Montauk Renewables (MNTK) 10-K 2020 FY Annual report

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, 2020;

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	85-3189583
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
680 Andersen Drive, 5th Floor, Pittsburgh, PA	15220
(Address of principal executive offices)	(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	☐	Accelerated Filer	☐
Non-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.  ☐

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

As of June 30, 2020, the last business day of the registrant’s most recently completed second fiscal quarter, the registrant did not have a public float because there was no established public market for the registrant’s common stock. As of March 17, 2021, the aggregate market value of shares of common stock held by non-affiliates of the registrant was $577,574,415.

The number of outstanding shares of the registrant’s common stock on March 17, 2021 was 142,157,835 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 Stockholders to be held in 2021 (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 ended December 31, 2020.

TABLE OF CONTENTS

			Page
PART I				1
	ITEM 1.	BUSINESS		1
	ITEM 1A.	RISK FACTORS		30
	ITEM 1B.	UNRESOLVED STAFF COMMENTS		57
	ITEM 2.	PROPERTIES		57
	ITEM 3.	LEGAL PROCEEDINGS		58
	ITEM 4.	MINE SAFETY DISCLOSURES		58
PART II				59
	ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		59
	ITEM 6.	SELECTED FINANCIAL DATA		61
	ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		62
	ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		79
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		81
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		118
	ITEM 9A.	CONTROLS AND PROCEDURES		118
	ITEM 9B.	OTHER INFORMATION		119
PART III				119
	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		119
	ITEM 11.	EXECUTIVE COMPENSATION		119
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		119
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		119
	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		120
PART IV				120
	ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES		120
	ITEM 16.	FORM 10-K SUMMARY		124

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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.

• “CWCs” 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.

• “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.

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Cautionary Note Regarding Forward-Looking Statements

This Annual Report on Form 10-K contains “forward-looking statements” 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,” “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 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:

• the impact of the ongoing COVID-19 pandemic on our business, financial condition and results of operations;

• our ability to develop and operate new renewable energy projects, including with livestock farms;

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

• delays in acquisition, financing, construction and development of new projects, including expansion plans into new areas such as dairy;

• the length of development 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;

• identifying suitable locations for new projects;

• reliance on interconnections to distribution and transmission products for our Renewable Natural Gas and Renewable Electricity Generation segments;

• our projects not producing expected levels of output;

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

• dependence on our landfill operators;

• 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;

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

• our expectations regarding the period during which we qualify as an emerging growth company under the JOBS Act;

• market volatility and fluctuations in commodity prices and the market prices of Environmental Attributes;

• profitability of our planned livestock farm projects;

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• sustained demand for renewable energy;

• security threats, including cyber-security attacks;

• the need to obtain and maintain regulatory permits, approvals and consents;

• 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;

• an active trading market for our common stock may not develop;

• our belief that we are taking appropriate measures to remediate the material weakness identified in our internal control over financial reporting;

• 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.

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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.

Company Overview

Overview

We are 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 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 $100.4 million in 2020.

Biogas is produced by microbes as they break down organic matter in the absence of oxygen (during a process called anaerobic digestion). Our two current sources of commercial scale biogas are LFG or ADG. We typically secure our biogas feedstock through long-term fuel supply agreements and property lease agreements with biogas site hosts. Once we secure long-term fuel supply rights, we design, build, own, and operate facilities that convert the biogas into RNG or use the processed biogas to produce Renewable Electricity. We sell the RNG and Renewable Electricity through a variety of 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.

Based on our analysis, we believe there are numerous sources of waste methane in the United States that could serve as potential future project opportunities. We expect to continue our growth through optimization of our current project portfolio, securing greenfield developments and acquiring existing projects, all while pursuing vertical integration opportunities. Our successful evaluation and execution of project opportunities is based on our ability to leverage our significant industry experience, relationships with customers and vendors, access to interconnections for rights-of-way, and capabilities to construct pipeline and electrical interconnections that ensure the economic viability of opportunities we pursue. We exercise financial discipline in pursuing these projects by targeting project returns that are in line with the relative risk of the specific projects and associated feedstock costs, offtake contracts and any other related attributes that can be monetized.

Our current operating projects generate RNG from landfill sites and livestock farms. We view livestock farms as a significant opportunity for us to expand our RNG business and we are also evaluating other agricultural markets. We believe that our business is highly scalable, which will allow us to continue to grow through development and acquisitions.

Our projects provide our landfill and livestock farm partners with a variety of benefits, including a means to monetize biogas from their sites, support their regulatory compliance, and provide them with environmental services. We differentiate ourselves from our competitors based on our long history of working with leading vendors and technologies and through our extensive expertise in designing, tuning and managing gas control collection systems at our host sites. We have significant experience with commercialized beneficial uses of processed biogas, including pipeline quality natural gas, power generation, carbon capture and boiler fuel gas products.

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Our revenues are generated from the sale of RNG and Renewable Electricity, under long-term contracts, along with the Environmental Attributes that are derived from these products. 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 low-carbon, renewable sources, which we can also monetize. 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. The RNG we process is pipeline-quality and can be used for transportation fuel when converted to CNG or LNG. 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. The Environmental Attributes that we sell are composed of RINs and state low-carbon fuel 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 operations and maintenance services to certain of our biogas site partners.

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 significant portion of the RNG volume we produce is sold under bundled fixed-price arrangements for the RNG and Environmental Attributes, with a sharing arrangement where we benefit from prices above certain thresholds. For our remaining RNG projects, we sometimes enter into in-kind sharing arrangements where our partners receive the Environmental Attributes instead of a cash payment, thereby sharing in the Environmental Attribute pricing risk.

We strive to sell our remaining RNG and environmental products under medium-and long-term indexed pricing and margin sharing arrangements designed to give us optimal price and revenue certainty. On the electricity side, all of our products and related Environmental Attributes are sold under fixed-price contracts with escalators, limiting our pricing risk. Finally, our payments to our site hosts are entirely in the form of royalties based on realized revenues, or, in some select cases, based on production volumes.

The Montauk Model

Reorganization Transactions

Montauk Holdings Limited, a corporation formed under the laws of the Republic of South Africa (“MNK”), was a holding company whose ordinary shares were traded on the Johannesburg Stock Exchange (“JSE”) under the symbol “MNK.” Prior to the initial public offering (the “IPO”) of our common stock, 100% of MNK’s

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business and operations were conducted through its U.S. subsidiaries, including Montauk Holdings USA, LLC (“Montauk USA”) and Montauk Energy Holdings LLC (“MEH”), and it held no assets other than the equity of its subsidiaries.

On January 4, 2021, we entered into a share exchange with Montauk USA in which we replaced Montauk USA as the top tier subsidiary of MNK and we became the direct parent company of MEH. On January 26, 2021, prior to the completion of the IPO, of all of the outstanding shares of Company common stock was distributed by MNK as a pro rata dividend to holders of MNK’s ordinary shares and, as a result, all of the shareholders of MNK became stockholders of the Company.

As we are the successor to all of Montauk USA’s interests in MEH, we present historical consolidated financial statements of Montauk USA. In connection with the above transactions (the “Reorganization Transactions”) and the IPO, the existing shareholders of MNK became stockholders of Montauk. Following the Reorganization Transactions and the closing of the IPO, MNK has been delisted from the JSE and will be liquidated prior to January 26, 2022.

Following the IPO, 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.”

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 and may be further exacerbated by the COVID-19 pandemic:

• Our commercial success depends on our ability to develop and operate individual renewable energy projects.

• 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.

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

• 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.

• 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 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.

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

• 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.

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

• Our operations are subject to numerous stringent environmental, health and safety laws and regulations that may expose us to significant costs and liabilities.

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

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

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

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

• We identified a material weakness in our internal control over financial reporting. While 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.

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

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

Market Opportunity

Increasing Demand for RNG

Demand for RNG produced from biogas is significant and growing in large part due to an increased focus by the public and governments on reducing the emission of GHG, such as methane, and increasing the energy independence of the United States. According to the EPA, methane is a significant GHG, which accounted for roughly 9.5% of all U.S. GHG emissions from human activities in 2018 and which has a comparative impact on global warming that is about 25 times more powerful than that of carbon dioxide (which is produced during the combustion process). Biogas processing facilities could substantially reduce methane emissions at landfills and livestock farms, which together accounted for approximately 27% of U.S. methane emissions in 2018 according to the EPA. The development of this energy source further supports the U.S. national security objective of attaining energy independence, as evidenced by Energy Independence and Security Act (“EISA”), which aimed to increase U.S. energy security, develop renewable energy production, and improve vehicle fuel economy.

Over the past decade, the fastest growing end market for RNG has been the transportation sector, where RNG is used as a replacement for fossil-based fuel. This growth has been driven, in large part, by more aggressive environmental subsidies to support the production of renewable transportation fuels. According to NGV America, a national organization dedicated to the development of a growing, profitable, and sustainable market for vehicles powered by natural gas or biomethane, from 2015 to 2020, “RNG use as a transportation fuel…increased 291%, displacing close to 7.5 million tons of carbon dioxide equivalent.”

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Given public calls for, and U.S. federal, state and local regulatory trends and policies aimed at, reducing GHG emissions and increasing U.S. energy independence, we expect continued regulatory support for RNG as a replacement for fossil-based fuels and therefore continued and growing demand for RNG over the next several years.

Availability of Long-Term Feedstock Supply

Biogas can be collected and processed to remove impurities for use as RNG (a form of high-Btu fuel) and injected into existing natural gas pipelines as it is fully interchangeable with natural gas. Partially treated biogas can be used directly in heating applications (as a form of medium-Btu fuel) or in the production of electricity. Common sources of biogas include landfills, livestock farms, and WRRFs.

Landfill- and livestock-sourced biogas represent a significant opportunity to produce RNG and Renewable Electricity, while also reducing GHG emissions. While landfill projects for RNG and Renewable Electricity have been developed over the past few decades, undeveloped landfills remain a significant source of biogas. Moreover, as technology continues to develop and economic incentives grow, livestock farm biogas, in particular, represents a relatively untapped biogas opportunity.

While LFG has accounted for most of the growth in biogas projects to date, we believe that additional economically viable LFG project opportunities exist. According to the EPALMOP project database, as of August 2020, there were 565 LFG projects in operation in the United States, including 399 operating LFG-to-electricity projects that may be converted to produce RNG, 11 construction projects, and 54 planned RNG and Renewable Electricity projects, as well as 477 additional candidate landfills. Based on EPA data, these 477 candidate landfills have the potential to collect a combined 499 million standard cubic feet of LFG per day, or the equivalent of carbon dioxide emissions from approximately 63,000 barrels of oil. 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 25 of these sites are potentially economically viable as projects for acquisition and growth. In the future, additional candidate landfills may become economically viable as their growth increases LFG production and requires installation of LFG collection systems.

The LFG market is heavily fragmented, which represents, in our view, a good opportunity for companies like ours to find project opportunities. The top ten players account for approximately 53% of installed LFG capacity as of August 2020, and over 90% of developers own five or fewer projects, according to the EPA. Aside from the top five players in the industry, which includes us, no company accounts for more than 5% of the total LFG-to-energy capacity. Within the LFG market, over three-quarters of projects are Renewable Electricity projects with PPAs dating back as far as 1984. As these PPAs expire, these legacy facilities present an opportunity for conversion to RNG facilities, which, in certain instances, can provide better financial terms than Renewable Electricity projects. This market fragmentation and limited expertise in RNG processing by other market participants creates significant acquisition opportunities for us.

Biogas from livestock farm waste also represents significant opportunities for RNG production that remain largely untapped. According to the U.S. Department of Agriculture, as of June 2018, biogas recovery systems are feasible, notwithstanding economic viability considerations, at 2,704 dairy farms and 5,409 swine farms in the United States, with potential to produce roughly 172.0 million MMBtu of RNG annually, or the equivalent of the carbon dioxide emissions from 4,556 million gallons of gasoline. Although many of the EPA identified project sites are not currently economically viable because of distance from pipelines and contaminants in the biogas, among other reasons as described above, we believe that there is potential for sustained growth in biogas conversion from waste sources given our significant experience in evaluating sites and assessing their viability, evolving consumer preferences, regulatory conditions, ongoing waste industry trends, and project economics. Additionally, all-in prices paid for RNG from livestock farms can be significantly higher than prices for RNG from landfills due to state-level low-carbon fuel incentives for these projects. Given our strong understanding of

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biogas processing and our market leadership in RNG, we believe that we are well-positioned to take advantage of opportunities in this emerging market.

The availability of additional waste streams, including from organic waste diversion, food waste, sludge, and wastewater, in combination with technological advances permitting new or more economical waste processing also have the potential to support long-term feedstock supply availability and the growth of our business.

Use of Environmental Attributes to Promote RNG Growth

When used as a transportation fuel or to produce electricity, RNG can generate additional revenue streams through Environmental Attributes. Environmental Attributes are provided for under a variety of programs, including the national RFS program and state-level RPS and LCFS.

The RFS program requires transportation fuel to contain a minimum volume of renewable fuel. To fulfill this regulatory mandate, the EPA requires Obligated Parties to blend renewable fuel with standard fuel to meet RVOs. Obligated Parties can comply with RVOs by either blending RNG into their existing fuel supply or purchasing RINs. RINs are generated when eligible renewable fuels are produced or imported and blended with a petroleum product for use as a transportation fuel. The RFS program has been a key driver of growth in the RNG industry since 2014 when the EPA ruled that RNG, when used as a transportation fuel, would qualify for D3 RINs (for cellulosic biofuels), which are generally the most valuable of the four RIN categories. In 2020 and 2019, our projects generated approximately 13.5% and 15.1%, respectively, of all D3 RINs in the United States.

The monetization of RNG also benefits from low-carbon fuel initiatives at the state-level, specifically from established programs in California and Oregon. The CA LCFS requires fuel producers and importers to reduce the CI of their products, with goals of a 10% reduction in carbon emissions from 1990 levels by 2020 and a 20% reduction by 2030. CARB awards CA LCFS credits to RNG projects based on each project’s CI score relative to the target CI score for gasoline and diesel fuels. The CI score represents the overall net impact of carbon emissions for each RNG pathway and is determined on a project-by-project basis. Based on our expected CI scores, we anticipate that RNG produced by livestock farms can potentially earn two to three times the amount of revenue per MMBtu relative to RNG produced from LFG projects. Several other states are considering LCFS initiatives similar to those implemented in California and Oregon.

Additionally, 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 is 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.

Our Strengths

Management and Project Expertise

Our management team has decades of combined experience in the development, design, construction and operation of biogas facilities that produce RNG and Renewable Electricity. We believe that our team’s proven track record and focus on development of RNG projects gives us a strategic advantage in continuing to grow our business profitably. Our diverse experience and integration of key technical, environmental, and administrative support functions support our ability to design and operate projects with sustained and predictable cash flows.

Our experience and extensive project portfolio has given us access to the full spectrum of available biogas-to-RNG and biogas-to-Renewable Electricity conversion technologies. We are technology agnostic and base project design on the available technologies (and related equipment) most suitable for the specific

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application, including membranes, media, and solvent-based gas cleanup technologies. We are actively engaged in the management of each project site and regularly serve in engineering, construction management, and commissioning roles. This allows us to develop a comprehensive understanding of the operational performance of each technology and how to optimize application of the technology to specific projects, including through enhancements and improvements of operating or abandoned projects. We also work with key vendors on initiatives to develop and test upgrades to existing technologies.

We continually seek to optimize the highest-value use of our existing assets. Because our equipment is modular, it can be disassembled and redeployed from one site to another at a lower cost than new greenfield development. For example, when equipment capacity at an existing project is larger than needed and can be repurposed for newer sites with larger production and growth potential where that capacity can be more fully utilized. This can occur at older landfill sites that have limited or no acceptance of waste intake or at sites where fuel supply agreements have expired, but where the equipment still has sufficient remaining useful life.

Access to Development Opportunities

We have strong relationships throughout the industry supply chain from technology and equipment providers to feedstock owners, and RNG off-takers. We believe that the trust and strong reputation we have attained in combination with our understanding of the various and complex Environmental Attributes gives us a competitive advantage relative to new market entrants.

We leverage our relationships built over the past several decades to identify and execute new project opportunities. Typically, new development opportunities come from our existing relationships with landfill owners who value our long operating history and strong reputation in the industry. This includes new projects with or referrals from existing partners. These relationships include Waste Management and Republic Services, the two largest waste management companies in the United States, which operate ten of our 14 landfill sites. We are the leading third-party developer for Waste Management and operate projects on both private and publicly owned landfills. We actively seek to extend the term of our contracts at our project sites and view our positive relationships with the owners and managers of our host landfills as a contributing factor to our ability to extend contract terms as they come due. Additionally, as one of the largest producers of RNG from LFG, we also frequently receive RFPs from landfill owners for new biogas facilities at their landfills.

Finally, our prominence in the industry often makes us a preferred suitor for owners seeking to sell existing projects. Acquisition opportunities often come to our attention by direct communications with industry participants as well as firms marketing portfolios of project.

Large and Diverse Project Portfolio

We believe that we have one of the largest and most technologically diverse project portfolios in the RNG industry. Our ability to solve unique project development challenges and integrate such solutions across our entire project portfolio has supported the long-term successful partnerships we have with our landfill hosts. Because we are able to meet the varying needs of our host partners, we have a strong reputation and are actively sought out for new project and acquisition opportunities. Additionally, our size and financial discipline generally affords us the ability to achieve priority service and pricing from contractors, service providers, and equipment suppliers.

Environmental, Health and Safety and Compliance Leadership

Our executive team places the highest priority on the health and safety of our staff and third parties at our sites, as well as the preservation of the environment. Our corporate culture is built around supporting these priorities, as reflected in our well-established practices and policies. By setting and maintaining high standards in the renewable energy field, we are often able to contribute positively to the safety practices and policies of our

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host landfills, which reflects favorably on us with potential hosts when choosing a counterparty. Our high safety standards include use of wireless gas monitoring safety devices, active monitoring of all field workers, performing periodic EHS audits and using technology throughout our safety processes from employee training in compliance with operational processes and procedures to emergency preparedness. By extension, we incorporate our EHS standards into our subcontractor selection qualifications to ensure that our commitment to high EHS standards is shared by our subcontractors which provides further assurances to our host landfills. As of December 31, 2020, excluding two incidents related to COVID-19, our year-to-date TRIR was 0.865 which is lower than the 2019 national average of 1.20 TRIR for the mining, quarrying and oil and gas extraction industries and the 2019 national average of 3.00 TRIR for all industries. As of December 31, 2020, we have not received any U.S. OSHA or state OSHA citations in the last five years. Our EHS programs include partnering with Blackline Safety to provide each of our site employees with a four-gas monitoring device with work-anywhere wireless capabilities; emergency response protocols for all locations which include facility and landfill access, gate access, and site specific alerts to account for employee safety at all points throughout the workday; a learning management system that combines traditional online safety training and instructor-led training; and monthly evaluations for training compliance at each operations facility.

Our Strategy

We aim to maintain and grow our position as a leading producer of RNG in the United States. We support this objective through a multi-pronged strategy of:

• promoting the reduction of methane emissions and expanding the use of renewable fuels to displace fossil-based fuels;

• expanding our existing project portfolio and developing new project opportunities;

• expanding our industry position as a full-service partner for development opportunities, including through strategic transactions; and

• expanding our capabilities to new feedstock sources and technologies.

Promoting the Reduction of Methane Emissions and Expanding the Use of Renewable Fuels to Displace Fossil-Based Fuels

We share the renewable fuel industry’s commitment to providing sustainable renewable energy solutions and to offering products with high economic and ecological value. By simultaneously replacing fossil-based fuels and reducing overall methane emissions, our projects have a substantial positive environmental impact. We are committed to capturing as much biogas from our host landfills as possible for conversion to RNG. As a leading producer of RNG, we believe it is imperative to our continued growth and success that we remain strong advocates for the sustainable development, deployment and utilization of RNG to reduce our dependence on fossil fuels while increasing our domestic energy production.

Many of our team members have been involved in the renewable fuel industry for over 30 years. We are a founding member and active participant in the RNGC. The RNGC was formed to provide an educational platform and to be an advocate for the protection, preservation and promotion of the RNG industry in North America. The RNGC’s diverse membership includes each sector of the RNG industry, such as waste collection and management companies, renewable energy developers, engineers, bankers, financiers, investors, marketers, transporters, manufacturers, and technology and service providers. Our participation allows us to align with industry colleagues to better understand the challenges facing the industry and to collaborate with them to develop creative solutions to such problems.

