain or modify the necessary environmental and other regulatory permits, approvals and consents on a timely basis could delay the construction, modification or commencement of commercial operation of our projects. In addition, once a permit, approval or consent has been issued or acquired for a project, we must take steps to comply with the conditions of each permit, approval or consent conditions, including conditions requiring timely development and commencement of the project. Failure to comply with certain conditions within a permit, approval or consent could result in the revocation or suspension of such permit, approval or consent; the imposition of penalties; or other enforcement action by governmental entities. We also may need to modify permits, consents or approvals we have already obtained to reflect changes in project design or requirements, which could trigger a legal or regulatory review under a standard more stringent than the standard under which the permits, approvals or consents were originally issued.
Obtaining and modifying necessary permits, approvals and consents is a time-consuming and expensive process, and we may not be able to obtain or modify them on a timely or cost-effective basis or at all. In the event that we fail to obtain or modify all necessary permits, approvals or consents, we may be forced to delay construction or operation of a project or abandon the project altogether, which could adversely affect our business, financial condition and results of operations. In addition, we may be required to make capital expenditures on an ongoing basis to comply with increasingly stringent federal, state, provincial and local EHS laws, regulations and permits.
Negative attitudes toward renewable energy projects from the U.S. government, other lawmakers and regulators, and activists could adversely affect our business, financial condition and results of operations.
Parties with an interest in other energy sources, including lawmakers, regulators, policymakers, environmental and advocacy organizations or other activists may invest significant time and money in efforts to delay, repeal or otherwise negatively influence regulations and programs that promote renewable energy. Many of these parties have substantially greater resources and influence than we have. Further, changes in U.S. federal, state or local political, social or economic conditions, including a lack of legislative focus on these programs and regulations, could result in their modification, delayed adoption or repeal. Any failure to adopt, delay in implementing, expiration, repeal or modification of these programs and regulations, or the adoption of any programs or regulations
that encourage the use of other energy sources over renewable energy, could adversely affect our business, financial condition and results of operations.
Since 2015, EPA has been attempting to regulate carbon dioxide (CO2) emissions from existing fossil-fuel fired electric power generation facilities under section 111(d) of the Clean Air Act. Depending on how these regulations are structured, they could result in favorable treatment for renewable energy, as happened with the 2015 Clean Power Plan, which allowed facility owners to reduce emissions with “outside the fence” measures, including those associated with renewable energy projects. EPA’s first two efforts to regulate these emissions from power generation facilities, including the Clean Power Plan and the later Affordable Clean Energy Rule, have been struck down through a combination of changes in administration and judicial review. EPA’s most recent regulation is the 2024 Power Plant GHG Rule, which was published on May 9, 2024. The Power Plant GHG Rule rule includes performance-based mechanisms for EGUs burning coal and incentivizes the early retirement of coal-fired plants by having less stringent (or no) emission limits for plants that agree to retire by certain dates. States are required to submit their individual compliance plans by May 11, 2026. State plans could include compliance flexibilities such as emission trading. However, the Power Plant GHG Rule has been heavily litigated, and EPA recently filed a motion that was granted to hold the case in abeyance so that new leadership at EPA can review the rule and consider next steps. Given the emphasis in President Trump’s executive orders regarding favoring fossil fuel production and rescinding the Biden administration’s executive orders on climate change, it is expected that EPA will reconsider this rule. In addition, in the Unleashing American Energy executive order, President Trump also directed the EPA Administrator to submit a report on the “legality and continuing applicability” of its 2009 endangerment finding for GHGs under the CAA. Revoking this finding would undermine the EPA’s regulations covering CO2 and other GHG emissions from power plants and its climate regulatory authority in general.
Revenue from any projects we complete may be adversely affected if there is a decline in public acceptance or support of renewable energy, or regulatory agencies, local communities, or other third parties delay, prevent, or increase the cost of constructing and operating our projects.
Certain persons, associations and groups could oppose renewable energy projects in general or our projects specifically, citing, for example, misuse of water resources, landscape degradation, land use, food scarcity or price increase and harm to the environment. Moreover, regulation may restrict the development of renewable energy plants in certain areas. In order to develop a renewable energy project, we are typically required to obtain, among other things, environmental impact permits or other authorizations and building permits, which in turn require environmental impact studies to be undertaken and public hearings and comment periods to be held during which any person, association or group may oppose a project. Any such opposition may be considered by government officials responsible for granting the relevant permits, which could result in the permits being delayed or not being granted or being granted solely on the condition that we carry out certain corrective measures to the proposed project. Opposition to our projects’ requests for permits or successful challenges or appeals to permits issued for our projects could adversely affect our operating plans.
As a result, we cannot guarantee that the renewable energy plants we currently plan to develop or, to the extent applicable, are developing, will ultimately be authorized or accepted by the local authorities or the local population. For example, the local population could oppose the construction of a renewable energy plant or infrastructure at the local government level, which could in turn lead to the imposition of more restrictive requirements. This type of negative response may lead to legal, public relations or other challenges that could impede our ability to meet our construction targets, achieve commercial operations for a project on schedule, address the changing needs of our projects over time or generate revenues.
In certain jurisdictions, if a significant portion of the local population were to mobilize against a renewable energy plant, it may become difficult, or impossible, for us to obtain or retain the required building permits and authorizations. Moreover, such challenges could result in the cancellation of existing building permits or even, in extreme cases, the dismantling of, or the retroactive imposition of changes in the design of, existing renewable energy plants.
Authorization for the use, construction, and operation of systems and associated transmission facilities on federal, state, and local lands will also require the assessment and evaluation of mineral rights, private rights-of-way, and other easements; environmental, agricultural, cultural, recreational, and aesthetic impacts; and the likely mitigation of adverse effects to these and other resources and uses. The inability to obtain the required permits and other federal, state and local approvals, and any excessive delays in obtaining such permits and approvals due, for example, to litigation or third-party appeals, could potentially prevent us from successfully constructing and operating such projects in a timely manner and could result in the potential forfeiture of any deposit we have made with respect to a given project. Moreover, project approvals subject to project modifications and conditions, including mitigation requirements and costs, could affect the financial success of a given project. Changing regulatory requirements and the discovery of unknown site conditions could also adversely affect the financial success of a given project.
A decrease in acceptance of renewable energy plants by local populations, an increase in the number of legal challenges, or an unfavorable outcome of such legal challenges could adversely affect our business, financial condition and results of operations. We may also be subject to labor unavailability due to multiple simultaneous projects in a geographic region. If we are unable to grow and
manage the capacity that we expect from our projects in our anticipated timeframes, it could adversely affect our business, financial condition and results of operations.
Existing regulations and policies, and future changes to these regulations and policies, may present technical, regulatory and economic barriers to the generation, purchase and use of renewable energy, and may adversely affect the market for credits associated with the production of renewable energy.
The market for renewable energy is influenced by U.S. federal, state and local government regulations and policies concerning renewable energy. These regulations and policies are continuously being modified, which could result in a significant future reduction in the potential demand for renewable energy, including RINs, RECs and LCFS credits, renewable energy project development and investments. For example, on December 12, 2024, EPA proposed a partial waiver of 2024 Cellulosic Biofuel Volume Requirements due to the projected shortfall of D3 RINs available to meet the 2024 RVO. This proposal is still pending, and, with a new presidential administration, it is unknown when this proposed rule will be finalized (if at all) in 2025. Any new government regulations applicable to our renewable energy projects or markets for renewable energy may result in significant additional expenses or related development costs and, as a result, could cause a significant reduction in demand for our renewable energy. For additional information on regulatory developments, see “Item 7A.-Management’s Discussion and Analysis of Financial Condition and Results of Operations -Key Trends-Regulatory, Environmental and Social Trends.”
In order to benefit from RINs and LCFS credits, our RNG projects are required to be registered and are subject to regulatory audit.
We are required to register an RNG project with the EPA and relevant state regulatory agencies to generate Environmental Attributes. As a participant of the EPA's RFS program, we qualify our RINs through a voluntary Quality Assurance Plan, which typically takes from three to five months from first injection of RNG into the commercial pipeline system. The Biogas Regulatory Reform Rule ("BRRR") implemented changes to the RFS program effective January 1, 2025. The BRRR requires that all unseparated K3 RINs generated by the RNG producer on RNG volumes injected into the commercial pipeline distribution system only become valid for sale once they are separated with the support of dispensing statements by a registered dispenser or RIN separator. This process could result in delays to the RNG producer's receipt of the separated K2 RINs from the dispenser. This rule change could also result in a RNG producer's failure to generate K3 RINs for a given gas flow month if the registered biogas producer negligently fails to generate the necessary biogas tokens before the end of the subsequent gas flow month. Furthermore, although no similar qualification process currently exists for LCFS credits, we expect such a process to be implemented and would expect to seek qualification on a state-by-state basis under such future programs. Changes to the LCFS program require annual verification of the CI score assigned to a project. Annual verification could significantly affect the profitability of a project, particularly in the case of a livestock farm project. Delays in obtaining registration, RIN qualification, and any future LCFS credit qualification, or CI rescoring through CARB annual audits, of a new project could delay future revenues from the project and could adversely affect our cash flow. Further, we typically make a large investment in the project prior to receiving the regulatory approval and RIN qualification. BRRR now requires that all RNG producers register their projects and use a Quality Assurance Plan (QAP). QAPs required third-party audits and semi-annual on-site visits of projects to validate generated RINs and overall compliance with the RFS program. We are also subject to a separate third party’s annual attestation review. The QAP provides a process for RIN owners to follow, for an affirmative defense to civil liability, if used or transferred QAP verified RINs were invalidly generated. A project’s failure to comply could result in remedial action by the EPA, including penalties, fines, retirement of RINs, or termination of the project’s registration, any of which could adversely affect our business, financial condition and results of operations. For additional information on recent developments in this area, including the Pico facility’s CI score, see “Item 7A.-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Key Trends-Regulatory, Environmental and Social Trends.”
Our business is subject to the risk of extreme or changing weather patterns.
Extreme weather patterns related to climate change could cause changes in rainfall and storm patterns and intensities, water shortages and changing temperatures, which could result in significant volatility in the supply and prices of energy. In addition, legislation and increased regulation regarding climate change could impose significant costs on us and our suppliers, including costs related to capital equipment, environmental monitoring and reporting and other costs to comply with such regulations.
Furthermore, extreme weather events, such as lightning strikes, ice storms, tornados, extreme wind, hurricanes and other severe storms, wildfires and other unfavorable weather conditions or natural disasters, such as floods, fires, earthquakes, and rising sea-levels, could adversely affect the input and output commodities associated with the renewable energy sector. Such weather events or natural disasters could also require us to temporarily or permanently shut down the equipment associated with our renewable energy projects, such as our access to power and our power to biogas collection, separation and transmission systems, which would impede the ability of our projects to operate and decrease production levels and our revenue. Operational problems, such as degradation of our project’s equipment due to wear or weather or capacity limitations or outages on the electrical transmission network, could also affect
the amount of energy that our projects are able to deliver. Any of these events, to the extent not fully covered by insurance, could adversely affect our business, financial condition and results of operations.
These events could result in significant volatility in the supply and prices of energy. This volatility may create fluctuations in commodity or energy prices and earnings of companies in the renewable energy sectors. See “-Operational Risks-“The concentration in revenues from five of our projects and geographic concentration of our projects expose us to greater risks of production interruptions from severe weather or other interruptions of production or transmission” for additional information.
Our business is subject to risks arising out of climate change, which could result in increased operating costs.
Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs and eliminate future GHG emissions. Governmental and public concern arising from GHG emissions has resulted in increasing regulatory, political, financial and litigation risks in the United States and globally that target predominantly fossil fuel-related energy entities or their operations, which may have indirect effects on other companies or industries, including the renewable energy industry.
The United States has not implemented comprehensive federal climate change legislation. Furthermore, the new presidential administration froze all funding provided by the Bipartisan Infrastructure Law (“Infrastructure Investment and Jobs Act”) and Section 7 of the IRA. However, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.
Cybersecurity and Information Technology Risks
A failure of our IT and data security infrastructure could have a material adverse effect on our business and operations.
We rely upon the capacity, reliability and security of our IT and data security infrastructure and our ability to expand and continually update this infrastructure in response to the changing needs of our business. Our existing IT systems and any new IT systems may not perform as expected. We also face the challenge of supporting our older systems and implementing necessary upgrades. If we experience a problem with the functioning of an important IT system or a security breach of our IT systems, including during system upgrades or new system implementations, the resulting disruptions could have a material adverse effect on our business.
We and some of our third-party vendors receive and store personal information in connection with our human resources operations and other aspects of our business. Our IT systems and those of our third-party vendors, are vulnerable to damages from computer viruses, natural disasters, fire, power loss, telecommunications failures, personnel misconduct, human error, unauthorized access, physical or electronic security breaches, cyber-attacks (including malicious and destructive code, phishing attacks, ransomware, and denial of service attacks), and other similar disruptions. We continue to develop our processes relating to identification, mitigation and response to potential cybersecurity threats, and such processes may prove to be inadequate. Such attacks or security breaches may be perpetrated by bad actors internally or externally (including computer hackers, persons involved with organized crime, or foreign state or foreign state-supported actors). Cybersecurity threat actors employ a wide variety of methods and techniques that are constantly evolving, increasingly sophisticated, and difficult to detect and successfully defend against. Cybersecurity incidents involving our IT systems or those of our third-party vendors could expose us to claims, litigation, regulatory or other governmental investigations, administrative fines and potential liability. Any system failure, accident or security breach could result in disruptions to our operations. A material network breach in the security of our IT systems or those of our third-party vendors could include the theft of our trade secrets, customer information, human resources information or other confidential data, including but not limited to personally identifiable information, that could have a material adverse effect on our business, financial condition, or results of operations. To the extent that any material disruptions or security breaches result in a loss or damage to our data, or an inappropriate disclosure of confidential, proprietary or customer information, it could materially cause damage to our reputation, affect our relationships with our customers and strategic partners, lead to claims against us from governments and private plaintiffs, and ultimately have a material adverse effect on our business. While we have been the previous target of cyberattacks and security breaches, none of these attacks or breaches to date have had a material adverse effect on us. We cannot guarantee that future cyberattacks, if successful, will not have a material effect on our business or financial results.
Many governments have enacted laws requiring companies to provide notice of cyber incidents involving certain types of data, including personal data. Any compromise of our security could result in a violation of applicable domestic and foreign security, privacy or data protection, consumer and other laws, regulatory or other governmental investigations, enforcement actions, and legal and financial exposure, including potential contractual liability that could have a material adverse effect on our business. In addition, we may be required to incur significant costs to protect against and remediate damage caused by these disruptions or security breaches in the future that could have a material adverse effect on our business.
We rely on the technology, infrastructure, and software applications of certain third parties in order to host or operate some of our business. Additionally, we rely on computer hardware purchased in order to operate our business. We do not have control over the operations of the facilities of the third parties that we use. In addition, as of the date of this Report, we have not implemented formal processes to oversee and identify risks from cybersecurity threats associated with our use of third parties. If any of these third-party services experience errors, disruptions, security issues, or other performance deficiencies, if these services, software, or hardware fail or become unavailable due to extended outages, interruptions, defects, or otherwise, or if they are no longer available on commercially reasonable terms or prices (or at all), these issues could result in material errors or defects in our platforms (including causing our platforms to fail), our revenue and margins could materially decline, or our reputation and brand to be materially damaged. Additionally, we could be exposed to material legal or contractual liability, our expenses could materially increase, our ability to manage our operations could be materially interrupted, and our processes for servicing our customers could be materially impaired until equivalent services or technology, if available, are identified, procured, and implemented, all of which may take significant time and resources, increase our costs, and could materially and adversely affect our business. Many of these third-party providers attempt to impose limitations on their liability for such errors, disruptions, defects, performance deficiencies, or failures, and if such limitations are enforceable, we may have additional liability to our customers or third-party providers that could have a material adverse effect on our business. A failure to maintain our relationships with our third-party providers (or obtain adequate replacements), and to receive services from such providers that do not contain any material errors or defects, could adversely affect our ability to deliver effective products and solutions to our customers and adversely affect our business and results of operations.
Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.
As a renewable energy producer, we face various security threats, including among others, computer viruses, malware, ransomware, telecommunication and electrical failures, cyber-attacks or cyber-intrusions over the internet, attachments to emails, persons with access to systems inside our organization, cybersecurity threats to gain unauthorized access to sensitive information or to expose, exfiltrate, alter, delete or render our data or systems unusable, threats to the security of our projects and infrastructure or third-party facilities and infrastructure, such as processing projects and pipelines, natural disasters, threats from terrorist acts and war.
As cyber incidents become more frequent and the sophistication of threat actors increases, our associated cybersecurity costs have and are expected to continue to increase. Specifically, we expect to implement several incremental cybersecurity improvements over the next 18 to 36 months to enhance our defensive capabilities and resilience. Despite our ongoing and anticipated cybersecurity efforts, a successful cybersecurity incident could lead to additional material costs, including those related to the loss of sensitive information, repairs to infrastructure or capabilities essential to our operations, responding to litigation or regulatory investigations, and those related to a material and adverse impact on our reputation, financial position, results of operations, or cash flows.
Third-Party Partner Risks
Failure of third parties to manufacture quality products or provide reliable services in a timely manner could cause delays in developing and operating our projects, which could damage our reputation, adversely affect our partner relationships or adversely affect our growth.
Our success depends on our ability to develop and operate projects in a timely manner, which depends in part on the ability of third parties to provide us with timely and reliable products and services. In developing and operating our projects, we rely on products meeting our design specifications and components manufactured and supplied by third parties, and on services performed by subcontractors. We also rely on subcontractors to perform substantially all of the construction and installation work related to our projects, and we often need to engage subcontractors with whom we have no experience.
If any of our subcontractors are unable to provide services that meet or exceed our customers’ expectations or satisfy our contractual commitments, our reputation, business and operating results could be harmed. In addition, if we are unable to avail ourselves of warranties and other contractual protections with providers of products and services, we may incur liability to our customers or additional costs related to the affected products and services, which could adversely affect our business, financial condition and results of operations. Moreover, any delays, malfunctions, inefficiencies or interruptions in these products or services could adversely affect the quality and performance of our projects and require considerable expense to maintain and repair our projects. This could cause us to experience interruption in our production and distribution of renewable energy and generation of related Environmental Attributes, difficulty retaining current relationships and attracting new relationships, or harm our brand, reputation or growth.
Our projects rely on interconnections with and access to electric distribution and transmission facilities and gas transportation pipelines that are owned and operated by third parties, and as a result, are exposed to risks related to such facilities’ development and operational curtailment risks.
Our projects are interconnected with electric distribution and transmission facilities owned and operated by regulated utilities necessary to deliver the Renewable Electricity that we produce. Our RNG projects are similarly interconnected with gas distribution and interstate pipeline systems required to deliver RNG. A failure or delay in the operation or development of these distribution or transmission facilities could result in a loss of revenues or breach of contract because such a failure or delay could limit the amount of RNG and Renewable Electricity that our operating projects deliver or delay the completion of our construction projects. In addition, certain of our operating projects’ generation may be curtailed without compensation due to distribution and transmission limitations, reducing our revenues and impairing our ability to capitalize fully on a particular project’s potential. Such a failure or curtailment at levels above our expectations could impact our ability to satisfy our supply agreements and adversely affect our business. Additionally, we experience work interruptions from time to time due to federally required maintenance shutdowns.
We are dependent upon our relationships with Waste Management and Republic Services for the operation and maintenance of landfills on which several of our RNG and Renewable Electricity projects operate.
We currently operate seven renewable energy projects (six RNG projects and one Renewable Electricity project) on landfills operated by Waste Management and two RNG projects on landfills operated by Republic Services. Our projects located on Waste Management operated landfills represented 38.5%, 37.3% and 38.9% of our revenue in 2024, 2023 and 2022, respectively. Our projects located on Republic Services operated landfills represented 24.6%, 22.2% and 25.1% of our revenue in 2024, 2023 and 2022, respectively. We are dependent upon Waste Management and Republic Services to operate and maintain their landfill facilities and provide a continuous supply of waste for conversion to RNG and Renewable Electricity. Further, we consider our relationship with these landfill operators an important factor in our growth strategy for additional projects. In the event that we fall out of favor with either of these landfill operators due to a dispute, problems with our operations at one of their facilities or otherwise, the landfill operator may seek to terminate the related project and be less inclined to work with us on future projects.
Additionally, Waste Management and Republic Services could seek to develop their own waste-to-renewable energy conversion projects at other existing landfill locations in lieu of contracting with us for these projects. Failure to maintain these favorable relationships could adversely affect our business, growth strategy, financial condition and results of operations.
We have significant customer concentration, with a limited number of customers accounting for a substantial portion of our revenues.
In 2024, sales to Valero, GE Warren, ExxonMobil and Mercuria represented approximately 17.6%, 15.7%, 13.8 and 11.8%, respectively of our operating revenue. In 2023, sales to Valero, GE Warren and HF Sinclair represented approximately 22.0%, 11.7% and 11.7%, respectively of our operating revenue. Five customers made up approximately 68.2% and 70.7% of our accounts receivable as of December 31, 2024 and 2023, respectively. Revenues from our largest customers may fluctuate from time to time based on our customers’ business needs, market conditions or other factors outside of our control. If any of our largest customers terminates its relationship with us, such termination could adversely affect our revenues and results of operations.
Capital and Credit Risks
Our senior credit facility may not be sufficient to meet our financial needs and contains financial and operating restrictions that may limit our business activities and our access to other forms of credit.
Our senior credit facility consists of an $80.0 million principal amount term loan, of which $56.0 remains outstanding as of December 31, 2024, and a $120.0 million revolving credit line, which is undrawn as of December 31, 2024. This facility may not be sufficient to meet our financial needs as our business grows. The senior credit facility matures in December 2026 and we may be unable to extend or replace it on acceptable terms, or at all. Furthermore, the credit agreement governing our facility (the “Amended Credit Agreement”) imposes business restrictions and contains other covenants that require us to meet specified financial ratios and financial tests. Under the Amended Credit Agreement, we are required to maintain:
•a fixed charge coverage ratio of at least 1.20 to 1.00; and
•a total leverage ratio of not more than 3.00 to 1.00.
The Amended Credit Agreement is subject to customary events of default, and contemplates that we would be in default if, for any fiscal quarter (x) the average monthly D3 RIN price is less than $0.80 per RIN and (y) the consolidated EBITDA for such quarter is less than $6.0 million. Additional information regarding the senior credit facility and the Amended Credit Agreement can be found
in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
Our failure to comply with these covenants could result in the declaration of an event of default and cause us to be unable to borrow under the Amended Credit Agreement. In addition to preventing additional borrowings under the Amended Credit Agreement, an event of default, if not cured or waived, could result in the acceleration of the maturity of indebtedness outstanding under the facility, which would require us to immediately repay all amounts outstanding. If an event of default occurs, we may not be able to cure it within any applicable cure period, or at all. As of December 31, 2024, we were in compliance with all covenants.
