Montauk Renewables, Inc. (MNTK) FY 2023 MD&A

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:

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 Environmental Attributes derived from RNG, such as RINs and LCFS credits. Our RNG revenues from Environmental Attributes are recorded net of a portion of Environmental Attributes shared with off-take counterparties as consideration for such counterparties using the RNG as a transportation fuel. We 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 and sale of the Environmental Attributes, such as RECs, derived from Renewable Electricity. All of our Renewable Electricity production is monetized under fixed-price PPAs from our existing operating projects.

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

Our operating revenues are priced based on published index prices which can be influenced by factors outside our control, such as market impacts on commodity pricing and regulatory developments. 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 of our or a landfill operator’s equipment or interconnection or transmission problems could result in a reduction of our RNG production. We strive to proactively address any issues that may arise through preventative maintenance, process improvement and flexible redeployment of equipment to maximize production and useful life.

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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 project sites is subject to change based on the volume and type of waste accepted. Variations in the quality of the biogas could affect our RNG production levels. At three of our projects, we operate the wellfield collection system, which allows greater control over the quality and consistency of the collected biogas. At two of our projects, 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 to take in additional waste and the amount of gas available for collection increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project would delay any realization of production from that project.

Pricing

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

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

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 structured as a percentage of revenue. Transportation and gathering expenses include capacity and metering expenses representing the costs of delivering our RNG and Renewable Electricity production to our customers. These expenses include payments to pipeline operators and other agencies that allow for the transmission of our gas and electricity commodities to end users. Production fuel expenses generally represent alternative royalty payments based on quantity usage of biogas feedstock.

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General and Administrative Expenses: General and administrative expenses primarily consist of corporate expenses and unallocated support functions for our operating facilities, including personnel costs for executive, finance, accounting, investor relations, legal, human resources, operations, engineering, environmental registration and reporting, health and safety, IT and other administrative personnel and professional fees and general corporate expenses. From time to time, we may be parties to legal proceedings arising in the normal course of business which could increase our legal expenses. We 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 significant capital 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 whenever events 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 acquisitions and other strategic transactions.

Key Operating Metrics

Total operating revenues reflect both sales of renewable energy and sales of related Environmental Attributes. As a result, our revenues are primarily affected by unit production of RNG and Renewable Electricity, production of Environmental Attributes, and the prices at which we monetize such production. Set forth below is an overview of these key metrics:

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Production Volumes: We review performance by site based on unit of production calculations for RNG and Renewable Electricity, measured in terms of MMBtu and MWh, respectively. While unit of production measurements can be influenced by schedule facility maintenance schedules, the metric is used to measure the efficiency of operations and the impact of optimization improvement initiatives. We monetize a majority of our RNG commodity production under variable-price agreements, based on indices. A portion of our Renewable Natural Gas segment commodity production is monetized under fixed-priced contracts. Our Renewable Electricity Generation segment commodity production is primarily monetized under fixed-priced PPAs.

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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 the Environmental 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.

(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:

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:

(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:

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, 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.