Montauk Renewables, Inc.: Form 10-Q for the period ended Mar 31, 2024

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Quarterly Report on Form 10-Q. Throughout this section, dollar amounts and production volumes are expressed in thousands, except for per share amounts, MMBtu, MWh, and RIN pricing amounts and unless otherwise indicated.

In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Cautionary Note Regarding Forward-Looking Statements,” “Item 1A.–Risk Factors” of our 2023 Annual Report and elsewhere in this report.

Overview

Montauk Renewables is a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources for beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply RNG into the transportation industry and use RNG to produce Renewable Electricity. We are one of the largest U.S. producers of RNG, having participated in the industry for over 30 years. We established our operating portfolio of 12 RNG and two Renewable Electricity projects through self-development, partnerships, and acquisitions that span eight states.

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

Our current operating projects produce either RNG or Renewable Electricity by processing biogas from landfill sites or agricultural waste from livestock farms. We view agricultural waste from livestock farms as a significant opportunity for us to expand our RNG business, and we continue to evaluate other agricultural feedstock opportunities. We believe that our business model and technology are highly scalable given availability of biogas from agriculturally derived sources, which will allow us to continue to grow through prudent development and complimentary acquisitions.

Recent Developments

RINs Generated but Unsold

Our profitability is highly dependent on the market price of Environmental Attributes, including the market price for RINs. As we self-market a significant portion of our RINs, a decision not to commit to transfer available RINs during a period will impact our revenue and operating profit. We made a strategic determination to not transfer all available D3 RINs generated and available for transfer during the first quarter of 2024. As a result, we have approximately 3,351 RINs in inventory from 2024 RNG production but we sold all of our RINs generated and available for sale from our 2023 RNG production in the first quarter of 2024. We have not entered into commitments to transfer these RINs from 2024 production 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 first quarter of 2024 was approximately $3.12.

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

During the first quarter of 2024, we successfully commissioned the last expansion of our digestion capacity which is necessary to process the final tranche of anticipated increased feedstock expected to be received in 2025. However, we are processing all current feedstock and continue to expect to ramp up production through the second quarter of 2024. With the increased digestion capacity, we produced approximately 39% more MMBtu during the first quarter of 2024 as compared to the first quarter of 2023. We still anticipate that our dairy host will deliver the final increase in feedstock volumes in 2025, at which point we will make the final contractual payment to the dairy host.

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. 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 continue to incur capital expenditures for this project and currently expect commercial operations in the first quarter of 2025. We do not expect a material operational production impact in 2024 based on the commissioning of the second facility.

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. Our pace of capital deployment for this project will match the expected timing related to the utility interconnection.

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. We continue to 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. We continue to incur capital expenditures for this project.

Montauk Ag Renewables 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 to generate electricity, North Carolina swine RECs, and micronutrient organic fertilizer alternatives (the “Montauk Ag Renewables Acquisition”).

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 engage with regulatory agencies in North Carolina to confirm that power generation from swine waste will be eligible for Renewable Energy Credits under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production. In early 2024, we received notification from the North Carolina Utilities Commission that the Turkey, NC location was approved for a New Renewables Energy Facility ("NREF") designation and Certificate of Public Convenience and Necessity. In the first quarter of 2024, we submitted an amendment to our NREF application and expect a decision on the NREF designation in 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 April 2024, we signed our second feedstock supply agreement which includes our ability to access more than twice the hog spaces we are currently contracted for at our future discretion. When added to the first feedstock supply agreement signed in December 2023, we believe we are on pace to target the 120 thousand hog spaces which will provide sufficient feedstock under our Duke Energy REC agreement signed in July 2023. We also believe these agreements are strategic because they will allow us to bring additional hog spaces under contract as we commission our first phase of development for Montauk Ag Renewables.

These feedstock supply agreements have allowed us to continue to refine our expected feedstock collection process. This process will involve installing equipment on the farms under agreements to collect feedstock and process the waste through multiple phases of solids concentration at both the farm and our Turkey, NC location.

