# Montauk Renewables, Inc. (MNTK) Informational only - not investment advice. CIK: 0001826600 SIC: 4932 Gas & Other Services Combined SIC breadcrumb: [Transportation, Communications, Electric, Gas, And Sanitary Services](/division/E/) > [Electric, Gas, And Sanitary Services](/major-group/49/) > [SIC 4932 Gas & Other Services Combined](/industry/4932/) Latest 10-K filed: 2026-03-11 SEC page: https://www.sec.gov/edgar/browse/?CIK=1826600 Filing source: https://www.sec.gov/Archives/edgar/data/1826600/000119312526102364/mntk-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 176382000 | USD | 2025 | 2026-03-11 | | Net income | 1748000 | USD | 2025 | 2026-03-11 | | Assets | 435460000 | USD | 2025 | 2026-03-11 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-03-11. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001826600.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts. | Metric | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | 105,714,000 | 100,383,000 | 148,127,000 | 205,559,000 | 174,904,000 | 175,736,000 | 176,382,000 | | Net income | 5,820,000 | 4,603,000 | -4,528,000 | 35,194,000 | 14,948,000 | 9,734,000 | 1,748,000 | | Operating income | 11,005,000 | 3,581,000 | 3,335,000 | 44,566,000 | 23,640,000 | 16,123,000 | 852,000 | | Diluted EPS | | | -0.03 | 0.25 | 0.11 | 0.07 | 0.01 | | Operating cash flow | 27,825,000 | 28,684,000 | 42,879,000 | 81,066,000 | 41,053,000 | 43,795,000 | 30,334,000 | | Capital expenditures | | | 9,986,000 | 22,277,000 | 63,091,000 | 62,323,000 | 116,542,000 | | Assets | 243,613,000 | 253,356,000 | 286,480,000 | 332,316,000 | 350,238,000 | 349,015,000 | 435,460,000 | | Liabilities | | 93,734,000 | 104,187,000 | 105,225,000 | 99,999,000 | 91,598,000 | 172,312,000 | | Stockholders' equity | 154,257,000 | 159,622,000 | 182,293,000 | 227,091,000 | 250,239,000 | 257,417,000 | 263,148,000 | | Cash and cash equivalents | 9,788,000 | 20,992,000 | 53,266,000 | 105,177,000 | 73,811,000 | 45,621,000 | 23,752,000 | | Free cash flow | | | 32,893,000 | 58,789,000 | -22,038,000 | -18,528,000 | -86,208,000 | ### Ratios ROE and ROA use period-end equity/assets. Liabilities / equity uses total liabilities divided by stockholders' equity. Current ratio uses current assets divided by current liabilities when both are reported. | Metric | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Net margin | 5.51% | 4.59% | -3.06% | 17.12% | 8.55% | 5.54% | 0.99% | | Operating margin | 10.41% | 3.57% | 2.25% | 21.68% | 13.52% | 9.17% | 0.48% | | Return on equity | 3.77% | 2.88% | -2.48% | 15.50% | 5.97% | 3.78% | 0.66% | | Return on assets | 2.39% | 1.82% | -1.58% | 10.59% | 4.27% | 2.79% | 0.40% | | Liabilities / equity | | 0.59 | 0.57 | 0.46 | 0.40 | 0.36 | 0.65 | | Current ratio | | 1.14 | 3.06 | 4.40 | 3.07 | 1.71 | 1.11 | ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-06. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001826600.json. Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived. | Quarter | End date | Revenue | Net income | Diluted EPS | Method | | --- | --- | ---: | ---: | ---: | --- | | 2022-Q2 | 2022-06-30 | | | 0.13 | reported discrete quarter | | 2022-Q3 | 2022-09-30 | | | 0.08 | reported discrete quarter | | 2023-Q1 | 2023-03-31 | | | -0.03 | reported discrete quarter | | 2023-Q2 | 2023-06-30 | 53,256,000 | 1,003,000 | 0.01 | reported discrete quarter | | 2023-Q3 | 2023-09-30 | 55,688,000 | 12,934,000 | 0.09 | reported discrete quarter | | 2023-Q4 | 2023-12-31 | 46,807,000 | 4,799,000 | | derived Q4 = FY annual - nine-month YTD | | 2024-Q1 | 2024-03-31 | 38,787,000 | 1,850,000 | 0.01 | reported discrete quarter | | 2024-Q2 | 2024-06-30 | 43,338,000 | -712,000 | -0.01 | reported discrete quarter | | 2024-Q3 | 2024-09-30 | 65,917,000 | 17,048,000 | 0.12 | reported discrete quarter | | 2024-Q4 | 2024-12-31 | 27,694,000 | -8,452,000 | | derived Q4 = FY annual - nine-month YTD | | 2025-Q1 | 2025-03-31 | 42,603,000 | -464,000 | 0.00 | reported discrete quarter | | 2025-Q2 | 2025-06-30 | 45,127,000 | -5,487,000 | -0.04 | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 45,258,000 | 5,205,000 | 0.04 | reported discrete quarter | | 2025-Q4 | 2025-12-31 | 43,394,000 | 2,494,000 | | derived Q4 = FY annual - nine-month YTD | | 2026-Q1 | 2026-03-31 | 46,428,000 | 5,000 | 0.00 | reported discrete quarter | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance - [MSPUS](/indicator/MSPUS/): Median Sales Price of Houses Sold for the United States - [HSN1F](/indicator/HSN1F/): New One Family Houses Sold: United States - [RHORUSQ156N](/indicator/RHORUSQ156N/): Homeownership Rate in the United States - [TTLCONS](/indicator/TTLCONS/): Total Construction Spending: Total Construction in the United States - [RRVRUSQ156N](/indicator/RRVRUSQ156N/): Rental Vacancy Rate in the United States - [TOTALSL](/indicator/TOTALSL/): Total Consumer Credit Owned and Securitized - [REVOLSL](/indicator/REVOLSL/): Revolving Consumer Credit Owned and Securitized - [DRCCLACBS](/indicator/DRCCLACBS/): Delinquency Rate on Credit Card Loans, All Commercial Banks - [GDP](/indicator/GDP/): Gross Domestic Product - [GPDI](/indicator/GPDI/): Gross Private Domestic Investment - [GCE](/indicator/GCE/): Government Consumption Expenditures and Gross Investment - [PCEC](/indicator/PCEC/): Personal Consumption Expenditures - [NETEXP](/indicator/NETEXP/): Net Exports of Goods and Services - [GFDEBTN](/indicator/GFDEBTN/): Federal Debt: Total Public Debt - [GFDEGDQ188S](/indicator/GFDEGDQ188S/): Federal Debt: Total Public Debt as Percent of Gross Domestic Product - [FYFSD](/indicator/FYFSD/): Federal Surplus or Deficit - [FGRECPT](/indicator/FGRECPT/): Federal