# Montauk Renewables, Inc.: Form 10-Q for the period ended Jun 30, 2023

- Company: [Montauk Renewables, Inc.](/companies/mntk.md) (CIK 1826600)
- Form: 10-Q
- Filed: 2023-08-09
- Accepted by EDGAR: Aug 9, 2023, 16:40 ET
- Period: 2023-06-30
- Accession: 0000950170-23-040687
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1826600/000095017023040687/mntk-20230630.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1826600/000095017023040687/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2023-06-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2023-04-01 to 2023-06-30 | $53.3m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Revenue | 6 months, 2023-01-01 to 2023-06-30 | $72.4m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Gross profit | 3 months, 2023-04-01 to 2023-06-30 | $18.9m | us-gaap:GrossProfit |
| Gross profit | 6 months, 2023-01-01 to 2023-06-30 | $9.9m | us-gaap:GrossProfit |
| Operating income | 3 months, 2023-04-01 to 2023-06-30 | $13.6m | us-gaap:OperatingIncomeLoss |
| Operating income | 6 months, 2023-01-01 to 2023-06-30 | −$610.0k | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2023-04-01 to 2023-06-30 | $711.0k | us-gaap:InterestExpense |
| Interest expense | 6 months, 2023-01-01 to 2023-06-30 | $2.4m | us-gaap:InterestExpense |
| Income tax | 3 months, 2023-04-01 to 2023-06-30 | $11.9m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 6 months, 2023-01-01 to 2023-06-30 | −$127.0k | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2023-04-01 to 2023-06-30 | $1.0m | us-gaap:NetIncomeLoss |
| Net income | 6 months, 2023-01-01 to 2023-06-30 | −$2.8m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2023-04-01 to 2023-06-30 | $0.01 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 6 months, 2023-01-01 to 2023-06-30 | −$0.02 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2023-04-01 to 2023-06-30 | $0.01 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 6 months, 2023-01-01 to 2023-06-30 | −$0.02 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2023-04-01 to 2023-06-30 | 142,045,498 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 6 months, 2023-01-01 to 2023-06-30 | 141,633,417 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 6 months, 2023-01-01 to 2023-06-30 | $6.1m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Cash and equivalents | at 2023-06-30 | $77.6m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2023-06-30 | $108.3m | us-gaap:AssetsCurrent |
| Total assets | at 2023-06-30 | $336.3m | us-gaap:Assets |
| Current liabilities | at 2023-06-30 | $35.0m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2023-06-30 | $108.5m | us-gaap:Liabilities |
| Long-term debt | at 2023-06-30 | $59.6m | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2023-06-30 | $7.9m | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2023-06-30 | $227.8m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 84,854 characters.

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 are expressed in thousands, except for per share amounts and MMBtu 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 2022 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 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 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

### Capital Development Summary

The following summarizes our ongoing development growth plans expected volume contribution, anticipated commencement of operations, and capital expenditure estimate, respectively:

| Development Opportunity | Estimated Volume Contribution (MMBtu/day) | Anticipated Commencement Date | Estimated Capital Expenditure |
| --- | ---: | --- | --- |
| Pico Digestion Capacity Increase | 300 | Second half of 2023 | Up to $18,000 |
| Second Apex RNG Facility | 2,100 | Second half of 2024 | $25,000-$35,000 |
| Blue Granite RNG Facility | 900 | 2025 | $25,000-$35,000 |
| Bowerman RNG Facility | 3,600 | 2026 | $85,000-$95,000 |

### Pico Digestion Capacity Increase

During the first quarter of 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 will be used starting 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.

Related to our Pico feedstock amendment, which increased the amount of feedstock supplied to the facility for processing over a one to three-year period (the “Pico Feedstock Amendment”), the dairy began delivering the first and second increases in feedstock during the third quarter of 2022 and we have 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 current expect to increase by five to ten percent once all increased feedstock deliveries have been received from the dairy. We completed the design of the digestion capacity project in the third quarter of 2022 and continue to incur capital expenditures related to the construction of the project. We currently expect the construction of the project to be functionally completed during the third quarter of 2023. We currently expect the dairy to begin delivering the final increase in feedstock volumes during 2024.

### Blue Granite RNG Project

In the first quarter of 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. Capital expenditures are ongoing and we continue to expect the project to be complete and become commercially operational in 2025.

### Bowerman RNG Project

In the second quarter of 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 a targeted commissioning date in 2026, we currently 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.

### 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 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 biochar (the “Montauk Ag Renewables Acquisition”).

We intend to deploy our patented emissions reduction reactor technology at our centralized conversion location in Turkey, NC. 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. 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 July 2023, we signed a REC agreement with Duke Energy (“Duke”) under which Duke will purchase the swine waste RECs from the conversion of swine waste feedstock into renewable energy as required under the North Carolina Renewable Energy Portfolio Standard. Once fully commissioned, we expect the facility to sell up to an estimated 47 RECs annually.