In connection with the build-out of the Turkey, NC processing facility, we believe that we have substantially completed the engineering of the reactors to be installed. We have placed orders for significant components related to the construction of the reactors, certain electrical componentry, and expect to enter into an engineering, procurement, and construction contract during the second quarter of 2024 to enable us to meet our commissioning schedule.

We 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 expect to begin generating revenues in 2025 and have sufficient capacity to satisfy the Duke REC agreement upon final commissioning during the second half of 2025.

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 commercial production. We expect the Magnolia, NC location to be used for various feedstock processing needs. Based on our current development timeline expectations, we do not expect to commence significant revenue generating activities until 2025. We intend to contract with additional farms to secure feedstock sources for future production processes.

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 and we continue to expect first delivery to begin in 2027. We continue to anticipate commissioning to begin in 2027 and we continue to expect the capital investment to be approximately $15,000 per facility with anticipating spend beginning second half of 2024, though we have not yet committed capital to this project.

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. We ceased operations at this site due to a utility interconnection upgrade that is not compatible with the existing operations and recorded an impairment charge of approximately $312. 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.

Key Trends

Market Trends Affecting the Renewable Fuel Market

We believe rising demand for RNG is attributable to a variety of factors, including growing public support for renewable energy, U.S. governmental actions to increase energy independence, environmental concerns increasing demand for natural gas powered vehicles, job creation, and increasing investment in the renewable energy sector.

Key drivers for the long-term growth of RNG include the following factors:

• Regulatory or policy initiatives, including the federal RFS program and state or national-level low-carbon fuel programs in states such as California and Oregon or Canada, that drive demand for RNG and its derivative Environmental Attributes (as further described below).
• Efficiency, mobility and capital cost flexibility in RNG operations enable them 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 counterparts.
• Demand for compressed natural gas (“CNG”) from natural gas-fueled vehicles. The RNG we create is pipeline quality and can be used for transportation fuel when converted to CNG. CNG is commonly used by medium-duty fleets that are close to fueling stations, such as city fleets, local delivery trucks and waste haulers.
• Regulatory requirements, market pressure and public relations challenges increase the time, cost and difficulty of permitting new fossil fuel-fired facilities.

Factors Affecting Our Future Operating Results:

Conversion of Electricity Projects to RNG Projects:

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

Acquisition and Development Pipeline

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

• Impact of Higher Selling, General and Administrative Expenses Prior to the Commencement of a Project’s Operation: We incur significant expenses in the development of new RNG projects. 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. Under the Biogas Regulatory Reform Rule, effective July 1, 2024, storage of RNG for future RIN generation prior to receiving EPA registration will not be permitted.
• Shifts in Revenue Composition for Projects from New Fuel Sources: As we expand into livestock farm projects, our revenue composition from Environmental Attributes will change. We believe that livestock farms offer us a

lucrative opportunity, as the value of LCFS credits for dairy farm projects, for example, are a multiple of those realized from landfill projects due to the significantly more attractive CI score of livestock farms.

• Incurrence of Expenses Associated with Pursuing Prospective Projects That Do Not Come to Fruition: We incur expenses to pursue prospective projects with the goal of a site host accepting our proposal or being awarded a project in a competitive bidding process. Historically, we have evaluated opportunities which we decided not to pursue further due to the prospective project not meeting our internal investment thresholds or a lack of success in a competitive bidding process. To the extent we seek to pursue a greater number of projects or bidding for projects becomes more competitive, our expenses may increase.

