MNTK

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 Quarterly Report on Form 10-Q. Throughout this section, dollar amounts and production volumes are expressed in thousands, except for per share amounts and RIN pricing amounts and unless otherwise indicated. 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 elsewhere in this report, “Item 1A.–Risk Factors” of our 2025 Annual Report, and in our other SEC filings. Overview Montauk Renewables 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. We established our operating portfolio of 11 RNG and two Renewable Electricity 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 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. We sell the RNG and Renewable Electricity through a variety of term length 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 renewable initiatives. Our current operating projects produce either RNG or Renewable Electricity by processing biogas from landfill sites or agricultural waste from livestock farms. We view agricultural waste from livestock farms as a significant opportunity for us to expand our RNG business, and we continue to evaluate other agricultural feedstock opportunities. We believe that our business model and technology are highly scalable given availability of biogas from agriculturally derived sources, which will allow us to continue to grow through prudent development and complimentary acquisitions. 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 and as the RFS is based on annual compliance, a decision not to commit to transfer and monetize available RINs during a period will impact the timing of our operating revenues and operating profit recognized during a period. We had approximately 137 RINs generated but unseparated at June 30, 2026. The average D3 RIN index price for the second quarter of 2026 was approximately $2.54. The following table summarizes select historical data related to RINs generated, RINs sold, and RINs generated but unsold from our RNG operations. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The results related to our GreenWave joint venture are excluded from the table below. The timing of RIN transfers can vary year over year and by period within a year and is contingent on various factors including, but not limited to: (a) the Company’s expectations on RIN index price, (b) operational needs of the Company, (c) obligated parties purchase needs, or (d) the type of customer among other matters. 31 Table of Contents Calendar Quarter RINs Available for Sale RINs Sold RINs sold as % of RINs Available RINs Available but Unsold RINs Unsold as % of RINs Available 2024 Third Quarter 15,895 15,750 99.1% 145 0.9% 2024 Fourth Quarter 9,822 3,000 30.5% 6,822 69.5% 2025 First Quarter 13,801 9,885 71.6% 3,916 28.4% 2025 Second Quarter 11,158 11,050 99.0% 108 1.0% 2025 Third Quarter 12,421 12,411 99.9% 10 0.1% 2025 Fourth Quarter 10,786 10,786 100.0% - 0.0% 2026 First Quarter 12,482 12,403 99.4% 79 0.6% 2026 Second Quarter 14,265 14,265 100.0% - 0.0% Capital Development Summary The following summarizes our ongoing development growth plans expected capacity contribution, anticipated commencement of operations, and capital expenditure estimate, respectively excluding the Montauk Ag Renewables Development Project: Development Opportunity Estimated Capacity Contribution(MMBtu/day) Anticipated Commencement Date Estimated Capital Expenditure Bowerman RNG Facility 3,600 2027-2028 $85,000-$95,000 Atascocita LCO2 Facility N/A TBD $30,000-$40,000 Tulsa RNG Facility 1,500 2027-2028 $25,000-$35,000 Rumpke RNG Relocation Project 7,500 2028 $70,000-$90,000 Montauk Ag Renewables Acquisition In 2021, Montauk Ag Renewables purchased technology and assets (the “Montauk Ag Renewables Acquisition”) to recover residual natural resources from swine waste and to refine and recycle such waste products through proprietary and other processes to produce high quality renewable electricity, North Carolina swine RECs, and micronutrient organic fertilizer alternatives. Upon completion of the first phase of the project, we expect that it will annually produce 41 MWh of electric power, approximately 120 RECs and 8.7 tons of organic fertilizer alternative. With the change in REC generation passed by the state of North Carolina in 2024, we continue our negotiations with other utility users to provide swine RECs from our expected first phase production of MWh. We expect the annual REC capacity of the Turkey, NC location to be approximately 120 RECs and have signed a REC agreement with Duke Energy for annual sales of 47 RECs, which represents approximately 45% of the set-aside compliance volumes for swine under North Carolina’s Renewable Energy and Energy Efficiency Portfolio Standard. We continue to optimize our monetization strategies for the currently uncontracted portion of annually generated RECs and are in various stages of negotiation and responses to requests from obligated purchasers. Many of these agreements contain competitive details and, while there remains a limited active swine REC market in North Carolina, we believe the prices we are negotiating will be market based. We believe our average achievable price per swine REC could fall within the range of $200 to $400 per REC. During the second quarter of 2026 we continued contract negotiations with other entities required to purchase RECs under the North Carolina Clean Energy and Portfolio Standard, specifically, the portfolio standards relating to swine RECs. These negotiations related to, among other matters, price, term, and mutual abilities to renegotiate any agreed contract. We have exchanged various versions of contracts with certain entities. We believe we are able to prioritize the sale of swine RECs generated from our Turkey facility to our executed REC agreement with Duke giving us this extended period during our ramp up to continue negotiations with these other entities. We believe that when we achieve our full first stage production, we will have contracts for all swine RECs generated. In September 2025, a joint motion was filed with the North Carolina Utility Commission (“NCUC”) by various entities seeking to modify and delay the 2025 requirements of certain aspects of the North Carolina Clean Energy and Portfolio Standard, specifically, the portfolio standards relating to swine RECs. We note this filing is consistent with historical annual filings in response to the historically limited swine REC market in North Carolina. In October 2025, we filed response comments to the joint motion with the NCUC requesting they grant modifications or delays only to individual power supplies that have demonstrated need, require power suppliers that have not achieved 100% compliance in 2025 to apply any cumulatively acquired swine RECs to the suppliers unsatisfied 2025 pro rata obligation, and modify the swine REC set-aside for 2026 and beyond to match the requirement originally set by North Carolina in 2018. In January 2026, the NCUC denied the request for waivers and determined that parties must use banked 32 Table of Contents RECs to meet 2025 compliance targets. The compliance obligations for those utilities filing the September 2025 joint motion continue to increase through 2029. Under a NCUC joint motion, various stakeholders subject to the requirements of certain aspects of the North Carolina Clean Energy and Portfolio Standard, specifically, the portfolio standards relating to swine RECs, continue to have working meetings under the direction of the NCUC. Certain of these