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. We continue to design and plan for the development of the Turkey, NC facility to be used for commercial production. We are evaluating uses for the Magnolia, NC location. Based on our current development timeline expectations, we do not expect to commence significant revenue generating activities until the first half of 2025. We intend to contract with additional farms to secure feedstock sources for future production processes.

### Carbon Dioxide Beneficial Use Opportunity

In July 2023, we entered into a letter of intent (“LOI”) with a North American subsidiary of Denmark-based European Energy (“EENA”) which reserves the use of the biogenic carbon dioxide (“CO2”) from our Texas facilities. Under the terms of LOI, we expect to contract CO2 volumes from facilities to EENA sufficient for EENA’s large scale production of E-methanol. Upon final agreement execution, the delivery term is expected to last up to 15 years with first delivery expected to begin in 2026. The LOI terms allow for our capital commitments to be based on choosing technology most suited for optimal delivery of the CO2 volumes to EENA. While we have a signed LOI, no assurances can be given that EENA will develop this large scale production and no assurances can be given that a definitive agreement will be executed.

### Key Trends

### Market Trends Affecting the Renewable Fuel Market

We believe demand for RNG produced from biogas remains strong due to increasing public policy initiatives focused on reducing greenhouse gas emissions, including methane, as well as continued public and private sector interest in the development of additional renewable energy sources to offset traditional fossil fuel energy sources.

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 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. We are not currently considering any conversion of electricity projects.

#### 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, subject to future EPA biogas regulatory reform.
- 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 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.

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 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, failure or degradation of our or a landfill operator’s equipment, our inability to fill open or newly created positions, 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.

- 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. We currently expect lower than historical volumes through the end of 2023.
- Our processing of increased Pico feedstock during 2023 may be impacted while we expand the receiving capacity associated with the Pico digestion capacity increase.
- *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.

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 sold all RINs generated and unsold as of June 30, 2023 and committed a significant portion of our expected 2023 third quarter RIN generation, though, we have not entered into forward sell commitments beyond the fourth quarter of 2023 RIN generation. The average realized price of these July 2023 commitments were priced at or above the average D3 RIN index price. 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. We expect increased general and administrative expenses associated with our ongoing development of Montauk Ag Renewables in 2023. 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 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 June 30, 2023 and 2022

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

*(in thousands, unless otherwise indicated)*

| Revenues | Three Months Ended June 30, 2023 | 2022 | Change% | Change |
| --- | ---: | ---: | ---: | ---: |
| Renewable Natural Gas Total Revenues | $48,609 | $64,566 | $(15,957) | (24.7%) |
| Renewable Electricity Generation Total Revenues | $4,647 | $4,329 | $318 | 7.3% |
| **RNG Metrics** |  |  |  |  |
| CY RNG production volumes (MMBtu) | 1,431 | 1,469 | (38) | (2.6%) |
| Less: Current period RNG volumes under fixed/floor-price contracts | (325) | (328) | 3 | (0.9%) |
| Plus: Prior period RNG volumes dispensed in current period | 418 | 372 | 46 | 12.4% |
| Less: Current period RNG production volumes not dispensed | (367) | (447) | 80 | (17.9%) |
| Total RNG volumes available for RIN generation (1) | 1,157 | 1,066 | 91 | 8.5% |
| **RIN Metrics** |  |  |  |  |
| Current RIN generation ( x 11.727) (2) | 13,568 | 12,499 | 1,069 | 8.6% |
| Less: Counterparty share (RINs) | (1,427) | (1,346) | (81) | 6.0% |
| Plus: Prior period RINs carried into current period | 8,266 | 4,394 | 3,872 | 88.1% |
| Less: CY RINs carried into next CY | — | — | — | — |
| Total RINs available for sale (3) | 20,407 | 15,547 | 4,860 | 31.3% |
| Less: RINs sold | (17,441) | (14,438) | (3,003) | 20.8% |
| RIN Inventory | 2,966 | 1,109 | 1,857 | 167.5% |
| RNG Inventory (volumes not dispensed for RINs) (4) | 418 | 447 | (29) | (6.5%) |
| Average Realized RIN price | $2.16 | $3.38 | $(1.22) | (36.1%) |
| **Operating Expenses** |  |  |  |  |
| Renewable Natural Gas Operating Expenses | $21,412 | $25,605 | $(4,193) | (16.4%) |
| Operating Expenses per MMBtu (actual) | $14.96 | $17.43 | $(2.47) | (14.2%) |
| REG Operating Expenses | $3,926 | $4,284 | $(358) | (8.4%) |
| $/MWh (actual) | $80.12 | $91.15 | $(11.02) | (12.1%) |
| **Other Metrics** |  |  |  |  |
| Renewable Electricity Generation Volumes Produced (MWh) | 49 | 47 | 2 | 4.3% |
| Average Realized Price $/MWh (actual) | $94.84 | $92.11 | $2.73 | 3.0% |