Regulatory, Environmental and Social Trends

Regulatory, environmental and social factors are key drivers that incentivize the development of RNG and Renewable Electricity projects and influence the economics of these projects. We are subject to the possibility of legislative and regulatory changes to certain incentives, such as RINs, RECs and GHG initiatives. On July 12, 2023, the EPA issued final rules in the Federal Register for the RFS volume requirements for 2023-2025. Final volumes for cellulosic biofuel were set at 838, 1,090 and 1,376 million RINs for the three years 2023, 2024 and 2025, respectively. The 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. CARB held a public workshop for the proposed rules on April 10, 2024. Final rules are expected for public comment sometime in the third quarter of 2024 with LCFS amendments in first quarter of 2025. 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. The industry may see pricing volatility including potential increase to LCFS credit prices. However, price increases are not anticipated until after 2025. 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.

• 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.
• Renewable Electricity Generation Revenues: We record revenues from the production and sale of Renewable Electricity and the generation and sale of the Environmental Attributes, such as RECs, derived from Renewable Electricity. All of our Renewable Electricity production is monetized under fixed-price PPAs from our existing operating projects.
• Corporate Revenues: Corporate reports realized and unrealized gains or losses under our gas hedge programs. The Company does not have any active gas hedge programs. Corporate also relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment.

Our operating revenues are priced based on published index prices which can be influenced by factors outside our control, such as market impacts on commodity pricing and regulatory developments. 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 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.

• Though we collaborate with the landfill host at our Rumpke facility on our gas collection efforts wellfield extraction environmental factors have impacted gas extraction at the site. While the site continues to expand its 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 through 2024.
• 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 continue to have lower volumes of feedstock available to be processed at the McCarty facility.
• Quality of Biogas: We are reliant upon the quality and availability of biogas from our site partners. The quality of the waste at our landfill project sites is subject to change based on the volume and type of waste accepted. Variations in the quality of the biogas could affect our RNG production levels. At three of our projects, we operate the wellfield collection system, which allows greater control over the quality and consistency of the collected biogas. At two of our projects, we have operating and management agreements by which we earn revenue for managing the wellfield collection systems. Additionally, our dairy farm project benefits from the consistency of feedstock and controlled environment of collection of waste to improve biogas quality.
• RNG Production from Our Growth Projects: We anticipate increased production at certain of our existing projects as open landfills continue to take in additional waste and the amount of gas available for collection increases. Delays in commencement of production or extended commissioning issues at a new project or a conversion project 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 termed agreements to counterparties, with contract terms varying from three years to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. All of the Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price arrangement with escalators.

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

The sale of RINs, which is subject to market price fluctuations, accounts for a substantial portion of our revenues. We manage against the risk of these fluctuations through forward sales of RINs, although currently we only sell RINs in the calendar year they are generated. We have not entered into commitments to transfer significant RINs generated from 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.

Factors Affecting Operating Expenses

Our operating expenses include royalties, transportation, gathering and production fuel expenses, project operating and maintenance expenses, general and administrative expenses, depreciation and amortization, net loss (gain) on sale of assets, impairment loss and transaction costs. Our operating expenses can be subject to inflationary cost increases that are largely out of our control.

• 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.
• Royalties, Transportation, Gathering and Production Fuel Expenses: Royalties represent payments made to our facility hosts, typically structured as a percentage of revenue. Transportation and gathering expenses include capacity and metering expenses representing the costs of delivering our RNG and Renewable Electricity production to our customers. These expenses include payments to pipeline operators and other agencies that allow for the transmission of our gas and electricity commodities to end users. Production fuel expenses generally represent alternative royalty payments based on quantity usage of biogas feedstock.
• General and Administrative Expenses: General and administrative expenses primarily consist of corporate expenses and unallocated support functions for our operating facilities, including personnel costs for executive, finance, accounting, investor relations, legal, human resources, operations, engineering, environmental registration and reporting, health and safety, IT and other administrative personnel and professional fees and general corporate expenses. From time to time, we may be parties to legal proceedings arising in the normal course of business which could increase our legal expenses. We 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 2023. The Company accounts for share-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 14 to our unaudited condensed consolidated financial statements related to share-based compensation.
• Depreciation and Amortization: Expenses related to the recognition of the useful lives of our intangible and fixed assets. We spend significant capital to build and own our facilities. In addition to development capital, we annually reinvest to maintain these facilities.
• Impairment Loss: Expenses related to reductions in the carrying value(s) of fixed and/or intangible assets based on periodic evaluations whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
• Transaction Costs: Transaction costs primarily consist of expenses incurred for due diligence and other activities related to potential acquisitions and other strategic transactions.