Government Current Receipts - [FGEXPND](/indicator/FGEXPND/): Federal Government: Current Expenditures - [MANEMP](/indicator/MANEMP/): All Employees, Manufacturing - [USCONS](/indicator/USCONS/): All Employees, Construction - [USTRADE](/indicator/USTRADE/): All Employees, Retail Trade - [USFIRE](/indicator/USFIRE/): All Employees, Financial Activities - [USGOVT](/indicator/USGOVT/): All Employees, Government - [AWHAETP](/indicator/AWHAETP/): Average Weekly Hours of All Employees, Total Private - [DGORDER](/indicator/DGORDER/): Manufacturers' New Orders: Durable Goods - [NEWORDER](/indicator/NEWORDER/): Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft - [BUSINV](/indicator/BUSINV/): Total Business Inventories - [EXPGS](/indicator/EXPGS/): Exports of Goods and Services - [IMPGS](/indicator/IMPGS/): Imports of Goods and Services - [IR](/indicator/IR/): Import Price Index (End Use): All Commodities - [PPIFIS](/indicator/PPIFIS/): Producer Price Index by Commodity: Final Demand ## Latest quarter (10-Q) Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/1826600/000119312526209250/mntk-20260331.htm Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Confidence: high Filing date: 2026-05-06 Report date: 2026-03-31 ITEM 2. 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 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,” “Item 1A.–Risk Factors” of our 2025 Annual Report, and elsewhere in this report. 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 sold all 3,903 D3 RINs generated and available for sale from our 2025 RNG production in the first quarter of 2026. We had approximately 165 RINs generated but unseparated at March 31, 2026. The average D3 RIN index price for the first quarter of 2026 was approximately $2.41. The following table summarizes select historical data related to RINs generated, RINs sold, and RINs generated but unsold. 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. 28 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 Second Quarter 14,707 10,000 68.0% 4,707 32.0% 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% 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 $85,000-$95,000 Atascocita LCO2 Facility N/A TBD $30,000-$40,000 Tulsa RNG Facility 1,500 2027 $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. 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 RECs to meet 2025 compliance targets. The compliance obligations for those utilities filing the September 2025 joint motion continue to increase through 2029. We have commissioned our Montauk Ag Renewables project and are producing syngas. We expect our production and sale of renewable electricity from our syngas to commence in May 2026, with revenue generation triggered upon the calibration of the sales meter from the interconnection utility. We have operated the full production line as part of the commissioning process and expect to be able to produce our targeted first phase of 47 MWh and 120 RECs annually with approximately 50 percent of our installed reactor capacity. Our capital investment expectation for this first phase of the project remains unchanged at $200,000. We expect a ramp-up in production volumes throughout 2026 directly related to additional feedstock collection. 29 Table of Contents 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. Raeger Gas Rights Extension In March 2026, we successfully negotiated a five-year gas rights extension at our Raeger facility. The extension secures our access to biogas feedstock at the site through 2031, supporting the continued operation of the facility. 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 $3,320 in the first quarter of 2026. We also received 1,398 in separated RINs distributed from GreenWave of which we have 425 available for sale as of March 31, 2026. 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. New Senior Credit Facility On March 9, 2026, , we entered into a five year New Senior Credit Facility with HASI that consists of up to $200,000 in senior indebtedness, of which $155,000 is outstanding as of March 31, 2026. We used this facility to refinance our existing outstanding debt and have $45,000 available to borrow subject to terms of the agreement. 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 are currently exploring 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. Key Trends Market Trends Affecting the Renewable Fuel Market We believe rising demand for RNG [Excerpt truncated for page length; source filing is linked above.] ## Latest 10-K MD&A Extracted from Item 7 to the first post-MD&A boundary after HTML sanitization. Confidence: high 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. Amounts are in thousands unless indicated otherwise. 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, 2025 compared to the year ended December 31, 2024. For discussion and analysis of our results for the year ended December 31, 2024 compared to the year ended December 31, 2023, 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, 2025. 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. -36- Table of Contents 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 expect the timing between RINs generated and unseparated and RINs available for sale to only impact 2025 which is the year BRRR became effective. We have entered into commitments to transfer all RINs generated and available for sale from 2025 RNG production. We had approximately 190 RINs generated and unseparated at December 31, 2025. We have entered into commitments to transfer approximately 2,500 RINs generated and available for sale from 2026 RNG production. The average D3 RIN index price for the fourth quarter of 2025 and January 2026 through February 28, 2026 was approximately $2.39 and $2.41, respectively. The following table summarizes select historical data related to RINs generated, RINs sold, and RINs generated but unsold. As we self-market a significant portion of our RINs and as the RFS is based on annual compliance, any strategic decision to not monetize available RINs in a quarter could impact the timing of operating revenues recognized during a fiscal year. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. 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. 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 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% 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% Capital Development Summary The following summarizes our ongoing development growth plans, expected capacity contribution, anticipated commencement of operations, and capital expenditure estimate, 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 $85,000-$95,000 European Energy Facilities N/A TBD $65,000-$75,000 Tulsa RNG Facility 1,500 2027 $25,000-$35,000 Rumpke RNG Relocation Project 7,500 2028 $70,000-$90,000 Pico Digestion Capacity Increase In 2025, we began processing the final tranche of increased feedstock. Upon receipt of the final tranche, we made the final contractual payment to the dairy host. As a result of the increased digestion capacity, we produced approximately 31.8% more MMBtu during 2025 as compared to 2024. During 2025, our digestion inlet feedstock averaged approximately 458 gallons per day, approximately 17% in excess of our contracted minimums of 390 gallons per day. We are currently evaluating additional development expansion opportunities to ensure beneficial processing of all available feedstock volumes. Second Apex RNG Facility In 2025, we successfully completed the construction and commissioning 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. 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 its waste intake. We continue to collaborate with the landfill host to mitigate impacts from wellfield extraction factors -37- Table of Contents which could impact capacity utilization. In connection with the commissioning of the second facility, we produced approximately 7.8% more MMBtu during 2025 as compared to 2024. Blue Granite RNG Project In 2025, we received notice from the utility that it will no longer accept RNG into its distribution system, which was in opposition of the letter of intent that was issued when we were awarded the gas rights to the site. As a result, we impaired the capital associated with the interconnection and equipment. We continue to have $1,000 recorded associated with the payment upon award of the gas rights agreement. 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, including physical and virtual and fixed interconnections. We are also reviewing alternatives for this site around producing energy other than RNG. We have paused capital expenditures related to this site while we consider all alternatives and continue discussions with the landfill host. Tulsa REG Conversion to RNG In 2025, we announced the conversion of our Tulsa, Oklahoma Renewable Electric Generation facility to RNG project. The project will offer a variable inlet capacity, ranging from 550 scfm to 2,250 scfm per day, providing average production capacity we target to be approximately 1,500 MMBtu per day and designed to beneficially process all of available inlet gas feedstock from its landfill host. We expect commissioning in 2027 and to continue incurring capital expenditures for long lead items. For the second half of 2025, our wellfield development initiatives have yielded increased feedstock totaling an overage of 1200 scfm per day. GreenWave Joint Venture In 2025, 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 (“Greenwave”). 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. In the third quarter of 2025, Greenwave began matching available RNG volumes to dispensing opportunities through Greenwaves's transportation pathways. The joint venture has matched available dispensing capacity with available third party RNG volumes to separate RINs. We recorded income from Greenwave of $1,485 in 2025. 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. 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. In 2025, we have been recognizing an exclusivity fee related to the minimum tons of CO2. The annual price per ton under the contract is adjusted annually by the U.S. consumer price index. The agreement with EENA includes a 50% sharing component of any available tax attributes generated by us under code section 45Q, Carbon dioxide sequestration credit, in the Inflation Reduction Act, as applicable. We have completed the initial site surveys related to location of the CO2 processing equipment, evaluated equipment suppliers, and started engineering design. We believe that we can fulfill the contracted volumes with the development of CO2 at two of our Texas facilities. We continue to match our capital investment in these project opportunities with the development timeline of EENA’s facility. Montauk Ag Asset 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 121 RECs and 8.7 tons of organic fertilizer alternative. Regulatory Developments In 2024, the North Carolina Utilities Commission ("NCUC") approved our Turkey, North Carolina location for a New Renewable Energy Facility (“NREF”) designation 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 Clean Energy and Energy Efficiency Portfolio Standards ("CEPS") governing the generation of RECs from swine waste that established a REC multiplier for swine waste produced in a Tier 1 county, which includes Sampson County, the location of our Turkey facility. For -38- Table of Contents qualifying projects, for each swine REC generated, 2 enhanced RECs will be credited for a total three RECs for a period of 8 years, followed by one enhanced REC for a total two RECs for a period of 6 years and a credit of one REC thereafter. There is a limit of 80 enhanced RECs in a year. In September 2025, a joint motion was filed with the NCUC by various entities seeking to modify and delay certain aspects of the CEPS, specifically, the portfolio standards relating to swine RECs. 