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

(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 for the periods set forth below:

|  | Three Months Ended June 30, 2023 | 2022 | Change% | Change |
| --- | ---: | ---: | ---: | ---: |
| **Total operating revenues** | $53,256 | $67,884 | $(14,628) | (21.5)% |
| **Operating expenses:** |  |  |  |  |
| Operating and maintenance expenses | 15,221 | 14,870 | 351 | 2.4% |
| General and administrative expenses | 8,745 | 8,753 | (8) | (0.1)% |
| Royalties, transportation, gathering and production fuel | 10,205 | 15,090 | (4,885) | (32.4)% |
| Depreciation, depletion and amortization | 5,251 | 5,134 | 117 | 2.3% |
| Impairment loss | 274 | 69 | 205 | 297.4% |
| Transaction costs | 3 | 5 | (2) | (42.2)% |
| **Total operating expenses** | 39,699 | 43,921 | (4,222) | (9.6)% |
| **Operating income** | $13,557 | $23,963 | $(10,406) | (43.4)% |
| **Other expenses:** | 621 | 246 | 375 | 152.5% |
| Income tax expense | 11,933 | 4,565 | 7,368 | 161.4% |
| **Net income** | $1,003 | $19,152 | $(18,149) | (94.8)% |

### Revenues for the Three Months Ended June 30, 2023 and 2022

Total revenues in the second quarter of 2023 were $53,256 a decrease of $14,628 (21.5%) compared to $67,884 in the second quarter of 2022. The decrease is primarily related to a decrease in pricing of gas commodity indices and average realized RIN pricing during the second quarter of 2023 compared to the second quarter of 2022. Gas commodity indices decreased 70.7% during the second quarter of 2023 compared to the second quarter of 2022. Realized RIN pricing decreased 36.1% during the second quarter of 2023 compared to the second quarter 2022. Also contributing to the decrease are gains recognized in the second quarter of 2022 of $1,644 which is related to a gas commodity hedge program that has since expired. The decrease is also driven by no revenues recognized in the second quarter of 2023 as compared to $1,059 in the second quarter of 2022 under our counter party sharing agreements.

### Renewable Natural Gas Revenues

We produced 1,431 MMBtu of RNG during the second quarter of 2023, a decrease of 38 MMBtu (2.6%) over the 1,469 MMBtu produced in the second quarter of 2022. Our Rumpke facility produced 53 fewer MMBtu in the second quarter of 2023 compared to the second quarter of 2022 as a result of process equipment failure in the second quarter of 2023 which temporarily impacted production. The process equipment which failed has been repaired. Also contributing to the decrease is our Pico facility which produced 16 fewer MMBtu in the second quarter of 2023 compared to the second quarter of 2022 as a result of feedstock processing challenges in the second quarter of 2023. Offsetting the decrease is our Galveston facility which produced 22 more MMBtu in the second quarter of 2023 as compared to the second quarter of 2022 as a result of process equipment modification.

Revenues from the Renewable Natural Gas segment in the second quarter of 2023 were $48,609, a decrease of $15,957 (24.7%) compared to $64,566 in the second quarter of 2022. Average commodity pricing for natural gas for the second quarter of 2023 was $2.10 per MMBtu, 70.7% lower than the second quarter of 2022. During the second quarter of 2023, we self-monetized 17,441 RINs, representing a 3,003 increase (20.8%) compared to 14,438 in the second quarter of 2022. Average pricing realized on RIN sales during the second quarter of 2023 was $2.16 as compared to $3.38 in the second quarter of 2022, a decrease of 36.1%. This compares to the average D3 RIN index price for the second quarter of 2023 of $2.16 being approximately 32.9% lower than the average D3 RIN index price in the second quarter of 2022. At June 30, 2023, we had approximately 367 MMBtu available for RIN generation and we had approximately 2,966 RINs generated and unsold. At June 30, 2022, we had approximately 447 MMBtu available for RIN generation and 1,109 RINs generated and unsold.

### Renewable Electricity Generation Revenues

We produced approximately 49 MWh in Renewable Electricity in the second quarter of 2023, an increase of 2 MWh (4.3%) from 47 MWh in the second quarter of 2022. Our Bowerman facility produced 1 MWh more in the second quarter of 2023 compared to the second quarter of 2022 as a result of preventative engine maintenance performed during the second quarter of 2022. Our Security facility produced approximately 1 MWh more in the second quarter of 2023 compared to the second quarter of 2022 due to engine maintenance completed in the second quarter of 2022.