Key Operating Metrics

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

• Production volumes: We review performance by site based on unit of production calculations for RNG and Renewable Electricity, measured in terms of MMBtu and MWh, respectively. While unit of production measurements can be influenced by schedule facility maintenance schedules, the metric is used to measure the efficiency of operations and the impact of optimization improvement initiatives. We monetize a majority of our RNG commodity production under variable-price agreements, based on indices. A portion of our Renewable Natural Gas segment commodity production is monetized under fixed-priced contracts. Our Renewable Electricity Generation segment commodity production is primarily monetized under fixed-priced PPAs.
• Production of Environmental Attributes: We monetize Environmental Attributes derived from our production of RNG and Renewable Electricity. We carry-over a portion of the RINs generated from RNG production to the following year and monetize the carried over RINs in such following calendar year. A majority of our Renewable Natural Gas segment Environmental Attributes are self-monetized. A majority of our Renewable Electricity Generation segment Environmental Attributes are monetized as a component of our fixed-price PPAs.
• Average realized price per unit of production: Our profitability is highly dependent on the commodity prices for natural gas and electricity, and the Environmental Attribute prices for RINs, LCFS credits, and RECs. Realized prices for Environmental Attributes monetized in a year may not correspond directly with that year’s production as attributes may be carried over and subsequently monetized. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

Comparison of Three Months Ended March 31, 2024 and 2023

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

(in thousands, unless otherwise indicated)

(1) RINs are generated in the month that the gas is dispensed to generate RINs, which occurs the month after the gas is produced. Volumes under fixed/floor-price arrangements generate RINs which we do not self-market.

(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 which has not been dispensed to generate RINs.

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

Revenues for the Three Months Ended March 31, 2024 and 2023

Total revenues in the first quarter of 2024 were $38,787 an increase of $19,633 (102.5%) compared to $19,154 in the first quarter of 2023. The increase is primarily related to an increase in self-monetized RINs in the first quarter of 2024 compared to the first quarter of 2023 as a result of our strategic decision in the first quarter of 2023 to not self market a significant amount of RINs from 2023 RNG production due to our belief that first quarter of 2023 D3 RIN index volatility was temporary. Of the 7,889 RINs sold in the first quarter of 2024, 4,000 RINs were related to 2024 RNG production. Also contributing to the increase is an increase in Realized RIN pricing of approximately 61.7% during the first quarter of 2024 compared to the first quarter of 2023.

Renewable Natural Gas Revenues

We produced 1,411 MMBtu of RNG during the first quarter of 2024, an increase of 59 MMBtu (4.4%) over the 1,352 MMBtu produced in the first quarter of 2023. Our Coastal facility produced 38 MMBtu more in the first quarter of 2024 compared to the first quarter of 2023 as a result of plant processing equipment improvements and wellfield operational enhancements. Our McCarty facility produced 24 MMBtu more in the first quarter of 2024 as compared to the first quarter of 2023 as a result of wellfield enhancements by our landfill host. Our Galveston facility produced 19 MMBtu more in the first quarter of 2024 compared to the first quarter of 2023 as a result of a temporary reduction of feedstock inlet during modifications to process equipment in the first quarter of 2023. Our Pico facility produced 9 MMBtu more in the first quarter of 2024 compared to the first quarter of 2023 as a result of commissioning our dairy digestion expansion project. Offsetting the improvements was our Rumpke facility which produced 55 MMBtu less in the first quarter of 2024 compared to the first quarter of 2023 as a result of a process equipment failure that occurred during the first quarter of 2024.

