Montauk Renewables, Inc. (MNTK, NASDAQ)
Industry: Basic Materials / Specialty Chemicals
Annual report, fiscal year 2022


## MONTAUK
RENEWABLES

2022 Annual Report



M ontauk is a leader in renewable energy development from biogas. We specialize in developing projects which collectively benefit all parties involved. Our portfolio is diversified and positioned to withstand market fluctuations, as well as to capture emerging trends and future demand.

## 2022 Financial Performance Snapshot

Revenue

Adjusted EBITDA

$205.6M
(38.8% increase over 2021)

$70.5M
(compared to $27.9M in 2021)

Production

5,522,000
MMBtu of renewable
natural gas
190,000
MWh of renewable
electricity

D3 RIN Generation

~49.7M
D3 RINs generated from
RNG volumes available
(4.1% increase over 2021)

Production Volumes Mix











* These financial highlights should be read in conjunction with the disclosures in the accompanying 2022 Form 10-K, including the audited financial statements. Adjusted EBITDA is a non-GAAP financial measure. For additional information regarding this metric and reconciliation to GAAP, please see Item 7 “Non-GAAP Financial Measures” of the accompanying 2022 Form 10-K and the reconciliations at the end of this Report.



# Letter from our President and Chief Executive Officer

## Dear Fellow Stockholders,

After completing the 2021 US IPO, Montauk Renewables focused its efforts during 2022 on ensuring that the Company would be well positioned to fund its selected development opportunities. We refinanced our credit agreement providing a combined $200 million capacity. The strategically timed selling of D3 RINs approximately 9% above the 2022 average D3 RIN index contributed to the over $80 million in cash generated from operations. Favorable pricing throughout 2022 saw Montauk exceed $200 million in revenues.

Our business strategy planning objectives focus on the following core business areas that we believe currently represent the greatest growth opportunities for Montauk Renewables:

• Continued facility capacity expansion supporting LFG for RNG production;

• Continued development into agricultural feedstocks for RNG production;

• Focused early-stage development into diversified agricultural feedstocks for either RNG or REG production; and

• Optimization and enhancement of existing assets and portfolio.

The end of 2022 brought exciting developments with the US EPA release of the RVO setting volume obligations for three years, 2023 through 2025, for the first time. While uncertainty exists with this RVO as the final rule will not be issued until June 2023, the proposed RVO set volumes for cellulosic biofuel at 720, 1,420, and 2,130 million RINs for the three years 2023, 2024, and 2025, respectively. For the first time, the EPA included volumes for eRINs generated from renewable electricity of 0, 600, and 1,200 million eRINs for the three years 2023, 2024, and 2025, respectively.

Throughout our more than 30 years of developing and operating renewable energy projects, we have experienced the cyclical nature of the renewable gas industry. Our history spans having renewable electricity producing sites and converting those sites to RNG production. We are currently in various stages of registering our existing renewable electricity facilities to be qualified to generate eRINs. We also believe our prudent development strategy, when coupled with our history, positions us to support the generation of eRINs as considered under the RVO.

While our recent development has focused on agricultural feedstocks with our Pico expansion project and our Montauk Ag Renewables acquisition, we were pleased to announce that we were awarded what will become our 13th LFG RNG facility. This site will continue to expand our presence with our entrance into South Carolina. Also, the California Air Resource Board certified our Pico facility Carbon Intensity Score. We will begin to release gas from storage and expect to generate Low Carbon Fuel Standards credit revenues during 2023. As the voluntary RNG market continues to develop, we are considering different approaches with our RNG production as we evaluate entrance into the voluntary RNG market. Finally, we expect to continue the momentum in North Carolina that our 2023 signing of a receipt interconnection agreement has started.

While the index price environment we have experienced to start 2023 is more challenging than 2022, our experienced and committed employees position us to meet these challenges. We are excited to enter what we consider to be our next phase of strategic growth of Montauk during 2023.

Thank you for your continued support as a Montauk Renewables investor.

Sincerely,



## Sean McClain

President and Chief Executive Officer

For more information regarding certain factors that could cause future results to differ, possibly materially, from historical performance or those anticipated in forward-looking statements, see “Cautionary Note Regarding Forward-Looking Statements” and the “Risk Factors” section of the accompanying 2022 Form 10-K.



## Montauk Ag Asset Acquisition

We began to relocate the reactor in Magnolia, NC to the Turkey, NC location to centralize processing at one location. Our Turkey location has been accepted 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. Due to our consolidation of operations at the Turkey, NC location and based on our current expectations related to commercial operations, we have paused our registration process to obtain NREF status for the Turkey, NC location.

## Pico Energy Capacity Expansion Project

We made $2.5 million payments under the terms of our amended feedstock agreement due to the receipt of the first and second increases in feedstock. We have improved our existing digestion process and implemented water management improvements. Finally, we completed the design phase of the capacity expansion.

## Second Apex RNG Facility

We announced the planned construction of a second RNG processing facility at the Apex landfill. This project is being driven by projections in biogas feedstock availability from the host landfill. We anticipate an approximate 40% increase in RNG processing capacity with the addition of the second facility. This expansion is expected to increase daily production approximately 2,100 MMBtu per day and expand the infrastructure for the conversion of LFG to RNG.

## Raeger Capital Improvement Project

We commenced a capital improvement project to make upgrades to our Raeger facility that will increase production. This facility is currently being impacted by requirements to meet federal pipeline tariffs which limit the oxygen content of product gas. The pipeline tariffs have resulted in limitations in our ability to process all existing feedstock.

## Our Project Footprint

<table><tr><td colspan="4">Renewable Natural Gas</td></tr><tr><td>Site</td><td>COD(1)</td><td>Capacity (MMBtu/day) (2)</td><td>Source</td></tr><tr><td>Rumpke Cincinnati, OH</td><td>1986</td><td>7,271</td><td>Landfill</td></tr><tr><td>Atascocita Humble, TX</td><td>2002*/2018</td><td>5,570</td><td>Landfill</td></tr><tr><td>McCarty Houston, TX</td><td>1986</td><td>4,415</td><td>Landfill</td></tr><tr><td>Apex Amsterdam, OH</td><td>2018</td><td>2,673</td><td>Landfill</td></tr><tr><td>Monroeville, PA</td><td>2004</td><td>2,372</td><td>Landfill</td></tr><tr><td>Valley Harrison City, PA</td><td>2004</td><td>2,372</td><td>Landfill</td></tr><tr><td>Galveston Galveston, TX</td><td>2019</td><td>1,857</td><td>Landfill</td></tr><tr><td>Raeger Johnston, PA</td><td>2006</td><td>1,857</td><td>Landfill</td></tr><tr><td>Shade Cairnbrook, PA</td><td>2007</td><td>1,857</td><td>Landfill (3)</td></tr><tr><td>Coastal Plains Alvin, TX</td><td>2020</td><td>1,775</td><td>Landfill</td></tr><tr><td>Southern Davidsville, PA</td><td>2007</td><td>928</td><td>Landfill</td></tr><tr><td>Pico Jerome, ID</td><td>2020</td><td>903</td><td>Livestock (Diary)</td></tr><tr><td>Total Capacity (MMBtu/day)</td><td></td><td>33,850</td><td></td></tr></table>



<table><tr><td colspan="4">Renewable Electricity Generation</td></tr><tr><td>Site</td><td>COD (1)</td><td>Capacity (MW)</td><td>Source</td></tr><tr><td>Bowerman</td><td></td><td></td><td></td></tr><tr><td>Irvine, CA</td><td>2016</td><td>23.6</td><td>Landfill</td></tr><tr><td>Security</td><td></td><td></td><td></td></tr><tr><td>Houston, TX</td><td>2003</td><td>3.4</td><td>Landfill</td></tr><tr><td>AEL</td><td></td><td></td><td></td></tr><tr><td>Sand Spring, OK</td><td>2013</td><td>3.2</td><td>Landfill</td></tr><tr><td>Total Capacity (MW)</td><td></td><td>30.2</td><td></td></tr></table>

Renewable Electricity Project
Renewable Natural Gas Project

(1) “COD” refers to the commercial operation date of each site.
(2) This is equivalent to the project’s design capacity and assumes inlet methane content of 56% for all sites other than Pico, which assumes inlet methane content of 62%, and process efficiency of 91%.
(3) All of our landfill sites are accepting waste except our Shade site. Our Shade site is closed to accepting new waste, but is currently expected to continue to generate a commercial level of RNG for an additional ten years. Our operating RNG projects have an average expected remaining useful life of approximately 18 years.



# UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2022;

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 001-39919

## MONTAUK RENEWABLES, INC.

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation or organization)

85-3189583
(I.R.S. Employer Identification No.)

5313 Campbells Run Road, Suite 200 Pittsburgh, Pennsylvania
(Address of principal executive offices)
15205
(Zip Code)

Registrant’s telephone number, including area code: (412) 747-8700

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol

Name of each exchange on which registered

Common Stock, par value $0.01 per share

MNTK

The Nasdaq Capital Market

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T ( \( §232.405 \)  of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer ☐

Non-accelerated filer ☐

Accelerated Filer ☒

Smaller Reporting Company ☐

Emerging Growth Company ☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

The aggregate market value of common stock held by non-affiliates of the registrant, based on the closing price for the registrant’s common stock on the Nasdaq Capital Market on June 30, 2022, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $474,438,279.

The number of outstanding shares of the registrant’s common stock on March 8, 2023 was 143,661,719 shares.

## DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated herein by reference from the registrant's definitive proxy statement relating to the registrant's Annual Meeting of Shareholders to be held in 2023 (the "Proxy Statement"), which definitive proxy statement shall be filed with the Securities and Exchange Commission not later than 120 days after the end of the fiscal year to which this report relates.



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## TABLE OF CONTENTS

Page

PART I ..... 1
ITEM 1. BUSINESS ..... 1
ITEM 1A. RISK FACTORS ..... 19
ITEM 1B. UNRESOLVED STAFF COMMENTS ..... 44
ITEM 2. PROPERTIES ..... 44
ITEM 3. LEGAL PROCEEDINGS ..... 44
ITEM 4. MINE SAFETY DISCLOSURES ..... 44

PART II ..... 45
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES ..... 45
ITEM 6. RESERVED ..... 47
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ..... 47
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ..... 66
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ..... 69
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE ..... 102
ITEM 9A. CONTROLS AND PROCEDURES ..... 102
ITEM 9B. OTHER INFORMATION ..... 102
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS ..... 103

PART III ..... 103
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE ..... 103
ITEM 11. EXECUTIVE COMPENSATION ..... 103
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS ..... 103
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE ..... 104
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES ..... 104

PART IV ..... 104
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES ..... 104
ITEM 16. FORM 10-K SUMMARY ..... 107



## Glossary of Key Terms

This Annual Report on Form 10-K uses several terms of art that are specific to our industry and business. For the convenience of the reader, a glossary of such terms is provided here. Unless we otherwise indicate, or unless the context requires otherwise, any references in this Annual Report on Form 10-K to:

• “ADG” refers to anaerobic digested gas.

• “CARB” refers to the California Air Resource Board.

• “CNG” refers to compressed natural gas.

• “CI” refers to carbon intensity.

• “WC \( _{s} \) ” refers to cellulosic waiver credits.

• “D3” refers to cellulosic biofuel with a 60% GHG reduction requirement.

• “D5” refers to advanced biofuels with a 50% GHG reduction requirement.

• “EHS” refers to environment, health and safety.

• “EIA” refers to the U.S. Energy Information Administration.

• “EPA” refers to the U.S. Environmental Protection Agency.

• “Environmental Attributes” refer to federal, state and local government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, rebates, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy.

• “FERC” refers to the U.S. Federal Energy Regulatory Commission.

• “GHG” refers to greenhouse gases.

• “JSE” refers to the Johannesburg Stock Exchange.

• “LCFS” refers to Low Carbon Fuel Standard.

• “LFG” refers to landfill gas.

• “LNG” refers to liquefied natural gas.

• “PPAs” refers to power purchase agreements.

• “QF” refers to “qualifying facility,” as such term is defined in the Public Utility Regulatory Policies Act of 1978.

• “RECs” refers to Renewable Energy Credits.

• “Renewable Electricity” refers to electricity generated from renewable sources.

• “RFS” refers to the EPA’s Renewable Fuel Standard.

• “RINs” refers to Renewable Identification Numbers.

• “RNG” refers to renewable natural gas.

• “RPS” refers to Renewable Portfolio Standards.

• “RVOs” refers to renewable volume obligations.

• “WRRFs” refers to water resource recovery facilities.



## Cautionary Note Regarding Forward-Looking Statements

This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of U.S. federal securities laws that involve substantial risks and uncertainties. All statements other than statements of historical or current fact included in this report are forward-looking statements. Forward-looking statements refer to our current expectations and projections relating to our financial condition, results of operations, plans, objectives, strategies, future performance, and business. You can identify forward-looking statements by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “anticipate,” “assume,” “believe,” “can have,” “contemplate,” “continue,” “strive,” “aim,” “could,” “design,” “due,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “likely,” “may,” “might,” “objective,” “plan,” “predict,” “project,” “potential,” “seek,” “should,” “target,” “will,” “would,” and other words and terms of similar meaning in connection with any discussion of the timing or nature of future operational performance or other events. For example, all statements we make relating to future results of operations, financial condition, expectations and plans of the Company, including expected benefits of the Pico feedstock amendment and the Montauk Ag project in North Carolina, the anticipated completion of the Raeger capital improvement project and Second Apex RNG Facility, the resolution of gas collection issues at the McCarty facility, our estimated and projected costs, expenditures, and growth rates, our plans and objectives for future operations, growth, or initiatives, or strategies are forward-looking statements. All forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from those that we expect and, therefore, you should not unduly rely on such statements. The risks and uncertainties that could cause those actual results to differ materially from those expressed or implied by these forward-looking statements include but are not limited to:

- our ability to develop and operate new renewable energy projects, including with livestock farms, and related challenges associated with new projects, such as identifying suitable locations and potential delays in acquisition financing, construction, and development;

• reduction or elimination of government economic incentives to the renewable energy market;

• the inability to complete strategic development opportunities;

- deterioration in general economic conditions outside our control including the impacts of supply chain disruptions, inflationary cost increases, recession and other macroeconomic factors;

- continued inflation could raise our operating costs or increase the construction costs of our existing or new projects;

• rising interest rates could increase the borrowing costs of future indebtedness;

- the potential failure to retain and attract qualified personnel of the Company or a possible increased reliance on third-party contractors as a result;

- the length of development and optimization cycles for new projects, including the design and construction processes for our renewable energy projects;

• dependence on third parties for the manufacture of products and services and our landfill operations;

- the quantity, quality and consistency of our feedstock volumes from both landfill and livestock farm operations;

- reliance on interconnections with and access to electric utility distribution and transmission facilities and gas transportation pipelines for our Renewable Natural Gas and Renewable Electricity Generation segments;

• our projects not producing expected levels of output;

- the anticipated benefits of the Raeger capital improvement project, Pico feedstock amendment, Second Apex RNG facility and the Montauk Ag project in North Carolina;



- potential benefits associated with the combustion-based oxygen removal condensate neutralization technology;

• resolution of gas collection issues at the McCarty facility;

• concentration of revenues from a small number of customers and projects;

• our outstanding indebtedness and restrictions under our credit facility;

• our ability to extend our fuel supply agreements prior to expiration;

• our ability to meet milestone requirements under our PPAs;

• existing regulations and changes to regulations and policies that effect our operations;

- expected benefits from the extension of the Production Tax Credit under the Inflation Reduction Act of 2022;

• decline in public acceptance and support of renewable energy development and projects;

- our expectations regarding Environmental Attribute volume requirements and prices and commodity prices;

- our expectations regarding the period during which we qualify as an emerging growth company under the Jumpstart Our Business Startups Act (“JOBS Act”);

• our expectations regarding future capital expenditures, including for the maintenance of facilities;

• our expectations regarding the use of net operating losses before expiration;

- our expectations regarding more attractive CI scores by regulatory agencies for our livestock farm projects;

- market volatility and fluctuations in commodity prices and the market prices of Environmental Attributes and the impact of any related hedging activity;

- regulatory changes in federal, state and international environmental attribute programs and the need to obtain and maintain regulatory permits, approvals, and consents;

• profitability of our planned livestock farm projects;

• sustained demand for renewable energy;

• security threats, including cyber-security attacks;

• potential liabilities from contamination and environmental conditions;

• potential exposure to costs and liabilities due to extensive environmental, health and safety laws;

• impacts of climate change, changing weather patterns and conditions, and natural disasters;

• failure of our information technology and data security systems;

• increased competition in our markets;

• continuing to keep up with technology innovations;

- concentrated stock ownership by a few stockholders and related control over the outcome of all matters subject to a stockholder vote and

• the other risks and uncertainties detailed in the section titled “Risk Factors.”

We make many of our forward-looking statements based on our operating budgets and forecasts, which are based upon detailed assumptions. While we believe that our assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors, and it is impossible for us to anticipate all factors that could affect our actual results.



See the “Risk Factors” section and elsewhere in this report for a more complete discussion of the risks and uncertainties mentioned above and for discussion of other risks and uncertainties we face that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements as well as others made in our other Securities and Exchange Commission (“SEC”) filings and public communications. You should evaluate all forward-looking statements made by us in the context of these risks and uncertainties.

We caution you that the risks and uncertainties identified by us may not be all of the factors that are important to you. Furthermore, the forward-looking statements included in this report are made only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statement as a result of new information, future events, or otherwise, except as required by law.



# Summary of Risks Associated with Our Business

Our business is subject to a number of risks and uncertainties, including those highlighted in the section titled “Risk Factors” in this Annual Report on Form 10-K. Some of these principal risks include the following:

- Our commercial success depends on our ability to identify, acquire, develop and operate individual renewable energy projects, as well as our ability to maintain and expand production at our current projects.

• Our renewable energy projects may not generate expected levels of output.

- The concentration in revenues from five of our projects and geographic concentration of our projects expose us to greater risks of production interruptions from severe weather or other interruptions of production or transmission.

- Our use and enjoyment of real property rights for our projects may be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to our projects.

• We may face intense competition and may not be able to successfully compete.

• Technological innovation may render us uncompetitive or our processes obsolete.

- We may not be able to obtain long-term contracts for the sale of power produced by our projects on favorable terms and we may not meet certain milestones and other performance criteria under existing PPAs.

- If there is insufficient demand for renewable energy, or if renewable energy projects do not develop or take longer to develop than we anticipate, we may be unable to achieve our investment objectives.

- Acquisition, financing, construction and development of new projects and project expansions and conversions may not commence on anticipated timelines or at all.

- Our fuel supply agreements with site hosts have defined contractual periods, and we cannot assure you that we will be able to successfully extend these agreements.

- Our PPAs, fuel-supply agreements, RNG off-take agreements and other agreements contain complex price adjustments, calculations and other terms based on gas price indices and other metrics, the interpretation of which could result in disputes with counterparties that could affect our results of operations and customer relationships.

- In order to secure contracts for new projects, we typically face a long and variable development cycle that requires significant resource commitments and a long lead time before we realize revenues.

- We plan to expand our business in part through developing RNG recovery projects at landfills and livestock farms, but we may not be able to identify suitable locations or complete development of new projects.

- Our dairy farm project has, and any future digester project will have, different economic models and risk profiles than our landfill facilities, and we may not be able to achieve the operating results we expect from these projects.

- While we currently focus on converting methane into renewable energy, in the future we may decide to expand our strategy to include other types of projects. Any future energy projects may present unforeseen challenges and result in a competitive disadvantage relative to our more established competitors.

- Any future acquisitions, investments or other strategic relationships that we make could disrupt our business, cause dilution to our stockholders or harm our business, financial condition or operating results.



- Our revenues may be subject to the risk of fluctuations in commodity prices and pricing volatility of Environmental Attributes.

- We are exposed to the risk of failing to meet our contractual commitments to sell RINs from our production.

- We may be unable to obtain, modify, or maintain the regulatory permits, approvals and consents required to construct and operate our projects.

- Negative attitudes toward renewable energy projects from the U.S. government, other lawmakers and regulators, and activists could adversely affect our business, financial condition and results of operations.

- Revenue from any projects we complete may be adversely affected if there is a decline in public acceptance or support of renewable energy, or regulatory agencies, local communities, or other third parties delay, prevent, or increase the cost of constructing and operating our projects.

- Existing regulations and policies, and future changes to these regulations and policies, may present technical, regulatory and economic barriers to the generation, purchase and use of renewable energy, and may adversely affect the market for credits associated with the production of renewable energy.

• Our business is subject to the risk of climate change and extreme or changing weather patterns.

- Our business could be negatively affected by security threats, including cybersecurity threats and other information technology-related disruptions.

- Failure of third parties to manufacture quality products or provide reliable services in a timely manner could cause delays in developing and operating our projects, which could damage our reputation, adversely affect our partner relationships or adversely affect our growth.

- Our projects rely on interconnections to distribution and transmission facilities that are owned and operated by third parties, and as a result, are exposed to interconnection and transmission facility development and curtailment risks.

- We are dependent upon our relationships with Waste Management and Republic Services for the operation and maintenance of landfills on which several of our RNG and Renewable Electricity projects operate.

- We have significant customer concentration, with a limited number of customers accounting for a substantial portion of our revenues.

- Our fuel supply agreements with site hosts have defined contractual periods, and we cannot assure you that we will be able to successfully extend these agreements.

- Our senior credit facility contains financial and operating restrictions that may limit our business activities and our access to credit.

- We may be required to write-off or impair capitalized costs or intangible assets in the future or we may incur restructuring costs or other charges, each of which would harm our earnings.

- Our ability to use our U.S. net operating loss carryforwards to offset future taxable income may be subject to certain limitations.

- We also face risks related to our common stock, being a controlled company, being an emerging growth company, and risks generally applicable to publicly-traded companies.

- Public health threats or outbreaks of communicable diseases could have a material effect on our operations and financial results.



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## PART I

## ITEM 1. BUSINESS.

Unless the context requires otherwise, references to “Montauk,” the “Company,” “we,” “us” or “our” refer to Montauk Renewables, Inc. and its consolidated subsidiaries.

## Overview

We are a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources to beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply renewable fuel into the transportation and electrical power sectors. 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 and have grown our revenues from $33.8 million in 2014 to $205.6 million in 2022.

## Corporate History

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

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

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

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

On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (the “Initial Promissory Note”) with MNK. MNK is currently an affiliate of the Company and certain of the Company’s directors and executive officers are also directors and executive officers of MNK. Pursuant to the Initial Promissory Note, the Company advanced a cash loan of $5,000 to MNK for MNK to pay its dividends tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended (the “South African Income Tax Act”). On February 22, 2021, the Company and MNK entered into an Amended and Restated Promissory Note (the “Amended Promissory Note”) to increase the principal amount of the loan to a total of $7,140, in the aggregate, on December 22, 2021 entered into the Second



Amended and Restated Loan Agreement and Secured Promissory Note (the “Second Amended Promissory Note”) to increase the principal amount of the loan to a total of $8,940, in the aggregate, and on December 22, 2022, entered into the First Amendment to the Second Amended Promissory Note, which extended the maturity date of the loan to June 30, 2023, each in accordance with the Company’s obligations set forth in the Transaction Implementation Agreement entered into by and among the Company, MNK and the other party thereto, dated November 6, 2020, and amended on January 14, 2021.

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

## Products Sold

The revenues Montauk receives from selling renewable energy consist of two main components. The first component is revenues from the commodity value of the natural gas or electricity generated, which we sell through a variety of term-length agreements. The second component is from the Environmental Attributes derived from the production of RNG and Renewable Electricity.

Our current operating projects produce either RNG or Renewable Electricity by processing biogas from landfill sites or agricultural waste from livestock farms. 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. Once collected, biogas can be processed into pipeline-quality RNG or converted into electricity. The conversion facility is typically located on landfill property away from the active fill operations where additional waste is added to the landfill site. Because we are capturing waste methane and making use of a renewable source of energy, the RNG and Renewable Electricity we produce also generates valuable Environmental Attributes which we can monetize under federal and state renewable initiatives.

## RNG

The RNG we process is pipeline-quality and can be used for transportation fuel when compressed (CNG) or liquefied (LNG). Virtually all of the RNG we produce is used as a transportation fuel because this market generally provides the most value for our RNG production. CNG has been the most common fuel used by fleets where medium-duty trucks are close to the fueling station, such as city fleets, local delivery trucks and waste haulers. Additionally, landfill gas (LFG) and gas from livestock digesters can be processed into pipeline-quality RNG by removing the majority of the non-methane components including carbon dioxide, water, sulfur, nitrogen, and other trace compounds.

RNG, like traditional natural gas, is traded nationally. Once in an interstate pipeline, RNG can be transported to vehicle fueling stations to be used as a transportation fuel, to utilities to generate power, or for use in generating fuel cell energy anywhere within the North American pipeline system. This flexibility enables us to capture value from the renewable attributes of biogas by delivering RNG to markets and customers that place a premium on renewable energy. Although RNG has the same chemical composition as natural gas from fossil sources, it has unique Environmental Attributes assigned to it through government incentive programs due to its origin from low-carbon, renewable sources, which we also monetize.

RNG is priced in-line with the wholesale natural gas market, based on Henry Hub pricing, with regional variation according to demand. We sell the RNG produced from our projects under a variety of short-term and medium-term agreements to counterparties, with tenures 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. We also share a portion of our Environmental Attributes with certain pathway providers as consideration for the counterparty using our RNG as a transportation fuel.



## Renewable Electricity

Renewable electricity is generated using gas-fueled engines or turbine-driven electrical generators, which are designed to operate efficiently on medium-Btu gas. As such, electricity generation typically involves producing medium-Btu gas, which is then pumped into a generating facility. Electricity is a commodity that trades and is priced on a regional basis in and among regional control areas. Pricing for commodity-sold electricity can be based on day-ahead prices for scheduled deliveries or hourly, real-time prices for unscheduled deliveries. Prices vary across the country based on weather, load patterns and local power and transmission restrictions. The Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price with escalators. The terms of these contracts range from 4 to 21 years, excluding renewal periods, with a weighted average remaining tenure of 13 years, based on 2022 electricity production.

## Environmental Attributes

When used as a transportation fuel or to produce electricity, RNG can generate additional revenue streams through the generation and sale of Environmental Attributes under various programs, including the national renewable fuels standard and state-level California LCFS. The Environmental Attributes that we generate and sell are composed of RINs and LCFS credits, which are generated from the conversion of biogas to RNG that is used as a transportation fuel, as well as RECs generated from the conversion of biogas to Renewable Electricity. In addition to revenues generated from our product sales, we also generate revenues by providing various value-added services to certain of our biogas site partners. In 2022 and 2021, our projects generated approximately 8.1% and 11.0%, respectively, of all D3 RINs in the United States. During 2021, we entered into an agreement to sell a portion of our production as a renewable component of refinery fuel exports into the European Union’s Renewable Energy Directive from certain RNG production facilities that have achieved International Sustainability & Carbon Certification registration. This diversification strategy accounted for approximately 1.5% of the reduction in generation of D3 RINs in 2022. We continue to sell a portion of our production as a renewable component of refinery fuel exports.

Whenever possible, we seek to mitigate our exposure to commodity and Environmental Attribute pricing volatility. Through contractual arrangements with our site hosts and counterparties, we typically share pricing and production risks while retaining our ability to benefit from potential upside. A portion of the RNG volume we produce is sold under bundled fixed-price arrangements for the RNG and Environmental Attributes, some of which included a sharing arrangement where we benefit from prices above certain thresholds. For our remaining RNG projects, our partners may receive a cash payment instead of in-kind sharing arrangements where our partners receive the Environmental Attributes, thereby sharing in Environmental Attribute pricing risk.

On the electricity side of our business, all of our products and related Environmental Attributes are sold under fixed-price contracts with escalators, limiting our pricing risk. Finally, our contracts with site hosts often require payments to our site hosts in the form of royalties based on realized revenues, direct development contributions, or, in some select cases, based on production volumes.

## D3 RINs

RNG has the same chemical composition as natural gas from fossil sources, but has unique Environmental Attributes assigned to it due to its origin from organic sources. These attributes qualify RNG as a renewable fuel under the federal RFS program, established pursuant to the EPACT 2005 and EISA, allowing RNG to generate renewable fuel credits called RINs when the RNG is used as a transportation fuel.

RINs are saleable regulatory credits that represent a quantity of qualifying fuel and are used by refiners and importers to evidence compliance with their RFS obligations. Given that the RFS is a national program, the price of a RIN is the same anywhere in the United States. The RFS program originally contemplated 1.75 billion gallons of fuel from cellulosic biofuels by 2014, the use of which would be tracked through D3 RINs. However,



cellulosic biofuel production grew slower than expected and prompted the EPA to expand the definition of biofuels that could qualify for D3 RINs to include fuels from cellulosic biogas, including biogas from landfills, livestock farms, and WRRFs. This significantly increased the quantity of D3 RINs produced, with production increasing to approximately 33 million net RINs in 2014 and approximately 660 million net RINs in 2022. In addition, given the historic shortage in supply of D3 RINs to meet blending requirements, the EPA allows obligated refiners to satisfy RFS compliance obligations for D3 RINs by either purchasing CWC plus D5 RINs or by purchasing D3 RINs. CWC prices were set annually and are typically published by the EPA each November. Historically, the value of a D3 RIN is therefore a derivative of the market price for D5 RINs and CWCs, which in turn, are inversely linked to the wholesale price of gasoline. In a December 1, 2022 proposed rule, EPA indicated that it will not be utilizing its cellulosic waiver authority to reduce cellulosic biofuel volume for 2023-2025, thus CWCs will not be available unless actual production is lower than the RVO. The EPA will have discretion to utilize the CWC. However, if production is equal to or higher than the RVO, the obligation will be met with only RINs and the CWC will be unnecessary.

We have been active in the RFS program since 2014 and expect to remain a significant contributor to the overall generation of RINs from RNG. We monetize our portion of the RINs, directly, at auction or through third-party agents or marketers.

## CA LCFS

CA LCFS credits are environmental credits generated in California in order to stimulate the use of cleaner, low-carbon fuels. This program encourages the production of low-carbon fuels by setting annual CI standards, which are intended to reduce GHG emissions from the state’s transportation sector. One of the key aspects of the program is that it encourages the use of low-carbon transportation fuel, such as CNG, in vehicles instead of gasoline. This program further encourages use of renewable fuels in vehicles over CNG from fossil fuels.

The value of an CA LCFS credit varies according to the CI value of the fuel source as determined by CARB. Fuels that have a lower CI score benefit from a higher percentage of a CA LCFS credit. RNG from LFG and livestock digester biogas that are used as a transportation fuel both qualify for CA LCFS credits. The number of CA LCFS credits for RNG from livestock digesters is significantly higher than the number of CA LCFS credits for RNG from landfills, due to the relative CI scores of the two fuels. Fuel that is eligible for RINs can also receive CA LCFS credits. As a result, CA LCFS credits represent a revenue stream incremental to the value RNG producers receive for RINs. For livestock digester RNG projects, CA LCFS credits are a substantial revenue driver. We have seven projects which are currently approved and eligible to earn CA LCFS credits, and we expect the revenue generated by CA LCFS credits to increase as we continue to develop and bring additional livestock digester projects online over the next few years.

Several states in the United States also have or are considering adopting this model. Oregon’s Clean Fuels Program, enacted in 2009 and implemented in 2016, operates using a credit system similar to the CA LCFS program. Washington’s Clean Fuel Standard was passed in 2021 and will be implemented in 2023 utilizing a similar credit system as Oregon and California. Similar to RINs, LCFS credits can be sold separately from the RNG fuel sold, allowing us to monetize LCFS credits for fuel produced and purchased outside of states that have LCFS programs.

## RECs.

The primary Environmental Attributes derived from the production of electricity from renewable resources are RECs, which translate into additional revenues for units of Renewable Electricity produced. Biogas is considered to be a renewable resource in all 37 states that encourage or mandate the use of renewable energy. Thirty states, the District of Columbia, and Puerto Rico have RPS that require utilities to supply a percentage of power from renewable resources, and seven states have a Renewable Portfolio Goal that is similar to RPS, but it is an objective or goal and not a requirement. Many states allow utilities to comply with RPS through tradable RECs, which provide an additional revenue stream to RNG projects that produce electricity from biogas.



The value of a REC is dependent on each state’s renewable energy requirements as mandated by its RPS. REC values are higher in states which require a percentage of total electricity to come from renewable resources. In states with no renewable energy requirements, RECs can have no value at all. In some markets, we have entered into PPAs under which we sell RECs bundled with the power being sold at a combined price. This occurs where the utility off-take counterparty offers a combined rate for the renewable energy it needs to satisfy RPS or other business requirements that is the best combined price for one of our projects.

## Strategic Overview

Our business strategy focuses on the following three areas that we believe present the greatest growth opportunities for the Company at this time.

• Continued Expansion into Agricultural Feedstocks for RNG Production

• Optimize Existing Assets and Project Portfolio and Opportunistically Develop New Projects

• Valued-added Service Offerings

## Continued Expansion into Agricultural Feedstocks for RNG Production

As part of our long-term strategy, we are focused on diversifying our project portfolio beyond LFG through expansion into additional methane producing assets, while opportunistically adding third-party developed technology capabilities to boost financial performance and our overall cost competitiveness. We are commercially operating our first agricultural waste project (dairy manure), actively pursuing new fuel supply opportunities in WRRFs, and looking at long-term organic waste and sludge opportunities for the generation of biogas.

We view dairy farms and other forms of organic agricultural waste as a significant opportunity for us to expand our RNG business, as processing biogas from dairy farms and from other forms of organic agricultural waste requires similar expertise and capabilities as processing biogas from landfills. Many of the existing biogas processing in these industries is for electricity production, which creates additional opportunities for acquisition and conversion to higher-value RNG facilities.

## Pico Facility

We undertook an agricultural project when we closed on the acquisition of Pico, the anaerobic digester and two Jenbacher engines at the Bettencourt dairy farm in Jerome, Idaho in September 2018. The project sources manure from a dairy farm with up to approximately 18,500 milking cows. While Pico was initially a Renewable Electricity site, we brought an RNG facility at that location online in 2020. The facility sells transportation fuel into the California transportation market. The collection of the fuel supply is much easier at dairy farms than at landfills due to higher quality, more uniform feedstock, less volatility in inlet gas and biogas collection in a more controlled environment. During the second quarter of 2021, we amended our Pico feedstock agreement (“Pico Feedstock Amendment”). The amendment increased the amount of feedstock supplied to the facility for processing over a three-year period.