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 RECs to meet 2025 compliance targets with the ability to use solar RECs to fill any compliance shortage. The compliance obligations for those utilities filing the September 2025 joint motion continue to increase through 2029. Offtake Developments We have entered into a ten-year agreement to sell all of the renewable electricity generated by the project. Furthermore, we expect the annual REC capacity of the Turkey location to be approximately 120 RECs and have signed a REC agreement with Duke Energy for 47 RECs. 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 the price per swine REC could fall within the range of $200 to $400 per REC. Feedstock Collection At full first phase capacity, we anticipate the ability to process feedstock from approximately 400 to 450 hog spaces per day, which equates to approximately 35 tons of annual waste collection. We have entered into long term agreements with over forty separate farming locations to provide access to waste from at least 300 hog spaces to support our expected processing needs under our first phase for the Turkey location. We continue to install collection equipment at these separate farms to access the waste. We currently estimate capital investment of approximately $250 at each farm related to the installed collection equipment. We intend to contract with additional farms to secure feedstock sources for future production processes. In advance of commercial operation date, feedstock collection has begun with collecting the dewatered feedstock from each farm and transporting to the project site for pelletization and storage. Capital Investment and Progress towards Commercial Operation Date (COD) We currently expect the first phase capital investment to be approximately $200,000 and have spent approximately $140,000 as of December 31, 2025. Winter storms in the Carolinas early 2026 and project deliveries have caused only nominal project delays. We have begun to commission the facility and expect our production and revenue generation activities to commence in April 2026. 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. Based on our Pico digestion expansion project experience, for other large and qualifying projects we believe that 50-75% of project capital will quality for IRC code 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 which do not meet the various safe harbor guidelines, we expect the tax benefits to range between 6-12% for qualifying assets. As it relates to our capital expenditures and future electric power production, we estimate IRC code section 48 investment tax credits and production tax credits could range between $6,000 - $20,000. We give no assurances that our estimates on tax attributes for our Montauk Ag Renewables project will meet these expectations. 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 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 and this work remains ongoing. 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. During 2025, wellfield initiatives have resulted in -39- Table of Contents approximately 4,100 scfm of averaged unprocessed gas which is more than the anticipated inlet of the RNG facility currently under development. Rumpke RNG Relocation Project In connection with our gas rights agreement with our landfill host at our Rumpke RNG location, in 2025, we began the process of relocating our existing Rumpke RNG facility. The timing of this project and requirement to relocate the facility coincides with the landfill's filling practices moving into the existing area of our Rumpke RNG facility and is contractually obligated. We expect facility commissioning in 2028 and the capital expenditures to range between $70,000 - $90,000, which is dependent on the timing of capital expenditures and potential other production capabilities requested by the landfill host. We continue to incur capital expenditures for this project. Additionally, the landfill host has requested a modification of our current development design to accommodate a large CNG filling station for their fleet. 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: 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: 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 -40- Table of Contents Register for the RFS volume requirements for 2023-2025. Final volumes for cellulosic biofuel were set at 838, 1,090 and 1,376 RINs for the three years 2023, 2024 and 2025, respectively. The final rule also included significant changes to the existing RFS program, referred to as BRRR, that required the RNG industry to modify how all RINs are generated as of January 1, 2025. 