Revenues from the Renewable Natural Gas segment in the first quarter of 2024 were $33,988, an increase of $19,203 (129.9%) compared to $14,785 in the first quarter of 2023. Average commodity pricing for natural gas for the first quarter of 2024 was $2.24 per MMBtu, 34.5% lower than the first quarter of 2023. During the first quarter of 2024, we self-monetized 7,889 RINs, representing a 4,940 increase (167.5%) compared to 2,949 in the first quarter of 2023. Average pricing realized on RIN sales during the first quarter of 2024 was $3.25 as compared to $2.01 in the first quarter of 2023, an increase of 61.7%. This compares to the average D3 RIN index price for the first quarter of 2024 of $3.12 as compared to $2.03 in the first quarter of 2023, an increase of approximately 53.7%. At March 31, 2024, we had approximately 384 MMBtu available for RIN generation and we had approximately 3,351 RINs generated and unsold. At March 31, 2023, we had approximately 418 MMBtu available for RIN generation and 8,266 RINs generated and unsold.

Renewable Electricity Generation Revenues

We produced approximately 54 MWh in Renewable Electricity in the first quarter of 2024, an increase of 8 MWh (17.4%) from 46 MWh in the first quarter of 2023. Our Security facility produced approximately 3 MWh more in the first quarter of 2024 compared to the first quarter of 2023 as a result of the completion of prior period engine maintenance. Our Bowerman facility produced approximately 3 MWh more in the first quarter of 2024 compared to the first quarter of 2023 primarily related to the timing of preventative engine maintenance.

Revenues from Renewable Electricity facilities in the first quarter of 2024 were $4,799, an increase of $430 (9.8%) compared to $4,369 in the first quarter of 2023. The increase is primarily driven by the increase in our Security and Bowerman facility production volumes.

In the first quarter of 2024, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs, as compared to 99.8% in the first quarter of 2023. This provides us with certainty of price resulting from our Renewable Electricity sites.

Expenses for the Three Months Ended March 31, 2024 and 2023

General and Administrative Expenses

Total general and administrative expenses were $9,427 for the first quarter of 2024, a decrease of $48 (0.5%) compared to $9,475 for the first quarter of 2023. Employee related costs, including stock-based compensation costs were $5,724 in the first quarter of 2024, an increase of $731 (14.6%) compared to $4,993 in the first quarter of 2023. Our corporate insurance fees increased approximately $167 (12.2%) in the first quarter of 2024 compared to the first quarter of 2023. Our professional fees decreased approximately $1,006 (48.7%) in the first quarter of 2024 compared to the first quarter of 2023.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in the first quarter of 2024 were $12,141, an increase of $799 (7.0%) as compared to $11,342 in the first quarter of 2023. Included in our first quarter of 2024 total operating and maintenance expenses for our RNG facilities is utility expense of $3,942 an increase of $103 (2.7%) compared to $3,839 in the first quarter of 2023. Our Rumpke facility operating maintenance expenses increased approximately $668 primarily related to the timing of annual preventative maintenance expenses. Our Atascocita facility operating maintenance expenses increased approximately $533 as a result of utility expense and timing of annual preventative maintenance. Our Pico facility operating and maintenance expenses decreased approximately $313 primarily related to a decrease in utility expense.

Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the first quarter of 2024 were $5,997, an increase of $2,531 (73.0%) compared to $3,466 in the first quarter of 2023. We recorded a reduction to our Pico facility earnout of approximately 16.6% during the first quarter of 2024. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 17.6% for the first quarter of 2024 from 23.4% in the first quarter of 2023.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in the first quarter of 2024 were $2,292, a decrease of $569 (19.9%) compared to $2,861 in the first quarter of 2023. Our Bowerman facility operating and maintenance expenses decreased approximately $298 which was primarily driven by the timing of annual original equipment manufacturer preventative maintenance expenses. Our Security facility operating and maintenance expenses decreased approximately $303 which was driven by the nonrecurring reversal of our asset retirement obligation liability related to the sale of the site.