As a founding member of the RNGC and participant in several RNGC technical committees, we regularly participate in conferences and regulatory initiatives, including lobbying, to address key issues and promote the RNG industry. Collaborating with the diverse RNGC membership provides us with a holistic view of the RNG

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industry, which aides us in identifying emerging trends and opportunities. Our participation allows us to align with industry colleagues to better understand the challenges facing the industry and to collaborate with them to develop creative solutions to such problems. A primary function of the RNGC is to educate those in the natural gas industry, including pipeline owners, who are not familiar with RNG and its fungibility with traditional pipeline natural gas. We are focused on maintaining and nurturing our relationships with pipeline off-takers and seek to ensure that such relationships are a priority, including by maintaining continuous communication, enforcing stringent real-time monitoring of our product quality, and providing marketing material to assist with their corporate sustainability messaging.

Expanding Our Existing Project Portfolio and Developing New Development Opportunities

We exercise financial discipline in pursuing projects by targeting project returns that are in line with the relative risk of the specific projects and associated feedstock costs, offtake contracts and any other related attributes that can be monetized. We are currently evaluating three project expansion opportunities at existing project sites and one new electricity-to-RNG conversion project. We regularly analyze several potential new projects that are at various stages of negotiation and review. The potential projects typically include a mix of new project sites, project conversions and strategic acquisitions. Currently, no new potential projects are subject to definitive agreements and each potential opportunity is subject to competitive market conditions.

Montauk Growth Channels

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. This has allowed us to maintain average production availability of approximately 76% at our RNG projects and 92% at our electricity projects, weighted by 2020 expected production, excluding projects that commenced operation in 2020. Additionally, we are evaluating opportunities to utilize excess gas for RNG production at some of our electricity projects. Most recently, we increased the gas production at our McCarty project by 7% through an expansion project completed in January 2018, as described below.

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 across our entire project portfolio quickly, including advances with respect to troubleshooting, optimization, cost savings, and host site interaction. For example, we recently

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were able to take advantage of findings from a root cause failure analysis on a particular piece of equipment at a single project site to improve maintenance on similar equipment throughout our portfolio. We frequently identify services that result in a positive reaction from our project partners and then communicate that to other project managers so that they can incorporate such services into their project sites. Our integrated, pro-active and value-add approach helps us maintain strong relationships with our partners, which can often lead to term extensions and new opportunities.

We also experience organic growth in production at our existing projects because of increases in biogas supply at our projects and continued operation optimization. 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 expansion efforts to date, such as those at McCarty and Rumpke, 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 these projects achieved an initial increase in production following the expansion project, but we also expect to see continued gradual increases over time.

Case Study of an Expansion Project: McCarty Landfill: The McCarty landfill is owned and operated by Republic Services and is one of the largest waste disposal facilities in Texas. Our RNG project at this landfill was originally constructed as a 3,892 MMBtu/day facility that achieved commercial operations in 1986. In January 2018, we undertook and completed an expansion of the project to increase RNG production by 7%, to a design capacity of 4,415 MMBtu at a cost of $2.1 million. The expansion effort added blower capacity, which increased the inlet pressure to the main compressors leading to higher production. The increased output from the project did not require amendments to our existing fuel supply and off-take agreements. Prior to commissioning the expansion, we applied for and obtained the necessary permits and other approvals to expand the project and the interconnects that we relied upon at this project. Engineering and design activities began in February 2017, with construction beginning in August 2017 and commissioning in November 2017.

Expanding through Acquisition. The RNG industry is highly fragmented with approximately 90% of operating projects owned by companies that own five or fewer projects. We believe that these small project portfolios present opportunity for 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 11 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, industry position and access to capital will provide us with increased acquisition opportunities.

Converting Existing 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. This strategy has been an increasingly attractive avenue for growth since 2014 when RNG from landfills became eligible for D3 RINs. Historically, we have taken advantage of these opportunities on a gradual basis as PPAs for our electricity projects have expired. To date, we have converted two projects from LFG-to-electricity to LFG-to-RNG and one project from ADG-to-electricity to ADG-to-RNG, and we are currently evaluating a fourth conversion opportunity for LFG-to-RNG.

Looking forward, several of our development and pipeline projects may convert existing electricity projects to RNG. For example, the existing generation facilities at the Coastal Plains project, which currently sells merchant power and RECs into the Electric Reliability Council of Texas market, was shut down in May 2019 and was converted to an RNG production facility with commercial operations that commenced in September 2020.

Case Study of a Conversion Project: Atascocita Landfill: We acquired the Atascocita project, an LFG-to-electricity project located in Humble, Texas, from Viridis Energy (Texas), LP in 2011. The Atascocita

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landfill is owned and operated by Waste Management. Electricity produced by the facility was sold on a merchant basis into the Electric Reliability Council of Texas market. Recognizing an opportunity to realize returns on favorable pricing for RNG and RIN attributes, we approached Waste Management about converting the project to RNG in 2016. We signed an updated gas supply agreement with Waste Management in October 2016, which included a royalty based on the monetization of Environmental Attributes, including RINs and LCFS credits. Construction was managed in-house and completed over 19 months after the gas supply agreement was signed, with the project achieving commercial operations in May 2018, making it one of the largest plants constructed for processing RNG. All of these aspects required unique design and implementation along with cooperation from Waste Management in order to meet regulatory requirements.

New equipment installed includes membrane separation, nitrogen removal, deoxygenation, and H2S removal technologies. The repurposed facility has a design capacity of 5,570 MMBtu/day. Known vendors and suppliers were used to procure the majority of equipment and systems. As such, timely ordering and delivery of equipment was achieved relative to the construction schedule. The total capital expenditures to convert Atascocita were approximately $40 million. The project has a remaining fuel supply contract with Waste Management for 20 years from commercial operation.

Leveraging and Creating Long-Term Relationships. Dependable and economic sources of renewable methane are critical to our success. Our projects provide our landfill and livestock farm partners with a variety of benefits, including a means to monetize biogas from their sites and support their regulatory compliance. By addressing the management of byproducts of our project hosts’ primary businesses, our services allow landfill owners and operators and livestock farms to increase their permitted landfill space and livestock count, respectively. These services facilitate long-term relationships with project hosts that may serve as a source for future projects and relationships.

Expanding Our Industry Position as a Full-Service Partner for Development Opportunities, Including Through Strategic Transactions

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.

Expanding Our Capabilities to New Feedstock Sources and Technologies

We intend to diversify our project portfolio beyond landfill biogas 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 livestock waste project (dairy), actively pursuing new fuel supply opportunities in WRRFs, and looking at long-term organic waste and sludge opportunities. 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, and we believe this trend will provide long-term growth opportunities.

We believe that the market has not yet unlocked the full potential of RNG and Renewable Electricity. We do not own any material registered intellectual property. However, as 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, such as providing fuel for the production of energy sources. With our experience and industry expertise, we are well-positioned to take advantage of opportunities to meet the clean energy needs of other industries looking to use renewable energy in their operations.

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Products Sold

The revenues received 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. The second component is from the Environmental Attributes derived from the production of RNG and Renewable Electricity. For RNG, Environmental Attribute revenues are substantially generated from RINs when used as a transportation fuel. In addition, RNG can generate an additional revenue stream when used as a transportation fuel in states that have adopted low-carbon fuel incentive programs. 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.

RNG

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 can be used for transportation fuel when compressed (CNG) or liquefied (LNG) and virtually all of the RNG we produce is used in this manner.

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.

RNG is priced in line with the wholesale natural gas market, based on Henry Hub pricing, with regional variation according to demand and supply issues. 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 our off-take counterparties as consideration for the counterparty using our RNG as a transportation fuel.

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, with 2013 output at only 281,819 gallons (422,740 RINs). This prompted the EPA to expand the definition of biofuels that could qualify for D3 RINs in July 2014, 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 505 million net RINs in 2021. 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 are set annually as the greater of (i) $0.25 or (ii) $3.00 (as adjusted by Consumer Price Index) less the average wholesale price of gasoline for the most recent 12-month period of data available as of September 30th prior to the calendar year in question. CWC prices are typically published by the EPA each November, with an announced CWC price for 2020 of $1.80. 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.

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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 CA LCFS credit. RNG from LFG and livestock digester biogas that are used as a transport 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 currently earn CA LCFS credits on seven of our projects, 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. 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.

Renewable Electricity

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 credit-worthy counterparties, typically under a fixed price with escalators. The terms of these contracts range from 5 to 22 years, with a weighted average remaining tenure of 14 years, based on 2021 expected electricity production.

RECs

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 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 and other renewable attributes bundled with the power being sold at

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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.

Our Projects

We currently own and operate 15 projects, 12 of which are RNG projects and three of which are Renewable Electricity projects. Of our three Renewable Electricity projects we currently operate, we expect to convert one of them to produce RNG. In addition to the electricity-to-RNG conversion project, we are currently in the process of developing one additional 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.

Renewable Electricity Generation
Site	COD (1)	Capacity (MW)	Source
Bowerman Irvine, CA	2016	23.6	Landfill
Security Houston, TX	2003	3.4	Landfill
AEL Sand Spring, OK	2013	3.2	Landfill
Total Capacity (MW)		30.2

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

	=  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 19 years.

(4) Pico was converted from a Renewable Electricity project to an RNG project as of August 2020. Pico is now reported under our Renewable Natural Gas segment as of October 2020.

We have a long history of operating our projects with partners, with our oldest relationship going back 46 years. On average, we have had an 18-year history with our current project site owners. Our operating RNG

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projects have an average expected remaining useful life of approximately 19 years, as weighted by 2021 expiration. Our operating electricity projects have an average expected remaining useful life of approximately 14 years, as weighted by 2021 expected expiration.

Approximately 93% of our 2020 RNG production has been monetized under fuel supply agreements with expiration dates more than 15 years from December 31, 2020. Additionally, approximately 96% of our 2020 Renewable Electricity production has been monetized under fuel supply agreements with expiration dates more than 15 years from December 31, 2020. 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 are currently restoring a fifth facility.

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.

An RNG project involves the conversion of raw LFG into pipeline quality gas for introduction to a natural gas transmission or distribution line. An RNG plant processes the gas by removing the majority of the non-methane components including carbon dioxide, water, and other volatile and non-volatile organic compounds to attain pipeline quality gas. This complex process has numerous variables that need to be managed in order to be cost-effective and efficient. At the end of the gas processing chain, RNG is typically compressed and then sold into a natural gas pipeline or to a dedicated end user. These sales occur at market prices for the energy and the value of the Environmental Attributes derived from the use of the RNG as a transportation fuel.

Our 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 also have historically used the other proven technology, refrigerated physical absorption, commonly referred to as Kryosol; however, it is not in use at any of our existing operating projects. All four of these technologies have similar features, but are distinguished primarily by the means employed to separate carbon dioxide from methane in biogas. 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.

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. The electricity is metered and sold under long-term contracts to utilities and municipalities or at spot prices.

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 operate in this fashion. Our larger projects are at or near design capacity and either have expansions planned or are being evaluated for future expansions dependent on the availability of excess biogas feedstock.

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RNG Projects

We currently own and operate 12 RNG projects in Ohio (two), Pennsylvania (five), Texas (four) and Idaho (one) which, in the aggregate, have a total design capacity of approximately 33,850 MMBtu/day, which equates to 624,000 tons of carbon dioxide emission reduction annually over using fossil fuels, or the equivalent of the carbon dioxide emissions from consuming approximately 1,940,000 gallons of gasoline per day.

RNG Projects

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

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

Typically, a biogas-to-RNG facility includes three phases: biogas collection, primary processing and additional processing.

At landfills, biogas collection systems can be configured as vertical wells or horizontal trenches. The most common method is drilling vertical wells into the waste mass and connecting the wellheads to lateral piping that transports the gas to a collection header using a blower or vacuum induction system. Horizontal trench systems are useful in areas of landfills that continue to have active filling. Some landfills use a combination of vertical wells and horizontal collectors. Collection system operators “tune” or adjust the wellfield to maximize the volume and quality of biogas collected while maintaining environmental compliance.

A basic biogas processing plant includes a knock-out drum to remove moisture, blowers to provide a vacuum to “pull” the gas and pressure to convey the gas, and a flare. System operators monitor parameters to maximize system efficiency. Using biogas in an energy recovery system usually requires some treatment of the gas to remove excess moisture, particulates, and other impurities. The type and extent of treatment depends on site-specific biogas characteristics and the type of energy recovery system. Treatment of the gas typically includes the removal of hydrogen sulfide (H2S), moisture and contaminants within the gas, and then separation of the carbon dioxide (CO2) from the methane (CH4). Further treatment of the biogas is often required to remove residual nitrogen and/or oxygen to meet pipeline specifications. Some end uses, such as pipeline injection or vehicle fuel projects, require additional cleaning and compression of the biogas.

Illustrative Projects

Rumpke. The Rumpke landfill, located in Cincinnati, Ohio, is an open landfill with significant filling capacity available. The landfill, which is our largest site by capacity, currently holds approximately 62 million tons of waste, receives over 10,000 tons of waste per day and is expected to operate through 2052 under its

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current permits. The landfill has filed for a new MSW permit to expand its footprint. The MSW permit includes a Land-GEM model that anticipates the landfill accepting waste through 2085.

At this site, we own and operate a 15 million standard cubic feet per day (“SCFD”) RNG processing facility using PSA technology. The facility consists of one, six million SCFD plant that was placed into service in 1985, one, five million SCFD plant that was placed into service in 2007 and one, three million SCFD plant that was placed into service in 1994. Pursuant to a fuel supply agreement with the owner of the landfill, we have fuel for this project through December 31, 2037. We are responsible for operation, maintenance and costs of this site’s biogas collection system.

The Rumpke project is registered with the EPA as a qualified facility for the generation of RINs under the RFS program and with CARB as a qualified facility for the generation of CA LCFS credits for fuel generated for use as a transportation fuel. We currently sell the RNG and Environmental Attributes produced at this facility at a fixed price. The fixed price is supplemented by sharing of incremental revenues from monetization of the Environmental Attributes under a margin sharing agreement.

Atascocita. The Atascocita landfill, located in Humble, Texas, is an open landfill with approximately 25.3 million tons of capacity available. The landfill currently holds approximately 36.4 million tons of waste, receives over 3,600 tons of waste per day and is expected to operate through 2045 under its current permits.

At this site, we shut down a merchant electricity project that was only able to process a portion of the gas the site was producing and repurposed it to an RNG project where we own and operate a 10.8 million SCFD RNG processing facility using membrane separation technology. The project was placed into service in May 2018. The plant is equipped with membrane separation, nitrogen removal, deoxygenation, and H2S removal technologies. Pursuant to a fuel supply agreement, we have fuel supply for this project through May 1, 2038. We are responsible for the operation, management and capital costs of the processing facility.

The Atascocita project is registered with the EPA as a qualified facility for the generation of RINs under the RFS program and for fuel generated for use as a transportation fuel. We currently sell the RNG produced at this facility at market prices under contract through 2023, and separately sell the RINs produced to Obligated Parties on either a spot or forward basis based on current calendar year.

McCarty. The McCarty landfill, located in Houston, Texas, is an open landfill that holds approximately 62.4 million tons of waste, receives approximately 4,573 tons per day, has been in operation since 1967 and is expected to operate through 2024 under its current permits.

At this site, we own and operate a nine million SCFD RNG gas processing facility that employs Selexol, a solvent scrubbing based gas separator technique.

Pursuant to a fuel supply agreement, we have fuel supply for this project through December 31, 2036, and we are responsible for the operation, management and capital costs of the LFG collection system.

The McCarty project is registered with the EPA as a qualified facility for the generation of RINs under the RFS program and with CARB as a qualified facility for the generation of CA LCFS credits. We currently sell the RNG produced at this facility at market prices under a contract extending through January 31, 2024, and separately sell the RINs produced to Obligated Parties on either a spot or forward basis based on current calendar year.

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, which equates to

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175,600 tons of carbon dioxide emission annually over using fossil fuels, or the equivalent of the carbon dioxide emissions from consuming approximately 469,000 gallons of gasoline per day. During 2020, our Renewable Electricity projects collectively produced 0.2 MWh. Our Renewable Electricity projects utilize reciprocating engine generator sets to generate electricity at landfills.

Renewable Electricity Projects

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

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

(2) Beginning in October 2020, we reported the result of operations of Pico within RNG.

Illustrative Projects

Bowerman Power. The Bowerman Power Facility, located in Irvine, California, is an open landfill with over 54 million tons of waste, receives approximately 6,800 tons of waste per day, has been in operation since 1990, and is expected to operate through 2053 under its current permits.

At this site, we own and operate a 19.6 MW (net) electricity generation facility which consists of seven CAT CG-260-16 reciprocating engine generator sets. The Bowerman facility is located in the southern part of the California Independent System Operator (“CAISO”) Regional Transmission Organization. CAISO is a regional transmission organization (“RTO”) that coordinates the movement of wholesale electricity in all or parts of California and Nevada. CAISO acts as a neutral, independent party that operates a competitive wholesale electricity market and manages the high-voltage electricity grid. CAISO provides an attractive and ready market for energy, capacity and RECs for new and existing resources.

Bowerman’s electricity output is sold under a PPA with the City of Anaheim, California, with a term running through 2036. Pursuant to a fuel supply agreement with the owner of the landfill, we have fuel supply for this project through 2067.

New Projects

Much of our historic growth has come from the addition of new projects either through third-party acquisitions or new development. We plan to leverage both of these avenues for growth as we seek to continue to expand our business. We exercise financial discipline in pursuing these projects by targeting project returns that are in line with the relative risk of the specific projects and associated feedstock costs, offtake contracts and any other related attributes that can be monetized. We are currently evaluating project expansion opportunities at existing project sites and a new electricity-to-RNG conversion project. We regularly analyze several potential new projects that are at various stages of negotiation and review. The potential projects typically include a mix of new project sites, project conversions and strategic acquisitions. As of March 15, 2021, no new potential projects are subject to definitive agreements and each potential opportunity is subject to competitive market conditions.

Acquisition of Existing Projects

Pursuing opportunities for acquisitions of existing projects has and continues to be a key component of our growth strategy. Small project portfolios present the opportunity for industry consolidation that we believe we

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are well-positioned to take advantage of because of our scale, operational efficiency, execution track record and technological flexibility. In evaluating new opportunities, we often look for underperforming projects or underutilized sites where we can leverage our premier operational platform to optimize efficiency at these facilities. As we continue to acquire new projects, we have the ability to improve synergies across our portfolio that we believe give us an advantage over other LFG operators and new entrants into the industry.

While new project and acquisition opportunities exhibit attractive processable biomethane quantities, we are experienced in both understanding the common deviations between feedstock projections (both in quantity and quality), and the best approach to plan and execute on development investments in making those projections reality. In evaluating a potential project, we evaluate whether there is economically viable access to an interconnection. We use our experience in the complexities of interconnection study and design, the securitization of rights-of-way, oversight of utility construction and self-construction of pipeline and electrical interconnections to determine economic viability. In addition to interconnection experience, our experience in detailed and scheduled preventative maintenance allows us to develop realistic operating cost projections for greenfield and other acquisition project opportunities at their onset.

In particular, a major focus area for us is the acquisition of existing LFG-to-electricity projects that we can convert to RNG. We look for opportunities where existing operators have a PPA with a limited remaining contract life or are selling power on a merchant basis and where sites are located close to existing natural gas pipelines. We believe we have a competitive advantage in pursuing these opportunities because of our strong track record as an RNG producer. Cleaning up biogas for use as RNG is a significantly more involved process than electricity production. There are few others that have the capabilities that we have to tune wellfields to process gas in the manner needed to produce pipeline-quality RNG. As a result, we are well-positioned to acquire these projects where the existing operator is not positioned to pursue the technology conversion on their own and merchant electricity prices do not support continued operation of the electricity facility.

Much of our historic growth has been achieved through acquisitions and our management team has significant experience in identifying, executing, closing and integrating acquisitions. Most recently, we closed on an acquisition of an existing anaerobic digester and Jenbacher engines at a large commercial dairy farm in Idaho. The project was converted to an RNG facility in order to sell transportation fuel into the California transportation market and began commercial operation in August 2020.

