MNTK US Equity☆

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. The historical consolidated financial data discussed below reflects the historical results of operations and financial position of Montauk USA, prior to the Equity Exchange on January 4, 2021. Following the Equity Exchange on January 4, 2021, the consolidated financial statements of Montauk USA became our historical financial statements for the periods prior to the Equity Exchange.

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, 2023 compared to the year ended December 31, 2022. For discussion and analysis of our results for the year ended December 31, 2022 compared to the year ended December 31, 2021, 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 16, 2023.

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 operating portfolio of 12 RNG and three Renewable Electricity projects through self-development, partnerships, and acquisitions that span six states.

Biogas is produced by microbes as they break down organic matter in the absence of oxygen (during a process called anaerobic digestion). Our two current sources of commercial scale biogas are LFG and ADG, which is produced inside an airtight tank used to breakdown organic matter, such as livestock waste. We typically secure our biogas feedstock through long-term fuel supply agreements and property lease agreements with biogas site hosts. Once we secure long-term fuel supply rights, we design, build, own, and operate facilities that convert the biogas into RNG or use the processed biogas to produce Renewable Electricity. We sell the RNG and Renewable Electricity through a variety of short-, medium-, and long-term agreements. Because we are capturing waste methane and making use of a renewable source of energy, our RNG and Renewable Electricity generate valuable Environmental Attributes, which we are able to monetize under federal and state initiatives.

Recent Developments

Capital Development Summary

The following summarizes our ongoing development growth plans expected capacity contribution, anticipated commencement of operations, and capital expenditure estimate, respectively, excluding Montauk Ag Renewables Development project:

Pico Digestion Capacity Increase 300 2024 second quarter Up to $20,000

European Energy Facility N/A 2027 Up to $15,000/facility

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 determined not to transfer a significant amount of D3 RINs generated and available for transfer during the first quarter of 2024. As a result, we have approximately 2,887 RINs in inventory from 2023 gas production and have approximately 7,250 RINs in inventory from 2024 gas production as of the filing of this Report. We have not entered into commitments to transfer these RINs in inventory nor have we entered into agreements to transfer future RINs generated from forecasted future production. The average D3 RIN index price for the fourth quarter of 2023 and January 2024 and through the end of February 2024 was approximately $3.30 and $3.06, respectively.

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Carbon Dioxide Beneficial Use Opportunity

In February 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. With targeting a commissioning start in 2027, we expect the capital investment to be approximately $15,000 per facility with anticipating spend beginning second half of 2024.

REG Facility Sale

In February 2024, we reached an agreement with the site host to sell the gas rights ahead of the fuel supply expiration of one of our existing REG operating facilities. We received proceeds of $1,000 and no longer have obligations to decommission or remove any machinery or equipment at the site. The proceeds received were in excess of the carrying value of the site. The PPA at this site expires during 2024 at which time we estimated that the revenues from this site would significantly decrease adversely impacting this sites future cash flows from operations. The effective date of the sale is October 1, 2024. In connection with the sale, we secured fuel supply agreement amendments to extend the terms of our existing RNG operating facilities, Atascocita and Coastal Plains.

Montauk Ag Asset Acquisition

In 2021, through a wholly-owned subsidiary Montauk Ag Renewables, we completed an asset purchase related to developing technology to recover residual natural resources from the waste streams of modern agriculture and to refine and recycle such waste products through proprietary and other processes in order to produce high quality renewable natural gas and recapture nitrogen, phosphorus, and micronutrient organic fertilizer alternatives (the “Montauk Ag Renewables Acquisition”).

While these project developments continue, we continue to engage with regulatory agencies in North Carolina related to the resulting power generation derived from swine waste to confirm its eligibility for Renewable Energy Credits under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production. The Turkey location was approved to participate in the Piedmont Natural Gas Renewable Gas Pilot Program which is a step towards obtaining the New Renewable Energy Facility (“NREF”) designation under the North Carolina Utilities Commission. In January 2024, we received notification from the North Carolina Utilities Commission that the Turkey, NC location was approved for an NREF and Certificate of Public Convenience and Necessity. In March 2024, we submitted an amendment to our NREF application for which we expect a decision on the NREF designation during 2024. Obtaining this designation could have an impact on the timing of utility infrastructure at the location. We signed a receipt interconnection agreement with Piedmont Natural Gas for the Turkey, NC location. This agreement is structured to coincide with the development timeline at the Turkey, NC location.

In connection with the July 2023 REC agreement with Duke Energy (“Duke”), our Board of Directors approved funding for the first phase of the North Carolina development project in September 2023. Once construction has been completed on the first phase and the facility has been fully commissioned, the project will provide sufficient capacity to satisfy the Duke REC agreement through the deployment of up to eight operational processing lines at the Turkey Creek facility. Including the original equipment acquired in the Montauk Ag Renewables Acquisition, the Turkey, NC asset acquisition, and the relocation of the Magnolia, NC site reactor to Turkey, NC, we currently expect the first phase capital investment to range between $140,000 and $160,000.

We continue to expect to have the first of the eight processing lines operational in the second quarter of 2024 and, we are currently planning for a rolling commissioning schedule for the remaining processing lines beginning in the second half of 2024 through the second half of 2025. We continue to expect to begin generating revenues in 2025 and expect to have sufficient capacity to satisfy the Duke REC agreement upon final commissioning during the second half of 2025. At full first phase capacity, we anticipate the ability to process feedstock from over 120 thousand hog spaces per day, which equates to over 200 tons of daily waste collection. We currently estimate the first phase of the project will annually produce approximately 45 to 50 thousand MWh equivalents through the combination of 190 to 200 thousand MMBtu and 25 to 30 thousand MWh. We also estimate that at full processing capabilities, the first phase of the project will additionally produce annually 17 to 20 thousand tons of organic fertilizer alternatives.

We continue to work with our engineer of record through the optimization of improvements to the now patented reactor technology. However, we have not completed our improvements, and we have not reached commercial operations at the Turkey, NC location. The improvements to the reactor technology are intended to be deployed at the Turkey, NC location. In 2023, we completed the relocation of the reactor in Magnolia, NC to the Turkey, NC location to centralize processing at one location. And as part of the centralization and in connection with the optimization of the reactor, we assessed various assets of the Magnolia, NC reactor as no longer being applicable to the improved reactor process. As a result, we recorded an impairment charge of approximately $1,393 in 2022 related to assets originally acquired in the May 2021 Montauk Ag Renewables Acquisition we determined were no longer usable.

We continue to develop the opportunities with Montauk Ag Renewables and can give no assurances that our plans related to this acquisition will meet our expectations. Utility interconnection, both inbound to and outbound from our centralized Turkey, NC processing facility is dependent on factors outside of our control. Our current construction timeline and costs are subject to delays or costs increases, respectively. We continue to design and plan for the development of the Turkey, NC facility to be used for

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commercial production. We expect the Magnolia, NC location to be used for various feedstock processing needs. Based on our current development timeline expectations, we expect to commence significant revenue generating activities in 2025. We intend to contract with additional farms to secure feedstock sources for future production processes.

Pico Digestion Capacity Increase

Related to our Pico feedstock amendment, which increased the amount of feedstock supplied to the facility for processing over a one to four-year period (the “Pico Feedstock Amendment”), the dairy began delivering the first and second increases in feedstock in 2022 and we made three payments to the dairy as required in the Pico Feedstock Agreement. The improved efficiencies of our existing digestion process and the water management improvements have enabled us to process the increased feedstock volumes which we currently expect to increase by five to ten percent once all increased feedstock deliveries have been received from the dairy. Our dairy host informed us that they expect to deliver the final increase in feedstock volumes in 2025, at which point we will make the final contractual payment to the dairy.

In 2023, CARB finalized the engineering review of the Pico facility's provisional CI application and released it for public comment. The public comment period ended March 14, 2023 and we did not receive any significant comments. CARB certified our Tier 2 application and the certified CI value was used beginning in the fourth quarter of 2022 to report and generate LCFS credits. We released the remaining gas from storage in the second quarter of 2023.

We completed the design of the digestion capacity project in 2022 and continue to incur capital expenditures related to the final commissioning phase of the project. During 2023, we successfully commissioned additional digestion capacity and our new reception pit, both of which are currently operational. We have begun utilizing the increased reception pit capacity and have been working to increase feedstock gas availability through the additional digestion capacity. We continue to commission the last expansion of our digestion capacity increase during the second quarter of 2024 and currently expect to ramp up production into the third quarter of 2024.

Second Apex RNG Facility

In 2022, we announced the planned construction of a second RNG processing facility at the Apex landfill. Currently, the landfill host is providing biogas feedstock in excess of our existing processing capacity, therefore triggering the addition of a second facility based on our existing fuel supply agreement. As the landfill host continues to increase waste intake, we believe that the additional 2,100 MMBtu per day of production capacity will allow us to process the currently forecasted increase in biogas feedstock volumes from this increase in waste intake. While the landfill host continues to increase waste intake, we expect there could be a period where we have excess available capacity after the second facility is commissioned. We currently expect commercial operations in the fourth quarter of 2024. We continue to incur capital expenditures for this project.

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. The project is anticipated to process the large and growing volumes of biogas in excess of the existing capacity of the REG facility. With target commissioning in 2026, we continue to expect the capital investment to range between $85,000 - $95,000, which is anticipated to have production nameplate capacity of approximately 3,600 MMBtu per day, assuming currently forecasted biogas feedstock volumes that are projected to be available from the host landfill at the time of commissioning.

Blue Granite RNG Project

In 2023, we announced the planned entrance into South Carolina with the development of a new landfill gas-to-RNG facility. The planned project is expected to contribute approximately 900 MMBtu per day of production capacity upon commissioning. We continue to design and plan for the development and location of the facility as we continue to incur capital expenditures. 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. We expect the utility interconnection initially included in our development assumptions to accept the production from this facility, but will require other upgrades not impacting our interconnection. However, these upgrades have delayed our expectation of commissioning of the facility into 2026.