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the first quarter of 2024 were $521, an increase of $54 (11.6%) compared to $467 in the first quarter of 2023. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses increased to 10.9% from 10.7%.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in the first quarter of 2024 were $6,518, an increase of $2,585 (65.7%) compared to $3,933 in the first quarter of 2023. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.

Depreciation

Depreciation and amortization in the first quarter of 2024 was $5,434, an increase of $238 (4.6%) compared to $5,196 in the first quarter of 2023. The increase is associated with timing of capital investment placed into service in the fourth quarter of 2023 compared to the fourth quarter of 2022.

Impairment loss

We calculated and recorded impairment losses of $528 in the first quarter of 2024, an increase of $77 (17.1%) compared to $451 in the first quarter of 2023. The impairment losses in the first quarter of 2024 primarily relate to the remaining book value of assets due to our decision to cease operations at the Security facility. We also impaired various RNG equipment that was deemed obsolete for current operations. The first quarter of 2023 impairment relates to feedstock processing machine component at an RNG site that was not in operational use.

Other Expenses

Other expenses in the first quarter of 2024 was $105, a decrease of $1,577 (93.8%) compared to $1,682 in the first quarter of 2023. The decrease is primarily related to proceeds received from the sale of gas rights ahead of the fuel supply agreement expiration of our Security facility.

Income Tax Expense

Income tax expense for the three months ended March 31, 2024 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily due to the benefit from production tax credits.

The effective tax rate of 18.2% for the three months ended March 31, 2024 was lower than the rate for the three months ended March 31, 2023 of 76.1% primarily due to the increase in pre-tax income for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

Operating Income (Loss) for the Three Months Ended March 31, 2024 and 2023

Operating income in the first quarter of 2024 was $2,368, an increase of $16,534 (116.7%) compared to an operating loss of $14,166 in the first quarter of 2023. RNG operating income for the first quarter of 2024 was $11,580, an increase of $15,865 (370.2%) compared to an operating loss of $4,285 in the first quarter of 2023. Renewable Electricity Generation operating income for the first quarter of 2024 was $376, an increase of $623 (252.4%) compared to an operating loss of $247 for the first quarter of 2023.

Non-GAAP Financial Measures:

The following table presents EBITDA and Adjusted EBITDA, non-GAAP financial measures for each of the periods presented below. We present EBITDA and Adjusted EBITDA because we believe the measures assist investors in analyzing our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance. In addition, EBITDA and Adjusted EBITDA are financial measurements of performance that management and the board of directors use in their financial and operational decision-making and in the determination of certain compensation programs. EBITDA and Adjusted EBITDA are supplemental performance measures that are not required by or presented in accordance with GAAP. EBITDA and Adjusted EBITDA should not be considered alternatives to net income (loss) or any other performance measure derived in accordance with GAAP, or as an alternative to cash flows from operating activities or a measure of our liquidity or profitability.

The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income (loss), which is the most directly comparable GAAP measure, for the three months ended March 31, 2024 and 2023:

(1) We recorded an impairment loss of $528 and $451 for the three months ended March 31, 2024 and 2023, respectively. On February 18, 2024, for one of our REG sites, we entered into a bill of sale, assignment and assumption agreement to sell our rights to the existing fuel supply agreement and property back to the site host in advance of the fuel supply agreement termination date and received $1,000 in proceeds. The effective date of the sale, assignment and assumption agreement is October 1, 2024 We elected to cease operations prior to the assignment date and consequently the remaining book value of long lived assets and intangibles were impaired for $312. The remaining $216 impairment was for various RNG equipment that was deemed obsolete or inoperable for current operations. The first quarter 2023 impairment was for a feedstock processing machine component at an RNG site that was not in operational use.