entities impacted by the NCUC motion are also entities we continue to negotiate swine REC sale agreements, including Duke Energy. While we continue to negotiate swine REC contracts with certain of these entities under the NCUC joint motion, this NCUC joint motion could impact our ability to successfully execute swine contracts. In July 2026, we began generating power for sale from our Turkey, North Carolina facility. This production of power is expected to be eligible to generate both swine RECs and enhanced RECs in subsequent months. As we work to increase the volumes of power and RECs that are able to be generated from our volume of produced syngas, we have identified specific programming modifications to our installed electrical switchgear. The installation of these modifications will provide for both the increase in production volumes and enhanced protection of our processing equipment and electrical transformers. We expect to have all programming completed by mid-August and consistently generate power and RECs from all available collected feedstock volumes. We continue to progress with our installation of feedstock collection at our targeted 400 to 450 hog spaces. As of the end of July, we have entered into long term agreements with over fifty separate farming locations providing us access to at least 350 hog spaces. We are currently able to collect from more than 250 hog spaces and will continue farm site collection equipment installations during the second half of 2026. Our capital investment expectation for this first phase of the project remains unchanged at $200,000. We continue to expect a ramp-up in production volumes throughout 2026 directly related to additional feedstock collection. We continue to develop opportunities with Montauk Ag Renewables and can give no assurances that our plans related to this acquisition will meet our expectations. We estimate our Montauk Ag Renewables project to potentially generate tax attributes once placed into service consisting mainly of a mix of federal investment tax and production tax credits and North Carolina state tax attributes. We give no assurances that our estimates on tax attributes for our Montauk Ag Renewables project will meet these expectations. GreenWave Joint Venture Through our wholly-owned subsidiary Pesta Energy, LLC, we entered into an agreement with Pioneer Renewables Energy Marketing, LLC to form a joint venture, GreenWave Energy Partners, LLC. The primary goal of the joint venture is to help address the limited capacity of RNG utilization for transportation by offering third party RNG volumes access to exclusive unique and proprietary pathways. We recorded income from GreenWave of approximately $7,092 in the first six months of 2026. We also received 2,909 in separated RINs distributed from GreenWave. Our capital investment in the joint venture is estimated to be up to approximately $4,500, subject to various and certain requirements as defined in the underlying agreements. Atascocita Carbon Dioxide Beneficial Use Opportunity In April 2026, we sent a letter confirming termination of our contract with European Energy North America (“EENA”) for the delivery of biogenic carbon dioxide (“CO2”). The termination was due to EENA’s failure to provide certain contractual assurances and notices related to the construction of their Texas-based e-methanol facility. We continue to explore alternative offtake arrangements with interested parties at our Atascocita location. The timing of capital expenditures will be synchronous with the finalization of replacement offtake agreements. We continue to anticipate a capital investment between $30,000 and $40,000, however our 2026 development capital range does not include additional capital outlay for this CO2 project. 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. 33 Table of Contents •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: 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. •Shifts in Revenue Composition for Projects from New Fuel Sources: We believe that agriculture offers us a lucrative opportunity For example, the value of LCFS credits for dairy farm projects, are a multiple of those realized from landfill projects due to the significantly more attractive CI scoring. Additionally, we believe that REC generation from swine farm projects, increases revenues from regulatory frameworks other than the RFS. As we expand into agriculture projects, our revenue composition from Environmental Attributes will change. •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. Our business is dependent on federal and state programs that support renewable fuels, including RIN, RECs and greenhouse gas reduction initiatives. These programs are subject to legislative and regulatory changes that could impact the timing and level of incentives available to our projects. On July 12, 2023, the EPA issued final rules establishing Renewable Fuel Standard (“RFS”) volume requirements for 2023 through 2025. Final cellulosic biofuel volumes were set at 838, 1,090 and 1,376 D3 RINs for 2023, 2024 and 2025, respectively. The rule also included significant changes to the RFS program, referred to as the biogas regulatory reform rule (“BRRR”), which modified the manner in which RINs are generated beginning January 1, 2025. We have registered all of our facilities under the BRRR provisions and have obtained Q-RIN status for RIN generation commencing January 1, 2025. Under these provisions, biogas from a single facility is limited to a single qualifying use under the RFS (e.g., as a biointermediate, RNG, or CNG/LNG via a biogas closed distribution system), although non-RFS uses at the same facility remain permissible. On June 13, 2025, the EPA issued a final rule partially waiving the 2024 cellulosic biofuel volume requirement, reducing the requirement from 1,090 to 1,010 D3 RINs based on actual production levels. In connection with this action, the EPA made Cellulosic Waiver Credits (“CWCs”) available to obligated parties as an additional compliance mechanism. On March 27, 2026, the EPA finalized RFS standards for 2026 and 2027, as well as a partial waiver of the 2025 cellulosic biofuel volume requirement. The 2025 cellulosic volume requirement was reduced from 1,376 to 1,210 D3 RINs, with CWCs also made available for 2025 compliance. Final cellulosic biofuel volume requirements for 2026 and 2027 were established at 1,360 and 1,430 D3 RINs, respectively. These volumes reflect the EPA’s assessment of expected RIN generation capacity and the related pathway constraints of the end-use demand for CNG/LNG transportation fuels derived from biogas. During the second quarter of 2026, legal challenges filed by various entities related to the finalized RFS standards for 2026 and 2027 were consolidated by the D.C. Circuit Court of Appeals . These challenges include claims relating to expected costs to comply with the RFS as well as challenges against partially waiving the 2025 RVO. On August 22, 2025, the EPA issued decisions on 175 Small Refinery Exemption (“SRE”) petitions, granting full exemptions to 63 petitions and partial exemptions to 77 petitions for the 2023 and 2024 compliance years. Additional SRE exemptions were granted by EPA on November 7, 2025. Full exemptions were granted to 2 petitions, 12 petitions were granted partial exemptions and 2 petitions were denied. These exemptions reduced renewable fuel blending obligations for affected parties and increased the availability of RINs in the market. In conjunction with these actions, the EPA finalized a reallocation mechanism as part of the 2026 34 Table of Contents and 2027 RFS rulemaking to redistribute a significant portion of exempted volumes into future RVOs. This reallocation is intended to partially offset the impact of prior exemptions by increasing future compliance requirements. The EPA, however, did not provide any reallocations of D3 RINs as part of the 2026 and 2027 RVO in the final rule issued March 27, 2026. This is primarily due to the statutory conditions on cellulosic biofuel volume requirements, which do not allow EPA to set the total applicable volume of cellulosic biofuel at a volume that is greater than the projected volume available, and which necessarily excludes cellulosic carryover RINs. We continue to monitor regulatory developments related to the RFS and other low-carbon fuel programs. Changes in regulatory requirements, including the implementation of BRRR, adjustments to RVOs, the availability of CWCs, and the treatment of SREs, may affect the supply-demand balance for RINs and the overall economics of our projects. 