Our operational capabilities across a broad array of gas clean-up and electricity generation technologies, including solvent scrubbing, PSA, membrane separation, reciprocating engines, and turbines, gives us flexibility to pursue a variety of potential projects. We have strong relationships with most major industry vendors and landfill owners. We believe we can use these existing relationships and our reputation in the industry to identify potential transactions and to minimize concerns about a change of the operator of a biogas project.

Greenfield Development

We are always looking for opportunities to expand our portfolio through new projects that we can design, build, own and operate at greenfield sites. A significant portion of our pipeline for new development comes from our existing relationships with landfill owners who value our long operating history and strong reputation in the industry. This includes new projects with existing partners as well as projects we have sourced through referrals from existing partners. For example, our Apex project, which was completed in 2019, came to us through our existing relationship with the landfill owner.

As one of the largest producers of RNG from LFG, we also frequently receive RFPs from landfill owners for new biogas facilities at their landfills. We exercise financial discipline in pursuing these projects by targeting project returns that are in line with the relative risk of the specific projects and associated feedstock costs, offtake contracts and any other related attributes that can be monetized.

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With our broad geographic footprint, we believe we are well-positioned to take advantage of opportunities in states where we currently operate. Although we believe that many of the EPA identified candidate landfills are not currently economically viable, approximately 40% of the these sites that we have identified as potentially economically viable are located in states in which we currently operate and we believe, due to our industry experience and technical knowledge, we will continue to be able to identify potentially economically viable sites in these locations in the future. Additionally, we also currently operate in three of the top four states with the largest biogas production potential from livestock farms. Our geographic footprint strategically positions us to take advantage of these opportunities given our existing relationships with operators, vendors and regulators, and our ability to realize operational synergies with nearby projects.

New Sources of Fuel Supply

Historically, our business has grown through new LFG projects. While we will continue to pursue LFG opportunities, we also anticipate projects that utilize other sources of fuel supply, including livestock farms and WRRFs, as major opportunities to further expand and diversify our footprint.

Dairy

We view dairy farms as a significant opportunity for us to expand our RNG business. Processing biogas from dairy farms requires similar expertise and capabilities as processing biogas from landfills. Meanwhile, 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.

The presence of our digester benefits dairy farmers in a number of ways, creating a mutually beneficial relationship. We assist in managing the waste for the dairy farmer, which they would otherwise have to manage. Additionally, processing this waste in a digester is significantly more environmentally friendly by reducing GHG emissions. Finally, a byproduct of the production process can be returned to farmers for use as bedding, alleviating the need to purchase other materials for bedding for the cows.

We undertook a dairy farm 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 have developed an RNG facility at this project that came online in August 2020. The facility sells transportation fuel into the California transportation market.

Other Waste Sources

Our long-term strategy is to continue to seek new opportunities for biogas processing with alternative sources of fuel supply as we have done recently with our entrance into the dairy farm biogas industry. Other industries that present opportunities of scale for biogas conversion include swine farms and WRRFs. Similar to 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.

Fuel Supply Agreements

A critical component of our business is our ability to negotiate and maintain long-term fuel supply agreements. We have developed strong working relationships with our landfill site owners, including ten of

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14 operating projects and one development project 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 dairy farm 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.

Fuel Supply Agreement Summary

RNG Projects

Fuel Supply Agreement Expiration Dates	Current Sites as of December 31, 2020		% of 2020 Total RNG Production
Within 0-5 years		0		0.0	%
Between 6-15 years		3		6.9	%
Greater than 15 years(1)		9		93.1	%

Renewable Electricity Projects

Fuel Supply Agreement Expiration Dates	Current Sites as of December 31, 2020		% of 2020 Total Renewable Electricity Production
Within 0-5 years		0		0.0	%
Between 6-15 years		1		4.2	%
Greater than 15 years(1)		3		95.8	%

(1) Our Pico project is included in both RNG and Renewable Electricity fuel supply agreements due to its conversion from a Renewable Electricity site to an RNG site in August 2020.

Each of our RNG projects in development has a contract length of 20 years from commencement of commercial operation, except for Pico, which has a contract length of 20 years from the date of the fuel supply agreement. Our fuel supply agreement expiration dates account for contract extensions at our option. 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.

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. For 2020, our sales to Royal Dutch Shell plc represented approximately 14.1% of our operating revenues. We sell RNG and Environmental Attributes to Royal Dutch Shell plc at a fixed price, which is supplemented by sharing of incremental revenues from monetization of the Environmental Attributes under a margin sharing agreement. Further, Victory Renewables, LLC and Exxon Mobil each represented approximately 11.3% and 15.1%,

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respectively, of our operating revenues in 2020 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 off-take counterparties 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 14.4% of our operating revenues in 2020. These sales occurred under a PPA between us and the City of Anaheim, in which electricity and RECs are sold at fixed prices. By the end of 2020, 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 2020 operating revenues.

Suppliers and Equipment Vendors

We use a variety of technological means to operate facilities that produce RNG and electricity from raw biogas collected from landfills and digesters. This affords Montauk experience with substantially all major vendors in the sector, and technical expertise in numerous technologies.

The major technologies used by our projects for gas processing include solvent scrubbing PSA, and membrane separation. For electricity generation, we use reciprocating engines and gas turbines.

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, 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, CAT, 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 a number of 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.

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The biogas market is heavily 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 Aria Energy and Morrow Renewables, 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.

Governmental Regulation

Each of our projects is subject to federal, state and local air quality, solid waste, and water quality regulations and permitting requirements. Specific construction and operating permit requirements may differ among states. Specific permits we frequently must obtain when developing our projects include: air permits, nonhazardous waste management permits, pollutant discharge elimination permits, and beneficial use permits. Our existing projects must also maintain compliance with relevant federal, state and local environmental, health and safety requirements.

Our RNG projects are subject to federal RFS program regulations, including the EPACT 2005 and EISA. 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.

The CAA regulates emissions of pollutants to protect the environment and public health and contains provisions for New Source Review (“NSR”) permits and Title V permits. New biogas projects may be required to obtain construction permits under the NSR program. The combustion of biogas results in emissions of carbon monoxide, oxides of nitrogen, sulfur dioxide, volatile organic compounds and particulate matter. The CAA and state and local laws and regulations impose significant monitoring, testing, recordkeeping and reporting

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requirements for these emissions. Requirements vary for control of these emissions, depending on local air quality. Applicability of the NSR permitting requirements will depend on the level of emissions resulting from the technology used and the project’s location. Many biogas projects must obtain operating permits that satisfy Title V of the 1990 CAA Amendments. The operating permit describes the emission limits and operating conditions that a facility must satisfy and specifies the reporting requirements that a facility must meet to show compliance with all applicable air pollution regulations. A Title V operating permit must be renewed every five years. Even when a biogas project does not require a Title V permit, the project may be subject to other federal, state and/or local air quality regulations and permits.

In addition, our operations and the operations of the landfills at which we operate may be subject to New Source Performance Standards and emissions guidelines, pursuant to the CAA, applicable to municipal solid waste landfills and to oil and gas facilities. Among other things, these regulations are designed to address the emission of methane, a potent GHG, into the atmosphere.

Before an RNG project can be developed, all Resource Conservation and Recovery Act (“RCRA”) Subtitle D requirements (requirements for nonhazardous solid waste management) must be satisfied. In particular, methane is explosive in certain concentrations and poses a hazard if it migrates beyond the project boundary. Biogas collection systems must meet RCRA Subtitle D standards for gas control. RNG projects may be subject to other federal, state and local regulations that impose requirements for nonhazardous solid waste management.

Certain biogas projects may be subject to federal requirements to prepare for and respond to spills or releases from tanks and other equipment located at these projects and provide training to employees on operation, maintenance and discharge prevention procedures and the applicable pollution control laws. At such projects, we may be required to develop spill prevention, control and countermeasure plans to memorialize our preparation and response plans and to update them on a regular basis.

Our operations may result in liability for hazardous substances or other materials placed into soil or groundwater. Pursuant to the Comprehensive Environmental Response, Compensation and Liability Act of 1980 or other federal, state or local laws governing the investigation and cleanup of sites contaminated with hazardous substances, we may be required to investigate and/or remediate soil and groundwater contamination at our projects, contiguous and adjacent properties and other properties owned and/or operated by third parties.

Additionally, biogas projects may need to obtain National Pollutant Discharge Elimination System permits if wastewater is discharged directly to a receiving water body. If wastewater is discharged to a local sewer system, biogas projects may need to obtain an industrial wastewater permit from a local regulatory authority for discharges to a Publicly Owned Treatment Works. The authority to issue these permits may be delegated to state or local governments by the EPA. The permits, which typically last five years, limit the quantity and concentration of pollutants that may be discharged. Permits may require wastewater treatment or impose other operating conditions to ensure compliance with the limits. In addition, the Clean Water Act and implementing state laws and regulations require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

FERC

The Federal Energy Regulatory Commission (“FERC”) regulates the sale of electricity at wholesale and the transmission of electricity in interstate commerce pursuant to its regulatory authority under the FPA. FERC also regulates certain natural gas transportation and storage facilities and services, and regulates the rates and terms of service for natural gas transportation in interstate commerce under the Natural Gas Act and the Natural Gas Policy Act.

With respect to electricity transmission and sales, FERC’s jurisdiction includes, among other things, authority over the rates, charges and other terms for the sale of electricity at wholesale by public utilities (entities

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that own or operate projects subject to FERC jurisdiction) and for transmission services. With respect to its regulation of the transmission of electricity, FERC requires transmission providers to provide open access transmission services, which supports the development of competitive markets by assuring nondiscriminatory access to the transmission grid. FERC has also encouraged the formation of RTOs to allow greater access to transmission services and certain competitive wholesale markets administered by ISOs and RTOs.

In 2005, the U.S. federal government enacted the EPACT 2005 conferring new authority for FERC to act to limit wholesale market power if required and strengthening FERC’s civil penalty authority (including the power to assess fines of up to $1.0 million per day per violation), and adding certain disclosure requirements. EPACT 2005 also directed FERC to develop regulations to promote the development of transmission infrastructure, which provides incentives for transmitting utilities to serve renewable energy projects and expanded and extended the availability of U.S. federal tax credits to a variety of renewable energy technologies, including wind power. EPACT 2005’s market conduct, penalty and enforcement provisions also apply to fraud and certain other misconduct in the natural gas sector.

Qualifying Facilities

PURPA established a class of generating facilities that would receive special rate and regulatory treatment, termed qualifying facilities (“QFs”). There are two categories of QFs: qualifying small power production facilities and qualifying cogeneration facilities. A small power production facility is a generating facility of 80 MW or less whose primary energy source is hydro, wind, solar, biomass, waste, or geothermal. A cogeneration facility is a generating facility that produces electricity and another form of useful thermal energy (such as heat or steam) in a way that is more efficient than the separate production of both forms of energy. QFs are generally subject to reduced regulatory requirements. Small power production facilities up to 20 MW are exempt from rate regulation under Sections 205 and 206 of the Federal Power Act. Each of our three Renewable Electricity projects has been certified as a QF by FERC.

In addition, PUHCA provides FERC and state regulatory commissions with access to the books and records of holding companies and other companies in holding company systems. It also provides for the review of certain costs. Companies that are holding companies under PUHCA solely with respect to one or more exempt wholesale generators, QFs or foreign utilities are exempt from these PUHCA books and records requirements.

State Utility Regulation

While federal law provides the utility regulatory framework for our sales of electricity at wholesale in interstate commerce, there are also important areas in which state regulatory control over traditional public utilities that fall under state jurisdiction may have an effect on our projects. For example, the regulated electricity utility buyers of electricity from our projects are generally required to seek state public utility commission approval for the pass through in retail rates of costs associated with PPAs entered into with a wholesale seller. Certain states, such as New York, regulate the acquisition, divestiture, and transfer of some wholesale power projects and financing activities by the owners of such projects. California, which is one of our markets, requires compliance with certain operations and maintenance reporting requirements for wholesale generators. In addition, states and other local agencies require a variety of environmental and other permits.

State law governs whether an independent generator or power marketer can sell retail electricity in that state, and whether gas can be sold by an entity other than a traditional, state-franchised gas utility. Some states, such as Florida, prohibit most sales of retail electricity except by the state’s franchised utilities. In other states, such as New Jersey and Pennsylvania, an independent generator may sometimes sell retail electricity power to a co-located or adjacent business customer, and a gas supplier can sometimes make on-premises or adjacent-premises gas deliveries to a single plant or customer. Some states, such as Massachusetts and New York, permit retail power and gas marketers to use the facilities of the state’s franchised utilities to sell power and/or gas to retail customers as competitors of the utilities.

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Independent System Operators and Regional Transmission Organizations

The bulk electricity transmission system and the electricity markets in several geographic regions of the U.S. are operated by FERC-regulated ISOs and RTOs. Each of the ISOs/RTOs established the market design, market rules, tariffs, cost allocations and bidding rules to which its market participants are subject. There is also a separate ISO in an entirely intrastate market in a portion of Texas that is not directly subject to FERC regulation under the FPA.

ISO/RTO market participants include traditional utilities that own transmission and distribution facilities and sell power to retail customers; transmission and distribution utilities within an ISO/RTO market turn control over their facilities over to the ISO/RTO. ISO/RTO market participants also include independent generating companies that produce and sell electricity to other market participants who in turn typically re-sell the electricity; municipal and cooperative utilities that distribute and sell electricity to customers in their service territories; power management businesses that engage in load reduction and provide power management contract services; and power marketers that engage in power trading and re-sales from generation assets owned or operated by others.

Each ISO/RTO provides transmission service over the facilities of the ISO/RTO’s member utilities that the ISO/RTO controls but does not own, and operates the wholesale power sales markets in the ISO/RTO region. The ISOs/RTOs work with their members and stakeholders to develop their own market rules, market clearing practices, pricing rules including floors and ceilings on electricity prices, and establish eligibility requirements for market participation, subject to review and approval by FERC. Bulk power transmission within the ISO/RTO regional markets is available only from the ISOs/RTOs acting on behalf of transmission-owning utilities.

RNG Production and Sale

Our projects typically convert biogas to RNG for sale as a fuel product. 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. 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. Purely local gas sales not utilizing FERC-regulated or certificated facilities are typically not subject to FERC gas regulation. The local distribution of gas to end-use customers by a state-regulated gas utility is also typically outside the scope of FERC’s gas regulatory jurisdiction. The opening and operation of a landfill or dairy farm that is expected to produce gas does not ordinarily require a FERC certificate or the acceptance by FERC of a gas tariff.

Future Regulations

The regulations that are applicable to our projects vary according to the type of energy being produced and the jurisdiction of the facility. As part of our growth strategy, we are looking to grow by pursuing development and acquisition opportunities. Such opportunities may exist in jurisdictions where we have no current operations and, as such, we may become exposed to different regulations for which we have no experience. Some states periodically revisit their regulation of electricity and gas sales. Other states, such as South Carolina and Florida, have adhered to traditional exclusive franchise practices, and in these and other states most electricity and gas customers may receive service only from a utility that holds an exclusive geographic franchise to provide service at that customer’s location. In some states that have experienced energy price hikes or market volatility, such as New York and California, investments in expanding facilities or buying or building additional facilities may be subject to changing regulatory requirements that may encourage competitive market entry.

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Effect of Existing or Probable Government Regulations on Our Business

Our business is affected by numerous laws and regulations on the international, federal, state and local levels, including energy, environmental, conservation, tax and other laws and regulations relating to our industry. Failure to comply with any laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respect with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive an effect on our operations than on other similar companies in our industry. We do not anticipate any material capital expenditures to comply with international, federal and state environmental requirements.

Employees and Human Capital Resources

We have approximately 115 full time professionals as of December 31, 2020. None of our employees are subject to any collective bargaining agreements.

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 maintain key recruitment and retention strategies. These include competitive salary structures, including bonus compensation programs, and competitive benefits policies, including paid time off for vacations, sick leave and holidays, short-term and long-term disability coverage, group term life insurance, tuition reimbursement for job-related education and training, and various retirement savings and incentive plans.

Safety of our personnel is a core value of Montauk and maintaining a safe work environment is critical to an energy company’s ability to attract and retain employees. As described in “Risk Factors,” to support the health and safety of our employees due to the COVID-19 pandemic, we have enhanced our safety protocols by arranging shifts at facilities to stagger employees to ensure social distancing, implemented more extensive cleaning and sanitation processes for both facilities and office spaces, incorporated temperature checks, required facial covering, instituted employee and visitor fitness questionnaires, restricted corporate travel and visitor access to sites and implemented work-from-home and work-flex initiatives for certain employees. We also established the IDRC to lead the development and implementation of such policies and to oversee the Company’s response to any infectious disease event. See “Our Strengths—Environmental, Health and Safety and Compliance Leadership” for a description of our employee-level EHS programs.

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 7A.–Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report.

Corporate Information

Montauk Renewables, Inc. was originally incorporated in the State of Delaware on September 21, 2020. Our principal executive offices are located at 680 Andersen Drive, 5th Floor, Pittsburgh, PA 15220. Our telephone number is (412) 747-8700.

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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 “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. Copelyn and Theventheran G. Govender, own approximately 53.1% 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 “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 prospectus, 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 30, 2021).

Name	Age		Position
Sean F. McClain		46	President and Chief Executive Officer, Director
Kevin A. Van Asdalan		43	Treasurer and Chief Financial Officer
James A. Shaw		49	Vice President of Operations
Scott Hill		54	Vice President of Business Development
John Ciroli		50	Vice President, General Counsel and Secretary

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 has also served as a member of the Board of Directors of MNK since August 2014 and as its President and Chief Executive Officer since September 2019. Prior to such roles, Mr. McClain served as MNK’s Chief Financial Officer from August 2014 until September

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2019. 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 is a Certified Public Accountant.

Kevin A. Van Asdalan. Mr. Van Asdalan has served as our Chief Financial Officer since January 4, 2021. He also has also served as a member of the Board of Directors of MNK since September 2019, and as Chief Financial Officer of MEH since that time. He previously served as 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 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.

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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.

COVID-19 Risks

The COVID-19 pandemic has had, and is expected to continue to have, an adverse effect on our business, financial condition and results of operations.

In December 2019, there was an outbreak of a novel strain of coronavirus (“COVID-19”) in China that has since spread to nearly all regions of the world. The outbreak was subsequently declared a pandemic by the World Health Organization in March 2020. To date, the COVID-19 pandemic and preventative measures taken to contain or mitigate the pandemic have caused, and are continuing to cause, business slowdowns or shutdowns in affected areas and significant disruptions in the financial markets both globally and in the United States.

In response to the COVID-19 pandemic and related mitigation measures, we began implementing changes in our business in March 2020 to protect our employees and customers, and to support appropriate health and safety protocols. For example, we arranged shifts at facilities to stagger employees to assist with following social distancing protocols, utilized overnight and weekend remote facility monitoring during normal operating shifts, implemented extensive cleaning and sanitation processes for both facilities and office spaces, incorporated temperature checks and facial covering requirements, instituted employee and visitor fitness questionnaires, restricted corporate travel and visitor access to sites and implemented work-from-home initiatives for certain employees. Further, we established the Infectious Disease and Response Committee (the “IDRC”) to lead the development and implementation of Montauk’s Infectious Disease and Response Plan and to oversee the company’s response to any infectious disease event. These measures resulted in additional costs, which we expect will continue through 2021 as we continue to work to address employee safety.

Although we are unable to predict the ultimate effects of the COVID-19 pandemic at this time, to date, the pandemic has adversely affected, and is expected to continue to adversely affect, our business, financial condition and results of operations. While we are considered an essential company under the U.S. Federal Cybersecurity and Infrastructure Security Agency guidance and the various state or local jurisdictions in which we operate, the spread of COVID-19 has disrupted certain aspects of our operations, including our ability to execute on our business strategy and goals, and complete the development of our projects. Commissioning of our development sites was delayed four to five months in 2020. Delayed commissioning also delays the registrations and qualifications necessary for EPA pathways, which in turn delays revenue streams from these facilities. In addition, the COVID-19 pandemic has caused delays and disruptions in our operations, including contract cancellations, and decreased our operational efficiency in maintenance and operations. State and local mitigation protocols have contributed to reduced needs for transportation fuels, which has lowered and could continue to lower state-based environmental premiums. During 2020, we also faced a reduction in RINs pricing due to the outbreak of COVID-19.

Additionally, certain third parties with whom we engage, including our project partners, third-party manufacturers and suppliers, and regulators with whom we conduct business have adjusted their operations and are assessing future operational and project needs in light of the COVID-19 pandemic. If these third parties experience shutdowns or continued business disruptions, our ability to conduct our business in the manner and on the timelines presently planned could be materially and adversely affected.