Raeger Capital Improvement

In 2022, our Board of Directors approved a capital improvement project to make upgrades to our Raeger facility to production. Construction on this capital project commenced in 2022 and the improvements became commercially operational during the second half of 2023.

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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:

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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).

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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.

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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.

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Regulatory requirements, market pressure and public relations challenges increase the time, cost and difficulty of permitting new fossil fuel-fired facilities.

Factors Affecting Our Future Operating Results:

Conversion of Electricity Projects to RNG Projects:

We periodically evaluate opportunities to convert existing facilities from Renewable Electricity to RNG production. These opportunities tend to be most attractive for any merchant electricity facilities given the favorable economics for the sale of RNG plus RINs relative to the sale of market rate electricity plus RECs. This strategy has been an increasingly attractive avenue for growth since 2014 when RNG from landfills became eligible for D3 RINs. However, during the conversion of a project, there is a gap in production while the electricity project is offline until it commences operation as an RNG facility, which can adversely affect us. This timing effect may adversely affect our operating results as a result of our potential conversion of Renewable Electricity projects. Upon completion of a conversion, we expect that the increase in revenue upon commencement of RNG production will more than offset the loss of revenue from Renewable Electricity production. Historically, we have taken advantage of these opportunities on a gradual basis at our merchant electricity facilities, such as Atascocita and Coastal Plains.

Acquisition and Development Pipeline

The timing and extent of our development pipeline affects our operating results due to:

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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. Further, the receipt of RINs is delayed, and typically does not commence for a period of four to six months after the commencement of injecting RNG into a pipeline, pending final registration approval of the project by the EPA and then the subsequent completion of a third-party quality assurance plan certification. During such time, the RNG is either physically or theoretically stored and later withdrawn from storage to allow for the generation of RINs.

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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.

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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.

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Regulatory, Environmental and Social Trends

Regulatory, environmental and social factors are key drivers that incentivize the development of RNG and Renewable Electricity projects and influence the economics of these projects. We are subject to the possibility of legislative and regulatory changes to certain incentives, such as RINs, RECs and GHG initiatives. On July 12, 2023, the EPA issued final rules in the Federal Register for the RFS volume requirements for 2023-2025. Final volumes for cellulosic biofuel were set at 838, 1,090 and 1,376 million RINs for the three years 2023, 2024 and 2025, respectively. The EPA did not finalize the eRIN program in this ruling, however, it indicated that it will continue to work on potential paths forward for the eRIN program. However, the EPA did not set a new date for a revised eRIN program. The cellulosic biofuel volumes in the final rule for 2024 and 2025 are lower than the proposed volume as they do not include cellulosic biofuel from eRINs. The final rule also included significant changes to the existing RFS program, referred to as biogas regulatory reform, that will require the RNG industry to modify how all RINs are generated. New RFS participating facilities that register July 1, 2024, or after will have to meet the biogas regulatory reform provisions beginning July 1, 2024. Existing RFS participating facilities which registered prior to July 1, 2024, will have until January 1, 2025, to come into compliance with biogas regulatory reforms. For existing registrants, registration updates must be submitted by October 1, 2024. On January 1, 2025, all RFS participants must comply with biogas regulatory reform provisions. The EPA finalized a limitation that biogas from one facility has a single use under the RFS as proposed (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.

In December 2023, CARB released the formal proposal for new LCFS rules. The proposed rules will increase the stringency of CI reduction targets from 20% to 30% in 2030 and create a 2045 target of 90%. This reduction would have the potential impact of reducing the number of net credits in the program. However, the industry may see pricing volatility including potential increase to LCFS credit prices. Also in the proposed rules is a phase out of avoided methane crediting for dairy and swine manure pathways by 2040 for CNG usage and through 2045 for RNG used to produce hydrogen. The RNG deliverability/book and claim provisions for out-of-region projects will be eliminated for all projects that break ground after 2030. These projects will be required to demonstrate physical deliverability requirements beginning in 2041.

Changes to the LCFS program require annual verification of the CI score assigned to a project. Annual verification could significantly affect the profitability of a project, particularly in the case of a livestock farm project.

Factors Affecting Revenue

Our total operating revenues include renewable energy and related sales of Environmental Attributes. Renewable energy sales primarily consist of the sale of biogas, including LFG and ADG, which is either sold or converted to Renewable Electricity. Environmental Attributes are generated and monetized from the renewable energy.

We report revenues from two operating segments: Renewable Natural Gas and Renewable Electricity Generation. Corporate relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering, and other operations functions not otherwise allocated to a segment. As such, the corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.

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Renewable Natural Gas Revenues: We record revenues from the production and sale of RNG and the generation and sale of the EnvironmentalAttributes 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 have certain pathway provider sharing arrangements expiring throughout 2024. If we are unable to renew these arrangements based on our historical counterparty share percentages, our ability to monetize RINs from RNG may be impacted. We monetize a portion of our RNG production under fixed-price agreements which provide floor prices in excess of commodity indices.

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Renewable Electricity Generation Revenues: We record revenues from the production and sale of Renewable Electricity and the generation andsale 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.

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Corporate Revenues: Corporate reports realized and unrealized gains or losses under our gas hedge programs. Corporate also relates to additionaldiscrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment.

Our operating revenues are priced based on published index prices which can be influenced by factors outside our control, such as market impacts on commodity pricing and regulatory developments. Strategic decisions to not monetize RINs available to be transferred will have an impact on our operating revenues and operating profit. 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. With our royalty payments structured as a percentage of revenue, royalty

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payments fluctuate with changes in revenues. Due to these factors, 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 ofour 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.

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Many of our operating locations are in areas that experienced lower than historical rainfall, higher than average temperatures, or both, during the second half of 2023. This had a negative impact on our production and ability to generate and sell RINs.

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Though we collaborate with the landfill host at our Rumpke facility on our gas collection efforts, in addition to drought weather anomalies, other wellfield extraction environmental factors have impacted gas extraction at the site. While the site continues to expand their waste intake and we continue to expand wellfield collection, our volumes could be impacted throughout 2024. Mitigation efforts related to wellfield environmental factors will continue into 2024.

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The landfill host at our McCarty facility recently changed its wellfield collection system which has contributed to elevated nitrogen in the feedstock received by our facility. Additionally, the landfill host modified the wellfield bifurcation approach which has impacted the quantity of feedstock received at the facility. We are working with the landfill host but have currently experienced lower volumes of feedstock available to be processed at the McCarty facility.

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Our processing of increased Pico feedstock during first half of 2024 may be impacted while we expand the receiving capacity associated with the Pico digestion capacity increase.

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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 projectsites is subject to change based on the volume and type of waste accepted. Variations in the quality of the biogas could affect our RNG production levels. At three of our projects, we operate the wellfield collection system, which allows greater control over the quality and consistency of the collected biogas. At two of our projects, 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.

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RNG Production from Our Growth Projects: We anticipate increased production at certain of our existing projects as open landfills continue totake in additional waste and the amount of gas available for collection increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project would delay any realization of production from that project.

Pricing

Our Renewable Natural Gas and Renewable Electricity Generation segments’ revenues are primarily driven by the prices under our off-take agreements and PPAs and the amount of RNG and Renewable Electricity that we produce. We sell the RNG produced from our projects under a variety of short-term and medium-term agreements to counterparties, with contract terms varying from three years to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. All of the Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price arrangement with escalators.

The pricing of Environmental Attributes, which accounts for a substantial portion of our revenues, is subject to volatility based on a variety of factors, including regulatory and administrative actions and commodity pricing.

During the first quarter of 2023, our Pico dairy farm project was awarded a more attractive CI by CARB, thereby generating LCFS credits at a multiple of those generated by our landfill projects.

The sale of RINs, which is subject to market price fluctuations, accounts for a substantial portion of our revenues. We manage against the risk of these fluctuations through forward sales of RINs, although currently we only sell RINs in the calendar year they are generated. We have not entered into commitments to transfer significant RINs generated from 2024 production. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

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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.

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Project 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.

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Royalties, Transportation, Gathering and Production Fuel Expenses: Royalties represent payments made to our facility hosts, typically structuredas 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.

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General and Administrative Expenses: General and administrative expenses primarily consist of corporate expenses and unallocated supportfunctions 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 expect increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2024. We also expect increased general and administrative expenses associated with share-based compensation related to the board of directors approval of grants of stock options to the executives of the Company in April 2023. The Company accounts for stock-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 15 to our audited consolidated financial statements.

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Depreciation and Amortization: Expenses related to the recognition of the useful lives of our intangible and fixed assets. We spend significantcapital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.

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Impairment Loss: Expenses related to reductions in the carrying value(s) of fixed and/or intangible assets based on periodic evaluations wheneverevents or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

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Transaction Costs: Transaction costs primarily consist of expenses incurred for due diligence and other activities related to potential acquisitionsand 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:

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Production Volumes: We review performance by site based on unit of production calculations for RNG and Renewable Electricity, measured interms 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.

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Production of Environmental Attributes: We monetize Environmental Attributes derived from our production of RNG and Renewable Electricity.We carry-over a portion of the RINs generated from RNG production to the following year and monetize the carried over RINs in such following calendar year. A majority of our Renewable Natural Gas segment Environmental Attributes are self-monetized, though a portion are generated and monetized by third parties under counterparty sharing agreements. A majority of our Renewable Electricity Generation segment Environmental Attributes are monetized as a component of our fixed-price PPAs.

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Average realized price per unit of production: Our profitability is highly dependent on the commodity prices for natural gas and electricity, and theEnvironmental Attribute prices for RINs, LCFS credits, and RECs. Realized prices for

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Environmental Attributes monetized in a year may not correspond directly with that year’s production as attributes may be carried over and subsequently monetized. We may elect to not commit to transfer all available RINs in a given period which could impact our revenue and operating profit. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

Comparison of Years Ended December 31, 2023 and 2022

The following table summarizes the key operating metrics described above, which metrics we use to measure performance.