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 90% by 2045. This reduction could have the potential impact of reducing the number of net credits in the program. On July 1, 2025, CARB’s amended LCFS rules officially took effect setting the aggressive carbon intensity reduction targets listed above. The industry may see gradual increases in LCFS credit prices over the next year. The rules also phase out 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 are 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. In June 2025, California lawmakers introduced California Senate Bill SB-237, which includes a potential cap on LCFS credit prices of approximately $75/ton. On March 15, 2025, the Full-Year Continuing Appropriations and Extensions Act, 2025 was signed into law. In May 2025, we were informed that the law eliminated the United States Department of Agriculture Advanced Biofuel Payment Program. We received approximately $200 annually since 2021 under this program. In 2025, we received notice that the program was reinstated and that retroactive payments would be issued for the missed quarters while the program was closed. In 2026, we recorded approximately $327 related to the Advanced Biofuel Payment Program. Income Tax and Tax Attributes Our net deferred tax asset position is a result of NOLs, fixed assets, intangibles, and various 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. We generally complete our review for new tax attributes from assets when applicable, but generally as new assets are placed into service. Included within our deferred tax assets are various energy-related federal tax credits totaling $17,339. This total is primarily comprised of approximately $14,663 in IRC code section 45 production tax credits from our applicable facilities. We also have recorded approximately $923 and estimated $1,753 in IRC code section 48 investment tax credits from our previous Pico digestion expansion and second Apex RNG facility, respectively, although our conclusions on the tax credits from our second Apex RNG facility are not finalized. When placed into service, Montauk Ag Renewables will generate primarily a mix federal investment tax and production tax credits and North Carolina state tax attributes. Based on past experience with other large and qualifying projects, we believe that 50 to 75% of project capital will qualify for IRC Section 48 investment tax credits and, depending on a variety of factors for projects started within various safe harbor guidelines, the tax benefits could be up to 30%. For qualifying projects that do not meet the various safe harbor guidelines, we expect the tax benefits to range between 6 and 12% for qualifying assets. As it relates to our capital expenditures and future electric power production, we estimate IRC Section 48 investment tax credits and section 45 production tax credits could range between $6,000 and $20,000, collectively. We give no assurances that our estimates on tax attributes for our Montauk Ag Renewables project will meet these expectations but expect to begin to review federal tax attributes and continue our review for North Carolina state income and property tax attributes in 2026. 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 complete a full analysis annually of our deferred tax assets and liabilities. We expect our New Senior Credit Facility could generate additional tax attributes related to interest expense limitations under IRC Section 163(j). We continue to review our future tax planning including the ability to stack tax attributes, limitation on deductibility and expiration, but we do not currently expect to transfer, as applicable, any tax attributes generated. 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. 35 Table of Contents 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. 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. Corporate also includes revenues from RINs distributed from GreenWave which are not included in our operating metrics table. As such, the Corporate segment 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 entered into pathway renewals in the third quarter of 2025 for certain volumes at percentages consistent with our historical percentages. Historically, we have monetized less than 25% of our RNG volumes under fixed-price agreements. •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 and other 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. Includes revenues from RINs distributed from GreenWave which are not included in our operating metrics table. 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 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 throughout 2026. •Wellfield extraction environmental factors continue to impact gas extraction at our Apex site. We are collaborating with the landfill to mitigate these impacts and these mitigation efforts have continued in 2026. These wellfield extraction environmental factors could impact and lengthen the period during which we have excess available combined production capacity at our Apex site. •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. We expect these trends to continue through 2026. 36 Table of Contents •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 our McCarty project, we have an operating and management agreement by which we earn revenue for managing the wellfield collection system. 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 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 separated. We have entered into commitments to transfer the majority of RINs generated and available for sale from our expected 2026 third quarter RNG production at an average price of $2.66. 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. Our operating expenses can be subject to inflationary cost increases that are largely out of our control. •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. Expenses from RINs distributed from GreenWave and the costs related to pathway dispensing are not included in our operating metrics table but are recorded within Operating and Maintenance Expenses. •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 37 Table of Contents administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2026. We account for share-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. We do not believe the May 2026 restricted stock unit awards granted by the Board of Directors will significantly increase share-based compensation expense for the second half of 2026. For more information, see Note 15 to our unaudited condensed consolidated financial statements related to share-based compensation. •Depreciation 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 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 may carry-over a portion of the RINs generated or separated 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. 