We may be required to write-off or impair capitalized costs or intangible assets in the future or we may incur restructuring costs or other charges, each of which would harm our earnings.
In accordance with GAAP, we capitalize certain expenditures and advances relating to our acquisitions, pending acquisitions, project development costs, interest costs related to project financing and certain energy assets. In addition, we have considerable unamortized assets. In 2024, we recorded impairment charges of $1.6 million of which $1.0 related to RNG and REG assets that were deemed obsolete or inoperable for current operations, $0.3 million related to an REG site that ceased operations and was subsequently sold, and $0.3 related to REG assets following initial startup testing failures for one of our construction work in progress sites. In 2023, we recorded impairment charges of $0.9 million of which $0.8 million related to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and $0.1 related to obsolete REG critical spares. In 2022, we recorded impairment charges of $2.1 million related to our estimate of future cash flows not exceeding the carrying amount of a Renewable Electricity facility and discrete charges of $1.4 million and $1.1 million related to the ongoing development of the Montauk Ag Renewables and an asset component of an RNG facility. In addition, from time to time in future periods, we may be required to incur a charge against earnings in an amount equal to any unamortized capitalized expenditures and advances, net of any portion thereof that we estimate will be recoverable, through sale or otherwise, relating to: (i) any operation or other asset that is being sold, permanently shut down, impaired or has not generated or is not expected to generate sufficient cash flow; (ii) any pending acquisition that is not consummated; (iii) any project that is not expected to be successfully completed; and (iv) any goodwill or other intangible assets that are determined to be impaired. A material write-off or impairment change could adversely affect our ability to comply with the financial covenants under the Amended Credit Agreement, and otherwise adversely affect our business, financial condition and results of operations.
Emerging Growth Company Risks
For as long as we are an emerging growth company, we will not be required to comply with certain requirements that apply to other public companies.
We are an emerging growth company, as defined in the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years following January 22, 2021, the completion of the IPO, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation and any golden-parachute payments not previously approved. In addition, the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for adopting new or revised financial accounting standards. We intend to take advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards permitted under the JOBS Act until we are no longer an emerging growth company. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to the JOBS Act.
We will remain an emerging growth company for up to five years after January 22, 2021, the date of the IPO, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.
For so long as we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. We cannot predict whether investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.
If we identify material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, we may be unable to accurately or timely report our financial condition or results of operations, which may adversely affect our business.
We are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act, which require management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of controls over financial reporting. As an emerging growth company, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting pursuant to Section 404 until the date we are no longer an emerging growth company. At such time, our independent registered public accounting firm may issue a report that is adverse in the event that it is not satisfied with the level at which our controls are documented, designed or operating.
To comply with the requirements of being a public company, we have undertaken various actions, including implementing additional internal controls and procedures and hiring additional accounting or internal audit staff, increasing the use of external specialists and may need to take additional actions in the future. Testing and maintaining internal controls can divert our management’s attention from other matters that are important to the operation of our business. If we identify material weaknesses in our internal controls over financial reporting or are unable to comply with the requirements of Section 404 or assert that our internal controls over financial reporting are effective, or if our independent registered public accounting firm is unable to express an opinion as to the effectiveness of our internal controls over financial reporting, investors may lose confidence in the accuracy and completeness of our financial reports and the market price of our common stock could be negatively affected. In addition, we could become subject to investigations by the SEC or other regulatory authorities, which could require additional financial and management resources.
Common Stock Risks
Our shares of common stock may trade on more than one market and this may result in price variations.
The Company’s common stock is traded on the Nasdaq Capital Market under the ticker symbol of “MNTK” and on the JSE under the ticker symbol of “MKR.” Trading in our common stock takes place in USD on the Nasdaq Capital Market and ZAR on the JSE, and at different times, resulting from different time zones, trading days and public holidays in the United States and South Africa. The trading prices of our common stock on these two markets may differ due to these and other factors. Any decrease in the price of our common stock on either exchange could cause a corresponding decrease in the trading price of the common stock on the other exchange.
Future sales of our common stock in the public market could cause the market price of our common stock to decline.
Sales of a substantial number of shares of our common stock in the public market, or the perception that these sales might occur, could depress the market price of our common stock and could impair our ability to raise capital through the sale of additional equity securities. Many of our existing equity holders have substantial unrecognized gains on the value of the equity they hold and may take steps to sell their shares or otherwise secure the unrecognized gains on those shares. Additionally, pursuant to the terms of the Fourth Amended and Restated Promissory Note, MNK is required to use the proceeds from any sale of the 976,623 shares of our common stock pledged as security for MNK’s loan obligations to repay the amounts due under the Note. These sales may have a downward impact on the prevailing market price of our common stock. The maturity of the loan has been extended until 2033 but MNK will continue to evaluate options to complete the sale of these shares including but not limited to register sale or underwritten offering in the US or direct sale to a South African investor. We also have default provisions in the underlying note whereby MNK can satisfy the note by delivering the shares back to us as permitted by applicable law. We are unable to predict the timing of or the effect that such sales, by MNK or by other shareholders, may have on the prevailing market price of our common stock.
We are a “controlled company” within the meaning of the Nasdaq rules and, as a result, qualify for, and intend to rely on, exemptions and relief from certain governance requirements.
Stockholder affiliates of Mr. Copelyn and Mr. Govender have entered into a Consortium Agreement whereby they agree to act together when voting our common stock in the election of directors, among other matters. The parties to the Consortium Agreement beneficially owned, in the aggregate, approximately 52.3% of our common stock as of February 28, 2025. As a result, we are a “controlled company” within the meaning of the Nasdaq corporate governance standards. Under these corporate governance standards, a company of which more than 50% of the voting power in the election of directors is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements. For example, controlled companies are not required to have:
•a board that is composed of a majority of “independent directors,” as defined under the Nasdaq rules;
•a compensation committee that is composed entirely of independent directors; and
•director nominations that are made, or recommended to the full board of directors, by its independent directors, or by a nominations/governance committee that is composed entirely of independent directors.
We may rely on any or all of these exemptions so long as we remain a controlled company.
The concentration of our capital stock ownership may limit our stockholders’ ability to influence corporate matters and may involve other risks.
As a result of the Consortium Agreement, certain stockholders control matters requiring stockholder approval, including the election of our directors and approval of significant corporate transactions. This concentration of ownership may also have the effect of delaying or preventing a change in control that may be otherwise viewed as beneficial by stockholders other than management. Accordingly, other stockholders may not have any influence over significant corporate transactions and other corporate matters. There is also a risk that certain controlling stockholders may have interests which are different from other stockholders and that they will pursue an agenda which is beneficial to themselves at the expense of other stockholders.
Certain of our directors reside outside of the United States and it may be difficult to enforce judgments against them in the United States.
Two of our directors, all of our executive officers and all of our operating assets reside in the United States. Directors Copelyn, Govender, Ahmed and Shaik are residents of South Africa. As a result, it may not be possible for you to effect service of legal process, within the United States or elsewhere, upon certain of our directors, including matters arising under U.S. federal securities laws. This may make it difficult or impossible to bring an action against these individuals in the United States in the event that a person believes that their rights have been violated under applicable law or otherwise. Even if an action of this type is successfully brought, the laws of the United States and South Africa may render a judgment unenforceable.
General Risk Factors
Our issuance of additional capital stock in connection with financings, acquisitions, investments, our equity incentive plans or otherwise will dilute stockholders.
We expect to issue additional capital stock in the future that will result in dilution to stockholders. We expect to grant equity awards to employees, directors and consultants under our equity incentive plans. We may also raise capital through equity financings in the future. As part of our business strategy, we may acquire or make investments in companies and issue equity securities to pay for any such acquisition or investment. Any such issuances of additional capital stock may cause stockholders to experience significant dilution of their ownership interests and the per share value of our common stock to decline.
If securities or industry analysts do not publish research or publish inaccurate or unfavorable research about our business, our share price and trading volume could decline.
The trading market for our common stock will be influenced by the research and reports that securities or industry analysts publish about us. If securities or industry analysts initiate coverage and one or more of the analysts who cover us downgrade our common stock or publish inaccurate or unfavorable research about our company, our common stock share price would likely decline. If analysts publish target prices for our common stock that are below historical sales prices or the then-current public price of our common stock, it could cause our stock price to decline significantly. Further, if one or more of these analysts cease coverage of us or fail to publish reports on us regularly, demand for our common stock could decrease, which might cause our common stock price and trading volume to decline.
We are highly dependent on our senior management team and other highly skilled personnel, and if we are not successful in attracting or retaining highly qualified personnel, we may not be able to successfully implement our business strategy.
Our success depends, in significant part, on the continued services of our senior management team and on our ability to attract, motivate, develop and retain a sufficient number of other highly skilled personnel, including engineering, design, finance and support personnel. Our senior management team has extensive experience in the renewable energy industry, and we believe that their depth of experience is instrumental to our continued success. The loss of any one or more members of our senior management team, for any reason, including resignation or retirement, could impair our ability to execute our business strategy and adversely affect our business, financial condition and results of operations.
Competition for qualified highly skilled personnel can be strong, and we cannot assure you that we will be successful in attracting or retaining such personnel now or in the future. Any inability to recruit, develop and retain qualified employees may result in high employee turnover and may force us to pay significantly higher wages, which may harm our profitability. Additionally, we do
not carry key personnel insurance for any of our management executives, and the loss of any key employee or our inability to recruit, develop and retain these individuals as needed, could adversely affect our business, financial condition and results of operations.
Our ability to pay regular dividends on our common stock is subject to the discretion of our Board of Directors.
Our common stock will have no contractual or other legal right to dividends. The payment of future dividends on our common stock will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board of Directors deems relevant. Accordingly, we may not make, or may have to reduce or eliminate, the payment of dividends on our common stock, which could adversely affect the market price of our common stock.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES.
We own approximately 216 acres in Turkey, NC for which we are using to develop Montauk Ag Renewables. Montauk Ag Renewables is reported in our Renewable Electricity Generation segment.
Our principal executive office is located in Pittsburgh, Pennsylvania. We lease an approximate 24,000 square foot office space at this site for approximately $45,000 per month pursuant to a lease which expires on April 30, 2033.
We also lease an 8,400 square foot regional office and warehouse to service our sites in Houston, Texas, pursuant to a lease which expires on December 31, 2026, for approximately $8,000 per month. We currently own and operate 13 projects, 11 of which are RNG projects and two of which are Renewable Electricity projects. See “Item 1. Business-Our Current Operating Portfolio” for further descriptions of our projects, which information is incorporated into this item by reference.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS.
From time to time we and our subsidiaries may be parties to legal proceedings arising in the normal course of our business. We and our subsidiaries are currently not a party, nor is our property subject, to any material pending legal proceedings. None of our directors, officers, affiliates, or any owner of record or beneficial owner of more than 5% of our common stock, is involved in a material proceeding adverse to us or our subsidiaries or has a material interest adverse to us or our subsidiaries.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES.
Not Applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information
The Company’s common stock has traded on the Nasdaq Capital Market under the ticker symbol of “MNTK” and on the JSE under the ticker symbol of “MKR” since January 22, 2021. Prior to that time, there was no established public trading market for the Company’s common stock.
Holders of Montauk Common Stock
As of March 7, 2025, there were 12 holders of record of 143,717,391 shares of Montauk common stock outstanding as of such date. The number of holders of record of Montauk common stock does not reflect the number of beneficial holders whose shares are held by depositaries, brokers or other nominees.
Performance Graph
The following stock performance graph compares our total stock return with the total return for (a) NASDAQ Composite Index and (b) an industry peer group. Our 2024 and 2023 peer group, which is comprised of companies that we believe have comparable characteristics and are in the same industry or line-of-business, consists of Ameresco, Inc., Aemetis, Inc., Anaergia, Inc., Clean Energy Fuels Corp., Gevo, Inc., and Opal Fuels, Inc. Our 2022 peer group consisted of Aemetis Inc., Clean Energy Fuels Corp., and Gevo Inc. Our eleven month 2021 peer group also included Archaea Energy, Inc., and Renewable Energy Group Inc. but these entities were acquired and ceased trading during 2022 and, as such, a separate line showing the total returns for this group is not possible in the below performance graph through December 31, 2022. The graph assumes that on January 22, 2021, the date our common stock began trading on the Nasdaq Capital Market, $100 was invested in our common stock and in each index based on the closing market price on that day and that all dividends were reinvested. The returns shown are based on historical events and are not intended to suggest future performance.
The following performance graph and related information is being furnished and shall not be deemed “soliciting material” or “filed” with the SEC for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities under that section, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it into reference into such filing.
1/22/21
3/21
6/21
9/21
12/21
3/22
6/22
9/22
12/22
Montauk Renewables, Inc.
100.00
116.49
73.87
108.29
98.84
108.00
96.91
168.18
106.36
NASDAQ Composite
100.00
102.95
112.92
112.66
122.18
111.25
86.46
83.08
82.43
Peer Group
100.00
105.94
94.35
87.29
88.23
89.02
50.82
64.52
55.01
3/23
6/23
9/23
12/23
3/24
6/24
9/24
12/24
Montauk Renewables, Inc.
75.89
71.75
87.85
85.92
40.12
54.97
50.24
38.38
NASDAQ Composite
96.48
109.07
104.77
119.22
130.32
141.36
145.26
154.48
Peer Group
47.23
49.77
42.25
35.22
28.09
27.16
33.85
27.12
Dividend Policy
The Company did not pay any dividends in the fiscal year ended December 31, 2024 and currently intends to retain future earnings, if any, to finance the operations, growth and development of its business. Any future determination as to the declaration and payment of dividends, if any, will be at the discretion of our Board of Directors, subject to compliance with contractual restrictions and covenants in the agreements governing our current and future indebtedness and the DGCL. Any such determination will also
depend upon our business prospects, results of operations, financial condition, cash requirements and availability, and other factors that our Board of Directors may deem relevant.
Securities Authorized for Issuance Under Equity Compensation Plans
The information required by Item 5 of Form 10-K regarding equity compensation plans is incorporated herein by reference to Item 12 of Part III of this Annual Report.
Issuer Repurchases of Equity Securities
None.
Recent Sales of Unregistered Securities
None.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. RESERVED

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K.
In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A.-Risk Factors” and elsewhere in this report.
This section generally discusses our results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023. For discussion and analysis of our results for the year ended December 31, 2023 compared to the year ended December 31, 2022 , refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K filed with the SEC on March 14, 2024.
Overview
Montauk is a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources for beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply RNG into the transportation industry and use RNG to produce Renewable Electricity. We are one of the largest U.S. producers of RNG, having participated in the industry for over 30 years. We established our currently operating portfolio of 11 RNG and two Renewable Electricity and development projects through self-development, partnerships, and acquisitions that span seven states.
Biogas is produced by microbes as they break down organic matter in the absence of oxygen (during a process called anaerobic digestion). Our two current sources of commercial scale biogas are LFG and ADG, which is produced inside an airtight tank used to breakdown organic matter, such as livestock waste. We typically secure our biogas feedstock through long-term fuel supply agreements and property lease agreements with biogas site hosts. Once we secure long-term fuel supply rights, we design, build, own, and operate facilities that convert the biogas into RNG or use the processed biogas to produce Renewable Electricity. We sell the RNG and Renewable Electricity through a variety of short-, medium-, and long-term agreements. Because we are capturing waste methane and making use of a renewable source of energy, our RNG and Renewable Electricity generate valuable Environmental Attributes, which we are able to monetize under federal and state initiatives.
Recent Developments
RINs Generated but Unsold
Our profitability is highly dependent on the market price of Environmental Attributes, including the market price for 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. We decided to not transfer all available D3 RINs generated and available for transfer during the fourth quarter of 2024. As a result, in the first quarter of 2025, we had approximately 9,885 RINs in inventory related to 2024 RNG production. We have entered into commitments to transfer all RINs generated and available for sale from 2024 RNG production. We have not entered into commitments to transfer future RINs generated from forecasted future 2025 RNG production. The average D3 RIN index price for the fourth quarter of 2024 and January 2025 through February 28, 2025 was approximately $2.80 and $2.42, respectively.
Calendar Quarter
RINs Available for Sale
RINs Sold
RINs sold as % of RINs Available
RINs Available but Unsold
RINs Unsold as % of RINs Available
2023 First Quarter
11,215
2,949
26.3%
8,266
73.7%
2023 Second Quarter
20,407
17,441
85.5%
2,966
14.5%
2023 Third Quarter
14,514
13,750
94.7%
5.3%
2023 Fourth Quarter
10,904
10,796
99.0%
1.0%
2024 First Quarter
11,240
7,889
70.2%
3,351
29.8%
2024 Second Quarter
14,707
10,000
68.0%
4,707
32.0%
2024 Third Quarter
15,895
15,750
99.1%
0.9%
2024 Fourth Quarter
9,822
3,000
30.5%
6,822
69.5%
Capital Development Summary
The following summarizes our ongoing development growth plans expected capacity contribution, anticipated commencement of operations, and capital expenditure estimate, respectively, excluding Montauk Ag Renewables Development project:
Development Opportunity
Estimated Capacity Contribution
(MMBtu/day)
Anticipated Commencement Date
Estimated Capital Expenditure
Second Apex RNG Facility
2,100
2025 second quarter
$30,000-$40,000
Blue Granite RNG Facility
Delayed
TBD
Bowerman RNG Facility
3,600
$85,000-$95,000
European Energy Facilities
N/A
$65,000-$75,000
Tulsa RNG Facility
1,500
$25,000-$35,000
Pico Digestion Capacity Increase
In 2024, we successfully commissioned the expansion of our digestion capacity which is necessary to process the final tranche of increased feedstock expected to be received in the second quarter of 2025. Upon receipt of the final tranche, we will make the final contractual payment to the dairy host. As a result of the increased digestion capacity, we produced approximately 73.4% more MMBtu during 2024 as compared to 2023.
Carbon Dioxide Beneficial Use Opportunity
In 2024, we signed a contract for the delivery of 140 thousand tons per year of biogenic carbon dioxide (“CO2”) from our four Texas facilities. We intend to capture, clean and liquefy CO2 at select Texas facilities, at which point it will be transported to EE North America (“EENA”), a Texas-based e-methanol facility. The delivery term is expected to last at least 15 years with first delivery expected to begin in 2027. During 2024, we completed the initial site surveys related to locating the CO2 processing equipment, evaluated equipment suppliers, and started engineering design. We continue to target a commissioning start in 2027 and currently expect the capital investment to begin in the second quarter of 2025 for long lead equipment and design engineering.
Waste-stream Biogas Recovery
In 2024, a collaboration with Emvolon was announced to transform methane emissions from waste stream biogas into high-value carbon negative fuel. Leveraging Emvolon's patented technology, the initial pilot at our Atascocita facility in Houston, Texas is a small-scale demonstration of recovering and converting biogas into green methanol. The pilot is designed to provide proof of concept and we may eventually move to a commercial facility capable of producing up to 15 thousand gallons of green methanol per year. The ultimate goal is to lead to a full-scale, commercial system capable of producing up to 2,400 gallons of methanol annually at the same or similar sites. We do not expect any short term financial benefits from this demonstration nor a disruption to our operations.
REG Facility Sale
In 2024, we reached an agreement with the site host to sell the gas rights ahead of the fuel supply expiration of one of our existing REG operating facilities. We received proceeds of $1,000 and no longer have obligations to decommission or remove any machinery or equipment at the site. The proceeds received were in excess of the carrying value of the site. The PPA at this site expired during 2024 at which time we estimated that the revenues from this site would significantly decrease adversely impacting this sites future cash flows from operations. The effective date of the sale was October 1, 2024. In connection with the sale, we secured fuel supply agreement amendments to extend the terms of our existing RNG operating facilities, Atascocita and Coastal Plains.
RNG Facility Sale
In December 2024, we entered into an asset purchase agreement to sell an RNG site for a purchase price of $1,000. We entered into the agreement regarding this immaterial site in advance of the expiration of the gas rights agreement at this site. The proceeds received were in excess of the carrying value of the site.
Tulsa REG Conversion to RNG
In 2025, we began an initiative to convert our Tulsa, Oklahoma Renewable Electric Generation facility project through the design and construction of an RNG facility. The project will offer a variable inlet capacity providing production capacity of approximately 1,500 MMBtu per day and designed to beneficially process all of the available inlet gas feedstock from its landfill host.
We expect the capital investment to range from approximately $25,000 to $35,000 and be commissioned during the first quarter of 2027.
Second Apex RNG Facility
In 2022, we announced the planned construction of a second RNG processing facility at the Apex landfill. The construction of a second facility under our existing fuel supply agreement was triggered by biogas feedstock volumes exceeding production capabilities discussions with the landfill host, and the host's waste intake forecasted projections. As the landfill host increases waste intake, we believe the additional 2,100 MMBtu per day of production capacity will enable us to process the forecasted increase in biogas feedstock volumes. We continue to expect there will be a period where we have excess availability capacity after the second facility is commissioned while the landfill host increases their waste intake. We are incurring capital expenditures for the project and expect commercial operations in the second quarter of 2025.
Montauk Ag Asset Acquisition
In 2021, through a wholly-owned subsidiary Montauk Ag Renewables, we completed an asset purchase related to developing technology and a centralized processing location to recover residual natural resources from the waste streams of modern agriculture and to refine and recycle such waste products through proprietary and other processes in order to produce high quality renewable natural gas and recapture nitrogen, phosphorus, and micronutrient organic fertilizer alternatives (the “Montauk Ag Renewables Acquisition”).
Regulatory update
Our progress with regulatory agencies in North Carolina related to the resulting power generation derived from swine waste to confirm its eligibility for RECs under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production remains ongoing. The Turkey location was approved to participate in the Piedmont Natural Gas Renewable Gas Pilot Program which is a step towards obtaining the NREF designation under the NCUC. In January 2024, we received notification from the NCUC that the Turkey, NC location was approved for an NREF and Certificate of Public Convenience and Necessity. In October 2024, our amended NREF application was approved. In December 2024, as part of a broader North Carolina omnibus bill package, the State of North Carolina approved a change in the laws governing the generation of RECs from swine waste under its renewable energy portfolio standards. For qualifying projects in qualifying locations, qualifying swine REC generators have the ability to generate 3:1 RECs for a period of 8 years, followed by 2:1 RECs for a period of 6 years, with normal 1:1 REC generation thereafter. The implementation of this law is ongoing with the NCUC and is subject to limitations, including but not limited to, the annual generation of swine RECs under the change in law.