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. On June 13, 2025, the EPA released both the Partial Waiver of the 2024 Cellulosic Biofuel Volume Requirement (Final Rule) and RFS Standards for 2026 and 2027, Partial Waiver of 2025 Cellulosic Biofuel Volume Requirement, and Other Changes (Proposed Rule). The final 2024 cellulosic biofuel volume requirement was reduced from 1,090 to 1,010 million D3 RINs. This reduction was based on actual volumes of D3 RINs generated in 2024. In addition, the EPA is making Cellulosic Waiver Credits ("CWCs") available for 2024 as an additional compliance flexibility for obligated parties. In the EPA’s proposed rule released on June 13, 2025, the cellulosic biofuel volumes for 2025 were proposed to be reduced from 1,376 to 1,190 RINs and make CWCs available for 2025. The proposed cellulosic biofuel volume requirements for 2026 and 2027 are 1,300 and 1,360 D3 RINs, respectively. These volumes are less than the EPA had previously finalized for 2025 and are based on their belief that cellulosic RIN generation from biogas-derived CNG/LNG during 2026-2030 will be constrained by the total usage capacity of CNG/LNG as transportation fuel. These proposed rules are subject to comment periods prior to finalization. On August 22, 2025, EPA issued decisions on 175 Small Refinery Exemption (SRE) petitions. EPA granted full exemption (100%) to 63 petitions and partial exemptions (50%) to 77 petitions. The SRE decisions exempted corresponding volumes of gasoline and diesel for the 2023 and 2024 compliance years, and increased the number of RINs available for obligated parties to use for compliance with their RFS obligations. Taking into consideration the expected impacts of the SRE decisions on the RFS market, on September 16, 2025, EPA co-proposed a Supplemental Rule that provides additional volumes in 2026 and 2027 RVOs that will represent complete (100%) reallocation or partial (50%) reallocation for SREs granted in full or in part, respectively, for 2023 and 2024, as well as those projected to be granted for 2025. EPA has indicated an intention to finalize the Supplemental Rule & the RVOs for 2025, 2026 and 2027 by the end of 2025, however, the duration of the US federal government shut down and any residual impacts on EPA staffing after the shutdown concludes may extend finalization of these items into 2026. 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 would 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 see3 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 November 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. 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. 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 -41- Table of Contents 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 and 2025. We have 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 these 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 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. Revenues from RINs distributed from GreenWave, 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. • 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 these mitigation efforts have continued in 2025. 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. • 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 projects, 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 -42- Table of Contents 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 entered into commitments to transfer approximately 2,500 RINs generated and available for sale from 2026 RNG production at an average price of $2.42. 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. Expenses from RINs distributed from GreenWave and the costs related to pathway dispensing are not included in our operating metrics table. • 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 see increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2025. We account for share-based compensation related to grants made through our equity and incentive compensation plan under FASB ASC 718. In 2025, we recognized $1,550 of onetime non-cash stock compensation expense within general and administration expenses as a result of the termination which we do not anticipate will recur in 2026. 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. -43- Table of Contents • 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 may 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. 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. -44- Table of Contents Comparison of Years Ended December 31, 2025 and 2024 The following table summarizes the key operating metrics described above, which metrics we use to measure performance. For the year ended December 31, Change 2025 2024 Change % (in thousands, unless otherwise indicated) Revenues Renewable Natural Gas Total Revenues $ 155,736 $ 157,983 $ (2,247 ) (1.4 %) Renewable Electricity Generation Total Revenues $ 17,231 $ 17,753 $ (522 ) (2.9 %) RNG Metrics CY RNG production volumes (MMBtu) 5,644 5,587 57 1.0 % Less: Current period RNG volumes under fixed/floor-price contracts (1,907 ) (1,546 ) (361 ) 23.4 % Plus: Prior period RNG volumes dispensed in current period 291 358 (67 ) (18.7 %) Less: Current period RNG production volumes not dispensed (354 ) (291 ) (63 ) 21.6 % Total RNG volumes available for RIN generation (1) 3,674 4,108 (434 ) (10.6 %) RIN Metrics Current RIN generation ( x 11.6935) (2) 42,970 48,177 (5,207 ) (10.8 %) Less: Counterparty share (RINs) (5,470 ) (4,824 ) (646 ) 13.4 % Plus: Prior period RINs carried into current period 6,822 108 6,714 6216.7 % Less: RINs generated but unseparated (190 ) — (190 ) 0.0 % Less: CY RINs carried into next CY — (6,822 ) 6,822 (100.0 %) Total RINs available for sale (3) 44,132 36,639 7,493 20.5 % Less: RINs sold (44,132 ) (36,639 ) (7,493 ) 20.5 % RIN Inventory — — — 0.0 % RNG Inventory (volumes not dispensed for RINs) (4) 354 291 63 21.6 % Average Realized RIN price $ 2.33 $ 3.28 $ (0.95 ) (29.0 %) Operating Expenses Renewable