Revenues from Renewable Electricity facilities in the second quarter of 2023 were $4,647, an increase of $318 (7.3%) compared to $4,329 in the second quarter of 2022. The increase is primarily driven by the increase in our Bowerman facility production volumes.

In the second quarter of 2023, 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 99.0% in the second quarter of 2022. This provides the Company with certainty of price resulting from our Renewable Electricity sites.

### Corporate Analysis

While we did not have any gas commodity hedge programs in the second quarter of 2023, our gas commodity hedge program during the second quarter of 2022 was priced as rates below actual index prices resulting in realized losses of $1,644.

### Expenses for the Three Months Ended June 30, 2023 and 2022

### General and Administrative Expenses

Total general and administrative expenses were $8,745 for the second quarter of 2023, a decrease of $8 (0.1%) compared to $8,753 for the second quarter of 2022. Our general and administrative expense for the second quarter of 2023 increased approximately $1,074 compared to the second quarter of 2022 associated with the 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. Offsetting this increase is a decrease in stock-based compensation of approximately $696 from forfeited stock awards in the second quarter of 2023. The decrease was partially offset by the April 2023 grant of stock option awards. Our professional fees were $679 in the second quarter of 2023, a decrease of $635 (48.3%) compared to $1,314 for the second quarter of 2022. Finally, our rent expense for the second quarter was $176, an increase $82 (87.2%) compared to $94 for the second quarter of 2022 associated with our new headquarters lease.

### Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in the second quarter of 2023 were $11,697, an increase of $716 (6.5%) as compared to $10,981 in the second quarter of 2022. Our Apex facility operating and maintenance expenses increased approximately $380 as a result of timing of preventative maintenance, increased waste disposal costs, and utility expenses in the second quarter of 2023 as compared to second quarter of 2022. Our Atascocita facility operating maintenance expenses increased approximately $144 as a result of wellfield operational enhancements and timing of preventative maintenance in the second quarter of 2023 as compared to the second quarter of 2022. Our Coastal facility operating and maintenance expenses increased approximately $144 as a result of wellfield operational enhancements. Our total RNG facilities reported reduced utility expenses of approximately $409 in the second quarter of 2023 as compared to the second quarter of 2022.

Royalties, transportation, gathering and production fuel expenses for the Company’s RNG facilities for the second quarter of 2023 were $9,715, a decrease of $4,909 (33.6%) compared to $14,624 in the second quarter of 2022. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 20.0% for the second quarter of 2023 from 22.6% in the second quarter of 2022. The decrease in royalties, transportation, gathering and production fuel expenses is primarily related to the decrease in RNG revenues in the second quarter of 2023 compared to the second quarter of 2022.

### Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in the second quarter of 2023 were $3,436, a decrease of $382 (10.0%) compared to $3,818 in the second quarter of 2022. The decrease is primarily related to scheduled preventative maintenance at our Bowerman facility, which was approximately $677 higher in the second quarter of 2022 compared to the second quarter of 2023. Our Tulsa facility operating and maintenance expenses increased approximately $217 as a result of scheduled preventative maintenance and wellfield maintenance. Our Turkey Creek facility operating and maintenance expenses increased approximately $151 as a result of non-capitalizable costs from Montauk Ag Renewables.

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the second quarter of 2023 were $490, an increase of $24 (5.2%) compared to $466 in the second quarter of 2022. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses decreased to 10.5% from 10.8%.

### Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in the second quarter of 2023 were $10,205, a decrease of $4,885 (32.4%) compared to $15,090 in the second quarter of 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.

### Depreciation

Depreciation and amortization in the second quarter of 2023 was $5,251, an increase of $117 (2.3%) compared to $5,134 in the second quarter of 2022. The increase is associated with the payments related to the Pico Feedstock Agreement.

### Impairment loss

We calculated and recorded an impairment loss of $274 in the second quarter of 2023, an increase of $205 (297.4%) compared to $69 in the second quarter of 2022. The impairments in the second quarter of 2023 were for specifically identified RNG machinery and equipment that were no longer in operational use. The impairments recorded in the second quarter of 2022 relate to an amended customer contract ($27) and miscellaneous capital assets no longer in use under current operations ($42).

### Other Expenses

Other expenses in the second quarter of 2023 was $621, an increase of $375 (152.5%) compared to other expenses of $246 in the second quarter of 2022. The increase is primarily related to an increase in interest expense of $440 from the second quarter of 2023 compared to the second quarter of 2022.

### Income Tax Expense

Income tax expense for the three months ended June 30,2023 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21% primarily due to the benefit from production tax credits.