Offtake update
In July 2023 we signed a REC agreement with Duke Energy (“Duke”). At full first phase capacity, we anticipate the ability to process feedstock from over 200 hog spaces per day, which equates to over two hundred tons of daily waste collection. We currently estimate the first phase of the project will annually produce approximately 45 to 50 MWh equivalents through the combination of 190 to 200 MMBtu and 25 to 30 MWh. We also estimate that at full processing capabilities, the first phase of the project will additionally produce annually 17 to 20 tons of organic fertilizer alternatives. Once the first phase and the facility has been fully commissioned, the project will provide sufficient capacity to satisfy the Duke REC agreement through the deployment of up to eight operational processing lines at the Turkey Creek facility.
With the change in REC generation passed by the state of North Carolina, we are in various other negotiations with other utility users to provide swine RECs from our expected first phase production of MWh.
Feedstock collection update
We have entered into agreements with over forty separate farming locations to provide access to waste from at least 200 thousand hog spaces to support our expected processing needs under our first phase for the Turkey, NC location. We continue to install collection equipment at these separate farms to access the waste. We currently estimate capital investment of up to approximately $250 at each farm related to the installed collection equipment.
We continue to test the most efficient methods of transporting the swine feedstock from the collection farms to the centralized process location. Currently, we are testing a waste palletization process on the mobile equipment. This palletization will capture the energy content in the waste preventing energy decay from time as well as enabling more efficient processing through the reactor. We currently estimate that each mobile collection and transportation unit could range up to approximately $300.
Interconnection update
Our electricity interconnection is ongoing and expected to be completed in the fourth quarter of 2025. This timeline meets our expectations for the commissioning of our reactors and to begin revenue generating activities. Additionally, and to provide future optionality, the gas interconnection is expected to be commissioned in the second quarter of 2025. While the production of RNG is currently secondary to the generation of MWh and swine RECs, this gas interconnection could provide future revenue opportunities to the Turkey, NC location through either production on site or through the injection of gas from other providers.
Production construction update
Including the original equipment acquired in the Montauk Ag Renewables Acquisition, the Turkey, North Carolina asset acquisition, and the relocation of the Magnolia, NC site reactor to Turkey, NC, we currently expect the first phase capital investment to range between $140,000 and $160,000. We continue to use the pilot reactor that was relocated in 2023 and previously operated prior to the 2021 Montauk Ag Renewables Acquisition. The pilot reactor testing includes refining feedstock conveyance, equipment processing, product gas composition, and the composition of the solid output. We have processed and tested both the biogas and micronutrient organic fertilizer alternatives. We are also continuing to staff the Turkey, North Carolina location. With the engineering of the Turkey, NC location being substantively completed, we have finalized an EPC contract to complete the site construction.
Excluding capital expenditures related to feedstock processing but including the original 2021 Montauk Ag Asset Acquisition, we have incurred the following significant capital expenditures at the Turkey, NC site:
•$16,856 related to the site including land and improvements
•$15,891 associated with electrical and engineering related matters
•$8,369 related to production processing equipment
•$4,415 related to interconnection
•$1,841 related to the reactors
We continue to develop the opportunities with Montauk Ag Renewables and can give no assurances that our plans related to this acquisition will meet our expectations. Utility interconnection, both inbound to and outbound from our centralized Turkey, NC processing facility is dependent on factors outside of our control. Regulatory development and offtake negotiations could delay our ability to fully optimize or meet the timing expectations related to revenue producing activities. Our current construction timeline and costs are subject to delays or costs increases, respectively. We continue to design and plan for the development of the Turkey, NC facility to be used for commercial production. We expect the Magnolia, NC location to be used for various feedstock processing needs. Based on our current development timeline expectations, we expect to commence significant revenue generating activities in 2026. We intend to contract with additional farms to secure feedstock sources for future production processes.
Bowerman RNG Project
In 2023, we announced a planned development of a renewable natural gas landfill project in Irvine, CA at the Frank R. Bowerman Landfill to process the large and growing volumes of biogas in excess of the existing capacity of the REG facility. We expect facility commissioning in 2027 and expect the capital investment to range between $85,000 - $95,000. As part of the agreement to develop the RNG plant, we agreed to work with the landfill host on the landfill's management of its wellfield and flare facility permit requirements. The landfill has proposed corresponding changes to our agreement, which could impact our existing commissioning schedule. We continue to work with the landfill on these proposed changes to assess what, if any, impacts these changes could have on receipt of required regional regulatory construction permits. The project is anticipated to have production nameplate capacity of approximately 3,600 MMBtu per day, assuming currently forecasted biogas feedstock volumes projected to be available from the host landfill at the time of commissioning. We continue to incur capital expenditures for this project.
Blue Granite RNG Project
In 2023, we announced the planned entrance into South Carolina with the development of a new landfill gas-to-RNG facility. The planned project was expected to contribute approximately 900 MMBtu per day of production capacity upon commissioning.
We experienced delays with our interconnection, most recently due to the utility informing us of their near-term prioritization of remediation efforts from the impacts of Hurricane Helene. In February 2025, we received notice from the utility that it will no longer be honoring a letter of intent secured when we won the development rights to this location and will no longer accept RNG into its distribution system. We continue to review various alternatives related to interconnection opportunities as part of our considerations for offtake options with the understanding those alternatives may differ from initial development project assumptions, included but not limited to physical and virtual and fixed interconnections. We are also reviewing alternatives for this site around producing energy other than RNG. We have paused further capital expenditures related to this site while we consider all alternatives.
Key Trends
Market Trends Affecting the Renewable Fuel Market
We believe rising demand for RNG is attributable to a variety of factors, including growing public support for renewable energy, U.S. governmental actions to increase energy independence, environmental concerns increasing demand for natural gas-powered vehicles, job creation, and increasing investment in the renewable energy sector.
Key drivers for the long-term growth of RNG include the following factors:
•Regulatory or policy initiatives, including the federal RFS program and state-level low-carbon fuel programs in states such as California and Oregon, that drive demand for RNG and its derivative Environmental Attributes (as further described below).
•Efficiency, mobility and capital cost flexibility in RNG operations enable it to compete successfully in multiple markets. Our operating model is nimble, as we commonly use modular equipment; our RNG processing equipment is more efficient than its fossil-fuel equivalents.
•Demand for compressed natural gas (“CNG”) from natural gas-fueled vehicles. The RNG we create is pipeline-quality and can be used for transportation fuel when converted to CNG. CNG is commonly used by medium-duty fleets that are close to fueling stations, such as city fleets, local delivery trucks and waste haulers.
•Regulatory requirements, market pressure and public relations challenges increase the time, cost and difficulty of permitting new fossil fuel-fired facilities.
Factors Affecting Our Future Operating Results:
Conversion of Electricity Projects to RNG Projects:
We continue to evaluate opportunities to convert existing facilities from Renewable Electricity to RNG production. These opportunities tend to be most attractive for any merchant electricity facilities given the favorable economics for the sale of RNG plus RINs relative to the sale of market rate electricity plus RECs. This strategy has been an increasingly attractive avenue for growth since 2014 when RNG from landfills became eligible for D3 RINs. However, during the conversion of a project, there is a gap in production while the electricity project is offline until it commences operation as an RNG facility, which can adversely affect us. This timing effect may adversely affect our operating results as a result of our potential conversion of Renewable Electricity projects. Upon completion of a conversion, we expect that the increase in revenue upon commencement of RNG production will more than offset the loss of revenue from Renewable Electricity production. Historically, we have taken advantage of these opportunities on a gradual basis at our merchant electricity facilities, such as Atascocita and Coastal Plains.
Acquisition and Development Pipeline
The timing and extent of our development pipeline affects our operating results due to:
•Impact of Higher Selling, General and Administrative Expenses Prior to the Commencement of a Project’s Operation: We incur significant expenses in the development of new RNG projects. Under the Biogas Regulatory Reform Rule, effective July 1, 2024, theoretical storage of RNG for future RIN generation prior to receiving EPA registration is no longer permitted and the receipt of RINs will no longer be delayed after injecting into a pipeline. We expect the elimination of theoretical storage, when combined with more timely EPA registration, to not materially impact the commencement of RIN revenue generation after pipeline injection.
•Shifts in Revenue Composition for Projects from New Fuel Sources: As we expand into livestock farm projects, our revenue composition from Environmental Attributes will change. We believe that livestock farms offer us a lucrative opportunity, as the value of LCFS credits for dairy farm projects, for example, are a multiple of those realized from landfill projects due to the significantly more attractive CI score of livestock farms.
•Incurrence of Expenses Associated with Pursuing Prospective Projects That Do Not Come to Fruition: We incur expenses to pursue prospective projects with the goal of a site host accepting our proposal or being awarded a project in a competitive bidding process. Historically, we have evaluated opportunities which we decided not to pursue further due to the prospective project not meeting our internal investment thresholds or a lack of success in a competitive bidding process. To the extent we seek to pursue a greater number of projects or bidding for projects becomes more competitive, our expenses may increase.
Regulatory, Environmental and Social Trends
Regulatory, environmental and social factors are key drivers that incentivize the development of RNG and Renewable Electricity projects and influence the economics of these projects. We are subject to the possibility of legislative and regulatory changes to certain incentives, such as RINs, RECs and GHG initiatives. On July 12, 2023, the EPA issued final rules in the Federal Register for the RFS volume requirements for 2023-2025. Final volumes for cellulosic biofuel were set at 838, 1,090 and 1,376 million RINs for the three years 2023, 2024 and 2025, respectively. The EPA did not finalize the eRIN program in this ruling, however, it indicated that it will continue to work on potential paths forward for the eRIN program. However, the EPA did not set a new date for a revised eRIN program. The cellulosic biofuel volumes in the final rule for 2024 and 2025 are lower than the proposed volume as they do not include cellulosic biofuel from eRINs. The final rule also included significant changes to the existing RFS
program, referred to as BRRR, that will require the RNG industry to modify how all RINs are generated. On January 1, 2025, all RFS participants must comply with BRRR provisions. We have registered all of our facilities under the BRRR provisions and have obtained Q-RIN status for RIN generation starting January 1, 2025. Under the BRRR provisions, the EPA finalized a limitation that biogas from one facility has a single use under the RFS as proposed (i.e., biointermediate, RNG or CNG/LNG via biogas closed distribution system). The EPA clarified that this does not preclude non-RFS uses at same facility.
The EPA did not meet the statutorily required deadline of November 2024 to finalize 2026 obligations under the RFS. The EPA is still expected to target March 2025 to propose RFS obligations for 2026 unless the EPA is directed otherwise by the Trump administration.
In December 2023, CARB released the formal proposal for new LCFS rules. The proposed rules will increase the stringency of CI reduction targets from 20% to 30% in 2030 and create a 2045 target of 90%. This reduction would have the potential impact of reducing the number of net credits in the program. CARB approved these new rules in November 2024, however in February 2025, the California Office of Administrative Law disapproved the changes because the regulations were not written in a way that persons directly affected by them could easily understand. CARB believes this disapproval to be routine and indicated its intention to resubmit the rules, which it has until June 2025 to do. Any substantive changes would be subject to a public comment period. The industry may see pricing volatility including potential decreases to LCFS credit prices whereas the amendments as originally approved were expected to increase LCFS credit prices. Also in the rules is a phase out of avoided methane crediting for dairy and swine manure pathways by 2040 for CNG usage and through 2045 for RNG used to produce hydrogen. The RNG deliverability/book and claim provisions for out-of-region projects will be eliminated for all projects that break ground after 2030. These projects will be required to demonstrate physical deliverability requirements beginning in 2041.
Changes to the LCFS program require annual verification of the CI score assigned to a project. Annual verification could significantly affect the profitability of a project, particularly in the case of a livestock farm project.
Factors Affecting Revenue
Our total operating revenues include renewable energy and related sales of Environmental Attributes. Renewable energy sales primarily consist of the sale of biogas, including LFG and ADG, which is either sold or converted to Renewable Electricity. Environmental Attributes are generated and monetized from the renewable energy.
We report revenues from two operating segments: Renewable Natural Gas and Renewable Electricity Generation. Corporate relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering, and other operations functions not otherwise allocated to a segment. As such, the corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.
•Renewable Natural Gas Revenues: We record revenues from the production and sale of RNG and the generation and sale of the Environmental Attributes derived from RNG, such as RINs and LCFS credits. Our RNG revenues from Environmental Attributes are recorded net of a portion of Environmental Attributes shared with off-take counterparties as consideration for such counterparties using the RNG as a transportation fuel. We had certain pathway provider sharing arrangements expiring throughout 2024. While we did not experience a significant increase in Environmental Attributes shared with pathway providers in our 2024 renewals, our most recent pathway renewals have been at higher percentages than our historical percentages and the currently proposed pathway renewals are for percentages significantly higher than our historical arrangements. Historically, we have monetized less than 25% of our RNG volumes under these fixed-price agreements. We are considering entry into multiple short term contracts throughout 2025, some potentially increasing our historical percentage of volumes monetized under fixed-price arrangements., to provide time for mitigation of these recent market trends.
•Renewable Electricity Generation Revenues: We record revenues from the production and sale of Renewable Electricity and the generation and sale of the Environmental Attributes, such as RECs, derived from Renewable Electricity. All of our Renewable Electricity production is monetized under fixed-price PPAs from our existing operating projects.
•Corporate Revenues: Corporate reports realized and unrealized gains or losses under our gas hedge programs. We do not have any active gas hedge programs. Corporate also relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment.
Our operating revenues are priced based on published index prices which can be influenced by factors outside our control, such as market impacts on commodity pricing and regulatory developments. With our royalty payments structured as a percentage of revenue, royalty payments fluctuate with changes in revenues. We place a primary focus on managing production volumes and operating and maintenance expenses as these factors are more controllable by us.
RNG Production
Our RNG production levels are subject to fluctuations based on numerous factors, including:
Disruptions to Production: Disruptions to waste placement operations at our active landfill sites, severe weather events, or failure or degradation of our or a landfill operator’s equipment or interconnection or transmission problems could result in a reduction of our RNG production. We strive to proactively address any issues that may arise through preventative maintenance, process improvement and flexible redeployment of equipment to maximize production and useful life.
•In the third quarter of 2024, we began to experience trends with several of our landfill hosts delaying their installation of or delaying our ability to install wellfield collection infrastructure in active waste placement areas, a practice historically common and critical to our projections of feedstock gas and, therefore, production. These landfill-driven delays impact the timing of collection system enhancement installations and the resulting timing of our production increases. We expect these trends to continue through 2025.
•Despite collaboration with the landfill host at our Rumpke facility on our gas collection efforts, wellfield extraction environmental factors continue to impact gas extraction at the site. While the landfill continues to expand its waste intake and we continue to expand wellfield collection, our volumes have been impacted during 2024. Mitigation efforts related to wellfield environmental factors will continue into 2025 as the benefits from 2024 efforts have not achieved anticipated results.
•Similar wellfield extraction environmental factors continue to impact gas extraction at our Apex site. We are collaborating with the landfill to mitigate these impacts and expect these mitigation efforts to continue into 2025.
•Changes made by the landfill host to the wellfield collection system at the McCarty facility have contributed to elevated nitrogen in the feedstock received by our facility. Additionally, the landfill host modified the wellfield bifurcation approach which has reduced the quantity of feedstock received at our facility. We are working with the landfill host but continue to have lower volumes of feedstock available to be processed at the McCarty facility.
•Quality of Biogas: We are reliant upon the quality and availability of biogas from our site partners. The quality of the waste at our landfill project sites is subject to change based on the volume and type of waste accepted. Variations in the quality of the biogas could affect our RNG production levels. At three of our projects, we operate the wellfield collection system, which allows greater control over the quality and consistency of the collected biogas. At two of our projects, McCarty and Galveston, we have operating and management agreements by which we earn revenue for managing the wellfield collection systems. Additionally, our dairy farm project benefits from the consistency of feedstock and controlled environment of collection of waste to improve biogas quality.
•RNG Production from Our Growth Projects: We anticipate increased production at certain of our existing projects as open landfills continue to take in additional waste and the amount of gas available for collection increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project, such as those we are currently experiencing at Blue Granite as described above, would delay any realization of production from that project.
Pricing
Our Renewable Natural Gas and Renewable Electricity Generation segments’ revenues are primarily driven by the prices under our off-take agreements and PPAs and the amount of RNG and Renewable Electricity that we produce. We sell the RNG produced from our projects under a variety of short-term and medium-term agreements to counterparties, with contract terms varying from three years to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. All of the Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price arrangement with escalators.
The pricing of Environmental Attributes, which accounts for a substantial portion of our revenues, is subject to volatility based on a variety of factors, including regulatory and administrative actions and commodity pricing.
The sale of RINs, which is subject to market price fluctuations, accounts for a substantial portion of our revenues. We manage against the risk of these fluctuations through forward sales of RINs, although currently we only sell RINs in the calendar year they are generated. We have not entered into commitments to transfer significant RINs generated from 2025 production. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.
Factors Affecting Operating Expenses
Our operating expenses include royalties, transportation, gathering and production fuel expenses, project operating and maintenance expenses, general and administrative expenses, depreciation and amortization, net loss (gain) on sale of assets, impairment loss and transaction costs.
•Operating and Maintenance Expenses: Operating and maintenance expenses primarily consist of expenses related to the collection and processing of biogas, including biogas collection system operating and maintenance expenses, biogas processing, operating and maintenance expenses, and related labor and overhead expenses. At the project level, this includes all labor and benefit costs, ongoing corrective and proactive maintenance, project level utility charges, rent, health and safety, employee communication, and other general project level expenses. Unanticipated feedstock processing or gas conditioning equipment failures occurring outside our planned preventative maintenance program can increase project operating and maintenance expenses and reduce production volumes. The timing of gas conditioning and process equipment preventative maintenance intervals could impact the timing and amount of our operating and maintenance expenses within a given quarter.
•Royalties, Transportation, Gathering and Production Fuel Expenses: Royalties represent payments made to our facility hosts, typically structured as a percentage of revenue. Transportation and gathering expenses include capacity and metering expenses representing the costs of delivering our RNG and Renewable Electricity production to our customers. These expenses include payments to pipeline operators and other agencies that allow for the transmission of our gas and electricity commodities to end users. Production fuel expenses generally represent alternative royalty payments based on quantity usage of biogas feedstock.
•General and Administrative Expenses: General and administrative expenses primarily consist of corporate expenses and unallocated support functions for our operating facilities, including personnel costs for executive, finance, accounting, investor relations, legal, human resources, operations, engineering, environmental registration and reporting, health and safety, IT and other administrative personnel and professional fees and general corporate expenses. From time to time, we may be parties to legal proceedings arising in the normal course of business which could increase our legal expenses. We continue to expect increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2025. The Company accounts for stock-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 15 to our audited consolidated financial statements.
•Depreciation, Depletion and Amortization: Expenses related to the recognition of the useful lives of our intangible and fixed assets. We spend significant capital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.
•Impairment Loss: Expenses related to reductions in the carrying value(s) of fixed and/or intangible assets based on periodic evaluations whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
•Transaction Costs: Transaction costs primarily consist of expenses incurred for due diligence and other activities related to potential acquisitions and other strategic transactions.
Key Operating Metrics
Total operating revenues reflect both sales of renewable energy and sales of related Environmental Attributes. As a result, our revenues are primarily affected by unit production of RNG and Renewable Electricity, production of Environmental Attributes, and the prices at which we monetize such production. Set forth below is an overview of these key metrics:
•Production Volumes: We review performance by site based on unit of production calculations for RNG and Renewable Electricity, measured in terms of MMBtu and MWh, respectively. While unit of production measurements can be influenced by schedule facility maintenance schedules, the metric is used to measure the efficiency of operations and the impact of optimization improvement initiatives. We monetize a majority of our RNG commodity production under variable-price agreements, based on indices. A portion of our Renewable Natural Gas segment commodity production is monetized under fixed-priced contracts. Our Renewable Electricity Generation segment commodity production is primarily monetized under fixed-priced PPAs.
•Production of Environmental Attributes: We monetize Environmental Attributes derived from our production of RNG and Renewable Electricity. We carry-over a portion of the RINs generated from RNG production to the following year and monetize the carried over RINs in such following calendar year. A majority of our Renewable Natural Gas segment Environmental Attributes are self-monetized, though a portion are generated and monetized by third parties under counterparty sharing agreements. A majority of our Renewable Electricity Generation segment Environmental Attributes are monetized as a component of our fixed-price PPAs.
•Average realized price per unit of production: Our profitability is highly dependent on the commodity prices for natural gas and electricity, and the Environmental Attribute prices for RINs, LCFS credits, and RECs. Realized prices for
Environmental Attributes monetized in a year may not correspond directly with that year’s production as attributes may be carried over and subsequently monetized. We may elect to not commit to transfer all available RINs in a given period which could impact our revenue and operating profit. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.
Comparison of Years Ended December 31, 2024 and 2023
The following table summarizes the key operating metrics described above, which metrics we use to measure performance.
For the year ended
December 31,
Change
Change
%
(in thousands, unless otherwise indicated)
Revenues
Renewable Natural Gas Total Revenues
$
157,983
$
156,455
$
1,528
1.0
%
Renewable Electricity Generation Total Revenues
$
17,753
$
18,449
$
(696
)
(3.8
%)
RNG Metrics
CY RNG production volumes (MMBtu)
5,587
5,499
1.6
%
Less: Current period RNG volumes under fixed/floor-price contracts
(1,546
)
(1,287
)
(259
)
20.1
%
Plus: Prior period RNG volumes dispensed in current period
(10
)
(2.7
%)
Less: Current period RNG production volumes not dispensed
(291
)
(358
)
(18.7
%)
Total RNG volumes available for RIN generation (1)
4,108
4,222
(114
)
(2.7
%)
RIN Metrics
Current RIN generation ( x 11.727) (2)
48,177
49,508
(1,331
)
(2.7
%)
Less: Counterparty share (RINs)
(4,824
)
(5,203
)
(7.3
%)
Plus: Prior period RINs carried into current period
(631
)
(85.4
%)
Less: CY RINs carried into next CY
(6,822
)
(108
)
(6,714
)
6216.7
%
Total RINs available for sale (3)
36,639
44,936
(8,297
)
(18.5
%)
Less: RINs sold
(36,639
)
(44,936
)
8,297
(18.5
%)
RIN Inventory
-
-
-
0.0
%
RNG Inventory (volumes not dispensed for RINs) (4)
(67
)
(18.7
%)
Average Realized RIN price
$
3.28
$
2.71
$
0.57
21.0
%
Operating Expenses
Renewable Natural Gas Operating Expenses
$
82,916
$
80,762
$
2,154
2.7
%
Operating Expenses per MMBtu (actual)
$
14.84
$
14.69
$
0.15
1.1
%
REG Operating Expenses
$
14,734
$
13,730
$
1,004
7.3
%
$/MWh (actual)
$
79.22
$
70.77
$
8.45
11.9
%
Other Metrics
Renewable Electricity Generation Volumes Produced (MWh)
(8
)
(4.1
%)
Average Realized Price $/MWh (actual)
$
95.45
$
95.10
$
0.35
0.4
%
(1)RINs are generated the month following the month gas is produced and dispensed. Volumes under fixed/floor arrangements generate RINs which we do not self-market.