As part of our overall capacity expansion at the Pico facility, in 2021 and 2022, we undertook significant efforts to improve the performance of the existing digestion process at our Pico facility. We temporarily idled RNG production at this facility in order to clean out settled solids in the digester, replace the cover of the digester, and make various other efficiency improvements. The Pico facility resumed operations during the first quarter of 2022. The dairy began delivering the first and second increases in feedstock during the third quarter of 2022 and we have made two payments to the dairy as required in the Pico Feedstock Amendment. The improved efficiencies of our existing digestion process and the water management improvements have enabled us to



process the increased feedstock volumes. We completed the design of the digestion capacity expansion project in the third quarter of 2022 and have begun incurring capital expenditures related to the construction of the project. We currently expect the dairy to begin delivering the final increase in feedstock volumes during 2024.

The improvement project has impacted the timeline for modeling Pico’s initial CI Score pathway model and subsequent auditing approval by CARB. During the fourth quarter of 2022, we learned through CARB that our dairy project CI Score Pathway will be subject to a public comment period. Due to this public comment period, we now currently expect to receive approval of our score during the first quarter of 2023. This public comment period follows the completion of the validation of the CI Score, which CARB finalized in the first quarter of 2023. We began to release gas from storage in the third quarter of 2022. We do not expect to recognize LCFS credit revenue on 2022 production until 2023 when we anticipate recognizing LCFS credit revenues during the first half of 2023 for all of 2022 production. Related to 2023 production, we expect to normalize the timing of LCFS credit revenue recognition, generally, six months after the month of production. We began releasing gas from storage during the third quarter of 2022 and recognized revenues from a portion of the RINs generated and currently expect to complete storage release during the third quarter of 2023. We committed RINs and recognized revenues from RINs generated in the fourth quarter of 2022. During the fourth quarter of 2022, CARB certified our temporary CI Score Pathway application for the third and fourth quarter of 2022. The approval of this temporary application will prevent us from not being able to generate LCFS credit revenue on 2022 production in 2023. We did not receive a temporary CI pathway in 2021 and were not able to generate LCFS credit revenue on 2021 production.

## Montauk Ag Renewables

In the second quarter of 2021, through our wholly owned subsidiary, Montauk Ag Renewables, we completed the 2021 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 to produce high quality renewable natural gas, bio-oil and biochar (the “Montauk Ag Renewables Acquisition”). The assets acquired include real property, intellectual property, mobile equipment, and other equipment related to operating the business and real property of an approximate 9.35 acre parcel in Magnolia, North Carolina. We subsequently closed on a transaction to acquire approximately 146 acres and an approximately 500,000 square foot existing structure in Turkey, North Carolina where we plan to consolidate and expand the production processes purchased in the Montauk Ag Renewables Acquisition.

We continue to work with our engineer of record through the optimization of improvements to the now patented reactor technology. We have relocated certain assets from Magnolia, NC to Turkey, NC and have recorded an impairment of approximately $1,393 related to assets which will no longer be used in the production process. However, we have not completed our improvements and have not yet reached commercial operations at the Turkey location.

While these project developments continue, we continue to engage with regulatory agencies in North Carolina related to the resulting power generation derived from swine waste to confirm its eligibility for Renewable Energy Credits under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production. Accordingly, we requested that our Turkey location be 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. Due to our consolidation of production at the Turkey, NC location and based on our current expectations related to commercial operations, we have paused our registration process to obtain NREF status for the Turkey, NC location. Our Turkey, NC location has been accepted into the Piedmont Natural Gas Renewable Gas Pilot Program.

We are at the beginning stages of developing the opportunities associated 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 facility to be used for commercial production. We do not currently expect commercial production to commence until 2024 based on the current development timeline. We intend to



contract with additional farms to secure feedstock sources, as we commission commercial production and increase our production capabilities, which we anticipate will secure additional feedstock for future production processes.

## Other Opportunities

Other industries that present opportunities of scale for biogas conversion include swine farms and WRRFs. Like dairy farms, biogas production from swine farms is a nascent biogas industry, with less than 1% of swine farms with biogas processing capabilities. Additionally, roughly 23% of WRRFs have biogas processing facilities, however, most process biogas for electricity production creating additional opportunities for acquisition and conversion to RNG facilities. As with LFG and dairy farms, biogas from both swine farms and WRRFs qualify for D3 RINs under the RFS program. We believe our demonstrated versatility to operate processing facilities using multiple fuel supply sources will give us a competitive advantage in these markets relative to other new entrants who have only demonstrated capabilities with one fuel supply source. The drive toward voluntary and most likely regulatory-required organic waste diversion from landfills is of particular interest as we leverage our current experience base. As our biogas processing technology continues to improve and the required energy intensity of the RNG and Renewable Electricity production process is reduced, we expect that we will be able to enter new markets for our products.

## Optimize Existing Assets and Project Portfolio and Opportunistically Develop New Projects

Expanding Operations at Existing Project Sites. We monitor biogas supply availability across our portfolio and seek to maximize production at existing projects by expanding operations when economically feasible. Most of our landfill locations continue to accept waste deliveries and the available LFG at these sites is expected to increase over time, which we expect to support expanded production. In 2022, this has allowed us to maintain average production availability of approximately 90% at our RNG projects and 85% at our Renewable Electricity projects.

We treat our existing assets as an integrated portfolio rather than a collection of individual projects. This allows us to utilize any new business practices or technologies across our entire project portfolio quickly, including advances with respect to troubleshooting, optimization, cost savings, and host site interaction. Our integrated, pro-active and value-add approach helps us maintain strong relationships with our partners, which we seek to leverage to optimize the performance of our existing projects.

We also experience organic growth in production at our existing projects as a result of increases in biogas supply at our projects and on-going optimization initiatives. We size our projects to account for this increase in the biogas supply curve over time. For example, at many of our newer projects, such as Apex and Galveston, we expect gradual increases in production as those landfill sites continue to grow. Additionally, many of our capacity expansion efforts to date, such as those at McCarty, Rumpke, and Pico, have helped to optimize our project capacity to take advantage of excess biogas at older landfills that are still open and growing. Not only have our projects achieved an initial increase in production following the capacity expansion project, but we also expect to see continued gradual increases in production over time.

Converting Existing Renewable Electricity Projects to RNG. We periodically evaluate opportunities to convert existing projects from electricity generation to RNG production. These opportunities tend to be attractive for our merchant electricity projects given the favorable economics for RNG plus RIN sales relative to merchant electricity rates plus REC sales. To date, we have converted two projects from LFG-to-electricity to LFG-to-RNG and a third project from ADG-to-electricity to ADG-to-RNG. We will continue to explore the feasibility of other opportunities across our existing Renewable Electricity portfolio.

Opportunistic Development of New RNG Projects. We apply a financially disciplined model toward new project development that considers the relative risk of a given project and associated feedstock costs, offtake



contracts and any other related Environmental Attributes that can be monetized. We are currently evaluating two project expansion opportunities at existing project sites. We regularly analyze potential new projects that are at various stages of negotiation, engineering design and financial review. The potential projects typically include a mix of new project sites and strategic acquisitions. Currently, no new potential projects are subject to definitive agreements and each potential opportunity is subject to competitive market conditions.

Developing LFG to Renewable Electricity Projects. Included within the proposed Renewable Fuel Standard for 2023, 2024 and 2025 issued by the EPA on December 1, 2023 included volumes of eRINs to be generated from renewable electricity and used as transportation fuel. The proposed eRIN volume obligations are 600 million and 1,200 million for 2024 and 2025, respectively. With the release of the proposed eRIN volumes, we are expanding the potential new projects we analyze to include site from which we would generate renewable electricity. This evaluation of potential new renewable electricity projects would be reviewed with the same financially disciplined model we use to evaluate new RNG projects.

The RNG industry remains highly fragmented. We believe continued industry fragmentation presents an opportunity for further industry consolidation. We are well-positioned to take advantage of this consolidation opportunity because of our scale, operational and managerial capabilities, and execution track record in integrating acquisitions. Over the last ten years, we have acquired 13 projects and members of our current management team have led all of those acquisitions. We expect that as we continue to scale up our business, our increased size, capabilities and access to capital will provide us with increased strategic acquisition opportunities.

## Valued-Added Service Offerings

Over our three decades of experience, we have developed the full range of RNG project related capabilities from engineering, construction, management and operations, through EHS oversight and Environmental Attributes management. By vertically integrating across RNG services, we are able to reduce development and operations costs, optimize efficiencies and improve operations. Our full suite of capabilities allows us to serve a multi-project partner for certain project hosts across multiple transactions, including through strategic transactions. To that end, we actively identify and evaluate opportunities to acquire entities that will further our vertically-integrated services.



## Our Current Operating Portfolio

We currently own and operate 15 projects, 12 of which are RNG projects and three of which are Renewable Electricity projects. We are currently in the process of expanding two RNG project from LFG. We are also working on other projects which will repurpose equipment from existing biogas facilities for use at new project sites. The below graphic does not include the Montauk Ag project, which is currently under development.



<table><tr><td colspan="4">Renewable Electricity Generation</td></tr><tr><td>Site</td><td>COD (1)</td><td>Capacity (MW)</td><td>Source</td></tr><tr><td>Bowerman</td><td></td><td></td><td></td></tr><tr><td>Irvine, CA</td><td>2016</td><td>23.6</td><td>Landfill</td></tr><tr><td>Security</td><td></td><td></td><td></td></tr><tr><td>Houston, TX</td><td>2003</td><td>3.4</td><td>Landfill</td></tr><tr><td>AEL</td><td></td><td></td><td></td></tr><tr><td>Sand Spring, OK</td><td>2013</td><td>3.2</td><td>Landfill</td></tr><tr><td>Total Capacity (MW)</td><td></td><td>30.2</td><td></td></tr></table>

<table><tr><td colspan="4">Renewable Natural Gas</td></tr><tr><td>Site</td><td>COD(1)</td><td>Capacity (MMBtu/day) (2)</td><td>Source</td></tr><tr><td>Rumpke</td><td></td><td></td><td></td></tr><tr><td>Cincinnati, OH</td><td>1986</td><td>7,271</td><td>Landfill</td></tr><tr><td>Atascocita</td><td>2002*/</td><td></td><td></td></tr><tr><td>Humble, TX</td><td>2018</td><td>5,570</td><td>Landfill</td></tr><tr><td>McCarty</td><td></td><td></td><td></td></tr><tr><td>Houston, TX</td><td>1986</td><td>4,415</td><td>Landfill</td></tr><tr><td>Apex</td><td></td><td></td><td></td></tr><tr><td>Amsterdam, OH</td><td>2018</td><td>2,673</td><td>Landfill</td></tr><tr><td>Monroeville</td><td></td><td></td><td></td></tr><tr><td>Monroeville, PA</td><td>2004</td><td>2,372</td><td>Landfill</td></tr><tr><td>Valley</td><td></td><td></td><td></td></tr><tr><td>Harrison City, PA</td><td>2004</td><td>2,372</td><td>Landfill</td></tr><tr><td>Galveston</td><td></td><td></td><td></td></tr><tr><td>Galveston, TX</td><td>2019</td><td>1,857</td><td>Landfill</td></tr><tr><td>Raeger</td><td></td><td></td><td></td></tr><tr><td>Johnston, PA</td><td>2006</td><td>1,857</td><td>Landfill</td></tr><tr><td>Shade</td><td></td><td></td><td></td></tr><tr><td>Cairnbrook, PA</td><td>2007</td><td>1,857</td><td>Landfill (3)</td></tr><tr><td>Coastal</td><td></td><td></td><td></td></tr><tr><td>Plains Alvin, TX</td><td>2020</td><td>1,775</td><td>Landfill</td></tr><tr><td>Southern</td><td></td><td></td><td></td></tr><tr><td>Davidsville, PA</td><td>2007</td><td>928</td><td>Landfill</td></tr><tr><td>Pico</td><td></td><td></td><td></td></tr><tr><td>Jerome, ID</td><td>2020</td><td>903</td><td>Livestock (Dairy)</td></tr><tr><td>Total Capacity (MMBtu/day)</td><td></td><td>33,850</td><td></td></tr></table>

= Renewable Natural Gas Project

= Renewable Electricity Project

(1) “COD” refers to the commercial operation date of each site.

(2) This is equivalent to the project’s design capacity and assumes inlet methane content of 56% for all sites other than Pico, which assumes inlet methane content of 62%, and process efficiency of 91%.

(3) All of our landfill sites are accepting waste except our Shade site. Our Shade site is closed to accepting new waste, but is currently expected to continue to generate a commercial level of RNG for an additional ten years. Our operating RNG projects have an average expected remaining useful life of approximately 18 years.

We have a long history of operating our projects with partners, with our oldest relationship going back nearly 50 years. On average, we have had an approximate 20-year history with our current project site owners. As of December 31, 2022, our operating RNG projects have an average expected remaining useful life of approximately 18 years and our operating Renewable Electricity projects have an average expected remaining useful life of approximately 26 years, including renewal periods.



Approximately 78% of our 2022 RNG production has been monetized under fuel supply agreements with expiration dates more than 15 years from December 31, 2022. Approximately 95% of our 2022 Renewable Electricity production has been monetized under fuel supply agreements with expiration dates more than 15 years from December 31, 2022. Concurrent with our fuel supply agreements, we typically enter into property leases with our project hosts, which govern access rights, permitted activities, easements and other property rights. We own all equipment and facilities on each leased property, other than equipment provided by utility companies providing services on-site. Lease termination typically requires the restoration of the leased area to its original condition. We have successfully ended leases on four facilities and completed associated restoration activities, and are currently completing restoration of two other facilities.

Our RNG projects currently utilize three of the four proven commercial technologies available to process raw biogas into RNG, including: pressure swing absorption (“PSA”), Membrane Filtration and solvent scrubbing. We are capable of working with virtually all available biogas processing technologies at our sites. We attend industry conferences and maintain an ongoing dialogue with key equipment providers to ensure we stay informed of the latest technology that could be deployed at our current and future facilities.

Stated capacity reflects the design capacity of each facility. Several of our projects have reserve capacity when comparing design capacity to available biogas feedstock. Several previous acquisitions are gas limited and therefore do not operate at their design capacity. Our larger projects have expansions planned or are being evaluated for future expansions dependent on the availability of excess biogas feedstock.

## RNG Projects

We currently own and operate 12 RNG projects across four states: Ohio (two), Pennsylvania (five), Texas (four) and Idaho (one) which, in the aggregate, have a total design capacity of approximately 33,850 MMBtu/day. This does not include the Montauk Ag Renewables project in North Carolina, which is not yet operational.

RNG Projects

<table><tr><td>Site</td><td>Location</td><td>Capacity*</td></tr><tr><td>Rumpke</td><td>Cincinnati, OH</td><td>7,271 MMBtu/day</td></tr><tr><td>Atascocita</td><td>Humble, TX</td><td>5,570 MMBtu/day</td></tr><tr><td>McCarty</td><td>Houston, TX</td><td>4,415 MMBtu/day</td></tr><tr><td>Apex</td><td>Amsterdam, OH</td><td>2,673 MMBtu/day</td></tr><tr><td>Monroeville</td><td>Monroeville, PA</td><td>2,372 MMBtu/day</td></tr><tr><td>Valley</td><td>Harrison City, PA</td><td>2,372 MMBtu/day</td></tr><tr><td>Galveston</td><td>Galveston, TX</td><td>1,857 MMBtu/day</td></tr><tr><td>Raeger Mountain</td><td>Johnstown, PA</td><td>1,857 MMBtu/day</td></tr><tr><td>Shade</td><td>Cairnbrook, PA</td><td>1,857 MMBtu/day</td></tr><tr><td>Coastal Plains</td><td>Alvin, TX</td><td>1,775 MMBtu/day</td></tr><tr><td>Southern</td><td>Davidsville, PA</td><td>928 MMBtu/day</td></tr><tr><td>Pico</td><td>Jerome, ID</td><td>903 MMBtu/day</td></tr><tr><td>Total</td><td></td><td>33,850 MMBtu/day</td></tr></table>

* Assumes inlet methane content of 56% for all sites other than Pico, which assumes inlet methane content of 62%, and process efficiency of 91%.

## Renewable Electricity Projects

We currently own and operate the following three Renewable Electricity projects in California, Oklahoma, and Texas which, in the aggregate, have a total design capacity of approximately 30.2 MW. During 2022, our Renewable Electricity projects collectively produced 190,000 MWh. Our Renewable Electricity projects utilize reciprocating engine generator sets to generate electricity at landfills.



## Renewable Electricity Projects

<table><tr><td>Site</td><td>Location</td><td>Capacity(1)</td></tr><tr><td>Bowerman Power</td><td>Irvine, CA</td><td>23.6 MW</td></tr><tr><td>Security</td><td>Cleveland, TX</td><td>3.4 MW</td></tr><tr><td>Tulsa/AEL</td><td>Sand Springs, OK</td><td>3.2 MW</td></tr><tr><td>Pico(2)</td><td>Jerome, ID</td><td>2.3 MW</td></tr><tr><td>Total</td><td></td><td>32.5 MW</td></tr></table>

(1) Assumes inlet methane content of 56% and process efficiency of 91%,

(2) Beginning in October 2020, we began reporting the result of operations of Pico within RNG, but Pico continues to generate Renewable Electricity.

A critical component of our business is our ability to negotiate and maintain long-term fuel supply agreements at our project sites. We have developed strong working relationships with our landfill site owners, including ten of 14 operating projects and other potential development projects each with Waste Management and Republic Services, the two largest waste companies in the United States, and actively seek to strategically extend our tenure at our project sites.

Our projects provide our landfill and agricultural partners a solution to monetize biogas from their sites, support their regulatory compliance and provide them with environmental services. We have had working relationships with Republic Services since 1986 and with Waste Management since 2004 and we enable monetization of their biogas while maintaining regulatory compliance. We seek to differentiate ourselves from our competitors through our extensive experience across a variety of commercialized beneficial uses of processed biogas, including pipeline-quality natural gas, power generation and boiler fuel gas products. To date, we have not had any fuel supply agreement terminated by any site partner once we have established a facility on the site, which we believe serves as evidence of our operational expertise, reliability and consistent value delivered to our site partners. The table below is a summary of the expiration periods of those agreements. We are consistently reviewing and pursuing extensions for all of our fuel supply agreements well before their expirations and for future agreements, we continue to target contracts with expirations of 20 years from commencement of operation with options for extension.

## Fuel Supply Agreement Summary

## RNG Projects

<table><tr><td>Fuel Supply Agreement Expiration Dates</td><td>Current Sites as of December 31, 2022</td><td>% of 2022 Total RNG Production</td></tr><tr><td>Within 0-5 years</td><td>3</td><td>6.6%</td></tr><tr><td>Between 6-15 years</td><td>1</td><td>15.2%</td></tr><tr><td>Greater than 15 years</td><td>8</td><td>78.2%</td></tr></table>

## Renewable Electricity Projects

<table><tr><td>Fuel Supply Agreement Expiration Dates</td><td>Current Sites as of December 31, 2022</td><td>% of 2022 Total Renewable Electricity Production</td></tr><tr><td>Within 0-5 years</td><td>1</td><td>5.5%</td></tr><tr><td>Between 6-15 years</td><td>0</td><td>0%</td></tr><tr><td>Greater than 15 years(1)</td><td>2</td><td>94.5%</td></tr></table>

(1) Our Pico project continues to generate both RNG and Renewable Electricity and is accounted for above in the RNG Projects summary.



## Customers

Our customers for RNG and RINs typically include large, long-term owner-operators of landfills and livestock farms, local utilities, and large refiners in the natural gas and refining sectors. Royalty structures included in our agreements, as well as the large size of our counterparties, limit their credit risk. ExxonMobil and Valero each represented approximately 32.0% and 17.0%, respectively, of our operating revenues in 2022 from the sale of Environmental Attributes. We sell RINs to numerous RIN off-take parties and our largest RIN off-taker as a percentage of revenue can vary year to year given the short-term nature of these contracts. In addition to revenues from sales of RNG and RINs, we also share a portion of our Environmental Attributes with our pathway providers as in-kind consideration for the counterparty using our RNG as a transportation fuel.

Our customers for electricity typically include investor-owned and municipal electricity utilities. For the sale of Renewable Electricity and RECs, the City of Anaheim represented approximately 7.6% of our operating revenues in 2022. These sales occurred under a PPA between us and the City of Anaheim, in which electricity and RECs are sold at fixed prices. In 2022, we converted 100% of the monetization of our Renewable Electricity production and Environmental Attributes under fixed-price agreements. For our electricity sales, all of our customers with whom we have off-take agreements are investment-grade entities with low credit risk.

No other single customer represented more than 10% of our total 2022 operating revenues.

## Suppliers and Equipment Vendors

The major technologies used by our projects for gas processing include solvent scrubbing PSA, and membrane separation. For electricity generation, we use reciprocating engines. This affords Montauk experience with substantially all major vendors in the sector, and technical expertise in numerous technologies.

We source equipment from a variety of major suppliers with specialties in each technology. We enter into written ordinary-course agreements with suppliers to obtain industry-standard equipment for use in our operations. The contracts generally do not include any intellectual property rights other than for the intended use of the equipment. Membrane separation equipment is primarily provided by UOP and Air Liquide. PSA equipment is primarily provided by Xebec, Guild, Air Products, and BioFerm. Solvent scrubbing is primarily provided by Selexol. RNG ancillary constituent removal is done using equipment provided by Iron Sponge, MV Technologies, Thiopaq, Guild Associates, and PSB Industries. Electricity generation equipment is provided by Solar Turbines, Caterpillar, and Jenbacher.

We have made substantial investments in a centralized Enterprise Resource Planning (“ERP”) system (Microsoft Dynamics) to better integrate operations across our projects. This system centralizes maintenance operations across all of our projects. Our proactive approach to maintenance, corrective maintenance, root cause analysis, failure reporting, project management, and budgeting are all completed using the ERP system.

## Competition

There are several other companies operating in the renewable energy and waste-to-energy space, ranging from other project developers to service or equipment providers.

Our primary competition is from other companies or solutions for access to biogas from waste. Evolving consumer preferences, regulatory conditions, ongoing waste industry trends, and project economics have a strong effect on the competitive landscape and our relative ability to continue to generate revenues and cash flows. We believe that our status as one of the largest operators of LFG-to-RNG projects, our 30-year track record of operating and developing projects, and our deep relationships with some of the largest landfill owners and dairy farms in the country position us very well to continue to operate and grow our portfolio, and respond to competitive pressures. We have demonstrated a track record of strategic flexibility across our 30-year history which has allowed us to pivot towards projects and markets that we believe deliver optimal returns and stockholder value in response to changes in market, regulatory and competitive pressures.



The biogas market is highly fragmented. We believe our size relative to many other LFG companies and our capital structure puts us in a strong position to compete for new project development opportunities or acquisitions of existing projects. However, competition for such opportunities, including the prices being offered for fuel supply, will impact the expected profitability of projects to us, and may make projects unsuitable to pursue. Likewise, prices being offered by our competitors for fuel supply may increase the royalty rates that we pay under our fuel supply agreements when such agreements expire and need to be renewed or when expansion opportunities present themselves at the landfills where our projects currently operate. It is also possible that more landfill owners may seek to install their own LFG projects on their sites, which would reduce the number of opportunities for us to develop new projects. Our overall size, reputation, access to capital, experience and decades of proven execution on LFG project development and operation leave us well-positioned to compete with other companies in our industry.

We are aware of several competitors in the United States that have a similar business model to our own, including Archaea Energy (acquired by bp in 2022), Morrow Renewables, Opal Fuels, U.S. Gain, Brightmark, and AMP Energy, as well as companies with biogas-to-energy facilities as a segment or subsidiary of their operations, including DTE and Ameresco. In addition, certain landfill operators, such as Waste Management, have also chosen to selectively pursue biogas conversion projects at their sites. Finally, Republic has entered into a joint venture with Archaea Energy to develop certain of its LFG locations.

## Government Regulation

Our projects are subject to a range of federal, state and local environmental, health and safety laws and regulations, depending on the nature and configuration of the project, as well as where the project is located. We have established processes and procedures to comply with laws and regulations applicable to our operations, and have partnered with external experts, as needed, to meet applicable compliance requirements. As a renewable energy company, we are committed to being good stewards of the environment and to positively impacting the communities in which we operate.

All of our current Renewable Electricity projects are QFs. As a result, the facilities are exempt from rate regulation under Sections 205 and 206 of the Federal Power Act. We are required to document the QF status of each of our facilities in applications or self-certifications filed with FERC, which typically require disclosure of upstream facility ownership, fuel and size characteristics, power sales, interconnection matters, and related technical disclosures. Failure to maintain QF status may subject the project to additional regulatory requirements and may require the payment of refunds to customers and other costs or penalties.

We are subject to the Clean Air Act which regulates the emissions of pollutants to protect the environmental and public health. The combustion of biogas results in emissions of carbon monoxide, oxides of nitrogen, sulfur dioxide, volatile organic compounds and particulate matter. Federal, state and local laws may require us to obtain permits or impose other burdens, including monitoring, testing recordkeeping and reporting by us in order for us to conduct operations. In addition, our operations and the operations of landfills may be subject to additional air emissions laws and regulations, such as those designed to address the emission of methane, a potent GHG.

Among other laws, we are subject to Subtitle D of the Resource Conservation and Recovery Act and other federal, state and local laws, which impose conditions on the handling of non-hazardous waste, including the emission of methane in landfills. Likewise, we are subject to the Comprehensive Environmental Response Compensation and Liability Act of 1980 and other federal, state and local laws, which govern the investigation and cleanup of sites contaminated with hazardous substances. We have not been identified as a potentially responsible party with respect to environmental remedial costs at any site to date. We also may be required to obtain permits to discharge wastewater and stormwater pursuant to the Clean Water Act’s National Pollutant Discharge Elimination System and other federal, state and local laws governing such discharges.

Our RNG projects are subject to federal RFS program regulations, including the Energy Policy Act of 2005 and the Energy Independence and Security Act. The EPA administers the RFS program with volume requirements



for several categories of renewable fuels. The EPA’s RFS regulations establish rules for fuel supplied and administer the RIN system for compliance, trading credits and rules for waivers. The EPA calculates a blending standard for each year based on estimates of gasoline usage from the Department of Energy’s Energy Information Agency. Separate quotas and blending requirements are determined for cellulosic biofuels, BBD, advanced biofuels and total renewable fuel. Further, we are required to register each RNG project with the EPA and relevant state regulatory agencies.

We qualify our RINs through a voluntary Quality Assurance Plan, which typically takes from three to five months from first injection of RNG into the commercial pipeline system. Further, we typically make a large investment in the project prior to receiving the regulatory approval and RIN qualification. In addition to registering each RNG project, we are subject to quarterly audits under the Quality Assurance Plan of our projects to validate our qualification.

Our RNG projects are also subject to state renewable fuel standard regulations. The CA LCFS program requires producers of petroleum-based fuels to reduce the CI of their products, beginning with a quarter of a percent in 2011, a 10% total reduction in 2020, and a 20% total reduction in 2030. Petroleum importers, refiners and wholesalers can either develop their own low-carbon fuel products, or buy CA LCFS credits from other companies that develop and sell low-carbon alternative fuels, such as biofuels, electricity, natural gas or hydrogen. We are subject to a qualification process similar to that for RINs, including verification of CI levels and other requirements, currently exists for CA LCFS credits.

Our RNG projects are also impacted by state and federal gas quality standards. State regulators determine whether RNG may be purchased by the state’s local gas utilities, and whether a site operator may directly sell gas to a retail, or direct end-use, customer. FERC regulates the natural gas pipelines that transport gas in interstate commerce, and specifies or approves a gas pipeline’s tariff that sets the rates, terms and conditions, gas quality, and other requirements applicable to transportation of natural gas on the pipelines, including shipping RNG. Our sites are not permitted, and may not be physically able, to deliver RNG to a FERC regulated pipeline unless the pipeline’s receipt of the gas is consistent with the standards adopted in the pipeline’s FERC tariff. RNG-related gas quality standards may vary by pipeline and may be revised at any time, subject to all required regulatory approvals. We routinely test the RNG produced at our facilities in order to ensure compliance with applicable pipeline gas quality standards.

We monitor regulatory trends and developments in the U.S. regarding the regulation of greenhouse gas emissions. We are aware the U.S. Environmental Protection Agency proposed the regulation of methane emissions, a greenhouse gas, from oil and gas facilities in November 2021. We do not anticipate this proposed regulation will apply to our operations and could, combined with another public policy and private sector initiatives, increase interest in developing more renewable energy projects in the U.S. We will continue to monitor greenhouse gas regulatory initiatives in the U.S. and assess their potential relevance to our business and operations.

We routinely conduct compliance audits on our projects to proactively identify and correct potential compliance deficiencies or risks. Additionally, we closely monitor emerging regulatory developments that may impact our operations or business strategy. Montauk also participates in industry trade groups, such as the RNG Coalition, to advocate policies and regulatory frameworks that support continued expansion of renewable energy in the United States.

The operation of our business may expose us to certain liabilities and compliance costs related to environmental matters. These liabilities or compliance costs did not have a material effect on our capital expenditures or competitive position for fiscal 2022, nor do we expect them to have a material effect in the future. We believe we are in material compliance with all environmental regulations applicable to our operations.

Inflation Reduction Act. The Inflation Reduction Act will be administered by multiple federal agencies including EPA, U.S. Department of Energy and the Internal Revenue Service of the U.S. Department of the



Treasury. The goals of the Inflation Reduction Act include incentivizing the development and production of renewable energy. We cannot speculate on exactly how the Inflation Reduction Act will be implemented; however, the Act does contain numerous incentives for the production of clean energy which may impact our products.

## Employees and Human Capital Resources

## Employee Profile

We employed 137 people on December 31, 2022, located in California, Idaho, Ohio, Oklahoma, Pennsylvania, North Carolina and Texas. Our employee population is comprised of a mix of field operations personnel and office-based professionals. As of December 31, 2022, none of our employees were represented by a collective bargaining unit or labor union. We consider our employee relations to be good across our organization.

## Health and Safety

Safety, including the health of our employees, is one of our core values and a priority across our operations. We are committed to developing a strong health and safety culture that reduces injuries and illness whenever possible. Our health and safety strategy is designed to proactively identify, mitigate and eliminate conditions that could result in serious injury or fatality. We also routinely train our employees on health and safety practices applicable to their job function and provide them all necessary personal protective equipment to perform their job in a safe manner.

Our recordable cases and total recordable incident rate (“TRIR”), excluding COVID-19 related incidents, was 3.00 in 2022, above the 2021 national average of 2.7 TRIR for all industries. We continue to focus on practices and measures to lower our TRIR.

## Employee Development and Training

The success and growth of our business is significantly correlated with our ability to recruit, train, promote and retain talented individuals at all levels of our organization. To succeed in a competitive labor market, we have developed and implemented various recruitment and retention strategies. These include competitive salary structures, bonus programs and competitive benefits, as well as paid time off, sick leave, disability coverage, group term life insurance, and a retirement savings program. We also offer our employees tuition reimbursement for job-related education and training opportunities.

## Intellectual Property

We rely on a combination of patent, trademark, copyright and trade secret laws, employee and third-party nondisclosure/confidentiality agreements and license agreements to protect our intellectual property. We acquired certain technology associated with the Montauk Ag Renewables Acquisition for which we received a patent during 2021 with a term of 20 years. In 2022, we filed a provisional patent application pertaining to a combustion-based oxygen removal condensate neutralization technology we developed. The provisional patent covers a new low pH neutralization technology designed to mitigate unfavorable pH condensate that is produced when wastewater is removed from the biogas conversion process. While we hold patents related to our business, we do not view our patents to be material to our total business.

## Segments and Geographic Information

We have two operating segments: Renewable Natural Gas and Renewable Electricity Generation. While our corporate entity is not an operating segment, we discretely disclose corporate entity revenues for purposes of



reconciliation of the Company’s consolidated financial statements. For information regarding revenues and other information regarding our results of operations for each of our last two financial years, please refer to our financial statements included in this report and within “Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report.

## Corporate Information

Montauk Renewables, Inc. is incorporated in the State of Delaware. Our principal executive offices are located at 5313 Campbells Run Road, Suite 200, Pittsburgh, PA 15205. Our telephone number is (412) 747-8700.

We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.

We also make financial information, news releases and other information available on our corporate investor relations website at www.ir.montaukrenewables.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free of charge on this website as soon as reasonably practicable after we file these reports and amendments with, or furnish them to, the SEC. The information contained on or connected to our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report filed with the SEC.

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012. As an emerging growth company, we may take advantage of certain reduced reporting requirements that are otherwise applicable generally to public companies. We currently intend to take advantage of several of these reduced reporting requirements, including the extended transition periods for complying with new or revised accounting standards. See “Item 1A. Risk Factors—Emerging Growth Company Risks” for certain risks related to our status as an emerging growth company.

We are a “controlled company” within the meaning of the Nasdaq Stock Market LLC (“Nasdaq”) corporate governance standards. Certain stockholders, which are affiliates of two of our directors, Mr. John A. Copleyn and Theventheran G. Govender, own approximately 52.3% of our common stock and have entered into a Consortium Agreement (the “Consortium Agreement”) whereby the parties thereto will agree to act in concert with respect to voting our common stock, including in the election of directors, among other matters. As a controlled company, we may elect not to comply with certain Nasdaq corporate governance standards. See “Item 1A. Risk Factors—Common Stock Risks” for certain risks related to our status as a controlled company.

This report includes estimates, projections, and other information concerning our industry and market data, including data regarding the estimated size of the market, projected growth rates, and perceptions and preferences of consumers. We obtained this data from industry sources, third-party studies, including market analyses and reports, and internal company surveys. Industry sources generally state that the information contained therein has been obtained from sources believed to be reliable. Although we are responsible for all of the disclosure contained in this report, and we believe the industry and market data to be reliable as of the date of this report, this information could prove to be inaccurate.



## Information About Our Executive Officers

Below is a list of the names, ages, and positions of our executive officers, and a brief summary of the business experience of our executive officers (ages as of March 16, 2023).

<table><tr><td>Name</td><td>Age</td><td>Position</td></tr><tr><td>Sean F. McClain</td><td>48</td><td>President and Chief Executive Officer, Director</td></tr><tr><td>Kevin A. Van Asdalan</td><td>45</td><td>Chief Financial Officer and Treasurer</td></tr><tr><td>James A. Shaw</td><td>51</td><td>Vice President of Operations</td></tr><tr><td>Scott Hill</td><td>56</td><td>Vice President of Business Development</td></tr><tr><td>John Ciroli</td><td>52</td><td>Chief Legal Officer and Secretary</td></tr><tr><td>Sharon Frank</td><td>66</td><td>Vice President of Environmental, Health and Safety</td></tr></table>

Sean F. McClain. Mr. McClain has served as our President and Chief Executive Officer and a member of our Board of Directors (the "Board") since January 4, 2021. He previously served as a member of the Board of Directors of MNK from August 2014 until March 2023 and as its President and Chief Executive Officer since September 2019. Mr. McClain resigned as a member of the Board of Directors of MNK at the MNK March 2023 annual general meeting. Mr. McClain served as MNK's Chief Financial Officer from August 2014 until September 2019 and as the Chief Financial Officer of Montauk Energy Holdings ("MEH") from April 2011 until August 2014. Prior to joining MNK and its affiliates, he held various management positions with BPL Global Limited, Bayer A.G. and Dick's Sporting Goods, Inc. and was in public accounting at Arthur Andersen LLP. He has over 25 years of business and financial management experience. He is a Certified Public Accountant.