For the year endedDecember 31, Change

(in thousands, unless otherwise indicated)

Revenues

RNG Metrics

Plus: Prior period RNG volumes dispensed in current period 368 372 (4 ) (1.1 %)

Total RNG volumes available for RIN generation (1) 4,222 4,238 (16 ) (0.4 %)

RIN Metrics

Plus: Prior period RINs carried into current period 739 140 599 427.9 %

Less: CY RINs carried into next CY (108 ) (739 ) 631 (85.4 %)

RIN Inventory — — — 0.0 %

RNG Inventory (volumes not dispensed for RINs) (4) 358 368 (10 ) (2.7 %)

Operating Expenses

Operating Expenses per MMBtu (actual) $ 14.69 $ 15.59 $ (0.90 ) (5.8 %)

Other Metrics

Renewable Electricity Generation Volumes Produced (MWh) 194 190 4 2.1 %

Average Realized Price $/MWh (actual) $ 95.10 $ 90.37 $ 4.73 5.2 %

(1)

RINs are generated the month following the month gas is produced and dispensed. Volumes under fixed/floor arrangements generate RINs which we do not self-market.

(2)

One MMBtu of RNG has the same energy content as 11.727 gallons of ethanol, and thus may generate 11.727 RINs under the RFS program.

(3)

Represents RINs available to be self-marketed by us during the reporting period.

(4)

Represents gas production on which RINs are not generated.

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Results of Operations

Comparison of Years Ended December 31, 2023 and 2022

The following table summarizes our revenues, expenses and net income for the periods set forth below:

For the year endedDecember 31, Change

Operating expenses:

Revenues for the Years Ended December 31, 2023 and 2022

Total revenues in 2023 were $174,904, a decrease of $30,655 (14.9%) compared to $205,559 in 2022. The primary driver for this decrease relates to the average realized RIN price decrease of approximately 16.6% in 2023 of $2.71 compared to $3.25 in 2022. Also contributing to this decrease was the natural gas index price decrease of approximately 58.7% during 2023 of $2.74 compared to $6.64 in 2022.

Renewable Natural Gas Revenues

We produced 5,499 MMBtu of RNG during 2023, a decrease of 23 MMBtu (0.4%) from the 5,522 MMBtus produced in 2022. Reduced preventative maintenance and wellfield optimization led to increased production, notably with our Atascocita facility producing 84 MMBtu more in 2023 compared to 2022. Offsetting these improvements were unrelated wellfield quality issues and weather anomalies which lowered production, led by our Rumpke facility producing 95 fewer MMBtu in 2023 compared to 2022.

Revenues from the Renewable Natural Gas segment in 2023 were $156,455, a decrease of $39,763 (20.3%) compared to $196,218 in 2022. Average commodity pricing for natural gas for 2023 was 58.7% lower than the prior year. During 2023, we self-marketed 44,936 RINs, representing a 1,113 increase (2.5%) compared to 43,823 in 2022. The increase was primarily related to the prior period RIN volumes carried over into 2023 compared to 2022. Average pricing realized on RIN sales during 2023 was $2.71 as compared to $3.25 in 2022, a decrease of 16.6%. This compares to the average D3 RIN index price for 2022 of $2.63 being approximately 11.7% lower than the average D3 RIN index price in 2022 of $2.98. At December 31, 2023, we had approximately 0.4 million MMBtus available for RIN generation and had approximately 0.1 million RINs generated and unsold. We had approximately 0.4 million MMBtus available for RIN generation and approximately 0.7 million RINs generated and unsold at December 31, 2022.

Renewable Electricity Generation Revenues

We produced 194 MWh in Renewable Electricity in 2023, an increase of approximately 4 MWh (2.1%) compared to 190 MWh in 2022. Our Security facility produced 5 MWh more in 2023 compared to 2022 as a result of the prior period engine maintenance.

Revenues from Renewable Electricity facilities in 2023 were $18,449, an increase of $1,279 (7.4%) compared to $17,170 in 2022. The increase is primarily driven by the timing of generation and monetization of RECs and PPA pricing step up at our Bowerman facility.

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Corporate Analysis

While we did not have any gas commodity hedge programs in 2023, we recorded losses of $7,829 related to our gas commodity hedge in 2022, which was recorded in revenues in the 2022 consolidated statement of operations.

Expenses for the Years Ended December 31, 2023 and 2022

General and Administrative Expenses

Total general and administrative expenses were $34,403 in 2023, an increase of $264 (0.8%) compared to $34,139 in 2022. Our general and administrative expenses for 2023 increased approximately $2,106 compared to 2022 associated with Montauk Ag Renewables. The increase was primarily driven by stock-based compensation expense as a result of the 2022 amendments to restricted share awards issued in the Montauk Ag Renewables acquisition and professional fees. Partially offsetting this increase was a reversal of approximately $1,024 in stock based compensation expense related to forfeited stock awards. Our professional fees expense was $4,609 in 2023, a decrease of $657 (12.5%) compared to $5,266 in 2022. Montauk Ag Renewables professional fees for 2023 increased approximately $381 compared to 2022. Finally, our rent expense was $713 in 2023, an increase of $293 (69.6%) compared to $420 in 2022.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in 2023 were $47,886, an increase of $4,157 (9.5%) compared to $43,729 in 2022. Total RNG facility utility expense decreased approximately $2,098 in 2023 as compared to 2022. Offsetting this decrease in RNG utility were increases in our RNG site operating and maintenance expenses. Our Rumpke facility operating and maintenance expenses increased approximately $1,271 as a result of timing of preventative maintenance interval costs and previously disclosed process equipment failure repair costs. Our McCarty facility operating and maintenance expenses increased approximately $925 as a result of timing of preventative maintenance interval costs and wellfield operational enhancements. Our Atascocita facility operating and maintenance expenses increased approximately $840 as a result of timing of preventative maintenance intervals as well as wellfield operational enhancements. Our Galveston facility operating and maintenance expenses increased approximately $703 primarily driven by wellfield operational enhancements. Our Pico facility operating and maintenance expenses increased approximately $630 as a result of non-capitalizable costs associated to the Pico Digestion Capacity Increase project as well as timing of preventative maintenance interval costs. Our Apex facility operating and maintenance expenses increased approximately $487 as a result of increased waste disposal fees and wellfield operational enhancements. Our Coastal facility operating and maintenance expenses increased approximately $336 as a result of wellfield operational enhancements.

Royalties, transportation, gathering and production fuel expenses for the Company’s RNG facilities for 2023 were $32,876, a decrease of $9,463 (22.4%) compared to $42,339 in 2022. Our Pico facility earnout increased approximately 12.8% during 2023 compared to 2022 based on our current estimate of the present value of the earnout. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 21.0% for 2023 from 21.6% in 2022.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in 2023 were $11,745, a decrease of $1,341 (10.2%) compared to $13,086 in 2022. Our Bowerman facility operating and maintenance expenses decreased approximately $2,579 driven by the timing of scheduled engine preventative maintenance intervals at our Bowerman facility in 2023 compared to 2022. Offsetting the decrease was an increase in Montauk Ag Renewables operating and maintenance expenses of approximately $295. Also, our Tulsa facility operating and maintenance expenses increased approximately $532 as a result of scheduled preventative maintenance interval costs and wellfield operational maintenance

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2023 were $1,985, an increase of $161 (8.8%) compared to $1,824 in 2022 and as a percentage of Renewable Electricity Generation segment revenues increased from 10.6% to 10.8%.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in 2023 were $34,861, a decrease of 9,302 (21.1%) compared to $44,163 in 2022. 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.

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Depreciation

Depreciation and amortization in 2023 was $21,158, an increase of $458 (2.2%) compared to $20,700 in 2022. The increase is associated with the timing of capital investments placed into service in 2023.

Impairment loss

We calculated and recorded impairment losses of $902 for 2023, a decrease of $3,950 (81.4%) compared to $4,852 for 2022. In 2023, we recorded impairments of $777 for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use as well as $125 in obsolete REG critical spares. In 2022, we recorded an impairment of $2,133 for a REG site wherein the forecast future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG site was impaired for $1,393 due to discrete conclusion that certain assets acquired in the May 2021 Montauk Ag Renewables Acquisition would no longer be utilized. Also in 2022, we recorded an impairment at an RNG facility for approximately $1,108 due to the specific identification of certain assets no longer being capable of use as designed.

Other Expenses

Other expenses in 2023 were $5,274, an increase of $3,950 (298.4%) compared to $1,324 in 2022. The increase is primarily related to an increase in interest expense of $3,961 in 2023 as compared to 2022 as a result of rising interest rates.

Income Tax Expense

As of December 31, 2023, we utilized all of our limited NOLs. We have an additional $12,986 of federal net operating losses that are not expected to be realizable due to loss limitation rules. As of December 31, 2022, we had utilized all of our non-limited NOLs.

We have approximately $13,042 in federal tax credit carryforwards that expire 20 years from the date incurred, which will begin to expire in tax year 2026. We have pre-tax state net operating loss carryforwards of $18,059 which will begin to expire in tax year 2026.

For the year ended December 31, 2023 and 2022, income tax expense was $3,418 and $8,048, respectively and has been calculated resulting in an annual effective tax rate (“AETR”) of 18.61%, respectively.

Operating Profit (Loss) for the Years Ended December 31, 2023 and 2022

Operating profit in 2023 was $23,640, a decrease of $20,926 (47.0%) compared to $44,566 in 2022. RNG operating profit for 2023 was $59,286, a decrease of $35,153 (37.2%) compared to $94,439 in 2022. Renewable Electricity Generation operating loss for 2022 was $595, a decrease of $6,424 (91.5%) compared to $7,019 in 2022.

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.