(2)One MMBtu of RNG has the same energy content as 11.727 gallons of ethanol, and thus may generate 11.727 RINs under the RFS program.
(3)Represents RINs available to be self-marketed by us during the reporting period.
(4)Represents gas production on which RINs are not generated.
Results of Operations
Comparison of Years Ended December 31, 2024 and 2023
The following table summarizes our revenues, expenses and net income for the periods set forth below:
For the year ended
December 31,
Change
Change
%
Total operating revenues
$
175,736
$
174,904
$
0.5
%
Operating expenses:
Operating and maintenance expenses
66,663
59,762
6,901
11.5
%
General and administrative expenses
36,286
34,403
1,883
5.5
%
Royalties, transportation, gathering and production fuel
31,502
34,861
(3,359
)
(9.6
)%
Depreciation, depletion and amortization
23,515
21,158
2,357
11.1
%
Impairment loss
1,586
75.8
%
Transaction costs
(117
)
(65.7
)%
Total operating expenses
159,613
151,264
8,349
5.5
%
Operating income
$
16,123
$
23,640
$
(7,517
)
(31.8
)%
Other expenses:
3,946
5,274
(1,328
)
(25.2
)%
Net income before income taxes:
12,177
18,366
(6,189
)
(33.7
)%
Income tax expense
2,443
3,418
(975
)
(28.5
)%
Net income
$
9,734
$
14,948
$
(5,214
)
(34.9
)%
Revenues for the Years Ended December 31, 2024 and 2023
Total revenues in 2024 were $175,736, an increase of $832 (0.5%) compared to $174,904 in 2023. The 2024 average realized RIN price of $3.28 increased approximately 21.0% compared to $2.71 in 2023. The natural gas index price decreased approximately 17.2% from $2.74 in 2023 to $2.27 in 2024. Also, there was a decrease in the number of RINs we self-marketed during 2024 due to a strategic decision to not self-market 6,822 RINs in the fourth quarter of 2024. We entered into margin sharing arrangements in 2024 which increased margin share revenues approximately $770 as compared to none in 2023. Offsetting this increase was a reduction of $1,758 in LCFS credit revenues primary related to 2022 RNG production volumes being released from storage and generating LCFS credit revenues in 2023.
Renewable Natural Gas Revenues
We produced 5,587 MMBtu of RNG during 2024, an increase of 88 MMBtu (1.6%) compared to 5,499 MMBtus in 2023. Wellfield optimization operational enhancements as well as plant processing equipment improvements contributed to the increase, notably with our Coastal facility producing 111 MMBtu more in 2024 compared to 2023. Our Pico facility produced 76 MMBtu more in 2024 compared to 2023 as a result of commissioning our dairy digestion expansion project. Our Galveston facility produced 59 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 wellfield quality issues and weather anomalies which lowered production, led by our Rumpke facility producing 159 fewer MMBtu in 2024 compared to 2023.
Revenues from the Renewable Natural Gas segment in 2024 were $157,983, an increase of $1,528 (1.0%) compared to $156,455 in 2023. Average commodity pricing for natural gas for 2024 was 17.2% lower than the prior year. During 2024, we self-marketed 36,639 RINs, representing an 8,297 decrease (18.5%) compared to 44,936 in 2023. The decrease was primarily related to the decision to not self-market a significant amount of RINs in inventory 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 21.0%. 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 MMBtus available for RIN generation and had approximately 6,822 RINs generated and unsold. We had approximately 358 MMBtus available for RIN generation and approximately 108 RINs generated and unsold at December 31, 2023. We have entered into commitments and transferred all of our RINs in inventory related to our 2024 RNG production.
Renewable Electricity Generation Revenues
We produced 186 MWh in Renewable Electricity in 2024, a decrease of approximately 8 MWh (4.1%) compared to 194 MWh in 2023. Our Security facility produced 9 MWh less in 2024 compared to 2023 as a result of us ceasing operations in connection with the first quarter of 2024 sale of the gas rights back to the landfill host.
Revenues from Renewable Electricity facilities in 2024 were $17,753, a decrease of $696 (3.8%) compared to $18,449 in 2023. The decrease is primarily driven by the decrease in our Security facility production volumes.
Expenses for the Years Ended December 31, 2024 and 2023
General and Administrative Expenses
Total general and administrative expenses were $36,286 in 2024, an increase of $1,883 (5.5%) compared to $34,403 in 2023. Employee related costs, including stock-based compensation costs were $23,099 in 2024, an increase of $3,366 (17.1%) compared to $19,733 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 $1,628 (35.3%) in 2024 compared to 2023.
Renewable Natural Gas Expenses
Operating and maintenance expenses for our RNG facilities in 2024 were $53,387, an increase of $5,501 (11.5%) compared to $47,886 in 2023. Our Rumpke facility operating and maintenance expenses increased approximately $1,839 as a result of increased media change outs and gas processing equipment maintenance costs. Our McCarty facility operating and maintenance expenses increased approximately $1,212 as a result of a wellfield operational enhancement program and increased gas compression system maintenance costs. Our Pico facility operating and maintenance expenses increased approximately $927 as a result of non-capitalizable costs associated with the digestion capacity increase project and efficiency improvements with the existing digestion capacity. Our Atascocita facility operating and maintenance expenses increased approximately $632 primarily driven by increased utility expense. Our Apex facility operating and maintenance expenses increased approximately $291 primarily related to increased gas processing equipment maintenance costs.
Royalties, transportation, gathering and production fuel expenses for our RNG facilities in 2024 were $29,529, a decrease of $3,347 (10.2%) compared to $32,876 in 2023. Our Pico facility earnout decreased approximately 33.3% during 2024 compared to 2023 based on our current estimate of the present value of the earnout. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 18.7% for 2024 from 21.0% in 2023.
Renewable Electricity Expenses
Operating and maintenance expenses for our Renewable Electricity facilities in 2024 were $12,760, an increase of $1,015 (8.6%) compared to $11,745 in 2023. The primary driver of the increase were operating and maintenance expenses at our Magnolia facility, associated with feedstock collection for Montauk Ag Renewables, which increased approximately $1,136 as a result of non-capitalizable costs.
Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2024 were $1,973, a decrease of $12 (0.6%) compared to $1,985 in 2023, and as a percentage of Renewable Electricity Generation segment revenues increased from 10.8% for 2023 to 11.1% for 2024.
Royalty Payments
Royalties, transportation, gathering, and production fuel expenses in 2024 were $31,502, a decrease of 3,359 (9.6%) compared to $34,861 in 2023. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization in 2024 was $23,515, an increase of $2,357 (11.1%) compared to $21,158 in 2023 . The increase is associated with the timing of capital investments placed into service in 2024, specifically our Pico digestion capacity increase and Raeger capital improvement projects.
Impairment loss
We calculated and recorded impairment losses of $1,586 for 2024, an increase of $684 (75.8%) compared to $902 for 2023. The impairment losses in 2024 primarily relate to the remaining book value of assets at the Security facility, various RNG equipment that
was deemed obsolete for current operations, and REG assets that were impacted under initial startup 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.
Other Expenses
Other expenses in 2024 were $3,946, a decrease of $1,328 (25.2%) compared to $5,274 in 2023. The decrease was primarily related to proceeds of $1,000 received from the sale of gas rights ahead of the fuel supply agreement expiration of our Security facility and decreased interest expense of $476.
Income Tax Expense
As of December 31, 2024 and 2023, we utilized all of our non-limited NOLs. A wholly-owned subsidiary continues to carry from 2023 to 2024 approximately $12,986 of federal net operating losses that are not expected to be realizable due to loss limitation rules.
As of December 31, 2024 and 2023, we had approximately $12,274 and $13,042, respectively, federal tax credit carryforwards that expire 20 years from the date incurred, which will begin to expire in tax year 2026. As of December 2024, we continue to carry state NOL balances in Pennsylvania and Florida from 2023.
For the year ended December 31, 2024 and 2023, income tax expense was $2,443 and $3,418, respectively. The 2024 effective tax rate was 20.1% and the 2023 effective tax rate was 18.6%.
Operating Profit (Loss) for the Years Ended December 31, 2024 and 2023
Operating profit in 2024 was $16,123, a decrease of $7,517 (31.8%) compared to $23,640 in 2023. RNG operating profit for 2024 was $56,032, a decrease of $3,254 (5.5%) compared to $59,286 in 2023. Renewable Electricity Generation operating loss for 2024 was $2,823, an increase of $2,228 (374.5%) compared to $595 in 2023.
Non-GAAP Financial Measures:
The following table presents EBITDA and Adjusted EBITDA, non-GAAP financial measures for each of the periods presented below. We present EBITDA and Adjusted EBITDA 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. In addition, EBITDA and Adjusted EBITDA are financial measurements of performance that management and the Board of Directors use in their financial and operational decision-making and in the determination of certain compensation programs. EBITDA and Adjusted EBITDA are supplemental performance measures that are not required by, or presented in accordance with GAAP. EBITDA and Adjusted EBITDA should not be considered alternatives to net income or any other performance measure derived in accordance with GAAP, or as an alternative to cash flows from operating activities or a measure of our liquidity or profitability.
The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income:
For the year ended
December 31,
Net income
$
9,734
$
14,948
Depreciation, depletion and amortization
23,515
21,158
Interest expense
5,277
5,753
Income tax expense
2,443
3,418
Consolidated EBITDA
40,969
45,277
Impairment loss (1)
1,586
Net loss of sale of assets
-
Transaction costs
Adjusted EBITDA
$
42,616
$
46,451
(1)For the year ended December 31, 2024, we recorded impairments of $1,586 for specifically related to the remaining book value of assets at the Security facility, various RNG equipment that was deemed obsolete for current operations, and REG assets that were impacted under initial startup testing for one of our REG construction work-in-progress sites. For the year ended
December 31, 2023, we recorded an impairment of $902 for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use.
Liquidity and Capital Resources
Sources of Liquidity
At December 31, 2024 and 2023, our cash and cash equivalents, net of restricted cash, was $45,621 and $73,811, respectively. We intend to fund development projects using cash flows from operations and borrowings under our revolving credit facility. We believe that we will have sufficient cash flows from operations and borrowing availability under our credit facility to meet our debt service obligations and anticipated required capital expenditures (including for projects under development) for the next 12 to 24 months. However, we are subject to business, operational, and political risks that could adversely affect our cash flows and liquidity.
At December 31, 2024, we had debt before debt issuance costs of $56,000, compared to debt before debt issuance costs of $64,000 at December 31, 2023.
Our debt before issuance costs (in thousands) is as follows:
December 31, 2024
December 31, 2023
Term loan
$
56,000
64,000
Revolving credit facility
-
-
Debt before debt issuance costs
$
56,000
$
64,000
Amended Credit Agreement
On December 21, 2021, the Company entered into the Fourth Amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement (the “Amended Credit Agreement”), with Comerica Bank (“Comerica”) and certain other financial institutions. The Amended Credit Agreement, which is secured by substantially all of our assets and assets of certain of our subsidiaries, provides for a five-year $80,000 term loan and a five-year $120,000 revolving credit facility.
As of December 31, 2024, $56,000 was outstanding under the term loan and we had no outstanding borrowings under the revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through December 2024, quarterly installments of $3,000 from 2025 through maturity, with a final payment of $32,000, on December 21, 2026. Interest rates were 6.01% and 6.11% at December 31, 2024 and 2023, respectively. The revolving and term loans under the Amended Credit Agreement bore interest at the BSBY Margin or Base Rate Margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement) as of September 30, 2024. The BSBY ceased publication on November 15, 2024, and the current debt agreement was amended to utilize the Secured Overnight Financing Rate Index ("SOFR"), plus applicable margin.
The Amended Credit Agreement contains customary covenants applicable to us and certain of our subsidiaries, including financial covenants. The Amended Credit Agreement is subject to customary events of default, and contemplates that we would be in default if, for any fiscal quarter (x) the average monthly D3 RIN price (as determined in accordance with the Amended Credit Agreement) is less than $0.80 per RIN and (y) the consolidated EBITDA for such quarter is less than $6,000. Consolidated EBITDA is defined under the Amended Credit Agreement as net income plus (a) income tax expense, (b) interest expense, (c) depreciation, depletion, and amortization expense, (d) non-cash unrealized derivative expense and (e) any other extraordinary, unusual, or non-recurring adjustments to certain components of net income, as agreed upon by Comerica in certain circumstances.
Under the Amended Credit Agreement, we are required to maintain the following ratios:
•a Total Leverage Ratio (as defined in the Amended Credit Agreement) of not more than 3.00 to 1.00 as of the end of any fiscal quarter from June 30, 2024 and thereafter; and
•as of the end of each fiscal quarter, a Fixed Charge Coverage Ratio (as defined in the Amended Credit Agreement) of not less than 1.2 to 1.0.
As of December 31, 2024, we were in compliance with all financial covenants related to the Amended Credit Agreement.
For additional information regarding the Amended Credit Agreement, see the sections entitled “Description of Indebtedness" and Note 13 to our audited consolidated financial statements.
Capital Expenditures
We have historically funded our growth and capital expenditures with our working capital, cash flow from operations and debt financing. We expect our non-development 2025 capital expenditures to range between $14,000 and $17,000. Our 2025 non-development capital plans include preventative maintenance expenditures, wellfield expansion projects, critical spare expenditures, other specific facility improvements, and information technology improvements. Additionally, we currently estimate that our existing 2025 development capital expenditures will range between $100,000 and $150,000. The majority of our 2025 development capital expenditures relate to our ongoing development of Montauk Ag Renewables, the second Apex facility, Bowerman RNG project, and our EENA CO2 project. Our Amended Credit Agreement provides us with a $120,000 revolving credit facility, with a $75,000 accordion option, providing us with access to additional capital to implement our acquisition and development strategy. We are currently in various stages of discussions regarding a variety of development and strategic growth opportunities. Development opportunities include: LFG RNG sites, waste water treatment RNG locations, and CNG distribution opportunities. If we ultimately enter into definitive agreements for any of these opportunities, we expect to incur material capital expenditures related to either acquisitions costs or development costs, or both. As we continue to explore strategic growth opportunities and while we have entered into nonbinding letters of intent for certain of these opportunities, we provide no assurances that our plans related to any or all of these strategic opportunities will progress to definitive agreements. We believe that our existing cash and cash equivalents, cash generated from operations, and credit availability under our Amended Credit Agreement would allow us to pursue and close on our identified strategic growth opportunities in addition to the previously discussed non-development and development capital expenditures.
Cash Flow
The following table presents information regarding our cash flows and cash equivalents for years ended December 31, 2024 and 2023:
For the year ended
December 31,
Net cash provided by (used in):
Operating activities
$
43,795
$
41,053
Investing activities
(62,191
)
(63,087
)
Financing activities
(9,842
)
(9,330
)
Net decrease in cash and cash equivalents
(28,238
)
(31,364
)
Restricted cash, end of the period
Cash and cash equivalents, end of period
46,004
74,242
For the year ended December 31, 2024, we generated $43,795 of cash from operating activities, a 6.7% increase compared to $41,053 for the year ended December 31, 2023. For the year ended December 31, 2024, income and adjustments to income from operating activities provided $44,961 compared to $49,896 in 2023. Working capital and other assets and liabilities used $1,166 in 2024 compared to $8,843 in 2023.
Our net cash flows used in investing activities has historically focused on project development and facility maintenance. For 2024, our capital expenditures were $62,323, of which $27,847, $12,643, and $8,759, were related to the ongoing development of the Montauk Ag Renewables, second Apex RNG facility, and Bowerman RNG project, respectively. For 2023, our capital expenditures were $63,091, of which $18,593, $13,655, and $13,092, were related to the ongoing development of the Montauk Ag Renewables, Pico facility digestion capacity increase and second Apex RNG facility, respectively.
Our net cash flows used in financing activities of $9,842 for 2024 increased by $512 compared to cash used in financing activities of $9,330 in 2023.
Related-Party Transactions
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 $5,000 to MNK for MNK to pay its dividend's tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended. As a result of several amendments, the current principal balance of the loan is $10,690, the due date is December 31, 2033 and the security interest is 976,623 shares of our common stock held by MNK (as amended the “Fifth Amended Promissory Note”).
In December 2021, Rivetprops 47 Proprietary Limited (“RP47”) entered into an agreement to loan MNK up to 10,000 South African Rand (the “RP47 Loan”). The current principal balance and accrued interest is 11,713 Rand or approximately $650 US Dollars. There was no collateral pledged for this loan. This loan became due on December 31, 2024 (“Maturity Date”) when MNK
and RP47 did not extend the maturity of the loan agreement. Associated with a modification on December 31, 2024 of the Transaction Implementation Agreement ("TIA") between us and MNK, we became obligated to repay the RP47 Loan on MNK’s behalf. 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. In connection with the modification under the TIA, RP47 retained its power over MNK but no longer held significant benefits in MNK. Substantially all of MNK’s activities are conducted on our behalf as MNK’s only asset is the 976,623 shares of our common stock held as security for the Fifth Amended Promissory Note. MNK’s only obligation is its loan to us and thus, we became the primary beneficiary of MNK on December 31 2024. In accordance with ASC 810, we consolidated MNK on December 31, 2024.
We consolidated MNK’s current assets ($85), current liabilities ($632) and long-term liabilities ($16). The Fifth Amended Promissory Note became an intercompany loan and was eliminated in consolidation. MNK’s investment of $10,178 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 also recorded a noncash acquisition of Treasury Stock ($8,309) related to the consolidation of the 976,623 shares of our Common Stock collateralizing the Fifth Amended Promissory Note. On February 2, 2025, 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. Refer to Note 22 - Subsequent Events for further information.
Contractual Obligations and Commitments
Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under GAAP. Our off-balance sheet arrangements are limited to the outstanding letters of credit and operating leases described below. Although these arrangements serve a variety of our business purposes, we are not dependent on them to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.
We have contractual obligations involving asset retirement obligations. See Note 9 to our audited consolidated financial statements for further information regarding the asset retirement obligations.
We have contractual obligations under our debt agreement, including interested payments and principal repayments. See Note 13 to our audited consolidated financial statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. During 2024, we had $2,185 of off-balance sheet arrangements of outstanding letters of credit. These letters of credit reduce the borrowing capacity of our revolving credit facility under our Amended Credit Agreement. Certain of our contracts require these letters of credit to be issued to provide additional performance assurances. There have been no usage against these outstanding letters of credit. During 2023, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $2,505.
We have contractual obligations involving operating leases. See Note 19 to our audited consolidated financial statements for further information related to the lease obligations.
We have other contractual obligations associated with our fuel supply agreements. The expiration of these agreements range between 3-19 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,695.
Internal Control Over Financial Reporting
There were no changes during 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Critical Accounting Policies and Estimates
Our consolidated financial statements are prepared in conformity with GAAP and require our management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, costs and expenses and related disclosures. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and such estimates may change if the underlying conditions or assumptions change.
Revenue Recognition
Our revenues are comprised of renewable energy and the related Environmental Attribute sales provided under a variety of short-term and medium-term agreements with our customers. All revenue is recognized when we satisfy our performance obligation(s)
under the contract (either implicit or explicit) by transferring the promised product to the customer either when (or as) the customer obtains control of the product. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. We allocate the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.
Revenue is measured as the amount of consideration we expect to receive in exchange for transferring our products. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred. To the extent applicable, sales, value add, and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.
The nature of our contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of our influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained. Refer to Item 7A for an estimate of the impact of decreases in the wholesale price of gas on our operating profit.
RINs
We generate D3 RINs through our production and sale of RNG used for transportation purposes as prescribed under the RFS program. Our operating costs are associated with the production of RNG. The RINs are government incentives that are generated through our renewable operating projects and not a result of physical attributes of our RNG production. The RINs that we generate are able to be separated and sold as credits independently from the energy produced. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. We enter into forward commitments to transfer RINs. These forward commitments are based on D3 RIN index prices at the time of the commitment. Realized prices for RINs monetized in a year may not correspond directly to index prices due to the forward selling of commitments. Refer to Item 7A for an estimate of the impact of decreases in the realized price per RIN on our operating profit.
RECs
We generate RECs through our production and conversion of landfill methane into Renewable Electricity in various states, including California and Oklahoma. These states have various laws requiring utilities to purchase a portion of their energy from renewable resources. Our operating costs are associated with the production of Renewable Electricity. The RECs are generated as an output of our renewable operating projects. The RECs that we generate are able to be separated and sold independently from the electricity produced. Therefore, no cost is allocated to the REC when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred.
Income Taxes
We are subject to income taxes in the U.S. federal jurisdiction and various state and local jurisdictions. Tax regulations within each jurisdiction are subject to the interpretation of the related tax laws and regulations and require significant judgment to apply.
Our net deferred tax asset position is a result of NOLs, fixed assets, intangibles, and tax credit carryforwards. The realization of deferred tax assets is dependent upon our ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in our financial statements or tax returns and forecasting future profitability by tax jurisdiction.
We evaluate our deferred tax assets at reporting periods on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of our deferred tax assets. We account for uncertain tax positions using a “more-likely-than-not” threshold for recognizing and resolving uncertain tax positions. The evaluation of uncertain tax positions is based on factors that include, but are not limited to, changes in tax law, the measurement of tax positions taken or expected to be taken in tax returns, the effective settlement of matters subject to audit, new audit activity and changes in facts or circumstances related to a tax position. Given our current level of pre-tax earnings and forecasted future pre-tax earnings, we expect to generate income before taxes in the United States in future periods at a level that would fully utilize our U.S. federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration. See Note 14 to our audited consolidated financial statements for additional information.
Intangible Assets
Separately identifiable intangible assets are recorded at their fair values upon acquisition. We account for intangible assets in accordance with ASC 350, Intangibles-Goodwill and Other. Finite-lived intangible assets include interconnections, customer contracts, and trade names and trademarks. The interconnection intangible asset is the exclusive right to utilize an interconnection line between the operating project and a utility substation to transmit produced electricity. Included in that right is full maintenance provided on this line by the utility. Intangible assets with finite useful lives are amortized on a straight-line basis over their estimated useful life. We evaluate our finite-lived intangible assets for impairment as events or changes in circumstances indicate the carrying value of these assets may not be fully recoverable. Events that could result in an impairment include, among others, a significant decrease in the market price or the decision to close a site.