Kevin A. Van Asdalan. Mr. Van Asdalan has served as our Chief Financial Officer and Treasurer since January 4, 2021. He previously served as a member of the Board of Directors of MNK from September 2019 to March 2023, and as Chief Financial Officer of MEH. Mr. Van Asdalan resigned as a member of the Board of Directors of MNK at the MNK March 2023 annual general meeting. Prior to that time, he was Controller of MEH from March 2018 to September 2019. Prior to joining MEH, Mr. Van Asdalan served as Controller, Construction Products, Controller, Tubular Products, and Manager of External Financial Reporting at the L.B. Foster Company, a manufacturer and distributor of products and provider of service for transportation and energy infrastructure (“L.B. Foster”), from July 2011 to March 2018. Prior to L.B. Foster, Mr. Van Asdalan held senior associate positions at PricewaterhouseCoopers LLP and Sisterson & Co LLP, both accounting firms. He has 20 years of business and financial management experience including accounting, financial reporting, corporate compliance and acquisitions. He is a Certified Public Accountant and Chartered Global Management Accountant.

James A. Shaw. Mr. Shaw has served as our Vice President of Operations since January 4, 2021. He has also served as the Vice President of Operations of MNK since September 2019. He previously served as North Region Manager of MEH from May 2016 to September 2019. He also held the position of Site Manager for five MEH operating sites in Pennsylvania from April 2015 to April 2016 and two MEH operating sites in Pennsylvania from June 2010 to March 2015. Prior to joining MEH, he was a facility manager for SONY Electronics Inc. at the world’s first vertically integrated television manufacturing facilities. Mr. Shaw has more than 25 years of experience in facilities operations and management.

Scott Hill. Mr. Hill has served as our Vice President of Business Development since January 4, 2021. He has also served as Vice President of Business Development of MNK since December 2020. Mr. Hill served as MEH's Vice President of Engineering from April 2018 to December 2020, Vice President of Engineering and Operations from September 2015 to April 2018, and Vice President of Operations from May 2010 to September 2015. Mr. Hill has over 30 years of experience in landfill and landfill-to-gas operations and engineering, including contract negotiation, permitting, construction, design, and management. Prior to joining MEH, he held positions with Energy Systems Group, Energy Developments Inc., Ecogas Corporation, HDR Engineering, Inc. and the City of Los Angeles. Mr. Hill is a registered Professional Engineer.



John Ciroli, Mr. Ciroli has served as our Chief Legal Officer since January 2023 and previously served as Vice President, General Counsel and Secretary since January 4, 2021. He has also served as MNK's Vice President General Counsel and Corporate Secretary since July 2020. From July 2016 to July 2020, Mr. Ciroli was the North American Counsel and HR Manager for the North American subsidiaries of FAAC Group, a company that designs, builds and markets reliable solutions for pedestrian and vehicle needs, representing all the entities in their American and Canadian portfolio. From 2014 to July 2016, Mr. Ciroli was a Senior Litigation Counsel with the Housing Authority of the City of Pittsburgh. Mr. Ciroli has over 23 years of experience representing and advising domestic and international corporations and government entities in the areas of contracts, mergers and acquisitions, litigation, employment and governmental procurement and regulatory affairs. He was also a professor for Concord Law School, now Purdue Global, in the areas of Contracts, Constitutional Law, Torts and Evidence and is a member of the Pennsylvania State Bar and the bar of the U.S. Supreme Court.

Sharon Frank. Ms. Frank has worked at the Company since 2007 and has served as our Vice President of Environmental, Health and Safety since October 2021. Ms. Frank previously served as Director of Environmental, Health and Safety from April 2020 until October 2021. Prior to that, Ms. Frank, served as Manager of Environmental Compliance from June 2007 until April 2020. Prior to joining the Company, Ms. Frank was Manager, Environmental Affairs for Duquesne Light Company’s unregulated business group from 2000 to 2007. Ms. Frank has over 30 years of regulatory and environmental compliance experience.



## ITEM 1A. RISK FACTORS.

This Annual Report on Form 10-K contains forward-looking information based on our current expectations. Because our business is subject to many risks and our actual results may differ materially from any forward-looking statements made by or on behalf of us, this section includes a discussion of important factors that could affect our business, operating results, financial condition and the trading price of Montauk common stock. You should carefully consider these risk factors, together with all of the other information included in this Annual Report on Form 10-K as well as our other publicly available filings with the SEC. Although the risks are organized by headings, and each risk is discussed separately, many are interrelated.

## Operational Risks

## Our renewable energy projects may not generate expected levels of output.

Landfills contain organic material whose decomposition causes the generation of gas consisting primarily of methane, which our RNG projects use to generate power or renewable natural gas, and carbon dioxide. The estimation of landfill gas production volume is an inexact process and dependent on many site-specific conditions, including the estimated annual waste volume, composition of waste, regional climate and the capacity and construction of the landfill. Production levels are subject to a number of additional risks, including a failure or wearing out of our or our landfill operators', customers' or utilities' equipment; an inability to find suitable replacement equipment or parts; less than expected supply or quality of the project's source of biogas and faster than expected diminishment of such biogas supply; or volume disruption in our fuel supply collection system. Any extended interruption and/or volume disruption in the project's operation, or failure of the project for any reason to generate the expected amount of output, could adversely affect our business and operating results. In addition, we have in the past, and may in the future, incur material asset impairment charges if any of our renewable energy projects incur operational issues that indicate our expected future cash flows from the project are less than the project's carrying value. Any such impairment charge could adversely affect our operating results in the period in which the charge is recorded.

In addition, in order to maximize collection of LFG, we will need to take various measures, such as drilling additional gas wells in the landfill to increase LFG collection, balancing the pressure on the gas field based on the data collected by the landfill operator from the gas wells to ensure optimum landfill gas utilization and ensuring that we match availability of engines and related equipment to availability of LFG. There can be no guarantee that we will be able to take all necessary measures to maximize collection. In addition, the LFG available to our projects is dependent in part on the actions of other persons, such as landfill operators. We may not be able to ensure the responsible management of the landfill site by owners and operators, which may result in less than optimal gas generation or increase the likelihood of “hot spots” occurring. Hot spots can temporarily reduce the volume of gas which may be collected from a landfill site, resulting in a lower gas yield. Other events that can result in a reduction in LFG output include: extreme hot or cold temperatures or excessive rainfall; liquid levels within a landfill increasing; oxidation within a landfill, which can kill the anaerobic microbes that produce landfill gas; and the buildup of sludge. The occurrence of these or any other changes within any of the landfills where our projects operate could lead to a reduction in the amount of LFG available to operate our projects, which could have a material adverse effect on our business, financial condition and results of operations.

The concentration in revenues from five of our projects and geographic concentration of our projects exposes us to greater risks of production interruptions from severe weather or other interruptions of production or transmission.

A substantial portion of our revenues are generated from five project sites. For the years ended December 31, 2022 and 2021, excluding the effect of derivative instruments, approximately 72.4% and 76.3%, respectively, of operating revenues were derived from these locations. During 2022, RNG production at our McCarty, Rumpke, Atascocita and Apex facilities accounted for approximately 17.5%, 21.6%, 21.6%, and 10.2% of our RNG revenues, respectively, and 15.2%, 26.3%, 18.6%, and 9.5% of the RNG we produced during 2022,



respectively. During 2022, Renewable Electricity production at our Bowerman Power LFG, LLC (“Bowerman”) facility accounted for approximately 90.5% of our Renewable Electricity Generation revenues and 82.3% of the Renewable Electricity we produced during 2022. A lengthy interruption of production or transmission of renewable energy from one or more of these projects, as a result of a severe weather event, failure or degradation of our or a landfill operator’s equipment or interconnection transmission problems could have a disproportionate effect on our revenues and cash flow as further described below.

Our Atascocita, McCarty, Galveston and Coastal Plains projects are located within 20 miles of each other near Houston, Texas and seven of our other RNG projects are located in relatively close proximity to each other in Pennsylvania and Ohio. Regional events, such as gas transmission interruptions, regional availability of replacement parts and service in the event of equipment failures and severe weather events in either of those geographic regions could adversely affect our RNG production and transmission more than if our projects were more geographically diversified. Historically cold weather impacted our Houston, Texas facilities during the winter of 2020-2021. Production at these facilities was temporarily idled from February 14, 2021 through February 20, 2021 while the facilities were without power. The index based pricing for the cost of utilities were adversely impacted during the month of February. Force majeure events were declared for the period February 12 through February 22, 2021 related to these weather events Operations at these facilities have subsequently resumed, but as a result of our utility provisions when we are not using utilities, providers are able to contribute the capacity back into the market and we receive credit against our future bills.

Additionally, California wildfires, which occurred in October of 2020, forced our Bowerman facility to temporarily shut down and caused limited damage to our facility and equipment. Production was reduced by approximately 38% at the Bowerman facility during the fourth quarter of 2020 as compared to the fourth quarter of 2019. While production resumed in November 2020, our first quarter of 2021 revenues related to the Bowerman facility were approximately 18.9% lower than the prior year period, related in part to these wildfires.

Our projects are not able to insure against all potential risks and may become subject to higher insurance premiums.

Our projects are exposed to the risks inherent in the construction and operation of renewable energy projects, such as breakdowns, manufacturing defects, extreme weather, natural disasters, terrorist attacks and sabotage. We are also exposed to environmental risks.

We have insurance policies covering certain risks associated with our business. Our insurance policies do not, however, cover all losses, including, in some situations, those as a result of force majeure, which is generally defined as events that are beyond the control of the parties. For example, we did not receive any insurance recovery from the shutdowns in Houston in February 2021 due to the extreme cold or from the Bowerman shutdown in October 2020 due to wildfires. Even if insurance policies for some of our projects cover losses as a result of certain types of force majeure events, such coverage is subject to important limitations. Furthermore, insurance liabilities are difficult to assess and quantify due to unknown factors, including the severity of an injury, the determination of our liability in proportion to other parties, the number of incidents not reported and the effectiveness of our safety program. Insurance coverage is not always available on commercially reasonable terms (if at all) and is often capped at predetermined limits. In addition, our insurance policies are subject to annual review by our insurers and may not be renewed on similar or favorable terms or at all. A serious uninsured loss or a loss significantly exceeding the limits of our insurance policies could adversely affect our business, financial condition and results of operations.

## Competition Risks

We may face intense competition and may not be able to successfully compete.

There are a number of other companies operating in the renewable energy and waste-to-energy markets. These include other renewable energy companies and service or equipment providers, consultants, managers and strategic investors.



We may not have the resources to compete with our existing competitors or with any new competitors, including in a competitive bidding process. Some of our competitors have significantly larger personnel, financial and managerial resources than we have, and we may fail to maintain or expand our business. Our competitors may also offer energy solutions at prices below cost, devote significant sales forces to competing with us or attempt to recruit our key personnel by increasing compensation, any of which could improve their competitive positions. Moreover, if the demand for renewable energy increases, new companies may enter the market, and the influx of added competition will pose an increased risk to us.

Further, certain of our strategic partners and other landfill or agricultural operators could decide to manage, recover and convert biogas from waste to renewable energy on their own which would further increase our competition, limit the number of commercially viable landfill sites available for our projects or require us to reduce our profit margins to maintain or acquire projects.

## Our success depends, in part, on technological innovation to stay ahead of market competitors.

Our success will depend on our ability to create and maintain a competitive position in the renewable energy industry. Other than the patented technology acquired through the Montauk Ag Renewables Acquisition, we do not have any exclusive rights to any of the technologies that we utilize, and our competitors may currently use and may be planning to use identical, similar or superior technologies. While significant to the development associated with our emerging North Carolina Montauk Ag Renewables business, we do not currently consider the patented technology material to the total business. In addition, the technologies that we use may be rendered obsolete or uneconomical by technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others.

We may also face competition based on technological developments that reduce demand for electricity, increase power supplies through existing infrastructure or that otherwise compete with our projects. We also encounter competition in the form of potential customers electing to develop solutions or perform services internally rather than engaging an outside provider such as us.

Our use and enjoyment of real property rights for our projects may be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to our projects.

Our projects generally are, and any of our future projects are likely to be, located on land occupied pursuant to long-term easements, leases and rights of way. The ownership interests in the land subject to these easements, leases and rights-of-way may be subject to mortgages securing loans or other liens (such as tax liens) and other easement, lease rights and rights-of-way of third parties (such as leases of oil or mineral rights) that were created prior to our projects' easements, leases and rights-of-way. As a result, certain of our projects' rights under these easements, leases or rights-of-way may be subject, and subordinate, to the rights of those third parties. We may not be able to protect our operating projects against all risks of loss of our rights to use the land on which our projects are located, and any such loss or curtailment of our rights to use the land on which our projects are located and any increase in rent due on such lands could adversely affect our business, financial condition and results of operations.

We may not be able to obtain long-term contracts for the sale of power produced by our projects on favorable terms and we may not meet certain milestones and other performance criteria under existing PPAs.

Obtaining long-term contracts for the sale of power produced by our projects at prices and on other terms favorable to us is essential for the long term success of our business. We must compete for PPAs against other developers of renewable energy projects. This intense competition for PPAs has resulted in downward pressure



on PPA pricing for newly contracted projects. The inability to compete successfully against other power producers or otherwise enter into PPAs favorable to us would negatively affect our ability to develop and finance our projects and negatively affect our revenues. In addition, the availability of PPAs depends on utility and corporate energy procurement practices that could evolve and shift allocation of market risks over time. Further, PPA availability and terms are a function of a number of economic, regulatory, tax, and public policy factors, which are also subject to change.

Our PPAs typically require us to meet certain milestones and other performance criteria. Our failure to meet these milestones and other criteria, including minimum quantities, may result in price concessions, in which case we would lose any future cash flow from the relevant project and may be required to pay fees and penalties to our counterparty. We cannot assure you that we will be able to perform our obligations under such agreements or that we will have sufficient funds to pay any fees or penalties thereunder.

## Business Strategy Risks

Our commercial success depends on our ability to identify, acquire, develop and operate individual renewable energy projects, as well as our ability to maintain and expand production at our current projects.

We aim to maintain and grow our position as a leading producer of RNG in the United States. Our specific focus on the renewable energy sector exposes us to risks related to the supply of and demand for energy commodities and Environmental Attributes, the cost of capital expenditures, government regulation, world and regional events and economic conditions, and the acceptance of alternative power sources. As a renewable energy producer, we may also be negatively affected by lower energy output resulting from variable inputs, mechanical breakdowns, faulty technology, competitive electricity markets or changes to the laws and regulations that mandate the use of renewable energy sources by refiners and importers of gasoline and diesel fuel and electric utilities.

In addition, several other factors related to the development and operation of individual renewable energy projects could adversely affect our business, including:

- regulatory changes that affect the demand for or supply of Environmental Attributes and the prices thereof, which could have a significant effect on the financial performance of our projects and the number of potential projects with attractive economics;

- changes in energy commodity prices, such as natural gas and wholesale electricity prices, which could have a significant effect on our revenues;

- changes in pipeline gas quality standards or other regulatory changes that may limit our ability to transport RNG on pipelines for delivery to third parties or increase the costs of processing RNG to allow for such deliveries;

- changes in the broader waste collection industry, including changes affecting the waste collection and biogas potential of the landfill industry, which could impede the LFG resource that we currently target for our projects;

- substantial construction risks, including the risk of delay, that may arise due to forces outside of our control, including those related to engineering and environmental problems, as a result of inclement weather or labor disruptions;

- operating risks and the effect of disruptions on our business, weather conditions, catastrophic events such as fires, explosions, earthquakes, droughts and acts of terrorism, and other force majeure events on us, our customers, suppliers, distributors and subcontractors;

- the ability to obtain financing for a project on acceptable terms or at all and the need for substantially more capital than initially budgeted to complete projects and exposure to liabilities as a result of unforeseen environmental, construction, technological or other complications;



• entering into markets where we have less experience, such as our projects for biogas recovery at livestock farms;

- the need for substantially more capital to complete projects than initially budgeted and exposure to liabilities as a result of unforeseen environmental, construction, technological or other complications;

- failures or delays in obtaining desired or necessary land rights, including ownership, leases, easements, zoning rights and building permits;

- a decrease in the availability, pricing and timeliness of delivery of raw materials and components, necessary for the projects to function;

- obtaining and keeping in good standing permits, authorizations and consents from local city, county, state and U.S. federal governments as well as local and U.S. federal governmental organizations;

- penalties, including potential termination, under short-term and long-term contracts for failing to deliver RNG in accordance with our contractual obligations;

- unknown regulatory changes RNG which may increase the transportation cost for delivering under contracts in place;

- the consent and authorization of local utilities or other energy development off-takers to ensure successful interconnection to energy grids to enable power sales; and

• difficulties in identifying, obtaining and permitting suitable sites for new projects.

Any of these factors could prevent us from completing or operating our projects, or otherwise adversely affect our business, financial condition and results of operations.

If there is not sufficient demand for renewable energy, or if renewable energy projects do not develop or take longer to develop than we anticipate, we may be unable to achieve our investment objectives.

If demand for renewable energy fails to grow sufficiently, we may be unable to achieve our business objectives. In addition, demand for renewable energy projects in the markets and geographic regions that we target may not develop or may develop more slowly than we anticipate. Many factors will influence the widespread adoption of renewable energy and demand for renewable energy projects, including:

- cost-effectiveness of renewable energy technologies as compared with conventional and competitive technologies;

- performance and reliability of renewable energy products as compared with conventional and non-renewable products;

- fluctuations in economic and market conditions that impact the viability of conventional and competitive alternative energy sources;

• increases or decreases in the prices of oil, coal and natural gas;

• continued deregulation of the electric power industry and broader energy industry; and

• availability or effectiveness of government subsidies and incentives.

Acquisition, financing, construction and development of new projects and project expansions and conversions may not commence on anticipated timelines or at all.

Our strategy is to continue to expand in the future, including through the acquisition of additional projects. From time to time, we enter into nonbinding letters of intent for projects. However, until the negotiations are



finalized and the parties have executed definitive documentation, we cannot assure you that we will be able to enter into any development or acquisition transactions, or any other similar arrangements, on the terms in the applicable letter of intent or at all.

The acquisition, financing, construction and development of new projects involves numerous risks, including:

• difficulties in identifying, obtaining and permitting suitable sites for new projects;

• failure to obtain all necessary rights to land access and use;

• assumptions with respect to the cost and schedule for completing construction;

• assumptions with respect to the biogas potential, including quality, volume, and asset life, for new projects;

• the ability to obtain financing for a project on acceptable terms or at all;

• delays in deliveries or increases in the prices of equipment;

• permitting and other regulatory issues, license revocation and changes in legal requirements;

• increases in the cost of labor, labor disputes and work stoppages;

• failure to receive quality and timely performance of third-party services;

• unforeseen engineering and environmental problems;

• cost overruns;

• accidents involving personal injury or the loss of life; and

- weather conditions, catastrophic events, including fires, explosions, earthquakes, droughts and acts of terrorism, and other force majeure events.

In addition, new projects have no operating history and may employ recently developed technology and equipment. A new project may be unable to fund principal and interest payments under its debt service obligations or may operate at a loss, which may adversely affect our business, financial condition or results of operations.

We may also experience delays and cost overruns in converting existing facilities from Renewable Electricity to RNG production. During the conversation projects, there is a gap in production and relating revenue while the electricity project is offline until it commences operation as an RNG facility, which adversely affects our financial condition and results of operations.

Our fuel supply agreements with site hosts have defined contractual periods, and we cannot assure you that we will be able to successfully extend these agreements.

Fuel supply rights are issued by the landfill owner to operators for a contractual period. As operators, we have already invested resources in the development of existing sites and the ability to extend these contracts on expiration would enable us to achieve operational efficiency in continuing to generate revenues from a site without significant additional capital investments. We cannot assure you that we will be able to extend existing fuel supply agreements when they expire.

Our agreements contain complex price adjustments, calculations and other terms based on gas price indices and other metrics, the interpretation of which could result in disputes with counterparties that could affect our results of operations and customer relationships.

Certain of our PPAs, fuel supply agreements, RNG off-take agreements and other agreements require us to make payments or adjust prices to counterparties based on past or current changes in gas price indices, project



productivity or other metrics and involve complex calculations. Moreover, the underlying indices governing payments under these agreements are subject to change, may be discontinued or replaced. The interpretation of these price adjustments and calculations and the potential discontinuation or replacement of relevant indices or metrics could result in disputes with the counterparties with respect to these agreements. Any such disputes could adversely affect project revenues, expense margins, customer or supplier relationships, or lead to costly litigation, the outcome of which we would be unable to predict.

In order to secure contracts for new projects, we typically face a long and variable development cycle that requires significant resource commitments and a long lead time before we realize revenues.

The development, design and construction process for our renewable energy projects generally lasts from 18 to 36 months, on average. We frequently receive requests for proposals from potential site hosts as part of their consideration of alternatives for their proposed projects. Prior to responding to an RFP, we typically conduct a preliminary audit of the site host's needs and assess whether the site is commercially viable based on our expected return on investment, investment payback period, and other operating metrics, as well as the necessary permits to develop a project on that site. If we are awarded a project, we then perform a more detailed review of the site's facilities, which serves as the basis for the final specifications of the project. Finally, we negotiate and execute a contract with the site host. This extended development process requires the dedication of significant time and resources from our sales and management personnel, with no certainty of success or recovery of our expenses. A potential site host may go through the entire sales process and not accept our proposal. Further, upon commencement of operations, it typically takes 12 months or longer for the project to ramp up to our expected production level. All of these factors, and in particular, increased spending that is not offset by increased revenues, can contribute to fluctuations in our quarterly financial performance and increase the likelihood that our operating results in a particular period will fall below investor expectations.

We plan to expand our business in part through developing RNG recovery projects at landfills and livestock farms, but we may not be able to identify suitable locations or complete development of new projects.

Historically, development of new RNG projects at landfills and livestock farms has been a significant part of our growth strategy. We plan to continue to develop new RNG projects at landfills and livestock farms to expand our project skillsets and capabilities, expand and complement our existing geographic markets, add experienced management and increase our product offerings. However, we may be unable to implement this growth strategy if we cannot identify suitable landfills and livestock farms on which to develop projects, reach agreements with landfill or livestock farm owners to develop RNG projects on acceptable terms or arrange required financing for new projects on acceptable terms. While the EPA has identified an additional 470 landfills as candidates for biogas projects, based on our industry experience and technical knowledge and analysis, after evaluating their currently available LFG collection systems and potential production capacities, we believe that approximately 38 of these sites produce sufficient quantities of LFG to support commercial-scale projects, with 25 of the approximately 38 sites being operated by Waste Management or Republic Waste, with whom we would need to negotiate with to secure sufficient LFG rights to support an RNG project. In the future, additional candidate landfills may become economically viable as their growth increases LFG production and requires installation of LFG collection systems. However, the time and effort involved in attempting to identify suitable sites and development of new projects may divert members of our management from our operations.

Our dairy farm project has, and any future digester project will have, different economic models and risk profiles than our landfill facilities, and we may not be able to achieve the operating results we expect from these projects.

Our dairy farm project produces significantly less RNG than our landfill facilities. As a result, we will be even more dependent on the LCFS credits and RINs produced at our dairy farm project than on the RINs produced at our landfill facilities for the project’s commercial viability. Since the number of LCFS credits for RNG generated on dairy farms is significantly greater than the number of LCFS credits for RNG generated at



landfills, we are substantially more dependent upon the revenue from LCFS credits for the commercial viability of the dairy farm project. In the event that CARB worsens the CI score that it applies to waste conversion projects, such as dairy digesters, the number of LCFS credits for RNG generated at our dairy farm project will decline. Additionally, revenue from LCFS credits also depends on the price per LCFS credit, which is driven by various market forces, including the supply of and demand for LCFS credits, which in turn depends on the demand for traditional transportation fuel and the supply of renewable fuel from other renewable energy sources, and mandated CI targets, which determine the number of LCFS credits required to offset LCFS deficits, and which increase over time. Fluctuations in the price of LCFS credits or the number of LCFS credits assigned will have a significantly greater impact on the success of our dairy farm project than the value that RINs have on our landfill facilities. A significant decline in the value of LCFS credits could require us to incur an impairment charge on our dairy farm project and could adversely affect our business, financial condition and results of operations.

While we currently focus on converting methane into renewable energy, in the future we may decide to expand our strategy to include other types of projects. Any future energy projects may present unforeseen challenges and result in a competitive disadvantage relative to our more established competitors.

Our business is currently focused on converting methane into renewable energy. In the future, we may expand our strategy to include other types of projects. We cannot assure you that we will be able to identify attractive opportunities outside of our current area of focus or acquire or develop such projects at a price and on terms that are attractive or that, once acquired or developed, such projects will operate profitably. In addition, these projects could expose us to increased operating costs, unforeseen liabilities or risks, and regulatory and environmental concerns associated with entering into new sectors of the energy industry, including requiring a disproportionate amount of our management’s attention and resources, which could adversely affect our business, as well as place us at a competitive disadvantage relative to more established market participants. A failure to successfully integrate such new projects into our existing project portfolio as a result of unforeseen operational difficulties or otherwise, could adversely affect our business, financial condition and results of operations.

Any future acquisitions, investments or other strategic relationships that we make could disrupt our business, cause dilution to our stockholders or harm our business, financial condition or operating results.

We expect future acquisitions of companies, purchases of assets and other strategic relationships to be an important part of our growth strategy. We plan to use acquisitions to expand our capabilities, expand our geographic markets, add experienced management and add to our project portfolio. However, we may not be able to identify suitable acquisition or investment candidates, reach agreements with acquisition targets on acceptable terms or arrange for any required financing for an acquisition on acceptable terms, any of which would materially impact our present strategy. While we perform due diligence on prospective acquisitions, we may not be able to discover all potential operational deficiencies in such projects. Further, if we are successful in consummating acquisitions, those acquisitions could subject us to a number of risks, including:

- the purchase prices we pay could significantly deplete our cash reserves or result in dilution to our existing stockholders;

- we may find that the acquired companies or assets do not improve our customer offerings or market position as planned;

• we may have difficulty integrating the operations and personnel of the acquired companies;

- key personnel and customers of the acquired companies may terminate their relationships with the acquired companies as a result of or following the acquisition;

- we may experience additional financial and accounting challenges and complexities in areas such as tax planning and financial reporting;



- we may experience delays in construction and development or regulatory approvals impacting, among other projects, the Pico, Apex or Montauk Ag development cycle;

- we may incur additional costs and expenses related to inflation and complying with additional laws, rules or regulations in new jurisdictions;

- we may assume or be held liable for risks and liabilities (including for environmental-related costs) as a result of our acquisitions, some of which we may not discover during our due diligence or adequately adjust for in our acquisition arrangements;

- our ongoing business and management’s attention may be disrupted or diverted by transition or integration issues and the complexity of managing geographically diverse enterprises;

• we may incur one-time write-offs or restructuring charges in connection with an acquisition;

- we may acquire goodwill and other intangible assets that are subject to amortization or impairment tests, which could result in future charges to earnings; and

• we may not be able to realize the cost savings or other modeled financial benefits we anticipated.

Any of these factors could adversely affect our business, financial condition and operating results.

## Our renewable fuel projects may be exposed to the volatility of the price of RINs.

The price of RINs is driven by various market forces, including gasoline prices and the availability of renewable fuel from other renewable energy sources and conventional energy sources. Refiners are permitted to carry-over up to 20% RINs generated for one calendar year after the RINs are generated to satisfy their RVO. As a result, we are only able to sell RINs on a forward basis for the year in which the RINs are generated and the following year. We may be unable to manage the risk of volatility in RIN pricing for all or a portion of our revenues from RINs, which would expose us to the volatility of commodity prices with respect to all or the portion of RINs that we are unable to sell through forward contracts, including risks resulting from changes in regulations, general economic conditions and changes in the level of renewable energy generation. We expect to have quarterly variations in the revenues from the projects in which we generate revenue from the sale of RINs that we are unable to sell through forward contracts.

## Our revenues may be subject to the risk of fluctuations in commodity prices.

The operations and financial performance of projects in the renewable energy sectors may be affected by the prices of energy commodities, such as natural gas, wholesale electricity and other energy-related products. For example, the price of renewable energy resources changes in relation to the market prices of natural gas and electricity. The market price for natural gas is sensitive to cyclical demand and capacity supply, changes in weather patterns, natural gas storage levels, natural gas production levels, general economic and geopolitical conditions (including the current conflict in Ukraine) and the volume of natural gas imports and exports. The market price of electricity is sensitive to cyclical changes in demand and capacity supply, and in the economy and geopolitical conditions (including the current conflict in Ukraine), as well as to regulatory trends and developments impacting electricity market rules and pricing, transmission development and investment to power markets within the United States and in other jurisdictions through interconnects and other external factors outside of the control of renewable energy power-producing projects. Volatility of commodity prices also creates volatility in the prices of Environmental Attributes, which are inversely related to the wholesale price of unleaded gasoline. In addition, volatility of commodity prices, such as the market price of gas and electricity, may also make it more difficult for us to raise any additional capital for our renewable energy projects that may be necessary to operate, to the extent that market participants perceive that a project’s performance may be tied directly or indirectly to commodity prices. Accordingly, the potential revenues and cash flows of these projects may be volatile and adversely affect the value of our investments.



Our off-take agreements for the sale of RNG are typically shorter in duration than our fuel supply agreements. Accordingly, if we are unable to renew or replace an off-take agreement for a project for which we continue to produce RNG, we would be subject to the risks associated with selling the RNG produced at that project at then-current market prices. We may be required to make such sales at a time when the market price for natural gas as a whole or in the region where that project is located, is depressed. If this were to occur, we would be subject to the volatility of gas prices and be unable to predict our revenues from such project, and the sales prices for such RNG may be lower than what we could sell the RNG for under an off-take agreement.

## We are subject to volatility in prices of RINs and other Environmental Attributes.

Volatility of commodity prices creates volatility in the price of Environmental Attributes. The value of RINs is inversely proportionate to the wholesale price of unleaded gasoline. Further, the production of RINs significantly in excess of the RVO \( _{s} \)  set by the EPA for a calendar year could adversely affect the market price of RINs, particularly towards the end of the year, if refiners and other RFS obligated parties have satisfied their RVO \( _{s} \)  for the year. A significant decline in the price of RINs and price of LCFS credits for a prolonged period could adversely affect our business, financial condition and results of operations, and could require us to take an impairment charge relating to one or more of our projects.

## We are exposed to the risk of failing to meet our contractual commitments to sell RINs from our production.

We may sell forward a portion of our RINs under contracts to fix the revenues from such attributes for financing purposes or to manage our risk against future declines in prices of such Environmental Attributes. If our RNG projects do not generate the amount of RINs sold under such forward contracts we may be required to make up the shortfall of RINs under such forward contracts through purchases on the open market or of the payment of liquidated damages. Forward selling our RINs could result in realized prices monetized in a year which do not correspond directly to index prices.

## The failure of our hedge counterparties or significant customers to meet their obligations to us may adversely affect our financial results.

To the extent we hedge our RNG revenues, our hedging transactions expose us to the risk that a counterparty fails to perform under a derivative contract. Volatility in the market index to which we hedge our RNG revenues could expose us to variability in our commodity based revenues. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by the counterparty to these derivative contracts could adversely affect our business, financial condition and results of operations.

We also face credit risk because we sell our RNG to a limited number of significant customers who do not post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

## Regulatory Risks

The reduction or elimination of governmental economic incentives for renewable energy projects or other related policies could adversely affect our business, financial condition and results of operation.

We depend, in part, on Environmental Attributes, which are federal, state and local government incentives in the United States, provided in the form of RINs, RECs, LCFS credits, rebates, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects, that promote the use of renewable energy. RINs are created through the RFS program administered by the EPA, which requires transportation fuel sold in the United States to contain a minimum volume of renewable fuel and has historically



permitted refineries and importers of transportation fuel to satisfy their RVO by purchasing either (i) D5 RINs and cellulosic waiver credits (“CWCs”) or (ii) D3 RINs. In a December 1, 2022 proposed rule, EPA proposed to not utilize its cellulosic waiver authority for the years 2023-2025. However, if actual production is lower than the RVO, the EPA will have discretion to utilize CWC. RECs are created through state law requirements for utilities to purchase a portion of their energy from renewable energy sources. 70% and 62% of our operating revenues for 2022 and 2021, respectively, were generated from the sale of Environmental Attributes. These government economic incentives could be reduced or eliminated altogether, or the categories of renewable energy qualifying for such government economic incentives could be changed. These renewable energy program incentives are subject to regulatory oversight and could be administratively or legislatively changed in a manner that could adversely affect our operations. Further, the generation of LCFS credits on our dairy farm project is expected to increase the percentage of our revenues generated from Environmental Attributes. Reductions in, changes to, or eliminations or expirations of governmental incentives could result in decreased demand for, and lower revenues from, our projects. Changes in the level or structure of the RPS of a state for electricity could also result in a decline in our revenues or decreased demand for, and lower revenues from, our electricity projects.

We may be unable to obtain, modify or maintain the regulatory permits, approvals and consents required to construct and operate our projects.

Our operations are subject to various federal, state and local EHS laws and regulations, including those relating to the release, emission or discharge of materials into the air, water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials and wastes, the health and safety of our employees and other persons, and the generation of RINs and LCFS credits.

These laws and regulations impose numerous obligations applicable to our operations, including the acquisition of permits before construction and operation of our projects; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of our activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from the ownership or operation of our properties. These laws, regulations and permits can require expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment.

Numerous governmental entities have the power to enforce difficult and costly compliance measures or corrective actions pursuant to these laws and regulations and the permits issued under them. We may be required to make significant capital and operating expenditures on an ongoing basis, or to perform remedial or other corrective actions at our properties, to comply with the requirements of these environmental laws and regulations or the terms or conditions of our permits. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required environmental regulatory permits or approvals, which may delay or interrupt our operations and limit our growth and revenue.

Our operations inherently risk incurring significant environmental costs and liabilities due to the need to manage waste from our processing facilities. Spills or other releases of regulated substances, including spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws, rules and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the EHS impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.



New laws, changes to existing laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make significant additional expenditures. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls at our plants. Present and future environmental laws and regulations, and interpretations of those laws and regulations, applicable to our operations, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial expenditures that could have a material adverse effect on our results of operations and financial condition. In January 2021, President Biden issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies, and any similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies and to address climate change. The federal agencies review of previous agency actions remain ongoing. In January 2021, President Biden also issued an executive order solely targeting climate change. Pursuant to these executive orders, on February 19, 2021 the United States formally rejoined the Paris Climate Agreement, an international treaty that provides for the cutting of carbon emissions every five years, beginning in 2023. In August 2022, President Biden signed into law the Inflation Reduction Act, which includes incentives for development and production of renewable energy. These incentives include grants, loan guarantees, development funding, investment tax credits, and production tax credits. At this time, we cannot predict the outcome of any of these executive actions on our operations.