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The COVID-19 pandemic could continue to adversely affect our business, financial condition and results of operations in the future. Such future effects may be material, and include, but are not limited to:

• reductions in state-based Environmental Attribute premiums associated with reduced volumes in the transportation sector;

• new “shelter-in-place” orders, quarantines or similar orders, which may reduce our operating effectiveness or the availability of personnel necessary to conduct our business activities;

• disruptions in our supply chain due to transportation delays, travel restrictions, raw material cost increases and shortages, and closures of businesses or facilities;

• delays in construction and other capital expenditure projects, regulatory approvals and collections of our receivables for the services we perform;

• attempts by customers to cancel or delay projects or for customers or subcontractors to invoke force majeure clauses in certain contracts resulting in a decreased or delayed demand for our products and services;

• the inability of a significant portion of our workforce, including our management team, to work as a result of illness or government restrictions; and

• reduced ability to access capital and limited availability of credit or financing upon acceptable terms or at all.

The situation surrounding the COVID-19 pandemic remains dynamic, and given its inherent uncertainty, it could have an adverse effect on our business in the future. The duration and extent of the impact from the COVID-19 pandemic depends on future developments that cannot be accurately predicted at this time, such as the severity and transmission rate of the virus, the extent and effectiveness of containment actions and the impact of these and other factors on our employees, customers, suppliers, and distributors. Should these conditions persist for a prolonged period, the COVID-19 pandemic, including any of the above factors and others that are currently unknown, could have a material adverse effect on our business, financial condition and results of operations. The impact of the COVID-19 pandemic may also exacerbate other risks discussed in these risk factors, any of which could have a material effect on us.

Renewable Energy Risks

Our commercial success depends on our ability to develop and operate individual renewable energy projects.

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, a number of 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;

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• 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 as a result of inclement weather or labor disruptions;

• operating risks and the effect of disruptions on our business, including the effects of the COVID-19 pandemic on us, our customers, suppliers, distributors and subcontractors;

• 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 or easements;

• 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; and

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

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.

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Regulatory Risks

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

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, 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.

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

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 permits refineries and importers of transportation fuel to satisfy their RVOs by purchasing either (i) D5 RINs and cellulosic waiver credits (“CWCs”) or (ii) D3 RINs. RECs are created through state law requirements for utilities to purchase a portion of their energy from renewable energy sources. 60% and 56% of our revenues for 2020 and 2019, 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.

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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 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.” It is anticipated that EPA will draft a new rule regulating GHG emissions, the impact of which 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.

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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. 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.

The EPA annually sets proposed RVOs for D3 RINs in accordance with the mandates established by EISA. The EPA’s issuance of timely and sufficient annual RVOs to accommodate the RNG industry’s growing production levels is necessary to stabilize the RIN market. Although the 590 million D3 RIN volume for 2020 is a 41% increase over 2019 levels, there can be no assurance that the EPA will timely set annual RVOs or that the RVOs will continue to increase or satisfy the growing receivable natural gas market. The manner in which the EPA will establish RVOs beginning in 2023, when the statutory RVO mandates are set to expire, is expected to create additional uncertainty as to RIN pricing. In addition, the EPA has exempted a number of small refineries from their RVOs through the issuance of waivers under U.S. federal law and is expected to continue to do so. Uncertainty as to how the RFS program will continue to be administered and supported by the EPA under the new U.S. presidential administration has created price volatility in the RIN market. We cannot assure you that we will be able to monetize the RINs we generate at the same price levels as we have in the past, that production shortfalls will not impact our ability to monetize RINs at favorable current pricing, and that the rising price environment will continue.

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

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qualification on a state by state basis under such future programs. Delays in obtaining registration, RIN qualification, and any future LCFS credit qualification 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.

Operating Risks

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

The renewable energy projects that we construct and own are subject to various operating risks that may cause them to generate less than expected amounts of RNG or electricity. These risks include 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 incurs 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.

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.

A substantial portion of our revenues are generated from five project sites. For the years ended December 31, 2020 and 2019, excluding the effect of derivative instruments, approximately 78.7% and 80.4%, respectively, of operating revenues were derived from these locations. During 2020, RNG production at our McCarty, Rumpke, Atascocita and Apex facilities accounted for approximately 22.6%, 24.8%, 20.6%, and 9.6% of our RNG revenues, respectively, and 18.8%, 28.9%, 19.6%, and 9.9% of the RNG we produced during 2020, respectively. During 2020, Renewable Electricity production at our Bowerman Power LFG, LLC (“Bowerman”) facility accounted for approximately 86.8% of our Renewable Electricity Generation revenues and 61.2% of the Renewable Electricity we produced during 2020. 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. Recent historical cold weather impacted our Houston, Texas facilities during the winter of 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

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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. These facilities have resumed operations and the Company expects that the cost of utilities will return to historical levels. Additionally, recent 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. Our Bowerman revenues were reduced by approximately 20% in the fourth quarter of 2020 over the prior year quarter and we expect 2021 first quarter revenues to be approximately 16% less than the 2020 first quarter.

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.

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, natural disasters, terrorist attacks and sabotage. We are also exposed to environmental risks. For example, our McCarty facility experienced the loss of one of its two production engines for the period of November 27, 2019 through March 27, 2020. The related commissioning and ramp up of the replacement engine was completed during the second quarter of 2020. Additionally, as described above, our Bowerman facility, located near major earthquake faults and fire zones, temporarily shut down due to the California wildfires in October 2020 which caused limited damage to our facility and equipment. Production and revenues were reduced in 2020 (as compared to 2019) as described above, and we expect 2021 first quarter revenues to be approximately 16% less than the 2020 first quarter.

We have insurance policies covering certain risks associated with our business. Our insurance policies do not, however, cover all losses, including those as a result of force majeure. We don’t expect any insurance recovery from the shutdowns in Houston in February 2021 or from the Bowerman shutdown in October 2020. 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. In addition, while our insurance policies for some of our projects cover losses as a result of certain types of natural disasters, terrorist attacks or sabotage, among other things, such coverage is subject to important limitations and is not always available in the insurance market 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.

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New Project and Growth Risks

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, global health crises such as COVID-19, 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.

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 12 to 24 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

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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 477 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 25 of these sites are potentially economically viable as projects for acquisition and growth. 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 reduces 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.

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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. 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 incur additional costs and expenses related to 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 financial benefits we anticipated.

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

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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 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.

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 that are also 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 a 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. For example, our Bowerman project lost a partial day in 2018 (March 31), and five days in 2019 (April 1-5), and then was curtailed for approximately 55 days (ending at 80% of power output) while the utility operator designed and permitted a permanent fix. Our Bowerman project also lost two days in 2019 (June 30-July 1) while the utility operator made permanent repairs. The Bowerman facility was also idled for 34 days in 2020 (October 27 – November 29) due to California wildfires. 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.

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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 approximately 30.8% and 23.7%, respectively, of our revenues for 2020. 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 2020, sales to ExxonMobil, City of Anaheim, Royal Dutch Shell plc, and Victory Renewables, LLC represented approximately 15.1%, 14.4%, 14.1% and 11.3%, respectively of our operating revenues. In addition, including two of the previous customers, five customers made up approximately 81%, 67% and 72% of our accounts receivable as of December 31, 2020, 2019 and 2018, 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.

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 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.

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.

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Market Pricing Risks

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 RVOs. 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 conditions 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, 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, since the value of D3 RINs is linked to the price of CWCs, which are inversely affected by 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 RVOs 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 Obligated Parties have satisfied their RVOs 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.

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

We have in the past, and may from time to time in the future, sell forward a portion of our RINs under contracts to fix the revenues from those 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, or if for any reason the RNG we generate does not produce RINs, we may be required to make up the shortfall of RINs under such forward contracts through purchases on the open market or by making payments of liquidated damages. Forward selling of a portion of 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 are able to hedge our RNG revenues, our hedging transactions expose us to the risk that a counterparty fails to perform under a derivative contract. 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 when they become due would adversely affect our business, financial condition and results of operations.

We also face credit risk through the sale of our RNG production. We are also subject to credit risk due to concentration of our RNG receivables with a limited number of significant customers. We do not require our customers to 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.

Environmental Risks

Our operations are subject to numerous stringent environmental, health and safety laws and regulations that may expose us to significant costs and liabilities.

Our operations are subject to stringent and complex 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.

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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, the current U.S. presidential administration signed multiple executive orders related to the climate and environment. These executive orders direct federal agencies to review and reverse more than one-hundred actions taken by the previous U.S. presidential administration on the environment, instruct the Director of National Intelligence to prepare a national intelligence estimate on the security implications of the climate crisis and direct all agencies to develop strategies for integrating climate considerations into their international work, establish the National Climate Task Force which assembles leaders from across twenty-one federal agencies and departments, commit to environmental justice and new, clean infrastructure projects, commence development of emissions reduction targets and establish the special presidential envoy for climate on the National Security Council. 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.

Liability relating to contamination and other environmental conditions may require us to conduct investigations or remediation at the properties underlying our projects and may impact the value of properties that we may acquire.

We may incur liabilities for the investigation and cleanup of any environmental contamination at the properties underlying or adjacent to our projects, or at off-site locations where we arrange for the disposal of hazardous substances or wastes. Under the Comprehensive Environmental Response, Compensation and Liability Act of 1980 and other federal, state and local laws, an owner or operator of a property may become liable for costs of investigation and remediation, and for damages to natural resources. These laws often impose liability without regard to whether the owner or operator knew of, or was responsible for, the release of such hazardous substances or whether the conduct giving rise to the release was legal at the time when it occurred. In addition, liability under certain of these laws is joint and several. We also may be subject to related claims by private parties alleging property damage and personal injury due to exposure to hazardous or other materials at or from those properties.

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The presence of environmental contamination at a project may adversely affect an owner’s ability to sell such project or borrow funds using the project as collateral. To the extent that an owner of the real property underlying one of our projects becomes liable with respect to contamination at the real property, the ability of the owner to make payments to us may be adversely affected.

The presence of any environmental contamination with respect to one of our projects could adversely affect our ability to sell the affected project, and we may incur substantial investigation costs, remediation costs or other damages, thus harming our business, financial condition and results of operations.

Our business is subject to the risk of climate change and 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.

Capital and Credit Risks

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

Provisions in our Amended Credit Agreement, as described in “Liquidity and Capital Resources” impose customary restrictions on our and certain of our subsidiaries’ business activities and uses of cash and other collateral. These agreements also contain other customary covenants, including covenants that require us to meet specified financial ratios and financial tests.

The Amended Credit Agreement consists of a $95.0 million principal amount term loan and an $80.0 million revolving credit line that matures in December 2023. The Amended Credit Agreement may not be sufficient to meet our needs as our business grows, and we may be unable to extend or replace it on acceptable terms, or at all. Under the Amended Credit Agreement, we are required to maintain a maximum ratio of total liabilities to tangible net worth of no greater than 2.0 to 1.0 as of the end of any fiscal quarter. We are also required to maintain:

• as of the end of each fiscal quarter, a fixed charge coverage ratio (meaning as of any date of determination, the ratio, (a) the numerator of which is consolidated EBITDA (as defined in the Amended Credit Agreement) for the applicable measuring period ending on such date of determination, minus taxes paid in cash during such period, minus Tax Distributions made on a consolidated basis

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(other than the excluded entities) during such period, minus consolidated maintenance capital expenditures (other than the excluded entities) during such period, and (b) the denominator of which is the Fixed Charges (as defined in the Amended Credit Agreement), for such period) of at least 1.2 to 1.0; and

• as of the end of each fiscal quarter, a total leverage ratio (meaning as of any date of determination, the ratio of (a) Funded Debt (as defined in the Amended Credit Agreement) on a consolidated basis (other than the excluded entities) on such date to (b) the sum of (i) the EBITDA Credit (as defined in the Amended Credit Agreement) as of such date and (ii) consolidated EBITDA for the four preceding fiscal quarters then ending, all as determined on a consolidated basis in accordance with GAAP of not more than 3.0 to 1.0.

Consolidated EBITDA, as used in the Amended Credit Agreement, may be calculated differently than EBITDA or Adjusted EBITDA, as used in this report. Consolidated EBITDA is defined under the Amended Credit Agreement as net income plus (a) income tax expense, (b) interest expense, (c) depreciation, depletion, and amortization expense, (d) non-cash unrealized derivative expense and (e) any other extraordinary, unusual, or non-recurring adjustments to certain components of net income, as agreed upon by Comerica in certain circumstances. Additional information on Consolidated EBITDA as used in the Amended Credit Agreement can be found in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under “Liquidity and Capital Resources.”

The Amended Credit Agreement also contemplates that we would be in default if for any fiscal quarter, (a) the average monthly D3 RIN price (as determined in accordance with the Amended Credit Agreement) is less than $0.80 per RIN and (b) the consolidated EBITDA for such quarter is less than $6,000,000.

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 it which would require us to pay 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, 2020, we were in compliance with all covenants. Certain of our debt agreements also contain subjective acceleration clauses based on a lender deeming that a “material adverse change” in our business has occurred. If these clauses are implicated, and the lender declares that an event of default has occurred, the outstanding indebtedness would likely be immediately due. If the maturity of our indebtedness is accelerated, we may not have sufficient funds available for repayment or we may not have the ability to borrow or obtain sufficient funds to replace the accelerated indebtedness on terms acceptable to us or at all.

Changes to and replacement of the LIBOR Benchmark Interest Rate may adversely affect our business, financial condition and results of operations.

Our Amended Credit Agreement is indexed to the London Interbank Offered Rate (“LIBOR”) to calculate the loan interest rate. In 2017, the United Kingdom’s Financial Conduct Authority (“FCA”), which regulates LIBOR, announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. However, on March 5, 2021 announcements by the ICE Benchmark Administration (“IBA”) and the FCA on future cessation and loss of representativeness of LIBOR indicated that IBA would cease publication of all settings of non-U.S. dollar LIBOR and only the one-week and two-month U.S. dollar LIBOR settings on December 31, 2021, with the publication of the remaining U.S. dollar LIBOR settings being discontinued after June 30, 2023 as the same will no longer be representative of the underlying market and economic reality that such setting is intended to measure. Although our Amended Credit Agreement provides for alternative reference rates, such alternative reference rates and the consequences of the phase out of LIBOR cannot be entirely predicted at this time. An alternative reference rate could be higher or more volatile than LIBOR prior to its discontinuance, which could result in an increase in the cost of our indebtedness, impact our ability to refinance some or all of our existing indebtedness or otherwise have a material adverse impact on our business, financial condition and results of operations. Furthermore, there can be no assurance that all tenor settings of LIBOR will actually cease to be available after June 30, 2023, whether certain U.S. dollar LIBOR settings will actually be available until June 30, 2023 or whether U.S. dollar

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LIBOR or such other LIBOR currency will be replaced by an alternative market benchmark in place of U.S. dollar LIBOR or such other LIBOR currency, as the case may be. The March 5, 2021 announcement by the FCA did note that U.S. dollar LIBOR could, subject to proposed new powers of the FCA, be published on a changed methodology (or “synthetic”) basis and not a representative basis. Similarly, it is not possible to predict whether LIBOR will continue to be viewed as an acceptable market benchmark prior to June 30, 2023, what rate or rates may become accepted alternatives to LIBOR, or what the effect of any such changes in views or alternatives may be on the markets for LIBOR-indexed financial instruments. In June 2017, the Alternative Reference Rates Committee (the “ARRC”) convened by the Federal Reserve Board and Federal Reserve Bank of New York announced the Secured Overnight Financing Rate (“SOFR”) as its recommended alternative to LIBOR for USD obligations. However, because the SOFR is a broad U.S. Treasury repo financing rate that represents overnight secured funding transactions, it differs fundamentally from LIBOR.

The LIBOR cessation fallback language under our Amended Credit Agreement provides for a transition to specified alternative SOFR-based rates, or, if those alternatives cannot be determined, to another rate selected by the administrative agent and the borrower under the Amended Credit Agreement as well as provisions that allow one or more parties to transition in advance of the dates set forth above where specified conditions are met. The implementation of a substitute index or indices for the calculation of interest rates under certain of our project loans may result in our incurring significant expenses in effecting the transition and could adversely affect our financial condition or results of operations.

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 2020, we recorded impairment charges of $0.3 million related to our digester joint venture. In 2019, we recorded impairment charges of $0.9 million, $0.8 million and $0.8 million related to one digester joint venture, one RNG facility, and one Renewable Electricity facility, respectively. 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, 2020, we had U.S. federal net operating loss (“NOL”) carryforwards of approximately $95.5 million, of which $53.5 million were incurred prior to the enactment of the U.S. Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and, therefore, can be carried forward for 20 years to fully offset taxable income in a future year, and of which $42.0 million 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. The CARES Act temporarily lifts the 80% limitation, allowing us to use our NOLs to offset 100% of our taxable income for our 2018, 2019, and 2020 taxable years. Our NOL carryforwards incurred in 2017 or earlier taxable years expire between 2027 and 2037, while our NOL carryforwards incurred in 2018 or later taxable years survive indefinitely. 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, Johnstown 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

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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 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.

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 service or equipment providers, consultants, managers or 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 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.

Technological innovation may render us uncompetitive or our processes obsolete.

Our success will depend on our ability to create and maintain a competitive position in the renewable energy industry. 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. 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.

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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. In addition, 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.

Cybersecurity and Information Technology Risks

A failure of our information technology (“IT”) and data security infrastructure could adversely affect 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 adversely affect 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. We have experienced such incidents in the past, and any future 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. Although past incidents have not had a material effect on our business operations or financial performance, to the extent that any disruptions or security breach results in a loss or damage to our data, or an inappropriate disclosure of confidential, proprietary or customer information, it could cause significant 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 harm our business. 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. If an actual or perceived cybersecurity breach or unauthorized

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access to our system or the systems of our third-party vendors, we may incur liability, costs, or damages, contract termination, our reputation may be compromised, our ability to attract new customers could be negatively affected, and our business, financial condition, and results of operations could be materially and adversely affected. Any compromise of our security could also 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. 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.

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 errors or defects in our platforms, cause our platforms to fail, our revenue and margins could decline, or our reputation and brand to be damaged, we could be exposed to legal or contractual liability, our expenses could increase, our ability to manage our operations could be interrupted, and our processes for servicing our customers could be 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 adversely affect our business. Many of these third-party providers 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. 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 12 to 24 months to enhance our defensive capabilities and resilience. Despite our ongoing and anticipated cybersecurity efforts, a successful cybersecurity incident could lead to additional 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 the 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 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. If any of these security breaches were to occur, they could lead to the loss of sensitive information, critical infrastructure or capabilities essential to our operations, and could adversely affect our reputation, financial position, results of operations or cash flows. Cybersecurity attacks, in particular, are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain

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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.

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, we, unlike other public companies, 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, 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.

We identified a material weakness in our internal control over financial reporting as of December 31, 2020. 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.

During the preparation of our interim financial statements in connection with the IPO, as well as the preparation of our year-end financial statements, we and our independent public accounting firm identified a material weakness in internal control over financial reporting. The material weakness related to inadequate procedures and controls with respect to complete and accurate recording of inputs to the consolidated income tax provision and related accruals.

The identified control deficiencies could have resulted in a misstatement of our accounts or disclosures that could have resulted in a material misstatement of our annual or interim consolidated financial statements that would not have been prevented or detected, and accordingly, we determined that these control deficiencies constituted a material weakness.

The material weakness also resulted in adjustments to deferred tax assets, income tax payable, member’s equity and income tax expense (benefit) in our consolidated financial statements as of and for the twelve months ended December 31, 2020 and as of and for the nine months ended September 30, 2020 and 2019, which were recorded prior to their issuance.

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Prior to the completion of the IPO, we were not required to implement internal controls over financial reporting similar to those required by Sections 302 and 404 of the Sarbanes-Oxley Act. As described above, we identified a material weakness in connection with the preparation of our interim financial statements for the IPO that we continue to implement remediation initiatives for by designing measures to improve our internal control over financial reporting and remediate the control deficiencies that led to the material weakness, including outsourcing the parallel preparation and review of our tax calculations and related disclosures by external specialists and initiating design and implementation of our financial control environment which includes creation of additional controls including those designed to strengthen our review and reconciliation processes around preparation of the annual and interim tax provision and related disclosures.