Liquidity and Capital Resources

Sources of Liquidity

At March 31, 2024 and March 31, 2023, our cash and cash equivalents, net of restricted cash, was $63,277 and $78,043 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 March 31, 2024, we had debt before debt issuance costs of $62,000, compared to debt before debt issuance costs of $64,000 at December 31, 2023.

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

Amended Credit Agreement

On December 21, 2021, the Company entered into the Fourth Amendment with Comerica and certain other financial institutions. The current credit agreement, which is secured by a lien on substantially all of our assets and assets of certain of our subsidiaries, provides for a five-year $80,000 term loan, a five-year $120,000 revolving credit facility, and a $75,000 accordion feature.

As of March 31, 2024, $62,000 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 2024, then increases to $3,000 through 2026, with a final payment of $32,000 in late 2026 with an interest rate of 6.18% and 6.11% at March 31, 2024 and December 31, 2023, respectively. The revolving and term loans under the Amended Credit Agreement bear interest at the Bloomberg Short-Term Bank Yield Index Rate plus an applicable margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement).

The Amended Credit Agreement contains customary covenants applicable to us and certain of our subsidiaries, including financial covenants. The Amended Credit Agreement is subject to customary events of default, and contemplates that we would be in default if, for any fiscal quarter (x) the average monthly D3 RIN price (as determined in accordance with the Amended Credit Agreement) is less than $0.80 per RIN and (y) the consolidated EBITDA for such quarter is less than $6,000. Consolidated EBITDA is defined under the Amended Credit Agreement as net income plus (a) income tax expense, (b) interest expense, (c) depreciation, depletion, and amortization expense, (d) non-cash unrealized derivative expense and (e) any other extraordinary, unusual, or non-recurring adjustments to certain components of net income, as agreed upon by Comerica in certain circumstances.

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

• a Total Leverage Ratio (as defined in the Amended Credit Agreement) of not more than 3.25 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 March 31, 2024, we were in compliance with all applicable financial covenants under the Amended Credit Agreement.

The Amended Credit Agreement replaced our prior credit agreements with Comerica 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 Note 12— Debt to our unaudited condensed consolidated financial statements.

Capital Expenditures

We have historically funded our growth and capital expenditures with our working capital, cash flow from operations and debt financing. We expect our non-development 2024 capital expenditures to range between $14,000 and $17,000. Our 2024 capital plans include annual preventative maintenance expenditures, annual wellfield expansion projects, other specific facility improvements, and information technology 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, the 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 strategic growth opportunities. Included amongst these opportunities are: approximately up to six LFG RNG, 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 acquisition costs or development costs, or both. As we continue to explore strategic growth opportunities and while we have entered into nonbinding letters of intent for certain of these opportunities, we provide no assurances that our plans related to any or all of these strategic opportunities will progress to definitive agreements. We believe that our existing cash and cash equivalents, cash generated from operations, and credit availability under our Amended Credit Agreement would allow us to pursue and close on our identified strategic growth opportunities in addition to the previously discussed non-development and development capital expenditures.

Cash Flow

The following table presents information regarding our cash flows and cash equivalents for the three months ended March 31, 2024 and 2023:

For the first quarter of 2024, we generated $14,292 of cash provided by operating activities compared to $11,838 of cash used in operating activities in the first quarter of 2023. For the first quarter of 2024, income and adjustments to income from operating activities provided $9,357 compared to income and adjustments to income used $8,565 in first quarter of 2023. Included within income and adjustments to income from operating activities for the first quarter of 2024 was a decrease of $13,282 related to our deferred tax provision adjustment. Working capital and other assets and liabilities provided $4,935 in the first quarter of 2024 compared to working capital and other assets and liabilities using $3,274 in the first quarter of 2023.