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. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. 38 Table of Contents Comparison of Three Months Ended June 30, 2026 and 2025 The following table summarizes the key operating metrics described above, which are metrics we use to measure performance. Results related to our GreenWave joint venture are excluded from the table below. For the three months ended June 30, Change 2026 2025 Change % (in thousands, unless otherwise indicated) Revenues Renewable Natural Gas Total Revenues $ 40,936 $ 40,829 $ 107 0.3 % Renewable Electricity Generation Total Revenues $ 4,505 $ 4,298 $ 207 4.8 % RNG Metrics CY RNG production volumes (MMBtu) 1,456 1,413 43 3.0 % Less: Current period RNG volumes under fixed/floor- price contracts (110 ) (549 ) 439 80.0 % Plus: Prior period RNG volumes dispensed in current period 431 336 95 28.3 % Less: Current period RNG production volumes not dispensed (429 ) (309 ) (120 ) (38.8 %) Total RNG volumes available for RIN generation (1) 1,348 891 457 51.3 % RIN Metrics Current RIN generation ( x 11.6935) (2) 15,766 10,410 5,356 51.5 % Less: Counterparty share (RINs) (1,608 ) (1,641 ) 33 2.0 % Plus: Prior period RINs carried into current period 244 5,398 (5,154 ) (95.5 %) Less: RINs generated but unseparated (137 ) (3,009 ) 2,872 95.4 % Total RINs available for sale (3) 14,265 11,158 3,107 27.8 % Less: RINs sold (14,265 ) (11,050 ) (3,215 ) (29.1 %) RIN Inventory (0 ) 108 (108 ) (100.0 %) RNG Inventory (volumes not dispensed for RINs) (4) 429 309 120 38.8 % Average Realized RIN price $ 2.45 $ 2.42 $ 0.03 1.2 % Operating Expenses Renewable Natural Gas Operating Expenses $ 23,862 $ 25,624 $ (1,762 ) (6.9 %) Operating Expenses per MMBtu (actual) $ 16.39 $ 18.13 $ (1.74 ) (9.6 %) REG Operating Expenses $ 5,583 $ 5,308 $ 275 5.2 % $/MWh (actual) $ 126.89 $ 126.38 $ 0.51 0.4 % Other Metrics Renewable Electricity Generation Volumes Produced (MWh) 44 42 2 4.8 % Average Realized Price $/MWh (actual) $ 102.39 $ 102.33 $ 0.06 0.1 % (1)RINs are generated in the month that the gas is dispensed to generate RINs, which occurs the month after the gas is produced. Volumes under fixed/floor-price arrangements generate RINs which we do not self-market. K3 RIN separation occurs after the gas is dispensed (RINs generated but unseparated). (2)One MMBtu of RNG has the same energy content as 11.6935 gallons of ethanol, and thus may generate 11.6935 RINs under the RFS program. (3)Represents RINs available to be self-marketed by us during the reporting period. (4)Represents gas production which has not been dispensed to generate RINs. 39 Table of Contents The following table summarizes our revenues, expenses and net income (loss) for the periods set forth below: Revenues for the Three Months Ended June 30, 2026 and 2025 For the three months ended June 30, Change 2026 2025 Change % Total operating revenues $ 54,020 $ 45,127 $ 8,893 19.7 % Operating expenses: Operating and maintenance expenses 29,061 21,864 7,197 32.9 % General and administrative expenses 7,666 9,044 (1,378 ) (15.2 )% Royalties, transportation, gathering and production fuel 8,814 9,168 (354 ) (3.9 )% Depreciation, depletion and amortization 7,904 7,029 875 12.4 % Impairment loss 650 377 273 72.4 % Total operating expenses 54,095 47,482 6,613 13.9 % Operating loss $ (75 ) $ (2,355 ) $ 2,280 96.8 % Other (income) expenses: (2,291 ) 1,256 (3,547 ) (282.4 )% Net income (loss) before income taxes: 2,216 (3,611 ) 5,827 161.4 % Income tax expense 1,990 1,876 114 6.1 % Net income (loss) $ 226 $ (5,487 ) $ 5,713 104.1 % Total revenues in the second quarter of 2026 were $54,020, an increase of $8,893 (19.7%) compared to $45,127 in the second quarter of 2025. The increase is primarily related to environmental attribute revenues of approximately $8,402 from RINs sold related to the distribution of RINs from our GreenWave joint venture which had no RINs distributed and sold in the second quarter of 2025. Our second quarter of 2026 RNG volumes sold under fixed/floor-price contracts decreased approximately 80.0% as compared to second quarter of 2025 as a result of the expiration of fixed price pathway contracts. Our RNG commodity revenue decreased approximately 63.7% which was offset by an increase in RINs sold of 29.1%. Also, our RINs generated and unseparated decreased approximately 95.4% as a result of the transition to BRRR in 2025. Renewable Natural Gas Revenues We produced 1,456 MMBtu of RNG during the second quarter of 2026, an increase of 43 MMBtu (3.0%) compared to 1,413 MMBtu produced in the second quarter of 2025. Our McCarty facility produced 53 MMBtu more in the second quarter of 2026 compared to the second quarter of 2025 as a result of landfill host wellfield operational and collection system enhancements. Our Apex facility produced 39 MMBtu more in the second quarter of 2026 as compared to second quarter of 2025 as a result of increased feedstock gas from our improvements related to the landfill collection system. Our Galveston facility produced 26 MMBtu fewer in the second quarter of 2026 compared to the second quarter of 2025 as a result of landfill host assuming responsibility of wellfield operations and maintenance beginning in 2026. Our Atascocita facility produced 37 MMBtu fewer in the second quarter of 2026 compared to the second quarter of 2025 as a result of landfill host wellfield operational and collection system enhancement project timing as well as planned facility maintenance. Revenues from the Renewable Natural Gas segment in the second quarter of 2026 were $40,936, an increase of $107 (0.3%) compared to $40,829 in the second quarter of 2025. Average commodity pricing for natural gas for the second quarter of 2026 was $2.90 per MMBtu, 15.7% lower than the second quarter of 2025. During the second quarter of 2026, we self-marketed 14,265 RINs, representing a 3,215 increase (29.1%) compared to 11,050 in the second quarter of 2025. Average pricing realized on RIN sales during the second quarter of 2026 was $2.45 as compared to $2.42 in the second quarter of 2025, an increase of 1.2%. Average D3 RIN index price for the second quarter of 2026 was $2.54 compared to $2.36 in the second quarter of 2025, an increase of approximately 7.6%. At June 30, 2026, we had approximately 429 MMBtu available for RIN generation, 137 RINs generated and unseparated, and 0 RINs generated and unsold. At June 30, 2025, we had approximately 309 MMBtu available for RIN generation, 3,009 RINs generated and unseparated, and 108 RINs generated and unsold. Renewable Electricity Generation Revenues We produced approximately 44 MWh in Renewable Electricity in the second quarter of 2026, an increase of 2 MWh (4.8%) from 42 MWh in the second quarter of 2025. Our Bowerman facility produced approximately 3 MWh more in the second quarter of 2026 compared to the second quarter of 2025. The increase is primarily related to increased gas flows due to landfill host wellfield improvements. Revenues from Renewable Electricity facilities in the second quarter of 2026 were $4,505, an increase of $207 (4.8%) compared to $4,298 in the second quarter of 2025. The increase was primarily driven by the increase in production volumes. 