The effective tax rate of 92.2% for the three months ended June 30, 2023 was higher than the rate for the three months ended June 30, 2022 of 19.2% primarily due to the increase in forecasted income in 2023 with respect to the annual estimated tax credit benefit, which remained the same from the first quarter of 2023.

### Operating Income (Loss) for the Three Months Ended June 30, 2023 and 2022

Operating income in the second quarter of 2023 was $13,557, a decrease of $10,406 (43.4%) compared to $23,963 in the second quarter of 2022. RNG operating income for the second quarter of 2023 was $23,029, a decrease of $12,226 (34.7%) compared to $35,255 in the second quarter of 2022. Renewable Electricity Generation operating loss for the second quarter of 2023 was $576, a decrease of $820 (58.7%) compared $1,396 for the second quarter of 2022.

### Comparison of Six Months Ended June 30, 2023 and 2022

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

*(in thousands, unless otherwise indicated)*

| Revenues | Six Months Ended June 30, 2023 | 2022 | Change% | Change |
| --- | ---: | ---: | ---: | ---: |
| Renewable Natural Gas Total Revenues | $63,393 | $97,233 | $(33,840) | (34.8%) |
| Renewable Electricity Generation Total Revenues | $9,016 | $8,300 | $716 | 8.6% |
| **RNG Metrics** |  |  |  |  |
| CY RNG production volumes (MMBtu) | 2,783 | 2,838 | (55) | (1.9%) |
| Less: Current period RNG volumes under fixed/floor-price contracts | (630) | (639) | 9 | (1.4%) |
| Plus: Prior period RNG volumes dispensed in current period | 368 | 372 | (4) | (1.1%) |
| Less: Current period RNG production volumes not dispensed | (367) | (447) | 80 | (17.9%) |
| Total RNG volumes available for RIN generation (1) | 2,154 | 2,124 | 30 | 1.4% |
| **RIN Metrics** |  |  |  |  |
| Current RIN generation ( x 11.727) (2) | 25,268 | 24,907 | 361 | 1.4% |
| Less: Counterparty share (RINs) | (2,651) | (2,562) | (89) | 3.5% |
| Plus: Prior period RINs carried into current period | 739 | 140 | 599 | 427.9% |
| Less: CY RINs carried into next CY | — | — | — | — |
| Total RINs available for sale (3) | 23,356 | 22,485 | 871 | 3.9% |
| Less: RINs sold | (20,390) | (20,923) | 533 | (2.5%) |
| RIN Inventory | 2,966 | 1,562 | 1,404 | 89.9% |
| RNG Inventory (volumes not dispensed for RINs) (4) | 367 | 447 | (80) | (17.9%) |
| Average Realized RIN price | $2.28 | $3.39 | $(1.11) | (32.7%) |
| **Operating Expenses** |  |  |  |  |
| Renewable Natural Gas Operating Expenses | $36,220 | $41,950 | $(5,730) | (13.7%) |
| Operating Expenses per MMBtu (actual) | $13.01 | $14.78 | $(1.77) | (12.0%) |
| REG Operating Expenses | $7,255 | $8,021 | $(766) | (9.5%) |
| $/MWh (actual) | $76.37 | $87.18 | $(10.81) | (12.4%) |
| **Other Metrics** |  |  |  |  |
| Renewable Electricity Generation Volumes Produced (MWh) | 95 | 92 | 3 | 3.3% |
| Average Realized Price $/MWh (actual) | $94.91 | $90.22 | $4.69 | 5.2% |

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

(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 for the periods set forth below:

|  | Six Months Ended June 30, 2023 | 2022 | Change% | Change |
| --- | ---: | ---: | ---: | ---: |
| **Total operating revenues** | $72,409 | $100,055 | $(27,646) | (27.6)% |
| **Operating expenses:** |  |  |  |  |
| Operating and maintenance expenses | 29,402 | 28,072 | 1,330 | 4.7% |
| General and administrative expenses | 18,220 | 17,248 | 972 | 5.6% |
| Royalties, transportation, gathering and production fuel | 14,138 | 22,296 | (8,158) | (36.6)% |
| Depreciation, depletion and amortization | 10,447 | 10,286 | 161 | 1.6% |
| Gain on insurance proceeds | — | (313) | 313 | (100.0)% |
| Impairment loss | 726 | 120 | 606 | 504.7% |
| Transaction costs | 86 | 32 | 54 | 168.5% |
| **Total operating expenses** | 73,019 | 77,741 | (4,722) | (6.1)% |
| **Operating (loss) income** | $(610) | $22,314 | $(22,924) | (102.7)% |
| **Other expenses (income):** | 2,302 | (30) | 2,332 | (7,774.5)% |
| Income tax (benefit) expense | (127) | 4,307 | (4,434) | (102.9)% |
| **Net (loss) income** | $(2,785) | $18,037 | $(20,822) | (115.4)% |

### Revenues for the Six Months Ended June 30, 2023 and 2022

Total revenues in the first six months of 2023 were $72,409 a decrease of $27,646 (27.6%) compared to $100,055 in the first six months of 2022. The decrease is primarily related to a decrease in pricing of gas commodity indices and average realized RIN pricing in the first six months of 2023 compared to the first six months of 2022. Gas commodity indices decreased 54.5% during the first six months of 2023 compared to the first six months of 2022. Realized RIN pricing decreased 32.7% during the first six months of 2023 compared to the first six months of 2022.