Our ability to generate revenue from sales of RINs and LCFS credits depends on our strict compliance with these federal and state programs, which are complex and can involve a significant degree of judgment. If the agencies that administer and enforce these programs disagree with our judgments, otherwise determine that we are not in compliance, conduct reviews of our activities or make changes to the programs, then our ability to generate or sell these credits could be temporarily restricted pending completion of reviews or as a penalty, permanently limited or lost entirely, and we could also be subject to fines or other sanctions. Moreover, the inability to sell RINs and LCFS credits could adversely affect our business.

In order to construct, modify and operate our projects, we will need to obtain or may need to modify numerous environmental and other regulatory permits, approvals and consents from federal, state and local governmental entities, including air permits, wastewater discharge permits, stormwater permits, permits or consents related to the management of municipal solid waste landfills and permits or consents related to the management and disposal of waste. A number of these permits, approvals and consents must be obtained prior to the start of development of a project. Other permits, approvals and consents are required to be obtained at, or prior to, the time of first commercial operation or within prescribed time frames following commencement of commercial operations. Any failure to successfully obtain or modify the necessary environmental and other regulatory permits, approvals and consents on a timely basis could delay the construction, modification or commencement of commercial operation of our projects. In addition, once a permit, approval or consent has been issued or acquired for a project, we must take steps to comply with the conditions of each permit, approval or consent conditions, including conditions requiring timely development and commencement of the project. Failure to comply with certain conditions within a permit, approval or consent could result in the revocation or suspension of such permit, approval or consent; the imposition of penalties; or other enforcement action by governmental entities. We also may need to modify permits, consents or approvals we have already obtained to reflect changes in project design or requirements, which could trigger a legal or regulatory review under a standard more stringent than the standard under which the permits, approvals or consents were originally issued.

Obtaining and modifying necessary permits, approvals and consents is a time-consuming and expensive process, and we may not be able to obtain or modify them on a timely or cost effective basis or at all. In the event that we fail to obtain or modify all necessary permits, approvals or consents, we may be forced to delay construction or operation of a project or abandon the project altogether, which could adversely affect our business, financial condition and results of operations. In addition, we may be required to make capital expenditures on an ongoing basis to comply with increasingly stringent federal, state, provincial and local EHS laws, regulations and permits.



Negative attitudes toward renewable energy projects from the U.S. government, other lawmakers and regulators, and activists could adversely affect our business, financial condition and results of operations.

Parties with an interest in other energy sources, including lawmakers, regulators, policymakers, environmental and advocacy organizations or other activists may invest significant time and money in efforts to delay, repeal or otherwise negatively influence regulations and programs that promote renewable energy. Many of these parties have substantially greater resources and influence than we have. Further, changes in U.S. federal, state or local political, social or economic conditions, including a lack of legislative focus on these programs and regulations, could result in their modification, delayed adoption or repeal. Any failure to adopt, delay in implementing, expiration, repeal or modification of these programs and regulations, or the adoption of any programs or regulations that encourage the use of other energy sources over renewable energy, could adversely affect our business, financial condition and results of operations.

In addition, in June 2019, the EPA issued the final Affordable Clean Energy (“ACE”) rule and repealed the Clean Power Plan (the “CPP”), which had previously established standards to limit carbon dioxide emissions from existing fossil-fueled power generation facilities. Under the ACE rule, emissions from electric utility generation facilities would be regulated only through the use of various “inside the fence” or onsite efficiency improvements and emission control technologies. In contrast, the CPP allowed facility owners to reduce emissions with “outside the fence” measures, including those associated with renewable energy projects. On January 19, 2021, the United States Court of Appeals for the D.C. Circuit vacated the ACE rule and remanded the rule back to EPA for reconsideration of the “best system of emission reduction.” On February 22, 2021, the D.C. Circuit subsequently issued an order allowing EPA to promulgate new standards in lieu of reviving the CPP. In June 2022, the U.S. Supreme Court reversed the D.C. Circuit’s decision on the Affordable Clean Energy rule and remanded the case back to the D.C. Circuit. The U.S. Supreme Court restricted the EPA’s authority to regulate GHG from existing power plants under Section 111(d). The U.S. Supreme Court concluded that Congress did not grant the EPA authority under the CAA to demand generation-shifting to achieve reduction of GHG emissions, but the court did not hold that the EPA is limited in future rulemakings to just the heat-rate improvements that made up the ACE rule. We are unable to predict the future course of the litigation on remand, nor the direction that the EPA may take in the future to regulate GHG emissions from existing fossil fuel-fired generation facilities. On August 16, 2022, President Biden signed into law the Inflation Reduction Act, which includes an amendment to the CAA defining GHGs as air pollutants. On September 8, 2022, the EPA announced the opening of a non-rulemaking docket for public comments on the EPA’s efforts to reduce GHG emissions from existing fossil fuel-fired electric generating units. Comments may be submitted to the EPA until March 27, 2023. The impact of the disposition of this litigation or a new rule regulating GHG emissions on our operations is unclear.

Revenue from any projects we complete may be adversely affected if there is a decline in public acceptance or support of renewable energy, or regulatory agencies, local communities, or other third parties delay, prevent, or increase the cost of constructing and operating our projects.

Certain persons, associations and groups could oppose renewable energy projects in general or our projects specifically, citing, for example, misuse of water resources, landscape degradation, land use, food scarcity or price increase and harm to the environment. Moreover, regulation may restrict the development of renewable energy plants in certain areas. In order to develop a renewable energy project, we are typically required to obtain, among other things, environmental impact permits or other authorizations and building permits, which in turn require environmental impact studies to be undertaken and public hearings and comment periods to be held during which any person, association or group may oppose a project. Any such opposition may be taken into account by government officials responsible for granting the relevant permits, which could result in the permits being delayed or not being granted or being granted solely on the condition that we carry out certain corrective measures to the proposed project. Opposition to our projects’ requests for permits or successful challenges or appeals to permits issued for our projects could adversely affect our operating plans.



As a result, we cannot guarantee that the renewable energy plants we currently plan to develop or, to the extent applicable, are developing, will ultimately be authorized or accepted by the local authorities or the local population. For example, the local population could oppose the construction of a renewable energy plant or infrastructure at the local government level, which could in turn lead to the imposition of more restrictive requirements. This type of negative response may lead to legal, public relations or other challenges that could impede our ability to meet our construction targets, achieve commercial operations for a project on schedule, address the changing needs of our projects over time or generate revenues.

In certain jurisdictions, if a significant portion of the local population were to mobilize against a renewable energy plant, it may become difficult, or impossible, for us to obtain or retain the required building permits and authorizations. Moreover, such challenges could result in the cancellation of existing building permits or even, in extreme cases, the dismantling of, or the retroactive imposition of changes in the design of, existing renewable energy plants.

Authorization for the use, construction, and operation of systems and associated transmission facilities on federal, state, and local lands will also require the assessment and evaluation of mineral rights, private rights-of-way, and other easements; environmental, agricultural, cultural, recreational, and aesthetic impacts; and the likely mitigation of adverse effects to these and other resources and uses. The inability to obtain the required permits and other federal, state and local approvals, and any excessive delays in obtaining such permits and approvals due, for example, to litigation or third-party appeals, could potentially prevent us from successfully constructing and operating such projects in a timely manner and could result in the potential forfeiture of any deposit we have made with respect to a given project. Moreover, project approvals subject to project modifications and conditions, including mitigation requirements and costs, could affect the financial success of a given project. Changing regulatory requirements and the discovery of unknown site conditions could also adversely affect the financial success of a given project.

A decrease in acceptance of renewable energy plants by local populations, an increase in the number of legal challenges, or an unfavorable outcome of such legal challenges could adversely affect our business, financial condition and results of operations. We may also be subject to labor unavailability due to multiple simultaneous projects in a geographic region. If we are unable to grow and manage the capacity that we expect from our projects in our anticipated timeframes, it could adversely affect our business, financial condition and results of operations.

Existing regulations and policies, and future changes to these regulations and policies, may present technical, regulatory and economic barriers to the generation, purchase and use of renewable energy, and may adversely affect the market for credits associated with the production of renewable energy.

The market for renewable energy is influenced by U.S. federal, state and local government regulations and policies concerning renewable energy. These regulations and policies are continuously being modified, which could result in a significant future reduction in the potential demand for renewable energy, including RINs, RECs and LCFS credits, renewable energy project development and investments. Renewable Fuel Standards for 2023 through 2025 remain subject to finalization. Any new government regulations applicable to our renewable energy projects or markets for renewable energy may result in significant additional expenses or related development costs and, as a result, could cause a significant reduction in demand for our renewable energy. For additional information on regulatory developments, see “Item 7A.—Management’s Discussion and Analysis of Financial Condition and Results of Operations —Key Trends—Regulatory, Environmental and Social Trends.”

In order to benefit from RINs and LCFS credits, our RNG projects are required to be registered and are subject to regulatory audit.

We are required to register an RNG project with the EPA and relevant state regulatory agencies. Further, we qualify our RINs through a voluntary Quality Assurance Plan, which typically takes from three to five months



from first injection of RNG into the commercial pipeline system. Although no similar qualification process currently exists for LCFS credits, we expect such a process to be implemented and would expect to seek qualification on a state-by-state basis under such future programs. 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. Delays in obtaining registration, RIN qualification, and any future LCFS credit qualification, or CI rescoring through CARB annual audits, of a new project could delay future revenues from the project and could adversely affect our cash flow. Further, we typically make a large investment in the project prior to receiving the regulatory approval and RIN qualification. By registering each RNG project with the EPA’s voluntary Quality Assurance Plan, we are subject to quarterly third-party audits and semi-annual on-site visits of our projects to validate generated RINs and overall compliance with the RFS program. We are also subject to a separate third party’s annual attestation review. The Quality Assurance Plan provides a process for RIN owners to follow, for an affirmative defense to civil liability, if used or transferred Quality Assurance Plan verified RINs were invalidly generated. A project’s failure to comply could result in remedial action by the EPA, including penalties, fines, retirement of RINs, or termination of the project’s registration, any of which could adversely affect our business, financial condition and results of operations. For additional information on recent developments in this area, including the Pico facility’s CI score, see “Item 7A.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Trends—Regulatory, Environmental and Social Trends.”

## Our business is subject to the risk of extreme or changing weather patterns.

Extreme weather patterns related to climate change could cause changes in rainfall and storm patterns and intensities, water shortages and changing temperatures, which could result in significant volatility in the supply and prices of energy. In addition, legislation and increased regulation regarding climate change could impose significant costs on us and our suppliers, including costs related to capital equipment, environmental monitoring and reporting and other costs to comply with such regulations.

Furthermore, extreme weather events, such as lightning strikes, ice storms, tornados, extreme wind, hurricanes and other severe storms, wildfires and other unfavorable weather conditions or natural disasters, such as floods, fires, earthquakes, and rising sea-levels, could adversely affect the input and output commodities associated with the renewable energy sector. Such weather events or natural disasters could also require us to temporarily or permanently shut down the equipment associated with our renewable energy projects, such as our access to power and our power to biogas collection, separation and transmission systems, which would impede the ability of our projects to operate and decrease production levels and our revenue. Operational problems, such as degradation of our project’s equipment due to wear or weather or capacity limitations or outages on the electrical transmission network, could also affect the amount of energy that our projects are able to deliver. Any of these events, to the extent not fully covered by insurance, could adversely affect our business, financial condition and results of operations.

These events could result in significant volatility in the supply and prices of energy. This volatility may create fluctuations in commodity or energy prices and earnings of companies in the renewable energy sectors. See “—Operational Risks—‘The concentration in revenues from five of our projects and geographic concentration of our projects expose us to greater risks of production interruptions from severe weather or other interruptions of production or transmission’ for additional information.

## Our business is subject to risks arising out of climate change, which could result in increased operating costs.

Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs and eliminate future GHG emissions. Governmental and public concern arising from GHG emissions has resulted in increasing regulatory, political, financial and litigation risks in the United States and globally that target predominantly fossil fuel-related energy entities or their operations, which may have indirect effects on other companies or industries, including the renewable energy industry.



In the United States, no comprehensive federal climate change legislation has been implemented. The EPA has adopted rules that, among other things, establish permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from specified sources in the U.S., implement standards reducing emissions of methane, a form of GHG, from specified oil and gas sectors, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the United States. While these rules largely do not directly impact our operations, they do represent a concerted effort at the federal level to reduce emissions of GHGs in an effort to mitigate adverse effects associated with climate change, which could in turn result in increased demand for renewable energy.

Additionally, in August 2022 the Inflation Reduction Act of 2022 was signed into law, which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities in the oil and natural gas sector. The emissions fee and renewable and low carbon energy funding provisions of the law could accelerate the transition away from fossil fuels, which could in turn have an indirect adverse effect on our business and results of operations. Under the Biden Administration, it is anticipated that efforts by the EPA or other federal agencies to restrict GHG emissions will continue. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. As a result, there exists the possibility of executive orders being issued or federal legislation or regulatory initiatives being adopted that could result in further restrictions on fossil fuels and have a further indirect effect on the demand for renewable energy and our products.

## Cybersecurity and Information Technology Risks

A failure of our IT and data security infrastructure could have a material adverse effect on our business and operations.

We rely upon the capacity, reliability and security of our IT and data security infrastructure and our ability to expand and continually update this infrastructure in response to the changing needs of our business. Our existing IT systems and any new IT systems may not perform as expected. We also face the challenge of supporting our older systems and implementing necessary upgrades. If we experience a problem with the functioning of an important IT system or a security breach of our IT systems, including during system upgrades or new system implementations, the resulting disruptions could have a material adverse effect on our business.

We and some of our third-party vendors receive and store personal information in connection with our human resources operations and other aspects of our business. Despite our implementation of reasonable security measures, our IT systems, like those of other companies, are vulnerable to damages from computer viruses, natural disasters, fire, power loss, telecommunications failures, personnel misconduct, human error, unauthorized access, physical or electronic security breaches, cyber-attacks (including malicious and destructive code, phishing attacks, ransomware, and denial of service attacks), and other similar disruptions. Such attacks or security breaches may be perpetrated by bad actors internally or externally (including computer hackers, persons involved with organized crime, or foreign state or foreign state-supported actors). Cybersecurity threat actors employ a wide variety of methods and techniques that are constantly evolving, increasingly sophisticated, and difficult to detect and successfully defend against. Cybersecurity incidents could expose us to claims, litigation, regulatory or other governmental investigations, administrative fines and potential liability. Any system failure, accident or security breach could result in disruptions to our operations. A material network breach in the security of our IT systems could include the theft of our trade secrets, customer information, human resources information or other confidential data, including but not limited to personally identifiable information, that could have a material adverse effect on our business, financial condition, or results of operations. To the extent that any material disruptions or security breaches result in a loss or damage to our data, or an inappropriate disclosure of confidential, proprietary or customer information, it could materially cause damage to our reputation, affect our



relationships with our customers and strategic partners, lead to claims against us from governments and private plaintiffs, and ultimately have a material adverse effect on our business. While we have been the previous target of cyberattacks and security breaches, none of these attacks or breaches to date have had a material adverse effect on the Company. We cannot guarantee that future cyberattacks, if successful, will not have a material effect on our business or financial results.

Many governments have enacted laws requiring companies to provide notice of cyber incidents involving certain types of data, including personal data. Any compromise of our security could result in a violation of applicable domestic and foreign security, privacy or data protection, consumer and other laws, regulatory or other governmental investigations, enforcement actions, and legal and financial exposure, including potential contractual liability that could have a material adverse effect on our business. In addition, we may be required to incur significant costs to protect against and remediate damage caused by these disruptions or security breaches in the future that could have a material adverse effect on our business.

We rely on the technology, infrastructure, and software applications of certain third parties in order to host or operate some of our business. Additionally, we rely on computer hardware purchased in order to operate our business. We do not have control over the operations of the facilities of the third parties that we use. If any of these third-party services experience errors, disruptions, security issues, or other performance deficiencies, if these services, software, or hardware fail or become unavailable due to extended outages, interruptions, defects, or otherwise, or if they are no longer available on commercially reasonable terms or prices (or at all), these issues could result in material errors or defects in our platforms (including causing our platforms to fail), our revenue and margins could materially decline, or our reputation and brand to be materially damaged. Additionally, we could be exposed to material legal or contractual liability, our expenses could materially increase, our ability to manage our operations could be materially interrupted, and our processes for servicing our customers could be materially impaired until equivalent services or technology, if available, are identified, procured, and implemented, all of which may take significant time and resources, increase our costs, and could materially and adversely affect our business. Many of these third-party providers that attempt to impose limitations on their liability for such errors, disruptions, defects, performance deficiencies, or failures, and if enforceable, we may have additional liability to our customers or third-party providers that could have a material adverse effect on our business. A failure to maintain our relationships with our third-party providers (or obtain adequate replacements), and to receive services from such providers that do not contain any material errors or defects, could adversely affect our ability to deliver effective products and solutions to our customers and adversely affect our business and results of operations.

Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.

As a renewable energy producer, we face various security threats, including among others, computer viruses, malware, telecommunication and electrical failures, cyber-attacks or cyber-intrusions over the internet, attachments to emails, persons with access to systems inside our organization, cybersecurity threats to gain unauthorized access to sensitive information or to expose, exfiltrate, alter, delete or render our data or systems unusable, threats to the security of our projects and infrastructure or third-party facilities and infrastructure, such as processing projects and pipelines, natural disasters, threats from terrorist acts and war.

We take various steps to identify and mitigate potential cybersecurity threats. As cyber incidents become more frequent and the sophistication of threat actors increases, our associated cybersecurity costs are expected to increase. Specifically, we expect to implement several incremental cybersecurity improvements over the next 18 to 36 months to enhance our defensive capabilities and resilience. Despite our ongoing and anticipated cybersecurity efforts, a successful cybersecurity incident could lead to additional material costs, including those related to the loss of sensitive information, repairs to infrastructure or capabilities essential to our operations, responding to litigation or regulatory investigations, and those related to a material and adverse impact on our reputation, financial position, results of operations, or cash flows.



Our implementation of various procedures and controls to monitor and mitigate these security threats, and to increase security for our information projects and infrastructure, may result in materially increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. Cybersecurity attacks, in particular, are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability which can have a material adverse effect on our business and results of operations.

## Third-Party Partner Risks

Failure of third parties to manufacture quality products or provide reliable services in a timely manner could cause delays in developing and operating our projects, which could damage our reputation, adversely affect our partner relationships or adversely affect our growth.

Our success depends on our ability to develop and operate projects in a timely manner, which depends in part on the ability of third parties to provide us with timely and reliable products and services. In developing and operating our projects, we rely on products meeting our design specifications and components manufactured and supplied by third parties, and on services performed by subcontractors. We also rely on subcontractors to perform substantially all of the construction and installation work related to our projects, and we often need to engage subcontractors with whom we have no experience.

If any of our subcontractors are unable to provide services that meet or exceed our customers' expectations or satisfy our contractual commitments, our reputation, business and operating results could be harmed. In addition, if we are unable to avail ourselves of warranties and other contractual protections with providers of products and services, we may incur liability to our customers or additional costs related to the affected products and services, which could adversely affect our business, financial condition and results of operations. Moreover, any delays, malfunctions, inefficiencies or interruptions in these products or services could adversely affect the quality and performance of our projects and require considerable expense to maintain and repair our projects. This could cause us to experience interruption in our production and distribution of renewable energy and generation of related Environmental Attributes, difficulty retaining current relationships and attracting new relationships, or harm our brand, reputation or growth.

Our projects rely on interconnections with and access to electric distribution and transmission facilities and gas transportation pipelines that are owned and operated by third parties, and as a result, are exposed to risks related to such facilities' development and operational curtailment risks.

Our projects are interconnected with electric distribution and transmission facilities owned and operated by regulated utilities necessary to deliver the Renewable Electricity that we produce. Our RNG projects are similarly interconnected with gas distribution and interstate pipeline systems required to deliver RNG A failure or delay in the operation or development of these distribution or transmission facilities could result in a loss of revenues or breach of contract because such a failure or delay could limit the amount of RNG and Renewable Electricity that our operating projects deliver or delay the completion of our construction projects. In addition, certain of our operating projects' generation may be curtailed without compensation due to distribution and transmission limitations, reducing our revenues and impairing our ability to capitalize fully on a particular project's potential. Such a failure or curtailment at levels above our expectations could impact our ability to satisfy our supply agreements and adversely affect our business. Additionally, we experience work interruptions from time to time due to federally required maintenance shutdowns.

We may acquire projects with their own interconnections to available transmission and distribution networks. In some cases, these projects may cover significant distances. A failure in our operation of these



projects that causes the projects to be temporarily out of service, or subject to reduced service, could result in lost revenues because it could limit the amount of Renewable Electricity and RNG our operating projects are able to deliver.

We are dependent upon our relationships with Waste Management and Republic Services for the operation and maintenance of landfills on which several of our RNG and Renewable Electricity projects operate.

We currently operate eight renewable energy projects (seven RNG projects and one Renewable Electricity project) on landfills operated by Waste Management and two RNG projects on landfills operated by Republic Services. Our projects located on Waste Management and Republic Services operated landfills represented a significant proportion of our revenue in 2022. We are dependent upon Waste Management and Republic Services to operate and maintain their landfill facilities and provide a continuous supply of waste for conversion to RNG and Renewable Electricity. Further, we consider our relationship with these landfill operators an important factor in our growth strategy for additional projects. In the event that we fall out of favor with either of these landfill operators due to a dispute, problems with our operations at one of their facilities or otherwise, the landfill operator may seek to terminate the related project and be less inclined to work with us on future projects.

Additionally, Waste Management and Republic Services could seek to develop their own waste-to-renewable energy conversion projects at other existing landfill locations in lieu of contracting with us for these projects. Failure to maintain these favorable relationships could adversely affect our business, growth strategy, financial condition and results of operations.

We have significant customer concentration, with a limited number of customers accounting for a substantial portion of our revenues.

For 2022, sales to ExxonMobil, Valero, and the City of Anaheim represented approximately 32.0%, 17.0%, and 7.6%, respectively of our operating revenues. For 2021, sales to Victory Renewables, LLC, Valero, and City of Anaheim represented approximately 13.1%, 12.4%, and 9.6%, respectively of our operating revenues. Five customers made up approximately 69% and 68% of our accounts receivable as of December 31, 2022 and 2021, respectively. Revenues from our largest customers may fluctuate from time to time based on our customers' business needs, market conditions or other factors outside of our control. If any of our largest customers terminates its relationship with us, such termination could adversely affect our revenues and results of operations.

## Capital and Credit Risks

Our senior credit facility may not be sufficient to meet our financial needs and contains financial and operating restrictions that may limit our business activities and our access to other forms of credit.

Our senior credit facility consists of an $80.0 million principal amount term loan, of which $72.0 remains outstanding as of December 31, 2022, and a $120.0 million revolving credit line, which is undrawn as of December 31, 2022. This facility may not be sufficient to meet our financial needs as our business grows. The senior credit facility matures in December 2026 and we may be unable to extend or replace it on acceptable terms, or at all. Furthermore, the credit agreement governing our facility (the “Amended Credit Agreement”) imposes business restrictions and contains other covenants that require us to meet specified financial ratios and financial tests. Under the Amended Credit Agreement, we are required to maintain:

• a fixed charge coverage ratio of at least 1.20 to 1.00; and

- a total leverage ratio 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 after June 30, 2024.



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 is less than $0.80 per RIN and (y) the consolidated EBITDA for such quarter is less than $6.0 million. Additional information regarding the senior credit facility and the Amended Credit Agreement can be found in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Our failure to comply with these covenants could result in the declaration of an event of default and cause us to be unable to borrow under the Amended Credit Agreement. In addition to preventing additional borrowings under the Amended Credit Agreement, an event of default, if not cured or waived, could result in the acceleration of the maturity of indebtedness outstanding under the facility, which would require us to immediately repay all amounts outstanding. If an event of default occurs, we may not be able to cure it within any applicable cure period, or at all. As of December 31, 2022, we were in compliance with all covenants.

Variable rate indebtedness under our Amended Credit Agreement may adversely affect our business, financial condition and results of operations.

Borrowings under our Amended Credit Agreement are at variable rates of interest, particularly the Bloomberg Short-Term Bank Yield Index Rate (“BSBY”), which will fluctuate with changing market conditions. If BSBY increases, our interest expense will mechanically increase, which could adversely affect our cash flow and our ability to service our indebtedness and fund our operations. Additionally, BSBY is one of a relatively new series of reference rates, and certain regulatory authorities have indicated that BSBY may suffer from the same or similar deficiencies that LIBOR suffered from. Therefore, based on its limited historical performance and other available information, the future performance of BSBY cannot be accurately predicted, which could result in increases in our interest expense that may adversely impact the amount of interest payments under the Amended Credit Agreement.

We may be required to write-off or impair capitalized costs or intangible assets in the future or we may incur restructuring costs or other charges, each of which would harm our earnings.

In accordance with GAAP, we capitalize certain expenditures and advances relating to our acquisitions, pending acquisitions, project development costs, interest costs related to project financing and certain energy assets. In addition, we have considerable unamortized assets. In 2022, we recorded impairment charges of $2.1 million related to our estimate of future cash flows no exceeding the carrying amount of an Renewable Electricity facility and discrete charges of $1.4 million and $1.1 million related to the ongoing development of the Montauk Ag Renewables and an asset component of an RNG facility. In 2021, we recorded impairment charges of $0.8 million related to the ongoing Renewable Electricity facility decommissioning and $0.4 million related to certain assets at one RNG facility. In 2020, we recorded impairment charges of $0.3 million related to our digester joint venture. In addition, from time to time in future periods, we may be required to incur a charge against earnings in an amount equal to any unamortized capitalized expenditures and advances, net of any portion thereof that we estimate will be recoverable, through sale or otherwise, relating to: (i) any operation or other asset that is being sold, permanently shut down, impaired or has not generated or is not expected to generate sufficient cash flow; (ii) any pending acquisition that is not consummated; (iii) any project that is not expected to be successfully completed; and (iv) any goodwill or other intangible assets that are determined to be impaired. A material write-off or impairment change could adversely affect our ability to comply with the financial covenants under the Amended Credit Agreement, and otherwise adversely affect our business, financial condition and results of operations.

Our ability to use our U.S. net operating loss carryforwards to offset future taxable income may be subject to certain limitations.

As of December 31, 2022, Montauk had U.S. federal net operating loss (“NOL”) carryforwards of approximately $12.1 million that were incurred in 2018 or later taxable years and, therefore, can generally be carried forward indefinitely to offset 80% of taxable income in a future year. Our ability to utilize our U.S. NOL carryforwards is dependent upon our ability to generate taxable income in future periods.



On January 1, 2020, the minority investor of MEC, Johnston LFG Holdings, Inc. (via assignment of shares from MEC on December 9, 2019), was bought out by MEH, converting MEC from a partnership to a disregarded entity for U.S. federal income tax purposes, which is currently wholly owned by MEH. This transaction allowed Monmouth Energy Inc., a subsidiary of MEC, to file as part of our consolidated federal tax group. Monmouth Energy, Inc. has NOLs of approximately $13.0 million that are limited for use under the separate return limitation year rules due to the fact that they were generated prior to Monmouth Energy Inc. joining our consolidated group.

In addition, our U.S. NOL carryforwards and certain other tax attributes may be limited if we have experienced or experience an “ownership change” under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), which generally occurs if one or more stockholders or groups of stockholders who own at least 5% of our shares increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling period that begins on the later of three years prior to the testing date and the date of the last ownership change. Similar rules may apply under state tax laws. Previous issuances and sales of MNK’s ordinary shares or of our common stock, and future issuances and sales of our common stock (including certain transactions involving our common stock that are outside of our control) could have caused or could cause an “ownership change.” If an “ownership change” either had occurred or were to occur, Section 382 of the Internal Revenue Code of 1986, as amended (the Code) would impose an annual limit on the amount of pre-ownership change NOL carryforwards and other tax attributes we could use to reduce our taxable income, potentially increasing and accelerating our liability for income taxes, and also potentially causing certain tax attributes to expire unused. It is possible that such an ownership change could materially reduce our ability to use our U.S. NOL carryforwards or other tax attributes to offset taxable income, which could adversely affect our profitability.

## Emerging Growth Company Risks

For as long as we are an emerging growth company, we will not be required to comply with certain requirements that apply to other public companies.

We are an emerging growth company, as defined in the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years following January 22, 2021, the completion of the IPO, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation and any golden-parachute payments not previously approved. In addition, the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for adopting new or revised financial accounting standards. We intend to take advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards permitted under the JOBS Act until we are no longer an emerging growth company. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to the JOBS Act.

We will remain an emerging growth company for up to five years after January 22, 2021, the date of the IPO, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700.0 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

For so long as we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that



are not emerging growth companies. We cannot predict whether investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

If we identify material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, we may be unable to accurately or timely report our financial condition or results of operations, which may adversely affect our business.

We are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act, which require management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of controls over financial reporting. As an emerging growth company, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting pursuant to Section 404 until the date we are no longer an emerging growth company. At such time, our independent registered public accounting firm may issue a report that is adverse in the event that it is not satisfied with the level at which our controls are documented, designed or operating.

To comply with the requirements of being a public company, we have undertaken various actions, including implementing additional internal controls and procedures and hiring additional accounting or internal audit staff, increasing the use of external specialists and may need to take additional actions in the future. Testing and maintaining internal controls can divert our management’s attention from other matters that are important to the operation of our business. If we identify material weaknesses in our internal controls over financial reporting or are unable to comply with the requirements of Section 404 or assert that our internal controls over financial reporting are effective, or if our independent registered public accounting firm is unable to express an opinion as to the effectiveness of our internal controls over financial reporting, investors may lose confidence in the accuracy and completeness of our financial reports and the market price of our common stock could be negatively affected. In addition, we could become subject to investigations by the SEC or other regulatory authorities, which could require additional financial and management resources.

## Common Stock Risks

Our stock price may be volatile, and the value of our common stock may decline.

The market price of our common stock may be highly volatile and may fluctuate or decline substantially as a result of a variety of factors, some of which are beyond our control, including:

• actual or anticipated fluctuations in our operating results due to factors related to our businesses;

• success or failure of our business strategies;

• our quarterly or annual earnings or those of other companies in our industries;

• our ability to obtain financing as needed;

• announcements by us or our competitors of significant acquisitions or dispositions;

• changes in accounting standards, policies, guidance, interpretations or principles;

• the failure of securities analysts to cover our common stock;

• changes in earnings estimates by securities analysts or our ability to meet those estimates;

• the operating and stock price performance of other comparable companies;

• investor perception of our company or our industry;

• overall market fluctuations;



• results from any material litigation or government investigation;

• changes in senior management or key personnel;

- changes in laws and regulations (including energy, environmental and tax laws and regulations) affecting our business;

• natural disasters, health-related crises, and weather conditions disrupting our business operations;

• the trading volume of our common stock;

• changes in capital gains taxes and taxes on dividends affecting stockholders;

• identification of material weaknesses or otherwise failing to maintain effective internal controls; and

• changes in the anticipated future growth rate of our business.

Broad market and industry fluctuations, as well as general economic, political, regulatory and market conditions, may also adversely affect the market price of our common stock.

## Our shares of common stock may trade on more than one market and this may result in price variations.

The Company’s common stock is traded on the Nasdaq Capital Market under the ticker symbol of “MNTK” and on the JSE under the ticker symbol of “MKR.” Trading in our common stock takes place in USD on the Nasdaq Capital Market and ZAR on the JSE, and at different times, resulting from different time zones, trading days and public holidays in the United States and South Africa. The trading prices of our common stock on these two markets may differ due to these and other factors. Any decrease in the price of our common stock on either exchange could cause a corresponding decrease in the trading price of the common stock on the other exchange.

## Future sales of our common stock in the public market could cause the market price of our common stock to decline.

Sales of a substantial number of shares of our common stock in the public market, or the perception that these sales might occur, could depress the market price of our common stock and could impair our ability to raise capital through the sale of additional equity securities. Many of our existing equity holders have substantial unrecognized gains on the value of the equity they hold based upon the price of the IPO, and therefore they may take steps to sell their shares or otherwise secure the unrecognized gains on those shares. Additionally, pursuant to the terms of the Second Amended Promissory Note (as amended), MNK is required to use the proceeds from any sale of the 800,000 shares of our common stock previously pledged as security for MNK’s loan obligations to repay the amounts due under the Second Amended Promissory Note (as amended). These sales may have a downward impact on the prevailing market price of our common stock. MNK is currently evaluating a number of options to complete the sale of these shares including but not limited to register sale or underwritten offering in the US, direct sale to a South African investor, or extending the term of the loan. We also have default provisions in the underlying note whereby MNK can satisfy the note by delivering the shares back to us as permitted by applicable law. We are unable to predict the timing of or the effect that such sales, by MNK or by other shareholders, may have on the prevailing market price of our common stock.

## We are a “controlled company” within the meaning of the Nasdaq rules and, as a result, qualify for, and intend to rely on, exemptions and relief from certain governance requirements.

Certain stockholders, which are Messrs. Copelyn’s and Govender’s respective affiliates, have entered into a Consortium Agreement whereby the parties thereto agreed to act in concert with respect to voting our common stock in the election of directors, among other matters. The parties to the Consortium Agreement beneficially owned, in the aggregate, approximately 52.3% of our common stock as of February 28, 2023. As a result, we are a “controlled company” within the meaning of the Nasdaq corporate governance standards. Under these



corporate governance standards, a company of which more than 50% of the voting power in the election of directors is held by an individual, group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements. For example, controlled companies are not required to have:

• a board that is composed of a majority of “independent directors,” as defined under the Nasdaq rules;

• a compensation committee that is composed entirely of independent directors; and

- director nominations that are made, or recommended to the full board of directors, by its independent directors, or by a nominations/governance committee that is composed entirely of independent directors.

We may rely on any or all of these exemptions so long as we remain a controlled company.

The concentration of our capital stock ownership may limit our stockholders’ ability to influence corporate matters and may involve other risks.

As a result of the Consortium Agreement, certain of our stockholders control matters requiring stockholder approval, including the election of our directors and approval of significant corporate transactions. This concentration of ownership may also have the effect of delaying or preventing a change in control of us that may be otherwise viewed as beneficial by stockholders other than management. Accordingly, other stockholders may not have any influence over significant corporate transactions and other corporate matters. There is also a risk that certain controlling stockholders may have interests which are different from other stockholders and that they will pursue an agenda which is beneficial to themselves at the expense of other stockholders.