Indefinite-lived intangible assets are not amortized and include emission allowances and land use rights. Emission allowances consist of credits that need to be applied to nitrogen oxide (“NOx”) emissions from internal combustion engines. These engines emit levels of NOx for which environmental permits are required in certain regions in the United States. Except for permanent allocations of NOx credits, allowances available for use each year are capped at a level necessary for ozone attainment per the National Ambient Air Quality Standards. We assess the impairment of intangible assets that have indefinite lives at least on an annual basis or whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable.
If finite-lived or indefinite-lived intangible assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. The fair value is determined based on the present value of expected future cash flows. We use our best estimates in making these evaluations, however, actual future pricing, operating costs and discount rates could vary from the assumptions used in our estimates and the impact of such variations could be material.
Our assessment of the recoverability of finite-lived and indefinite-lived intangible assets is determined by performing monitoring assessment of the future cash flows associated with the underlying gas rights agreements. The cash flows estimates are performed at the operating unit level and based on the average remaining length of the gas rights agreements. Based on our analysis, we concluded the cashflows generated to be well in excess of the carrying amounts. Changes in market conditions related to the various price indexes used in estimating these cash flows could adversely effect these estimates.
Finite-Lived Asset Impairment
In accordance with FASB ASC Topic 360, Property, Plant and Equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results, including considering project specific assumptions for long-term credit prices, escalated future project operating costs and expected site operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, (ii) third-party valuations, and/or (iii) information available regarding the current market value for such assets. We use our best estimates in making these evaluations and consider various factors, including future pricing and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates and the impact of such variations could be material. Based on our annual cash flow assessment conduction for monitoring potential indicators of impairment, we concluded the cashflows to be generated are significantly in excess of their carrying value of our operating sites primarily due to the lengths of the underlying gas rights agreements.
As to the remaining long lived asset groups, the Company further concluded, based on our annual cashflow assessment conducted for monitoring potential indicators of impairment, that the cashflows to be generated are significantly in excess of their carrying values of our operating sites primarily due to the lengths of the underlying gas rights agreements and the Company did not record any other impairments related to its cash flows assessment. Separate from our cash flows assessment, we identified discrete events and recorded impairment of We identified discrete events and recorded impairment of $1,586 and $902 for 2024 and 2023, respectively. See Note 3 to our audited consolidated financial statements for further information related to asset impairments.
Emerging Growth Company
We are an emerging growth company, as defined in the JOBS Act. The JOBS Act allows emerging growth companies to delay the adoption of new or revised accounting standards until such time as those standards apply to private companies. We intend to utilize these transition periods, which may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the transition periods afforded under the JOBS Act.
Recent Accounting Pronouncements
For a description of our recently adopted accounting pronouncements and recently issued accounting standards not yet adopted, see Note 2 to our consolidated financial statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to market risks related to Environmental Attribute pricing, commodity pricing, changes in interest rates and credit risk with our contract counterparties. We currently have no foreign exchange risk and do not hold any derivatives or other financial instruments purely for trading or speculative purposes.
We employ various strategies to economically hedge these market risks, including derivative transactions relating to commodity pricing and interest rates. Any realized or unrealized gains or losses from our derivative transactions are reported within corporate revenue in our consolidated financial statements. For information about our realized or unrealized gains or losses with respect to our derivative transactions and the fair value of such financial instruments, see Note 10 and Note 11 to our audited consolidated financial statements.
RIN and Environmental Attribute Pricing Risk
We attempt to negotiate the best prices for our Environmental Attributes and to competitively price our products to reflect the fluctuations in market prices. Reductions in the market prices of Environmental Attributes may have a material adverse effect on our revenues and profits as they directly reduce our revenues. To manage this market risk, we use a mix of short-, medium-, and long-term sales contracts and sell a portion of our Environmental Attributes at fixed-prices, through floor-price margin share agreements and pursuant to forward contracts with terms between one and two years. We also sell our Environmental Attributes bundled with RNG in contracts between two to five years.
We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to RIN prices. Our analysis, which may differ from actual results, was based on a 2025 estimated D3 RIN Index price of approximately $2.42 and our actual 2024 RINs sold. The estimated annual impact of a hypothetical 10% decrease in the average realized price per RIN would have a negative effect on our operating profit of approximately $7.0 million.
RNG and Renewable Electricity Pricing Risk
The price of RNG and Renewable Electricity changes in relation to the market prices of wholesale gas and wholesale electricity, respectively. Pricing for wholesale gas and wholesale electricity is volatile and we expect this volatility to continue in the future. Further, volatility of wholesale gas and electricity prices also creates volatility in the prices of Environmental Attributes.
We use a mix of short-, medium-, and long-term sales contracts and commodity hedging derivatives to manage our exposure to our pricing risk. We did not enter into a derivative contract to hedge a portion of our RNG production for 2024 or 2023.
We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the market price of wholesale gas. Our analysis, which may differ from actual results, was based on a 2025 estimated NYMEX average Index Price of approximately $3.851/MMBtu and our actual 2024 gas production sold pursuant to contracts that do not provide for a fixed or floor price. The estimated annual impact of a hypothetical 10% decrease in the market price of wholesale gas would have a negative effect on our operating profit of approximately $1.2 million.
Interest Rate Risk
In order to maintain liquidity and fund a portion of development and working capital needs, we have the Amended Credit Facility, which bears a variable interest rate based on SOFR index rate plus a margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement). We use interest rate swaps to set the variable interest rates under the Amended Credit Facility at a fixed interest rate to manage our interest rate risk.
As of December 31, 2024, we had $56.0 million outstanding under the Amended Credit Facility. Our weighted average interest rate on variable debt balances during 2024 was approximately 6.01%. We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to changes in interest rates. Based on our analysis, which may differ from actual results, a hypothetical increase in our effective borrowing rate of 10% would not have a material effect on our annual interest expenses and consolidated financial statements.
Credit Risk
We have certain financial and derivative instruments that subject us to credit risk. These consist of our commodity hedging derivatives and interest rate swaps contracts. We are exposed to credit losses in the event of non-performance by the counterparties to our financial and derivative instruments.
We are also subject to credit risk due to concentration of our RNG receivables with a limited number of significant customers. This concentration increases our exposure to credit risk on our receivables, since the financial insolvency of these customers could have a significant impact on our results of operations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Page
Montauk Renewables, Inc.
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)
Consolidated Balance Sheets as of December 31, 2024 and 2023
Consolidated Statements of Operations for the years ended December 31, 2024, 2023 and 2022
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2024, 2023 and 2022
Consolidated Statements of Cash Flows for the years ended December 31, 2024, 2023 and 2022
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Montauk Renewables, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Montauk Renewables, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Company has adopted new accounting guidance in 2024 related to the disclosure of segment information in accordance with ASU 2023-07, Segment Reporting (Topic 280). The adoption was retrospectively applied to 2023 and 2022.
Basis for opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2007.
Pittsburgh, Pennsylvania
March 14, 2025
MONTAUK RENEWABLES, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
as of December 31,
ASSETS
Current assets:
Cash and cash equivalents
$
45,621
$
73,811
Accounts and other receivables
8,172
12,752
Current restricted cash
Income tax receivable
-
Current portion of derivative instruments
Prepaid insurance and other current assets
2,911
2,819
Total current assets
$
57,224
$
90,175
Non-current restricted cash
$
$
Property, plant and equipment, net
252,288
214,289
Goodwill and intangible assets, net
18,113
18,421
Deferred tax assets
1,272
2,076
Non-current portion of derivative instruments
Operating lease right-of-use assets
7,064
4,313
Finance lease right-of-use assets
Related party receivable
-
10,138
Other assets
12,271
9,897
Total assets
$
349,015
$
350,238
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable
$
8,856
$
7,916
Accrued liabilities
10,069
12,789
Related party payable
-
Income tax payable
-
Current portion of operating lease liability
2,049
Current portion of finance lease liability
Current portion of long-term debt
11,853
7,886
Total current liabilities
$
33,528
$
29,350
Long-term debt, less current portion
$
43,763
$
55,614
Non-current portion of operating lease liability
5,138
4,133
Non-current portion of finance lease liability
Asset retirement obligations
6,338
5,900
Other liabilities
2,795
4,992
Total liabilities
$
91,598
$
99,999
Commitments and contingencies (Note 20)
STOCKHOLDERS’ EQUITY
Common stock, $0.01 par value, authorized 690,000,000 shares; 143,792,811 and 143,732,811 shares issued at December 31, 2024 and December 31, 2023, respectively; 142,711,797 and 141,986,189 shares outstanding at December 31, 2024 and December 31, 2023, respectively
$
1,426
$
1,420
Treasury stock, at cost, 2,308,524 and 984,762 shares December 31, 2024 and December 31, 2023, respectively
(21,262
)
(11,173
)
Additional paid-in capital
221,905
214,378
Retained earnings
55,348
45,614
Total stockholders' equity
$
257,417
$
250,239
Total liabilities and stockholders' equity
$
349,015
$
350,238
The accompanying notes to the consolidated financial statements are an integral part of these statements.
MONTAUK RENEWABLES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
For The Year Ended December 31,
Total operating revenues
$
175,736
$
174,904
$
205,559
Operating expenses:
Operating and maintenance expenses
66,663
59,762
57,267
General and administrative expenses
36,286
34,403
34,139
Royalties, transportation, gathering and production fuel
31,502
34,861
44,163
Depreciation, depletion and amortization
23,515
21,158
20,700
Gain on insurance proceeds
-
-
(313
)
Impairment loss
1,586
4,852
Transaction costs
Total operating expenses
$
159,613
$
151,264
$
160,993
Operating income
$
16,123
$
23,640
$
44,566
Other expenses (income):
Interest expense
$
5,277
$
5,753
$
1,792
Other income
(1,331
)
(479
)
(468
)
Total other expenses
$
3,946
$
5,274
$
1,324
Income before income taxes
$
12,177
$
18,366
$
43,242
Income tax expense
2,443
3,418
8,048
Net income
$
9,734
$
14,948
$
35,194
Income per share:
Basic
$
0.07
$
0.11
$
0.25
Diluted
$
0.07
$
0.11
$
0.25
Weighted-average common shares outstanding:
Basic
142,279,079
141,727,905
141,238,851
Diluted
142,397,493
142,151,640
142,579,389
The accompanying notes to the consolidated financial statements are an integral part of these statements.
MONTAUK RENEWABLES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Common stock
Treasury stock
Shares
Amount
Shares
Amount
Additional paid-in capital
Retained earnings (deficit)
Total equity
Balance at December 31, 2021
141,015,213
$
1,410
950,214
$
(10,813
)
$
196,224
$
(4,528
)
$
182,293
Vesting of stock awards
618,204
-
-
-
-
Treasury stock
-
-
21,092
(238
)
-
-
(238
)
Net income
-
-
-
-
-
35,194
35,194
Stock-based compensation
-
-
-
-
9,836
-
9,836
Balance at December 31, 2022
141,633,417
$
1,416
971,306
$
(11,051
)
$
206,060
$
30,666
$
227,091
Vesting of stock awards
352,772
-
-
-
-
Treasury stock
-
-
13,456
(122
)
-
-
(122
)
Net income
-
-
-
-
-
14,948
14,948
Stock-based compensation
-
-
-
-
8,318
-
8,318
Balance at December 31, 2023
141,986,189
$
1,420
984,762
$
(11,173
)
$
214,378
$
45,614
$
250,239
Vesting of stock awards
725,608
-
-
-
-
Treasury stock
-
-
1,323,762
(10,089
)
-
-
(10,089
)
Consolidation of VIE
-
-
-
-
(2,432
)
-
(2,432
)
Net income
-
-
-
-
-
9,734
9,734
Stock-based compensation
-
-
-
-
9,959
-
9,959
Balance at December 31, 2024
142,711,797
$
1,426
2,308,524
$
(21,262
)
$
221,905
$
55,348
$
257,417
The accompanying notes to the consolidated financial statements are an integral part of these statements.
MONTAUK RENEWABLES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands):
For The Year Ended December 31,
Cash flows from operating activities:
Net income
$
9,734
$
14,948
$
35,194
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization
23,515
21,158
20,700
Provision for deferred income taxes
1,876
6,618
Stock-based compensation
9,959
8,318
9,836
Gain on property insurance proceeds
-
-
(313
)
Derivative mark-to-market adjustments and settlements
(2,652
)
Net loss on sale of assets
-
(233
)
(Decrease) increase in earn-out liability
(1,703
)
1,266
1,122
Accretion of asset retirement obligations
Liabilities associated with properties sold
(225
)
-
-
Amortization of debt issuance costs
Impairment loss
1,586
4,852
Cash provided (used) by changes in assets and labilities:
Accounts receivable
4,580
(5,531
)
2,116
Royalty offset long term receivable
(3,089
)
(3,515
)
-
Income tax payables
(354
)
(89
)
Critical spare inventory
(1,012
)
(752
)
Accounts payable and Accrued liabilities
(2,298
)
1,326
3,467
Other
(477
)
(22
)
(331
)
Net cash provided by operating activities
$
43,795
$
41,053
$
81,066
Cash flows from investing activities:
Capital expenditures
$
(62,323
)
$
(63,091
)
$
(22,277
)
Asset acquisition
(820
)
-
-
Cash collateral deposits
(48
)
Proceeds from insurance recovery
-
-
Proceeds from sale of assets
1,000
1,088
Net cash used in investing activities
$
(62,191
)
$
(63,087
)
$
(20,794
)
Cash flows from financing activities:
Repayments of long-term debt
$
(8,000
)
$
(8,000
)
(8,000
)
Common stock issuance
Treasury stock purchase
(1,780
)
(122
)
(238
)
Related party receivable
-
(1,138
)
-
Finance lease payments
(68
)
(74
)
(47
)
Net cash used in financing activities
$
(9,842
)
$
(9,330
)
$
(8,279
)
Net decrease in cash and cash equivalents and restricted cash
$
(28,238
)
$
(31,364
)
$
51,993
Cash and cash equivalents and restricted cash at beginning of period
$
74,242
$
105,606
$
53,613
Cash and cash equivalents and restricted cash at end of period
$
46,004
$
74,242
$
105,606
Reconciliation of cash, cash equivalents, and restricted cash at end of period:
Cash and cash equivalents
$
45,621
$
73,811
$
105,177
Restricted cash and cash equivalents - current
Restricted cash and cash equivalents - non-current
$
46,004
$
74,242
$
105,606
The accompanying notes to the consolidated financial statements are an integral part of these statements.
MONTAUK RENEWABLES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Year Ended December 31,
Supplemental cash flow information:
Cash paid for interest
$
4,300
$
5,003
$
3,463
Cash paid for income taxes
1,993
1,915
Accrual for purchase of property, plant and equipment included in accounts payable and accrued liabilities
4,699
5,471
2,635
Non-cash purchase of Treasury stock
8,309
-
-
The accompanying notes to the consolidated financial statements are an integral part of these statements.
MONTAUK RENEWABLES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1-DESCRIPTION OF BUSINESS
Operations and organization
Montauk Renewables’ Business
Montauk Renewables, Inc. (the “Company” or “Montauk Renewables”) is a renewable energy company specializing in the management, recovery and conversion of biogas into Renewable Natural Gas (“RNG”). The Company captures methane, preventing it from being released into the atmosphere, and converts it into either RNG or electrical power for the electrical grid (“Renewable Electricity”). The Company, headquartered in Pittsburgh, Pennsylvania, has more than 30 years of experience in the development, operation and management of landfill methane-fueled renewable energy projects. The Company has current operations at 13 operating projects located in California, Idaho, Ohio, Oklahoma, Pennsylvania, North Carolina and Texas. The Company sells RNG and Renewable Electricity, taking advantage of Environmental Attribute premiums available under federal and state policies that incentivize their use.
Two of the Company’s key revenue drivers are sales of captured gas and sales of Renewable Identification Numbers (“RINs”) to fuel blenders. The Renewable Fuel Standard (“RFS”) is an Environmental Protection Agency (“EPA”) administered federal law that requires transportation fuel to contain a minimum volume of renewable fuel. RNG derived from landfill methane, agricultural digesters and wastewater treatment facilities used as a vehicle fuel qualifies as a D3 (cellulosic biofuel with a 60% greenhouse gas reduction requirement) RIN. The RINs are compliance units for fuel blenders that were created by the RFS program in order to reduce greenhouse gases and imported petroleum into the United States.
An additional program utilized by the Company is the Low Carbon Fuel Standard (“LCFS”). This is state specific and is designed to stimulate the use of low-carbon fuels. To the extent that RNG from the Company’s facilities is used as a transportation fuel in states that have adopted an LCFS program, it is eligible to receive an Environmental Attribute additional to the RIN value under the federal RFS.
Another key revenue driver is the sale of captured electricity and the associated environmental premiums related to renewable sales. The Company’s electric facilities are designed to conform to and monetize various state renewable portfolio standards requiring a percentage of the electricity produced in that state to come from a renewable resource. Such premiums are in the form of Renewable Energy Credits (“RECs”). The Company’s largest electric facility, located in California, receives revenue for the monetization of RECs as a part of a purchase power agreement.
Collectively, the Company benefits from federal and state government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy, as Environmental Attributes.
Background and Reorganization Transactions
On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by Montauk USA, and Montauk Renewables became a direct wholly-owned subsidiary of MNK. Prior to the Reorganization Transactions, MNK’s business and operations were conducted entirely through Montauk USA and its U.S. subsidiaries, and MNK held no substantial assets other than equity of Montauk USA. The Company had no significant operations or assets prior to January 4, 2021 when it engaged in the equity exchange with Montauk USA and MNK.
After completion of the Reorganization Transactions, (i) Montauk USA ceased to own any substantial assets and (ii) all entities through which MNK’s business and operations were conducted became owned, directly or indirectly, by the Company. MNK adopted a plan contemporaneously with the completion of the Reorganization Transactions that authorized the liquidation and dissolution of MNK.
On January 15, 2021, MNK sold the membership interest of Montauk USA to a third party. On January 26, 2021, MNK distributed all of the outstanding shares of the Company’s common stock as a pro rata dividend to the holders of MNK’s ordinary shares (the “Distribution”), subject to any tax withholding obligations under applicable South African law. Each ordinary share of MNK outstanding on January 21, 2021, the record date for the Distribution (the “Record Date”), entitled the holder thereof to receive one share of the Company’s common stock.
On January 26, 2021, the Company closed the initial public offering of its common stock on the Nasdaq Capital Market (the “IPO”) with the shares traded under the symbol “MNTK”. Montauk Renewables issued 2,702,500 shares at $8.50 per share and received gross proceeds of $22,971. The Company’s common stock was also secondarily listed on the Johannesburg Stock Exchange (“JSE”) under the trading symbol “MKR”.
On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (as amended on February 22, 2021, December 22, 2021, December 22, 2022, December 27, 2023 and March 5, 2025) with MNK pursuant to which the Company advanced a cash loan to MNK for MNK to pay its dividends tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended. The terms of the loan following the amendments are substantially similar to the initial loan agreement and were primarily entered into to (1) increase the principal amount outstanding under the loan to $10,690 in the aggregate (2) extended the maturity date to December 31, 2033 also, in accordance with Montauk Renewables’ obligations set forth in the Transaction Implementation Agreement ("TIA"). MNK is currently an affiliate of the Company and certain of the Company’s directors are also directors of MNK. See Note 17 for more information.
MNK was delisted from the JSE on January 26, 2021. The MNK Board of Directors and Shareholders held its annual general meeting in March 2023 and voted to take MNK private.
NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The historical consolidated financial information included reflects the historical results of operations and financial position of Montauk USA through January 4, 2021 when MNK sold the membership interest of Montauk USA. The consolidated financial statements of Montauk USA became the Company’s historical financial statements following the IPO. Certain historical financial information included relates to periods prior to the Reorganization Transactions. On December 31, 2024, the Company re-assessed its determination of the primary beneficiary of the Variable Interest Entity ("VIE") MNK under the guidance in ASC 810, Consolidation. Refer to Note 17 - Related Parties for further information. All intercompany balances and transactions have been eliminated in consolidation.
The Company utilizes the equity method of accounting for companies where its ownership is greater than 50% and significant but controlling interest does not exist.
Retrospective Presentation of Ownership Related to the Reorganization Transactions
As discussed in Note 1, as a result of the Reorganization Transactions, the Company acquired the assets and entities (excluding Montauk USA) which were previously owned by MNK. As part of the Reorganization Transactions, a 1:1 pro rata distribution of shares of the Company’s common stock was made to holders of MNK’s ordinary shares. The Reorganization Transactions resulted in a pro rata distribution whereby the ownership of the Company after the Reorganization Transactions was identical to the ownership of MNK prior to the Reorganization Transaction and was therefore akin to a common control transaction. All member’s equity in the financial statements and notes have been retrospectively adjusted to give effect to the Distribution, as if such pro rata distribution on a 1:1 basis occurred as of all pre-IPO periods presented, including periods presented on the Consolidated Balance Sheets, Consolidated Statements of Operations, Consolidated Statements of Stockholders’ and Member’s Equity and notes to the Consolidated Financial Statements contained herein.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.
Segment Reporting
The Company reports segment information in three segments: RNG, Renewable Electricity Generation and Corporate. This is consistent with the internal reporting provided to the chief operating decision maker who evaluates operating results and performance. The aforementioned business services and offerings described in Note 1 are grouped and defined by management as two distinct operating segments: RNG and Renewable Electricity Generation. Below is a description of the Company’s operating segments and other activities.
The RNG segment represents the sale of gas sold at fixed-price contracts, counterparty share RNG volumes and applicable Environmental Attributes. This business unit represents the majority of the revenues generated by the Company. The Renewable Electricity Generation segment represents the sale of captured electricity and applicable Environmental Attributes. Corporate & Other
relates to additional discrete financial information for the corporate function. It is primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment. As such, the corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.
Use of Estimates
The preparation of financial statements, in conformity with accounting principles generally accepted in the United States (“GAAP”), requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash, Cash Equivalents and Restricted Cash
Cash and cash equivalents include highly liquid investments with maturity dates of three months or less from the date of purchase and are recorded at cost. The Company may hold cash in excess of federally insured limits. Restricted cash is classified as current or non-current based on the terms of the underlying agreements and represents cash held as deposits, cash held in escrow and cash collateral for financial letters of credit.
Accounts and Other Receivables
Accounts and other receivables on the Consolidated Balance Sheets represent outstanding billings for goods and services delivered to customers on an unsecured basis as well as reimbursable expenses. In evaluating its allowance for doubtful accounts for accounts receivable, the Company performs ongoing reviews of its outstanding receivables to determine if any amounts are uncollectible and adjusts the allowance for doubtful accounts accordingly.