### Renewable Natural Gas Revenues

We produced 2,783 MMBtu of RNG during the first six months of 2023, a decrease of 55 MMBtu (1.9%) over the 2,838 MMBtu produced in the first six months of 2022. Our Rumpke facility produced 36 fewer MMBtu in the first six months of 2023 compared to the first six months of 2022 as a result of process equipment failure in the first six months of 2023. Also contributing to the decrease is our Pico facility which produced 27 fewer MMBtu in the first six months of 2023 compared to the first six months of 2022 as a result of operational feedstock processing challenges in the first six months of 2023. Our Apex facility produced 14 MMBtu more in the first six months of 2023 compared to the first six months of 2022 as a result of process equipment failure in the first quarter of 2022.

Revenues from the Renewable Natural Gas segment in the first six months of 2023 were $63,393, a decrease of $33,840 (34.8%) compared to $97,233 in the first six months of 2022. Average commodity pricing for natural gas for the first six months of 2023 was $2.76 per MMBtu, 54.5% lower than the first six months of 2022. During the first six months of 2023, we self-monetized 20,390 RINs, representing a 533 decrease (2.5%) compared to 20,923 in the first six months of 2022. Average pricing realized on RIN sales during the first six months of 2023 was $2.28 as compared to $3.39 in the first six months of 2022, a decrease of 32.7%. This compares to the average D3 RIN index price for the first six months of 2023 of $2.10 being approximately 35.1% lower than the average D3 RIN index price in the first six months of 2022. At June 30, 2023, we had approximately 367 MMBtu available for RIN generation and we had approximately 2,966 RINs generated and unsold. At June 30, 2022, we had approximately 447 MMBtu available for RIN generation and 1,562 RINs generated and unsold. Of the RINs generated and unsold as of June 30,2023, we entered into commitments to transfer all RINs generated and unsold in July 2023, at average realized prices in excess of the July 2023 average D3 RIN index price of $3.05.

### Renewable Electricity Generation Revenues

We produced approximately 95 MWh in Renewable Electricity in the first six months of 2023, an increase of 3 MWh (3.3%) from 92 MWh in the first six months of 2022. Our Bowerman facility produced 4 MWh more in the first six months of 2023 compared to the first six months of 2022 as a result of preventative engine maintenance performed during the first six months of 2022.

Revenues from Renewable Electricity facilities in the first six months of 2023 were $9,016, an increase of $716 (8.6%) compared to $8,300 in the first six months of 2022. The increase is primarily driven by the increase in our Bowerman facility production volumes.

In the first six months of 2023, 99.9% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs, as compared to 99.0% in the first six months of 2022. This provides the Company with certainty of price resulting from our Renewable Electricity sites.

### Corporate Analysis

While we did not have any gas commodity hedge programs in the first six months of 2023, our gas commodity hedge program during the first six months of 2022 was priced at rates below actual index prices resulting in realized losses of $1,807.

### Expenses for the Six Months Ended June 30, 2023 and 2022

### General and Administrative Expenses

Total general and administrative expenses were $18,220 for the first six months of 2023, an increase of $972 (5.6%) compared to $17,248 for the first six months of 2022. Our general and administrative expense for the first six months of 2023 increased approximately $2,211 compared to the first six months of 2022 associated with the 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. Our stock-based compensation expense increased as a result of the April 2023 grant of stock option awards. Partially offsetting this increase is a reversal of approximately $1,024 stock based compensation expense related to forfeited stock awards. Finally, our rent expense was $352 for the first six months of 2023, an increase $168 (91.3%) compared to $184 for the first six months 2022.

### Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in the first six months of 2023 were $23,040, an increase of $2,500 (12.2%) as compared to $20,540 in the first six months of 2022. Our Apex facility operating and maintenance expenses increased approximately $622 as a result of timing of preventative maintenance, increased waste disposal costs and utility costs in the first six months of 2023 as compared to first six months of 2022. Our Pico facility operating and maintenance expenses increased approximately $489 as a result of the Pico Capacity Expansion project and utility costs in the first six months of 2023 as compared to first six months of 2022. Our Rumpke facility operating and maintenance expenses increased approximately $434 as a result of timing of preventative maintenance and utility costs in the first six months of 2023 as compared to first six months of 2022. Our Galveston operating and maintenance expenses increased approximately $291 as a result of timing of preventative maintenance and wellfield operational enhancements costs in the first six months of 2023 as compared to first six months of 2022. Our McCarty operating and maintenance expenses increased approximately $273 as a result of timing of preventative maintenance in the first six months of 2023 as compared to first six months of 2022. Total RNG facilities utility costs decreased $322 during the first six months of 2023 as compared to the first six months of 2022.