40 Table of Contents In both the second quarter of 2026 and 2025, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs. This provides us with certainty of price resulting from our Renewable Electricity sites. General and Administrative Revenues Total general and administrative revenues in the second quarter of 2026 were $8,579. We recorded approximately $8,402 in the second quarter of 2026 related to RINs distributed from our joint venture, GreenWave. We sold approximately 3,387 RINs distributed from GreenWave and the RINs related to pathway dispensing, which are not included within our operating metrics table. There were no such revenues incurred during the second quarter of 2025. Expenses for the Three Months Ended June 30, 2026 and 2025 General and Administrative Expenses Total general and administrative expenses in the second quarter of 2026 were $7,666, a decrease of $1,378 (15.2%) compared to $9,044 in the second quarter of 2025. The decrease is primarily related to a one-time accelerated vesting of $1,550 from certain restricted share awards in the second quarter of 2025 due to the termination of an employee. Operating and Maintenance Expenses Total operating and maintenance expenses in the second quarter of 2026 were $29,061, an increase of $7,197 (32.9%) compared to $21,864 in the second quarter of 2025. We recorded approximately $8,348 in the second quarter of 2026 related to the cost of RINs distributed from GreenWave and the costs related to pathway dispensing associated with our dispensing RNG in exclusive unique and proprietary pathways, which are not included within our operating metrics table. There were no such expenses incurred during the second quarter of 2025. Renewable Natural Gas Expenses Operating and maintenance expenses for our RNG facilities in the second quarter of 2026 were $15,568, a decrease of $1,387 (8.2%) as compared to $16,955 in the second quarter of 2025. Our McCarty facility operating and maintenance expenses decreased approximately $891 primarily related to the timing of maintenance related to gas processing equipment. Our Apex facility operating and maintenance expenses decreased approximately $451 primarily related to timing of gas processing preventative maintenance. Renewable Electricity Expenses Operating and maintenance expenses for our Renewable Electricity facilities in the second quarter of 2026 were $5,062, an increase of $253 (5.3%) compared to $4,809 in the second quarter of 2025. The increase is driven by an increase in non-capitalizable costs of approximately $1,162 at our Montauk Ag Renewables project. Our Bowerman facility operating and maintenance expenses decreased approximately $716 primarily related to decreased wellfield operational costs and timing of gas processing preventative maintenance. Royalty Payments Royalties, transportation, gathering, and production fuel expenses in the second quarter of 2026 were $8,814, a decrease of $354 (3.9%) compared to $9,168 in the second quarter of 2025. 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. Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the second quarter of 2026 were $8,293, a decrease of $375 (4.3%) compared to $8,668 in the second quarter of 2025. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 20.3% for the second quarter of 2026 from 21.2% in the second quarter of 2025. Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the second quarter of 2026 were $521, an increase of $22 (4.4%) compared to $499 in the second quarter of 2025. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of Renewable Electricity revenues to 11.5% for the second quarter of 2026 from 11.7% in the second quarter of 2025. 41 Table of Contents Depreciation Depreciation and amortization in the second quarter of 2026 was $7,904, an increase of $875 (12.4%) compared to $7,029 in the second quarter of 2025. The increase was primarily driven by our Second Apex RNG Facility project being placed into service. Impairment loss We calculated and recorded impairment losses of $650 in the second quarter of 2026, an increase of $273 (72.4%) compared to $377 in the second quarter of 2025. The increase relates to specifically identified discrete or non-operable assets. Other (Income) Expenses Other income in the second quarter of 2026 was $2,291, an increase of $3,547 (282.4%) compared to other expenses of $1,256 in the second quarter of 2025. In the second quarter of 2026, we recorded approximately $3,772 in income related to our joint venture investment in GreenWave. There was no such income from GreenWave in the second quarter of 2025. Income Tax Expense Income tax expense for the three months ended June 30, 2026 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily related to the adjustment of Production Tax Credits as well as stock based compensation. The effective tax rate of 89.8% for the three months ended June 30, 2026 was higher than the rate for the three months ended June 30, 2025 of (52.0%) primarily due to the change in our pre-tax book loss for the three months ended June 30, 2026 as compared to the three months ended June 30, 2025. Operating Loss for the Three Months Ended June 30, 2026 and 2025 Operating loss in the second quarter of 2026 was $75, a decrease of $2,280 (96.8%) compared to $2,355 in the second quarter of 2025. RNG operating income for the second quarter of 2026 was $9,643, an increase of $415 (4.5%) compared to $9,228 in the second quarter of 2025. Renewable Electricity Generation operating loss for the second quarter of 2026 was $2,132, a decrease of $216 (9.2%) compared to $2,348 for the second quarter of 2025. 42 Table of Contents Comparison of Six Months Ended June 30, 2026 and 2025 The following table summarizes the key operating metrics described above, which are metrics we use to measure performance. For the six months ended June 30, Change 2026 2025 Change % (in thousands, unless otherwise indicated) Revenues Renewable Natural Gas Total Revenues $ 79,010 $ 79,280 $ (270 ) (0.3 %) Renewable Electricity Generation Total Revenues $ 8,621 $ 8,450 $ 171 2.0 % RNG Metrics CY RNG production volumes (MMBtu) 2,810 2,802 8 0.3 % Less: Current period RNG volumes under fixed/floor-price contracts (199 ) (1,045 ) 846 81.0 % Plus: Prior period RNG volumes dispensed in current period 354 291 63 21.6 % Less: Current period RNG production volumes not dispensed (429 ) (309 ) (120 ) (38.8 %) Total RNG volumes available for RIN generation (1) 2,536 1,739 797 45.8 % RIN Metrics Current RIN generation ( x 11.6935) (2) 29,648 20,342 9,306 45.7 % Less: Counterparty share (RINs) (3,033 ) (3,112 ) 79 2.5 % Plus: Prior period RINs carried into current period 190 6,822 (6,632 ) (97.2 %) Less: RINs generated but unseparated (137 ) (3,009 ) 2,872 95.4 % Total RINs available for sale (3) 26,668 21,043 5,625 26.7 % Less: RINs sold (26,668 ) (20,935 ) (5,733 ) (27.4 %) RIN Inventory (0 ) 108 (108 ) (100.0 %) RNG Inventory (volumes not dispensed for RINs) (4) 429 309 120 38.8 % Average Realized RIN price $ 2.44 $ 2.42 $ 0.02 0.8 % Operating Expenses Renewable Natural Gas Operating Expenses $ 45,796 $ 46,828 $ (1,032 ) (2.2 %) Operating Expenses per MMBtu (actual) $ 16.30 $ 16.71 $ (0.41 ) (2.5 %) REG Operating Expenses $ 10,523 $ 9,116 $ 1,407 15.4 % $/MWh (actual) $ 120.95 $ 103.59 $ 17.36 16.8 % Other Metrics Renewable Electricity Generation Volumes Produced (MWh) 87 88 (1 ) (1.1 %) Average Realized Price $/MWh (actual) $ 99.09 $ 96.02 $ 3.07 3.2 % (1)RINs are