Property, Plant and Equipment
Property, plant and equipment purchases are stated at cost, except for asset retirement obligations, which are recorded at estimated fair value at inception date. Depreciation and amortization are based on costs less estimated salvage values, primarily using the straight-line method over the estimated useful lives or, if applicable, the term of the related gas rights agreements or power purchase agreements, whichever is shorter. Maintenance and repairs are expensed as incurred. Major improvements that extend the useful lives of property are capitalized.
The estimated useful lives of the Company’s property, plant and equipment reflect the expected consumption of the economic benefit of these assets as noted in the following table:
Buildings and improvements
5 - 30 years
Machinery and equipment
1 - 43 years
Gas mineral rights
15 - 25 years
$313 in insurance proceeds were received for the year ended December 31, 2022, related to an engine failure at an RNG Facility. These insurance proceeds are included in Gain on insurance proceeds for the year ended December 31, 2022, within the Consolidated Statements of Operations.
Goodwill and Intangible Assets
Goodwill is the cost of an acquisition less the fair value of the identified net assets of the acquired business.
Separately identifiable intangible assets are recorded at their fair values upon acquisition. The Company accounts for its intangible assets in accordance with ASC 350, Intangibles-Goodwill and Other (“ASC 350”). Finite-lived intangible assets include interconnections, customer contracts and trade names & trademarks. The interconnection intangible asset is the exclusive right to utilize an interconnection line between the operating plant and a utility substation to transmit produced natural gas and electricity. Included in that right is full maintenance provided on this line by the utility. Intangible assets with finite useful lives are amortized on a straight-line basis over their estimated useful life as depicted in the chart below. Indefinite intangible assets are not amortized and include emission allowances and land use rights.
The estimated useful lives of separately identified intangible assets are as follows:
Interconnection
10 - 25 years
Customer contracts
2 - 15 years
Emissions allowances
Indefinite
Land use rights
Indefinite
Assets Held for Sale
Assets classified as held for sale are reported at the lower of their carrying value or fair value less costs to sell. Assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction, rather than through continued use. This condition is met only when the sale is highly probable and the assets are available for immediate sale in their present condition, subject only to terms that are usual and customary for sales of such assets. Management must be committed to a sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale and actions required to complete the plan of sale indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. Impairment losses on initial classification as held-for-sale are recognized in the Consolidated Statement of Operations. Assets classified as held for sale are no longer depreciated or amortized.
Leases
The Company assesses leases in accordance with ASU 2016-02, Leases, (“ASU 2016-02”). This ASU requires lessees to recognize a right-of-use asset and lease liability on the Consolidated Balance Sheet for leases classified as either operating or finance leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize a right-of-use asset and lease liability. Additionally, when measuring assets and liabilities arising from a lease, optional payments should be included only if the lessee is reasonably certain to exercise an option to extend the lease, exercise a purchase option, or not exercise an option to terminate the lease. A right-of-use asset represents an entity’s right to use the underlying asset for the lease term, and a lease liability represents an entity’s obligation to make lease payments. The measurement, recognition and presentation of expenses and cash flows arising from leases by a lessee remains the same. The Company has included further lease disclosures in Note 19.
Long-lived Asset Impairment
In accordance with ASC 360, Property, plant, equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.
A summary of impairment losses on tangible and intangible assets for the year ended December 31, 2024, 2023 and 2022 is included in Note 3.
Indefinite-Lived Asset Impairment
Indefinite-lived intangible assets are required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. The evaluation of impairment under ASC 350 requires the use of projections, estimates and assumptions as to the future performance of the Company’s operations, including anticipated future revenues, expected operating costs and the discount factor used. Actual results may differ from projections. If such indefinite-lived assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.
Asset Retirement Obligations
The Company accounts for asset retirement obligations as required under ASC 410, Asset Retirement and Environmental Obligations, (“ASC 410”). ASC 410 requires the fair value of a liability for an asset retirement obligation be recognized in the period in which the legal obligation arises, with the associated discounted asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset and the annual accretion expense recorded in operations. The Company has recorded in the consolidated financial statements estimates for asset retirement obligations related to the decommissioning and removal requirements for specific gas processing and distribution assets, as required by their associated gas rights agreements.
Revenue
The Company recognizes revenue in accordance with ASC 606, Revenue from Contracts with Customers (“ASC 606”). Revenue from the Company’s point in time product sales is recognized when products are transferred, or services are invoiced and control transferred. Revenue from the Company’s product and service sales provided under long-term agreements is recognized as the Company transfers control of the product or renders service to its customers, which approximates the time when the customer is invoiced. The Company has presented the disclosures required by ASC 606 in Note 4.
Income Taxes
The Company is treated as a corporation for income tax purposes. Therefore, income taxes are accounted for under the liability method on a consolidated basis by the Company and its consolidated subsidiaries in accordance with ASC 740, Income Taxes (“ASC 740”). Deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws. The provision for income taxes includes federal and state income taxes.
The Company recognizes the financial statement benefit of a tax position only after determining the relevant tax authority would more-likely-than-not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company recognizes accrued interest and penalties related to unrecognized tax benefits in income tax expense.
Derivative Instruments
The Company applies the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 requires each derivative instrument to be recorded in the Consolidated Balance Sheets at its fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings.
Fair Value of Financial Instruments
The Company employs varying methods and assumptions in estimating the fair value of each class of financial instruments for which it is practical to estimate fair value. For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value due to the short maturity of these instruments. For long-term debt, the carrying amounts approximate fair value as the interest rates obtained by the Company approximate the prevailing interest rates available to the Company for similar instruments.
In accordance with ASC 820, Fair Value Measurement (“ASC 820”), a hierarchy is established which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1-Unadjusted quoted prices in active markets for identical unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2-Inputs other than quoted prices included within Level 1 that are observable for the assets and liabilities or can be corroborated with observable market data for substantially the entire contractual term of the assets or liabilities.
Level 3-Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the assets or liabilities and are consequently not based on market activity but rather through particular valuation techniques. The Company uses the fair value methodology to value the assets and liabilities recorded at fair value, including the Company’s asset retirement obligations and earn out liability.
The values of the Level 2 interest rate derivatives were determined using a model, which incorporates market inputs including the implied forward interest rate yield curve for the same period as the future interest rate swap settlement. The Company has also considered both its own credit risk and counterparty credit risk in determining fair value and determined these adjustments were insignificant for the years ended December 31, 2024 and 2023. The Company’s asset retirement obligations are recorded at fair value at the time the liability is incurred if a reasonable estimate of fair value can be made. Fair value is determined by calculating the estimated present value of the cost to retire the asset as determined by qualified engineers, based on currently available information and inflation estimates and is considered a Level 3 measurement. The Company’s earn-out liability fair value is determined by calculating the estimated present value of future obligations based on currently available information and the discount factor used and is considered a Level 3 measurement.
A summary of changes in the fair values of the Company’s Level 3 instruments, attributable to asset retirement obligations and the earn out liability, for the years ended December 31, 2024 and 2023 is included in Note 11.
Renewable Identification Numbers (“RINs”)
The Company generates D3 RINs through its production and sale of RNG used for transportation purposes as prescribed under the Federal Renewable Fuel Standard. The RINs that the Company generates as government incentives through its renewable operating projects can be separated and sold as credits independent from the energy produced and not a result of physical attributes of the Company’s production. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The Company had 6.8 and 0.1 million RINs generated and unsold as of December 31, 2024 and 2023, respectively.
Renewable Energy Credits (“RECs”)
The Company generates RECs through its production and sale of landfill methane into renewable electric energy as prescribed by the State of California Renewables Portfolio Standard or the EPA. The RECs that the Company generates as government incentives through its renewable operating projects are able to be separated and sold as credits independent from the electricity produced and not a result of physical attributes of the Company’s production. Therefore, no cost is allocated to the REC when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred.
Equity-Based Compensation
The Company accounts for equity-based compensation under the provisions of ASC 718, Compensation-Stock Compensation, (“ASC 718”). ASC 718 requires compensation costs related to share-based payment transactions, measured based on the fair value of the instruments issued, be recognized in the consolidated financial statements over the requisite service period of the award. Stock options are initially measured on the grant date using the Black-Scholes valuation model, which requires the use of subjective assumptions related to the expected stock price volatility, term, risk-free interest rate and dividend yield. For restricted stock shares, the Company determines the grant date fair value based on the closing market price of the stock on the date of the grant.
Employee Benefits
Leave entitlement
Employee entitlements to annual leave are recognized when they accrue to employees. An accrual is made for the estimated liability to the employees for annual leave up to the financial year end date. This liability is included in “Accrued liabilities” in the Consolidated Balance Sheets.
Bonus Plans
The Company recognizes a liability and an expense for incentive compensation bonuses awarded based on the achievement of Company and personnel goals where contractually obliged or where there is a past practice that has created a constructive obligation. An accrual is maintained for the appropriate proportion of the expected bonuses which would become payable at year end.
Recently Adopted Accounting Standards
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segments. The amendments in 2023-07 aim to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. ASU 2023-07 is effective for the Company's Annual Report on Form 10-K for the year ended December 31, 2024, and subsequent interim periods, with early adoption permitted. The amendments should be applied retrospectively to all prior periods presented in the financial statements. The Company has adopted the standard and the enhanced expense disclosures can be found in Note 18.
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848), which provides optional expedients and exceptions to the current guidance on contract modifications and hedging relationships to ease the financial reporting burdens of the expected market transition from London Interbank Offered Rate (“LIBOR”) and other interbank offered rates to alternative reference rates. The guidance was effective upon issuance and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. The FASB included a sunset provision within Topic 848 based on expectations of when the LIBOR would cease being published. The sunset provision has been amended from December
31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. The Company’s current debt agreement bears interest at the Secured Overnight Financing Rate, "SOFR", plus an applicable margin.
Recently Issued Accounting Standards
In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This ASU requires public business entities to disclose, on an annual and interim basis, disaggregated information about certain income statement expense line items. The ASU also requires disclosure of the total amount of selling expenses recognized in continuing operations on an annual and interim basis and disclosure of a public business entity’s definition of selling expenses on an annual basis (or in interim reporting periods if the definition is changed). Public business entities are required to apply the guidance prospectively but are permitted to apply it retrospectively. The ASU is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. The Company is currently evaluating the impact of this standard on its consolidated financial statements.
In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments in 2023-09 aim to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for the Company's Annual Report on Form 10-K for the year ended December 31, 2025, with early adoption permitted. Other than enhanced disclosures, the Company does not expect a material impact from the adoption of this standard on its consolidated financial statements.
NOTE 3-ASSET IMPAIRMENT
The Company recorded $1,586, $902 and $4,852 in impairment losses for the years ended December 31, 2024, 2023 and 2022, respectively. In 2024, for one of its REG sites, the Company entered into a bill of sale, assignment and assumption agreement to sell its rights to the existing fuel supply agreement and property back to the site host in advance of the fuel supply agreement termination date and received $1,000 in proceeds. The effective date of the sale, assignment and assumption agreement was October 1, 2024. The Company elected to cease operations prior to the assignment date and consequently the remaining book value of long lived assets and intangibles were impaired for $312. The $1,000 in proceeds received was recognized as Other income in the Consolidated Statement of Operations. In addition, $329 in REG impaired assets were due to initial startup testing failures for one of its REG construction work in progress sites. Remaining 2024 impairments, $843 in RNG assets and $102 in REG assets, were for various equipment that was deemed obsolete or inoperable for current operations. 2023 impairments included $777 for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in the Company's RNG segment. The remaining $125 in impairments were for specifically identified obsolete REG critical spares. The 2022 impairments included $2,133 for a REG site wherein the forecasted future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG site was impaired for $1,393 due to a discrete conclusion that certain assets acquired in the May 2021 Asset acquisition would no longer be utilized by the Company. An RNG site was impaired for $1,108 due to the specific identification of certain assets no longer capable of being used as designed. Additional impairments were recorded for computer software and hardware no longer being utilized, $191, and an amended customer contract, $27, no longer in use.
Impairment loss was recorded under Operating expenses within the Consolidated Statements of Operations for the years ended December 31, 2024, 2023, and 2022.
NOTE 4-REVENUES FROM CONTRACTS WITH CUSTOMERS
The Company’s revenues are comprised of renewable energy and related Environmental Attribute sales provided under short, medium and long term contracts with its customers. All revenue is recognized when (or as) the Company satisfies its performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product or service to its customer either when (or as) its customer obtains control of the product or service. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. The Company allocates the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract. The Company's typical invoicing terms are payment due within 30 days.
Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring its products or services. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred by the customer following the transfer of control of the commodities sold. To the extent applicable, sales, value add and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.
The Company’s performance obligations related to the sale of renewable energy (i.e. RNG and Renewable Electricity) are generally satisfied over time. Revenue related to the sale of renewable energy is generally recognized over time using an output based upon the product quantity delivered to the customer. This measure is used to best depict the Company’s performance to date under the
terms of the contract. Revenue from products transferred to customers over time accounted for approximately 26%, 24% and 29% of revenue for the years ended December 31, 2024, 2023 and 2022, respectively.
The nature of the Company’s long-term contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of the Company’s influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained.
The Company’s performance obligations related to the sale of Environmental Attributes are generally satisfied at a point in time and were approximately 74%, 76% and 71% of revenue for the years ended December 31, 2024, 2023 and 2022, respectively. The Company recognizes Environmental Attribute revenue at the point in time in which the customer obtains control of the Environmental Attributes, which is generally when the title of the Environmental Attribute passes to the customer upon delivery. In limited cases, title does not transfer to the customer and revenue is not recognized until the customer has accepted the Environmental Attributes. The Company’s performance obligations under its counterparty sharing agreements are generally satisfied at a point in time when the earnings process is completed by the counterparty. Counterparty sharing arrangement revenues were approximately 0.4%, 0.0% and 0.6% of revenue for the years ended December 31, 2024, 2023 and 2022, respectively.
The following tables display the Company’s disaggregated revenue by major source, excluding realized and unrealized gains or losses under the Company’s gas hedge program, based on product type and timing of transfer of goods and services for the years ended December 31, 2024, 2023 and 2022:
Year Ended December 31, 2024
Goods transferred at a point in time
Goods transferred over time
Total
Major goods/Service line:
Natural gas commodity
$
$
34,269
$
35,039
Natural gas environmental attributes
122,463
-
122,463
Electric commodity
-
10,648
10,648
Electric environmental attributes
7,586
-
7,586
$
130,819
$
44,917
$
175,736
Operating segment:
RNG
$
123,233
$
34,269
$
157,502
REG
7,586
10,648
18,234
$
130,819
$
44,917
$
175,736
Year Ended December 31, 2023
Goods transferred at a point in time
Goods transferred over time
Total
Major goods/Service line:
Natural gas commodity
$
-
$
30,207
$
30,207
Natural gas environmental attributes
125,874
-
125,874
Electric commodity
-
11,301
11,301
Electric environmental attributes
7,522
-
7,522
$
133,396
$
41,508
$
174,904
Operating segment:
RNG
$
125,874
$
30,207
$
156,081
REG
7,522
11,301
18,823
$
133,396
$
41,508
$
174,904
Year Ended December 31, 2022
Goods transferred at a point in time
Goods transferred over time
Total
Major goods/Service line:
Natural gas commodity
$
1,246
$
51,652
$
52,898
Natural gas environmental attributes
143,025
-
143,025
Electric commodity
-
10,449
10,449
Electric environmental attributes
7,016
-
7,016
$
151,287
$
62,101
$
213,388
Operating segment:
RNG
$
144,271
$
51,652
$
195,923
REG
7,016
10,449
17,465
$
151,287
$
62,101
$
213,388
Practical expedients and remaining performance obligations
The Company recognizes the sale of natural gas and electric commodities using the right to invoice practical expedient. The Company determined that the revenues recognized as of period end correspond directly with the value transferred to customers and the Company's satisfaction of the performance obligations to date. Furthermore, with the application of the right to invoice practical expedient and in consideration that contracts related to future environmental attributes sales do not exceed one year, there are no remaining unsatisfied or partially satisfied performance obligations as of December 31, 2024.
NOTE 5-ACCOUNTS AND OTHER RECEIVABLES
The Company extends credit based upon an evaluation of the customer’s financial condition. Credit terms are consistent with industry standards and practices. Accounts Receivable consist of sales to large creditworthy energy and utility companies. Reserves for uncollectible accounts, if any, are recorded as part of general and administrative expenses in the Consolidated Statements of Operations. No reserve expense was recorded for the years ended December 31, 2024, 2023 and 2022.
Accounts and other receivables consist of the following as of December 31, 2024, 2023 and 2022:
December 31, 2024
December 31, 2023
December 31, 2022
Accounts receivables
$
7,869
$
12,557
$
7,148
Other receivables
Reimbursable expenses
Accounts and other receivables, net
$
8,172
$
12,752
$
7,222
NOTE 6-ASSETS HELD FOR SALE
In 2021, the Company initiated a plan to sell nitrogen oxide (“NOx”) emissions allowances credits. The Company concluded that it met the criteria under applicable guidance for a long-lived asset to be held for sale, and accordingly reclassified the emissions allowances of $777 as current assets held for sale on the Consolidated Balance Sheet at December 31, 2021. The Company estimated the fair value of these assets and concluded that the fair value exceeded the carrying value and no impairment was recorded by the Company for the year ended December 31, 2021. In March 2022, the NOx emissions allowances credits were sold for $1,088. A $311 gain on sale of intangible assets was recorded for the year ended December 31, 2022.
NOTE 7-PROPERTY, PLANT AND EQUIPMENT, NET
Property, plant and equipment consists of the following as of December 31, 2024 and 2023:
December 31, 2024
December 31, 2023
Land
$
1,568
$
Buildings and improvements
36,434
30,329
Machinery and equipment
275,692
255,421
Gas mineral rights
35,526
35,526
Construction work in progress
95,551
67,747
Total
$
444,771
$
389,771
Less: Accumulated depreciation and amortization
(192,483
)
(175,482
)
Property, plant & equipment, net
$
252,288
$
214,289
Depreciation expense for Property plant and equipment was $22,096, $19,624 and $19,251 and Depletion expense for gas mineral rights was $365, $489 and $515 for the years ended December 31, 2024, 2023 and 2022, respectively.
Construction work in progress consists of RNG and REG capital expenditures on developmental projects and improvements to existing sites. Projects, on average, last between 18 to 36 months, and when completed for their intended use, costs are placed in service and begin depreciating.
In February 2024, the Company completed an Asset acquisition with a privately-held entity. The Company paid $820 for land located in North Carolina. The Asset acquisition was accounted for as an asset purchase in accordance with ASC 805, Business Combinations, and the purchase price has been allocated all to land within Property, plant and equipment, net on the Company's consolidated balance sheet.
In February 2024, for one of its REG sites, the Company entered into a bill of sale, assignment and assumption agreement to sell its rights to the existing fuel supply agreement and property back to the site host in advance of the fuel supply agreement termination date and received $1,000 in proceeds. The effective date of the sale, assignment and assumption agreement was October 2024. See Note 3 for impairment charges related to this site.
In October 2024, the Company entered into an asset purchase agreement to sell one of its immaterial RNG sites for a purchase price of $1,000. The Company entered into this agreement with the site host in advance of the expiration of the gas rights agreement. The company sold all of the site's assets and a $73 gain was recognized for the year ended December 31, 2024.
NOTE 8-GOODWILL AND INTANGIBLE ASSETS, NET
Goodwill and Intangible assets consist of the following as of December 31, 2024 and December 31, 2023:
December 31, 2024
December 31, 2023
Goodwill
$
$
Intangible assets with indefinite lives:
Land use rights
Total intangible assets with indefinite lives:
$
$
Intangible assets with finite lives:
Interconnection, net of accumulated amortization
of $4,593 and $3,847
$
14,614
$
14,584
Customer contracts, net of accumulated
amortization of $17,476 and $17,254
3,209
3,448
Total intangible assets with finite lives:
$
17,823
$
18,032
Total Goodwill and Intangible assets
$
18,113
$
18,421
The weighted average remaining useful life of the customer contracts and interconnections are approximately 13 and 14 years, respectively. Amortization expense was $986, $972 and $887 for the years ended December 31, 2024, 2023 and 2022, respectively.
Amortization expense for customer contracts and interconnections for the next five years is as follows:
Customer
Inter-
Year ending
Contracts
connections
$
$
Thereafter
1,999
10,929
NOTE 9-ASSET RETIREMENT OBLIGATIONS
The Company accounts for asset retirement obligations by recording the fair value of the liability in the period in which it is incurred. The Company estimates the fair value of asset retirement obligations by calculating the estimated present value of the cost to retire the asset. Factors that are considered when determining the present value of the cost to retire the asset include future inflation and discount rates, along with estimates date(s) of retiring the asset. Additionally, changes in legal, regulatory, environmental, and political environments can affect the fair value of the obligations. As such, asset retirement obligations are considered a level 3 financial instrument.
The $218 change in estimates for the year ended December 31, 2024 was due to RNG fuel supply agreement extensions and an RNG project that necessitated reassessment. The $225 reduction in the liability was due to an REG site sale as described in Note 3.