As a newly public company, 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;

• overall market fluctuations;

• results from any material litigation or government investigation;

• changes in senior management or key personnel;

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• 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, particularly in light of uncertainties surrounding the ongoing COVID-19 pandemic and the related impacts.

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. We are unable to predict the timing of or the effect that such sales may have on the prevailing market price of our common stock.

All of our directors and officers and certain stockholders are subject to lock-up agreements that restrict their ability to transfer shares of our capital stock for 180 days from January 21, 2021, subject to certain exceptions. The underwriter in the IPO, Roth Capital Partners, LLC, may, in its sole discretion, permit our stockholders who are subject to these lock-up agreements to sell shares prior to the expiration of the lock-up agreements, subject to applicable notice requirements. If not earlier released, all of the shares of common stock sold in the IPO will become eligible for sale upon expiration of the 180-day lock-up period, except for any shares held by our affiliates as defined in Rule 144 under the Securities Act.

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 the historical sales prices for the ordinary shares of MNK on

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the JSE 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 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 will agree 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 53.1% of our common stock after the completion of the IPO. These stockholders have informed us that they intend to enter into 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 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.

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.

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Our Amended and Restated Certificate of Incorporation provides that, unless we determine otherwise, the Court of Chancery of the State of Delaware and the U.S. federal district courts are the sole and exclusive forums for certain litigation matters, which could discourage stockholder lawsuits or limit our stockholders’ ability to bring a claim in any judicial forum that they find favorable for disputes with us or our officers and directors.

Pursuant to our Amended and Restated Certificate of Incorporation, unless we consent in writing to an alternative forum, the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have jurisdiction, the federal district court for the District of Delaware) is the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (“DGCL”), our Amended and Restated Certificate of Incorporation, or our Amended and Restated Bylaws, or (iv) any action asserting a claim governed by the internal affairs doctrine. We refer to this provision in our Amended and Restated Certificate of Incorporation as the Delaware Forum Provision. The Delaware Forum Provision does not apply to any claim arising under the Securities Act or the Exchange Act. Furthermore, unless we consent in writing to the selection of an alternative forum, the U.S. federal district courts are, to the fullest extent permitted by law, the sole and exclusive forum for any action asserting a claim arising under the Securities Act. We refer to this provision in our Amended and Restated Certificate of Incorporation as the Federal Forum Provision. Any person or entity purchasing or otherwise acquiring an interest in any of our securities shall be deemed to have notice of and to have consented to the Delaware Forum Provision and the Federal Forum Provision, provided, however, that such security holders cannot and will not be deemed to have waived compliance with the U.S. federal securities laws and the rules and regulations thereunder.

The Delaware Forum Provision and the Federal Forum Provision may impose additional litigation costs on security holders in pursuing any such claims to the extent the provisions require the security holders to litigate in a particular or different forum. Additionally, these forum selection clauses may limit our stockholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers or employees, which may discourage the filing of lawsuits against us and our directors, officers and employees, even though an action, if successful, might benefit our stockholders or us. The Court of Chancery of the State of Delaware and the federal district courts, as applicable, may reach a different judgment or result than would other courts, including courts where a stockholder considering an action may be located or would otherwise choose to bring the action, and such judgments may be more or less favorable to our stockholders. In addition, while the Delaware Supreme Court ruled in March 2020 that federal forum selection provisions purporting to require claims under the Securities Act be brought in federal court are “facially valid” under Delaware law, there is uncertainty as to whether other courts will enforce our Federal Forum Provision. The Federal Forum Provision may impose additional litigation costs on stockholders who assert that the provision is not enforceable or invalid. If the Federal Forum Provision is found to be unenforceable, we may incur additional costs associated with resolving such matters.

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 and Mohamed H. Ahmed 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.

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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.

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 a 10,874 square foot office space at this site for approximately $21,500 per month pursuant to a lease which expires on December 31, 2022.

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, 2022, for approximately $4,100 per month. We currently own

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and operate 15 projects, 12 of which are RNG projects and three of which are Renewable Electricity projects. See “Item 1. Business—Our Projects” 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.

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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 17, 2021, there were 12 holders of record of 141,015,213 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.

Dividend Policy

MNK declared cash dividends of $7.6 million and $4.1 million in May 2018 and October 2018, respectively. MNK did not declare any cash dividends in 2019 or 2020 and the Company has not paid any cash dividends since the completion of the IPO. 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

There were no repurchases of equity securities during the year ended December 31, 2020.

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.

Since the closing of the IPO, approximately $0.1 million of the net proceeds from the IPO have been used for due diligence activities. The remaining net proceeds of approximately $14.9 is held as cash.

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There has been no material change in the expected use of the net proceeds from the IPO as described in in the Registration Statement.

Recent Sales of Unregistered Securities

On September 22, 2020 and in connection with our initial formation, Montauk issued 10 shares of our common stock to Ms. Melissa Zotter for $10 under Section 4(a)(2) of the Securities Act on the basis that the transaction did not involve a public offering.

On January 4, 2021, Montauk redeemed the 10 shares of its common stock owned by Ms. Melissa Zotter for $10. Immediately thereafter, Montauk issued 138,312,713 shares of its common stock to Montauk USA (representing all of the issued and outstanding shares of common stock of Montauk) in exchange for all of the issued and outstanding membership interests of MEH under Section 4(a)(2) of the Securities Act on the basis that the transaction did not involve a public offering.

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ITEM 6. SELECTED FINANCIAL DATA

We have derived the following selected consolidated statements of operations and cash flow data for the years ended December 31, 2020 and 2019 and the consolidated balance sheet data as of the years ended December 31, 2020 and 2019 from our consolidated financial statements included elsewhere in this Annual Report on Form 10-K. We have derived the following selected consolidated statements of operations and cash flow data for the year ended December 31, 2018 included elsewhere in this Annual Report on Form 10-K and the consolidated balance sheet data as of the year ended December 31, 2018 from our consolidated financial statements not included in this Annual Report on Form 10-K.

The historical results presented below are not necessarily indicative of the results to be expected for any future period. You should read the selected financial data presented below in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K.

(in thousands)	For the year ended December 31,
	2020			2019			2018
Statement of operations data:
Total operating revenues	$	100,383		$	105,714		$	115,087
Operating expenses:
Operating and maintenance expenses	$	43,463		$	39,783		$	29,073
General and administrative expenses		16,594			13,632			11,953
Royalties, transportation, gathering and production fuel		18,284			18,889			21,013
Depreciation, depletion and amortization		22,117			19,760			16,195
Gain on insurance proceeds		(3,934	)		—			—
Impairment loss		278			2,443			854
Transaction costs		—			202			176
Total operating expenses	$	96,802		$	94,709		$	79,264
Operating profit	$	3,581		$	11,005		$	35,823
Other expenses (income)
Interest expense	$	4,339		$	5,576		$	3,083
Net gain on sale of assets		320			10			(266	)
Other expense (income)		315			(47	)		(3,557	)
Total other expense (income)	$	4,974		$	5,539		$	(740	)
Income (loss) before income taxes	$	(1,393	)	$	5,466		$	36,563
Income tax expense (benefit)		(5,996	)		(354	)		7,796
Net income	$	4,603		$	5,820		$	28,767
Per share data(1):
Pro forma earnings per share (unaudited):
Basic		0.03			0.04			0.20
Diluted		0.03			0.04			0.20
Pro forma weighted-average common shares outstanding (unaudited):
Basic		140,662,713			140,662,713			140,662,713
Diluted		141,057,566			141,057,566			141,057,566
Balance sheet data:
Total assets	$	253,356		$	243,613		$	261,732
Long-term debt, including current maturities		65,760			66,566			92,962
Total equity		159,622			154,257			147,941

(1) On January 26, 2021, the Company closed its IPO. The pro forma adjustments give effect to per share data as if the IPO and associated transactions had occurred at the years ended December 31, 2020, 2019, and 2018 using the share amounts at the time of the IPO.

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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. The consolidated financial statements of Montauk USA, our predecessor for accounting purposes, became our historical financial statements following the IPO. The historical financial data discussed below relates to periods prior to the Reorganization Transactions.

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.

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.

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.

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We monetize a portion of our RNG production under fixed-price and counterparty sharing agreements, which provide floor prices in excess of commodity indices and sharing percentages of the monetization of Environmental Attributes. Under these sharing arrangements, we receive a portion of the profits derived from counterparty monetization of the Environmental Attributes in excess of the floor prices.

• 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 November 2019, our McCarty facility lost production capacity of one of its engines due to its failure. Production was not restored until March 2020 when a replacement was commissioned. We recorded $3.9 million as a gain on insurance proceeds related to the replacement of property and business interruption. 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. We expect 2021 first quarter revenues for our Bowerman facility to be approximately 16% less than the 2020 first quarter revenues.

• Recent historical cold weather impacted our Atascocita, Galveston, McCarty, and Coastal Plains facilities located in Texas during February 2021. 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 counter-parties or by us for the period February 12 through February 22, 2021 related to these weather events. Operations at these facilities have subsequently resumed, but we estimate that our cost of utilities will increase approximately 7.1% in the first quarter of 2021 within our RNG segment.

• Quality of Biogas: We are reliant upon the quality and availability of biogas from our site partners. The quality of the waste at our landfill project sites is subject to change based on the volume and type of waste accepted. Variations in the quality of the biogas could affect our RNG production levels. At three of our projects, we operate the wellfield collection system, which allows greater control over the quality and consistency of the collected biogas. At two of our projects, we have operating and management agreements by which we earn revenue for managing the wellfield collection systems. Additionally, our dairy farm project benefits from the consistency of feedstock and controlled environment of collection of waste to improve biogas quality.

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

Pricing

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

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

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. With election uncertainty, in the fourth quarter of 2020, we entered into forward commitments of approximately 50% of our expected 2021 RIN generation. These forward commitments were based on D3 RIN index prices at the time of the commitment, which averaged $1.50—$1.57. While our average commitment price was in excess of these index averages at the time we entered into the forward commitments, it is below current D3 RIN index prices. These forward commitments will be monetized throughout 2021. 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

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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. In connection with the consummation of the IPO and the Reorganization Transactions, stock options issued under MNK’s Employee Share Appreciation Rights Scheme for US Affiliates were canceled. Under FASB ASC 718, the Company accelerated all previously unvested stock-based compensation expense of approximately $2.1 million in January 2021. The Company’s Board of Directors approved grants of restricted stock, non-qualified stock option, and restricted share unit awards under the Company’s Equity and Incentive Compensation Plan on January 28, 2021. The Company will account for stock-based compensation related to these equity awards under FASB ASC 718. For more information, see Note 21 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. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.

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

(in thousands, unless otherwise indicated)	For the year ended December 31,
	2020			2019			Change			Change%
Revenues
Renewable Natural Gas Total Revenues	$	83,236		$	84,157		$	(921	)		(1.1	)%
Renewable Electricity Generation Total Revenues	$	16,665		$	19,859		$	(3,194	)		(16.1	)%
RNG Metrics
CY RNG production volumes (MMBtu)		5,746			5,361			386			7.2	%
Less: Current period RNG volumes under fixed/floor-price contracts		(2,009	)		(1,987	)		(22	)		1.1	%
Plus: Prior period RNG volumes dispensed in current period		266			371			(105	)		(28.3	)%
Less: Current period RNG production volumes not dispensed		(353	)		(266	)		(86	)		32.4	%
Total RNG volumes available for RIN generation(1)		3,650			3,478			172			4.9	%
RIN Metrics
Current RIN generation ( x 11.727)(2)		42,809			40,791			2,018			4.9	%
Less: Counterparty share (RINs)		(4,701	)		(3,729	)		(972	)		26.1	%
Plus: Prior period RINs carried into CY		1,330			1,690			(360	)		(21.3	)%
Less: CY RINs carried into next CY		(99	)		(886	)		787			(88.8	)%
Total RINs available for sale(3)		39,338			37,866			1,473			3.7	%
Less: RINs sold		(39,335	)		(36,767	)		(2,569	)		7.0	%
RIN Inventory		3			1,099			(1,096	)		(100.0	)%
RNG Inventory (volumes not dispensed for RINs)(4)		353			(266	)		619			232.7	%
Average Realized RIN price	$	1.32		$	1.45		$	(0.13	)		(9.0	)%
Operating Expenses
Renewable Natural Gas Operating Expenses	$	51,744		$	46,853		$	4,890			10.4	%
Operating Expenses per MMBtu (actual)	$	9.00		$	8.74		$	0.26			3.0	%
Renewable Electricity Generation Operating Expenses	$	11,552		$	13,299		$	(1,746	)		(13.1	)%
$/MWh (actual)	$	62.12		$	56.36		$	5.34			10.2	%
Other Metrics
Renewable Electricity Generation Volumes Produced (MWh)		186			236			(50	)		(21.2	)%
Average Realized Price $/MWh (actual)	$	89.60		$	84.16		$	5.45			6.5	%

(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.

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Results of Operations

Comparison of Years Ended December 31, 2020 and 2019

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

(in thousands, except per share data)	For the year ended December 31,
	2020			2019			Change			Change%
Total operating revenues	$	100,383		$	105,714		$	(5,331	)		(5.0	)%
Operating Expenses:
Operating and maintenance expenses		43,463			39,783			3,680			9.3	%
General and administrative expenses		16,594			13,632			2,962			21.7	%
Royalties, transportation, gathering and production fuel		18,284			18,889			(605	)		(3.2	)%
Depreciation and amortization		22,117			19,760			2,357			11.9	%
Gain on insurance proceeds		(3,934	)		—			(3,934	)		100.0	%
Impairment loss		278			2,443			(2,165	)		(88.6	)%
Transaction costs		—			202			(202	)		(100	)%
Total operating expenses	$	96,802		$	94,709		$	2,093			2.2	%
Operating profit	$	3,581		$	11,005		$	(7,424	)		(67.5	)%
Other expenses:		4,974			5,539			(565	)		(10.2	)%
Income tax expense (benefit)		(5,996	)		(354	)		(5,642	)		(1,593.8	)%
Net income	$	4,603		$	5,820		$	(1,217	)		(20.9	)%

Revenues for the Years Ended December 31, 2020 and 2019

Total revenues in 2020 were $100.4 million, a decrease of $5.3 million (5.0%) compared to $105.7 million in 2019. The primary driver for this decrease related to a 16.1% decrease in Renewable Electricity from our election to end the contract and exit our Monmouth facility and California wildfires impacting power generation at our Bowerman facility. To a lesser extent, decreased realized average RIN prices offset increased RINs sold, leading to an overall 1.1% decrease in RNG revenues.

Renewable Natural Gas Revenues

We produced 5.7 million MMBtu of RNG during 2020, an increase of over the 5.4 million MMBtu (7.2%) produced in 2019. Of this increase, 0.2 million MMBtu of RNG were produced from development site commissioned during 2019. Less than 0.1 million MMBtu of RNG were produced from development sites commissioned during 2020. Wellfield improvement initiatives at our Apex site yielded an increase of 0.1 million MMBtus over the prior year period. Our McCarty site was unfavorably impacted by the loss of one of its engines leading to a reduction in 2020 of (0.1) million MMBtus over the 2019 period.

Revenues from the Renewable Natural Gas segment in 2020 were $83.2 million, a decrease of $0.9 million 1.1% compared to $84.2 million in 2019. Average commodity pricing for natural gas for 2020 was 3.0% higher than the prior year. During 2020, we self-monetized 39.3 million RINs, representing a 2.5 million increase (6.8%) compared to 36.8 million in 2019. The increase was primarily related to increased MMBtu production over the prior year period. Average pricing realized on RIN sales during 2020 was $1.32 as compared to $1.45 in 2019, a decrease of 9.0%. This compares to the average D3 RIN index price for 2020 of $1.49 being approximately 29.8% higher than the average D3 RIN index price in 2019. Approximately 8.0 million of our RIN sales during 2019 were based on commitment pricing calculated based on the D5 RIN index with a portion of the cellulosic waiver credit which results in a RIN sales price in excess of the D3 RIN index. The CWC price in 2020 was $1.80, a 1.7% increase from $1.77 from 2019. All of our 2020 RIN sales were priced generally on the D3

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index. At December 31, 2020, we had approximately 0.4 million MMBtus available for RIN generation. We had approximately 0.1 million RINs generated and unsold at December 31, 2020. We did not have any MMBtus available for RIN generation at December 31, 2019, however we did have 0.9 million RINs generated and unsold at December 31, 2019.

Renewable Electricity Generation Revenues

We produced 0.2 million MWh in Renewable Electricity in 2020, a decrease of approximately 0.05 million (21.2%) MWh compared to 0.2 million in 2019. In 2019, we elected to end the contract and exit our Monmouth, New Jersey facility and ended electricity production at our Coastal Plains location during its conversion to an RNG site. As of October 1, 2020, Pico is now reported in our Renewable Natural Gas segment due to its conversion to an RNG site.

Revenues from Renewable Electricity facilities in 2020 were $16.7 million, a decrease of $3.2 million (16.1%) compared to $19.9 million in 2019. The exit of Monmouth and conversion of Coastal Plains was responsible for approximately $1.2 million of the decrease. Prior to reporting Pico in RNG, Pico accounted for $0.9 million of the $3.2 million decrease between 2020 and 2019. With the conversion of Pico to an RNG, the fixed price for Renewable Electricity was reduced as part of the power purchase agreement. Our Bowerman facility was impacted in the 2020 fourth quarter by the California wildfires forcing it to temporarily shut down the facility. This temporary shutdown is the primary reason our Bowerman facility contributed approximately $0.6 million less revenues in 2020 over the prior year period.

For 2020, 100% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with the underlying PPAs, as compared to 93.9% in 2019. This provides the Company with certainty of revenues resulting from our Renewable Electricity sites.

Corporate Revenue

Our gas hedge program during 2020 was priced at rates in excess of the actual index price, resulting in realized losses of $0.4 million, a decrease of $0.7 million (229.4%) compared to realized gains of $0.3 million in 2019.

Expenses for the Years Ended December 31, 2020 and 2019

General and Administrative Expenses

Total general and administrative expenses of $16.6 million in 2020, increased of $3.0 million (21.7%) compared to $13.6 million in 2019. Employee related costs, including severance, increased approximately $1.3 million (17.6%) in 2020 as compared to the prior year period. Additionally, our corporate insurance premiums increased approximately $0.8 million (42.9%) in 2020 over 2019. Third-party consulting fees increased approximately $1.1 million (56.1%) in 2020 resulting from our successful completion of the IPO and Reorganization Transactions.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in 2020 were $33.6 million, an increase of $4.9 million (17.3%) compared to $28.7 million in 2019. $2.8 million of the increase related to development sites commissioned during 2019 and $1.4 million related to development sites commissioned in 2020. Exclusive of the effects of these development sites, operating and maintenance expenses for 2020 were $28.5 million, an increase of $0.7 million (2.6%) compared to $27.8 million in 2019. The increase is primarily attributable to increased condensate removal and utility costs at our Apex location. Our Rumpke facility also incurred preventative maintenance costs than compared to the prior year period. Our Rumpke facility also incurred increased utility

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costs related to our running a third processing plant at less than nameplate capacity levels and increased preventive maintenance costs. Finally, we incurred increased wellfield operating costs associated with optimization programs at our Monroeville facility. While our McCarty plant experienced reduced production while replacing one of its engines, it incurred lower operating and maintenance expenses primarily related to reduced breakdown costs in 2020.

Royalties, transportation, gathering and production fuel expenses for the Company’s RNG facilities for 2020 were $16.4 million, a decrease of $0.1 million (0.6%) compared to $16.5 million in 2019. Royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues to 19.8% for 2020 from 19.6% in 2019. A site commissioned during 2020 contributed $0.1 million to the total while a site commissioned during 2019 contributed an additional $0.7 million during 2020. Exclusive of the effects of the development sites, royalty related costs for 2020 were $15.5 million, a decrease of $1.0 million (5.8%) compared to $16.5 million in 2019.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in 2020 were $9.8 million, a decrease of $1.1 million (10.1%) compared to $10.9 million in 2019. We reported the results of Pico within the Renewable Electricity Generation segment until October 2020. Of the total, Pico contributed $1.4 million in 2020 and, exclusive of Pico, Renewable Electricity facility operating and maintenance expenses decreased by $1.3 million (13.2%). The decrease is related increasing preventative maintenance intervals at our Bowerman facility to mitigate increased condensate removal costs. Additionally, our exit from our Monmouth facility reduced operating and maintenance expenses in 2020 by $0.6 million. Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2020 were $1.7 million, a decrease of $0.7 million (30.2%) compared to $2.4 million in 2019 and as a percentage of Renewable Electricity Generation segment, revenues decreased from 12.4% to 10.5%. This decrease relates primarily to a site vacated in 2019 and from $0.6 million related to the exit of our Monmouth site in 2020.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in 2020 were $18.3 million, a decrease of $0.6 million (3.2%) compared to $18.9 million in 2019. 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 2020 were $22.1 million, an increase of $2.3 million (11.9%) compared to $19.8 million in 2019. The increase was due to approximately $35.3 million in development site assets being placed into service during 2020 at the time of commercial operation date (“COD”). In 2019, approximately $21.2 million of assets were placed into service at the time of COD.