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The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income:

For the year endedDecember 31,

Depreciation, depletion and amortization 21,158 20,700

Net loss (gain) on sale of assets 94 (233 )

(1)

For the year ended December 31, 2023, we recorded impairments of $777 for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use as well as $125 in obsolete REG critical spares. For the year ended December 31, 2022, we recorded an impairment of $2,133 for a REG site wherein the forecast future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG site was impaired for $1,393 due to discrete conclusion that certain assets acquired in the May 2021 Montauk Ag Renewables Acquisition would no longer be utilized. Also in 2022, we recorded an impairment at an RNG facility for approximately $1,108 due to the specific identification of certain assets no longer being capable of use as designed.

Liquidity and Capital Resources

Sources of Liquidity

At December 31, 2023 and 2022, our cash and cash equivalents, net of restricted cash, was $73,811 and $105,177, respectively. We intend to fund development projects using cash flows from operations and borrowings under our revolving credit facility. We believe that we will have sufficient cash flows from operations and borrowing availability under our credit facility to meet our debt service obligations and anticipated required capital expenditures (including for projects under development) for the next 12 to 24 months. However, we are subject to business and operational risks that could adversely affect our cash flows and liquidity.

At December 31, 2023, we had debt before debt issuance costs of $64,000, compared to debt before debt issuance costs of $72,000 at December 31, 2022.

Our debt before issuance costs (in thousands) is as follows:

Revolving credit facility — —

Amended Credit Agreement

On December 21, 2021, the Company entered into the Fourth Amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement (the “Amended Credit Agreement”), with Comerica Bank (“Comerica”) and certain other financial institutions. The Amended Credit Agreement, which is secured by substantially all of our assets and assets of certain of our subsidiaries, provides for a five-year $80,000 term loan and a five-year $120,000 revolving credit facility.

As of December 31, 2023, $64,000 was outstanding under the term loan and we had no outstanding borrowings under the revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through December 2024, quarterly installments of $3,000 from 2025 through the maturity, with a final payment of $32,000, on December 21, 2026. Interest rates were 6.11% and 4.12% at December 31, 2023 and 2022, respectively. The revolving and term loans under the Amended Credit Agreement bear 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).

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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 $6.0 million. 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, (e) any extraordinary, unusual, or non-recurring cash expenses and/or losses not exceeding $500,000 in the aggregate to the extent not included in the determination of operating income on MEH’s consolidated statements of profits and loss, (f) subject to Comerica’s approval, which may be granted or withheld in its reasonable credit judgment, any extraordinary, unusual, or non-recurring cash expenses or losses to the extent not included in the determination of operating income on MEH’s consolidated statements of profits and losses exceeding $500,000 in the aggregate, (g) any extraordinary, unusual, or non-recurring non-cash expenses and/or losses not included in the determination of operating income on MEH’s consolidated statements of profits and loss, and (h) any extraordinary, unusual, or non-recurring non-cash expenses and/or losses included in the determination of operating income on MEH’s consolidated statements of profits and loss, plus, to the extent not included in the calculation of net income, the amount of dividends and distributions paid by the Excluded Entities (as defined in the Amended Credit Agreement) to MEH during such period minus the sum of (j) any non-cash unrealized derivative income during such period, (k) any extraordinary, unusual or non-recurring cash or non-cash income and/or gains not included in the determination of operating income on MEH’s consolidated statements of profits and loss, (l) any extraordinary, unusual, or non-recurring non-cash income and/or gains included in the determination of operating income on MEH’s consolidated statements of profits and loss, all as determined on a consolidated basis for MEH and its subsidiaries (excluding the Excluded Entities except where an Excluded Entity is specifically included in the calculation) in accordance with GAAP.

Under the Amended Credit Agreement, we are required to maintain the following ratios:

•

a Total Leverage Ratio (as defined in the Amended Credit Agreement) of not more than 3.25 to 1.00 as of the end of any fiscal quarter from June 30, 2023 through June 29, 2024, and 3.00 to 1.00 as of the end of any fiscal quarter from June 30, 2024 and thereafter.; and

•

as of the end of each fiscal quarter, a Fixed Charge Coverage Ratio (as defined in the Amended Credit Agreement) of not less than 1.2 to 1.0.

As of December 31, 2023, we were in compliance with all financial covenants related to the Amended Credit Agreement.

The Amended Credit Agreement replaced our prior credit agreements with Comerica Bank and a portion of the proceeds of the term loan made under the Amended Credit Agreement were used by us to, among other things, fully satisfy an aggregate of $59,197 outstanding principal under such credit agreements. For additional information regarding the Amended Credit Agreement, see the sections entitled “Description of Indebtedness" and Note 13 to our audited consolidated financial statements.

Capital Expenditures

We have historically funded our growth and capital expenditures with our working capital, cash flow from operations and debt financing. We expect our non-development 2024 capital expenditures to range between $14,000 and $17,000. Our 2024 capital plans include preventative maintenance expenditures, wellfield expansion projects, critical spare expenditures, and other specific facility improvements. Additionally, we currently estimate that our existing 2024 development capital expenditures will range between $135,000 and $150,000. The majority of our 2024 development capital expenditures are related to our ongoing development of Montauk Ag Renewables, the second Apex facility, the Blue Granite RNG project Bowerman RNG project, and our EENA CO2 project. Our Amended Credit Agreement provides us with a $120,000 revolving credit facility, with a $75,000 accordion option, providing us with access to additional capital to implement our acquisition and development strategy. We are currently in various stages of discussions regarding a variety of development and strategic growth opportunities. Development opportunities include: up to five LFG RNG sites, waste water treatment RNG, and CNG distribution opportunities. If we ultimately enter into definitive agreements for any of these opportunities, we expect to incur material capital expenditures related to either acquisitions costs or development costs, or both. As we continue to explore strategic growth opportunities and while we have entered into nonbinding letters of intent for certain of these opportunities, we provide no assurances that our plans related to any or all of these strategic opportunities will progress to definitive agreements. We believe that our existing cash and cash equivalents, cash generated from operations, and credit availability under our Amended Credit Agreement would allow us to pursue and close on our identified strategic growth opportunities.

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Cash Flow

The following table presents information regarding our cash flows and cash equivalents for years ended December 31, 2023 and 2022:

For the year ended December 31,

Net cash provided by (used in):

Net (decrease) increase in cash and cash equivalents (31,364 ) 51,993

Restricted cash, end of the period 431 429

For the year ended December 31, 2023, we generated $41,053 of cash from operating activities, a 49.4% decrease compared to $81,066 for the year ended December 31, 2022. For the year ended December 31, 2023, income and adjustments to income from operating activities provided $49,896 compared to $75,832 in 2022. Working capital and other assets and liabilities used $8,843 in 2023 compared to $5,234 being provided in 2022. When we commission new sites, we invest capital to ramp up operations prior to the project generating revenue.

Our net cash flows used in investing activities has historically focused on project development and facility maintenance. For 2023, our capital expenditures were $63,091, of which $18,593, $13,655, and $13,092, were related to the ongoing development of the Montauk Ag Renewables, Pico facility digestion capacity increase and second Apex RNG facility, respectively. For 2022, our capital expenditures were $22,277, of which $6,860 and $3,555 were related to the Pico facility digestion capacity increase and Montauk Ag Renewables in North Carolina, respectively.

Our net cash flows used in financing activities of $9,330 for 2023 increased by $1,051 compared to cash used in financing activities of $8,279 in 2022. The increase is primarily related to the Fourth Amended and Restated Loan Agreement and Secured Promissory Note amended during 2023.

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 2023, we had $2,505 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 2022, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $3,905.

We have contractual obligations involving operating leases. See Note 19 to our audited consolidated financial statements for further information related to the lease obligations.

We have other contractual obligations associated with our fuel supply agreements. The expiration of these agreements range between 3-20 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,640.

Internal Control Over Financial Reporting

There were no changes during 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Critical Accounting Policies and Estimates

Our consolidated financial statements are prepared in conformity with GAAP and require our management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, costs and expenses and related disclosures. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and such estimates may change if the underlying conditions or assumptions change.

Revenue Recognition

Our revenues are comprised of renewable energy and the related Environmental Attribute sales provided under a variety of short-term and medium-term agreements with our customers. All revenue is recognized when we satisfy our performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product to the customer either when (or as) the customer obtains control of the product. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. We allocate the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.

Revenue is measured as the amount of consideration we expect to receive in exchange for transferring our products. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred. To the extent applicable, sales, value add, and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.

The nature of our contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of our influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained. Refer to Item 7A for an estimate of the impact of decreases in the wholesale price of gas on our operating profit.

RINs

We generate D3 RINs through our production and sale of RNG used for transportation purposes as prescribed under the RFS program. Our operating costs are associated with the production of RNG. The RINs are government incentives that are generated through our renewable operating projects and not a result of physical attributes of our RNG production. The RINs that we generate are able to be separated and sold as credits independently from the energy produced. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. We enter into forward commitments to transfer RINs. These forward commitments are based on D3 RIN index prices at the time of the commitment. Realized prices for RINs monetized in a year may not correspond directly to index prices due to the forward selling of commitments. Refer to Item 7A for an estimate of the impact of decreases in the realized price per RIN on our operating profit.

RECs

We generate RECs through our production and conversion of landfill methane into Renewable Electricity in various states, including California, Oklahoma, and Texas. These states have various laws requiring utilities to purchase a portion of their energy from renewable resources. Our operating costs are associated with the production of Renewable Electricity. The RECs are generated as an output of our renewable operating projects. The RECs that we generate are able to be separated and sold independently from the electricity produced. Therefore, no cost is allocated to the REC when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred.

Income Taxes

We are subject to income taxes in the U.S. federal jurisdiction and various state and local jurisdictions. Tax regulations within each jurisdiction are subject to the interpretation of the related tax laws and regulations and require significant judgment to apply.