Natural Gas Operating Expenses $ 90,095 $ 82,916 $ 7,179 8.7 % Operating Expenses per MMBtu (actual) $ 15.96 $ 14.84 $ 1.12 7.5 % REG Operating Expenses $ 16,670 $ 14,734 $ 1,936 13.1 % $/MWh (actual) $ 94.18 $ 79.22 $ 14.96 18.9 % Other Metrics Renewable Electricity Generation Volumes Produced (MWh) 177 186 (9 ) (4.8 %) Average Realized Price $/MWh (actual) $ 97.35 $ 95.45 $ 1.90 2.0 % (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 on which RINs are not generated. Results of Operations Comparison of Years Ended December 31, 2025 and 2024 -45- Table of Contents The following table summarizes our revenues, expenses and net income for the periods set forth below: For the year ended December 31, Change 2025 2024 Change % Total operating revenues $ 176,382 $ 175,736 $ 646 0.4 % Operating expenses: Operating and maintenance expenses 77,646 66,663 10,983 16.5 % General and administrative expenses 31,736 36,286 (4,550 ) (12.5 )% Royalties, transportation, gathering and production fuel 32,945 31,502 1,443 4.6 % Depreciation, depletion and amortization 29,972 23,515 6,457 27.5 % Impairment loss 3,231 1,586 1,645 103.7 % Transaction costs - 61 (61 ) (100.0 )% Total operating expenses 175,530 159,613 15,917 10.0 % Operating income $ 852 $ 16,123 $ (15,271 ) (94.7 )% Other expenses: 3,339 3,946 (607 ) (15.4 )% Net (loss) income before income taxes: (2,487 ) 12,177 (14,664 ) (120.4 )% Income tax (benefit) expense (4,235 ) 2,443 (6,678 ) (273.4 )% Net income $ 1,748 $ 9,734 $ (7,986 ) (82.0 )% Revenues for the Years Ended December 31, 2025 and 2024 Total revenues in 2025 were $176,382, an increase of $646 (0.4%) compared to $175,736 in 2024. The increase is driven by the number of RINs we self-marketed during 2025 due to a strategic decision to not self-market 6,822 RINs in the fourth quarter of 2024. Offsetting the increase, is a decrease in the 2025 average realized RIN price of $2.33, which decreased approximately 29.0% compared to $3.28 in 2024, and an increase in our current period RNG volumes sold under fixed/floor-price contracts. Our margin sharing revenues increased approximately $1,016 in 2025 as compared to 2024. The natural gas index price increased approximately 51.1% from $2.27 in 2024 to $3.43 in 2025. Renewable Natural Gas Revenues We produced 5,644 MMBtu of RNG during 2025, an increase of 57 MMBtu (1.0%) compared to 5,587 MMBtu in 2024. We increased our production when considering our 2024 fourth quarter sale of our Southern facility which produced 85 MMBtu in 2024. Our Rumpke facility produced 218 MMBtu more in 2025 compared to 2024 as a result of increased volumes of feedstock gas. Our McCarty facility produced 76 MMBtu less in 2025 compared to 2024. The decrease is related to the landfill host wellfield bifurcation and changes to the wellfield collection system. Revenues from the Renewable Natural Gas segment in 2025 were $155,736, a decrease of $2,247 (1.4%) compared to $157,983 in 2024. Average commodity pricing for natural gas for 2025 was 51.1% higher than the prior year. During 2025, we self-marketed 44,132 RINs, representing an 7,493 increase (20.5%) compared to 36,639 in 2024. The increase 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 2025 was $2.33 as compared to $3.28 in 2024, a decrease of 29.0%. This compares to the average D3 RIN index price for 2025 of $2.34 being approximately 25.0% lower than the average D3 RIN index price in 2024 of $3.12. At December 31, 2025, we had approximately 354 MMBtu available for RIN generation, 190 RINs generated and unseparated, and no RINs generated and unsold. At December 31, 2024,we had approximately 291 MMBtus available for RIN generation and had approximately 6,822 RINs generated and unsold. We have entered into commitments and transferred all of our RINs related to our 2025 RNG production. Renewable Electricity Generation Revenues We produced 177 MWh in Renewable Electricity in 2025, a decrease of approximately 9 MWh (4.8%) compared to 186 MWh in 2024. Our Security facility produced 6 MWh less in 2025 compared to 2024 as a result of us ceasing operations in connection with the 2024 sale of the gas rights back to the landfill host. Our Bowerman facility produced approximately 2 fewer MWh in 2025 compared to 2024 primarily related to the planned preventative engine maintenance that was completed in 2025. Revenues from Renewable Electricity facilities in 2025 were $17,231, a decrease of $522 (2.9%) compared to $17,753 in 2024. The decrease is primarily driven by the decrease in our Security facility production volumes. -46- Table of Contents General and Administrative Revenues We recorded approximately $3,415 in Environmental Attribute revenues from RINs distributed from GreenWave. We sold approximately 1,483 RINs distributed from GreenWave, which are not included within our operating metrics table. As a result of the services performed by GreenWave, we recorded income from GreenWave of $1,485. Expenses for the Years Ended December 31, 2025 and 2024 General and Administrative Expenses Total general and administrative expenses were $31,736 in 2025, a decrease of $4,550 (12.5%) compared to $36,286 in 2024. Employee related costs, including stock-based compensation costs were $18,356 in 2025, a decrease of $4,743 (20.5%) compared to $23,099 in 2024. The decrease was primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee in 2024. Our corporate insurance fees decreased approximately $843 (15.4%) in 2025 compared to 2024. Renewable Natural Gas Expenses Operating and maintenance expenses for our RNG facilities in 2025 were $59,108, an increase of $5,721 (10.7%) compared to $53,387 in 2024. Our