Impairment loss

We calculated and recorded an impairment loss of $0.3 million for 2020, a decrease of $2.1 million (88.6%) compared to $2.4 million in 2019. The decrease in 2020 was partially attributable to the termination of a

development agreement related to our Pico acquisition. In the prior year, the impairment loss was due to the cancellation of a site conversion agreement and conversion of existing Renewable Electricity to RNG sites in

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2020 and the write-off of assets distributed from our Red Top joint venture. We calculated impairments based upon replacement cost, if applicable, and pre-tax cash flow projections.

Other Expenses (Income)

Other expenses in 2020 were $0.3 million, an increase of $0.4 million (770.2%) compared to income of $47 thousand in 2019. We recorded losses on the disposition of assets of $0.3 million in 2020. We recorded a gain of $0.1 million in 2019 associated with the sale of the Red Top joint venture interests and related distribution of fixed assets.

Income Tax Expense (Benefit)

Prior to 2018, we generated sizeable NOLs, which reduced our income tax payable for 2018 and 2019. Based upon our historical pre-tax book income and forecasts, we expect to utilize all remaining NOLs and thus have not recorded a valuation allowance against such NOLs.

Our effective income tax rate (“ETR”) for 2020 was a benefit of 430.4% compared to a benefit of 6.5% for the prior year period. This increased benefit in the ETR is driven by low pre-tax earnings compared to the tax benefit of 2020. Additionally, we recorded a tax benefit of $2,417 in connection with the January 1, 2020 dissolution of the MEC partnership which will allow all entities under MEC to file as part of our consolidated federal tax group. The Company also made adjustments to deferred taxes related to intangibles and net operating losses, and released our valuation allowance related to certain deferred tax assets that can now be utilized within the new federal tax consolidated group.

The CARES Act and the Consolidated Appropriations Act, enacted by the United States on March 27, 2020 and December 27, 2020, respectively, did not have a material impact on our provision for income taxes for the year ended December 31, 2020. The Company is continuing to analyze the ongoing impact of this legislation.

Operating Profit for the Years Ended December 31, 2020 and 2019

Operating profit in 2020 was $3.6 million, a decrease of $7.4 million (67.5%) compared to $11.0 million in 2019. RNG operating profit for 2020 was $22.7 million, a decrease of $3.0 million (11.7%) compared to $25.7 million in 2019. Renewable Electricity Generation operating loss for 2020 was $2.3 million, a decrease of $0.2 million (7.0%) compared to $2.4 million in 2019.

Comparison of Years Ended December 31, 2019 and 2018

For a discussion of our results of operations for the year ended December 31, 2019 compared to the year ended December 31, 2018, see the section entitled “Management Discussion and Analysis” in our Registration Statement on Form S-1 (Registration No. 333-251312). The registration statement was filed in connection with the IPO and was declared effective by the SEC on January 21, 2020.

Key Trends

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.

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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.

• Efficiency, mobility and capital cost flexibility in our operations enable RNG 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 correlates.

• 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.

There is significant potential for sustained growth in biogas conversion from waste sources, given evolving consumer preferences, regulatory conditions, ongoing waste industry trends, and project economics. We believe that our status as a large producer of RNG from LFG, our 30-year track record of developing and operating projects, and our deep relationships with some of the largest landfill owners in the country position us well to continue to grow our portfolio. We intend to continue to pursue financially disciplined growth through our proven growth channels, including expansion of existing projects, conversion projects, optimization across our portfolio, greenfield development and acquisitions.

The primary factors that we believe will affect our future operating results are as follows:

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 2021 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

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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. The EPA missed its November 30, 2020 statutory deadline to set RVOs for 2021. Accordingly, EPA has not set RVOs for 2021, though it indicates a final rule setting the RVOs can be expected in June 2021. It is unclear if they will meet this timeline. The manner in which the EPA will establish RVOs beginning in 2023, when the statutory RVO mandates are set to expire, is expected to create additional uncertainty as to RIN pricing. Further changes to the CI score assigned to a project upon its renewal or a change in the way CARB develops the CI score for a new project could significantly affect the profitability of a project, particularly in the case of a livestock farm project.

Non-GAAP Financial Measures:

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

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

	Year Ended December 31,
	2020			2019
Net income	$	4,603		$	5,820
Depreciation and amortization		22,117			19,760
Interest expense		4,339			5,576
Income tax benefit		(5,996	)		(354	)
Consolidated EBITDA		25,063			30,802
Impairment loss(1)		278			2,443
Transaction costs		—			202
Equity gain of nonconsolidated investments		—			(94	)
Net loss on sale of assets		320			10
Non-cash hedging charges		388			(252	)
Adjusted EBITDA	$	26,049		$	33,111

(1) For the year ended December 31, 2020, we recorded an impairment of 0.3 million termination of a development agreement related to our Pico acquisition. For the year ended December 31, 2019, we recorded an impairment of $1.5 million associated with our decision to cancel a site conversion agreement and we recorded an impairment loss of $0.9 million associated with a 2018 asset distribution from Red Top.

Liquidity and Capital Resources

Sources of Liquidity

At December 31, 2020 and 2019, our cash and cash equivalents, net of restricted cash, was $21.0 million and $9.8 million, respectively. We intend to fund near-term development projects using cash flows from operations and borrowings under our revolving credit facility. We believe that we will have sufficient cash flows from operations and borrowing availability under our credit facility to meet our debt service obligations and anticipated required capital expenditures (including for projects under development) for at least the next 12 months. However, we are subject to business and operational risks that could adversely affect our cash flows and liquidity.

At December 31, 2020, we had debt before debt issuance costs of $66.7 million, compared to debt before debt issuance costs of $68.2 million at December 31, 2019.

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

	December 31, 2020		December 31, 2019		December 31, 2018
Term Loans	$	30,000	$	40,000	$	95,000
Revolving Credit Facility		36,697		28,198		—
Debt before debt issuance costs	$	66,697	$	68,198	$	95,000

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Amended Credit Agreement

On December 12, 2018, we entered into an amended revolving credit and term loan agreement (as amended, 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 and provides for a five-year $95.0 million term loan and a five-year $80.0 million revolving credit facility.

As of December 31, 2020, $30.0 million was outstanding under the term loan and $36.7 million was outstanding under the revolving credit facility. The term loan amortizes in quarterly installments of $2.5 million and has a final maturity of December 12, 2023 with an interest rate of 2.961% and 4.642% at December 31, 2020 and 2019, respectively. The revolving and term loans under the Amended Credit Agreement bear interest at the Eurodollar 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 and (e) any other extraordinary, unusual, or non-recurring adjustments to certain components of net income, as agreed upon by Comerica in certain circumstances.

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

• a maximum ratio of Total Liabilities to Tangible Net Worth (in each case, as those terms are defined in the Amended Credit Agreement) of greater than 2.0 to 1.0 as of the end of any fiscal quarter; and

• as of the end of each fiscal quarter, (x) a Fixed Charge Coverage Ratio (as defined in the Amended Credit Agreement) of not less than 1.2 to 1.0 and (y) a Total Leverage Ratio (as defined in the Amended Credit Agreement) of not more than 3.0 to 1.0.

On August 28, 2019, we received a waiver for a Specified Event of Default (as defined in the Amended Credit Agreement), for the period from August 31, 2019 to October 1, 2019. The Specified Event of Default related to the average monthly D3 RIN price being less than the minimum required price for a consecutive three-month period. The waiver was temporary in nature and expired on October 1, 2019, at which time no events of default were ongoing.

As of December 31, 2020, 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 $52.5 million outstanding under such credit agreements. For additional information regarding the Amended Credit Agreement, see the sections entitled “Description of Indebtedness and Note 12—Debt to our audited consolidated financial statements.

Debt Financing

We have historically funded our growth and capital expenditures with our working capital, cash flow from operations and debt financing. Excluding strategic transactions, we expect our 2021 capital expenditures to range

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between $8.0 and $9.0 million. Our 2021 capital plans include annual preventative maintenance expenditures, annual wellfield expansion projects, and other specific facility improvements. Additionally, we expect to spend between $2.0 and $4.0 million on optimization projects at our recently commissioned development facilities. Our Amended Credit Agreement provides us with an $80.0 million revolving credit facility, with a $75.0 million accordion option, providing us with access to additional capital to implement our acquisition and development strategy.

Cash Flow

The following table presents information regarding our cash flows and cash equivalents for years ended December 31, 2020 and 2019:

	Year Ended December 31,
	2020			2019
Net cash flows provided by operating activities	$	28,684		$	27,825
Net cash flows used in investing activities		(15,987	)		(44,927	)
Net cash flows used in financing activities		(1,500	)		(27,515	)
Net increase (decrease) in cash and cash equivalents		11,197			(44,617	)
Restricted cash, end of period		567			574
Cash and cash equivalents and restricted, end of period		21,559			10,362

For the year ended December 31, 2020, we generated $28.7 million of cash from operating activities, a 3.1% increase from the prior year ended December 31, 2019 of $27.8 million. For the year ended December 31, 2020, income and adjustments to income from operating activities provided $22.5 million compared to $29.5 million in 2019. Working capital and other assets and liabilities provided $6.2 million in the current period compared to ($2.1) million 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. In addition, our operating profit was also negatively affected by an 8.8% reduction in realized RIN pricing in 2020 over the prior year period. Our net cash flows used in investing activities has historically focused on project development and facility maintenance.

For 2020, our capital expenditures were $17.6 million, of which $0.9 million, $5.9 million and $2.0 million related to the construction of our Galveston, Coastal Plains, and Pico RNG facilities, respectively. We also incurred $3.5 million in capital expenditures rebuilding the failed engine at our McCarty RNG site. For 2019, our capital expenditures were $45.6 million, of which $12.6 million, $10.7 million and $10.6 million related to the construction of our Galveston, Coastal Plains, and Pico RNG facilities, respectively.

Our net cash flows used in financing activities of $1.5 million for 2020 decreased by $26.0 million compared to 2019, primarily due to lower borrowings and debt repayments in 2020. Additionally, we made a distribution to acquire outstanding share rights related to a minority partner of a fully consolidated entity, but otherwise paid no dividends in 2020. Higher debt issuance costs in the prior year period related to closing of the Amended Credit Agreement.

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Contractual Obligations and Commitments

The following table summarizes our outstanding contractual obligations as of December 31, 2020 that require us to make future cash payments:

	Payments Due by Period
	Total		Less than 1 Year		1-3 Years		3-5 years		More than 5 years
Long-term debt(1)	$	66,697	$	10,000	$	56,697	$	—	$	—
Operating lease obligations(2)		629		303		325		1		—
Minimum obligation under gas rights agreements(3)		59,827		3,703		11,109		11,109		33,906
Total(4)(5)	$	127,153		$14,006	$	68,131	$	11,110	$	33,906

(1) Includes fixed interest associated with these obligations.

(2) Operating lease obligations consist of leases for various office spaces and equipment.

(3) Minimum royalty and capital obligations associated with fuel supply agreements at certain operating sites.

(4) This table does not include the estimated discounted liability for the decommissioning and removal requirements for specific gas processing and distribution assets of $5.7 million. See Note 8, “Asset Retirement Obligations of the Consolidated Financial Statements.”

(5) This table excludes any obligations which may arise in connection with any future site closures.

Internal Control Over Financial Reporting

In the preparation of our interim financial statements for the IPO, as well as the preparation of our year end financial statements, we and our independent public accounting firm identified a material weakness in our internal control over financial reporting that impacted the twelve months ended December 31, 2020 and for the nine months ended September 30, 2020 and 2019. During the quarter ended December 31, 2020, we continued to implement remediation initiatives in response to the previously identified material weakness in connection with our material weakness remediation plan as noted below.

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 long-term contracts with its 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

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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. To the extent applicable, sales, value add, and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis. The nature of our long-term contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of our control as the variable consideration is dictated by the market.

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.

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

RECs

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

Income Taxes

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

Our net deferred tax asset position is a result of 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 13, “Income Taxes” to our audited consolidated financial statements included elsewhere in this prospectus. We evaluate our deferred tax assets at reporting periods on a jurisdictional basis to determine

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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.

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.

Finite-Lived Asset Impairment

In accordance with FASB Accounting Standards Codification (“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.

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We recorded impairment of $0.3 million and $2.4 million for the years ended December 31, 2020 and 2019, respectively. See Note 3, “Asset Impairment” to our audited consolidated financial statements included elsewhere in this prospectus.

Off-Balance Sheet Arrangements

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.

During 2020, we had $7.1 million 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 2019, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $7.6 million.

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 prospectus.

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 11, “Derivative Instruments” and Note 12, “Fair Value of Financial Instruments” to our audited consolidated financial statements.

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.

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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 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 2021 estimated D3 RIN Index price of approximately $2.31 and our actual 2020 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 $7.1 million.

RIN 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 the calendar years 2020 and 2019 we entered into derivative transactions to hedge our exposure to the market price of wholesale gas.

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 2021 estimated NYMEX average Index Price of approximately $2.92/MMBtu and our actual 2020 gas production sold pursuant to contracts that do not provide for a fixed or floor price. The estimated annual impact of a hypothetical 10% decrease in the market price of wholesale gas would have a negative effect on our operating profit of approximately $0.9 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 the Eurodollar Margin or Base Rate 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, 2020, we had $66.7 million outstanding under the Amended Credit Facility. Our weighted average interest rate on variable debt balances during 2020 was approximately 2.961%. 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 interest rate swaps and commodity price hedging contracts. We are exposed to credit losses in the event of non-performance by the counterparties to our financial and derivative instruments.

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

	Page
Montauk Holdings USA, LLC
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm		82
Consolidated Balance Sheets as of December 31, 2020 and 2019		83
Consolidated Statements of Operations for the years ended December  31, 2020, 2019 and 2018		84
Consolidated Statements of Member’s Equity for the years ended December 31, 2020, 2019 and 2018		85
Consolidated Statements of Cash Flows for the years ended December  31, 2020, 2019 and 2018		86
Notes to Consolidated Financial Statements		87
Montauk Renewables, Inc.
Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm		113
Consolidated Balance Sheet as of December 31, 2020		114
Notes to Consolidated Financial Statements		115

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Montauk Renewables, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Montauk Holdings USA, LLC (a Delaware limited liability company) and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of operations, member’s equity, and cash flows for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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 31, 2021

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MONTAUK HOLDINGS USA, LLC

CONSOLIDATED BALANCE SHEETS

(in thousands):	As of December 31,
	2020		2019
ASSETS
Current assets:
Cash and cash equivalents	$	20,992	$	9,788
Accounts and other receivables, net		5,449		9,968
Prepaid expenses and other current assets		6,044		2,786
Total current assets	$	32,485	$	22,542
Non-current restricted cash	$	567	$	567
Property, plant & equipment, net		187,046		193,498
Goodwill and intangible assets, net		14,033		12,398
Deferred tax assets		14,822		8,745
Operating lease right-of-use assets		586		769
Other assets		3,817		5,094
Total assets	$	253,356	$	243,613
LIABILITIES AND MEMBER’S EQUITY
Current liabilities:
Accounts payable	$	5,964	$	3,844
Accrued liabilities		11,539		8,685
Current portion of operating lease liability		282		269
Current portion of derivative instruments		1,185		588
Current portion of long-term debt		9,492		9,310
Total current liabilities	$	28,462	$	22,696
Long-term debt, less current portion	$	56,268	$	57,256
Non-current portion of operating lease liability		320		511
Non-current portion of derivative instruments		1,075		1,045
Asset retirement obligation		5,689		5,928
Other liabilities		1,920		1,920
Total liabilities	$	93,734	$	89,356
Member’s equity	$	159,622	$	154,257
Total liabilities and member’s equity	$	253,356	$	243,613

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

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MONTAUK HOLDINGS USA, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands except per share values):	For the year ended December 31,
	2020			2019			2018
Total operating revenues	$	100,383		$	105,714		$	115,087
Operating expenses:
Operating and maintenance expenses	$	43,463		$	39,783		$	29,073
General and administrative expenses		16,594			13,632			11,953
Royalties, transportation, gathering and production fuel		18,284			18,889			21,013
Depreciation and amortization		22,117			19,760			16,195
Gain on insurance proceeds		(3,934	)		—			—
Impairment loss		278			2,443			854
Transaction costs		—			202			176
Total operating expenses	$	96,802		$	94,709		$	79,264
Operating profit	$	3,581		$	11,005		$	35,823
Other expenses (income):
Interest expense	$	4,339		$	5,576		$	3,083
Net loss (gain) on sale of assets		320			10			(266	)
Other expense (income)		315			(47	)		(3,557	)
Total other expenses (income)	$	4,974		$	5,539		$	(740	)
Income (loss) before income taxes	$	(1,393	)	$	5,466		$	36,563
Income tax expense (benefit)		(5,996	)		(354	)		7,796
Net income	$	4,603		$	5,820		$	28,767

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

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MONTAUK HOLDINGS USA, LLC

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

(in thousands):	Member’s Equity
Balance December 31, 2017	$	130,293
Net income		28,767
Stock-based compensation		637
Dividends		(11,756	)
Balance December 31, 2018	$	147,941
Net income		5,820
Stock-based compensation		570
Dividends		(74	)
Balance December 31, 2019	$	154,257
Net income		4,603
Stock-based compensation		762
Balance December 31, 2020	$	159,622

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

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MONTAUK HOLDINGS USA, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands):	For the year ended December 31,
	2020			2019			2018
Cash flows from operating activities:
Net income	$	4,603		$	5,820		$	28,767
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		22,117			19,760			16,195
Provision (benefit) for deferred income taxes		(6,077	)		(898	)		6,300
Stock-based compensation		762			570			637
Related party receivables (loans to executives)		164			—			—
Gain on property insurance proceeds		(1,659	)		—			—
Non-cash asset held for sale transfer		—			—			1,234
Derivative mark-to-market and settlements		1,016			994			430
Net (gain)/loss on sale of assets		320			(40	)		(322	)
Accretion of asset retirement obligations		320			391			399
Amortization of debt issuance costs		695			1,118			655
Inventory obsolescence		—			—			105
Equity (income) loss of nonconsolidated investments		—			(94	)		224
Impairment loss		278			2,443			854
Accounts and other receivables and other current assets		2,483			(2,287	)		(3,196	)
Accounts payable and other accrued expenses		3,662			48			(2,630	)
Net cash provided by operating activities	$	28,684		$	27,825		$	49,652
Cash flows from investing activities
Capital expenditures	$	(17,646	)	$	(45,610	)	$	(40,162	)
Cash collateral deposits, net		—			353			(46	)
Proceeds from sale of equity method investments		—			300			—
Proceeds from insurance recovery		1,659			30			401
Distributions from equity method investment		—			—			(1,320	)
Proceeds from sale of assets		—			—			1,250
Acquisitions, net of cash received		—			—			(12,980	)
Net cash used in investing activities	$	(15,987	)	$	(44,927	)	$	(52,857	)
Cash flows from financing activities:
Borrowings of long-term debt	$	8,500		$	28,198		$	114,500
Repayments of long-term debt		(10,000	)		(55,001	)		(66,165	)
Debt issuance costs		—			(638	)		(2,348	)
Dividends		—			—			(11,756	)
Class B shareholder repurchase		—			(74	)		—
Net cash provided by (used in) financing activities	$	(1,500	)	$	(27,515	)	$	34,231
Net increase or decrease in cash and cash equivalents and restricted cash	$	11,197		$	(44,617	)	$	31,026
Cash and cash equivalents and restricted cash at beginning of year	$	10,362		$	54,979		$	23,953
Cash and cash equivalents and restricted cash at end of year	$	21,559		$	10,362		$	54,979
Reconciliation of cash, cash equivalents, and restricted cash at end of year:
Cash and cash equivalents	$	20,992		$	9,788		$	54,032
Restricted cash and cash equivalents-current		—			7			—
Restricted cash and cash equivalents-non-current		567			567			947
	$21,559			$10,362			$54,979
Supplemental cash flow information:
Capital expenditures financed by accounts payable	$	252		$	92		$	821
Cash paid for interest (net of amounts capitalized)		4,184			4,847			2,843
Cash paid for income taxes		(454	)		2,679			349
Change in asset retirement obligation estimate		—			—			(1,778	)

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

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MONTAUK HOLDINGS USA, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—DESCRIPTION OF BUSINESS

Operations and organization

Montauk Holdings USA, LLC and subsidiaries (“Montauk USA” or the “Company”) is a holding company, formed on November 20, 2006 for the specific purpose of acquiring the membership interests in MEC. On November 20, 2010, Montauk USA formed MEH, a wholly owned subsidiary to which Montauk USA contributed its membership interests in MEC. All references to operations and operating results pertain to the combined operations of MEC and MEH (collectively “Montauk Energy”). The Company is 100% owned by Montauk Holdings Ltd., an investment holding company, incorporated in South Africa with its operating subsidiaries domiciled in the United States. See Note 21 for additional information for a reorganization transaction and initial public offering that took place after the year ended December 31, 2020.