Provisions of our Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws, and Delaware law may prevent or delay an acquisition of us, which could decrease the trading price of our common stock.

Certain provisions of our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws, together with applicable Delaware law, may discourage, delay or prevent a merger or acquisition that our stockholders consider favorable. These provisions may discourage, delay or prevent certain types of transactions involving an actual or a threatened acquisition or change in control of us, including unsolicited takeover attempts, even though the transaction may offer our stockholders the opportunity to sell their common stock at a price above the prevailing market price.

Certain of our directors reside outside of the United States and it may be difficult to enforce judgments against them in the United States.

Two of our directors, all of our executive officers and all of our operating assets reside in the United States. Certain of our directors, including John A. Copelyn, Theventheran (Kevin) G. Govender, Mohamed H. Ahmed and Yunis Shaik are residents of South Africa. Another director, Michael A. Jacobson, is a resident of Australia. As a result, it may not be possible for you to effect service of legal process, within the United States or elsewhere, upon certain of our directors, including matters arising under U.S. federal securities laws. This may make it difficult or impossible to bring an action against these individuals in the United States in the event that a person believes that their rights have been violated under applicable law or otherwise. Even if an action of this type is successfully brought, the laws of the United States and of South Africa or Australia may render a judgment unenforceable.



## General Risk Factors

Our issuance of additional capital stock in connection with financings, acquisitions, investments, our equity incentive plans or otherwise will dilute stockholders.

We expect to issue additional capital stock in the future that will result in dilution to stockholders. We expect to grant equity awards to employees, directors and consultants under our equity incentive plans. We may also raise capital through equity financings in the future. As part of our business strategy, we may acquire or make investments in companies and issue equity securities to pay for any such acquisition or investment. Any such issuances of additional capital stock may cause stockholders to experience significant dilution of their ownership interests and the per share value of our common stock to decline.

If securities or industry analysts do not publish research or publish inaccurate or unfavorable research about our business, our share price and trading volume could decline.

The trading market for our common stock will be influenced by the research and reports that securities or industry analysts publish about us. Securities and industry analysts do not currently, and may never, publish research focused on us. If no securities or industry analysts commence coverage of us, the price and trading volume of our common stock likely would be adversely affected. If securities or industry analysts initiate coverage and one or more of the analysts who cover us downgrade our common stock or publish inaccurate or unfavorable research about our company, our common stock share price would likely decline. If analysts publish target prices for our common stock that are below historical sales prices or the then-current public price of our common stock, it could cause our stock price to decline significantly. Further, if one or more of these analysts cease coverage of us or fail to publish reports on us regularly, demand for our common stock could decrease, which might cause our common stock price and trading volume to decline.

We are highly dependent on our senior management team and other highly skilled personnel, and if we are not successful in attracting or retaining highly qualified personnel, we may not be able to successfully implement our business strategy.

Our success depends, in significant part, on the continued services of our senior management team and on our ability to attract, motivate, develop and retain a sufficient number of other highly skilled personnel, including engineering, design, finance, marketing, sales and support personnel. Our senior management team has extensive experience in the renewable energy industry, and we believe that their depth of experience is instrumental to our continued success. The loss of any one or more members of our senior management team, for any reason, including resignation or retirement, could impair our ability to execute our business strategy and adversely affect our business, financial condition and results of operations.

Competition for qualified highly skilled personnel can be strong, and we cannot assure you that we will be successful in attracting or retaining such personnel now or in the future. Any inability to recruit, develop and retain qualified employees may result in high employee turnover and may force us to pay significantly higher wages, which may harm our profitability. Additionally, we do not carry key personnel insurance for any of our management executives, and the loss of any key employee or our inability to recruit, develop and retain these individuals as needed, could adversely affect our business, financial condition and results of operations.

Our ability to pay regular dividends on our common stock is subject to the discretion of our Board of Directors.

Our common stock will have no contractual or other legal right to dividends. The payment of future dividends on our common stock will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our Board of Directors deems relevant. Accordingly, we may not make, or may have to reduce or eliminate, the payment of dividends on our common stock, which could adversely affect the market price of our common stock.



## ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

## ITEM 2. PROPERTIES.

Our principal executive office is located in Pittsburgh, Pennsylvania. We lease an approximate 24,000 square foot office space at this site for approximately $43,000 per month pursuant to a lease which expires on April 30, 2033.

We also lease an 8,400 square foot regional office and warehouse to service our sites in Houston, Texas, pursuant to a lease which expires on December 31, 2026, for approximately $5,000 per month. We also have a month to month lease for nominal office space for Montauk Ag in Greensboro, North Carolina. We currently own and operate 15 projects, 12 of which are RNG projects and three of which are Renewable Electricity projects. See “Item 1. Business—Our Current Operating Portfolio” for further descriptions of our projects, which information is incorporated into this item by reference.

## ITEM 3. LEGAL PROCEEDINGS.

From time to time we and our subsidiaries may be parties to legal proceedings arising in the normal course of our business. We and our subsidiaries are currently not a party, nor is our property subject, to any material pending legal proceedings. None of our directors, officers, affiliates, or any owner of record or beneficially of more than 5% of our common stock, is involved in a material proceeding adverse to us or our subsidiaries or has a material interest adverse to us or our subsidiaries.

## ITEM 4. MINE SAFETY DISCLOSURES.

Not Applicable.



## PART II

## ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

## Market Information

The Company’s common stock has traded on the Nasdaq Capital Market under the ticker symbol of “MNTK” and on the JSE under the ticker symbol of “MKR” since January 22, 2021. Prior to that time, there was no established public trading market for the Company’s common stock.

## Holders of Montauk Common Stock

As of March 8, 2023, there were 11 holders of record of 141,633,417 shares of Montauk common stock outstanding as of such date. The number of holders of record of Montauk common stock does not reflect the number of beneficial holders whose shares are held by depositaries, brokers or other nominees.

## Performance Graph

The following stock performance graph compares our total stock return with the total return for (a) NASDAQ Composite Index and (b) an industry peer group. Our 2022 peer group, which is comprised of companies that we believe have comparable characteristics and are in the same industry or line-of-business, consists of Aemetis Inc., Clean Energy Fuels Corp., and Gevo Inc. Our eleven month 2021 peer group also included Archaea Energy, Inc., and Renewable Energy Group Inc. but these entities were acquired and ceased trading during 2022 and, as such, a separate line showing the total returns for this group is not possible in the below performance graph through December 31, 2022. The graph assumes that on January 22, 2021, the date our common stock began trading on the Nasdaq Capital Market, $100 was invested in our common stock and in each index based on the closing market price on that day and that all dividends were reinvested. The returns shown are based on historical events and are not intended to suggest future performance.

The following performance graph and related information is being furnished and shall not be deemed “soliciting material” or “filed” with the SEC for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities under that section, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it into reference into such filing.

COMPARISON OF 23 MONTH CUMULATIVE TOTAL RETURN*

Among Montauk Renewables, Inc., the NASDAQ Composite Index, and a Peer Group



*$100 invested on 1/22/21 in stock or 12/31/20 in index, including reinvestment of dividends. Fiscal year ending December 31.



<table><tr><td></td><td>1/22/21</td><td>3/31/21</td><td>6/30/21</td><td>9/30/21</td><td>12/31/21</td><td>3/31/22</td><td>6/30/22</td><td>9/30/22</td><td>12/31/22</td></tr><tr><td>Montauk Renewables, Inc.</td><td>100.00</td><td>116.49</td><td>73.87</td><td>108.29</td><td>98.84</td><td>108.00</td><td>96.91</td><td>168.18</td><td>106.36</td></tr><tr><td>NASDAQ Composite</td><td>100.00</td><td>102.95</td><td>112.92</td><td>112.66</td><td>122.18</td><td>111.25</td><td>86.46</td><td>83.08</td><td>82.43</td></tr><tr><td>Peer Group</td><td>100.00</td><td>121.76</td><td>85.76</td><td>78.41</td><td>54.99</td><td>65.34</td><td>34.06</td><td>38.35</td><td>34.48</td></tr></table>

## Dividend Policy

The Company did not pay any dividends in the fiscal year ended December 31, 2022 and currently intends to retain future earnings, if any, to finance the operations, growth and development of its business. Any future determination as to the declaration and payment of dividends, if any, will be at the discretion of our Board of Directors, subject to compliance with contractual restrictions and covenants in the agreements governing our current and future indebtedness and the DGCL. Any such determination will also depend upon our business prospects, results of operations, financial condition, cash requirements and availability, and other factors that our Board of Directors may deem relevant.

## Securities Authorized for Issuance Under Equity Compensation Plans

The information required by Item 5 of Form 10-K regarding equity compensation plans is incorporated herein by reference to Item 12 of Part III of this Annual Report.

## Issuer Repurchases of Equity Securities

None.

## Use of Proceeds from Sale of Registered Securities

On January 21, 2021, our Registration Statement on Form S-1, as amended (File No. 333-251312) (the "Registration Statement"), was declared effective by the SEC in connection with the IPO. The underwriter for the IPO was Roth Capital Partners. A total of 3,399,515 shares of our common stock were sold pursuant to the Registration Statement, which was comprised of (1) 2,702,500 shares of new common stock issued by the Company and (2) 697,015 shares of the Company's common stock held by MNK. The 3,399,515 shares were sold at an offering price of $8.50 per share and resulting in net proceeds to the Company of approximately $15.0 million, after deducting the underwriting discount of approximately $1.6 million and offering expenses payable by the Company of approximately $6.2 million.

The IPO closed on January 26, 2021. No payments for such expenses were made directly or indirectly to (i) any of our officers or directors or their associates, (ii) any persons owning 10% or more of any class of our equity securities or (iii) any of our affiliates.

From the closing of the IPO through December 31, 2022, approximately $14.8 million of the net proceeds from the IPO have been used by Montauk for the following: the Montauk Ag Asset Acquisition in May 2021, the purchase of the real-estate and property in October 2021 related to Montauk Ag, and subsequent development activities related to Montauk Ag Renewables. An immaterial amount has been used relating to other possible acquisitions and projects. As of December 31, 2022, the remaining net proceeds of approximately $0.2 million is held as cash. The remaining net proceeds have been used by the Company during 2023 in the continued development of Montauk Ag Renewables.

## Recent Sales of Unregistered Securities

None.



## ITEM 6. RESERVED

## ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K. The historical consolidated financial data discussed below reflects the historical results of operations and financial position of Montauk USA, prior to the Equity Exchange on January 4, 2021. Following the Equity Exchange on January 4, 2021, the consolidated financial statements of Montauk USA became our historical financial statements for the periods prior to the Equity Exchange.

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

This section generally discusses our results of operations for the year ended December 31, 2022 compared to the year ended December 31, 2021. For discussion and analysis of our results for the year ended December 31, 2021 compared to the year ended December 31, 2020, refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K filed with the SEC on March 16, 2022.

## Overview

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

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

## Recent Developments

## 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. The industry experienced volatile D3 RIN index prices since the EPAs release of the 2023 RVO in December 2022. Though the average market price of D3 RINs since the 2023 RVO release was approximately $2.18, the market price declined as low as $1.88 in February 2023 from a D3 RIN index price of $2.43 on the day of the 2023 RVO release. We viewed this reduction in price as temporary and, accordingly, we determined not to transfer a significant amount of D3 RINs generated and available for transfer during the first quarter of 2023. As a result, we have approximately 3,890 RINs in inventory from 2022 gas production and have approximately 7,269 RINs in inventory from 2023 gas production as of the filing of this Report.



We have not entered into commitments to transfer these RINs in inventory nor have we entered into agreements to transfer future RINs generated from forecasted future production. The average D3 RIN index price during the month of February 2023 was approximately $1.95.

## 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, bio-oil and biochar (the “Montauk Ag Renewables Acquisition”). The assets acquired include real property, intellectual property, mobile equipment, and other equipment related to operating the business. The real property includes the purchase of an approximate 9.35 acre parcel in Duplin County, North Carolina. Also, in 2021, we closed on a transaction to acquire approximately 146 acres and an approximately 500,000 square foot existing structure in Turkey, North Carolina where we plan to use consolidate and expand the production processes purchased in the Montauk Ag Renewables Acquisition.

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

While these project developments continue, we continue to engage with regulatory agencies in North Carolina related to the resulting power generation derived from swine waste to confirm its eligibility for Renewable Energy Credits under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production. Accordingly, we requested that our Turkey location be 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. Due to our consolidation of operations at the Turkey, NC location and based on our current expectations related to commercial operations, we have paused our registration process to obtain NREF status for the Turkey, NC location. Our Turkey, NC location has been accepted into the Piedmont Natural Gas Renewable Gas Pilot Program.

In the first quarter of 2023 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. We are also in varying stages of discussions with potential power purchasers.

We are at the beginning stages of developing the opportunities associated 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 facility to be used for commercial production. Based on our current development timeline expectations, we do not expect to commence significant revenue generating activities until 2024. We intend to contract with additional farms to secure feedstock sources for future production processes.

## Amendment to Pico Feedstock Agreement

During the second quarter of 2021, we completed an amendment to our Pico feedstock agreement (“Pico Feedstock Amendment”). The amendment will increase the amount of feedstock supplied to the facility for processing over a one to three-year period. We have paid $3,500 in cash under the terms of the Pico Feedstock Amendment.



Under the Pico Feedstock Amendment the dairy began delivering the first and second increases in feedstock during the third quarter of 2022. The improved efficiencies of our existing digestion process and the water management improvements have enabled us to process the increased feedstock volumes which we currently expect to increase by five to ten percent once all increased feedstock deliveries have been received from the dairy. We completed the design of the digestion capacity project in the third quarter of 2022 and have begun incurring capital expenditures related to the construction of the project. We currently expect the construction 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.

In 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. We do not believe we received any significant public comments and expect to receive the certified provisional CI score before the end of the first quarter of 2023.

## Second Apex RNG Facility

In August 2022, we announced the planned construction of a second RNG processing facility at the Apex landfill. This project is being driven by projections in biogas feedstock availability from the host landfill. We anticipate an approximate 40% increase in RNG processing capacity with the addition of the second facility. This expansion is expected to increase daily production approximately 2,100 MMBtu per day and expand the infrastructure for the conversion of LFG to RNG. We have begun to incur capital expenditures for this project and expect the project to be complete and become commercially operational in 2024.

## Raeqer Capital Improvement

In June 2022, our Board of Directors approved a capital improvement project to make upgrades to our Raeqer facility that will increase production. This facility is currently being impacted by requirements to meet federal pipeline tariffs which limit the oxygen content of product gas. The pipeline tariffs have resulted in limitations in our ability to process all existing feedstock. During the second quarter of 2022, we completed our analysis of process facility improvements necessary to meet these more stringent tariff requirements. Construction on this capital project commenced during the third quarter of 2022 and we expect it will become commercially operational during the second half of 2023. Based on the current production of the Raeqer facility, we anticipate an approximate increase of 50% of average daily production.

## Key Trends

## Market Trends Affecting the Renewable Fuel Market

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

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

- Regulatory or policy initiatives, including the federal RFS program and state-level low-carbon fuel programs in states such as California and Oregon, that drive demand for RNG and its derivative Environmental Attributes (as further described below).

- Efficiency, mobility and capital cost flexibility in RNG operations enable it to compete successfully in multiple markets. Our operating model is nimble, as we commonly use modular equipment; our RNG processing equipment is more efficient than its fossil-fuel equivalents.

- Demand for compressed natural gas (“CNG”) from natural gas-fueled vehicles. The RNG we create is pipeline-quality and can be used for transportation fuel when converted to CNG. CNG is commonly used by medium-duty fleets that are close to fueling stations, such as city fleets, local delivery trucks and waste haulers.



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

## Factors Affecting Our Future Operating Results:

## Conversion of Electricity Projects to RNG Projects:

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

## Acquisition and Development Pipeline

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

- 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.

- 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. In accordance with the consent decree entered into between the EPA and Growth Energy approved by the U.S. District Court for the District of Columbia, the EPA issued the final Renewable Fuel Standards for 2020, 2021, and 2022 on June 3, 2022. Final volumes for cellulosic biofuel were set at 510, 560 and 630 million RINs for the three years 2020, 2021 and 2022, respectively. While final volumes set for all three years were lower than proposed, the EPA partially offset the lower volumes by issuing its final notice, also on June 3, 2022, to deny the remaining 69 petitions for RFS Small Refinery Exemptions. Per the settlement agreement with Growth Energy, the EPA was



required to issue a proposed 2023 RVO no later than November 16, 2022 with final volume requirements established by June 11, 2023. On November 4, 2022, the EPA filed a notice with the U.S. District Court for the District of Columbia indicating that EPA and Growth Energy have agreed to extend the deadline for signing the proposed rule for the 2023 renewable fuel standards.

The EPA issued the proposed Renewable Fuel Standard for 2023, 2024, and 2025 on December 1, 2022. Comments on this proposed rule were due by February 10, 2023 with a final rule to be issued by June 14, 2023. The proposed volumes for cellulosic biofuel were set at 720, 1,420, and 2,130 million RINs for the three years 2023, 2024, and 2025, respectively. Included within these volumes are 0, 600, and 1,200 million volumes of eRINs generated from renewable electricity for 2023, 2024, and 2025, respectively.

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. CARB finalized engineering review of the Pico facility’s provisional CI application and posted the application for public comment on February 28, 2023. The public comment period ended March, 14, 2023. We expect to receive the certified provisional CI score before the end of the first quarter of 2023.

## 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. 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 revenues are priced based on published index prices which can be influenced by factors outside our control, such as market impacts on commodity pricing and regulatory developments. With our royalty payments structured as a percentage of revenue, royalty payments fluctuate with changes in revenues. 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 or interconnection or transmission problems could result in a reduction of our RNG production. We strive to proactively address any issues that may arise through preventative maintenance, process improvement and flexible redeployment of equipment to maximize production and useful life.

- In October 2020, California wildfires forced our Bowerman facility to temporarily shut down. While production resumed in November 2020, our fourth quarter 2020 Bowerman revenues were approximately 20.0% lower than the prior year period. Operations at this facility have resumed.

- A 2021 cold weather event impacted our Atascocita, Galveston, McCarty, and Coastal Plains facilities located in Texas. Production at these facilities was temporarily idled due to the loss of power from February 14 through February 20, 2021 and force majeure events were declared by certain of our counterparties or by us for the period February 12 through February 22, 2021 related to these weather events. Operations at these facilities have resumed.

- 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 experienced lower than historical volumes beginning in 2022.

- Our Pico facility has resumed operations and we expect all ramp up activities to be completed by the second quarter of 2022. Our improvement project has impacted the timeline related to modeling the CI Score pathway model. 2022 production will be stored until CARB completes its CI Score Pathway. We currently expect to receive LCFS credit revenue on 2022 production until 2023.

- Many of our sites were impacted by severe cold weather events occurring during the fourth quarter of 2022. In anticipation of these events, we implemented winterization programs designed to protect our processing equipment from these cold weather events. These programs included draining water and adding temporary insulation and heat trace at certain sites. Even with our winterization efforts, we experienced lower than historical production volumes during December 2022 due to this severe cold weather. Operations at these facilities have subsequently resumed.

- 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 short-term and medium-term agreements to counterparties, with contract terms varying from three years to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. All of the Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price arrangement with escalators.

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

Our dairy farm project is expected to be 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 in the following calendar year. We did not forward sell a significant portion of expected 2023 RIN generation. 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.

- 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.

- 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 2023. The Company accounts for stock-based compensation related to grants made through its equity and incentive compensation plan under FASB ASC 718. For more information, see Note 15 to our audited consolidated financial statements.

- 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, though a portion are generated and monetized by third parties under counterparty sharing agreements. A majority of our Renewable Electricity Generation segment Environmental Attributes are monetized as a component of our fixed-price PPAs.

- Average realized price per unit of production: Our profitability is highly dependent on the commodity prices for natural gas and electricity, and the Environmental Attribute prices for RINs, LCFS credits, and RECs. Realized prices for Environmental Attributes monetized in a year may not correspond directly with that year’s production as attributes may be carried over and subsequently monetized. We may elect to not commit to transfer all available RINs in a given period which could impact our revenue and operating profit. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.



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

<table><tr><td rowspan="2">(in thousands, unless otherwise indicated)</td><td colspan="2">For the year ended December 31,</td><td rowspan="2">Change</td><td rowspan="2">Change %</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Renewable Natural Gas Total Revenues</td><td>$196,218</td><td>$131,803</td><td>$64,415</td><td>48.9%</td></tr><tr><td>Renewable Electricity Generation Total Revenues</td><td>$17,170</td><td>$15,449</td><td>$1,721</td><td>11.1%</td></tr><tr><td>RNG Metrics</td><td></td><td></td><td></td><td></td></tr><tr><td>CY RNG production volumes (MMBtu)</td><td>5,522</td><td>5,688</td><td>(166)</td><td>(2.9)%</td></tr><tr><td>Less: Current period RNG volumes under fixed/floor-price contracts</td><td>(1,278)</td><td>(1,596)</td><td>318</td><td>(19.9)%</td></tr><tr><td>Plus: Prior period RNG volumes dispensed in current period</td><td>372</td><td>353</td><td>19</td><td>5.4%</td></tr><tr><td>Less: Current period RNG production volumes not dispensed</td><td>(378)</td><td>(372)</td><td>(6)</td><td>1.6%</td></tr><tr><td>Total RNG volumes available for RIN generation(1)</td><td>4,238</td><td>4,073</td><td>165</td><td>4.1%</td></tr><tr><td>RIN Metrics</td><td></td><td></td><td></td><td></td></tr><tr><td>Current RIN generation (x 11.727)(2)</td><td>49,697</td><td>47,758</td><td>1,939</td><td>4.1%</td></tr><tr><td>Less: Counterparty share (RINs)</td><td>(5,275)</td><td>(5,124)</td><td>(151)</td><td>2.9%</td></tr><tr><td>Plus: Prior period RINs carried into CY</td><td>140</td><td>110</td><td>30</td><td>27.3%</td></tr><tr><td>Less: CY RINs carried into next CY</td><td>(739)</td><td>(140)</td><td>(599)</td><td>427.9%</td></tr><tr><td>Total RINs available for sale(3)</td><td>43,823</td><td>42,604</td><td>1,219</td><td>2.9%</td></tr><tr><td>Less: RINs sold</td><td>(43,823)</td><td>(42,604)</td><td>(1,219)</td><td>2.9%</td></tr><tr><td>RIN Inventory</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>RNG Inventory (volumes not dispensed for RINs)(4)</td><td>368</td><td>372</td><td>(4)</td><td>(1.1)%</td></tr><tr><td>Average Realized RIN price</td><td>$3.25</td><td>$1.91</td><td>$1.34</td><td>70.2%</td></tr><tr><td>Operating Expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Renewable Natural Gas Operating Expenses</td><td>$86,068</td><td>$65,046</td><td>$21,022</td><td>32.3%</td></tr><tr><td>Operating Expenses per MMBtu (actual)</td><td>$15.59</td><td>$11.44</td><td>$4.15</td><td>36.3%</td></tr><tr><td>Renewable Electricity Generation Operating Expenses</td><td>$14,910</td><td>$12,177</td><td>$2,733</td><td>22.4%</td></tr><tr><td>$/MWh (actual)</td><td>$78.47</td><td>$66.56</td><td>$11.91</td><td>17.9%</td></tr><tr><td>Other Metrics</td><td></td><td></td><td></td><td></td></tr><tr><td>Renewable Electricity Generation Volumes Produced (MWh)</td><td>190</td><td>183</td><td>7</td><td>3.8%</td></tr><tr><td>Average Realized Price /MWh (actual)</td><td>$90.37</td><td>$84.45</td><td>$5.92</td><td>7.0%</td></tr></table>

(1) RINs are generated in the month that the gas 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.



## Results of Operations

## Comparison of Years Ended December 31, 2022 and 2021

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

<table><tr><td rowspan="2">(in thousands, except per share data)</td><td colspan="2">For the year ended December 31,</td><td rowspan="2">Change</td><td rowspan="2">Change%</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Total operating revenues</td><td>$205,559</td><td>$148,127</td><td>$57,432</td><td>38.8%</td></tr><tr><td>Operating Expenses:</td><td></td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance expenses</td><td>57,267</td><td>49,477</td><td>7,790</td><td>15.7%</td></tr><tr><td>General and administrative expenses</td><td>34,139</td><td>42,552</td><td>(8,413)</td><td>(19.8)%</td></tr><tr><td>Royalties, transportation, gathering and production fuel</td><td>44,163</td><td>28,683</td><td>15,480</td><td>54.0%</td></tr><tr><td>Depreciation and amortization</td><td>20,700</td><td>22,869</td><td>(2,169)</td><td>(9.5)%</td></tr><tr><td>Gain on insurance proceeds</td><td>(313)</td><td>(332)</td><td>19</td><td>(5.7)%</td></tr><tr><td>Impairment loss</td><td>4,852</td><td>1,191</td><td>3,661</td><td>307.4%</td></tr><tr><td>Transaction costs</td><td>185</td><td>352</td><td>(167)</td><td>(47.4)%</td></tr><tr><td>Total operating expenses</td><td>$160,993</td><td>$144,792</td><td>$16,201</td><td>11.2%</td></tr><tr><td>Operating profit</td><td>$44,566</td><td>$ 3,335</td><td>$41,231</td><td>1236.3%</td></tr><tr><td>Other expenses:</td><td>1,324</td><td>3,702</td><td>(2,378)</td><td>(64.2)%</td></tr><tr><td>Income tax expense</td><td>8,048</td><td>4,161</td><td>3,887</td><td>93.4%</td></tr><tr><td>Net income (loss)</td><td>$ 35,194</td><td>$ (4,528)</td><td>$39,722</td><td>877.3%</td></tr></table>

## Revenues for the Years Ended December 31, 2022 and 2021

Total revenues in 2022 were $205,559, an increase of $57,432 (38.8%) compared to $148,127 in 2021. The primary driver for this increase relates to an increase of 70.2% in realized RIN pricing during 2022 of $3.25 compared to $1.91 in 2021. Additionally, the natural gas index price increased approximately 72.9% in 2022 and was $6.64 compared to $3.84 in 2021. These increases were offset by lower counterparty sharing revenues of $13,176 in 2022 compared to 2021 due to these arrangements ending.

## Renewable Natural Gas Revenues

We produced 5,522 MMBtu of RNG during 2022, a decrease of 166 MMBtu (2.9%) from the 5,688 MMBtus produced in 2021. Our Atascocita facility produced 160 fewer MMBtu in 2022 compared to 2021 due to a temporary process equipment failure. Our Rumpke facility produced 89 fewer MMBtu in 2022 compared to 2021 as a result of lower wellfield inlet flow associated with the landfill host operations. Our Apex facility produced 70 fewer MMBtu in 2022 compared to 2021 due to landfill filling pattern changes resulting in lower production. Offsetting the decrease are production volume increases at our Pico and Galveston facilities. Our Pico facility produced 108 MMBtu more in 2022 compared to 2021 as a result of improvements related to the existing digestion process and our water management practices. Our Galveston facility produced 52 MMBtu more in 2022 compared to 2021 as a result of higher inlet gas due to wellfield changes and plant efficiency optimization of process equipment.

Revenues from the Renewable Natural Gas segment in 2022 were $196,218, an increase of $64,415 (48.9%) compared to $131,803 in 2021. Average commodity pricing for natural gas for 2022 was 72.9% higher than the prior year. During 2022, we self-marketed 43,823 RINs, representing a 1,219 increase (2.9%) compared to 42,604 in 2021. The increase was primarily related to an offtake agreement change in 2021 providing more RNG volumes available to self-market. Average pricing realized on RIN sales during 2022 was $3.25 as compared to $1.91 in 2021, an increase of 70.2%. This compares to the average D3 RIN index price for 2022 of $2.98 being approximately 1.3% lower than the average D3 RIN index price in 2021 of $3.02. All our RIN sales in 2022 and



2021 were priced generally on the D3 index with none based on CWC. At December 31, 2022, we had approximately 0.4 million MMBtus available for RIN generation and had approximately 0.7 million RINs generated and unsold. We had approximately 0.4 million MMBtus available for RIN generation and approximately 0.1 million RINs generated and unsold at December 31, 2021.

## Renewable Electricity Generation Revenues

We produced 190 MWh in Renewable Electricity in 2022, an increase of approximately 7 MWh (3.8%) compared to 183 MWh in 2021. In 2022, our Security facility produced 10 MWh in 2022 compared to zero production in 2021 as a result of the prior period engine restoration project. Offsetting this increase, is a decrease at our Tulsa facility that produced 3 MWh less in 2022 compared to 2021 due to reduced feedstock availability at the landfill.

Revenues from Renewable Electricity facilities in 2022 were $17,170, an increase of $1,721 (11.1%) compared to $15,449 in 2021. Our Bowerman facility contributed to $1,244 of the increase, which was primarily driven by a temporary shutdown of the facility in the fourth quarter 2020 due to the California wildfires, resulting in $598 in reduced Environmental Attribute revenues in 2021 compared to 2022. Also contributing to the increase is our Security facility engine restoration project resulting in $668 in higher revenues for 2022 compared to zero in 2021.

## Corporate Analysis

During 2022, our gas commodity hedge was priced at rates below actual index prices and we recorded losses of $7,829 related to our gas commodity hedge. Our gas commodity hedge expired in December 2022 and we did not have any gas commodity hedges during 2021. During 2021, we recorded revenues of $875 related to RINs purchased in 2021 and recorded an adjustment of $710, associated with our purchase of RINs, to reduce the carrying value of those RINs to net realizable value. This is included within our operating revenues in the Consolidated Statement of Operations for the 2021 period. We did not have market purchased RINs during 2022.

## Expenses for the Years Ended December 31, 2022 and 2021

## General and Administrative Expenses

Total general and administrative expenses of $34,139 in 2022, a decrease of $8,413 (19.8%) compared to $42,552 in 2021. Employee related costs, including stock-based compensation, decreased approximately $10,643 (35.4%) in 2022 compared to 2021. The decrease is primarily related to our accounting for the cancellation of MNK options and January 2021 grants of restricted stock, non-qualified stock options, and restricted stock units to the Company’s employees. Offsetting this decrease is an increase in general and administrative expenses of approximately $3,608 (337.5%) in 2022 as compared to 2021 associated with the Montauk Ag Renewables Acquisition. Our corporate insurance premiums increased approximately $377 (6.8%) during 2022 compared to 2021, primarily related to premium increases. Our board of directors approved payments of cash fees to non-employee directors resulting in increased fees of approximately $675 in 2022 as compared to 2021. Finally, excluding the Montauk Ag Renewables Acquisition, our professional fees increased approximately $799 (19.4%) in 2022 as compared to 2021 primarily related to increased legal fees.

## Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in 2022 were $43,729, an increase of $5,615 (14.7%) compared to $38,114 in 2021. The increase is driven by increased RNG utilities of approximately $6,061 (61.2%) in 2022 compared to 2021. The increase was caused by a cold weather event in the first quarter of 2021 impacting our Houston based facilities being favorably impacted by lower utility rates.



Royalties, transportation, gathering and production fuel expenses for the Company’s RNG facilities for 2022 were $42,339, an increase of $15,407 (57.2%) compared to $26,932 in 2021. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 21.6% for 2022 from 20.4% in 2021.

## Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in 2022 were $13,086, an increase of $2,660 (25.5%) compared to $10,426 in 2021. The increase is primarily driven by the timing of scheduled engine preventative maintenance intervals at our Bowerman facility, of approximately $1,645 higher in 2022 over 2021. Adding to the increase are operating expenses of approximately $434 related to Montauk Ag Renewables Acquisition.

Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2022 were $1,824, an increase of $73 (4.2%) compared to $1,751 in 2021 and as a percentage of Renewable Electricity Generation segment, revenues decreased from 11.3% to 10.6%.

## Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in 2022 were $44,163, an increase of 15,480 (54.0%) compared to $28,683 in 2021. 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 2022 were $20,700, a decrease of $2,169 (9.5%) compared to $22,869 in 2021. The decrease is associated with assets remaining in service being fully amortized.

## Impairment loss

We calculated and recorded impairment losses of $4,852 for 2022, an increase of $3,661 (307.4%) compared to $1,191 for 2021. The primary driver of this increase relates to an impairment of $2,133 for a REG site wherein the forecast future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG site was impaired for $1,393 due to discrete conclusion that certain assets acquired in the May 2021 Montauk Ag Renewables Acquisition would no longer be utilized. Also in 2022, we recorded an impairment at an RNG facility for approximately $1,108 due to the specific identification of certain assets no longer being capable of use as designed. The 2021 impairment loss of $1,191 was primarily related to the closure of two REG sites and the disposal of machinery at one RNG site.

## Other Expenses (Income)

Other expenses in 2022 were $1,324, a decrease of $2,378 (64.2%) compared to $3,702 in 2021. Reduced interest expense of $1,136 is related to our favorable interest rate swap contract resulting in reduction of interest expense in 2022 as compared to 2021. Also impacting the decrease is $865 relating to asset disposal costs at our Galveston and Pico facilities in 2021.

## Income Tax Expense

Prior to 2022, we generated NOLs, which can be carried forward indefinitely, however, some of the NOLs are under an 80% limitation. In 2022, we utilized all non-limited NOL carryforwards. Based upon our historical



pre-tax book income and forecasts, we expect to utilize some remaining NOLs and thus have not recorded a valuation allowance against such NOLs.

Our effective income tax rate (“ETR”) for 2022 was an expense of 18.6% compared to 1,132.1% for the prior year period. The higher ETR in the prior year period was driven by the low pre-tax income compared to the tax expense of $4,161 for 2021, which was primarily driven by the Section 162(m) limitation.

The Inflation Reduction Act of 2022, enacted by the United States on August 16, 2022, did not have a material impact on our provision for income taxes for the year ended December 31, 2022. The American Rescue Plan Act of 2021, enacted on March 11, 2021 did not have a material impact on the provision for income taxes for the year ended December 31, 2021. The Company is continuing to analyze the ongoing impact of the Inflation Reduction Act legislation.

## Operating Profit (Loss) for the Years Ended December 31, 2022 and 2021

Operating profit in 2022 was $44,566, an increase of $41,231 (1236.3%) compared to $3,335 in 2021. RNG operating profit for 2022 was $94,439, an increase of $44,089 (87.6%) compared to $50,350 in 2021. Renewable Electricity Generation operating loss for 2022 was $7,019, an increase of $3,929 (127.2%) compared to an operating loss of $3,090 in 2021.