Apex facility operating and maintenance expenses increased approximately $2,258 primarily driven by increased utility expense, the timing of maintenance related to gas processing equipment, increased media change outs and disposal costs, as well as a wellfield operational enhancement program. Our Atascocita facility operating and maintenance expenses increased approximately $1,450 primarily driven by gas processing equipment maintenance, a wellfield operational enhancement program, media change outs, and utility expense. Our Rumpke facility operating and maintenance expenses increased approximately $1,348 as a result of a wellfield operational enhancement program and increased utility expense. Our Raeger facility operating and maintenance expenses increased approximately $917 as a result of a wellfield operational enhancement program and increased media change outs and disposal costs. We recorded approximately $3,428 in environmental attribute expense 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 2024. Royalties, transportation, gathering and production fuel expenses for our RNG facilities in 2025 were $30,986, an increase of $1,457 (4.9%) compared to $29,529 in 2024. Our Pico facility earnout expense increased approximately 22.6% during 2025 compared to 2024. We settled the Pico earnout obligation in 2025 resulting in a payment of $4,176. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 19.9% for 2025 from 18.7% in 2024. Renewable Electricity Expenses Operating and maintenance expenses for our Renewable Electricity facilities in 2025 were $14,711, an increase of $1,951 (15.3%) compared to $12,760 in 2024. The primary driver of the increase was operating and maintenance expenses at our Montauk Ag Renewables project which increased approximately $1,708 as a result of non-capitalizable costs. Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2025 were $1,959, a decrease of $14 (0.7%) compared to $1,973 in 2024, and as a percentage of Renewable Electricity Generation segment revenues increased from 11.1% for 2024 to 11.4% for 2025. Royalty Payments Royalties, transportation, gathering, and production fuel expenses in 2025 were $32,945, an increase of $1,443 (4.6%) compared to $31,502 in 2024. 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 2025 was $29,972, an increase of $6,457 (27.5%) compared to $23,515 in 2024. The increase was primarily driven by the timing of wellfield and maintenance capital investments and our Second Apex RNG Facility project being placed into service. -47- Table of Contents Impairment loss We calculated and recorded impairment losses of $3,231 for 2025, an increase of $1,645 (103.7%) compared to $1,586 for 2024. The impairment losses in 2025 primarily relate to an RNG development project for which the local utility is no longer accepting RNG into its distribution system. 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. Other Expenses Other expenses in 2025 were $3,339, a decrease of $607 (15.4%) compared to $3,946 in 2024. The primary driver of the decrease is decreased interest expense of $461. In 2025, we recorded $1,485 in income related to our joint venture investment in GreenWave. In 2024, we recorded proceeds of $1,000 from the sale of gas rights ahead of the fuel supply agreement expiration of our Security facility. Income Tax (Benefit) Expense As of December 31, 2025 and 2024, we utilized all of our non-limited NOLs. A wholly-owned subsidiary continues to carry from 2024 to 2025 approximately $12,986 of federal net operating losses that are not expected to be realizable due to loss limitation rules. As of December 31, 2025 and 2024, we had approximately $17,339 and $12,274, 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 2025, we have no remaining state NOL’s. Additionally, we have created a federal net operating loss of $407 in 2025. For the year ended December 31, 2025, we had an income tax benefit of $4,235 and for the year ended December 31 2024, we had income tax expense of $2,443. The 2025 effective tax rate was 170.3% and the 2024 effective tax rate was 20.1%. Operating Profit (Loss) for the Years Ended December 31, 2025 and 2024 Operating profit in 2025 was $852, a decrease of $15,271 (94.7%) compared to $16,123 in 2024. RNG operating profit for 2025 was $38,173, a decrease of $17,859 (31.9%) compared to $56,032 in 2024. Renewable Electricity Generation operating loss for 2025 was $4,870, an increase of $2,047 (72.5%) compared to $2,823 in 2024. 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. -48- Table of Contents 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, 2025 2024 Net income $ 1,748 $ 9,734 Depreciation, depletion and amortization 29,972 23,515 Interest expense 4,816 5,277 Income tax (benefit) expense (4,235 ) 2,443 Consolidated EBITDA 32,301 40,969 Impairment loss (1) 3,231 1,586 Net loss on sale of assets 36 — Transaction costs — 61 Adjusted EBITDA $ 35,568 $ 42,616 (1) For the year ended December 31, 2025, we recorded impairments of $3,231 for costs related to a development project RNG interconnection for which the local utility is no longer accepting RNG into its distribution system, identified assets deemed obsolete or non-operable. 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. Liquidity and Capital Resources Sources of Liquidity At December 31, 2025 and 2024, our cash and cash equivalents, net of restricted cash, was $23,752 and $45,621, respectively. We believe our credit refinancing with will afford us increased flexibility with securing project based additional financing for our in progress development projects. 