Montauk Energy 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, converting 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 and Texas. The Company sells RNG and Renewable Electricity, taking advantage of Environmental Attributes (as defined below) premiums available under federal and state policies that incentivize their use.

One of the Company’s key revenue drivers is the selling of captured gas and the selling of Renewable Identification Numbers (“RINs”) to fuel blenders. The Renewable Fuel Standard (“RFS”) is an Environmental Protection Agency (the “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.

The second primary revenue driver is the selling 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”). All three of the Company’s electric facilities receive revenue for the monetization of RECs either as a part of a power sales agreement or separately.

Collectively, the Company benefits from 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, as environmental attributes.

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COVID-19

In March 2020, the World Health Organization classified the outbreak of COVID-19 as a pandemic and recommended containment and mitigation measures worldwide. The Company is considered an essential company under the U.S. Federal Cybersecurity and Infrastructure Security Agency guidance and various state or local jurisdictions in which we operate. In response to the COVID-19 pandemic, the Infectious Disease and Response Plan was activated to lead the development and response to any infectious disease event.

Although the Company has not experienced any material disruptions in its ability to continue its business operations or a material impact to its financial results to date due to COVID-19, the potential future impact cannot be predicted with certainty. Although the Company is unable to predict the ultimate effects of the COVID-19 pandemic, the pandemic has adversely affected the Company’s business, financial condition and results of operations. The spread of COVID-19 has disrupted certain aspects of the Company’s operations, including commissioning of development sites which were delayed up to five months in 2020. Delayed commissioning also delays the registrations and qualifications necessary for EPA pathways, which in turn delays revenue streams from these facilities. In addition, the COVID-19 pandemic has caused delays and disruptions in the Company’s operations, including contract cancellations, and a decrease in operational efficiency in maintenance and operations. State and local mitigation protocols have contributed to reduced needs for transportation fuels, which has lowered and could continue to lower state-based environmental premiums. During 2020, the Company also faced a reduction in RINs pricing due to the outbreak of COVID-19.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements include the accounts of Montauk USA, MEH, MEC and their respective subsidiaries and joint ventures in which a controlling interest is held. 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.

Reclassification

Certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation in the consolidated statements of operations, primarily to present certain costs relating to customer transportation and gathering fees on a net basis within total operating revenues rather than included in royalties, transportation, gathering and production fuel. The effect of these reclassifications is a decrease of $1,855, $1,669 and $1,347 for the years ended December 31, 2020, 2019 and 2018, respectively, in both total operating revenues and royalties, transportation, gathering and production fuel.

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.

Our 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.

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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. From time to time, the Company holds cash in banks 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:

Buildings and improvements	5 - 30 years
Machinery and equipment	1 - 43 years
Gas mineral rights	15 - 25 years

In 2020, the Company received $3,934 in insurance proceeds related to an engine failure at an RNG facility of which $1,659 was related to the replacement of property and $2,275 was for the related business interruption. During 2019, the Company received insurance proceeds of $30 for business interruption at one of its RNG facilities as a result of a truck crash. During 2018, the Company received insurance proceeds of $401, net of deductibles of $250, related to schedule and performance inefficiencies due to a forced interconnection curtailment at one of its electric generation facilities. These insurance proceeds are included in Gain on insurance proceeds for the year ended December 31, 2020 and Other income for the years ended December 31, 2019 and 2018 on the Consolidated Statements of Operations.

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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 name & 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. Emission allowances consist of permanent allocations of nitrogen oxide (“NOx”) credits. In certain regions of the United States, our business operations require us to obtain environmental permits, including environmental permits for the emission of NOx from internal combustion engines. Except for permanent allocations of NOx credits, the NOx credits available for use each year are capped at a level necessary for ozone attainment per the National Ambient Air Quality Standards. Permanent allowance allocations represent an ongoing authorization to emit NOx, making permanent allocations highly valuable. The Company acquired permanent allowance allocations through a prior acquisition and they are required in order to operate sites that were part of the acquisition.

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

Interconnection	10 - 25 years
Customer contracts	2 - 15 years
Emissions allowances	Indefinite
Land use rights	Indefinite

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 held for sale are no longer depreciated or amortized.

Investments

Investments in companies in which the Company has the ability to exert significant influence, but not control, over operating and financial policies (generally, 20% to 50% ownership) are accounted for using the equity method. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. The equity method of accounting requires a company to recognize a loss in the value of an equity method investment that is other than a temporary decline.

On July 18, 2018, the Company entered into a joint venture, Red Top, in which it maintained an 80% ownership interest while a dairy farm owned 20% and represented the Company’s first RNG project on a dairy farm. Red Top was established to own and operate a manure digester and build, own and operate an RNG facility for a term of 20 years from commercial operation.

In March 2019, pursuant to the underlying joint venture agreement, the Company made the decision to sell its equity interest and no longer classified Red Top as a variable interest entity. The Company concluded that Red

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Top has met the criteria under applicable guidance for a long-lived asset to be held for sale and reclassified its investment in Red Top of $1,096 as a current asset held for sale. On July 26, 2019, the Company entered into an agreement to sell Red Top to the 20% owner for $300. The terms of the sale included the distribution of approximately $892 in fixed assets to the Company. After this distribution, the Company recorded a gain of approximately $94. The Company continued to classify the $892 of fixed assets as held for sale.

At December 31, 2019, the Company estimated the fixed assets held for sale carrying value exceeded the fair value and recorded an impairment charge of $892.

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 operating 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. Currently, an asset and liability only are recorded for leases classified as capital leases (financing leases). The measurement, recognition and presentation of expenses and cash flows arising from leases by a lessee remains the same. In connection with the adoption of this guidance, the Company has completed an assessment resulting in an accumulation of all of its leasing arrangements and has validated the information for accuracy and completeness. The Company has included further lease disclosures in Note 18.

Long-lived Asset Impairment

In accordance with ASC 360, Property, Plant and Equipment (“ASC 360”) 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, 2020, 2019 and 2018 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 which, in turn, may result in the recognition of an impairment loss.

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

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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 unless specific hedge criteria are met.

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 practicable 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.

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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 derivative instruments and asset retirement obligations.

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, 2020 and 2019. 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.

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, 2020 and 2019 is included in Note 10.

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 an output of its renewable operating projects can be separated and sold independent 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. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The Company had 0.1 million and 0.9 million RINs generated and unsold as of December 31, 2020 and 2019, 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 an output of its renewable operating projects are able to be separated and sold independent 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.

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.

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Employee Benefits

Leave entitlement

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

Bonus Plans

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

Recently Adopted Accounting Standards

In August 2018, the FASB issued ASU 2018-15, Intangibles–Goodwill and Other–Internal-Use Software, (“ASU 2018-15”) associated with a customer’s accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. The amendments align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. Costs for implementation activities in the application development stage are capitalized as prepayments depending on the nature of the costs, while costs incurred during the preliminary project and post-implementation stages are expensed as the activities are performed. The Company early adopted this amended guidance on January 1, 2020 prospectively, and it did not have a material impact on our consolidated financial statements.

In December 2019, the 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.

Recently Issued Accounting Standards

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”). The new guidance changes how entities measure credit losses on financial instruments and the timing of when such losses are recorded. The new standard is effective for fiscal years beginning after December 15, 2022, with early adoption permitted. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements and related disclosures.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848)—(“ASU 2020-04”), 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 Company is assessing which of its contracts will require an update for a new reference rate, and will determine the timing for its implementation of this guidance at the completion of that analysis.

NOTE 3—ASSET IMPAIRMENT

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

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related to the acquisition of Pico Energy, LLC (“Pico”). For the year ended December 31, 2019, the Company calculated and recorded an impairment loss of $2,443. Of the 2019 loss, $1,690 and $753 is included in RNG and Renewable Electricity Generation, respectively. The impairment loss was due to the continued deterioration in market pricing for electricity, conversion of existing Renewable Electricity to RNG sites, cancellation of a site conversion agreement, and calculated based upon replacement cost and pre-tax cash flow projections, which is considered a Level 3 measurement. The Company recorded an impairment loss of $854 for the year ended December 31, 2018 in Renewable Electricity Generation. The impairment loss was due to the conversion of certain Renewable Electricity facilities to RNG facilities and the continued deterioration in market pricing for electricity as well as a cancellation of a site conversion agreement. Impairment loss was recorded under Operating expenses within the Consolidated Statements of Operations for the years ended December 31, 2020, 2019, and 2018.

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 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 either using an output or measure 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 32%, 37% and 35% of revenue for the years ended December 31, 2020, 2019 and 2018, 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 68%, 63% and 65% of revenue for the years ended December 31, 2020, 2019 and 2018, 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.

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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, 2020, 2019 and 2018:

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

	Year Ended December 31, 2019
	Goods transferred at a point in time		Goods transferred over time		Total
Major Goods/Service Line:
Natural Gas Commodity	$	6,591	$	25,594	$	32,185
Natural Gas Environmental Attributes		52,204		—		52,204
Electric Commodity		—		12,396		12,396
Electric Environmental Attributes		7,231		—		7,231
	$	66,026	$	37,990	$	104,016
Operating Segment:
RNG	$	58,795	$	25,594	$	84,389
REG		7,231		12,396		19,627
	$	66,026	$	37,990	$	104,016

	Year Ended December 31, 2018
	Goods transferred at a point in time		Goods transferred over time		Total
Major Goods/Service Line:
Natural Gas Commodity	$	13,069	$	28,827	$	41,896
Natural Gas Environmental Attributes		55,341		—		55,341
Electric Commodity		—		12,044		12,044
Electric Environmental Attributes		6,163		—		6,163
	$	74,573	$	40,871	$	115,444
Operating Segment:
RNG	$	68,410	$	28,827	$	97,237
REG		6,163		12,044		18,207
	$	74,573	$	40,871	$	115,444

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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 and, while collateral is not required, the Company periodically receives surety bonds that guarantee payment. 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 and were $0, $360 and $0 for the years ended December 31, 2020, 2019 and 2018, respectively.

Accounts and other receivables consist of the following as of December 31, 2020 and 2019:

	Year Ended December 31,
	2020		2019
Accounts receivables	$	5,264	$	9,859
Other receivables		164		173
Reimbursable expenses		21		8
Allowance for doubtful accounts		—		(72	)
Accounts and Other Receivables, Net	$	5,449	$	9,968

NOTE 6—PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment consists of the following as of December 31, 2020 and 2019 :

	Year Ended December 31,
	2020		2019
Buildings and improvements	$	28,065	$	13,999
Machinery and equipment		246,874		229,793
Gas mineral rights		34,551		40,451
Construction work in progress		4,485		30,125
Total		313,975		314,368
Less: Accumulated depreciation and amortization		(126,929)		(120,870	)
Property, Plant & Equipment, Net	$	187,046	$	193,498

Depreciation expense for property plant and equipment was $18,679, $15,878 and $12,368 and amortization expense for gas mineral rights was $1,965, $2,355 and $2,256 for the years ended December 31, 2020, 2019 and 2018, respectively.

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NOTE 7—GOODWILL AND INTANGIBLE ASSETS, NET

Intangible assets consist of the following as of December 31, 2020 and December 31, 2019:

	Year Ended December 31,
	2020		2019
Goodwill	$	60	$	60
Intangible assets with indefinite lives:
Emissions allowances	$	777	$	777
Land use rights		329		329
Total intangible assets with indefinite lives:	$	1,106	$	1,106
Intangible assets with finite lives:
Interconnection, net of accumulated amortization of $2,329 and $1,613	$	11,951		9,327
Customer contracts, net of accumulated amortization of $16,367 and $15,832		916	$	1,905
Total intangible assets with finite lives:	$	12,867	$	11,232
Total Goodwill and Intangible Assets	$	14,033	$	12,398

The weighted average remaining useful life of the customer contracts and interconnection is approximately 4 years and 17 years, respectively. Amortization expense was $1,473, $1,526 and $1,570 for the years ended December 31, 2020, 2019 and 2018, respectively. Amortization expense for customer contracts and interconnection the next five years is as follows:

	Customer Contracts		Inter- Connections
Year Ending
2021	$	726	$	760
2022		33		760
2023		23		691
2024		9		676
2025		8		676
Thereafter		117		8,388

NOTE 8—ASSET RETIREMENT OBLIGATIONS

The following table summarizes the activity associated with asset retirement obligations of the Company for the years ended December 31, 2020, 2019, and 2018:

	Year ended December 31,
	2020			2019			2018
Asset retirement obligations—beginning of year	$	5,928		$	5,399		$	6,472
Accretion expense		320			391			399
Changes in asset retirement obligations estimate		—			—			(1,778	)
New asset retirement obligations		350			177			306
Decommissioning		(909	)		(39	)		—
Asset retirement obligations—end of year	$	5,689		$	5,928		$	5,399

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NOTE 9—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, 2020, 2019, and 2018:

		Year Ended December 31,
Derivative Instrument	Location	2020			2019			2018
Commodity Contracts:
Realized Natural Gas	Gas commodity sales	$	551		$	1,446		$	(451	)
Unrealized Natural Gas	Other income		(388	)		252			91
Interest Rate Swaps	Interest expense		(628	)		(1,246	)		(520	)
Net gain (loss)		$	(465	)	$	452		$	(880	)

NOTE 10—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, 2020 and 2019, set forth by level, within the fair value hierarchy:

	December 31, 2020
	Level 1		Level 2			Level 3			Total
Interest rate swap derivative liabilities	$	—	$	(2,260	)	$	—		$	(2,260	)
Asset retirement obligations		—		—			(5,689	)		(5,689	)
Pico earn-out liability		—		—			(1,920	)		(1,920	)
	$	—	$	(2,260	)	$	(7,609	)	$	(9,869	)
	December 31, 2019
	Level 1		Level 2			Level 3			Total
Current commodity derivative asset	$	388	$	—		$	—		$	388
Current interest rate swap derivative liabilities		—		(1,633	)		—			(1,633	)
Asset retirement obligations		—		—			(5,928	)		(5,928	)
Pico earn-out liability		—		—			(1,920	)		(1,920	)
	$	388	$	(1,633	)	$	(7,848	)	$	(9,093	)

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, 2020 and 2019 is included in Note 8.

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.

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NOTE 11—ACCRUED LIABILITIES

The Company’s accrued liabilities consists of the following as of December 31, 2020 and December 31, 2019:

	Year ended December 31,
	2020		2019
Accrued expenses	$	4,975	$	4,952
Payroll and related benefits		2,341		849
Royalty		2,620		1,440
Utility		1,147		1,105
Other		456		339
Accrued Liabilities	$	11,539	$	8,685

NOTE 12—DEBT

The Company’s debt consists of the following as of December 31, 2020 and December 31, 2019:

	Year ended December 31,
	2020			2019
Term Loans	$	30,000		$	40,000
Revolving credit facility		36,697			28,198
Less: current principal maturities		(10,000	)		(10,000	)
Less: debt issuance costs (on long-term debt)		(429	)		(942	)
Long-term Debt	$	56,268		$	57,256
Current Portion of Long- term Debt		9,492			9,310
	$	65,760		$	66,566

Amended Credit Agreement

On December 12, 2018, the Company entered into the Second Amended and Restated Revolving Credit and Term Loan Agreement (as amended by the First Amendment to Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of March 21, 2019 (the “First Amendment”), and the Second Amendment to Second Amended and Restated Revolving Credit and Term Loan Agreement, dated as of September 12, 2019 (the “Second Amendment”), and as may be further amended from time to time (the “Credit Agreement”), by and among the Company, 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) amends and restates in its entirety the Amended and Restated Revolving Credit And Term Loan Agreement, dated as of August 4, 2017 (as amended by the First Amendment to Amended and Restated Revolving Credit And Term Loan Agreement, dated as of August 14, 2018 (the “Prior Credit Agreement”), by and between the Company and Comerica and (ii) replaces in its entirety the Credit Agreement, dated as of August 4, 2017 (as amended by the First Amendment to Credit Agreement, dated as of July 30, 2018 (the “Prior Subsidiary Credit Agreement”), by and between Bowerman Power LFG, LLC, a wholly-owned subsidiary of the Company, and Comerica. Proceeds of the term loan made under the Credit Agreement were used by the Company to, among other things, fully satisfy $28,232 of outstanding borrowings under the Prior Credit Agreement and $24,336 of outstanding borrowings under the Prior Subsidiary Credit Agreement.

On March 21, 2019, the Company entered into 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.

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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. The maturity date of the Credit Agreement was not changed by the Second Amendment and remains December 12, 2023.

The Credit Agreement, which is secured by a lien on substantially all assets of the Company and certain of its subsidiaries, provides for a $95,000 term loan and an $80,000 revolving credit facility. The term loan amortizes in quarterly installments of $2,500 and has a final maturity of December 12, 2023 with an interest rate of 2.961% and 4.642% at December 31, 2020 and 2019, respectively.

As of December 31, 2020, $30,000 was outstanding under the term loan and $36,697 was outstanding under the revolving credit facility. In addition, the Company had $7,145 of outstanding letters of credit as of December 31, 2020. Amounts available under the revolving credit facility are reduced by any amounts outstanding under letters of credit. As of December 31, 2020, the Company’s capacity available for borrowing under the revolving credit facility was $36,158. Borrowings of the term loans and revolving credit facility bear interest at the LIBOR rate plus an applicable margin or the Prime Reference Rate plus an applicable margin, as elected by the Company.

The Company accounted for the Credit Agreement as a debt modification in accordance with ASC 470, Debt (“ASC 470”). In connection with the Credit Agreement, the Company paid a total of $1,821 in new debt issuance costs comprised of $836 in costs paid to the lenders and $985 in costs paid as arranger fees. Of this amount, $364 was expensed and $1,457 was capitalized and will be amortized over the life of the Credit Agreement. The Company also incurred $59 in legal fees associated with the Credit Agreement. Amortized debt issuance expense in the amount of $695, $1,118 and $655 for the years ended December 31, 2020, 2019 and 2018, respectively, was recorded in the interest expense on the statement of operations.

As of December 31, 2020, the Company was in compliance with all financial covenants related to the Credit Agreement.

The Company entered into the Third Amendment to the Amended Credit Agreement in January 2021. The Company has included further information in Note 21.

Prior Credit Agreement

On August 4, 2017, the Company entered into the Prior Credit Agreement, by and between the Company and Comerica. The Prior Credit Agreement provided a three-year term loan in the amount of $20,000 and a three-year revolving credit facility in the amount of $20,000. On August 14, 2018, the Company entered into the First Amendment to Amended and Restated Revolving Credit and Term Loan Agreement (the “First Amendment to Prior Credit Agreement”), which among other items, temporarily increased commitments of the revolving credit facility to $40,000 and amended certain financial covenants thereunder. The Prior Credit Agreement replaced the Company’s $12,000 term loan and $12,000 revolving credit facility outstanding as of March 31, 2017. In connection with entering into the Prior Credit Agreement, the Company recorded a loss on extinguishment of approximately $1,611. The Company paid approximately $1,127 related to this extinguishment. The Company was the sole borrower under the Prior Credit Agreement, mandatory repayments were due in monthly installments through August 2020, and the obligations thereunder were secured by a lien on substantially all of the assets of the Company, except for those assets secured by the Prior Subsidiary Credit Agreement. The Prior Credit Agreement required the Company to maintain customary affirmative and negative covenants, including certain financial ratios, which were measured at the end of each fiscal quarter. As of December 31, 2018, the Company was in compliance with all financial covenants related to the Prior Credit Agreement. As described above, the Prior Credit Agreement was paid in full on December 12, 2018 when the Company entered into the Credit Agreement.