Our net deferred tax asset position is a result of NOLs, fixed assets, intangibles, and tax credit carryforwards. The realization of deferred tax assets is dependent upon our ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in our financial statements or tax returns and forecasting future profitability by tax jurisdiction.

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We evaluate our deferred tax assets at reporting periods on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of our deferred tax assets. We account for uncertain tax positions using a “more-likely-than-not” threshold for recognizing and resolving uncertain tax positions. The evaluation of uncertain tax positions is based on factors that include, but are not limited to, changes in tax law, the measurement of tax positions taken or expected to be taken in tax returns, the effective settlement of matters subject to audit, new audit activity and changes in facts or circumstances related to a tax position. Given our current level of pre-tax earnings and forecasted future pre-tax earnings, we expect to generate income before taxes in the United States in future periods at a level that would fully utilize our U.S. federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration. See Note 14 to our audited consolidated financial statements for additional information.

Intangible Assets

Separately identifiable intangible assets are recorded at their fair values upon acquisition. We account for intangible assets in accordance with ASC 350, Intangibles—Goodwill and Other. Finite-lived intangible assets include interconnections, customer contracts, and trade names and trademarks. The interconnection intangible asset is the exclusive right to utilize an interconnection line between the operating project and a utility substation to transmit produced electricity. Included in that right is full maintenance provided on this line by the utility. Intangible assets with finite useful lives are amortized on a straight-line basis over their estimated useful life. We evaluate our finite-lived intangible assets for impairment as events or changes in circumstances indicate the carrying value of these assets may not be fully recoverable. Events that could result in an impairment include, among others, a significant decrease in the market price or the decision to close a site.

Indefinite-lived intangible assets are not amortized and include emission allowances and land use rights. Emission allowances consist of credits that need to be applied to nitrogen oxide (“NOx”) emissions from internal combustion engines. These engines emit levels of NOx for which environmental permits are required in certain regions in the United States. Except for permanent allocations of NOx credits, allowances available for use each year are capped at a level necessary for ozone attainment per the National Ambient Air Quality Standards. We assess the impairment of intangible assets that have indefinite lives at least on an annual basis or whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable.

If finite-lived or indefinite-lived intangible assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. The fair value is determined based on the present value of expected future cash flows. We use our best estimates in making these evaluations, however, actual future pricing, operating costs and discount rates could vary from the assumptions used in our estimates and the impact of such variations could be material.

Our assessment of the recoverability of finite-lived and indefinite-lived intangible assets is determined by performing monitoring assessment of the future cash flows associated with the underlying gas rights agreements. The cash flows estimates are performed at the operating unit level and based on the average remaining length of the gas rights agreements. Based on our analysis, we concluded the cashflows generated to be well in excess of the carrying amounts. Changes in market conditions related to the various price indexes used in estimating these cash flows could adversely effect these estimates.

Finite-Lived Asset Impairment

In accordance with FASB ASC Topic 360, Property, Plant and Equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results, including considering project specific assumptions for long-term credit prices, escalated future project operating costs and expected site operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, (ii) third-party valuations, and/or (iii) information available regarding the current market value for such assets. We use our best estimates in making these evaluations and consider various factors, including future pricing and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates and the impact of such variations could be material. Based on our annual cash flow assessment conduction for monitoring potential indicators of impairment, we concluded the cashflows to be generated are significantly in excess of their carrying value of our operating sites primarily due to the lengths of the underlying gas rights agreements.

As to the remaining long lived asset groups, the Company further concluded, based on our annual cashflow assessment conducted for monitoring potential indicators of impairment, that the cashflows to be generated are significantly in excess of their carrying values of our operating sites primarily due to the lengths of the underlying gas rights agreements and the Company did not

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record any other impairments related to its cash flows assessment. Separate from our cash flows assessment, we identified discrete events and recorded impairment of We identified discrete events and recorded impairment of $902 and $4,852 for 2023 and 2022, respectively. See Note 3 to our audited consolidated financial statements for further information related to asset impairments.

Emerging Growth Company

We are an emerging growth company, as defined in the JOBS Act. The JOBS Act allows emerging growth companies to delay the adoption of new or revised accounting standards until such time as those standards apply to private companies. We intend to utilize these transition periods, which may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the transition periods afforded under the JOBS Act.

Recent Accounting Pronouncements

For a description of our recently adopted accounting pronouncements and recently issued accounting standards not yet adopted, see Note 2 to our consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to market risks related to Environmental Attribute pricing, commodity pricing, changes in interest rates and credit risk with our contract counterparties. We currently have no foreign exchange risk and do not hold any derivatives or other financial instruments purely for trading or speculative purposes.

We employ various strategies to economically hedge these market risks, including derivative transactions relating to commodity pricing and interest rates. Any realized or unrealized gains or losses from our derivative transactions are reported within corporate revenue in our consolidated financial statements. For information about our realized or unrealized gains or losses with respect to our derivative transactions and the fair value of such financial instruments, see Note 10 and Note 11 to our audited consolidated financial statements.

RIN and Environmental Attribute Pricing Risk

We attempt to negotiate the best prices for our Environmental Attributes and to competitively price our products to reflect the fluctuations in market prices. Reductions in the market prices of Environmental Attributes may have a material adverse effect on our revenues and profits as they directly reduce our revenues. To manage this market risk, we use a mix of short-, medium-, and long-term sales contracts and sell a portion of our Environmental Attributes at fixed-prices, through floor-price margin share agreements and pursuant to forward contracts with terms between one and two years. We also sell our Environmental Attributes bundled with RNG in contracts between two to five years.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to RIN prices. Our analysis, which may differ from actual results, was based on a 2024 estimated D3 RIN Index price of approximately $3.06 and our actual 2023 RINs sold. The estimated annual impact of a hypothetical 10% decrease in the average realized price per RIN would have a negative effect on our operating profit of approximately $10.9 million.

RNG and Renewable Electricity Pricing Risk

The price of RNG and Renewable Electricity changes in relation to the market prices of wholesale gas and wholesale electricity, respectively. Pricing for wholesale gas and wholesale electricity is volatile and we expect this volatility to continue in the future. Further, volatility of wholesale gas and electricity prices also creates volatility in the prices of Environmental Attributes.

We use a mix of short-, medium-, and long-term sales contracts and commodity hedging derivatives to manage our exposure to our pricing risk. In particular, during 2022, we entered into derivative transactions to hedge our exposure to the market price of wholesale gas. We did not enter into a 2023 derivative contract to hedge a portion of our RNG production.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the market price of wholesale gas. Our analysis, which may differ from actual results, was based on a 2024 estimated NYMEX average Index Price of approximately $2.373/MMBtu and our actual 2023 gas production sold pursuant to contracts that do not provide for a fixed or floor price. The estimated annual impact of a hypothetical 10% decrease in the market price of wholesale gas would have a negative effect on our operating profit of approximately $0.8 million.

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Interest Rate Risk

In order to maintain liquidity and fund a portion of development and working capital needs, we have the Amended Credit Facility, which bears a variable interest rate based on BSBY (the Bloomberg Short-Term Bank Yield Index rate plus a margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement). We use interest rate swaps to set the variable interest rates under the Amended Credit Facility at a fixed interest rate to manage our interest rate risk.

As of December 31, 2023, we had $64.0 million outstanding under the Amended Credit Facility. Our weighted average interest rate on variable debt balances during 2023 was approximately 6.11%. We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to changes in interest rates. Based on our analysis, which may differ from actual results, a hypothetical increase in our effective borrowing rate of 10% would not have a material effect on our annual interest expenses and consolidated financial statements.

Credit Risk

We have certain financial and derivative instruments that subject us to credit risk. These consist of our commodity hedging derivatives and interest rate swaps contracts. We are exposed to credit losses in the event of non-performance by the counterparties to our financial and derivative instruments.

We are also subject to credit risk due to concentration of our RNG receivables with a limited number of significant customers. This concentration increases our exposure to credit risk on our receivables, since the financial insolvency of these customers could have a significant impact on our results of operations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Page

Montauk Renewables, Inc.

Audited Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248) 57

Consolidated Balance Sheets as of December 31, 2023 and 2022 58

Notes to Consolidated Financial Statements 62

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Montauk Renewables, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Montauk Renewables, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations, stockholders’ and member’s equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2007.

Pittsburgh, Pennsylvania

March 14, 2024

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MONTAUK RENEWABLES, INC.

CONSOLIDATED BALANCE SHEETS

(in thousands, except per share data) As of December 31,

Current assets:

Current restricted cash 8 22

Related party receivable — 9,000

Current portion of derivative instruments 785 879

Prepaid expenses and other current assets 2,819 2,568

Non-current restricted cash $ 423 $ 407

Non-current portion of derivative instruments 470 936

Operating lease right-of-use assets 4,313 4,742

Finance lease right-of-use assets 36 96

Related party receivable 10,138 —

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:

Current portion of operating lease liability 420 410

Current portion of finance lease liability 26 71

Current portion of long-term debt 7,886 7,870

Long-term debt, less current portion $ 55,614 $ 63,505

Non-current portion of operating lease liability 4,133 4,341

Non-current portion of finance lease liability 10 25

Commitments and contingencies (note 20)

STOCKHOLDERS’ EQUITY

Total liabilities and stockholders' equity $ 350,238 $ 332,316

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data) For the year ended December 31,

Operating expenses:

Royalties, transportation, gathering and production fuel 34,861 44,163 28,683

Gain on insurance proceeds — (313 ) (332 )

Other expenses (income):

Loss on extinguishment of debt — — 154

Income (loss) per share:

Weighted-average common shares outstanding:

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’

AND MEMBER’S EQUITY

Common stock Treasury stock Additional Retained Total

Vesting of stock awards 618,204 6 — — — — — 6

Stock-based compensation — — — — — 9,836 — 9,836

Vesting of stock awards 352,772 4 — — — - — 4

Stock-based compensation — — — — — 8,318 — 8,318

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the year ended

(in thousands): December 31,

Cash flows from operating activities:

Loss on extinguishment of debt — — 154

Gain on property insurance proceeds — (313 ) (332 )

Derivative mark-to-market adjustments and settlements 560 (2,652 ) (1,421 )

Net loss (gain) on sale of assets 94 (233 ) 822

Accretion of asset retirement obligations 407 296 (160 )

Amortization of debt issuance costs 367 412 483

Changes in operating assets and liabilities:

Accounts payable and other accrued expenses 977 8,288 (2,149 )

Cash flows from investing activities:

Asset acquisitions — — (9,673 )

Cash collateral deposits, net 2 82 (220 )

Proceeds from insurance recovery — 313 332

Proceeds from sale of assets 2 1,088 73

Cash flows from financing activities:

Borrowings of long-term debt $ — $ — $ 80,000

Debt issuance costs — — (339 )

Debt extinguishment costs — — (154 )

Related party receivable (1,138 ) — (8,940 )

Finance lease payments (74 ) (47 ) —

Reconciliation of cash, cash equivalents, and restricted cash at end of period:

Restricted cash and cash equivalents - current 8 22 19

Restricted cash and cash equivalents - non-current 423 407 328

Supplemental cash flow information:

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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MONTAUK RENEWABLES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—DESCRIPTION OF BUSINESS

Operations and organization

Montauk Renewables’ Business

Montauk Renewables, Inc. (the “Company” or “Montauk Renewables”) is a renewable energy company specializing in the management, recovery and conversion of biogas into Renewable Natural Gas (“RNG”). The Company captures methane, preventing it from being released into the atmosphere, and converts it into either RNG or electrical power for the electrical grid (“Renewable Electricity”). The Company, headquartered in Pittsburgh, Pennsylvania, has more than 30 years of experience in the development, operation and management of landfill methane-fueled renewable energy projects. The Company has current operations at 15 operating projects located in California, Idaho, Ohio, Oklahoma, Pennsylvania, North Carolina and Texas. The Company sells RNG and Renewable Electricity, taking advantage of Environmental Attribute premiums available under federal and state policies that incentivize their use.

Two of the Company’s key revenue drivers are sales of captured gas and sales of Renewable Identification Numbers (“RINs”) to fuel blenders. The Renewable Fuel Standard (“RFS”) is an Environmental Protection Agency (“EPA”) administered federal law that requires transportation fuel to contain a minimum volume of renewable fuel. RNG derived from landfill methane, agricultural digesters and wastewater treatment facilities used as a vehicle fuel qualifies as a D3 (cellulosic biofuel with a 60% greenhouse gas reduction requirement) RIN. The RINs are compliance units for fuel blenders that were created by the RFS program in order to reduce greenhouse gases and imported petroleum into the United States.

An additional program utilized by the Company is the Low Carbon Fuel Standard (“LCFS”). This is state specific and is designed to stimulate the use of low-carbon fuels. To the extent that RNG from the Company’s facilities is used as a transportation fuel in states that have adopted an LCFS program, it is eligible to receive an Environmental Attribute additional to the RIN value under the federal RFS.

Another key revenue driver is the sale of captured electricity and the associated environmental premiums related to renewable sales. The Company’s electric facilities are designed to conform to and monetize various state renewable portfolio standards requiring a percentage of the electricity produced in that state to come from a renewable resource. Such premiums are in the form of Renewable Energy Credits (“RECs”). The Company’s largest electric facility, located in California, receives revenue for the monetization of RECs as a part of a purchase power agreement.

Collectively, the Company benefits from federal and state government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy, as Environmental Attributes.

Background and Reorganization Transactions

On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by Montauk USA, and Montauk Renewables became a direct wholly-owned subsidiary of MNK. Prior to the Reorganization Transactions, MNK’s business and operations were conducted entirely through Montauk USA and its U.S. subsidiaries, and MNK held no substantial assets other than equity of Montauk USA. The Company had no significant operations or assets prior to January 4, 2021 when it engaged in the equity exchange with Montauk USA and MNK.

After completion of the Reorganization Transactions, (i) Montauk USA ceased to own any substantial assets and (ii) all entities through which MNK’s business and operations were conducted became owned, directly or indirectly, by the Company. MNK adopted a plan contemporaneously with the completion of the Reorganization Transactions that authorized the liquidation and dissolution of MNK.

On January 15, 2021, MNK sold the membership interest of Montauk USA to a third party. On January 26, 2021, MNK distributed all of the outstanding shares of the Company’s common stock as a pro rata dividend to the holders of MNK’s ordinary shares (the “Distribution”), subject to any tax withholding obligations under applicable South African law. Each ordinary share of MNK outstanding on January 21, 2021, the record date for the Distribution (the “Record Date”), entitled the holder thereof to receive one share of the Company’s common stock.

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On January 26, 2021, the Company closed the initial public offering of its common stock on the Nasdaq Capital Market (the “IPO”) with the shares traded under the symbol “MNTK”. Montauk Renewables issued 2,702,500 shares at $8.50 per share and received gross proceeds of $22,971. The Company’s common stock was also secondarily listed on the Johannesburg Stock Exchange (“JSE”) under the trading symbol “MKR”.

On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (as amended on February 22, 2021, December 22, 2021, December 22, 2022 and December 27, 2023) with MNK pursuant to which the Company advanced a cash loan to MNK for MNK to pay its dividends tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended. The terms of the loan following the amendments are substantially similar to the initial loan agreement and were primarily entered into to (1) increase the principal amount outstanding under the loan to $10,040 in the aggregate (2) extended the maturity date to December 31, 2033 also, in accordance with Montauk Renewables’ obligations set forth in the Transaction Implementation Agreement. MNK is currently an affiliate of the Company and certain of the Company’s directors are also directors of MNK. See Note 17 for more information.

MNK was delisted from the JSE on January 26, 2021. The MNK Board of Directors and Shareholders held its annual general meeting in March 2023 and voted to take MNK private.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The historical consolidated financial information included reflects the historical results of operations and financial position of Montauk USA through January 4, 2021 when MNK sold the membership interest of Montauk USA. The consolidated financial statements of Montauk USA became the Company’s historical financial statements following the IPO. Certain historical financial information included relates to periods prior to the Reorganization Transactions. All intercompany balances and transactions have been eliminated in consolidation. The Company utilizes the equity method of accounting for companies where its ownership is greater than 50% and significant but controlling interest does not exist.

Retrospective Presentation of Ownership Related to the Reorganization Transactions

As discussed in Note 1, as a result of the Reorganization Transactions, the Company acquired the assets and entities (excluding Montauk USA) which were previously owned by MNK. As part of the Reorganization Transactions, a 1:1 pro rata distribution of shares of the Company’s common stock was made to holders of MNK’s ordinary shares. The Reorganization Transactions resulted in a pro rata distribution whereby the ownership of the Company after the Reorganization Transactions was identical to the ownership of MNK prior to the Reorganization Transaction and was therefore akin to a common control transaction. All member’s equity in the financial statements and notes have been retrospectively adjusted to give effect to the Distribution, as if such pro rata distribution on a 1:1 basis occurred as of all pre-IPO periods presented, including periods presented on the Consolidated Balance Sheets, Consolidated Statements of Operations, Consolidated Statements of Stockholders’ and Member’s Equity and notes to the Consolidated Financial Statements contained herein.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.

Segment Reporting

The Company reports segment information in three segments: RNG, Renewable Electricity Generation and Corporate. This is consistent with the internal reporting provided to the chief operating decision maker who evaluates operating results and performance. The aforementioned business services and offerings described in Note 1 are grouped and defined by management as two distinct operating segments: RNG and Renewable Electricity Generation. Below is a description of the Company’s operating segments and other activities.

The RNG segment represents the sale of gas sold at fixed-price contracts, counterparty share RNG volumes and applicable Environmental Attributes. This business unit represents the majority of the revenues generated by the Company.

The Renewable Electricity Generation segment represents the sale of captured electricity and applicable Environmental Attributes. Corporate & Other relates to additional discrete financial information for the corporate function. It is primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental,

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engineering and other operations functions not otherwise allocated to a segment. As such, the corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.

Use of Estimates

The preparation of financial statements, in conformity with accounting principles generally accepted in the United States (“GAAP”), requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents include highly liquid investments with maturity dates of three months or less from the date of purchase and are recorded at cost. The Company may hold cash in excess of federally insured limits. Restricted cash is classified as current or non-current based on the terms of the underlying agreements and represents cash held as deposits, cash held in escrow and cash collateral for financial letters of credit.

Accounts and Other Receivables

Accounts and other receivables on the Consolidated Balance Sheets represent outstanding billings for goods and services delivered to customers on an unsecured basis as well as reimbursable expenses. In evaluating its allowance for doubtful accounts for accounts receivable, the Company performs ongoing reviews of its outstanding receivables to determine if any amounts are uncollectible and adjusts the allowance for doubtful accounts accordingly.

Property, Plant and Equipment

Property, plant and equipment purchases are stated at cost. Depreciation and amortization are based on costs less estimated salvage values, primarily using the straight-line method over the estimated useful lives or, if applicable, the term of the related gas rights agreements or power purchase agreements, whichever is shorter. Maintenance and repairs are expensed as incurred. Major improvements that extend the useful lives of property are capitalized.

The estimated useful lives of the Company’s property, plant and equipment reflect the expected consumption of the economic benefit of these assets as noted in the following table:

Buildings and improvements 5 - 30 years

Machinery and equipment 1 - 43 years

Gas mineral rights 15 - 25 years

$313 and $332 in insurance proceeds were received for the years ended December 31, 2022 and 2021, respectively, related to an engine failure at an RNG Facility. These insurance proceeds are included in Gain on insurance proceeds for the years ended December 31, 2022 and 2021, respectively within the Consolidated Statements of Operations.

Goodwill and Intangible Assets

Goodwill is the cost of an acquisition less the fair value of the identified net assets of the acquired business.