generated in the month that the gas is dispensed to generate RINs, which occurs the month after the gas is produced. Volumes under fixed/floor-price arrangements generate RINs which we do not self-market. K3 RIN separation occurs after the gas is dispensed (RINs generated but unseparated). (2)One MMBtu of RNG has the same energy content as 11.6935 gallons of ethanol, and thus may generate 11.6935 RINs under the RFS program. (3)Represents RINs available to be self-marketed by us during the reporting period. (4)Represents gas production which has not been dispensed to generate RINs. 43 Table of Contents The following table summarizes our revenues, expenses and net income (loss) for the periods set forth below: For the six months ended June 30, Change 2026 2025 Change % Total operating revenues $ 100,447 $ 87,730 $ 12,717 14.5 % Operating expenses: Operating and maintenance expenses 52,215 39,422 12,793 32.5 % General and administrative expenses 15,686 17,798 (2,112 ) (11.9 )% Royalties, transportation, gathering and production fuel 16,851 16,739 112 0.7 % Depreciation, depletion and amortization 16,277 13,293 2,984 22.4 % Impairment loss 1,093 2,424 (1,331 ) (54.9 )% Total operating expenses 102,122 89,676 12,446 13.9 % Operating loss $ (1,675 ) $ (1,946 ) $ 271 13.9 % Other (income) expenses: (3,598 ) 2,446 (6,044 ) (247.1 )% Net income (loss) before income taxes: 1,923 (4,392 ) 6,315 143.8 % Income tax expense 1,692 1,559 133 8.5 % Net income (loss) $ 231 $ (5,951 ) $ 6,182 103.9 % Revenues for the Six Months Ended June 30, 2026 and 2025 Total revenues in the first six months of 2026 were $100,447, an increase of $12,717 (14.5%) compared to $87,730 in the first six months of 2025. The increase is primarily related to environmental attribute revenues of approximately $12,639 from RINs sold related to the distribution of RINs from our GreenWave joint venture which had no RINs distributed and sold in the first six months of 2025. Our first six months of 2026 RNG volumes sold under fixed/floor-price contracts decreased approximately 81.0% as compared to the first six months of 2025 as a result of the expiration of fixed price pathway contracts. Our RNG commodity revenue decreased approximately 56.5% which was offset by an increase in RINs sold of 27.4%. Also, our RINs generated and unseparated decreased approximately 95.4% as a result of the transition to BRRR in 2025. Renewable Natural Gas Revenues We produced 2,810 MMBtu of RNG during the first six months of 2026, an increase of 8 MMBtu (0.3%) over the 2,802 MMBtu produced in the first six months of 2025. Our Galveston facility produced 67 MMBtu fewer in the first six months of 2026 compared to the first six months of 2025 as a result of the landfill host assuming responsibility of wellfield operations and maintenance beginning in 2026. Offsetting this decrease was our Apex facility which produced 76 MMBtu more in the first six months of 2026 compared to the first six months of 2025 as a result of increased feedstock gas from our improvements related to the landfill collection system. Revenues from the Renewable Natural Gas segment in the first six months of 2026 were $79,010, a decrease of $270 (0.3%) compared to $79,280 in the first six months of 2025. Average commodity pricing for natural gas for the first six months of 2026 was $3.97 per MMBtu, 11.8% higher than the first six months of 2025. During the first six months of 2026, we self-monetized 26,668 RINs, representing a 5,733 increase (27.4%) compared to 20,935 in the first six months of 2025. Average pricing realized on RIN sales during the first six months of 2026 was $2.44 as compared to $2.42 in the first six months of 2025, an increase of 0.8%. The average D3 RIN index price for the first six months of 2026 was $2.48 as compared to $2.39 for the first six months of 2025, an increase of approximately 3.8%. At June 30, 2026, we had approximately 429 MMBtu available for RIN generation, 137 RINs generated and unseparated, and no RINs generated and unsold. At June 30, 2025, we had approximately 309 MMBtu available for RIN generation, 3,009 RINs generated and unseparated, and 108 RINs generated and unsold. Renewable Electricity Generation Revenues We produced approximately 87 MWh in Renewable Electricity in the first six months of 2026, a decrease of 1 MWh (1.1%) compared to 88 MWh in the first six months of 2025. Our Pico facility produced approximately 2 fewer MWh in the first six months of 2026 compared to the first six months of 2025 which is primarily related to decommissioning of one of our engines in 2025 due to the shift towards boiler heat for our digestion process. Our Bowerman facility produced approximately 2 MWh more in the first six months of 2026 compared to the first six months of 2025 which is primarily related to increased gas flows due to landfill host wellfield improvements. 44 Table of Contents Revenues from Renewable Electricity facilities in the first six months of 2026 were $8,621, an increase of $171 (2.0%) compared to $8,450 in the first six months of 2025. The increase is primarily driven by the increase in our Bowerman facility production volumes. In both the first six months of 2026 and 2025, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs. This provides us with certainty of price resulting from our Renewable Electricity sites. General and Administrative Revenues Total general and administrative revenues in the first six months of 2026 were $12,816. We recorded revenues of approximately $12,683 in the first six months of 2026 related to RINs distributed from our joint venture, GreenWave. We sold approximately 5,142 RINs distributed from GreenWave and the RINs related to pathway dispensing, which are not included within our operating metrics table. There were no such revenues incurred during the first six months of 2025. Expenses for the Six Months Ended June 30, 2026 and 2025 General and Administrative Expenses Total general and administrative expenses in the first six months of 2026 were $15,686, a decrease of $2,112 (11.9%) compared to $17,798 in the first six months of 2025. The decrease is primarily related to a one-time accelerated vesting of $1,550 from certain restricted share awards in the first six months of 2025 due to the termination of an employee and the vesting of share awards of approximately $942. Our professional fees increased approximately $514 driven by integrated audit fees. Operating and Maintenance Expenses Total operating and maintenance expenses in the first six months of 2026 were $52,215, an increase of $12,793 (32.5%) compared to $39,422 in the first six months of 2025. We recorded approximately $12,595 in the first six months of 2026 related to the cost of RINs distributed from GreenWave and the costs related to pathway dispensing associated with our dispensing RNG in exclusive unique and proprietary pathways, which are not included within our operating metrics table. There were no such expenses incurred during the first six months of 2025. Renewable Natural Gas Expenses Operating and maintenance expenses for our RNG facilities in the first six months of 2026 were $29,921, a decrease of $1,124 (3.6%) compared to $31,045 in the first six months of 2025. Our McCarty facility operating and maintenance expenses decreased approximately $890 primarily related to the timing of maintenance related to gas processing equipment. Our Galveston facility operating and maintenance expenses decreased approximately $748 primarily related to timing of gas processing preventative maintenance and decreased utility expense. Our Atascocita facility operating and maintenance expenses increased approximately $659 primarily related to wellfield operational enhancement expenses. Renewable Electricity Expenses Operating and maintenance expenses for our Renewable Electricity facilities in the first six months of 2026 were $9,546, an increase of $1,386 (17.0%) compared to $8,160 in the first six months of 2025. The increase was primarily driven by an increase in non-capitalizable costs at our Montauk Ag Renewables projects of approximately $1,970. Our Bowerman facility operating and maintenance expenses decreased approximately $345 primarily related to timing of gas processing preventative maintenance. Royalty Payments Royalties, transportation, gathering, and production fuel expenses in the first six months of 2026 were $16,851, an increase of $112 (0.7%) compared to $16,739 in the first six months of 2025. Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the first six months of 2026 were $15,875, an increase of $92 (0.6%) compared to $15,783 in the first six months of 2025. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 20.1% for the first six months of 2026 from 19.9% in the first six months of 2025. Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the first six months of 2026 were $976, an increase of $20 (2.1%) compared to $956 in the first six months of 2025. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses remained unchanged at 11.3%. 45 Table of Contents Depreciation Depreciation and amortization in the first six months of 2026 was $16,277, an increase of $2,984 (22.4%) compared to $13,293 in the first six months of 2025. The increase was primarily driven by our Second Apex RNG Facility project being placed into service. Impairment loss We calculated and recorded impairment losses of $1,093 in the first six months of 2026, a decrease of $1,331 (54.9%) compared to $2,424 in the first six months of 2025. The impairment losses in the first six months of 2026 primarily relate to various RNG equipment that was deemed obsolete for current operations. The impairment losses in the first six months of 2025 primarily relate to a development project RNG interconnection for which the local utility is no longer accepting RNG into its distribution system. All associated costs related to the interconnection were impaired and specifically identified assets deemed obsolete or non-operable. Other (Income) Expenses Other income in the first six months of 2026 was $3,598, an increase of $6,044 (247.1%) compared to other expenses of $2,446 the first six months of 2025. In the first six months of 2026, we recorded approximately $7,092 in income related to our joint venture investment in GreenWave. There was no such income from GreenWave in the first six months of 2025. We recorded approximately $944 in debt extinguishment costs in the first six months of 2026 related to our refinancing of our credit agreement. Income Tax Expense Income tax expense for the six months ended June 30, 2026 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily due to the benefit from production tax credits. The effective tax rate of 88.0% for the six months ended June 30, 2026 was lower than the rate for the six months ended June 30, 2025 of (35.5)% primarily due to the change in our pre-tax book loss for the six months ended June 30, 2026 compared to our pre-tax book loss for the six months ended June 30, 2025. Operating (Loss) Income for the Six Months Ended June 30, 2026 and 2025 Operating loss in the first six months of 2026 was $1,675, a decrease of $271 (13.9%) compared to $1,946 in the first six months of 2025. RNG operating income for the first six months of 2026 was $18,385, a decrease of $1,212 (6.2%) compared to $19,597 in the first six months of 2025. Renewable Electricity Generation operating loss for the first six months of 2026 was $4,303, an increase of $934 (27.7%) compared to $3,369 for the first six months of 2025. 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 (loss) 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 (loss), which is the most directly comparable GAAP measure, for the three months ended June 30, 2026 and 2025: For the three months ended June 30, 2026 2025 Net income (loss) $ 226 $ (5,487 ) Depreciation, depletion and amortization 7,904 7,029 Interest expense 1,531 1,216 Income tax expense 1,990 1,876 Consolidated EBITDA 11,651 4,634 Impairment loss (1) 650 377 Loss on sale or disposal of assets — 21 Adjusted EBITDA $ 12,301 $ 5,032 46 Table of Contents (1)We recorded impairment losses of $650 and $377 for the three months ended June 30, 2026 and 2025, respectively. The impairment losses recorded in the three months ended June 30, 2026 relate to specifically identified assets deemed obsolete or non-operable. The impairment losses recorded in the three months ended June 30, 2025 primarily relate to an RNG interconnection impairment. The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income (loss), which is the most directly comparable GAAP measure, for the six months ended June 30, 2026 and 2025: For the six months ended June 30, 2026 2025 Net income (loss) $ 231 $ (5,951 ) Depreciation, depletion and amortization 16,277 13,293 Interest expense 2,866 2,459 Income tax expense 1,692 1,559 Consolidated EBITDA 21,066 11,360 Impairment loss (1) 1,093 2,424 Loss on extinguishment of debt 944 — Net (gain) loss on sale or disposal of assets (13 ) 36 Adjusted EBITDA $ 23,090 $ 13,820 (1)We recorded impairment losses of $1,093 and $2,424 for the six months ended June 30, 2026 and 2025, respectively. The impairment losses recorded in the first six of 2026 relate to specifically identified assets deemed obsolete or non-operable. The impairment losses recorded in the first six months of 2025, relate to a development project RNG interconnection for which the local utility is no longer accepting RNG into its distribution system and specifically identified assets deemed obsolete or non-operable. Liquidity and Capital Resources Sources of Liquidity At June 30, 2026 and June 30, 2025, our cash and cash equivalents, net of restricted cash, was $15,757 and $29,133, 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 interest-only 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 and operational risks that could adversely affect our cash flows and liquidity. At June 30, 2026, we had debt before debt issuance costs of $155,000, compared to debt before debt issuance costs of $129,000 at December 31, 2025. Our debt before issuance costs (in thousands) are as follows: June 30, 2026 December 31, 2025 Term loan $ 155,000 44,000 Revolving credit facility — 85,000 Debt before debt issuance costs $ 155,000 $ 129,000 New Senior Credit Facility On March 9, 2026, we entered into a five year New Senior Credit Facility with HASI that provides up to $200,000 in senior indebtedness. The New Senior Credit Facility has a 24 month availability period during which only interest is payable quarterly. After the availability period, we will be subject to quarterly principal payments equal to 1.25% of the total outstanding principal balance. The New Senior Credit Facility has an interest rate of 10.25% and matures in 2031. The New Senior Credit Facility is subject to customary financial covenants. The New Senior Credit Facility 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 $1.00 per RIN and (y) the consolidated average quarterly trailing EBITDA over the previous four quarters is less than $10,000. The New Senior Credit Facility includes various affirmative and negative covenants that require us to meet specified financial ratios and financial tests, as defined in the underlying agreement. 