The following table summarizes the activity associated with asset retirement obligations of the Company for the years ended December 31, 2024, 2023 and 2022:
For The Year Ended December 31,
Asset retirement obligations-beginning of period
$
5,900
$
5,493
$
5,301
Accretion expense
Changes in estimate
-
-
Liabilities associated with properties sold
(225
)
-
(104
)
Asset retirement obligations-end of period
$
6,338
$
5,900
$
5,493
NOTE 10-DERIVATIVE INSTRUMENTS
To mitigate market risk associated with fluctuations in energy commodity prices (natural gas) and interest rates, the Company utilizes various derivative contracts to secure energy commodity pricing and interest rates under a board-approved program. The Company does not apply hedge accounting to any of its derivative instruments, and all realized and unrealized gains and losses from changes in derivative values are recognized in earnings each period. As a result of the economic hedging strategies employed, the Company had the following cash gains/losses and non-cash gains/losses in the Consolidated Statements of Operations for the years ended December 31, 2024, 2023 and 2022:
For The Year Ended December 31,
Derivative Instrument
Location
Commodity contracts:
Cash paid on derivatives
Operating revenue
$
-
$
-
$
(7,829
)
Interest rate swaps
Interest expense
(486
)
(560
)
2,652
Net (loss) gain
$
(486
)
$
(560
)
$
(5,177
)
NOTE 11-FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company’s assets and liabilities that are measured at fair value on a recurring basis include the following as of December 31, 2024 and 2023, set forth by level, within the fair value hierarchy:
December 31, 2024
Level 1
Level 2
Level 3
Total
Interest rate swap derivative asset
$
-
$
$
-
$
Asset retirement obligations
-
-
(6,338
)
(6,338
)
Pico earn-out liability
-
-
(3,406
)
(3,406
)
$
-
$
$
(9,744
)
$
(8,975
)
December 31, 2023
Level 1
Level 2
Level 3
Total
Interest rate swap derivative asset
$
-
$
1,255
$
-
$
1,255
Asset retirement obligations
-
-
(5,900
)
(5,900
)
Pico earn-out liability
-
-
(5,109
)
(5,109
)
$
-
$
1,255
$
(11,009
)
$
(9,754
)
A summary of changes in the fair value of the Company’s Level 3 instrument, attributable to asset retirement obligations, for the years ended December 31, 2024, 2023 and 2022 is included in Note 9. The Company’s earn-out fair value liability at its Idaho agricultural digester site is determined by calculating the estimated present value of the future obligation. The present value is assessed quarterly and is based on macro-economic factors such as inflation and risk free US Treasury rates. Company specific estimates utilized include current and future interest rates, digester inlet gas flow and projected EBITDA. A weighted average probability approach is utilized for the variables discussed above. The undiscounted maximum payout of the earn-out ranges between 5% and 20% of EBITDA based on average inlet gas production ranging from 641 standard cubic feet per minute ("scfm") to greater than 944 scfm for each semiannual period in the remaining term, as defined in the underlying agreement. The contractual term ends in 2038. The earn-out is classified as a Level 3 financial instrument and changes in the balance are recorded in Accrued liabilities and Other liabilities within the Consolidated Balance Sheets and in Royalties, transportation, gathering and production fuel within the Consolidated Statements of Operations. Interest rate swap derivatives are classified as Level 2 financial instruments and are valued utilizing Secured Overnight Financing Rates. In addition, certain assets are measured at fair value on a non-recurring basis when an indicator of impairment is identified and the assets’ fair values are determined to be less than its carrying value. See Note 3 for additional information.
There were no transfer of assets or liabilities between Levels 1, 2 or 3 of the fair value hierarchy as of December 31, 2024 and 2023.
NOTE 12-ACCRUED LIABILITIES
The Company’s accrued liabilities consists of the following as of December 31, 2024 and December 31, 2023:
December 31, 2024
December 31, 2023
Accrued expenses
$
2,701
$
3,983
Payroll and related benefits
3,401
2,355
Royalty
1,266
3,897
Utility
1,655
1,653
Accrued interest
Other
Accrued liabilities
$
10,069
$
12,789
NOTE 13-DEBT
The Company’s debt consists of the following as of December 31, 2024 and December 31, 2023:
December 31, 2024
December 31, 2023
Term loans
$
56,000
$
64,000
Less: current principal maturities
(12,000
)
(8,000
)
Less: debt issuance costs (on long-term debt)
(237
)
(386
)
Long-term debt
$
43,763
$
55,614
Current portion of long-term debt
11,853
7,886
Total debt
$
55,616
$
63,500
Amended Credit Agreement
On December 12, 2018, Montauk Energy Holdings LLC (“MEH”) entered into the Second Amended and Restated Revolving Credit and Term Loan Agreement (as amended, “Credit Agreement”), by and among MEH, the financial institutions from time to time party thereto as lenders and Comerica Bank, as the administrative agent, sole lead arranger and sole bookrunner (“Comerica”). The Credit Agreement (i) amended and restated in its entirety MEH’s prior revolving credit and term loan facility, dated as of August 4, 2017, as amended, with Comerica and certain other financial institutions and (ii) replaced in its entirety the prior credit agreement, dated as of August 4, 2017, as amended, between Comerica and Bowerman Power LFG, LLC, a wholly-owned subsidiary of MEH.
On March 21, 2019, MEH entered into the first amendment to the Credit Agreement (the “First Amendment”), which clarified a variety of terms, definitions and calculations in the Credit Agreement. The Credit Agreement requires the Company to maintain customary affirmative and negative covenants, including certain financial covenants, which are measured at the end of each fiscal quarter.
On August 28, 2019, the Company received a temporary waiver for an anticipated Event of Default (as defined in the Credit Agreement) for the consecutive three-month period ended on August 31, 2019 (the “Specified Event of Default”). The Specified Event of Default was waived through October 1, 2019.
On September 12, 2019, the Company entered into the second amendment to the Credit Agreement (the "Second Amendment"). Among other matters, the Second Amendment redefined the Fixed Charge Coverage Ratio (as defined in the Credit Agreement), reduced the commitments under the revolving credit facility to $80,000, redefined the Total Leverage Ratio (as defined in the Credit Agreement) and eliminated the RIN Floor (as defined in the Second Amendment) as an Event of Default. In connection with the Second Amendment, the Company paid down the outstanding term loan by $38,250 and the resulting quarterly principal installments were reduced to $2,500
On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by Montauk USA, and Montauk Renewables became a direct wholly-owned subsidiary of MNK. In connection with the completion of the Reorganization Transactions and the IPO, the Company entered into the third amendment to the Credit Agreement (the “Third Amendment”). This amendment permitted the change of control provisions, as defined in the underlying agreement, to permit the Reorganization Transactions and the IPO to be completed.
On December 21, 2021, MEH entered into the Fourth Amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement. The current credit agreement, which is secured by a lien on substantially all assets of the Company and certain of its subsidiaries, provides for a $80,000 term loan and a $120,000 revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through 2024, then increases to $3,000 from 2025 to 2026 with a final payment of $32,000 in late 2026.
The Company accounted for the Fourth amendment as both a debt modification and debt extinguishment in accordance with ASC 470, Debt (“ASC 470”). In connection with the Credit Agreement, the Company paid $2,027 in fees. Of this amount, $326 was expensed and $1,701 was capitalized and will be amortized over the life of the Credit Agreement. Amortized debt issuance expense in the amount of $360, $367 and $412 for the years ended December 31, 2024, 2023 and 2022, respectively, was recorded in interest expense in the Consolidated Statement of Operations. Unamortized debt issuance cost on the revolver was $479 and $723 as of December 31, 2024 and 2023, respectively.
As of December 31, 2024, $56,000 was outstanding under the term loan. In addition, the Company had $2,185 of outstanding letters of credit as of December 31, 2024. Amounts available under the revolving credit facility are reduced by any amounts
outstanding under letters of credit. As of December 31, 2024, the Company’s capacity available for borrowing under the revolving credit facility was $117,815. Borrowings of the term loan and revolving credit facility bear interest at the Secured Overnight Financing Rate plus an applicable margin. Interest rates as of December 31, 2024 and 2023 were 6.01% and 6.11%, respectively.
As of December 31, 2024, the Company was in compliance with all financial covenants related to the Credit Agreement.
Annual Maturities of Long-Term Debt
The following is a summary of annual principal maturities of long-term debt as of December 31, 2024:
Year ending
Amount
$
12,000
44,000
Total
$
56,000
NOTE 14-INCOME TAXES
The Company is subject to income taxes in the U.S. federal jurisdiction and various state and local jurisdictions. Tax regulations within each jurisdiction are subject to the interpretation of the related tax laws and regulations and require significant judgment to apply.
The following table details the components of the Company’s income tax provision for the years ended December 31, 2024, 2023 and 2022:
Year Ended December 31,
Current expense:
Federal
$
1,041
$
1,006
$
State
1,109
$
1,638
$
1,542
$
1,430
Deferred expense:
Federal
$
$
1,869
$
6,446
State
$
$
1,876
$
6,618
Income tax expense
$
2,443
$
3,418
$
8,048
The following table illustrates the deferred tax assets and liabilities as of December 31, 2024 and December 31, 2023:
December 31, 2024
December 31, 2023
Deferred tax assets:
Net operating loss carry forwards
$
4,100
$
4,107
Federal tax credits
12,274
13,042
Book reserves
1,824
1,397
Intangible asset amortization
5,297
5,799
Stock compensation
1,657
1,370
Impairment
Lease liabilities
2,815
1,009
VIE Loss on investment
-
Total deferred tax assets
28,919
27,030
Less: valuation analysis
(4,542
)
(3,950
)
Net deferred tax assets
$
24,377
$
23,080
Deferred tax liabilities:
Property depreciation
$
(20,319
)
$
(20,048
)
Right of use assets
(2,786
)
(956
)
Total deferred tax liabilities
(23,105
)
(21,004
)
Net deferred tax assets
1,272
2,076
As of December 31, 2024, the Company has $12,985 of federal net operating losses carryforwards that are not expected to be realizable due to restrictive loss limitation rules. As such a full valuation allowance has been recorded to offset the value of the related carryforward. The Company has $3,596 of state net operating loss carryforwards. A partial valuation allowance has been recorded to recognize that some attributes may expire before utilization.
As of December 31, 2024, the Company has $12,274 of federal tax credit carryforwards that expire 20 years from the date earned. The credits available as of December 31, 2024 will begin to expire in 2039.
The following table details the components of the Company’s income tax provision for the years ended December 31, 2024, 2023 and 2022:
Year Ended December 31,
Tax provision at federal statutory rate of 21%
$
2,557
$
3,857
$
9,081
State tax provision
Permanent differences
Stock compensation
1,298
(175
)
(24
)
162(m) compensation limitation
1,530
-
Valuation allowance
-
Production tax credit
(2,382
)
(2,324
)
(2,052
)
Return to provision
-
-
(20
)
Other
-
(14
)
-
Total income tax expense
$
2,443
$
3,418
$
8,048
As of December 31, 2024, the tax years 2021, 2022 and 2023 are open for examination by the IRS.
Valuation Allowance
The Company annually reviews its deferred tax assets for the possibility they will not be realized. A valuation allowance will be recorded if it is determined more than a 50% likelihood exists that a deferred tax asset will not be realized. A $4,542 valuation allowance exists as of December 31, 2024, which represents the Company’s deferred tax assets that are not expected to be realized. $565 of the valuation on December 31, 2024 represents MNK's investment deferred tax assets that the Company does not expect to realize. Refer to Note 17, Related Party Transactions for further information regarding the consolidation of MNK on December 31, 2024. The balance as of December 31, 2023, wherein there was no consolidated VIE balance, was $3,950.
Uncertain Tax Position
The calculation of the Company’s tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in both federal and state jurisdictions. ASC 740 states that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, on the basis of each situation’s technical merits.
At this point in time the Company is not aware of any tax positions taken that would give rise to recording an uncertain tax position. As such, the Company has not recorded any liability for unrecognized tax benefits as of December 31, 2024 or 2023. The Company records interest and penalties as a component of income tax expense. However, as there are no unrecognized tax benefits for the years ended December 31, 2024 and December 31, 2023, the Company has no penalties or interest accrued at December 31, 2024 and 2023, respectively.
NOTE 15-SHARE-BASED COMPENSATION
The board of directors of Montauk Renewables adopted the Montauk Renewables, Inc. Equity and Incentive Compensation Plan (“MRI EICP”) in January 2021. Following the closing of the IPO, the board of directors of Montauk Renewables approved the grant of non-qualified stock options, restricted stock units and restricted share awards to the employees of Montauk Renewables and its subsidiaries in January 2021. In connection with the restricted share awards, the officers of the Company made elections under Section 83(b) of the Code. Pursuant to such elections, the Company withheld 950,214 shares of common stock from such awards at a price of $11.38 per share from such awards. The Company records and reports restricted shares and restricted stock units when vested and in the case of options, when such awards are settled in the Company’s common stock. Stock compensation expense related to these awards was $1,470, $1,723 and $6,979 for the years ended December 31, 2024, 2023 and 2022, respectively.
In connection with a May 2021 asset acquisition, 1,250,000 restricted share awards (“RS Awards”) were granted to two employees that were hired by the Company in connection with such acquisition. The RS Awards were to vest over a five-year period and subject to the achievement of time and performance-based vesting criteria over such period. In May 2022, the RS Awards were amended to remove the performance-based vesting criteria and will only be subject to time-based vesting requirements over a five-year period. The awards were revalued at $15,500. Stock compensation expense related to the two awards was $5,866, $4,908 and $2,863 for the year ended December 31, 2024, 2023 and 2022, respectively. During the third quarter of 2024, the Company recognized $2,911 of noncash stock compensation expense. This nonrecurring expense recorded within General and administration expense was related to the acceleration of previously unrecognized stock compensation expense related to an employment termination.
In 2023, the board of directors of the Company approved the grant of non-qualified stock options to the executive officers of the Company, which vest ratably over a period of three to five years. Stock compensation expense related to these awards was $2,629 and $1,692 for the years ended December 31, 2024 and 2023, respectively.
The restricted shares, restricted stock units and option awards are subject to vesting schedules and are subject to the terms and conditions of the MRI EICP and related award agreements including, in the case of the restricted share awards, each officer having made an election under Section 83(b) of the Code.
Options granted under the MRI EICP allow the recipient to receive the Company’s common stock equal to the appreciation in the fair market value of the Company’s common stock between the grant date and the exercise and settlement of options into shares as of the exercise date(s). The fair value of the MRI EICP options was estimated using the Black-Scholes option pricing model with the following weighted-average assumptions (no dividends were expected):
September 2023 Awards
Options awarded
225,000
Risk-free interest rate
4.44%-4.65%
Expected volatility
71%-73%
Expected option life (in years)
3.5-5.5
Grant-date fair value
$
5.72
April 2023 Awards
Options awarded
2,100,000
Risk-free interest rate
3.71%-3.97%
Expected volatility
78%-80%
Expected option life (in years)
3.5-5.5
Grant-date fair value
$
4.25
January 2021 Awards
Options awarded
950,214
Risk-free interest rate
0.5%
Expected volatility
32%
Expected option life (in years)
5.5
Grant-date fair value
$
3.44
The following table summarizes the restricted shares, restricted stock units and options outstanding under the MRI EICP for the years ended December 31, 2024, 2023 and 2022:
Restricted Shares
Restricted Stock Units
Options
Number of
shares
Weighted
Average
Grant Date
Fair Value
Number of
shares
Weighted
Average
Grant Date
Fair Value
Number of
shares
Weighted
Average
Exercise
Price
End of period - December 31, 2022
2,028,301
$
11.80
280,000
$
10.13
-
$
-
Beginning of period - January 1, 2023
2,028,301
$
11.80
280,000
$
10.13
-
$
-
Granted
-
-
-
-
2,325,000
7.04
Vested
(316,228
)
11.38
(50,000
)
10.09
-
-
Forfeited
(73,395
)
11.38
(80,000
)
10.23
-
-
End of period - Balance at December 31, 2023
1,638,678
$
11.91
150,000
$
10.09
2,325,000
$
7.04
End of period - December 31, 2023
1,638,678
$
11.91
150,000
$
10.09
2,325,000
$
7.04
Beginning of period - January 1, 2024
1,638,678
$
11.91
150,000
$
10.09
2,325,000
$
7.04
Granted
-
-
80,000
4.41
-
-
Vested
(1,012,570
)
11.89
(60,000
)
9.49
-
-
Forfeited
-
-
-
-
-
-
End of period - December 31, 2024
626,108
$
11.93
170,000
$
7.63
2,325,000
$
7.04
Unrecognized MRI EICP compensation expense for awards the Company expects to vest as of December 31, 2024, was $8,543 and will be recognized over approximately 4 years.
NOTE 16-DEFINED CONTRIBUTION PLAN
The Company maintains a 401(k) defined contribution plan for eligible employees. The Company matches 50% of an employee’s deferrals up to 4%. The Company also contributes 3% of eligible employee’s compensation expense as a safe harbor contribution. The matching contributions vest ratably over four years of service, while the safe harbor contributions vest immediately. Incurred expense related to the 401(k) plan was $796, $640 and $589 for the years ended December 31, 2024, 2023 and 2022, respectively.
NOTE 17-RELATED-PARTY TRANSACTIONS
Related Party Loan
On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (the “Initial Promissory Note”) with Montauk Holdings Limited (“MNK”). MNK is currently an affiliate of the Company and certain of the Company’s directors are also directors of MNK. Pursuant to the Initial Promissory Note, the Company advanced a cash loan of $5,000 to MNK for MNK to pay its dividend's tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended (the “South African Income Tax Act”). On February 22, 2021, the Company and MNK entered into an Amended and Restated Promissory Note (the “Amended Promissory Note”) to increase the principal amount of the loan to a total of $7,140, in the aggregate, on December 22, 2021 entered into the Second Amended and Restated Loan Agreement and Secured Promissory Note (the “Second Amended Promissory Note”) to increase the principal amount of the loan to a total of $8,940, in the aggregate, and on December 22, 2022 entered into the First Amendment of the Second Amended and Restated Loan Agreement and Secured Promissory Note (the “First Amendment of Second Amended Promissory Note”) to amend the maturity date to June 30, 2023, and on June 21, 2023 entered into the Third Amended and Restated Loan Agreement and Secured Promissory Note (the "Third Amended and Restated Loan Agreement and Secured Promissory Note") to increase the principal amount of the loan to a total of $10,040, in the aggregate and extend the maturity date of the loan to December 31, 2023 and on December 27, 2023 entered into the Fourth Amended and Restated Loan Agreement and Secured Promissory Note to extend the maturity date of the loan to December 31, 2033, and on March 5, 2025 entered into the Fifth Amended and Restated Loan Agreement and Secured Promissory Note (the "Fifth Amended and Restated Loan Agreement and Secured Promissory Note") to increase the principal amount of the loan to a total of $10,690, in the aggregate, each in accordance with the Company’s obligations set forth in the TIA entered into by and among the Company, MNK and the other party thereto, dated November 6, 2020, and amended on January 14, 2021 and on December 31, 2024. The "Third Amended and Restated Loan Agreement and Secured Promissory Note" increased the security interest of the Company from 800,000 shares of the common stock of the Company owned by MNK to 976,623 shares of the Company. MNK is required to use the proceeds of any such sale of the shares to repay the note. The Amended Promissory Note has default provisions where MNK will deliver any unsold shares of the Company back to the Company to satisfy repayment of the note No other terms were amended under the Fifth Amended and Restated Loan Agreement and Secured Promissory Note and the security interest of the Company from MNK remains 976,623 shares of the Company and the maturity remains December 31, 2033.
In December 2021, Rivetprops 47 Proprietary Limited (“RP47”) entered into an agreement to loan MNK up to 10,000 South African Rand (the “RP47 Loan”). The current principal balance and accrued interest is 11,713 Rand or approximately $650 US Dollars. There was no collateral pledged for this loan. This loan became due on December 31, 2024 (“Maturity Date”) when MNK and RP47 did not extend the maturity of the loan agreement. Associated with a modification on December 31, 2024 of the TIA between us and MNK, we became obligated to repay the RP47 Loan on MNK’s behalf as MNK did not have sufficient funds to repay the RP47 Loan. On February 2, 2025, our Board of Directors approved the repayment of the RP47 Loan under the TIA. On March 5, 2025 and in connection with the Fifth Amended and Restated Loan Agreement and Secured Promissory Note", the Company repaid the RP47 loan as required under the TIA.
Variable Interest Entities
Under ASC 810-10-25-38A and 38B, a reporting entity is deemed to have a controlling financial interest in a VIE if it possesses both of the following characteristics: the power to direct the activities of the VIE that most significantly impact its economic performance, and the obligation to absorb losses of the VIE that could potentially be significant or the right to receive benefits from the VIE that could potentially be significant.
Under ASC 810, the Company determined that MNK is a variable interest entity. The Company does not hold any equity interest in MNK but has entered into the Fifth Amended and Restated Loan Agreement and Secured Promissory Note between the Company and MNK.
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. In connection with the modification under the TIA, RP47 retained its power over MNK but no longer held significant benefits in MNK. Substantially all of MNK’s activities are conducted on our behalf as MNK’s only asset is the 976,623 shares of our common stock held as security for the Fifth Amended and Restated Loan
Agreement and Secured Promissory Note. MNK’s only obligation is its loan to us and thus, we became the primary beneficiary of MNK on December 31, 2024. In accordance with ASC 810, we consolidated MNK on December 31, 2024. We consolidated MNK’s current assets ($85), current liabilities ($632) and long-term liabilities ($16). The Fifth Amended Promissory Note became an intercompany loan and was eliminated in consolidation. MNK’s investment of $10,178 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 also recorded a noncash acquisition of Treasury Stock ($8,309) related to the consolidation of the 976,623 shares of our Common Stock collateralizing the Fifth Amended Promissory Note.
Related Party Reimbursements
Periodically the Company will reimburse MNK and HCI Managerial Services Proprietary Limited, the administrator for the Company’s secondarily listed Johannesburg Stock Exchange trading symbol, for expenses incurred on behalf of the Company. Amounts reimbursed were $61, $156 and $68 for the years ended December 31, 2024, 2023 and 2022, respectively. $32 and $11 were owed as of December 31, 2024 and 2023, respectively.
Employment Transactions
The Company signed a long-term immaterial lease in December 2023 with a landowner in North Carolina. This lease enabled the Company to construct a feedstock collection system on the property which is owned by the Company. In September 2024, the Company hired the landowner as an employee to assist in the procuring of additional long-term leases on farms for additional collection system installations related to feedstock in North Carolina.
NOTE 18-SEGMENT INFORMATION
The Company’s reportable operating segments for the years ended December 31, 2024, 2023 and 2022 are Renewable Natural Gas and Renewable Electricity Generation. Renewable Natural Gas includes the production of RNG. Renewable Electricity Generation includes generation of electricity at biogas-to-electricity plants. The Corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation of the Company’s consolidated financial statements, and though not denoted as an operating segment, significant expenses are noted within the segment. The following tables are consistent with the manner in which the Chief Executive Officer, who is the Company's chief operating decision maker ("CODM"), evaluates the performance of each segment and allocates the Company's resources. The CODM evaluates the performance of the segments based on segment operating income (loss). The Company maintains discrete financial information for its operating sites, which meet the definition of an operating segment, but are aggregated into reportable segments based on the type of commodity produced. Total Assets and Capital expenditures by segment are also provided within the tables below. “RNG” refers to Renewable Natural Gas and “REG” refer to Renewable Electricity Generation.
For The Year Ended December 31, 2024
RNG
REG
Corporate
Total
Total operating revenue
$
157,983
$
17,753
$
-
$
175,736
Less (1)
Payroll and related expenses
8,516
2,226
23,847
34,589
Wellfield operating and maintenance
5,104
3,537
-
8,641
Plant expense
2,262
1,133
-
3,395
Waste disposal
2,353
-
2,407
Preventative maintenance
13,677
3,607
-
17,284
Breakdown expenses
1,736
-
2,205
Utility expense
15,571
-
15,881
Insurance
-
-
5,488
5,488
Professional and IT fees
-
-
4,141
4,141
Royalties, transportation, gathering and production fuel
29,529
1,973
-
31,502
Depreciation, depletion and amortization
18,192
5,099
23,515
Impairment
-
1,586
Other operating expenses (2), (3)
4,168
1,425
3,386
8,979
Total operating expenses
$
101,951
$
20,576
$
37,086
$
159,613
Operating income (loss)
$
56,032
$
(2,823
)
$
(37,086
)
$
16,123
Interest expense
-
5,276
5,277
Other (income) expense
(32
)
(1,011
)
(288
)
(1,331
)
Income (loss) before income taxes
$
56,064
$
(1,813
)
$
(42,074
)
$
12,177
Total assets
$
187,438
$
107,519
$
54,058
$
349,015
Capital expenditures
25,403
36,280
62,323
(1) Significant expenses regularly provided to the CODM.