## Non-GAAP Financial Measures:

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

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

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Net income (loss)</td><td>$35,194</td><td>$ (4,528)</td></tr><tr><td>Depreciation and amortization</td><td>20,700</td><td>22,869</td></tr><tr><td>Interest expense</td><td>1,792</td><td>2,928</td></tr><tr><td>Income tax expense</td><td>8,048</td><td>4,161</td></tr><tr><td>Consolidated EBITDA</td><td>65,734</td><td>25,430</td></tr><tr><td>Impairment loss(1)</td><td>4,852</td><td>1,191</td></tr><tr><td>Net (gain) loss on sale of assets</td><td>(233)</td><td>822</td></tr><tr><td>Transaction costs</td><td>185</td><td>352</td></tr><tr><td>Loss on extinguishment of debt</td><td>—</td><td>154</td></tr><tr><td>Adjusted EBITDA</td><td>$70,538</td><td>$27,949</td></tr></table>

(1) For the year ended December 31, 2022, we recorded an impairment of $2,133 for a REG site wherein the forecast future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG



site was impaired for $1,393 due to discrete conclusion that certain assets acquired in the May 2021 Montauk Ag Renewables Acquisition would no longer be utilized. Also in 2022, we recorded an impairment at an RNG facility for approximately $1,108 due to the specific identification of certain assets no longer being capable of use as designed. For year ended December 31, 2021, we recorded an impairment of $626 related to a landfill host request to decommission a previously converted RNG site. We were previously contractually obligated to maintain this facility. Additionally, we impaired $421 related to disposal of machinery at our Rumpke facility.

## Liquidity and Capital Resources

## Sources of Liquidity

At December 31, 2022 and 2021, our cash and cash equivalents, net of restricted cash, was $105,177 and $53,266, respectively. We intend to fund development projects using cash flows from operations and borrowings under our revolving credit facility. We believe that we will have sufficient cash flows from operations and borrowing availability under our credit facility to meet our debt service obligations and anticipated required capital expenditures (including for projects under development) for the next 12 to 24 months. However, we are subject to business and operational risks that could adversely affect our cash flows and liquidity.

At December 31, 2022, we had debt before debt issuance costs of $72,000, compared to debt before debt issuance costs of $80,000 at December 31, 2021.

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

<table><tr><td></td><td>December 31, 2022</td><td>December 31, 2021</td></tr><tr><td>Term Loans</td><td>$72,000</td><td>$80,000</td></tr><tr><td>Revolving Credit Facility</td><td>—</td><td>—</td></tr><tr><td>Debt before debt issuance costs</td><td>$72,000</td><td>$80,000</td></tr></table>

## Amended Credit Agreement

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

As of December 31, 2022, $72,000 was outstanding under the term loan and we had no outstanding borrowings under the revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through December 2024, quarterly installments of $3,000 from 2025 through the maturity, with a final payment of $32,000, of December 21, 2026 with an interest rate of 4.12% and 2.91% at December 31, 2022 and 2021, respectively. The revolving and term loans under the Amended Credit Agreement bear interest at the BSBY Margin or Base Rate Margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement).

The Amended Credit Agreement contains customary covenants applicable to us and certain of our subsidiaries, including financial covenants. The Amended Credit Agreement is subject to customary events of default, and contemplates that we would be in default if, for any fiscal quarter (x) the average monthly D3 RIN price (as determined in accordance with the Amended Credit Agreement) is less than $0.80 per RIN and (y) the consolidated EBITDA for such quarter is less than $6.0 million. Consolidated EBITDA is defined under the Amended Credit Agreement as net income plus (a) income tax expense, (b) interest expense, (c) depreciation, depletion, and amortization expense, (d) non-cash unrealized derivative expense, (e) any extraordinary, unusual, or non-recurring cash expenses and/or losses not exceeding $500,000 in the aggregate to the extent not included in the determination of operating income on MEH’s consolidated statements of profits and loss, (f) subject to



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

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

- a Total Leverage Ratio (as defined in the Amended Credit Agreement) of not more than 3.50 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 December 31, 2022, we were in compliance with all financial covenants related to the Amended Credit Agreement.

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

## Capital Expenditures

We have historically funded our growth and capital expenditures with our working capital, cash flow from operations and debt financing. We used the proceeds from our 2021 IPO to fund the Montauk Ag Renewables Asset Acquisition and the continued development of Montauk Ag Renewables. In 2023, we expect the development of Montauk Ag Renewables to be funded from our working capital, cash flow from operations and debt financing. We expect our non-development 2023 capital expenditures to range between $15,000 and $18,000. Our 2023 capital plans include annual preventative maintenance expenditures, annual wellfield expansion projects, critical spare expenditures, and other specific facility 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 and the second Apex facility. Our Amended Credit Agreement provides us with an $120,000 revolving credit facility, with a $75,000 accordion option, providing us with access to additional capital to implement our acquisition and development strategy. We are currently in various stages of discussions regarding a variety of development and strategic growth opportunities. Development opportunities include: up to seven LFG RNG sites which we could contemplate generating renewable electricity to qualify for eRINs and up to two waste water treatment RNG opportunities. If we ultimately enter into definitive agreements for any of these opportunities, we expect to incur material capital expenditures related to either acquisitions costs or development costs, or both. As we continue to explore



strategic growth opportunities and while we have entered into nonbinding letters of intent for certain of these opportunities, we provide no assurances that our plans related to any or all of these strategic opportunities will progress to definitive agreements. We believe that our existing cash and cash equivalents, cash generated from operations, and credit availability under our Amended Credit Agreement would allow us to pursue and close on our identified strategic growth opportunities.

## Cash Flow

The following table presents information regarding our cash flows and cash equivalents for years ended December 31, 2022 and 2021:

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Net cash flows provided by operating activities</td><td>$ 81,066</td><td>$ 42,879</td></tr><tr><td>Net cash flows used in investing activities</td><td>(20,794)</td><td>(19,474)</td></tr><tr><td>Net cash flows (used in) provided by financing activities</td><td>(8,279)</td><td>8,649</td></tr><tr><td>Net increase in cash and cash equivalents</td><td>51,993</td><td>32,054</td></tr><tr><td>Restricted cash, end of period</td><td>429</td><td>347</td></tr><tr><td>Cash and cash equivalents and restricted, end of period</td><td>105,606</td><td>53,613</td></tr></table>

For the year ended December 31, 2022, we generated $81,066 of cash from operating activities, an 89.1% increase from the prior year ended December 31, 2021 of $42,879. For the year ended December 31, 2022, income and adjustments to income from operating activities provided $75,832 compared to $46,549 in 2021. Working capital and other assets and liabilities provided $5,234 in the current period compared to $3,671 being used in the prior year period. When we commission new sites, we invest capital to ramp up operations prior to the project generating revenue. Our net cash flows used in investing activities has historically focused on project development and facility maintenance.

Our net cash flows used in investing activities has historically focused on project development and facility maintenance. For 2022, our capital expenditures were $22,277, of which $6,860 and $3,555 were related to the Pico facility digestion capacity increase and Montauk Ag Renewables in North Carolina, respectively. For 2021, our capital expenditures were $9,986, of which approximately $2,428 were related to optimization projects at our recently commissioned facilities and $1,000 related to the Pico Feedstock Amendment. We acquired assets of $4,142, including $341 in acquisition costs for land, building, mobile equipment and other property, plant and equipment for the Montauk Ag Renewables Acquisition in North Carolina and we paid an additional $5,531, including $31 in acquisition costs, for land, land improvements and a building.

Our net cash flows used in financing activities of $8,279 for 2022 decreased by $16,928 compared to cash provided by in financing activities of $8,649 in 2021. In 2021, the closing of our IPO provided $15,593 in proceeds after payment of commissions and expenses. The company reacquired 950,214 shares with a value of approximately $10,813 connection with withholding shares from restricted stock awards pursuant to elections made by employees under Section 83(b) of the Code related to the IPO. Additionally, during 2021 and in connection with the Distribution, we loaned $8,940 to MNK for its dividends tax liability arising under the South African Income Tax Act, 1962, as amended. As security for this loan, MNK has pledged certain of its shares in the Company to Montauk Renewables and agreed to use the proceeds from the sale of such shares to repay this loan. During 2021, we borrowed $80,000 under our revolving credit agreement to be used primarily for development capital expenditures.

## Contractual Obligations and Commitments

Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under



GAAP. Our off-balance sheet arrangements are limited to the outstanding letters of credit and operating leases described below. Although these arrangements serve a variety of our business purposes, we are not dependent on them to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.

The Company has contractual obligations involving asset retirement obligations. See Note 9 in the Consolidated Financial Statements for further information regarding the asset retirement obligations.

The Company has contractual obligations under our debt agreement, including interested payments and principal repayments. See Note 13 in the Consolidated Financial Statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. During 2022, we had $3,905 of off-balance sheet arrangements of outstanding letters of credit. These letters of credit reduce the borrowing capacity of our revolving credit facility under our Amended Credit Agreement. Certain of our contracts require these letters of credit to be issued to provide additional performance assurances. There have been no usage against these outstanding letters of credit. During 2021, 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. See Note 19 in the Consolidated Financial Statements for further information related to the lease obligations. In 2022, the Company entered into a new, ten year corporate office lease with monthly rent payments of approximately $43 per month beginning in 2023, the first full year of the lease. The lease includes annual rent increases. Also, in 2022, the Company entered into a four year extension for its regional corporate office with monthly rent payments of approximately $5 per month beginning in 2023. The lease includes annual rent increases.

The Company has other contractual obligations associated with our fuel supply agreements. The expiration of these agreements range between 5-21 years. agreements range. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,385.

## Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

See “Risk Factors—Emerging Growth Company Risks—We have identified a material weakness in our internal control over financial reporting. We continue to implement remediation initiatives in response to this material weakness. If we identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, we may not be able to accurately or timely report our financial condition or results of operations, which may adversely affect our business.”

## Critical Accounting Policies and Estimates

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

## Revenue Recognition

Our revenues are comprised of renewable energy and the related Environmental Attribute sales provided under a variety of short-term and medium-term agreements with our customers. All revenue is recognized when we satisfy our performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product to the customer either when (or as) the customer obtains control of the product. A performance



obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. We allocate the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.

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

The nature of 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. Refer to Item 7A for an estimate of the impact of decreases in the wholesale price of gas on the Company’s operating profit.

## RINs

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

## RECs

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

## Income Taxes

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

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



See Note 14, “Income Taxes” to our audited consolidated financial statements included elsewhere in this report. 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.

Indefinite-lived intangible assets are not amortized and include emission allowances and land use rights. Emission allowances consist of credits that need to be applied to nitrogen oxide (“NOx”) emissions from internal combustion engines. These engines emit levels of NOx for which environmental permits are required in certain regions in the United States. Except for permanent allocations of NOx credits, allowances available for use each year are capped at a level necessary for ozone attainment per the National Ambient Air Quality Standards. We assess the impairment of intangible assets that have indefinite lives at least on an annual basis or whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. The Company has classified these NOx allowances as held for sale as of December 31, 2021 and sold the NOx allowances in 2022.

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

Our assessment of the recoverability of finite-lived and indefinite-lived intangible assets is determined by performing monitoring assessment of the future cash flows associated with the underlying gas rights agreements. The cash flows estimates are performed at the operating unit level and based on the average remaining length of the gas rights agreements. Based on our analysis, we concluded the cashflows generated to be well in excess of the carrying amounts. Changes in market conditions related to the various price indexes used in estimating these cash flows could adversely effect these estimates. We perform various sensitivities around price estimates and our price estimates for certain environmental attributes are currently approximately 15-25% lower than current index prices.



## 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.

During the third quarter of 2022, we performed interim recoverability tests for our Tulsa facility asset group when it was determined it was more likely than not the carrying value of the long-lived asset group would not be recoverable. The results of our testing indicated that the long-lived assets related to the Tulsa facility within our REG segment had carrying values in excess of the asset group’s fair value. Based upon level 3 unobservable inputs, we incorporated assumptions that we believe would be a reasonable market participant’s view in a hypothetical transaction in developing a cash flow analysis. Significant level 3 inputs included estimates of future revenue growth, gross margin, EBITDA, and positive cash flow generation. As a result of the analysis, the Company recorded a $2,133 property, plant and equipment impairment related to the REG site in 2022.

As to the remaining long lived asset groups, the Company further concluded, based on our annual cashflow assessment conducted for monitoring potential indicators of impairment, that the cashflows to be generated are significantly in excess of their carrying values of our operating sites primarily due to the lengths of the underlying gas rights agreements and the Company did not record any other impairments related to its cash flows assessment. Separate from our cash flows assessment, we identified discrete events and recorded impairment of $2,719 and $1,191 for 2022 and 2021, respectively. See Note 3 in the audited 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, “Summary of Significant Accounting Policies” to our consolidated financial statements appearing elsewhere in this report.

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

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



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

## RIN and Environmental Attribute Pricing Risk

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

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to RIN prices. Our analysis, which may differ from actual results, was based on a 2023 estimated D3 RIN Index price of approximately $2.08 and our actual 2022 RINs sold. The estimated annual impact of a hypothetical 10% decrease in the average realized price per RIN would have a negative effect on our operating profit of approximately $7.3 million.

## RNG and Renewable Electricity Pricing Risk

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

We use a mix of short-, medium-, and long-term sales contracts and commodity hedging derivatives to manage our exposure to our pricing risk. In particular, during 2022 and 2020, we entered into derivative transactions to hedge our exposure to the market price of wholesale gas. We did not enter into a 2023 derivative contract to hedge a portion of our RNG production.

We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to the market price of wholesale gas. Our analysis, which may differ from actual results, was based on a 2023 estimated NYMEX average Index Price of approximately $3.162/MMBtu and our actual 2022 gas production sold pursuant to contracts that do not provide for a fixed or floor price. The estimated annual impact of a hypothetical 10% decrease in the market price of wholesale gas would have a negative effect on our operating profit of approximately $1.1 million.

## Interest Rate Risk

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

As of December 31, 2022, we had $72.0 million outstanding under the Amended Credit Facility. Our weighted average interest rate on variable debt balances during 2022 was approximately 4.12%. We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to changes in interest rates.



Based on our analysis, which may differ from actual results, a hypothetical increase in our effective borrowing rate of 10% would not have a material effect on our annual interest expenses and consolidated financial statements.

## Credit Risk

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

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



## ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Montauk Renewables, Inc.
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248) ..... 70
Consolidated Balance Sheets as of December 31, 2022 and 2021 ..... 71
Consolidated Statements of Operations for the years ended December 31, 2022, 2021 and 2020 ..... 72
Consolidated Statements of Stockholders' and Member's Equity for the years ended December 31, 2022, 2021 and 2020 ..... 73
Consolidated Statements of Cash Flows for the years ended December 31, 2022, 2021 and 2020 .... 74
Notes to Consolidated Financial Statements ..... 75



# REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Montauk Renewables, Inc.

## Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Montauk Renewables, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of operations, stockholders’ and member’s equity, and cash flows for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.

## Basis for opinion

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

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

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

## /s/ GRANT THORNTON LLP

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

Pittsburgh, Pennsylvania
March 16, 2023



## MONTAUK RENEWABLES, INC.

## CONSOLIDATED BALANCE SHEETS

(in thousands, except share data):

<table><tr><td rowspan="2">ASSETS</td><td colspan="2">As of December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Current assets:</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$105,177</td><td>$53,266</td></tr><tr><td>Accounts and other receivables</td><td>7,222</td><td>9,338</td></tr><tr><td>Related party receivable</td><td>9,000</td><td>8,940</td></tr><tr><td>Current portion of derivative instruments</td><td>879</td><td>—</td></tr><tr><td>Prepaid expenses and other current assets</td><td>2,590</td><td>2,846</td></tr><tr><td>Assets held for sale</td><td>—</td><td>777</td></tr><tr><td>Total current assets</td><td>$124,868</td><td>$75,167</td></tr><tr><td>Non-current restricted cash</td><td>$407</td><td>$328</td></tr><tr><td>Property, plant &amp; equipment, net</td><td>175,946</td><td>180,893</td></tr><tr><td>Goodwill and intangible assets, net</td><td>15,755</td><td>14,113</td></tr><tr><td>Deferred tax assets</td><td>3,952</td><td>10,570</td></tr><tr><td>Non-current portion of derivative instruments</td><td>936</td><td>—</td></tr><tr><td>Operating lease right-of-use assets</td><td>4,742</td><td>305</td></tr><tr><td>Finance lease right-of-use assets</td><td>96</td><td>—</td></tr><tr><td>Other assets</td><td>5,614</td><td>5,104</td></tr><tr><td>Total assets</td><td>$332,316</td><td>$286,480</td></tr><tr><td>LIABILITIES AND STOCKHOLDERS&#x27; EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities:</td><td></td><td></td></tr><tr><td>Accounts payable</td><td>$4,559</td><td>$4,973</td></tr><tr><td>Accrued liabilities</td><td>15,090</td><td>10,823</td></tr><tr><td>Income tax payable</td><td>402</td><td>—</td></tr><tr><td>Current portion of derivative instruments</td><td>—</td><td>650</td></tr><tr><td>Current portion of operating lease liability</td><td>410</td><td>296</td></tr><tr><td>Current portion of finance lease liability</td><td>71</td><td>—</td></tr><tr><td>Current portion of long-term debt</td><td>7,870</td><td>7,815</td></tr><tr><td>Total current liabilities</td><td>$28,402</td><td>$24,557</td></tr><tr><td>Long-term debt, less current portion</td><td>$63,505</td><td>$71,392</td></tr><tr><td>Non-current portion of derivative instruments</td><td>—</td><td>189</td></tr><tr><td>Non-current portion of operating lease liability</td><td>4,341</td><td>27</td></tr><tr><td>Non-current portion of finance lease liability</td><td>25</td><td>—</td></tr><tr><td>Asset retirement obligation</td><td>5,493</td><td>5,301</td></tr><tr><td>Other liabilities</td><td>3,459</td><td>2,721</td></tr><tr><td>Total liabilities</td><td>$105,225</td><td>$104,187</td></tr><tr><td>Common stock, $0.01 par value, authorized 690,000,000 shares; 143,682,811 and 143,584,827 shares issued at December 31, 2022 and December 31, 2021, respectively; 141,633,417 and 141,015,213 shares outstanding at December 31, 2022 and December 31, 2021, respectively</td><td>$1,416</td><td>$1,410</td></tr><tr><td>Treasury stock, at cost, 971,306 and 950,214 shares December 31, 2022 and December 31, 2021, respectively</td><td>(11,051)</td><td>(10,813)</td></tr><tr><td>Additional paid-in capital</td><td>206,060</td><td>196,224</td></tr><tr><td>Retained earnings (deficit)</td><td>30,666</td><td>(4,528)</td></tr><tr><td>Total stockholders&#x27; equity</td><td>227,091</td><td>182,293</td></tr><tr><td>Total liabilities and stockholders&#x27; equity</td><td>$332,316</td><td>$286,480</td></tr></table>

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



## MONTAUK RENEWABLES, INC.

## CONSOLIDATED STATEMENTS OF OPERATIONS

<table><tr><td rowspan="2">(in thousands except per share values):</td><td colspan="4">For the year ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Total operating revenues</td><td>$ 205,559</td><td>$ 148,127</td><td>$100,383</td><td></td></tr><tr><td>Operating expenses:</td><td></td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance expenses</td><td>$ 57,267</td><td>$ 49,477</td><td>$ 43,463</td><td></td></tr><tr><td>General and administrative expenses</td><td>34,139</td><td>42,552</td><td>16,594</td><td></td></tr><tr><td>Royalties, transportation, gathering and production fuel</td><td>44,163</td><td>28,683</td><td>18,284</td><td></td></tr><tr><td>Depreciation and amortization</td><td>20,700</td><td>22,869</td><td>22,117</td><td></td></tr><tr><td>Gain on insurance proceeds</td><td>(313)</td><td>(332)</td><td>(3,934)</td><td></td></tr><tr><td>Impairment loss</td><td>4,852</td><td>1,191</td><td>278</td><td></td></tr><tr><td>Transaction costs</td><td>185</td><td>352</td><td>—</td><td></td></tr><tr><td>Total operating expenses</td><td>$ 160,993</td><td>$ 144,792</td><td>$ 96,802</td><td></td></tr><tr><td>Operating profit</td><td>$ 44,566</td><td>$ 3,335</td><td>$ 3,581</td><td></td></tr><tr><td>Other expenses (income):</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense</td><td>$ 1,792</td><td>$ 2,928</td><td>$ 4,339</td><td></td></tr><tr><td>Loss on extinguishment of debt</td><td>—</td><td>154</td><td>—</td><td></td></tr><tr><td>Other (income) expense</td><td>(468)</td><td>620</td><td>635</td><td></td></tr><tr><td>Total other expenses</td><td>$ 1,324</td><td>$ 3,702</td><td>$ 4,974</td><td></td></tr><tr><td>Income (loss) before income taxes</td><td>$ 43,242</td><td>$ (367)</td><td>$ (1,393)</td><td></td></tr><tr><td>Income tax expense (benefit)</td><td>8,048</td><td>4,161</td><td>(5,996)</td><td></td></tr><tr><td>Net income (loss)</td><td>$ 35,194</td><td>$ (4,528)</td><td>$ 4,603</td><td></td></tr><tr><td>Earnings (loss) per share:</td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ 0.25</td><td>$ (0.03)</td><td></td><td></td></tr><tr><td>Diluted</td><td>$ 0.25</td><td>$ (0.03)</td><td></td><td></td><td></td></tr><tr><td>Weighted-average common shares outstanding</td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>141,238,851</td><td>141,015,213</td><td></td><td></td></tr><tr><td>Diluted</td><td>142,579,389</td><td>141,015,213</td><td></td><td></td></tr></table>

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



## MONTAUK RENEWABLES, INC.

## CONSOLIDATED STATEMENTS OF STOCKHOLDERS' AND MEMBER'S EQUITY

<table><tr><td rowspan="2"></td><td colspan="2">Common Stock</td><td colspan="2">Treasury Stock</td><td rowspan="2">Member&#x27;s Equity</td><td rowspan="2">Additional Paid-in Capital</td><td rowspan="2">Retained Earnings (Deficit)</td><td rowspan="2">Total Equity</td></tr><tr><td>Shares</td><td>Amount</td><td>Shares</td><td>Amount</td></tr><tr><td>Balance at December 31, 2019</td><td>—</td><td>$ —</td><td>—</td><td>$ —</td><td>$ 154,257</td><td>$ —</td><td>$ —</td><td>$154,257</td></tr><tr><td>Net income</td><td>—</td><td>—</td><td>—</td><td>—</td><td>4,603</td><td>—</td><td>—</td><td>4,603</td></tr><tr><td>Stock-based compensation</td><td>—</td><td>—</td><td>—</td><td>—</td><td>762</td><td>—</td><td>—</td><td>762</td></tr><tr><td>Balance at December 31, 2020</td><td>—</td><td>$ —</td><td>—</td><td>$ —</td><td>$ 159,622</td><td>$ —</td><td>$ —</td><td>$159,622</td></tr><tr><td>Effect of reorganization transactions</td><td>138,312,713</td><td>1,383</td><td>—</td><td>—</td><td>(159,622)</td><td>158,239</td><td>—</td><td>—</td></tr><tr><td>IPO common stock</td><td>2,702,500</td><td>27</td><td>—</td><td>—</td><td>—</td><td>15,566</td><td>—</td><td>15,593</td></tr><tr><td>Treasury stock</td><td>—</td><td>—</td><td>950,214</td><td>(10,813)</td><td>—</td><td>—</td><td>—</td><td>(10,813)</td></tr><tr><td>Net loss</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(4,528)</td><td>(4,528)</td></tr><tr><td>Stock-based compensation</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>22,419</td><td>—</td><td>22,419</td></tr><tr><td>Balance at December 31, 2021</td><td>141,015,213</td><td>$1,410</td><td>950,214</td><td>$(10,813)</td><td>$ —</td><td>$196,224</td><td>$ (4,528)</td><td>$182,293</td></tr><tr><td>Issuance of common stock</td><td>618,204</td><td>6</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>6</td></tr><tr><td>Treasury stock</td><td>—</td><td>—</td><td>21,092</td><td>(238)</td><td>—</td><td>—</td><td>—</td><td>(238)</td></tr><tr><td>Net income</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>35,194</td><td>35,194</td></tr><tr><td>Stock-based compensation</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>9,836</td><td>—</td><td>9,836</td></tr><tr><td>Balance at December 31, 2022</td><td>141,633,417</td><td>$1,416</td><td>971,306</td><td>$(11,051)</td><td>$ —</td><td>$206,060</td><td>$30,666</td><td>$227,091</td></tr></table>

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



## MONTAUK RENEWABLES, INC.

## CONSOLIDATED STATEMENTS OF CASH FLOWS

<table><tr><td rowspan="2">(in thousands):</td><td colspan="3">For the year ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td></tr><tr><td>Cash flows from operating activities:</td><td></td><td></td><td></td></tr><tr><td>Net income (loss)</td><td>$ 35,194</td><td>$ (4,528)</td><td>$ 4,603</td></tr><tr><td>Adjustments to reconcile net income (loss) to net cash provided by operating activities:</td><td></td><td></td><td></td></tr><tr><td>Depreciation and amortization</td><td>20,700</td><td>22,869</td><td>22,117</td></tr><tr><td>Provision (benefit) for deferred income taxes</td><td>6,618</td><td>4,252</td><td>(6,077)</td></tr><tr><td>Loss on extinguishment of debt</td><td>—</td><td>154</td><td>—</td></tr><tr><td>Stock-based compensation</td><td>9,836</td><td>22,419</td><td>762</td></tr><tr><td>Related party receivables</td><td>—</td><td>—</td><td>164</td></tr><tr><td>Gain on property insurance proceeds</td><td>(313)</td><td>(332)</td><td>(1,659)</td></tr><tr><td>Derivative mark-to-market adjustments and settlements</td><td>(2,652)</td><td>(1,421)</td><td>1,016</td></tr><tr><td>Net (gain) loss on sale of assets</td><td>(233)</td><td>822</td><td>320</td></tr><tr><td>Increase in earn-out liability</td><td>1,122</td><td>801</td><td>—</td></tr><tr><td>Accretion of asset retirement obligations</td><td>296</td><td>(160)</td><td>320</td></tr><tr><td>Amortization of debt issuance costs</td><td>412</td><td>483</td><td>695</td></tr><tr><td>Impairment loss</td><td>4,852</td><td>1,191</td><td>278</td></tr><tr><td>Changes in operating assets and liabilities:</td><td></td><td></td><td></td></tr><tr><td>Accounts and other receivables and other current assets</td><td>(3,054)</td><td>(1,522)</td><td>2,483</td></tr><tr><td>Accounts payable and other accrued expenses</td><td>8,288</td><td>(2,149)</td><td>3,662</td></tr><tr><td>Net cash provided by operating activities</td><td>$ 81,066</td><td>$ 42,879</td><td>$ 28,684</td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>$ (22,277)</td><td>$ (9,986)</td><td>$ (17,646)</td></tr><tr><td>Asset acquisitions</td><td>—</td><td>(9,673)</td><td>—</td></tr><tr><td>Cash collateral deposits, net</td><td>82</td><td>(220)</td><td>—</td></tr><tr><td>Proceeds from insurance recovery</td><td>313</td><td>332</td><td>1,659</td></tr><tr><td>Proceeds from sale of assets</td><td>1,088</td><td>73</td><td>—</td></tr><tr><td>Net cash used in investing activities</td><td>$ (20,794)</td><td>$ (19,474)</td><td>$ (15,987)</td></tr><tr><td>Cash flows from financing activities:</td><td></td><td></td><td></td></tr><tr><td>Borrowings of long-term debt</td><td>$ —</td><td>$ 80,000</td><td>$ 8,500</td></tr><tr><td>Repayments of long-term debt</td><td>(8,000)</td><td>(66,698)</td><td>(10,000)</td></tr><tr><td>Debt issuance costs</td><td>—</td><td>(339)</td><td>—</td></tr><tr><td>Debt extinguishment costs</td><td>—</td><td>(154)</td><td>—</td></tr><tr><td>Common stock issuance</td><td>6</td><td>15,593</td><td>—</td></tr><tr><td>Treasury stock purchase</td><td>(238)</td><td>(10,813)</td><td>—</td></tr><tr><td>Related party receivable</td><td>—</td><td>(8,940)</td><td>—</td></tr><tr><td>Finance lease payments</td><td>(47)</td><td>—</td><td>—</td></tr><tr><td>Net cash (used in) provided by financing activities</td><td>$ (8,279)</td><td>$ 8,649</td><td>$ (1,500)</td></tr><tr><td>Net increase in cash and cash equivalents and restricted cash</td><td>$ 51,993</td><td>$ 32,054</td><td>$ 11,197</td></tr><tr><td>Cash and cash equivalents and restricted cash at beginning of year</td><td>$ 53,613</td><td>$ 21,559</td><td>$ 10,362</td></tr><tr><td>Cash and cash equivalents and restricted cash at end of year</td><td>$ 105,606</td><td>$ 53,613</td><td>$ 21,559</td></tr><tr><td>Reconciliation of cash, cash equivalents, and restricted cash at end of year:</td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 105,177</td><td>$ 53,266</td><td>$ 20,992</td></tr><tr><td>Restricted cash and cash equivalents-current</td><td>22</td><td>19</td><td>—</td></tr><tr><td>Restricted cash and cash equivalents-non-current</td><td>407</td><td>328</td><td>567</td></tr><tr><td></td><td>$ 105,606</td><td>$ 53,613</td><td>$ 21,559</td></tr><tr><td>Supplemental cash flow information:</td><td></td><td></td><td></td></tr><tr><td>Cash paid for interest (net of amounts capitalized)</td><td>3,463</td><td>3,787</td><td>4,184</td></tr><tr><td>Cash paid (refunded) for income taxes</td><td>696</td><td>280</td><td>(454)</td></tr></table>

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



# MONTAUK RENEWABLES, INC.

# NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

## NOTE 1—DESCRIPTION OF BUSINESS

## Operations and organization

Montauk Renewables' Business

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

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

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

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

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

## Background and Reorganization Transactions

On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by Montauk USA, and Montauk Renewables became a direct wholly-owned subsidiary of MNK. Prior to the Reorganization Transactions, MNK’s business and operations were conducted entirely through Montauk USA.



and its U.S. subsidiaries, and MNK held no substantial assets other than equity of Montauk USA. The Company had no significant operations or assets prior to January 4, 2021 when it engaged in the equity exchange with Montauk USA and MNK.

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

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

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

On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (as amended on February 22, 2021, December 22, 2021 and December 22, 2022) with MNK pursuant to which the Company advanced a cash loan to MNK for MNK to pay its dividends tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended. The terms of the loan following the amendments are substantially similar to the initial loan agreement and were primarily entered into to increase the principal amount outstanding under the loan to $8,940 in the aggregate, in accordance with Montauk Renewables’ obligations set forth in the Transaction Implementation Agreement. MNK is currently an affiliate of the Company and certain of the Company’s directors and executive officers are also directors and executive officers of MNK. See Note 17 for more information.

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

## NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

## Principles of Consolidation

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

## Retrospective Presentation of Ownership Related to the Reorganization Transactions

As discussed in Note 1, as a result of the Reorganization Transactions, the Company acquired the assets and entities (excluding Montauk USA) which were previously owned by MNK. As part of the Reorganization Transactions, a 1:1 pro rata distribution of shares of the Company’s common stock was made to holders of MNK’s ordinary shares. The Reorganization Transactions resulted in a pro rata distribution whereby the ownership of the Company after the Reorganization Transactions was identical to the ownership of MNK prior to



the Reorganization Transaction and was therefore akin to a common control transaction. All member’s equity in the financial statements and notes have been retrospectively adjusted to give effect to the Distribution, as if such pro rata distribution on a 1:1 basis occurred as of all pre-IPO periods presented, including periods presented on the Consolidated Balance Sheets, Consolidated Statements of Operations, Consolidated Statements of Stockholders’ and Member’s Equity and notes to the Consolidated Financial Statements contained herein.

## Segment Reporting

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

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

The Renewable Electricity Generation segment represents the sale of captured electricity and applicable Environmental Attributes. Corporate & Other relates to additional discrete financial information for the corporate function. It is primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering and other operations functions not otherwise allocated to a segment. As such, the corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.

## Use of Estimates

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

## Cash, Cash Equivalents and Restricted Cash

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

## Accounts and Other Receivables

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

## Property, Plant and Equipment

Property, plant and equipment purchases are stated at cost. Depreciation and amortization are based on costs less estimated salvage values, primarily using the straight-line method over the estimated useful lives or, if



applicable, the term of the related gas rights agreements or power purchase agreements, whichever is shorter. Maintenance and repairs are expensed as incurred. Major improvements that extend the useful lives of property are capitalized.

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

<table><tr><td>Buildings and improvements</td><td>5 - 30 years</td></tr><tr><td>Machinery and equipment</td><td>1 - 43 years</td></tr><tr><td>Gas mineral rights</td><td>15 - 25 years</td></tr></table>

$313 and $332 in insurance proceeds were received for the years ended December 31, 2022 and 2021, respectively, related to an engine failure at an RNG Facility. $3,934 was also received in 2020 for the same engine failure, of which $1,659 was related to the replacement of property and $2,275 was for the related business interruption. These insurance proceeds are included in Gain on insurance proceeds for the years ended December 31, 2022, 2021 and 2020, respectively within the Consolidated Statements of Operations.

## Goodwill and Intangible Assets

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

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

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

<table><tr><td>Interconnection</td><td>10 - 25 years</td></tr><tr><td>Customer contracts</td><td>2 - 15 years</td></tr><tr><td>Emissions allowances</td><td>Indefinite</td></tr><tr><td>Land use rights</td><td>Indefinite</td></tr></table>

## Assets Held for Sale

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

## Leases

The Company assesses leases in accordance with ASU 2016-02, Leases, (“ASU 2016-02”). This ASU requires lessees to recognize a right-of-use asset and lease liability on the Consolidated Balance Sheet for leases



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

## Long-lived Asset Impairment

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

A summary of impairment losses on tangible and intangible assets for the year ended December 31, 2022, 2021 and 2020 is included in Note 3.

## Indefinite-Lived Asset Impairment

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

## Asset Retirement Obligations

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

## Revenue

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



## Income Taxes

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

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

## Derivative Instruments

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

## Fair Value of Financial Instruments

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

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

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

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

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

The Company’s gas hedges are valued based on the observable market price of the commodity hedged and are considered a Level 1 measurement. The values of the Level 2 interest rate derivatives were determined using a model, which incorporates market inputs including the implied forward interest rate yield curve for the same period as the future interest rate swap settlement. The Company has also considered both its own credit risk and counterparty credit risk in determining fair value and determined these adjustments were insignificant for the years ended December 31, 2022 and 2021. The Company’s asset retirement obligations are recorded at fair value.



at the time the liability is incurred if a reasonable estimate of fair value can be made. Fair value is determined by calculating the estimated present value of the cost to retire the asset as determined by qualified engineers, based on currently available information and inflation estimates and is considered a Level 3 measurement. The Company’s earn-out liability fair value is determined by calculating the estimated present value of future obligations based on currently available information and the discount factor used and is considered a Level 3 measurement.

A summary of changes in the fair values of the Company’s Level 3 instruments, attributable to asset retirement obligations and the earn out liability, for the years ended December 31, 2022 and 2021 is included in Note 11.