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, 2025, we had debt before debt issuance costs of $129,000, compared to debt before debt issuance costs of $56,000 at December 31, 2024. Our debt before issuance costs (in thousands) is as follows: December 31, 2025 December 31, 2024 Term loan $ 44,000 56,000 Revolving credit facility 85,000 — Debt before debt issuance costs $ 129,000 $ 56,000 Amended Credit Agreement On December 31, 2025, we entered into the Sixth 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. 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 and in certain circumstances. -49- Table of Contents Under the Amended Credit Agreement, we are required to maintain the following: • a Total Net Leverage Ratio (as defined in the Amended Credit Agreement) of not more than 3.50 to 1.00 as of the end December 31, 2025; stepping down to 3.00 to 1.00 on March 31, 2026 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. • requires that MEH provide additional financial information and analysis to the lenders within fifteen business days of the end of each month As of December 31, 2025, $44,000 was outstanding under the term loan and we had $85,000 of outstanding borrowings under the revolving credit facility. The term loan amortizes in quarterly installments of $3,000 quarterly through 2026 with a final payment of $32,000, on December 21, 2026. Interest rates were 6.44% and 6.01% at December 31, 2025 and 2024, 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 December 31, 2025. 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. As of December 31, 2025, we were in compliance with all financial covenants related to the Amended Credit Agreement. New Senior Credit Facility On March 9, 2026, we entered into a new five year senior credit facility ("New Senior Credit Facility") with CCH1 MEH Lender LLC (a wholly owned subsidiary of Hannon Armstong Capital LLC) ("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. Under the New Senior Credit Facility, we are required to maintain the following, which became applicable upon entry into the new facility on March 9, 2026: • 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 March 9, 2026, $155,000 was outstanding under the New Senior Credit Facility. For additional information regarding the Amended Credit Agreement and the New Senior Credit Facility, see 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 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. The increase in 2026 non-development capital expenditures relate to original equipment manufacturer required lifecycle expenditures on our engines at our Bowerman facility. We expect this process to continue through 2027. Additionally, we currently estimate that our existing 2026 development capital expenditures will range between $100,000 and $150,000. The majority of our 2026 development capital expenditures relate to our ongoing development of Montauk Ag Renewables, Bowerman RNG project, Rumpke RNG Relocation Project, and our EENA CO2 project. Our focus is on achieving COD for the Montauk Ag Renewables project which we expect to be funded by the undrawn $200,000 Senior Secured Credit Facility with HASI. We believe our credit refinancing with HASI will afford us increased flexibility with securing project based additional financing for our in progress development projects. We believe that our existing cash and cash -50- Table of Contents equivalents, cash generated from operations, and credit availability under our Senior Credit Facility will meet our 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 years ended December 31, 2025 and 2024: For the year ended December 31, 2025 2024 Net cash provided by (used in): Operating activities $ 30,334 $ 43,795 Investing activities (120,487 ) (62,191 ) Financing activities 68,339 (9,842 ) Net decrease in cash and cash equivalents (21,814 ) (28,238 ) Restricted cash, end of the period 438 383 Cash and cash equivalents, end of period 24,190 46,004 For the year ended December 31, 2025, we generated $30,334 of cash from operating activities, a 30.7% decrease compared to $43,795 for the year ended December 31, 2024. For the year ended December 31, 2025, income and adjustments to income from operating activities provided $37,348 compared to $44,961 in 2024. Working capital and other assets and liabilities used $7,014 in 2025 compared to $1,166 in 2024. Our net cash flows used in investing activities has historically focused on project development and facility maintenance. For 2025, our capital expenditures were $116,542, of which $80,978, $8,726, and $7,735, were related to the ongoing development of the Montauk Ag Renewables, Rumpke RNG relocation project, and second Apex RNG facility, respectively. 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. Our net cash flows in financing activities provided $68,339 for 2025 increased by $78,181 compared to cash used in financing activities of $9,842 in 2024. We had $105,000 in increased borrowings on our revolver in 2025 as compared to none in 2024. Offsetting this amount of cash were increased repayments of $24,000 on our debt in 2025 as compared to 2024. 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 principal balance and accrued interest was 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 -51- Table of Contents 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. 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 2025, we had $2,571 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 2024, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $2,185. 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 2-18 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,746.