(2) The majority of other operating expenses for RNG and REG are consumables, rent, environmental compliance and 		general and administrative expenses.
(3) The majority of other operating expenses for Corporate are office expenses, board of director and corporate filing fees.
For The Year Ended December 31, 2023
RNG
REG
Corporate
Total
Total operating revenue
$
156,455
$
18,449
$
-
$
174,904
Less (1)
Payroll and related expenses
7,620
1,850
20,396
29,866
Wellfield operating and maintenance
3,659
2,080
-
5,739
Plant expense
2,874
-
3,680
Waste disposal
2,103
-
2,127
Preventative maintenance
10,202
3,822
-
14,024
Breakdown expenses
2,711
-
3,543
Utility expense
15,168
-
15,747
Insurance
-
-
5,951
5,951
Professional and IT fees
-
-
5,399
5,399
Royalties, transportation, gathering and production fuel
32,876
1,985
-
34,861
Depreciation, depletion and amortization
15,720
5,193
21,158
Impairment
-
Other operating expenses (2), (3)
3,458
1,749
3,060
8,267
Total operating expenses
$
97,168
$
19,045
$
35,051
$
151,264
Operating income (loss)
$
59,287
$
(596
)
$
(35,051
)
$
23,640
Interest expense
-
-
5,753
5,753
Other expense (income)
(24
)
(471
)
(479
)
Income (loss) before income taxes
$
59,271
$
(572
)
$
(40,333
)
$
18,366
Total assets
$
176,951
$
73,369
$
99,918
$
350,238
Capital expenditures
41,325
21,682
63,091
(1) Significant expenses regularly provided to the CODM.
(2) The majority of other operating expenses for RNG and REG are consumables, rent, environmental compliance and general and administrative expenses.
(3) The majority of other operating expenses for Corporate are office expenses, board of director and corporate filing fees.
For The Year Ended December 31, 2022
RNG
REG
Corporate
Total
Total operating revenue
$
196,218
$
17,170
$
(7,829
)
$
205,559
Less (1)
Payroll and related expenses
6,722
1,574
19,788
28,084
Wellfield operating and maintenance
2,127
1,866
-
3,993
Plant expense
2,446
-
3,123
Waste disposal
2,034
-
2,103
Preventative maintenance
8,173
6,214
-
14,387
Breakdown expenses
1,809
-
2,452
Utility expense
17,266
-
17,884
Insurance
-
-
5,893
5,893
Professional and IT fees
-
-
5,967
5,967
Royalties, transportation, gathering and production fuel
42,339
1,824
-
44,163
Depreciation, depletion and amortization
14,967
5,443
20,700
Impairment
1,135
3,526
4,852
Other operating expenses (2), (3)
2,761
1,736
2,895
7,392
Total operating expenses
$
101,779
$
24,190
$
35,024
$
160,993
Operating income (loss)
$
94,439
$
(7,020
)
$
(42,853
)
$
44,566
Interest expense
-
-
1,792
1,792
Other expense (income)
(280
)
(296
)
(468
)
Income (loss) before income taxes
$
94,331
$
(6,740
)
$
(44,349
)
$
43,242
Total assets
$
151,998
$
53,255
$
127,063
$
332,316
Capital expenditures
16,667
5,033
22,277
(1) Significant expenses regularly provided to the CODM.
(2) The majority of other operating expenses for RNG and REG are consumables, rent, environmental compliance and general and administrative expenses.
(3) The majority of other operating expenses for Corporate are office expenses, board of director and corporate filing fees.
For the years ended December 31, 2024, 2023 and 2022, four, three and two customers, respectively, made up greater than 10% of our total revenues.
Year Ended December 31, 2024
RNG
REG
Corporate
Total
Customer A
17.6
%
-
-
17.6
%
Customer B
15.7
%
-
-
15.7
%
Customer C
13.8
%
-
-
13.8
%
Customer D
11.8
%
-
-
11.8
%
Year Ended December 31, 2023
RNG
REG
Corporate
Total
Customer A
22.0
%
-
-
22.0
%
Customer B
11.7
%
-
-
11.7
%
Customer C
11.7
%
-
-
11.7
%
Year Ended December 31, 2022
RNG
REG
Corporate
Total
Customer A
32.0
%
-
-
32.0
%
Customer B
17.0
%
-
-
17.0
%
NOTE 19-LEASES
The Company leases office space and other office equipment under operating lease arrangements (with initial terms greater than twelve months), expiring in various years through 2033. These leases have been entered into to better enable the Company to conduct business operations. Office space is leased to provide adequate workspace for all employees in Pittsburgh, Pennsylvania and Houston, Texas. Landfill site operating leases include gas monitoring devices that serve to improve production efficiencies and alert technicians to issues and safety concerns occurring at the well head. Office space, office equipment and gas monitoring equipment agreements that exceed 12 months are accounted for as operating leases in accordance with ASC 842, Leases.
The Company also leases safety equipment for the various operational sites in the United States. The term of certain equipment exceeds twelve months and is accordingly classified as a finance lease under ASC 842. The finance leases expire in 2026 and were entered into in order to provide a safe work environment for operational employees.
The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. For all operating and finance lease arrangements, the Company presents at the commencement date: a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.
The Company has elected, as a practical expedient, not to separate non-lease components from lease components, and instead account for each separate component as a single lease component for all lease arrangements, as lessee. In addition, the Company has elected, as a practical expedient, not to apply lease recognition requirements to short-term lease arrangements, generally those with a lease term of less than twelve months for all classes of underlying assets. In determination of the lease term, the Company considers the likelihood of lease renewal options and lease termination provisions.
The Company uses its incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. The incremental borrowing rate represents the rate of interest a lessee would have to pay to borrow an amount equal to the total lease payments on a collateralized basis over a similar term in a similar economic environment.
As of December 31, 2024, there were no leases entered into which have not yet commenced and that would entitle the Company to significant rights or create additional obligations. The total lease cost included in our consolidated financial statements statement of operations for the years ended December 31, 2024, 2023 and 2022 were $859, $695, and $412, respectively.
Leases with an initial term of 12 months or less are not recorded on the Consolidated Balance Sheet and the lease expense for those leases is recognized on a straight-line basis. The short-term lease expense for the years ended December 31, 2024, 2023 and 2022 were $3,927, $2,960 and $895, respectively.
Supplemental information related to operating lease arrangements was as follows as of and for the year ended December 31, 2024, 2023 and 2022:
For The Year Ended December 31,
Cash paid for amounts included in the measurement of
operating lease liabilities
$
$
$
Weighted average remaining lease term (in years)
3.48
5.24
5.87
Weighted average discount rate
5.00%-6.00%
5.00
%
5.00
%
Future minimum lease payments for the years ending December 31, are as follows:
Year Ending
$
2,299
2,111
Thereafter
2,106
Imputed interest
(1,112
)
Total
$
7,187
Supplemental information related to finance lease arrangements was as follows:
For The Year Ended December 31,
Cash paid for amounts included in the measurement of
financing lease liabilities
$
$
$
Weighted average remaining lease term (in years)
2.02
3.54
1.25
Weighted average discount rate
5.00
%
5.00
%
5.00
%
Future minimum finance lease payments are as follows:
Year Ending
$
Thereafter
Imputed interest
(8
)
Total
$
NOTE 20-COMMITMENTS AND CONTINGENCIES
Concentrations
A substantial portion of the Company’s revenues are generated from five locations in 2024, 2023, and 2022, each in separate areas of the country. For the years ended December 31, 2024, 2023 and 2022, excluding the impact of derivative instruments, approximately 69%, 68% and 72%, respectively, of operating revenues were derived from these locations. In addition, five customers make up approximately 76% and 71% of trade receivables as of December 31, 2024 and December 31, 2023, respectively.
Environmental
The Company is subject to a variety of environmental laws and regulations governing discharges to the air and water, as well as the handling, storage and disposing of hazardous or waste materials. The Company believes its operations currently comply in all material respects with all environmental laws and regulations applicable to its business. However, there can be no assurance that
environmental requirements will not change in the future or that the Company will not incur significant costs to comply with such requirements.
Contingencies
The Company, from time to time, may be involved in litigation. At December 31, 2024, management does not believe there are any matters outstanding that would have a material adverse effect on the Company’s financial position or results of operations.
On December 31, 2024 associated with a modification of the TIA between us and MNK, we became obligated to repay the RP47 Loan on MNK’s behalf, subject to MNK confirming that the RP47 Loan maturity was not extended and that MNK did not have sufficient funds to repay the loan. On December 31, 2024, we deemed the repayment probable and the amount estimable, and therefore accrued a contingent liability for the repayment of the RP47 Loan in connection with the amendment under the TIA. Refer to Note 17 - Related Parties and Note 22 - Subsequent Events for further information.
Note 21-INCOME PER SHARE
Basic and diluted income per share was computed using the following common share data for the years ended December 31, 2024, 2023 and 2022, respectively:
For The Year Ended December 31,
Net income
$
9,734
$
14,948
$
35,194
Basic weighted-average shares outstanding
142,279,079
141,727,905
141,238,851
Dilutive effect of share-based awards
118,414
423,735
1,340,538
Diluted weighted-average shares outstanding
142,397,493
142,151,640
142,579,389
Basic income per share
$
0.07
$
0.11
$
0.25
Diluted income per share
$
0.07
$
0.11
$
0.25
NOTE 22-SUBSEQUENT EVENTS
Subsequent Events
The Company evaluated its December 31, 2024 consolidated financial statements through the date the financial statements were issued. The Company is not aware of any subsequent events which would require recognition or disclosure in the financial statements, except for the matters discussed below.
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. Refer to Note 17 - Related Party Transactions for further information regarding the consolidation of MNK as of December 31, 2024.

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.

---

ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES.
Management’s Evaluation of Disclosure Controls and Procedures.
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. The Company, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, concluded that, as of December 31, 2024 (the end of the period covered by this Annual Report on Form 10-K), the Company’s disclosure controls and procedures were effective, pursuant to Rule 13a-15 and Rule 15d-15 of the Exchange Act.
Management’s Annual Report on Internal Control Over Financial Reporting.
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with appropriate authorizations; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.
Our management has conducted an evaluation of the effectiveness of our internal control over financial reporting, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013) (“COSO”). Based on the results of this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2024.
This Annual Report on Form 10-K does not include an attestation report of internal controls from our independent registered public accounting firm due to our status as an emerging growth company under the JOBS Act.
Changes in Internal Control over Financial Reporting.
There have been no changes during the quarter ended December 31, 2024, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting

---

ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION.
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
We have an insider trading policy governing the purchase, sale and other dispositions of our securities that applies to all company personnel, including directors, officers, employees and other covered persons. We believe that our insider trading policy is reasonably designed to promote compliance with insider trading laws, rules and regulations and listing standards applicable to us. A copy of our insider trading policy is filed as Exhibit 19.1 to this Form 10-K.
Information regarding our executive officers is included in Part I of this Report under the header “Information About Our Executive Officers.”
The information otherwise required by this item is set forth in our Proxy Statement in the section entitled “Proposal No. 1-Election of Directors” under the headings “-Nominees for Election for a Term Expiring at the 2028 Annual Meeting,” and “Information Regarding our Board of Directors and Corporate Governance” under the sub-headings “Code of Business Conduct and Ethics,” “Communications with the Board,” “Board Committees,” “Committee Functions,” “Insider Trading/No Hedging and Pledging Policy,” and “Audit Committee” and in the section entitled “Delinquent Section 16(a) Reports.” The information in these sections is incorporated by reference into this Annual Report on Form 10-K.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth in our Proxy Statement under the headings “Proposal No. 1-Election of Directors-Information Regarding our Board of Directors and Corporate Governance-Compensation Committee Interlocks and Insider Participation” and “Executive Compensation” and is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Except as set forth herein, the information required by this item is set forth in our Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
As of December 31, 2024, our securities authorized for issuance under equity compensation plans were as follows:
Plan Category
Number of
securities
to be issued
upon
exercise of
outstanding
awards
Weighted-
average
exercise
price
of
outstanding
awards
Number of
securities
remaining
available for
future
issuance
under equity
compensation
plans
(excluding
securities
reflected
in column
(a))
(a) (1)
(b) (2)
(c) (3)
Equity compensation plan approved by security
holders
3,275,214
$
8.30
12,826,975
Equity compensation plan not approved by security
holders
-
-
-
Total
3,275,214
8.30
12,826,975
(1)Included in column (a) are stock options and restricted stock units issued in connection with the IPO under the MRI EICP. The stock options issued in connection with the IPO are fully vested. Column (a) does not include 3,869,827 shares of restricted stock issued under the Plan.
(2)Reflects the weighted-average exercise price of outstanding stock options only, and not restricted stock and restricted stock units that do not have an exercise price.
(3)This amount represents 12,826,975 shares of common stock remaining available for future issuance under the MRI EICP.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item is set forth in our Proxy Statement under the headings “Proposal No. 1-Election of Directors-Information Regarding the Board of Directors and Corporate Governance-Director Independence and Controlled Company Exemption” and “Certain Relationships and Related Party Transactions” under the subheadings “Certain Transactions” and “Policies and Procedures for Related Party Transactions” and is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item is set forth in our Proxy Statement under the heading “Proposal No. 2-Ratification of the Appointment of Grant Thornton LLP as Independent Auditor” under the subheadings “Principal Accountant Fees and Services” and “Pre-Approval Policies and Procedures” and is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)(1) Financial Statements
See Part II, Item 8. “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
(a)(2) Financial Statements
Schedules not filed with this Annual Report on Form 10-K are omitted because of the absence of conditions under which they are required or because the information called for is shown in the financial statements or related notes.
(a)(3) Exhibits
Exhibit
Number
Description
2.1.1+
Transaction Implementation Agreement, dated as of November 6, 2020, between Montauk Renewables, Inc., Montauk Holdings Limited and Montauk Holdings USA, LLC (incorporated by reference to Exhibit 2.1 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
2.1.2
Letter Agreement, dated as of January 3, 2021, to the Transaction Implementation Agreement, dated as of November 6, 2020, between Montauk Renewables, Inc., Montauk Holdings Limited and Montauk Holdings USA, LLC (incorporated by reference to Exhibit 2.2 of Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
2.2.1+
Membership Interest and Asset Purchase Agreement, dated May 10, 2021, by and among J.P. Carroll & Co., LLC, Eagle Creek Ranch, L.L.C., NR Nutrient Recovery, LLC, Joseph P. Carroll, Jr., Martin A. Redeker and Montauk Swine Ag, LLC (incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K, filed on May 11, 2021)
2.2.2
First Amendment to Membership Interest and Asset Purchase Agreement, dated May 26, 2022, by and among J.P. Carroll & Co., LLC, Eagle Creek Ranch, L.L.C., NR3 Nutrient Recovery, LLC, Joseph P. Carroll, Jr., Martin A. Redeker, Montauk Ag Renewables, LLC and Montauk Energy Holdings, LLC (incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K, filed on June 1, 2022)
2.3+
Real Estate Purchase and Sale Agreement, dated May 10, 2021, by and among Greensboro Ecosystems, LLC and Montauk Swine Ag, LLC (incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K, filed on May 11, 2021)
3.1
Amended and Restated Certificate of Incorporation of Montauk Renewables, Inc. (incorporated by reference to Exhibit 3.1 of Amendment No. 3 of our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
3.2
Amended and Restated Bylaws of Montauk Renewables, Inc., as adopted on October 18, 2023 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed October 19, 2023)
4.1
Description of Securities (incorporated by reference to Exhibit 4.1 of our Annual Report on Form 10-K, filed March 31, 2021)
10.1^
Montauk Renewables, Inc. Equity and Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
10.2^
Form of Key Employee Separation Plan (incorporated by reference to Exhibit 10.2 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
10.3^
Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.3 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
10.4^
Form of Restricted Stock Unit Award Agreement (Employees) (incorporated by reference to Exhibit 10.4 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
10.5^
Form of Restricted Stock Unit Award Agreement (Non-Employee Directors) (incorporated by reference to Exhibit 10.5 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
10.6^+
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.6 of our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
Exhibit
Number
Description
10.7^
Form of Indemnification Agreement between Montauk Renewables, Inc. and each of its directors and executive officers (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed June 8, 2021)
10.8^+
Employment Agreement, effective September 25, 2019, between Montauk Energy Holdings LLC and Sean F. McClain (incorporated by reference to Exhibit 10.9 to Annual Report on Form 10-K filed March 31, 2021)
10.9^+
Employment Agreement, effective September 25, 2019, between Montauk Energy Holdings LLC and Kevin A. Van Asdalan (incorporated by reference to Exhibit 10.10 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
10.10^+
Employment Agreement, effective September 24, 2019, between Montauk Energy Holdings LLC and James A. Shaw (incorporated by reference to Exhibit 10.11 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
10.11^+
Employment Agreement, effective June 1, 2020, between Montauk Energy Holdings LLC and John Ciroli (incorporated by reference to Exhibit 10.42 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
10.12^
Promotion Letter, dated October 15, 2021, between Montauk Renewables, Inc. and Sharon Frank (incorporated by reference to Exhibit 10.12 of Annual Report on Form 10-K filed on March 14, 2024)
10.13^
Employment Understanding, dated January 23, 2023, and Promotion Letter, dated September 14, 2023, between Montauk Renewables, Inc. and Michael Barsch (incorporated by reference to Exhibit 10.13 of Annual Report on Form 10-K filed on March 14, 2024)
10.14.1+
Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of December 12, 2018, by and among Montauk Energy Holdings LLC, the financial institutions from time to time party thereto, as lenders, and Comerica Bank, as administrative agent, sole lead arranger and sole book runner (incorporated by reference to Exhibit 10.13 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
10.14.2
First Amendment, dated as of March 21, 2019, to the Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of December 12, 2018, by and among Montauk Energy Holdings LLC, the financial institutions from time to time party thereto, as lenders, and Comerica Bank, as administrative agent, sole lead arranger and sole book runner (incorporated by reference to Exhibit 10.14 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
10.14.3
Second Amendment, dated as of September 12, 2019, to the Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of December 12, 2018, by and among Montauk Energy Holdings LLC, the financial institutions from time to time party thereto, as lenders, and Comerica Bank, as administrative agent, sole lead arranger and sole book runner (incorporated by reference to Exhibit 10.15 to our Registration Statement on Form S-1(File No. 333-251312), filed December 11, 2020)
10.14.4
Third Amendment, dated as of January 4, 2021, to the Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of December 12, 2018, by and among Montauk Energy Holdings LLC, the financial institutions from time to time party thereto, as lenders, and Comerica Bank, as administrative agent, sole lead arranger and sole book runner (incorporated by reference to Exhibit 10.16 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
10.14.5+
Fourth Amendment to Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of December 22, 2021, by and among Montauk Energy Holdings, LLC, the financial institutions from time to time signatory thereto and Comerica Bank, as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (file No. 001-39919), filed on December 23, 2021)
10.14.6
Fifth Amendment to Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of November 8, 2024 by and among Montauk Energy Holdings, LLC, the financial institutions from time to time signatory thereto and Comerica Bank, as Administrative Agent (incorporated by reference to Exhibit 10.14 of Quarterly Report on Form 10-Q filed on November 12, 2024)
10.15.1+
Second Amended & Restated Landfill Gas Rights & Production Facilities Agreement, by and between County of Orange and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
Exhibit
Number
Description
10.15.2+
First Amendment to the Second Amended & Restated Landfill Gas Rights & Production Facilities Agreement, by and between County of Orange and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to our Registration Statement on Form S-1(File No. 333-251312), filed December 31, 2021)
10.15.3+
Third Amendment to the Landfill Gas Rights and Production Facilities Agreement and Settlement Agreement, dated as of June 27, 2023, by and between the County of Orange and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K, filed June 30, 2023)
10.16+
Renewable Power Purchase and Sale Agreement by and between the City of Anaheim and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.19 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
10.17+
Amended and Restated Gas Sale and Purchase Agreement, by and between McCarty Road Landfill TX, LP and GSF Energy, LLC (incorporated by reference to Exhibit 10.20 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
10.18+
Third Amended and Restated Gas Lease Agreement, dated January 1, 2018, by and between Rumpke Sanitary Landfill, Inc. and GSF Energy, LLC (incorporated by reference to Exhibit 10.24 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
10.19+
Amended and Restated Landfill Gas Purchase and Sale Agreement, dated October 17, 2016, by and between Waste Management of Texas, Inc. and TX LFG Energy, LP (incorporated by reference to Exhibit 10.35 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
10.20
Fifth Amended and Restated Loan Agreement and Secured Promissory Note, dated as of March 5, 2025 by and between Montauk Holdings Limited and Montauk Renewables (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K, filed on March 7, 2025)
19.1
Insider Trading Policy
21.1
List of Subsidiaries of Montauk Renewables, Inc.
23.1
Consent of Independent Registered Public Accounting Firm
24.1
Power of Attorney
31.1
Certification of the Chief Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) of the Securities Exchange Act
31.2
Certification of the Chief Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) of the Securities Exchange Act
32.1
Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes- Oxley Act of 2002
32.2
Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes- Oxley Act of 2002
97.1
Clawback Policy (incorporated by reference to Exhibit 97.1 of Annual Report on Form 10-K filed on March 14, 2024)
99.2+
Consortium Agreement, dated as of January 24, 2021, by and among the stockholders named therein (incorporated by reference to Exhibit 99.2 of Annual Report on Form 10-K filed March 31, 2021)
101.INS
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101.SCH
Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents
Cover page formatted as Inline XBRL and contained in Exhibit 101
^	Exhibits marked with a (^) are management contracts or compensation plans or arrangements.
+	Exhibits marked with a (+) exclude certain immaterial schedules and exhibits pursuant to the provisions of Regulation S-K, Item 601(a)(5) or Item 601(a)(6). A copy of any of the omitted schedules and exhibits pursuant to Regulation S-K, Item 601(a)(5) will be furnished to the Securities and Exchange Commission upon request.
	Exhibits marked with a () exclude certain portions of the exhibit pursuant to Item 601(b)(10)(iv) of Regulation S-K. A copy of the omitted portions will be furnished to the Securities and Exchange Commission upon request.