47 Table of Contents The New Senior Credit Facility financial debt covenants commenced June 30, 2026 and we are required to maintain the following as defined in the underlying agreement: •Total Net Leverage Ratio of not more than 4.00 to 1.00, •As of the end of each fiscal quarter, a Fixed Charge Coverage Ratio of not less than 1.20 to 1.00, and •Various other financial covenants or mandatory prepayments As of June 30, 2026, we were in compliance with all applicable financial covenants under the New Senior Credit Facility. For additional information regarding the New Senior Credit Facility, see Note 13— Debt to our unaudited condensed 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 2026 capital expenditures to range between $20,000 and $25,000. Our 2026 non- development capital plans include preventative maintenance expenditures, wellfield expansion projects, critical spare expenditures, other specific facility improvements, and information technology improvements. Additionally, included in our 2026 non-development capital expenditures are original equipment manufacturer required lifecycle expenditures on our engines at our Bowerman facility. We expect these lifecycle expenditures at our Bowerman facility to continue through 2027. We currently estimate that our existing 2026 development capital expenditures will range between $80,000 and $100,000. Our ongoing 2026 development capital expenditures relate to the development of Montauk Ag Renewables, the Bowerman RNG project, the Rumpke RNG Relocation Project, the Atascocita CO2 project and the Tulsa RNG project. The reduction of 2026 development capital expenditures is primarily driven by the timing of our Atascocita CO2 project development and the refinement of long lead milestone payments. We believe that our credit refinancing with HASI will provide us the ability to secure additional project-based financing for our current development projects. We believe that our existing cash and cash equivalents, cash generated from operations, and credit availability under our New Senior Credit Facility will meet our interest-only debt service obligations and anticipated required capital expenditures (including for projects under development) for the next 12 to 24 months. Cash Flow The following table presents information regarding our cash flows and cash equivalents for the six months ended June 30, 2026 and 2025: For the six months ended June 30, 2026 2025 Net cash provided by (used in): Operating activities $ 30,445 $ 17,346 Investing activities (55,527 ) (47,446 ) Financing activities 19,382 13,614 Net decrease in cash and cash equivalents and restricted cash (5,700 ) (16,486 ) Restricted cash, end of the period 2,733 385 Cash and cash equivalents, end of period 18,490 29,518 For the first six months of 2026, we generated $30,445 of cash provided by operating activities compared to $17,346 in the first six months of 2025. For the first six months of 2026, income and adjustments to income from operating activities provided $22,847 compared to income and adjustments to income providing $16,172 in first six months of 2025. Working capital and other assets and liabilities provided $7,598 in the first six months of 2026 compared to working capital and other assets and liabilities providing $1,174 in the first six months of 2025. Our net cash flows used in investing activities has historically focused on project development and facility maintenance. Our capital expenditures for the first six months of 2026 were $61,049, of which $49,782 and $3,557, were related to the Montauk Ag Renewables in North Carolina and Bowerman RNG, respectively. Our capital expenditure cash payments were $55,560. The variance is primarily driven by the timing differences related to capital expenditures in accounts payable. Our net cash flows provided by financing activities of $19,382 for the first six months of 2026, increased $5,768, compared to cash provided by financing activities in the first six months of 2025 of $13,614. 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 described below. Although these arrangements serve a variety of our business purposes, 48 Table of Contents 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 in the unaudited condensed consolidated financial statements for further information regarding the asset retirement obligations. We have contractual obligations under our debt agreement, including interest payments and principal repayments. See Note 13 in the unaudited condensed consolidated financial statements for further discussion of the contractual commitments under our debt agreements. During the first six months of 2026, we had $2,185 of outstanding letters of credit. There have been no draw downs on these outstanding letters of credit. During the first six months of 2025, we did not have off-balance sheet arrangements other than outstanding letters of credit of $2,571. Under the terms of our New Senior Credit Facility with HASI, we are required to maintain cash to collateralize these outstanding letters of credit. This restricted cash is included in “Non-current restricted cash” within our consolidated balance sheet as of June 30, 2026. We have contractual obligations involving operating leases. We lease office space and other office equipment under operating lease arrangements, expiring in various years through 2033. See Note 19 in the unaudited condensed 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 ranges from 1 to 17 years. The minimum royalty and capital obligation associated with these agreements ranges from $8 to $1,746. Critical Accounting Policies and Estimates Our unaudited condensed 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, medium and long 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 the Company’s 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. 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. RECs We generate RECs through our production and conversion of landfill methane into Renewable Electricity in 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 49 Table of Contents 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 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. 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. 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 cash flows 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 affect 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. We identified discrete events and recorded an impairment of $1,093 and $2,424 for the six months ended June 30, 2026 and 2025, respectively. See Note 3 in the unaudited condensed consolidated financial statements for further information related to asset impairments. 50 Table of Contents Emerging Growth Company We are an emerging growth company, as defined in the JOBS Act. We will lose our emerging growth company status on December 31, 2026. As a result, we will no longer be permitted to take advantage of certain reduced disclosure and other requirements applicable to emerging growth companies, including the ability to delay the adoption of new or revised accounting standards. Recent Accounting Pronouncements For a description of our recently adopted accounting pronouncements and recently issued accounting standards not yet adopted, see Note 2 of our unaudited condensed consolidated financial statements in this report. 51 Table of Contents