Royalties, transportation, gathering and production fuel expenses for the Company’s RNG facilities for the first six months of 2023 were $13,180, a decrease of $8,230 (38.4%) compared to $21,410 in the first six months of 2022. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 20.8% for the first six months of 2023 from 22.0% in the first six months of 2022. The decrease in royalties, transportation, gathering and production fuel expenses is primarily related to the decrease in RNG revenues in the first six months of 2023 compared to the first six months of 2022.

### Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in the first six months of 2023 were $6,297, a decrease of $837 (11.7%) compared to $7,134 in the first six months of 2022. The decrease is primarily related to scheduled preventative maintenance at our Bowerman facility, which was approximately $1,600 higher in the first six months of 2022 compared to the first six months of 2023. Our Tulsa facility operating and maintenance expenses increased approximately $323 as a result of scheduled preventative maintenance and wellfield maintenance. Our Turkey Creek facility operating and maintenance expenses increased approximately $262 as a result of the non-capitalizable costs of Montauk Ag Renewables.

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the first six months of 2023 were $958, an increase of $71 (8.0%) compared to $887 in the first six months of 2022. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses decreased to 10.6% from 10.7%.

### Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in the first six months of 2023 were $14,138, a decrease of $8,158 (36.6%) compared to $22,296 in the first six months of 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.

### Depreciation

Depreciation and amortization in the first six months of 2023 was $10,447, an increase of $161 (1.6%) compared to $10,286 in the first six months of 2022. The increase is associated with the payments related to the Pico Feedstock Agreement.

### Impairment loss

We calculated and recorded an impairment loss of $726 in the first six months of 2023, an increase of $606 (504.7%) compared to $120 in the first six months of 2022. The 2023 impairments were for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use. The 2022 impairments recorded relate to computer software and hardware no longer being utilized ($51), an amended customer contract ($27) and miscellaneous capital assets no longer in use under current operations ($42).

### Other Expense (Income)

Other expense in the first six months of 2023 was $2,302, a decrease of $2,332 (7,774.5%) compared to other income of $30 in the first six months of 2022. The increase is primarily related to an increase in interest expense of $2,083 from the first six months of 2023 compared to the first six months of 2022.

### Income Tax Expense

Income tax expense for the six months ended June 30, 2023 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21% primarily due to the benefit from production tax credits.

The effective tax rate of 4.4% for the six months ended June 30, 2023 was lower than the rate for the six months ended June 30, 2022 of 19.3% primarily due to discrete tax expense recorded in 2023. The June 30, 2023 rate also includes utilization of production tax credits.

### Operating Loss (Income) for the Six Months Ended June 30, 2023 and 2022

Operating loss in the first six months of 2023 was $610, a decrease of $22,924 (102.7%) compared to operating profit of $22,314 in the first six months of 2022. RNG operating profit for the first six months of 2023 was $18,745, a decrease of $29,466 (61.1%) compared to operating profit of $48,211 in the first six months of 2022. Renewable Electricity Generation operating loss for the first six months of 2023 was $823, a decrease of $1,734 (67.8%) compared $2,557 for the first six months of 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 (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, which is the most directly comparable GAAP measure, for the three months ended June 30, 2023 and 2022:

|  | Three Months Ended June 30, 2023 | 2022 |
| --- | ---: | ---: |
| Net income | $1,003 | $19,152 |
| Depreciation, depletion and amortization | 5,251 | 5,134 |
| Interest expense | 711 | 271 |
| Income tax expense | 11,933 | 4,565 |
| **Consolidated EBITDA** | 18,898 | 29,122 |
| Impairment loss (1) | 274 | 69 |
| Transaction costs | 3 | 5 |
| Non-cash hedging charges | — | (1,644) |
| **Adjusted EBITDA** | **$19,175** | **$27,552** |

(1) During the three months ended June 30, 2023, we recorded an impairment loss of $274 for specifically identified RNG machinery and equipment that were no longer in operational use. During the three months ended June 30, 2022, we recorded an impairment loss of $69 related to an amended customer contract and miscellaneous capital assets no longer in use under current operations.