Separately identifiable intangible assets are recorded at their fair values upon acquisition. The Company accounts for its intangible assets in accordance with ASC 350, Intangibles—Goodwill and Other (“ASC 350”). Finite-lived intangible assets include interconnections, customer contracts and trade names & trademarks. The interconnection intangible asset is the exclusive right to utilize an interconnection line between the operating plant and a utility substation to transmit produced natural gas and electricity. Included in that right is full maintenance provided on this line by the utility. Intangible assets with finite useful lives are amortized on a straight-line basis over their estimated useful life as depicted in the chart below. Indefinite intangible assets are not amortized and include emission allowances and land use rights.

The estimated useful lives of separately identified intangible assets are as follows:

Interconnection 10 - 25 years

Customer contracts 2 - 15 years

Emissions allowances Indefinite

Land use rights Indefinite

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Assets Held for Sale

Assets classified as held for sale are reported at the lower of their carrying value or fair value less costs to sell. Assets are classified as held for sale if their carrying amounts will be recovered through a sale transaction, rather than through continued use. This condition is met only when the sale is highly probable and the assets are available for immediate sale in their present condition, subject only to terms that are usual and customary for sales of such assets. Management must be committed to a sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale and actions required to complete the plan of sale indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. Impairment losses on initial classification as held-for-sale are recognized in the Consolidated Statement of Operations. Assets classified as held for sale are no longer depreciated or amortized.

Leases

The Company assesses leases in accordance with ASU 2016-02, Leases, (“ASU 2016-02”). This ASU requires lessees to recognize a right-of-use asset and lease liability on the Consolidated Balance Sheet for leases classified as either operating or finance leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize a right-of-use asset and lease liability. Additionally, when measuring assets and liabilities arising from a lease, optional payments should be included only if the lessee is reasonably certain to exercise an option to extend the lease, exercise a purchase option, or not exercise an option to terminate the lease. A right-of-use asset represents an entity’s right to use the underlying asset for the lease term, and a lease liability represents an entity’s obligation to make lease payments. The measurement, recognition and presentation of expenses and cash flows arising from leases by a lessee remains the same. The Company has included further lease disclosures in Note 19.

Long-lived Asset Impairment

In accordance with ASC 360, Property, plant, equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.

A summary of impairment losses on tangible and intangible assets for the year ended December 31, 2023, 2022 and 2021 is included in Note 3.

Indefinite-Lived Asset Impairment

Indefinite-lived intangible assets are required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. The evaluation of impairment under ASC 350 requires the use of projections, estimates and assumptions as to the future performance of the Company’s operations, including anticipated future revenues, expected operating costs and the discount factor used. Actual results may differ from projections. If such indefinite-lived assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets.

Asset Retirement Obligations

The Company accounts for asset retirement obligations as required under ASC 410, Asset Retirement and Environmental Obligations, (“ASC 410”). ASC 410 requires the fair value of a liability for an asset retirement obligation be recognized in the period in which the legal obligation arises, with the associated discounted asset retirement costs being capitalized as a part of the carrying amount of the long-lived asset and the annual accretion expense recorded in operations. The Company has recorded in the consolidated financial statements estimates for asset retirement obligations related to the decommissioning and removal requirements for specific gas processing and distribution assets, as required by their associated gas rights agreements.

Revenue

The Company recognizes revenue in accordance with ASC 606, Revenue from Contracts with Customers(“ASC 606”). Revenue from the Company’s point in time product sales is recognized when products are transferred, or services are invoiced and control transferred. Revenue from the Company’s product and service sales provided under long-term agreements is recognized as the Company transfers control of the product or renders service to its customers, which approximates the time when the customer is invoiced. The Company has presented the disclosures required by ASC 606 in Note 4.

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Income Taxes

The Company is treated as a corporation for income tax purposes. Therefore, income taxes are accounted for under the liability method on a consolidated basis by the Company and its consolidated subsidiaries in accordance with ASC 740, Income Taxes (“ASC 740”). Deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws. The provision for income taxes includes federal and state income taxes.

The Company recognizes the financial statement benefit of a tax position only after determining the relevant tax authority would more-likely-than-not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company recognizes accrued interest and penalties related to unrecognized tax benefits in income tax expense.

Derivative Instruments

The Company applies the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 requires each derivative instrument to be recorded in the Consolidated Balance Sheets at its fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings.

Fair Value of Financial Instruments

The Company employs varying methods and assumptions in estimating the fair value of each class of financial instruments for which it is practical to estimate fair value. For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value due to the short maturity of these instruments. For long-term debt, the carrying amounts approximate fair value as the interest rates obtained by the Company approximate the prevailing interest rates available to the Company for similar instruments.

In accordance with ASC 820, Fair Value Measurement (“ASC 820”), a hierarchy is established which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the assets and liabilities or can be corroborated with observable market data for substantially the entire contractual term of the assets or liabilities.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the assets or liabilities and are consequently not based on market activity but rather through particular valuation techniques. The Company uses the fair value methodology to value the assets and liabilities recorded at fair value, including the Company’s asset retirement obligations and earn out liability.

The values of the Level 2 interest rate derivatives were determined using a model, which incorporates market inputs including the implied forward interest rate yield curve for the same period as the future interest rate swap settlement. The Company has also considered both its own credit risk and counterparty credit risk in determining fair value and determined these adjustments were insignificant for the years ended December 31, 2023 and 2022. The Company’s asset retirement obligations are recorded at fair value at the time the liability is incurred if a reasonable estimate of fair value can be made. Fair value is determined by calculating the estimated present value of the cost to retire the asset as determined by qualified engineers, based on currently available information and inflation estimates and is considered a Level 3 measurement. The Company’s earn-out liability fair value is determined by calculating the estimated present value of future obligations based on currently available information and the discount factor used and is considered a Level 3 measurement.

A summary of changes in the fair values of the Company’s Level 3 instruments, attributable to asset retirement obligations and the earn out liability, for the years ended December 31, 2023 and 2022 is included in Note 11.

Renewable Identification Numbers (“RINs”)

The Company generates D3 RINs through its production and sale of RNG used for transportation purposes as prescribed under the Federal Renewable Fuel Standard. The RINs that the Company generates as government incentives through its renewable operating projects can be separated and sold as credits independent from the energy produced and not a result of physical attributes of the Company’s production. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these

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Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The Company had 0.1 and 0.7 million RINs generated and unsold as of December 31, 2023 and 2022, respectively.

Renewable Energy Credits (“RECs”)

The Company generates RECs through its production and sale of landfill methane into renewable electric energy as prescribed by the State of California Renewables Portfolio Standard or the EPA. The RECs that the Company generates as government incentives through its renewable operating projects are able to be separated and sold as credits independent from the electricity produced and not a result of physical attributes of the Company’s production. Therefore, no cost is allocated to the REC when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred.

Equity-Based Compensation

The Company accounts for equity-based compensation under the provisions of ASC 718, Compensation—Stock Compensation, (“ASC 718”). ASC 718 requires compensation costs related to share-based payment transactions, measured based on the fair value of the instruments issued, be recognized in the consolidated financial statements over the requisite service period of the award. Stock options are initially measured on the grant date using the Black-Scholes valuation model, which requires the use of subjective assumptions related to the expected stock price volatility, term, risk-free interest rate and dividend yield. For restricted stock shares, the Company determines the grant date fair value based on the closing market price of the stock on the date of the grant.

Employee Benefits

Leave entitlement

Employee entitlements to annual leave are recognized when they accrue to employees. An accrual is made for the estimated liability to the employees for annual leave up to the financial year end date. This liability is included in “Accrued liabilities” in the Consolidated Balance Sheets.

Bonus Plans

The Company recognizes a liability and an expense for incentive compensation bonuses awarded based on the achievement of Company and personnel goals where contractually obliged or where there is a past practice that has created a constructive obligation. An accrual is maintained for the appropriate proportion of the expected bonuses which would become payable at year end.

Recently Adopted Accounting Standards

In August 2020, the FASB issued ASU 2020-06, Debt: Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging—Contracts in Entity’s Own Equity (Subtopic 815-40), which simplifies the accounting for convertible instruments and contracts in an entity’s own equity. This guidance is effective for annual reporting periods beginning after December 15, 2021, including interim periods within those years, with early adoption permitted only as of annual reporting periods beginning after December 15, 2020. The ASU does not have a material impact on the Company’s consolidated financial statements or related financial statement disclosures.

In June 2016, the FASB issued Accounting Standards Update 2016-13, Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). This ASU and subsequent amendments are codified as Accounting Standards Codification Topic 326, Financial Instruments—Credit Losses (“ASC 326”). Application of ASC 326 was effective for SEC Issuers (excluding smaller reporting companies) for fiscal years beginning after December 15, 2019. Adoption for smaller reporting companies, emerging growth companies and nonpublic entities was deferred due to the COVID-19 pandemic and was required for fiscal years beginning after December 15, 2022. The ASU did not have a material impact on the Company’s consolidated financial statements or related financial statement disclosures.

Recently Issued Accounting Standards

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848), which provides optional expedients and exceptions to the current guidance on contract modifications and hedging relationships to ease the financial reporting burdens of the expected market transition from London Interbank Offered Rate (“LIBOR”) and other interbank offered rates to alternative reference rates. The guidance was effective upon issuance and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. The FASB included a sunset provision within Topic 848 based on expectations of when the LIBOR would cease being published. The sunset provision has been amended from December

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31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. The Company’s current debt agreement bears interest at the Bloomberg Short-Term Bank Yield Index Rate plus an applicable margin. LIBOR is no longer utilized as a reference rate.

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segments. The amendments in 2023-07 aim to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. ASU 2023-07 is effective for the Company's Annual Report on Form 10-K for the year ended December 31, 2024, and subsequent interim periods, with early adoption permitted. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The amendments in 2023-09 aim to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for the Company's Annual Report on Form 10-K for the year ended December 31, 2025, with early adoption permitted. The Company is currently evaluating the impact of this standard on its consolidated financial statements.