Our net cash flows used in investing activities has historically focused on project development and facility maintenance. Our capital expenditures for the first three months of 2024 were $21,986, of which $12,010, $4,335, $1,718, $1,548, and $1,279 were related to the Montauk Ag Renewables in North Carolina, second Apex RNG facility, Blue Granite RNG project, Bowerman RNG project, and the ongoing development of the Pico facility digestion capacity increase, respectively. We completed a land acquisition in Turkey, NC for 42 acres during the first quarter of 2024 for $820.

Our net cash flows used in financing activities of $2,020 for the first three months of 2024 increase by $2 compared to cash used in financing activities in the first three months of 2023 of $2,018.

Contractual Obligations and Commitments

Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under GAAP. Our off-balance sheet arrangements are limited to the outstanding letters of credit described below. Although these arrangements serve a variety of our business purposes, 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.

The Company has contractual obligations involving asset retirement obligations. See Note 8 in the unaudited condensed consolidated financial statements for further information regarding the asset retirement obligations.

The Company has contractual obligations under our debt agreement, including interest payments and principal repayments. See Note 12 in the unaudited condensed consolidated financial statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. During the first three months of 2024, we had approximately $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 draw downs on these outstanding letters of credit. During the first three months of 2023, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $4,477.

The Company has contractual obligations involving operating leases. The Company leases office space and other office equipment under operating lease arrangements, expiring in various years through 2033. See Note 18 in the unaudited condensed consolidated financial statements for further information related to the lease obligations.

The Company has other contractual obligations associated with our fuel supply agreements. The expiration of these agreements range between 1-19 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,645.

Critical Accounting Policies and Estimates

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

Revenue Recognition

Our revenues are comprised of renewable energy and the related Environmental Attribute sales provided under a variety of short-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 the Company’s contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of the Company’s influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained.

RINs

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

RECs

We generate RECs through our production and conversion of landfill methane into Renewable Electricity in 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 fixed assets, intangibles, and tax credit carryforwards. The realization of deferred tax assets is dependent upon our ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in our financial statements or tax returns and forecasting future profitability by tax jurisdiction.

We evaluate our deferred tax assets at reporting periods on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of our deferred tax assets. We account for uncertain tax positions using a “more-likely-than-not” threshold for recognizing and resolving uncertain tax positions. The evaluation of uncertain tax positions is based on factors that include, but are not limited to, changes in tax law, the measurement of tax positions taken or expected to be taken in tax returns, the effective settlement of matters subject to audit, new audit activity and changes in facts or circumstances related to a tax position.

Intangible Assets

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

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

Our assessment of the recoverability of finite-lived and indefinite-lived intangible assets is determined by performing monitoring assessment of the future cash flows associated with the underlying gas rights agreements. The cash flows estimates are performed at the operating unit level and based on the average remaining length of the gas rights agreements. Based on our analysis, we concluded the 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 affect these estimates.

Finite-Lived Asset Impairment

In accordance with FASB ASC Topic 360, Property, Plant and Equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results, including considering project specific assumptions for long-term credit prices, escalated future project operating costs and expected site operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, (ii) third-party valuations, and/or (iii) information available regarding the current market value for such assets. We use our best estimates in making these evaluations and consider various factors, including future pricing and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates and the impact of such variations could be material. We identified discrete events and recorded impairment of $528 and $451 for the three months ended March 31, 2024 and 2023, respectively. See Note 3 in the unaudited condensed 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 of our unaudited condensed consolidated financial statements in this report.

There have been no material changes since our disclosure in Quantitative and Qualitative Disclosures About Market Risk included as Item 7A in our 2023 Annual Report.

Management’s Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act, as of the end of the period covered by this quarterly report. Disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Our management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Our management, including our principal executive officer and principal financial officer, after evaluating the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, concluded that as of such date, our disclosure controls and procedures were effective at a reasonable level of assurance.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

We face a number of risks that could materially and adversely affect our business, results of operations, cash flow, liquidity, or financial condition. A discussion of our risk factors can be found in Part I, “Item 1A Risk Factors” in our 2023 Annual Report any of which could have a material effect on us.