The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net (loss) income, which is the most directly comparable GAAP measure, for the six months ended June 30, 2023 and 2022:

|  | Six Months Ended June 30, 2023 | 2022 |
| --- | ---: | ---: |
| Net (loss) income | $(2,785) | $18,037 |
| Depreciation, depletion and amortization | 10,447 | 10,286 |
| Interest expense | 2,386 | 303 |
| Income tax (benefit) expense | (127) | 4,307 |
| **Consolidated EBITDA** | 9,921 | 32,933 |
| Impairment loss (1) | 726 | 120 |
| Net loss (gain) of sale of assets | 37 | (293) |
| Transaction costs | 86 | 32 |
| Non-cash hedging charges | — | 1,807 |
| **Adjusted EBITDA** | **$10,770** | **$34,599** |

(1) During the six months ended June 30, 2023, we recorded an impairment loss of $726 for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use. During the six months ended June 30, 2022, we recorded an impairment loss of $120 related to computer software and hardware no longer being utilized, an amended customer contract and miscellaneous capital assets no longer in use under current operations

### Liquidity and Capital Resources

### Sources of Liquidity

At June 30, 2023 and June 30, 2022, our cash and cash equivalents, net of restricted cash, was $77,630 and $72,195 respectively. We intend to fund near-term 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 at least the next 12 months. However, we are subject to business and operational risks that could adversely affect our cash flows and liquidity.

At June 30, 2023, we had debt before debt issuance costs of $68,000, compared to debt before debt issuance costs of $72,000 at December 31, 2022.

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

|  | June 30, 2023 | December 31, 2022 |
| --- | ---: | ---: |
| Term loan | $68,000 | 72,000 |
| Revolving credit facility | — | — |
| Debt before debt issuance costs | $68,000 | $72,000 |

### 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 and a five-year $120,000 revolving credit facility.

As of June 30, 2023, $68,000 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 6.49% and 4.12% at June 30, 2023 and December 31, 2022, 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 3.50 to 1.00 as of the end of any fiscal quarter from December 31, 2021 through June 29, 2023, 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 June 30, 2023, 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 2023 capital expenditures to range between $15,000 and $19,000. Our 2023 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 2023 development capital expenditures will range between $70,000 and $100,000. The majority of our 2023 development capital expenditures are related to our Pico digestion capacity increase, the ongoing development of Montauk Ag Renewables, our second Apex facility, Blue Granite RNG and our recently announced Bowerman RNG 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 eight LFG RNG, ADG RNG, and waste water treatment to RNG 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 six months ended June 30, 2023 and 2022:

| Net cash provided by (used in): | Six Months Ended June 30, 2023 | 2022 |
| --- | ---: | ---: |
| Operating activities | $6,077 | $26,772 |
| Investing activities | (29,587) | (3,747) |
| Financing activities | (4,036) | (4,095) |
| Net (decrease) increase in cash and cash equivalents | (27,546) | 18,930 |
| Restricted cash, end of the period | 430 | 347 |
| Cash and cash equivalents, end of period | 78,060 | 72,542 |

For the first six months of 2023, we generated $6,077 of cash provided by operating activities compared to $26,772 of cash provided by operating activities in the first six months of 2022. For the first six months of 2023, income and adjustments to income from operating activities provided $12,624 compared to income and adjustments to income providing $38,157 in first six months of 2022. Included within income and adjustments to income from operating activities for the first six months of 2023 was an increase of $12,797 related to the deferred tax provision adjustment. Working capital and other assets and liabilities provided $6,547 in the first six months of 2023 compared to working capital and other assets and liabilities providing $11,385 in the first six months of 2022.

Our net cash flows used in investing activities has historically focused on project development and facility maintenance. Our capital expenditures for the first six months of 2023 were $29,587, of which $9,772, $4,977, $6,745, and 2,997 were related to the ongoing development of the Pico facility digestion capacity increase, the Montauk Ag Renewables in North Carolina, second Apex RNG facility, and Blue Granite RNG project, respectively.

Our net cash flows used in financing activities of $4,036 for the first six months of 2023 decreased by $59 compared to cash used in financing activities in the first six months of 2022 of $4,095.

### 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 six months of 2023, we had approximately $2,405 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 six months of 2022, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $3,905.

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 3-20 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,635.

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

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

### 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 $726 and $120 for the six months ended June 30, 2023 and 2022, 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.

## Market risk

As filed, 165 characters.

There have been no material changes since our disclosure in Quantitative and Qualitative Disclosures About Market Risk included as Item 7A in our 2022 Annual Report.

## Controls and procedures

As filed, 1,593 characters.

### 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.

## Risk factors

As filed, 306 characters.

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 2022 Annual Report any of which could have a material effect on us.

Filed Aug 9, 2023.
Source: SEC EDGAR, the filing index for accession 0000950170-23-040687. Last ingested by Listed: Oct 24, 2026, 15:15 ET. No prices; not investment advice.