## Renewable Identification Numbers (“RINs”)

The Company generates D3 RINs through its production and sale of RNG used for transportation purposes as prescribed under the Federal Renewable Fuel Standard. The RINs that the Company generates as government incentives through its renewable operating projects can be separated and sold as credits independent from the energy produced and not a result of physical attributes of the Company’s production. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The Company had 0.7 and 0.1 million RINs generated and unsold as of December 31, 2022 and 2021, respectively.

## Renewable Energy Credits (“RECs”)

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

## Equity-Based Compensation

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

## Employee Benefits

## Leave entitlement

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



## Bonus Plans

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

## Recently Adopted Accounting Standards

In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The new guidance which simplifies the accounting for income taxes, eliminates certain exceptions with ASC 740 and clarifies certain aspects of the current guidance to promote consistency among reporting entities. The new standard is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company early adopted this guidance on January 1, 2020 prospectively, and it did not have a material impact on our consolidated financial statements.

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

## Recently Issued Accounting Standards

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

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848), which provides optional expedients and exceptions to the current guidance on contract modifications and hedging relationships to ease the financial reporting burdens of the expected market transition from London Interbank Offered Rate (“LIBOR”) and other interbank offered rates to alternative reference rates. The guidance was effective upon issuance and may be applied prospectively to contract modifications made and hedging relationships entered into or evaluated on or before December 31, 2022. The FASB included a sunset provision within Topic 848 based on expectations of when the LIBOR would cease being published. The sunset provision has been amended from December 31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. The Company’s current debt agreement bears interest at the Bloomberg Short-Term Bank Yield Index Rate plus an applicable margin. LIBOR is no longer utilized as a reference rate.

## NOTE 3—ASSET IMPAIRMENT

The Company recorded $4,852, $1,191 and $278 in impairment losses for the years ended December 31, 2022, 2021 and 2020, respectively. The 2022 impairments included $2,133 for a REG site wherein the forecasted future cash flows did not exceed the carrying value of the site’s long lived assets. A second REG site was impaired for $1,393 due to a discrete conclusion that certain assets acquired in the May 2021 Asset acquisition



would no longer be utilized by the Company. More information on the Asset acquisition can be found in Note 7. An RNG site was impaired for $1,108 due to the specific identification of certain assets no longer capable of being used as designed. Additional impairments were recorded for computer software and hardware no longer being utilized ($191) and an amended customer contract ($27) no longer in use. The 2021 impairment loss of $1,191 was due to the closure of two REG Sites and also the disposal of machinery at one RNG site. The Company recorded an impairment loss of $278 for the year ended December 31, 2020 in the Renewable Electricity Generation segment. The impairment loss was due to a termination of a development agreement related to the acquisition of Pico Energy, LLC (“Pico”).

Impairment loss was recorded under Operating expenses within the Consolidated Statements of Operations for the years ended December 31, 2022, 2021, and 2020.

## NOTE 4—REVENUES FROM CONTRACTS WITH CUSTOMERS

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

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

The Company’s performance obligations related to the sale of renewable energy (i.e. RNG and Renewable Electricity) are generally satisfied over time. Revenue related to the sale of renewable energy is generally recognized over time using an output based upon the product quantity delivered to the customer. This measure is used to best depict the Company’s performance to date under the terms of the contract. Revenue from products transferred to customers over time accounted for approximately 29%, 28% and 32% of revenue for the years ended December 31, 2022, 2021 and 2020, respectively.

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

The Company’s performance obligations related to the sale of Environmental Attributes are generally satisfied at a point in time and were approximately 71%, 72% and 68% of revenue for the years ended December 31, 2022, 2021 and 2020, respectively. The Company recognizes Environmental Attribute revenue at the point in time in which the customer obtains control of the Environmental Attributes, which is generally when the title of the Environmental Attribute passes to the customer upon delivery. In limited cases, title does not transfer to the customer and revenue is not recognized until the customer has accepted the Environmental Attributes. The Company’s performance obligations under its counterparty sharing agreements are generally satisfied at a point in time when the earnings process is completed by the counterparty. Counterparty sharing arrangement revenues were approximately 1%, 10%, and 6% of revenue for the years ended December 31, 2022, 2021, and 2020, respectively.



The following tables display the Company’s revenue by major source, excluding realized and unrealized gains or losses under the Company’s gas hedge program, based on product type and timing of transfer of goods and services for the years ended December 31, 2022, 2021 and 2020:

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31, 2022</td></tr><tr><td>Goods transferred at a point in time</td><td>Goods Transferred over time</td><td>Total</td></tr><tr><td>Major Goods/Service Line:</td><td></td><td></td><td></td></tr><tr><td>Natural Gas Commodity</td><td>$ 2,053</td><td>$50,845</td><td>$ 52,898</td></tr><tr><td>Natural Gas Environmental Attributes</td><td>143,025</td><td>—</td><td>143,025</td></tr><tr><td>Electric Commodity</td><td>—</td><td>10,449</td><td>10,449</td></tr><tr><td>Electric Environmental Attributes</td><td>7,016</td><td>—</td><td>7,016</td></tr><tr><td></td><td>$152,094</td><td>$61,294</td><td>$213,388</td></tr><tr><td>Operating Segment:</td><td></td><td></td><td></td></tr><tr><td>RNG</td><td>$145,078</td><td>$50,845</td><td>$195,923</td></tr><tr><td>REG</td><td>7,016</td><td>10,449</td><td>17,465</td></tr><tr><td></td><td>$152,094</td><td>$61,294</td><td>$213,388</td></tr><tr><td></td><td colspan="3">Year Ended December 31, 2021</td></tr><tr><td></td><td>Goods transferred at a point in time</td><td>Goods Transferred over time</td><td>Total</td></tr><tr><td>Major Goods/Service Line:</td><td></td><td></td><td></td></tr><tr><td>Natural Gas Commodity</td><td>$ 15,178</td><td>$32,143</td><td>$ 47,321</td></tr><tr><td>Natural Gas Environmental Attributes</td><td>84,906</td><td>—</td><td>84,906</td></tr><tr><td>Electric Commodity</td><td>—</td><td>9,692</td><td>9,692</td></tr><tr><td>Electric Environmental Attributes</td><td>6,208</td><td>—</td><td>6,208</td></tr><tr><td></td><td>$106,292</td><td>$41,835</td><td>$148,127</td></tr><tr><td>Operating Segment:</td><td></td><td></td><td></td></tr><tr><td>RNG</td><td>$100,084</td><td>$32,143</td><td>$132,227</td></tr><tr><td>REG</td><td>6,208</td><td>9,692</td><td>15,900</td></tr><tr><td></td><td>$106,292</td><td>$41,835</td><td>$148,127</td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31, 2020</td></tr><tr><td>Goods transferred at a point in time</td><td>Goods transferred over time</td><td>Total</td></tr><tr><td>Major Goods/Service Line:</td><td></td><td></td><td></td></tr><tr><td>Natural Gas Commodity</td><td>$ 6,991</td><td>$22,467</td><td>$ 29,458</td></tr><tr><td>Natural Gas Environmental Attributes</td><td>54,098</td><td>—</td><td>54,098</td></tr><tr><td>Electric Commodity</td><td>—</td><td>9,642</td><td>9,642</td></tr><tr><td>Electric Environmental Attributes</td><td>7,023</td><td>—</td><td>7,023</td></tr><tr><td></td><td>$68,112</td><td>$32,109</td><td>$100,221</td></tr><tr><td>Operating Segment:</td><td></td><td></td><td></td></tr><tr><td>RNG</td><td>$61,089</td><td>$22,467</td><td>$ 83,556</td></tr><tr><td>REG</td><td>7,023</td><td>9,642</td><td>16,665</td></tr><tr><td></td><td>$68,112</td><td>$32,109</td><td>$100,221</td></tr></table>

## Practical expedients

The Company elected to recognize the sale of the gas and electric commodities using the right to invoice practical expedient. The Company determined that the amounts invoiced to customers correspond directly with the value to customers and the Company’s satisfaction of the performance obligations to date. Furthermore, with the election of the right to invoice practical expedient, the Company also elects to omit disclosures on the remaining, or unsatisfied performance obligations since the revenue recognized corresponds to the amount that the Company has the right to invoice.

## NOTE 5—ACCOUNTS AND OTHER RECEIVABLES

The Company extends credit based upon an evaluation of the customer’s financial condition. Credit terms are consistent with industry standards and practices. Reserves for uncollectible accounts, if any, are recorded as part of general and administrative expenses in the Consolidated Statements of Operations. No reserve expense was recorded for the years ended December 31, 2022, 2021 and 2020.

Accounts and other receivables consist of the following as of December 31, 2022 and 2021:

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Accounts receivables</td><td>$7,148</td><td>$9,281</td></tr><tr><td>Other receivables</td><td>57</td><td>26</td></tr><tr><td>Reimbursable expenses</td><td>17</td><td>31</td></tr><tr><td>Accounts and other receivables</td><td>$7,222</td><td>$9,338</td></tr></table>

## NOTE 6—ASSETS HELD FOR SALE

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



## NOTE 7—PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment consists of the following as of December 31, 2022 and 2021:

<table><tr><td rowspan="2"></td><td colspan="2">Year Ended December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Land</td><td>$ 595</td><td>$ 595</td></tr><tr><td>Buildings and improvements</td><td>29,268</td><td>28,693</td></tr><tr><td>Machinery and equipment</td><td>247,631</td><td>246,670</td></tr><tr><td>Gas mineral rights</td><td>34,526</td><td>34,551</td></tr><tr><td>Construction work in progress</td><td>20,745</td><td>12,725</td></tr><tr><td>Total</td><td>$ 332,765</td><td>$ 323,234</td></tr><tr><td>Less: Accumulated depreciation and amortization</td><td>(156,819)</td><td>(142,341)</td></tr><tr><td>Property, plant &amp; equipment, net</td><td>$ 175,946</td><td>$ 180,893</td></tr></table>

Depreciation expense for property plant and equipment was $19,251, $19,617 and $18,679 and amortization expense for gas mineral rights was $515, $1,828 and $1,965 for the years ended December 31, 2022, 2021 and 2020, respectively.

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

In May 2021, the Company completed a series of transactions (the “Asset acquisition”) with a privately-held entity. The Company paid $4,142, including $341 in acquisition costs, for land, building, mobile equipment and other property, plant and equipment for the Montauk Ag Renewables Acquisition. In October 2021, the Company completed a separate purchase with an unrelated privately-held entity. The Company paid $5,531, including $31 in acquisition costs, for land, land improvements and a building. $1,393 of the assets originally acquired in the May 2021 Asset acquisition have been impaired for the year ended December 31, 2022, as mentioned above and also in Note 3. The Asset acquisitions were accounted for as an asset purchase in accordance with ASC 805, Business combinations, and the purchase price and direct transaction costs have been allocated to the individual assets obtained.



## NOTE 8—GOODWILL AND INTANGIBLE ASSETS, NET

Intangible assets consist of the following as of December 31, 2022 and December 31, 2021:

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td></td></tr><tr><td>Goodwill</td><td>$ 60</td><td>$ 60</td><td></td></tr><tr><td>Intangible assets with indefinite lives:</td><td></td><td></td><td></td></tr><tr><td>Land use rights</td><td>329</td><td>329</td><td></td></tr><tr><td>Total intangible assets with indefinite lives:</td><td>$ 329</td><td>$ 329</td><td></td></tr><tr><td>Intangible assets with finite lives:</td><td></td><td></td><td></td></tr><tr><td>Interconnection, net of accumulated amortization of $3,107 and $3,034</td><td>$11,686</td><td>$12,526</td><td></td></tr><tr><td>Customer contracts, net of accumulated amortization of $17,022 and $17,085</td><td>3,680</td><td>1,198</td><td></td></tr><tr><td>Total intangible assets with finite lives:</td><td>$15,366</td><td>$13,724</td><td></td></tr><tr><td>Total Goodwill and Intangible assets</td><td>$15,755</td><td>$14,113</td><td></td></tr></table>

The weighted average remaining useful life of the customer contracts and interconnection is approximately 16 years for both intangible asset categories. Amortization expense was $887, $1,424 and $1,473 for the years ended December 31, 2022, 2021 and 2020, respectively. Impairments related to intangibles totaled $71 for the year ended December 31, 2022, which included $44 related to one REG site discussed in Note 7 and $27 related to an RNG site associated with the early termination of a customer contract.

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

<table><tr><td></td><td>Customer Contracts</td><td>Inter-Connections</td></tr><tr><td>Year Ending</td><td></td><td></td></tr><tr><td>2023</td><td>$ 232</td><td>$ 740</td></tr><tr><td>2024</td><td>231</td><td>740</td></tr><tr><td>2025</td><td>230</td><td>740</td></tr><tr><td>2026</td><td>230</td><td>740</td></tr><tr><td>2027</td><td>230</td><td>740</td></tr><tr><td>Thereafter</td><td>2,527</td><td>7,986</td></tr></table>

## NOTE 9—ASSET RETIREMENT OBLIGATIONS

The following table summarizes the activity associated with asset retirement obligations of the Company for the years ended December 31, 2022, 2021, and 2020:

<table><tr><td rowspan="2"></td><td colspan="3">Year ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td></tr><tr><td>Asset retirement obligations—beginning of year</td><td>$5,301</td><td>$5,689</td><td>$5,928</td></tr><tr><td>Accretion expense</td><td>296</td><td>(160)</td><td>320</td></tr><tr><td>New asset retirement obligations</td><td>—</td><td>—</td><td>350</td></tr><tr><td>Decommissioning</td><td>(104)</td><td>(228)</td><td>(909)</td></tr><tr><td>Asset retirement obligations—end of year</td><td>$5,493</td><td>$5,301</td><td>$5,689</td></tr></table>



## NOTE 10—DERIVATIVE INSTRUMENTS

To mitigate market risk associated with fluctuations in energy commodity prices (natural gas) and interest rates, the Company utilizes various hedges to secure energy commodity pricing and interest rates under a board-approved program. As a result of the hedging strategy employed, the Company had the following realized and unrealized gains and losses in the Consolidated Statements of Operations for the years ended December 31, 2022, 2021, and 2020:

<table><tr><td rowspan="2">Derivative Instrument</td><td rowspan="2">Location</td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td></tr><tr><td>Commodity contracts:</td><td></td><td></td><td></td><td></td></tr><tr><td>Realized natural gas</td><td>Operating revenue</td><td>$ (7,829)</td><td>$ —</td><td>$ 551</td></tr><tr><td>Unrealized natural gas</td><td>Operating revenue</td><td>—</td><td>—</td><td>(388)</td></tr><tr><td>Interest rate swaps</td><td>Interest expense</td><td>2,652</td><td>1,422</td><td>(628)</td></tr><tr><td>Net (loss) gain</td><td></td><td>$ (5,177)</td><td>$1,422</td><td>$ (465)</td></tr></table>

## NOTE 11—FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company’s assets and liabilities that are measured at fair value on a recurring basis include the following as of December 31, 2022 and 2021, set forth by level, within the fair value hierarchy:

<table><tr><td rowspan="2"></td><td colspan="4">December 31, 2022</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td>Interest rate swap derivative asset</td><td>$—</td><td>$1,815</td><td>$ —</td><td>$ 1,815</td></tr><tr><td>Asset retirement obligations</td><td>—</td><td>—</td><td>(5,493)</td><td>(5,493)</td></tr><tr><td>Pico earn-out liability</td><td>—</td><td>—</td><td>(3,843)</td><td>(3,843)</td></tr><tr><td></td><td>$—</td><td>$1,815</td><td>$(9,336)</td><td>$(7,521)</td></tr><tr><td></td><td colspan="4">December 31, 2021</td></tr><tr><td></td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td></tr><tr><td>Interest rate swap derivative liability</td><td>$—</td><td>$ (839)</td><td>$ —</td><td>$ (839)</td></tr><tr><td>Asset retirement obligations</td><td>—</td><td>—</td><td>(5,301)</td><td>(5,301)</td></tr><tr><td>Pico earn-out liability</td><td>—</td><td>—</td><td>(2,721)</td><td>(2,721)</td></tr><tr><td></td><td>$—</td><td>$ (839)</td><td>$(8,022)</td><td>$(8,861)</td></tr></table>

A summary of changes in the fair values of the Company’s Level 3 instruments, attributable to asset retirement obligations, for the years ended December 31, 2022 and 2021 is included in Note 9.

In addition, certain assets are measured at fair value on a non-recurring basis when an indicator of impairment is identified and the assets fair value is determined to be less than its carrying value. See Note 3 for additional information.



## NOTE 12—ACCRUED LIABILITIES

The Company’s accrued liabilities consists of the following as of December 31, 2022 and December 31, 2021:

<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Accrued expenses</td><td>$ 3,221</td><td>$ 3,551</td></tr><tr><td>Payroll and related benefits</td><td>1,561</td><td>1,239</td></tr><tr><td>Royalty</td><td>7,836</td><td>4,630</td></tr><tr><td>Utility</td><td>1,605</td><td>1,274</td></tr><tr><td>Other</td><td>867</td><td>129</td></tr><tr><td>Accrued liabilities</td><td>$15,090</td><td>$10,823</td></tr></table>

## NOTE 13—DEBT

The Company’s debt consists of the following as of December 31, 2022 and December 31, 2021:

<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Term loans</td><td>$72,000</td><td>$80,000</td></tr><tr><td>Revolving credit facility</td><td>—</td><td>—</td></tr><tr><td>Less: current principal maturities</td><td>(8,000)</td><td>(8,000)</td></tr><tr><td>Less: debt issuance costs (on long-term debt)</td><td>(495)</td><td>(608)</td></tr><tr><td>Long-term debt</td><td>$63,505</td><td>$71,392</td></tr><tr><td>Current portion of long-term debt</td><td>7,870</td><td>7,815</td></tr><tr><td></td><td>$71,375</td><td>$79,207</td></tr></table>

## Amended Credit Agreement

On December 12, 2018, Montauk Energy Holdings LLC (“MEH”) entered into the Second Amended and Restated Revolving Credit and Term Loan Agreement (as amended, “Credit Agreement”), by and among MEH, the financial institutions from time to time party thereto as lenders and Comerica Bank, as the administrative agent, sole lead arranger and sole bookrunner (“Comerica”). The Credit Agreement (i) amended and restated in its entirety MEH’s prior revolving credit and term loan facility, dated as of August 4, 2017, as amended, with Comerica and certain other financial institutions and (ii) replaced in its entirety the prior credit agreement, dated as of August 4, 2017, as amended, between Comerica and Bowerman Power LFG, LLC, a wholly-owned subsidiary of MEH.

On March 21, 2019, MEH entered into the first amendment to the Credit Agreement (the “First Amendment”), which clarified a variety of terms, definitions and calculations in the Credit Agreement. The Credit Agreement requires the Company to maintain customary affirmative and negative covenants, including certain financial covenants, which are measured at the end of each fiscal quarter.

On August 28, 2019, the Company received a temporary waiver for an anticipated Event of Default (as defined in the Credit Agreement) for the consecutive three-month period ended on August 31, 2019 (the “Specified Event of Default”). The Specified Event of Default was waived through October 1, 2019. On September 12, 2019, the Company entered into the Second Amendment. Among other matters, the Second Amendment redefined the Fixed Charge Coverage Ratio (as defined in the Credit Agreement), reduced the



commitments under the revolving credit facility to $80,000, redefined the Total Leverage Ratio (as defined in the Credit Agreement) and eliminated the RIN Floor (as defined in the Second Amendment) as an Event of Default. In connection with the Second Amendment, the Company paid down the outstanding term loan by $38,250 and the resulting quarterly principal installments were reduced to $2,500.

In connection with the completion of the Reorganization Transactions and the IPO, the Company entered into the third amendment to the Credit Agreement (the “Third Amendment”). This amendment permitted the Change of Control provisions, as defined in the underlying agreement, to permit the Reorganization Transactions and IPO to be completed.

On December 21, 2021, MEH entered into the Fourth Amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement. The current credit agreement, which is secured by a lien on substantially all assets of the Company and certain of its subsidiaries, provides for a $80,000 term loan and a $120,000 revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through 2024, then increases to $3,000 from 2025 to 2026 with a final payment of $32,000 in late 2026.

As of December 31, 2022, $72,000 was outstanding under the term loan. In addition, the Company had $3,905 of outstanding letters of credit as of December 31, 2022. Amounts available under the revolving credit facility are reduced by any amounts outstanding under letters of credit. As of December 31, 2022, the Company’s capacity available for borrowing under the revolving credit facility was $116,095. Borrowings of the term loan and revolving credit facility bear interest at the Bloomberg Short-Term Bank Yield Index Rate plus an applicable margin. Interest rates as of December 31, 2022 and 2021 were 4.12% and 2.91%, respectively.

The Company accounted for the Fourth amendment as both a debt modification and debt extinguishment in accordance with ASC 470, Debt (“ASC 470”). In connection with the Credit Agreement, the Company paid $2,027 in fees. Of this amount, $326 was expensed and $1,701 was capitalized and will be amortized over the life of the Credit Agreement. Amortized debt issuance expense in the amount of $412, $483 and $695 for the years ended December 31, 2022, 2021 and 2020, respectively, was recorded in interest expense on the Statement of Operations.

As of December 31, 2022, the Company was in compliance with all financial covenants related to the Credit Agreement.

## Annual Maturities of Long-Term Debt

The following is a summary of annual principal maturities of long-term debt as of December 31, 2022:

<table><tr><td>Year Ending</td><td>Amount</td></tr><tr><td>2023</td><td>$ 8,000</td></tr><tr><td>2024</td><td>8,000</td></tr><tr><td>2025</td><td>12,000</td></tr><tr><td>2026</td><td>44,000</td></tr><tr><td>Total</td><td>$72,000</td></tr></table>

## NOTE 14—INCOME TAXES

The Company is 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.



On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act (the “CARES Act”) was signed into law. The CARES Act contains several corporate income tax provisions which include the (i) temporary removal of the 80% taxable income limitation on utilization of Net Operating Losses (NOLs) generated before 2021, and (ii) temporarily liberalizing the interest deductions rules under IRC Sec. 163(j) of the Tax Act raising the adjusted taxable income limitation from 30% to 50%, among others. Additionally, on December 27, 2020, the Consolidated Appropriations Act, 2021 (the “Appropriations Act”) was signed into law. Neither the CARES Act nor the Appropriations Act had a material impact on the Company’s financial statements for the years ending December 2022, 2021 and 2020.

On March 11, 2021, the American Rescue Plan Act of 2021 (“ARPA”) was signed into law. The ARPA contains several corporate income tax provisions which include (i) extending the $1 million limitation on deductions for compensation paid to executives of publicly traded corporations to include compensation paid to the eight highest paid individuals (rather than three highest), plus the chief executive officer and the chief financial officer (effective for tax years after 2026), and (ii) extending the period for which companies may claim an employee retention credit. The ARPA did not have a material impact on the Company’s financial statements for the years ending December 31, 2022 and 2021.

The following table details the components of the Company’s income tax provision (benefit) for the years ended December 31, 2022, December 31, 2021 and December 31, 2020:

<table><tr><td rowspan="2"></td><td colspan="3">Year Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td></tr><tr><td>Current expense (benefit):</td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>$ 321</td><td>$ —</td><td>$ —</td></tr><tr><td>State</td><td>1,109</td><td>(91)</td><td>81</td></tr><tr><td></td><td>$1,430</td><td>$ (91)</td><td>$ 81</td></tr><tr><td>Deferred expense (benefit):</td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>$6,446</td><td>$3,368</td><td>$(5,358)</td></tr><tr><td>State</td><td>172</td><td>884</td><td>(719)</td></tr><tr><td></td><td>$6,618</td><td>$4,252</td><td>$(6,077)</td></tr><tr><td>Income Tax Expense (Benefit)</td><td>$8,048</td><td>$4,161</td><td>$ (5,996)</td></tr></table>



The following table illustrates the deferred tax assets and liabilities as of December 31, 2022 and December 31, 2021:

<table><tr><td rowspan="2"></td><td colspan="2">Year ended December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Deferred tax assets:</td><td></td><td></td></tr><tr><td>Net operating loss carry forwards</td><td>$ 6,744</td><td>$ 17,180</td></tr><tr><td>Federal tax credits</td><td>13,691</td><td>12,606</td></tr><tr><td>Book reserves</td><td>1,368</td><td>1,353</td></tr><tr><td>Intangible asset amortization</td><td>6,701</td><td>7,553</td></tr><tr><td>Stock compensation</td><td>1,087</td><td>—</td></tr><tr><td>Other</td><td>—</td><td>230</td></tr><tr><td>Total Deferred Tax Assets</td><td>29,591</td><td>38,922</td></tr><tr><td>Less: valuation allowance</td><td>(3,950)</td><td>(3,900)</td></tr><tr><td>Net deferred tax assets</td><td>$ 25,641</td><td>$ 35,022</td></tr><tr><td>Deferred tax liabilities:</td><td></td><td></td></tr><tr><td>Property depreciation</td><td>$ (21,683)</td><td>$ (23,516)</td></tr><tr><td>Stock compensation</td><td>—</td><td>(936)</td></tr><tr><td>Other</td><td>(6)</td><td>—</td></tr><tr><td>Total deferred tax liabilities</td><td>(21,689)</td><td>(24,452)</td></tr><tr><td>Net Deferred tax assets</td><td>$ 3,952</td><td>$ 10,570</td></tr></table>

As of December 31, 2022, the Company has federal net operating loss (“NOL”) carryforwards of $12,146, which are limited to 80% of taxable income. In 2022, the Company utilized all of its non-limited NOLs.

On January 1, 2020, the minority investor of MEC, Johnstonw LFG Holdings, Inc. (via assignment of shares from MEC on December 9, 2019), was bought out by MEH, converting MEC from a partnership to a disregarded entity for U.S. federal income tax purposes, and which is currently wholly owned by MEH. This change in tax status resulted in a tax benefit of $2,417 in 2020. This transaction allowed Monmouth Energy Inc., a subsidiary of MEC, to file as part of our consolidated federal tax group.

The Company has $13,691 of federal tax credit carryforwards that expire 20 years from the date incurred, which begin to expire in tax year 2026.

The Company has pre-tax state net operating loss carryforwards of $17,994 which will begin to expire in tax year 2026.



The following table details the components of the Company’s income tax provision (benefit) for the years ended December 31, 2022, 2021 and 2020:

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Tax provision at federal statutory rate of 21%</td><td>$ 9,081</td><td>$ (77)</td><td>$ (293)</td><td></td></tr><tr><td>State tax provision</td><td>998</td><td>800</td><td>(50)</td><td></td></tr><tr><td>Permanent differences</td><td>15</td><td>79</td><td>—</td><td></td></tr><tr><td>Stock compensation</td><td>(24)</td><td>723</td><td>—</td><td></td></tr><tr><td>162(m) compensation limitation</td><td>—</td><td>4,382</td><td>—</td><td></td></tr><tr><td>Valuation allowance</td><td>50</td><td>12</td><td>(286)</td><td></td></tr><tr><td>Production tax credit</td><td>(2,052)</td><td>(2,112)</td><td>(2,036)</td><td></td></tr><tr><td>Return to provision</td><td>(20)</td><td>(29)</td><td>(34)</td><td></td></tr><tr><td>Impact of MEC partnership dissolution</td><td>—</td><td>—</td><td>(2,417)</td><td></td></tr><tr><td>Deferred tax adjustments</td><td>—</td><td>383</td><td>(908)</td><td></td></tr><tr><td>Other</td><td>—</td><td>—</td><td>28</td><td></td></tr><tr><td>Total Income Tax Expense (Benefit)</td><td>$ 8,048</td><td>$ 4,161</td><td>$ (5,996)</td><td></td></tr></table>

As of December 31, 2022, the tax years 2018, 2019 and 2020 are subject to examination by the IRS.

## Valuation Allowance

The Company annually reviews its deferred tax assets for the possibility they will not be realized. A valuation allowance will be recorded if it is determined more than a 50% likelihood exists that a deferred tax asset will not be realized. A $3,950 valuation allowance exists, which represents the Company’s deferred tax assets that are not expected to be realized. This represents a $50 increase in the valuation allowance from $3,900 at the year ended December 31, 2021.

## Uncertain Tax Position

The calculation of the Company’s tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in both federal and state jurisdictions. ASC 740 states that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, on the basis of each situation’s technical merits.

At this point in time the Company is not aware of any tax positions taken that would give rise to recording an uncertain tax position. As such, the Company has not recorded any liability for unrecognized tax benefits as of December 31, 2022 or 2021. The Company records interest and penalties as a component of income tax expense. However, as there are no unrecognized tax benefits for the years ended December 31, 2022 and December 31, 2021, the Company has zero penalties or interest accrued at December 31, 2022 and 2021, respectively.

## NOTE 15—SHARE-BASED COMPENSATION

In January 2021, Montauk Renewables undertook the Reorganization Transactions which resulted in the Company owning all of the assets and entities (excluding Montauk USA) through which MNK’s business and operations were conducted. As a result of the Distribution, the options outstanding under MNK’s Employee Share Appreciation Rights Scheme (the “SAR Plan”) were cancelled. The Company recorded $2,050 of accelerated compensation expense in its consolidated statements of operations within general and administrative expenses in connection with the cancellation of the options under the SAR Plan for the year ended December 31, 2021.



The board of directors of Montauk Renewables adopted the Montauk Renewables, Inc. Equity and Incentive Compensation Plan (“MRI EICP”) in January 2021. Following the closing of the IPO, the board of directors of Montauk Renewables approved the grant of non-qualified stock options, restricted stock unit and restricted stock awards to the employees of Montauk Renewables and its subsidiaries in January 2021. In connection with the restricted stock grants the officers of the Company made elections under Section 83(b) of the Code. Pursuant to such elections, the Company withheld 950,214 shares of common stock from such awards at a price of $11.38 per share from such awards. The Company records and reports restricted shares and restricted stock units when vested and in the case of options, when such awards are settled in the Company’s common stock. As of December 31, 2022, unrecognized MRI EICP compensation expense for awards the Company expects to vest approximated $17,921 and will be recognized over approximately 4 years.

In connection with a May 2021 asset acquisition, 1,250,000 restricted stock awards (“RS Awards”) were granted to two employees that were hired by the Company in connection with such acquisition. The RS Awards were to vest over a five-year period and subject to the achievement of time and performance-based vesting criteria over such period. In May 2022, the RS Awards were amended to remove the performance-based vesting criteria and will only be subject to time-based vesting requirements over a five-year period. The awards were revalued at $15,500. Stock compensation expense related to the two awards was $2,863 for the year ended December 31, 2022.

The restricted stock, restricted stock units and option awards are subject to vesting schedules that commence or conclude, in the case of the option and restricted stock unit awards, on the one-year anniversary of the grant date and are subject to the terms and conditions of the MRI EICP and related award agreements including, in the case of the restricted stock awards, each officer having made an election under Section 83(b) of the Code. The Company recorded $10,813 of compensation expense in its consolidated statements of operations within general and administrative expenses for the year ended December 31, 2021 in connection with the withheld 950,214 shares associated with the Section 83(b) elections.

Options granted under the MRI EICP allow the recipient to receive the Company’s common stock equal to the appreciation in the fair market value of the Company’s common stock between the grant date and the exercise and settlement of options into shares as of the exercise date(s). The fair value of the MRI EICP options was estimated using the Black-Scholes option pricing model with the following weighted-average assumptions (no dividends were expected):

<table><tr><td></td><td>Grant Date</td></tr><tr><td>Risk-free interest rate</td><td>0.5%</td></tr><tr><td>Expected volatility</td><td>32.0%</td></tr><tr><td>Expected option life (in years)</td><td>5.5</td></tr><tr><td>Grant-date fair value</td><td>$3.44</td></tr></table>



The following table summarizes the restricted shares, restricted stock units and options outstanding under the MRI EICP as of December 31, 2022:

<table><tr><td rowspan="2"></td><td colspan="2">Restricted Shares</td><td colspan="2">Restricted Stock Units</td><td colspan="2">Options</td></tr><tr><td>Number of Shares</td><td>Weighted Average Grant Date Fair Value</td><td>Number of Shares</td><td>Weighted Average Grant Date Fair Value</td><td>Number of Shares</td><td>Number of Exercise Price</td></tr><tr><td>End of period—December 31, 2020</td><td>—</td><td>$ —</td><td>—</td><td>$ —</td><td>—</td><td>$ —</td></tr><tr><td>Beginning of period—January 1, 2021</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Granted</td><td>3,519,827</td><td>10.43</td><td>379,304</td><td>10.23</td><td>950,214</td><td>11.38</td></tr><tr><td>Vested</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Forfeited</td><td>(950,214)</td><td>11.38</td><td>(1,320)</td><td>11.38</td><td>—</td><td>—</td></tr><tr><td>End of period—December 31, 2021</td><td>2,569,613</td><td>$10.08</td><td>377,984</td><td>$10.23</td><td>950,214</td><td>$11.38</td></tr><tr><td>Beginning of period—January 1, 2022</td><td>2,569,613</td><td>$10.08</td><td>377,984</td><td>$10.23</td><td>950,214</td><td>$11.38</td></tr><tr><td>Granted</td><td>1,250,000</td><td>12.40</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Vested</td><td>(541,312)</td><td>11.38</td><td>(97,984)</td><td>10.49</td><td>(950,214)</td><td>11.38</td></tr><tr><td>Forfeited</td><td>(1,250,000)</td><td>9.04</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>End of period—December 31, 2022</td><td>2,028,301</td><td>$11.80</td><td>280,000</td><td>$10.13</td><td>—</td><td>$ —</td></tr></table>

Stock-based compensation expense for the years ended December 31, 2022, 2021, and 2020 was $9,842, $9,474 and $762, respectively, and is included in general and administrative expense in the Consolidated Statement of Operations.

## NOTE 16—DEFINED CONTRIBUTION PLAN

The Company maintains a 401(k) defined contribution plan for eligible employees. The Company matches 50% of an employee’s deferrals up to 4%. The Company also contributes 3% of eligible employee’s compensation expense as a safe harbor contribution. The matching contributions vest ratably over four years of service, while the safe harbor contributions vest immediately. Incurred expense related to the 401(k) plan was approximately $589, $502 and $521 for the years ended December 31, 2022, 2021 and 2020, respectively.