NOTE 3—ASSET IMPAIRMENT

The Company recorded $902, $4,852 and $1,191 in impairment losses for the years ended December 31, 2023, 2022 and 2021, respectively. 2023 impairments included $777 for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in the Company's RNG segment. The remaining $125 in impairments were for specifically identified obsolete REG critical spares. The 2022 impairments included $2,133 for a REG site wherein the forecasted future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG site was impaired for $1,393 due to a discrete conclusion that certain assets acquired in the May 2021 Asset acquisition would no longer be utilized by the Company. More information on the Asset acquisition can be found in Note 7. An RNG site was impaired for $1,108 due to the specific identification of certain assets no longer capable of being used as designed. Additional impairments were recorded for computer software and hardware no longer being utilized ($191) and an amended customer contract ($27) no longer in use. The 2021 impairment loss of $1,191 was due to the closure of two REG Sites and also the disposal of machinery at one RNG site.

Impairment loss was recorded under Operating expenses within the Consolidated Statements of Operations for the years ended December 31, 2023, 2022, and 2021.

NOTE 4—REVENUES FROM CONTRACTS WITH CUSTOMERS

The Company’s revenues are comprised of renewable energy and related Environmental attribute sales provided under long-term contracts with its customers. All revenue is recognized when (or as) the Company satisfies its performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product or service to its customer either when (or as) its customer obtains control of the product or service. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. The Company allocates the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.

Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring its products or services. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred by the customer following the transfer of control of the commodities sold. To the extent applicable, sales, value add and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.

The Company’s performance obligations related to the sale of renewable energy (i.e. RNG and Renewable Electricity) are generally satisfied over time. Revenue related to the sale of renewable energy is generally recognized over time using an output based upon the product quantity delivered to the customer. This measure is used to best depict the Company’s performance to date under the terms of the contract. Revenue from products transferred to customers over time accounted for approximately 23%, 29% and 28% of revenue for the years ended December 31, 2023, 2022 and 2021, respectively.

The nature of the Company’s long-term contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of the Company’s influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained.

The Company’s performance obligations related to the sale of Environmental Attributes are generally satisfied at a point in time and were approximately 77%, 71% and 72% of revenue for the years ended December 31, 2023, 2022 and 2021, respectively. The Company recognizes Environmental Attribute revenue at the point in time in which the customer obtains control of the Environmental Attributes, which is generally when the title of the Environmental Attribute passes to the customer upon delivery. In limited cases, title does not transfer to the customer and revenue is not recognized until the customer has accepted the Environmental Attributes. The

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Company’s performance obligations under its counterparty sharing agreements are generally satisfied at a point in time when the earnings process is completed by the counterparty. Counterparty sharing arrangement revenues were approximately 1% and 10% of revenue for the years ended December 31, 2022 and 2021, respectively. The Company does not currently recognize revenues under counterparty sharing arrangements.

The following tables display the Company’s disaggregated revenue by major source, excluding realized and unrealized gains or losses under the Company’s gas hedge program, based on product type and timing of transfer of goods and services for the years ended December 31, 2023, 2022 and 2021:

Goods transferred at a point in time Goods transferred over time Total

Major goods/Service line:

Electric environmental attributes 7,522 — 7,522

Operating segment:

Goods transferred at a point in time Goods transferred over time Total

Major goods/Service line:

Electric environmental attributes 7,016 — 7,016

Operating segment:

Goods transferred at a point in time Goods transferred over time Total

Major goods/Service line:

Natural gas environmental attributes 84,906 — 84,906

Electric environmental attributes 6,208 — 6,208

Operating segment:

Practical expedients and remaining performance obligations

The Company recognizes the sale of natural gas and electric commodities using the right to invoice practical expedient. The Company determined that the revenues recognized as of period end correspond directly with the value transferred to customers and the Company's satisfaction of the performance obligations to date. Furthermore, with the application of the right to invoice practical

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expedient and in consideration that contracts related to future environmental attributes sales do not exceed one year, there are no remaining unsatisfied or partially satisfied performance obligations as of December 31, 2023.

NOTE 5—ACCOUNTS AND OTHER RECEIVABLES

The Company extends credit based upon an evaluation of the customer’s financial condition. Credit terms are consistent with industry standards and practices. Accounts Receivable consist of sales to large creditworthy energy and utility companies. Reserves for uncollectible accounts, if any, are recorded as part of general and administrative expenses in the Consolidated Statements of Operations. No reserve expense was recorded for the years ended December 31, 2023, 2022 and 2021.

Accounts and other receivables consist of the following as of December 31, 2023 and 2022:

Reimbursable expenses 47 17

Accounts and other receivables, net $ 12,752 $ 7,222

NOTE 6—ASSETS HELD FOR SALE

In 2021, the Company initiated a plan to sell nitrogen oxide (“NOx”) emissions allowances credits. The Company concluded that it met the criteria under applicable guidance for a long-lived asset to be held for sale, and accordingly reclassified the emissions allowances of $777 as current assets held for sale on the Consolidated Balance Sheet at December 31, 2021. The Company estimated the fair value of these assets and concluded that the fair value exceeded the carrying value and no impairment was recorded by the Company for the year ended December 31, 2021. In March 2022, the NOx emissions allowances credits were sold for $1,088. A $311 gain on sale of intangible assets was recorded for the year ended December 31, 2022.

NOTE 7—PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment consists of the following as of December 31, 2023 and 2022:

Less: Accumulated depreciation and amortization (175,482 ) (156,819 )

Depreciation expense for property plant and equipment was $19,624, $19,251 and $19,617 and amortization expense for gas mineral rights was $489, $515 and $1,828 for the years ended December 31, 2023, 2022 and 2021, respectively.

In 2023, the Company specifically identified $777 in discrete RNG machinery and feedstock processing equipment that were no longer in operational use and recorded an impairment in the Company's RNG segment. The remaining $125 in impairments were for obsolete REG critical spares.

In 2022, the Company performed a recoverability test for one REG site when it was determined that it was more likely than not the carrying value of the long-lived assets would not be recoverable. The results of the testing indicated that the site had carrying values in excess of the asset group’s fair value. As a result of the analysis, the company recorded an impairment totaling $2,089 in property, plant and equipment for the year ended December 31, 2022. Additionally, $1,393 in property, plant and equipment at another REG site was impaired due a discrete conclusion that certain assets acquired in the Asset acquisition would no longer be utilized by the Company. An RNG site was impaired for $1,108 due specific identification of certain assets no longer capable of being used as designed. Finally, computer software and hardware no longer being utilized ($191) were impaired in 2022. The 2021 impairment loss of $1,191 was due to the closure of two REG Sites and also the disposal of machinery at one RNG site.

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NOTE 8—GOODWILL AND INTANGIBLE ASSETS, NET

Intangible assets consist of the following as of December 31, 2023 and December 31, 2022:

Intangible assets with indefinite lives:

Total intangible assets with indefinite lives: $ 329 $ 329

Intangible assets with finite lives:

Total intangible assets with finite lives: $ 18,032 $ 15,366

Total Goodwill and Intangible assets $ 18,421 $ 15,755

The weighted average remaining useful life of the customer contracts and interconnection is approximately 15 years for both intangible asset categories. Amortization expense was $972, $887 and $1,424 for the years ended December 31, 2023, 2022 and 2021, respectively. Impairments related to intangibles totaled $71 for the year ended December 31, 2022, which included $44 related to one REG site discussed in Note 7 and $27 related to an RNG site associated with the early termination of a customer contract.

Amortization expense for customer contracts and interconnection the next five years is as follows:

Customer Inter-

Year ending Contracts connections

NOTE 9—ASSET RETIREMENT OBLIGATIONS

The Company accounts for asset retirement obligations by recording the fair value of the liability in the period in which it is incurred. The Company estimates the fair value of asset retirement obligations by calculating the estimated present value of the cost to retire the asset. Factors that are considered when determining the present value of the cost to retire the asset include future inflation and discount rates, along with estimates date(s) of retiring the asset. Additionally, changes in legal, regulatory, environmental, and political environments can affect the fair value of the obligations. As such, asset retirement obligations are considered a level 3 financial instrument. The following table summarizes the activity associated with asset retirement obligations of the Company for the years ended December 31, 2023, 2022 and 2021:

Year ended December 31,

Asset retirement obligations—beginning of period $ 5,493 $ 5,301 $ 5,689

Decommissioning — (104 ) (228 )

Asset retirement obligations—end of period $ 5,900 $ 5,493 $ 5,301

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NOTE 10—DERIVATIVE INSTRUMENTS

To mitigate market risk associated with fluctuations in energy commodity prices (natural gas) and interest rates, the Company utilizes various derivative contracts to secure energy commodity pricing and interest rates under a board-approved program. The Company does not apply hedge accounting to any of its derivative instruments, and all realized and unrealized gains and losses from changes in derivative values are recognized in earnings each period. As a result of the hedging strategy employed, the Company had the following cash received (paid) on derivatives in the Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021:

Year ended December 31,

Commodity contracts:

Cash paid on derivatives Operating revenue $ — $ (7,829 ) $ —

NOTE 11—FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company’s assets and liabilities that are measured at fair value on a recurring basis include the following as of December 31, 2023 and 2022, set forth by level, within the fair value hierarchy:

Level 1 Level 2 Level 3 Total

Interest rate swap derivative asset $ — $ 1,255 $ — $ 1,255

Asset retirement obligations — — (5,900 ) (5,900 )

Pico earn-out liability — — (5,109 ) (5,109 )

Level 1 Level 2 Level 3 Total

Interest rate swap derivative asset $ — $ 1,815 $ — $ 1,815

Asset retirement obligations — — (5,493 ) (5,493 )

Pico earn-out liability — — (3,843 ) (3,843 )