## NOTE 17—RELATED-PARTY TRANSACTIONS

## Related Party Loan

On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (the "Initial Promissory Note") with MNK. MNK is currently an affiliate of the Company and certain of the Company's directors and executive officers are also directors and executive officers of MNK. Pursuant to the Initial Promissory Note, the Company advanced a cash loan of $5,000 to MNK for MNK to pay its dividends tax liability arising from the Reorganization Transactions under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended (the "South African Income Tax Act"). On February 22, 2021, the Company and MNK entered into an Amended and Restated Promissory Note (the "Amended Promissory Note") to increase the principal amount of the loan to a total of $7,140, in the aggregate, and on December 22, 2021 entered into the Second Amended and Restated Loan Agreement and Secured Promissory Note (the "Second Amended Promissory Note") to increase the principal amount of the loan to a total of $8,940, in the aggregate, and on December 22, 2022 entered into the First Amendment of the Second Amended and Restated Loan Agreement and Secured Promissory Note (the "First Amendment of Second Amended Promissory Note") to amend the maturity date of June 30, 2023, each in accordance with the Company's obligations set forth in the Transaction Implementation Agreement entered into by and among the Company, MNK and the other party thereto, dated November 6, 2020, and amended on January 14, 2021. The terms of the Amended Promissory Note provide the



Company a security interest of 800,000 shares of the Company and require MNK to use the proceeds of any such sale of the shares to repay the note. The Amended Promissory Note also has default provisions where MNK will deliver any unsold shares of the Company back to the Company to satisfy repayment of the note. The Amended Promissory Note matures on June 30, 2023.

Under applicable guidance for variable interest entities in ASC 810, Consolidation, the Company determined that MNK is a variable interest entity. The Company concluded that it is not the primary beneficiary of the variable interest entity, as the Company does not have a controlling financial interest and does not have the power to direct the activities that most significantly impact the economic performance of MNK. Accordingly, the Company concluded that presentation of the Amended Promissory Note as a related party receivable remains appropriate.

## Related Party Reimbursements

Periodically the Company will reimburse MNK and HCI Managerial Services Proprietary Limited, the administrator for the Company’s secondarily listed Johannesburg Stock Exchange trading symbol, for expenses incurred on behalf of the Company. Amounts reimbursed were $68, $813 and $238 for the years ended December 31, 2022, 2021 and 2020, respectively. $26 and $0 were owed as of December 31, 2022 and 2021, respectively.

## NOTE 18—SEGMENT INFORMATION

The Company’s reportable segments for the years ended December 31, 2022, 2021, and 2020 are Renewable Natural Gas and Renewable Electricity Generation. Renewable Natural Gas includes the production of RNG. Renewable Electricity Generation includes generation of electricity at biogas-to-electricity plants. The corporate entity is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation of the Company’s consolidated financial statements. The following table is consistent with the manner in which the chief operating decision maker evaluates the performance of each segment and allocates the Company’s resources. In the following tables “RNG” refers to Renewable Natural Gas and “REG” refers to Renewable Electricity Generation.

<table><tr><td rowspan="2"></td><td colspan="4">For the year ended December 31, 2022</td></tr><tr><td>RNG</td><td>REG</td><td>Corporate</td><td>Total</td></tr><tr><td>Total revenue</td><td>$196,218</td><td>$17,170</td><td>$ (7,829)</td><td>$205,559</td></tr><tr><td>Net income (loss)</td><td>94,330</td><td>(6,756)</td><td>(52,380)</td><td>35,194</td></tr><tr><td>EBITDA</td><td>109,297</td><td>(1,297)</td><td>(42,266)</td><td>65,734</td></tr><tr><td>Adjusted EBITDA(1)</td><td>110,510</td><td>1,918</td><td>(41,890)</td><td>70,538</td></tr><tr><td>Total assets</td><td>151,998</td><td>53,255</td><td>127,063</td><td>332,316</td></tr><tr><td>Capital expenditures</td><td>16,667</td><td>5,033</td><td>577</td><td>22,277</td></tr></table>

(1) 2022 EBITDA Reconciliation



The following table is a reconciliation of the Company’s reportable segments’ net income from continuing operations to Adjusted EBITDA for the year ended December 31, 2022:

<table><tr><td rowspan="2"></td><td colspan="4">For the year ended December 31, 2022</td></tr><tr><td>RNG</td><td>REG</td><td>Corporate</td><td>Total</td></tr><tr><td>Net income (loss)</td><td>$ 94,330</td><td>$ (6,756)</td><td>$ (52,380)</td><td>$ 35,194</td></tr><tr><td>Depreciation and amortization</td><td>14,967</td><td>5,443</td><td>290</td><td>20,700</td></tr><tr><td>Interest expense</td><td>—</td><td>—</td><td>1,792</td><td>1,792</td></tr><tr><td>Income tax expense</td><td>—</td><td>16</td><td>8,032</td><td>8,048</td></tr><tr><td>EBITDA</td><td>$109,297</td><td>$ (1,297)</td><td>$ (42,266)</td><td>$ 65,734</td></tr><tr><td>Impairment loss</td><td>1,135</td><td>3,526</td><td>191</td><td>4,852</td></tr><tr><td>Net loss (gain) of sale of assets</td><td>78</td><td>(311)</td><td>—</td><td>(233)</td></tr><tr><td>Transaction costs</td><td>—</td><td>—</td><td>185</td><td>185</td></tr><tr><td>Adjusted EBITDA</td><td>$110,510</td><td>$ 1,918</td><td>$ (41,890)</td><td>$ 70,538</td></tr></table>

<table><tr><td></td><td>RNG</td><td>REG</td><td>Corporate</td><td>Total</td></tr><tr><td>Total revenue</td><td>$131,803</td><td>$15,449</td><td>$ 875</td><td>$148,127</td></tr><tr><td>Net income (loss)</td><td>49,387</td><td>(3,129)</td><td>(50,786)</td><td>(4,528)</td></tr><tr><td>EBITDA</td><td>66,549</td><td>2,399</td><td>(43,518)</td><td>25,430</td></tr><tr><td>Adjusted EBITDA(2)</td><td>67,812</td><td>3,149</td><td>(43,012)</td><td>27,949</td></tr><tr><td>Total assets</td><td>150,472</td><td>57,980</td><td>78,028</td><td>286,480</td></tr><tr><td>Capital expenditures</td><td>7,647</td><td>2,296</td><td>43</td><td>9,986</td></tr></table>

## (2) 2021 EBITDA Reconciliation

The following table is a reconciliation of the Company’s reportable segments’ net income from continuing operations to Adjusted EBITDA for the year ended December 31, 2021:

<table><tr><td rowspan="2"></td><td colspan="4">For the year ended December 31, 2021</td></tr><tr><td>RNG</td><td>REG</td><td>Corporate</td><td>Total</td></tr><tr><td>Net income (loss)</td><td>$ 49,387</td><td>$ (3,129)</td><td>$ (50,786)</td><td>$ (4,528)</td></tr><tr><td>Depreciation and amortization</td><td>17,162</td><td>5,528</td><td>179</td><td>22,869</td></tr><tr><td>Interest expense</td><td>—</td><td>—</td><td>2,928</td><td>2,928</td></tr><tr><td>Income tax expense</td><td>—</td><td>—</td><td>4,161</td><td>4,161</td></tr><tr><td>EBITDA</td><td>$ 66,549</td><td>$ 2,399</td><td>$ (43,518)</td><td>$ 25,430</td></tr><tr><td>Impairment loss</td><td>441</td><td>750</td><td>—</td><td>1,191</td></tr><tr><td>Net loss on sale of assets</td><td>822</td><td>—</td><td>—</td><td>822</td></tr><tr><td>Transaction costs</td><td>—</td><td>—</td><td>352</td><td>352</td></tr><tr><td>Loss on extinguishment of debt</td><td>—</td><td>—</td><td>154</td><td>154</td></tr><tr><td>Adjusted EBITDA</td><td>$ 67,812</td><td>$ 3,149</td><td>$ (43,012)</td><td>$ 27,949</td></tr></table>

<table><tr><td></td><td>RNG</td><td>REG</td><td>Corporate</td><td>Total</td></tr><tr><td>Total revenue</td><td>$ 83,236</td><td>$16,665</td><td>$ 482</td><td>$100,383</td></tr><tr><td>Net income (loss)</td><td>22,068</td><td>(2,713)</td><td>(14,752)</td><td>4,603</td></tr><tr><td>EBITDA</td><td>36,920</td><td>4,649</td><td>(16,506)</td><td>25,063</td></tr><tr><td>Adjusted EBITDA(3)</td><td>37,219</td><td>4,948</td><td>(16,118)</td><td>26,049</td></tr><tr><td>Total assets</td><td>159,899</td><td>52,539</td><td>40,918</td><td>253,356</td></tr><tr><td>Capital expenditure</td><td>14,071</td><td>3,513</td><td>62</td><td>17,646</td></tr></table>

## (3) 2020 EBITDA Reconciliation



The following table is a reconciliation of the Company’s reportable segments’ net income from continuing operations to Adjusted EBITDA for the year ended December 31, 2020:

<table><tr><td rowspan="2"></td><td colspan="4">For the year ended December 31, 2020</td></tr><tr><td>RNG</td><td>REG</td><td>Corporate</td><td>Total</td></tr><tr><td>Net income (loss)</td><td>$22,068</td><td>$(2,713)</td><td>$ (14,752)</td><td>$ 4,603</td></tr><tr><td>Depreciation and amortization</td><td>14,852</td><td>7,086</td><td>179</td><td>22,117</td></tr><tr><td>Interest expense</td><td>—</td><td>—</td><td>4,339</td><td>4,339</td></tr><tr><td>Income tax expense (benefit)</td><td>—</td><td>276</td><td>(6,272)</td><td>(5,996)</td></tr><tr><td>EBITDA</td><td>$36,920</td><td>$ 4,649</td><td>$ (16,506)</td><td>$25,063</td></tr><tr><td>Impairment loss</td><td>—</td><td>278</td><td>—</td><td>278</td></tr><tr><td>Net loss sale of assets</td><td>299</td><td>21</td><td>—</td><td>320</td></tr><tr><td>Non-cash hedging charges</td><td>—</td><td>—</td><td>388</td><td>388</td></tr><tr><td>Adjusted EBITDA</td><td>$37,219</td><td>$ 4,948</td><td>$ (16,118)</td><td>$26,049</td></tr></table>

For the years ended December 31, 2022, 2021 and 2020, two, two and four customers, respectively, made up greater than 10% of our total revenues.

<table><tr><td rowspan="2"></td><td colspan="4">For the year ended December 31, 2022</td></tr><tr><td>RNG</td><td>REG</td><td>Corporate</td><td>Total</td></tr><tr><td>Customer A</td><td>32.0%</td><td>—</td><td>—</td><td>32.0%</td></tr><tr><td>Customer B</td><td>17.0%</td><td>—</td><td>—</td><td>17.0%</td></tr><tr><td rowspan="2"></td><td colspan="4">For the year ended December 31, 2021</td></tr><tr><td>RNG</td><td>REG</td><td>Corporate</td><td>Total</td></tr><tr><td>Customer A</td><td>13.1%</td><td>—</td><td>—</td><td>13.1%</td></tr><tr><td>Customer B</td><td>12.4%</td><td>—</td><td>—</td><td>12.4%</td></tr><tr><td rowspan="2"></td><td colspan="4">For the year ended December 31, 2020</td></tr><tr><td>RNG</td><td>REG</td><td>Corporate</td><td>Total</td></tr><tr><td>Customer A</td><td>15.1%</td><td>—</td><td>—</td><td>15.1%</td></tr><tr><td>Customer B</td><td>—</td><td>14.4%</td><td>—</td><td>14.4%</td></tr><tr><td>Customer C</td><td>14.1%</td><td>—</td><td>—</td><td>14.1%</td></tr><tr><td>Customer D</td><td>11.3%</td><td>—</td><td>—</td><td>11.3%</td></tr></table>

## NOTE 19—LEASES

The Company leases office space and other office equipment under operating lease arrangements (with initial terms greater than twelve months), expiring in various years through 2033. These leases have been entered into to better enable the Company to conduct business operations. Office space is leased to provide adequate workspace for all employees in Pittsburgh, Pennsylvania and Houston, Texas. Office space and office equipment agreements that exceed 12 months are accounted for as operating leases in accordance with ASC 842, Leases.

The Company also leases safety equipment for the various operational sites in the United States. The term of certain equipment exceeds twelve months and is accordingly classified as a finance lease under ASC 842. The finance leases expire in 2024 and were entered into in order to provide a safe work environment for operational employees.

The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of



time. For all operating lease arrangements, the Company presents at the commencement date: a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.

The Company has elected, as a practical expedient, not to separate non-lease components from lease components, and instead account for each separate component as a single lease component for all lease arrangements, as lessee. In addition, the Company has elected, as a practical expedient, not to apply lease recognition requirements to short-term lease arrangements, generally those with a lease term of less than twelve months, for all classes of underlying assets. In determination of the lease term, the Company considers the likelihood of lease renewal options and lease termination provisions.

The Company uses its incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. The incremental borrowing rate represents the rate of interest a lessee would have to pay to borrow an amount equal to the total lease payments on a collateralized basis over a similar term in a similar economic environment.

As of December 31, 2022, there were no leases entered into which have not yet commenced and that would entitle the Company to significant rights or create additional obligations. The total lease cost included in our consolidated financial statements statement of operations for the years ended December 31, 2022, 2021 and 2020 were $412, $349, and $322, respectively.

Leases with an initial term of 12 months or less are not recorded on the Consolidated Balance Sheet and the lease expense for those leases is recognized on a straight-line basis. The short-term lease expense for the years ended December 31, 2022, 2021 and 2020 were approximately $895, $494 and $637, respectively.

Supplemental information related to operating lease arrangements was as follows as of and for the year ended December 31, 2022 and 2021:

<table><tr><td rowspan="2"></td><td colspan="2">Years ended December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Cash paid for amounts included in the measurement of operating lease liabilities</td><td>$ 385</td><td>$ 304</td></tr><tr><td>Weighted average remaining lease term (in years)</td><td>5.87</td><td>1.03</td></tr><tr><td>Weighted average discount rate</td><td>5.00%</td><td>5.00%</td></tr></table>

Future minimum lease payments for the years ending December 31, are as follows:

<table><tr><td>Year Ending</td><td></td></tr><tr><td>2023</td><td>$ 431</td></tr><tr><td>2024</td><td>611</td></tr><tr><td>2025</td><td>624</td></tr><tr><td>2026</td><td>573</td></tr><tr><td>2027</td><td>583</td></tr><tr><td>Thereafter</td><td>3,307</td></tr><tr><td>Interest</td><td>(1,378)</td></tr><tr><td>Total</td><td>$ 4,751</td></tr></table>



Supplemental information related to finance lease arrangements was as follows:

<table><tr><td rowspan="2"></td><td colspan="2">Years ended December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Cash paid for amounts included in the measurement of financing lease liabilities</td><td>$ 50</td><td>$—</td></tr><tr><td>Weighted average remaining lease term (in years)</td><td>1.25</td><td>—</td></tr><tr><td>Weighted average discount rate</td><td>5.00%</td><td>—</td></tr></table>

Future minimum finance lease payments are as follows:

<table><tr><td>Year Ending</td><td></td></tr><tr><td>2023</td><td>$75</td></tr><tr><td>2024</td><td>25</td></tr><tr><td>Interest</td><td>(4)</td></tr><tr><td>Total</td><td>$96</td></tr></table>

## NOTE 20—COMMITMENTS AND CONTINGENCIES

## Concentrations

A substantial portion of the Company’s revenues are generated from five locations in 2022, 2021, and 2020, each in separate areas of the country. For the years ended December 31, 2022, 2021 and 2020, excluding the impact of derivative instruments, approximately 72%, 76% and 80%, respectively, of operating revenues were derived from these locations. In addition, five customers make up approximately 69% and 68% of trade receivables as of December 31, 2022 and December 31, 2021, respectively.

## Environmental

The Company is subject to a variety of environmental laws and regulations governing discharges to the air and water, as well as the handling, storage and disposing of hazardous or waste materials. The Company believes its operations currently comply in all material respects with all environmental laws and regulations applicable to its business. However, there can be no assurance that environmental requirements will not change in the future or that the Company will not incur significant costs to comply with such requirements.

## Contingencies

The Company, from time to time, may be involved in litigation. At December 31, 2022, management does not believe there are any matters outstanding that would have a material adverse effect on the Company’s financial position or results of operations.



## NOTE 21—QUARTERLY FINANCIAL DATA (UNAUDITED)

Presented below is the selected quarterly financial data for year 2022 and year 2021, which was prepared on the same basis as the audited consolidated financial statements and includes all adjustments necessary to present fairly, in all material respects, the information set forth therein on a consistent basis. The Reorganization Transactions resulted in a pro rata distribution whereby the ownership of the Company after the Reorganization Transactions was identical to the ownership of MNK prior to the Reorganization Transaction and was therefore akin to a common control transaction. The retrospective presentation of the periods presented in the consolidated financial statements as a result of this common control transaction require the following unaudited quarterly financial disclosures.

<table><tr><td></td><td>First Quarter</td><td>Second Quarter</td><td>Third Quarter</td><td>Fourth Quarter</td></tr><tr><td>2022</td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 32,169</td><td>$67,884</td><td>$55,860</td><td>$49,646</td></tr><tr><td>Operating (loss) income(1)</td><td>(1,651)</td><td>23,963</td><td>13,632</td><td>8,622</td></tr><tr><td>Net (loss) income</td><td>(1,115)</td><td>19,152</td><td>11,187</td><td>5,970</td></tr><tr><td>2021</td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 31,447</td><td>$31,674</td><td>$39,749</td><td>$45,257</td></tr><tr><td>Operating (loss) income(1)</td><td>(12,204)</td><td>(537)</td><td>6,729</td><td>9,347</td></tr><tr><td>Net (loss) income</td><td>(14,265)</td><td>(4,652)</td><td>8,896</td><td>5,493</td></tr></table>

(1) The company received $313 and $332 in insurance proceeds for the years ended December 31, 2022 and 2021, respectively. The proceeds related to an engine failure and related business interruption at an RNG facility.

## Note 22—EARNINGS (LOSS) PER SHARE

Earnings (loss) per share was computed using the following common share data for the years ended December 31, 2022 and 2021, respectively:

<table><tr><td></td><td>Year Ended December 31, 2022</td><td>Year Ended December 31, 2021</td></tr><tr><td>Net income (loss)</td><td>$ 35,194</td><td>$ (4,528)</td></tr><tr><td>Basic weighted-average shares outstanding</td><td>141,238,851</td><td>141,015,213</td></tr><tr><td>Dilutive effect of share-based awards</td><td>1,340,538</td><td>—</td></tr><tr><td>Diluted weighted-average shares outstanding</td><td>142,579,389</td><td>141,015,213</td></tr><tr><td>Basic income (loss) per share</td><td>$ 0.25</td><td>$ (0.03)</td></tr><tr><td>Diluted income (loss) per share</td><td>$ 0.25</td><td>$ (0.02)</td></tr></table>

As a result of incurring a net loss for the year ended December 31, 2021, 3,897,811 potential antidilutive shares were excluded from the above loss per share calculation.

## NOTE 23—SUBSEQUENT EVENTS

## Subsequent Events

The Company evaluated its December 31, 2022 consolidated financial statements through the date the financial statements were issued. The Company is not aware of any subsequent events which would require disclosure in the consolidated financial statements.



## ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

## ITEM 9A. CONTROLS AND PROCEDURES.

## Management’s Evaluation of Disclosure Controls and Procedures.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. The Company, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, concluded that, as of December 31, 2022 (the end of the period covered by this Annual Report on Form 10-K), the Company’s disclosure controls and procedures were effective, pursuant to Rule 13a-15 and Rule 15d-15 of the Exchange Act.

## Management’s Annual Report on Internal Control Over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with appropriate authorizations; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

Our management has conducted an evaluation of the effectiveness of our internal control over financial reporting, using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013) (“COSO”). Based on the results of this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2022.

This Annual Report on Form 10-K does not include an attestation report of internal controls from our independent registered public accounting firm due to our status as an emerging growth company under the JOBS Act.

## Changes in Internal Control over Financial Reporting.

There have been no material changes in our internal control over financial reporting during the quarter ended December 31, 2022, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting

## ITEM 9B. OTHER INFORMATION.

None.



# ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.

None.

## PART III

## ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is set forth in our Proxy Statement in the section entitled “Proposal No. 1—Election of Directors” under the headings “—Nominees for Election for a Term Expiring at the 2026 Annual Meeting,” and “Information Regarding our Board of Directors and Corporate Governance” under the sub-headings “Code of Business Conduct and Ethics,” “Communications with the Board,” “Board Committees,” “Committee Functions,” and “Audit Committee” and, to the extent necessary, under the section entitled “Delinquent Section 16(a) Reports.” The information in these sections is incorporated by reference into this Annual Report on Form 10-K.

Information regarding our executive officers is included in Part I of this Report under the header “Information About Our Executive Officers.”

## ITEM 11. EXECUTIVE COMPENSATION

The information required by this item is set forth in our Proxy Statement under the headings “Proposal No. 1—Election of Directors—Information Regarding our Board of Directors and Corporate Governance—Compensation Committee Interlocks and Insider Participation” and “Executive Compensation” and is incorporated herein by reference.

## ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Except as set forth herein, the information required by this item is set forth in our Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.

As of December 31, 2022, our securities authorized for issuance under equity compensation plans were as follows:

<table><tr><td>Plan Category</td><td>Number of securities to be issued upon exercise of outstanding awards (a) (1)</td><td>Weighted-average exercise price of outstanding awards (b) (2)</td><td>Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) (3)</td></tr><tr><td>Equity compensation plan approved by security holders</td><td>950,214</td><td>11.38</td><td>15,151,975</td></tr><tr><td>Equity compensation plan not approved by security holders</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total</td><td>950,214</td><td></td><td>15,151,975</td></tr></table>

(1) Included in column (a) are stock options and restricted stock units issued in connection with the IPO under the MRI EICP. Column (a) does not include 3,869,827 shares of restricted stock issued under the Plan.



(2) Reflects the weighted-average exercise price of outstanding stock options only, and not restricted stock and restricted stock units that do not have an exercise price.

(3) This amount represents 15,151,975 shares of common stock remaining available for future issuance under the MRI EICP.

## ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item is set forth in our Proxy Statement under the headings “Proposal No. 1—Election of Directors—Information Regarding the Board of Directors and Corporate Governance—Director Independence and Controlled Company Exemption” and “Certain Relationships and Related Party Transactions” under the subheadings “Certain Transactions” and “Policies and Procedures for Related Party Transactions” and is incorporated herein by reference.

## ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item is set forth in our Proxy Statement under the heading “Proposal No. 2—Ratification of the Appointment of Grant Thornton LLP as Independent Auditor” under the subheadings “Principal Accountant Fees and Services” and “Pre-Approval Policies and Procedures” and is incorporated herein by reference.

## PART IV

## ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

## (a)(1) Financial Statements

See Part II, Item 8. “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

## (a)(2) Financial Statements

Schedules not filed with this Annual Report on Form 10-K are omitted because of the absence of conditions under which they are required or because the information called for is shown in the financial statements or related notes.

## (a)(3) Exhibits

<table><tr><td>Exhibit Number</td><td>Description</td></tr><tr><td>2.1.1+</td><td>Transaction Implementation Agreement, dated as of November 6, 2020, between Montauk Renewables, Inc., Montauk Holdings Limited and Montauk Holdings USA, LLC (incorporated by reference to Exhibit 2.1 our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)</td></tr><tr><td>2.1.2</td><td>Letter Agreement, dated as of January 3, 2021, to the Transaction Implementation Agreement, dated as of November 6, 2020, between Montauk Renewables, Inc., Montauk Holdings Limited and Montauk Holdings USA, LLC (incorporated by reference to Exhibit 2.2 Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)</td></tr><tr><td>2.2.1+</td><td>Membership Interest and Asset Purchase Agreement, dated May 10, 2021, by and among J.P. Carroll &amp; Co., LLC, Eagle Creek Ranch, L.L.C., NR Nutrient Recovery, LLC, Joseph P. Carroll, Jr., Martin A. Redeker and Montauk Swine Ag, LLC (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K (File No. 001-39919), filed on May 11, 2021)</td></tr></table>



2.2.2 First Amendment to Membership Interest and Asset Purchase Agreement, dated May 26, 2022, by and among J.P. Carroll & Co., LLC, Eagle Creek Ranch, L.L.C., NR3 Nutrient Recovery, LLC, Joseph P. Carroll, Jr., Martin A. Redeker, Montauk Ag Renewables, LLC and Montauk Energy Holdings, LLC (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K (File No. 001-39919), filed on June 1, 2022)

2.3+ Real Estate Purchase and Sale Agreement, dated May 10, 2021, by and among Greensboro Ecosystems, LLC and Montauk Swine Ag, LLC (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K (File No. 001-39919), filed on May 11, 2021)

3.1 Amended and Restated Certificate of Incorporation of Montauk Renewables, Inc. (incorporated by reference to Exhibit 3.1 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)

3.2 Bylaws of Montauk Renewables, Inc. (incorporated by reference to Exhibit 3.2 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)

10.1^ Montauk Renewables, Inc. Equity and Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)

10.2^ Form of Key Employee Separation Plan (incorporated by reference to Exhibit 10.2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)

10.3^ Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.3 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)

10.4^ Form of Restricted Stock Unit Award Agreement (Employees) (incorporated by reference to Exhibit 10.4 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)

10.5^ Form of Restricted Stock Unit Award Agreement (Non-Employee Directors) (incorporated by reference to Exhibit 10.5 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)

10.6^+ Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.6 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)

10.7^ Form of Indemnification Agreement between Montauk Renewables, Inc. and each of its directors and executive officers (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed June 8, 2021)

10.8^+ Employment Agreement, effective September 25, 2019, between Montauk Energy Holdings LLC and Sean F. McClain (incorporated by reference to Exhibit 10.9 to Annual Report on Form 10-K (file No. 001-39919), filed March 31, 2021)

10.9^+ Employment Agreement, effective September 25, 2019, between Montauk Energy Holdings LLC and Kevin A. Van Asdalan (incorporated by reference to Exhibit 10.10 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)

10.10^+ Employment Agreement, effective September 24, 2019, between Montauk Energy Holdings LLC and James A. Shaw (incorporated by reference to Exhibit 10.11 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)

10.11^+ Employment Agreement, effective June 1, 2020, between Montauk Energy Holdings LLC and John Ciroli (incorporated by reference to Exhibit 10.42 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)



10.12^ Employment Agreement, effective April 15, 2010, between Montauk Energy Capital, LLC and Scott Hill (incorporated by reference to Exhibit 10.43 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)

10.13.1+ Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of December 12, 2018, by and among Montauk Energy Holdings LLC, the financial institutions from time to time party thereto, as lenders, and Comerica Bank, as administrative agent, sole lead arranger and sole book runner (incorporated by reference to Exhibit 10.13 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)

10.13.2 First Amendment, dated as of March 21, 2019, to the Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of December 12, 2018, by and among Montauk Energy Holdings LLC, the financial institutions from time to time party thereto, as lenders, and Comerica Bank, as administrative agent, sole lead arranger and sole book runner (incorporated by reference to Exhibit 10.14 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)

10.13.3 Second Amendment, dated as of September 12, 2019, to the Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of December 12, 2018, by and among Montauk Energy Holdings LLC, the financial institutions from time to time party thereto, as lenders, and Comerica Bank, as administrative agent, sole lead arranger and sole book runner (incorporated by reference to Exhibit 10.15 to our Registration Statement on Form S-1(File No. 333-251312), filed December 11, 2020)

10.13.4 Third Amendment, dated as of January 4, 2021, to the Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of December 12, 2018, by and among Montauk Energy Holdings LLC, the financial institutions from time to time party thereto, as lenders, and Comerica Bank, as administrative agent, sole lead arranger and sole book runner (incorporated by reference to Exhibit 10.16 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)

10.13.5+ Fourth Amendment to Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of December 22, 2021, by and among Montauk Energy Holdings, LLC, the financial institutions from time to time signatory thereto and Comerica Bank, as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K (file No. 001-39919), filed on December 23, 2021)

10.14.1++ Second Amended & Restated Landfill Gas Rights & Production Facilities Agreement, by and between County of Orange and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)

10.14.2++ First Amendment to the Second Amended & Restated Landfill Gas Rights & Production Facilities Agreement, by and between County of Orange and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to our Registration Statement on Form S-1(File No. 333-251312), filed December 31, 2021)

10.15+ Renewable Power Purchase and Sale Agreement by and between the City of Anaheim and Bowerman Power LFG, LLC (incorporated by reference to Exhibit 10.19 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)

10.16++ Amended and Restated Gas Sale and Purchase Agreement, by and between McCarty Road Landfill TX, LP and GSF Energy, LLC (incorporated by reference to Exhibit 10.20 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)



10.17 \( ^{++} \)  Third Amended and Restated Gas Lease Agreement, dated January 1, 2018, by and between Rumpke Sanitary Landfill, Inc. and GSF Energy, LLC (incorporated by reference to Exhibit 10.24 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)

10.18 \( ^{++} \)  Amended and Restated Landfill Gas Purchase and Sale Agreement, dated October 17, 2016, by and between Waste Management of Texas, Inc. and TX LFG Energy, LP (incorporated by reference to Exhibit 10.35 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)

10.19.1 Second Amended and Restated Loan Agreement and Promissory Note, by and between Montauk Holdings Limited and Montauk Renewables, (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (file No. 001-39919), filed on December 23, 2021

10.19.2 First Amendment to the Second Amended and Restated Loan Agreement and Secured Promissory Note, dated December 22, 2022, by and between Montauk Renewables, Inc. and Montauk Holdings Limited, (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (file No. 001-39919), filed on December 23, 2022)

21.1 List of subsidiaries of Montauk Renewables, Inc.

23.1 Consent of Independent Registered Public Accounting Firm

24.1 Power of Attorney

31.1 Certification of the Chief Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) of the Securities Exchange Act

31.2 Certification of the Chief Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) of the Securities Exchange Act

32.1 Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2 Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.1+ Consortium Agreement, dated as of January 24, 2021, by and among the stockholders named therein (incorporated by reference to Exhibit 99.2 to Annual Report on Form 10-K (file No. 001-39919), filed March 31, 2021)

 \( ^{^} \)  Exhibits marked with a ( \( ^{+} \) ) are management contracts or compensation plans or arrangements.

+ Exhibits marked with a (+) exclude certain immaterial schedules and exhibits pursuant to the provisions of Regulation S-K, Item 601(a)(5) or Item 601(a)(6). A copy of any of the omitted schedules and exhibits pursuant to Regulation S-K, Item 601(a)(5) will be furnished to the Securities and Exchange Commission upon request.

† Exhibits marked with a (†) exclude certain portions of the exhibit pursuant to Item 601(b)(10)(iv) of Regulation S-K. A copy of the omitted portions will be furnished to the Securities and Exchange Commission upon request.

## ITEM 16. FORM 10-K SUMMARY

None.



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 16, 2023

Montauk Renewables, Inc.

By: /s/ Sean F. McClain
Name: Sean F. McClain
Title: President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

<table><tr><td>Signature</td><td>Title</td><td>Date</td></tr><tr><td>/s/ Sean F. McClain</td><td rowspan="2">President, Chief Executive Officer and Director (Principal Executive Officer)</td><td rowspan="2">March 16, 2023</td></tr><tr><td>Sean F. McClain</td></tr><tr><td>/s/ Kevin A. Van Asdalan</td><td rowspan="2">Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)</td><td rowspan="2">March 16, 2023</td></tr><tr><td>Kevin A. Van Asdalan</td></tr><tr><td>*</td><td>Lead Director</td><td>March 16, 2023</td></tr><tr><td>Mohamed H. Ahmed</td><td></td><td></td></tr><tr><td>*</td><td>Chairman of the Board and Director</td><td>March 16, 2023</td></tr><tr><td>John A. Copelyn</td><td></td><td></td></tr><tr><td>*</td><td>Director</td><td>March 16, 2023</td></tr><tr><td>Jennifer Cunningham</td><td></td><td></td></tr><tr><td>*</td><td>Director</td><td>March 16, 2033</td></tr><tr><td>Theventheran G. Govender</td><td></td><td></td></tr><tr><td>*</td><td>Director</td><td>March 16, 2033</td></tr><tr><td>Michael A. Jacobson</td><td></td><td></td></tr><tr><td>*</td><td>Director</td><td>March 16, 2023</td></tr><tr><td>Yunis Shaik</td><td></td><td></td></tr></table>

* The undersigned, by signing his name hereto, does hereby sign this report on behalf of each of the above named and designated directors of the Company pursuant to Powers of Attorney executed by such persons and filed with the Securities and Exchange Commission.

By: /s/ Sean F. McClain
Name: Sean F. McClain
Title: Attorney-in-Fact



## Board of Directors

Mohamed H. Ahmed
Executive Director of Ritz Tiles

Jennifer Cunningham
Advisor to the Open Space Institute
and Mohonk Preserve in New York

Sean F. McClain
President and Chief Executive Officer
of Montauk Renewables

John A. Copelyn
Chief Executive Officer of Hoskins Consolidated Investments

Theventheran G. Govender
Executive Director of Hoskins Consolidated
Investments

Yunis Shaik
Executive Director of Hoskins Consolidated
Investments

## Executive Leadership Team

John Ciroli
Chief Legal Officer & Secretary

Sean McClain
President and Chief Executive Officer

Kevin Van Asdalan
Chief Financial Officer

Sharon Frank
Vice President, Environmental, Health and Safety

Jim Shaw
Vice President, Operations

## Non-GAAP Reconciliations

<table><tr><td></td><td>2018</td><td>2019</td><td>2020</td><td>2021</td><td>2022</td></tr><tr><td>Net income (loss)</td><td>$28,767</td><td>$ 5,820</td><td>$ 4,603</td><td>$ (4,528)</td><td>$35,194</td></tr><tr><td>Depreciation and amortization</td><td>16,195</td><td>19,760</td><td>22,117</td><td>22,869</td><td>20,700</td></tr><tr><td>Interest expense</td><td>3,083</td><td>5,576</td><td>4,339</td><td>2,928</td><td>1,792</td></tr><tr><td>Income tax expense (benefit)</td><td>7,796</td><td>(354)</td><td>(5,996)</td><td>4,161</td><td>8,048</td></tr><tr><td>Consolidated EBITDA</td><td>55,841</td><td>30,802</td><td>25,063</td><td>25,430</td><td>65,734</td></tr><tr><td>Impairment loss</td><td>854</td><td>2,443</td><td>278</td><td>1,191</td><td>4,852</td></tr><tr><td>Net (gain) loss on sale of assets</td><td>(266)</td><td>10</td><td>320</td><td>822</td><td>(233)</td></tr><tr><td>Transaction costs</td><td>176</td><td>202</td><td>—</td><td>352</td><td>185</td></tr><tr><td>Loss on extinguishment of debt</td><td>—</td><td>—</td><td>—</td><td>154</td><td>—</td></tr><tr><td>Non-cash hedging charges</td><td>(92)</td><td>(252)</td><td>388</td><td>—</td><td>—</td></tr><tr><td>Equity (gain) loss of nonconsolidated investments</td><td>224</td><td>(94)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Adjusted EBITDA</td><td>$56,737</td><td>$33,111</td><td>$26,049</td><td>$27,949</td><td>$70,538</td></tr></table>