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In addition, the Company had $8,260 of outstanding letters of credit under the Prior Credit Agreement as of December 31, 2018. Amounts available under the revolving credit facility were reduced by any amounts outstanding under letters of credit. The Company’s capacity available for borrowing under the revolving credit facility was $13,700 for the year ended December 31, 2018.

Under the Prior Credit Agreement, the term loans and revolving credit facilities bore interest at the LIBOR plus an applicable margin or the Prime Reference Rate (as defined in the Prior Credit Agreement) plus an applicable margin, as elected by the Company. As of December 31, 2018, the interest rate on the outstanding term loan under the Prior Credit Agreement was 5.590%.

The Company was in compliance with all financial covenants related to the Prior Credit Agreement through December 12, 2018 when it was amended and restated by the Credit Agreement.

Prior Subsidiary Credit Agreement

On August 4, 2017, Bowerman Power LFG, LLC, a wholly-owned subsidiary of the Company (“Bowerman”), entered into the Prior Subsidiary Credit Agreement, by and between Bowerman and Comerica. The Prior Subsidiary Credit Agreement, which was secured by a lien on substantially all of the assets of Bowerman, provided for a five-year term loan in the amount of $27,500 and a five-year revolving credit facility in the amount of $10,000. On July 30, 2018, the Company entered into the First Amendment to Credit Agreement (the “First Amendment to Prior Subsidiary Credit Agreement”), which among other items, reduced the monthly principal payment and increased the payoff amount at the end of the term under the Prior Subsidiary Credit Agreement. The proceeds from the Prior Subsidiary Credit Agreement were used to repay all indebtedness outstanding under Bowerman’s construction term loan that was outstanding as of August 4, 2017. Mandatory repayments of the Prior Subsidiary Credit Agreement were payable in monthly installments through August 2022 at an interest rate of 4.914%. The Prior Subsidiary Credit Agreement was paid in full on December 12, 2018 when the Company entered into the Credit Agreement.

The Prior Subsidiary Agreement required Bowerman to maintain customary affirmative and negative covenants, including certain financial ratios, which were measured at the end of each fiscal quarter. Amounts available under the Prior Subsidiary Credit Agreement’s revolving credit facility were reduced by $1,960 in outstanding letters of credit.

The Company was in compliance with all financial covenants related to the Prior Subsidiary Agreement through December 12, 2018 when it was fully repaid and replaced by the Credit Agreement.

Capitalized Interest

Capitalized interest was $1,056 and $1,706 for the years ended December 31, 2020 and December 31, 2019, respectively. Interest is capitalized using the borrowing rate for the assets being constructed. Interest capitalized during 2020 and 2019 was for the construction of two and three LFG-to-energy projects, respectively.

Annual Maturities of Long-Term Debt

The following is a summary of annual principal maturities of long-term debt as of December 31, 2020:

Year Ending	Amount
2021	$	10,000
2022		10,000
2023		46,697
Total	$	66,697

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NOTE 13—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 (i) temporary removal of the 80% taxable income limitation on utilization of Net Operating Losses (NOLs), (ii) deferral of employer withholding tax requirements, (iii) 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.

The following table details the components of the Company’s income tax provision (benefit) for the years ended December 31, 2020 and December 31, 2019:

	Year Ended December 31,
	2020			2019			2018
Current expense (benefit):
Federal	$	—		$	—		$	(973	)
State		81			544			2,469
	$	81		$	544		$	1,496
Deferred expense (benefit):
Federal	$	(5,358	)	$	(722	)	$	4,784
State		(719	)		(176	)		1,516
	$	(6,077	)	$	(898	)	$	6,300
Income Tax Expense (Benefit)	$	(5,996	)	$	(354	)	$	7,796

The following table illustrates the deferred tax assets and liabilities as of December 31, 2020 and December 31, 2019:

	Year ended December 31,
	2020			2019
Deferred tax assets:
Net operating loss (“NOL”) carry forwards	$	22,203		$	16,843
Federal tax credits		10,464			8,402
Book reserves		1,538			1,768
Intangible asset amortization		9,264			852
Interest expense		—			6,501
Other		3,396			2,235
Total Deferred Tax Assets		46,865			36,601
Less: valuation allowance		(3,888	)		(4,174	)
Net deferred tax assets	$	42,977		$	32,427
Deferred tax liabilities:
Property depreciation	$	(28,155	)	$	(23,682	)
Total deferred tax liabilities		(28,155	)		(23,682	)
Net Deferred Tax Assets	$	14,822		$	8,745

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As of December 31, 2020, the Company has federal net operating loss (“NOL”) carryforwards of $95,536, of which $53,525 were generated prior to the TCJA and will begin to expire in tax year 2028. The remaining $42,001 current NOL carryforwards are indefinite lived. Of the total federal NOL carryforwards, $12,986 were historically generated by Monmouth Energy, Inc. and are limited for use under the separate return limitation year rules.

On January 1, 2020, the minority investor of MEC, Johnstown 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 the current year. This transaction allowed Monmouth Energy Inc., a subsidiary of MEC, to file as part of our consolidated federal tax group.

The Company has $10,464 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 $26,760 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, 2020, 2019 and 2018:

	Year Ended December 31,
	2020			2019			2018
Tax provision at federal statutory rate of 21%	$	(293	)	$	1,125		$	7,693
State tax provision		(50	)		(29	)		2,576
Non-controlling interests		—			16			(15	)
Valuation allowance		(286	)		634			467
Production tax credit		(2,036	)		(1,881	)		(2,821	)
Return to provision		(34	)		(24	)		(284	)
Impact of MEC partnership dissolution		(2,417	)		—			—
Deferred tax adjustments		(908	)		—			—
Other		28			(195	)		180
Total Income Tax Expense (Benefit)	$	(5,996	)	$	(354	)	$	7,796

The Company has completed an Internal Revenue Service (“IRS”) examination for the period ended March 31, 2011 with no material adjustments. Additionally, the IRS completed an exam for the period ended March 31, 2018 with a “No Change” result. As of December 31, 2020, the tax years 2017, 2018 and 2019 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 $3,888 valuation allowance exists for Monmouth Energy, Inc., which represents the subsidiary’s deferred tax assets that are not expected to be realized. This represents a $286 decrease in valuation allowance from $4,174 at the year ended December 31, 2019.

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.

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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, 2020 or 2019. 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, 2020 and December 31, 2019, the Company has zero penalties or interest accrued at December 31, 2020 and 2019, respectively.

NOTE 14—SHARE-BASED COMPENSATION

The Company records and reports share-based compensation for stock options (“Options”) and restricted stock. When vested and exercised, Options and restricted stock are converted into shares of, and issued by, the Company’s parent, Montauk Holdings Ltd. The Company does not have an equity plan from which it issues options or restricted stock.

The Options issued allows the recipient to receive common stock equal to the appreciation in the fair market value of the Company’s common stock between the date the award was granted and the conversion date of the shares vested.

The following table summarizes the Options and restricted stock as of December 31, 2020, 2019 and 2018:

	Options					Restricted Stocks
	Number of Shares			Weighted Average Exercise Price		Number of Shares		Weighted Average Exercise Price
Beginning of Period—January 1, 2018		875,000		$	0.44		1,939,200	$	0.95
Granted		204,480			1.84		—		—
End of period—December 31, 2018		1,079,480		$	0.71		1,939,200	$	0.95
Beginning of Period- January 1, 2019		1,079,480		$	0.71		1,939,200	$	0.95
Granted		2,027,666			1.48		—		—
Forfeited		(626,278	)		1.67		—		—
Exercised		(608,334	)		0.86		—		—
End of period—December 31, 2019		1,872,534		$	1.18		1,939,200	$	0.95
Beginning of period—January 1, 2020		1,872,534		$	1.18		1,939,200	$	0.95
Granted		924,779			0.90		—		—
Forfeited		(166,666	)		0.62		—		—
Exercised		(50,000	)		0.44		—		—
End of period—December 31, 2020		2,580,647		$	1.13		1,939,200	$	0.95
Vested and exercisable—December 31, 2020		50,000		$	0.56		1,939,200	$	0.95

During the year ended December 31, 2020, the intrinsic value of the 50,000 Options exercised was $50. The Company received $56 related to the exercise of a portion of these Options. At December 31, 2020 and December 31, 2019, the aggregate intrinsic value (difference between exercise price and closing price at that date) of all Options outstanding was $14,945 and $2,858, respectively.

Stock-based compensation expense for the years ended December 31, 2020, 2019, and 2018 was $762, $570 and $637, respectively, and is included in general and administrative expense in the Consolidated Statement of Operations.

As of December 31, 2020, unrecognized compensation expense for awards the Company expects to vest approximated $2,131 and will be recognized over approximately 5 years. The Company has included further information on Options and share-based compensation in Note 21.

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In May 2007, MEC issued 50.7 restricted Class B units to certain executives of MEC. Twenty percent of the units vested immediately upon issuance. The remaining units vested in four equal annual installments beginning in May 2008. The grant date fair value of the units issued was approximately $0.2 million. Six units issued in May 2007 were forfeited during 2011. The value of the units forfeited was immaterial. During 2016, 29.52 units issued in May 2007 were repurchased for an immaterial amount and 8.28 units issued in May 2007 were surrendered. No Class B units were issued and no units were forfeited during the years ended December 31, 2020 or 2019.

In July 2007, MEC issued Options to purchase up to 5.52 Class B units to an executive of MEC, with an exercise price of $3,600 per unit. Twenty percent of the Options vested immediately upon issuance. The remaining Options vested in four equal annual installments beginning in July 2008. In September 2019, 6.9 Class B units were canceled associated with the September 2019 resignation of the Company’s former Chief Executive Officer. In October 2019, 5.52 units were surrendered in consideration of a restricted stock award discussed previously.

As MEC’s units are not publicly traded, the Company utilized the probability-weighted expected return method (“PWERM”) to value the Class B units issued. Under the PWERM, the value of the units was estimated based upon a probability-weighted present value of expected future investment returns for the enterprise assuming various future outcomes. The future outcomes considered were an initial public offering, a merger or sale, dissolution or continued operation as the existing private enterprise. The discount rate utilized was 15%, with an additional 33% discount on the estimated value for the lack of marketability of the units.

NOTE 15—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 $521, $438 and $400 for the years ended December 31, 2020, 2019 and 2018, respectively.

NOTE 16—RELATED-PARTY TRANSACTIONS

Executive Loans

In March 2019, the Company’s former Chief Executive Officer and Vice President Engineering exercised 100,000 and 25,000 shares, respectively, of a vested tranche of Options. In connection with this exercise, the Company loaned to its former Chief Executive Officer and Vice President Engineering $80 and $20, respectively, related to the personal income tax consequences of the exercise. Both of these loans have an interest rate of 2.53% and mature on July 31, 2019. In July 2019, the maturity of both of these loans were amended to mature on March 21, 2020. The Company’s former Chief Executive Officer repaid the loan in February 2020 and the Vice President of Engineering repaid the loan in March 2020.

These loans are included in Prepaid expenses and other current assets in the December 31, 2019 Consolidated Balance Sheet.

Options

In December 2019, the Company’s current Chief Executive Officer and former Vice President and General Counsel exercised 50,000 and 83,334 shares, respectively, of a vested tranche of Options. In connection with this exercise, the Company loaned its current Chief Executive Office and former Vice President and General Counsel $29 and $36, respectively related to the personal income tax consequences of the exercise. Both of these loans were repaid in January 2020.

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NOTE 17—SEGMENT INFORMATION

The Company’s reportable segments for the years ended December 31, 2020, 2019, and 2018 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” refer to Renewable Electricity Generation.

	For the year ended December 31, 2020
	RNG		REG			Corporate			Total
Total Revenue	$	83,236	$	16,665		$	482		$	100,383
Net Income (Loss)		22,068		(2,713	)		(14,752	)		4,603
EBITDA		36,920		4,649			(16,506	)		25,063
Adjusted EBITDA(1)		37,219		4,948			(16,118	)		26,049
Total Assets		159,899		52,539			40,918			253,356
Capital Expenditure		14,071		3,513			62			17,646

(1) 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:

	For the year ended December 31, 2020
	RNG		REG			Corporate			Total
Net Income (loss)	$	22,068	$	(2,713	)	$	(14,752	)	$	4,603
Depreciation and amortization		14,852		7,086			179			22,117
Interest expense		—		—			4,339			4,339
Income tax expense (benefit)		—		276			(6,272	)		(5,996	)
EBITDA	$	36,920	$	4,649		$	(16,506	)	$	25,063
Impairment loss		—		278			—			278
Net loss (gain) of sale of assets		299		21			—			320
Non-cash hedging charges		—		—			388			388
Adjusted EBITDA	$	37,219	$	4,948		$	(16,118	)	$	26,049
	For the year ended December 31, 2019
	RNG		REG			Corporate			Total
Total Revenue	$	84,157	$	19,859		$	1,698		$	105,714
Net Income (Loss)		25,640		(1,635	)		(18,185	)		5,820
EBITDA		37,342		5,428			(11,968	)		30,802
Adjusted EBITDA(2)		39,019		6,185			(12,093	)		33,111
Total Assets		136,068		83,051			24,494			243,613
Capital Expenditure		33,509		11,731			370			45,610

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(2) 2019 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, 2019:

	For the year ended December 31, 2019
	RNG			REG			Corporate			Total
Net Income (loss)	$	25,640		$	(1,635	)	$	(18,185	)	$	5,820
Depreciation and amortization		11,702			7,878			180			19,760
Interest expense		—			7			5,569			5,576
Income tax expense (benefit)		—			(822	)		468			(354	)
EBITDA	$	37,342		$	5,428		$	(11,968	)	$	30,802
Impairment loss		1,690			753			—			2,443
Transaction Cost		83			4			115			202
Equity gain of nonconsolidated investments		(94	)		—			—			(94	)
Net loss (gain) of sale of assets		(2	)		—			12			10
Non-cash hedging charges		—			—			(252	)		(252	)
Adjusted EBITDA	$	39,019		$	6,185		$	(12,093	)	$	33,111
	For the year ended December 31, 2018
	RNG			REG			Corporate			Total
Total Revenue	$	97,238		$	18,207		$	(358	)	$	115,087
Net Income (Loss)		51,102			(1,639	)		(20,696	)		28,767
EBITDA		60,176			7,378			(11,713	)		55,841
Adjusted EBITDA(3)		59,877			8,489			(11,629	)		56,737
Total Assets		115,392			84,008			62,332			261,732
Capital Expenditure		37,528			2,471			163			40,162

(3) 2018 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, 2018:

	For the year ended December 31, 2018
	RNG			REG			Corporate			Total
Net Income (loss)	$	51,102		$	(1,639	)	$	(20,696	)	$	28,767
Depreciation and amortization		9,074			6,952			169			16,195
Interest expense		—			1,180			1,903			3,083
Income tax expense (benefit)		—			885			6,911			7,796
EBITDA	$	60,176		$	7,378		$	(11,713	)	$	55,841
Impairment loss		—			854			—			854
Transaction Cost		—			—			176			176
Equity loss (gain) of nonconsolidated investments		224			—			—			224
Net loss (gain) of sale of assets		(523	)		257			—			(266	)
Non-cash hedging charges		—			—			(92	)		(92	)
Adjusted EBITDA	$	59,877		$	8,489		$	(11,629	)	$	56,737

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For the years ended December 31, 2020, 2019 and 2018, four, five and three customers, respectively, made up greater than 10% of our total revenues.

	For the year ended December 31, 2020
	RNG			REG			Corporate		Total
Customer A		15.1	%		—			—		15.1	%
Customer B		—			14.4	%		—		14.4	%
Customer C		14.1	%		—			—		14.1	%
Customer D		11.3	%		—			—		11.3	%
	For the year ended December 31, 2019
	RNG			REG			Corporate		Total
Customer A		—			14.5	%		—		14.5	%
Customer B		14.2	%		—			—		14.2	%
Customer C		14.1	%		—			—		14.1	%
Customer D		11.2	%		—			—		11.2	%
Customer E		11.1	%		—			—		11.1	%
	For the year ended December 31, 2018
	RNG			REG			Corporate		Total
Customer A		—			11.8	%		—		11.8	%
Customer B		18.3	%		—			—		18.3	%
Customer C		15.9	%		—			—		15.9	%

NOTE 18—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 2024. 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.

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 that would be approximate the rate to borrow funds on a collateralized basis over a similar term and in a similar economic environment.

As of December 31, 2020, 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 year ended December 31, 2020 was $322.

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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 year ended December 31, 2020 was approximately $637.

Supplemental information related to operating lease arrangements was as follows as of and for the year ended December 31, 2020 and 2019:

	December 31, 2020			December 31, 2019
Cash paid for amounts included in the measurement of operating lease liabilities	$	301		$	83
Weighted average remaining lease term (in years)		1.53			3.06
Weighted average discount rate		5.00	%		5.00	%

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

Year Ending	Amount
2021	$	303
2022		317
2023		8
2024		1
Interest		(27	)
Total	$	602

NOTE 19—COMMITMENTS AND CONTINGENCIES

Concentrations

A substantial portion of the Company’s revenues are generated from five locations in 2020, 2019, and 2018, each in separate areas of the country. For the years ended December 31, 2020, 2019 and 2018, excluding the impact of derivative instruments, approximately 80%, 83% and 83%, respectively, of operating revenues were derived from these locations. In addition, five customers make up approximately 81% and 67% of trade receivables as of December 31, 2020 and December 31, 2019, 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, 2020, 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.

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NOTE 20—QUARTERLY FINANCIAL DATA (UNAUDITED)

Presented below is the selected quarterly financial data for year 2020 and year 2019, 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.

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2020
Operating Revenues	$	18,403		$	27,910		$	28,249		$	25,821
Operating Income (Loss)		(2,783	)		3,563			4,835			(2,034	)
Net Income (Loss)(1)		5,816			(1,583	)		(2,084	)		2,454
2019
Operating Revenues	$	31,674		$	28,145		$	22,663		$	23,232
Operating Income (Loss)(2)		5,466			4,100			911			528
Net Income (Loss)(2)		3,874			2,151			(202	)		(3	)

(1) In 2020, the company received $3,934 in insurance proceeds related to an engine failure and related business interruption at an RNG facility.

(2) 2019 stock based compensation expense was reclassed between the third and fourth quarter. The third quarter Operating Income increased and the Net Loss decreased by $375.

NOTE 21—SUBSEQUENT EVENTS

Subsequent Events

The Company evaluated its December 31, 2020 consolidated financial statements through March 31, 2021, 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, except for the matters discussed below.

Reorganization transaction and initial public offering

Starting January 4, 2021, Montauk Renewables, Inc. (“MRI”), Montauk Holdings Limited (“MNK”) and the Company (as a direct wholly-owned subsidiary of MNK at the time) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions”, (as detailed further below) that resulted in MRI owning all of the assets and entities (other than Montauk USA) previously owned by 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 the Company. MRI had no significant operations or assets prior to January 4, 2021 when it engaged in the equity exchange with the Company described below. The key steps involved in the Reorganization Transactions included:

• On January 4, 2021, Montauk USA transferred to MRI all of the issued and outstanding equity of MEH in exchange for all of the outstanding shares of MRI common stock (the “Transfer”). Subsequently, Montauk USA became the sole stockholder of MRI and MEH became a wholly owned subsidiary of MRI.

• On January 4, 2021, Montauk USA distributed all of the shares of MRI common stock to Company’s sole equity holder, MNK, and elected to be disregarded for U.S. tax purposes (collectively, with the Transfer, the “Equity Exchange”). Subsequently, MRI became a direct wholly owned subsidiary of MNK until the Distribution (as defined below) and Montauk USA remained a direct wholly-owned subsidiary of MNK but without any substantial assets.

• On January 15, 2021, MNK sold the membership interest of Montauk USA to a third party after completing the Reorganization Transactions, Transfer, and Equity Exchange.

• On January 26, 2021, MNK distributed all of the outstanding shares of Company’s common stock as a pro rata dividend to the holders of MNK’s ordinary shares (the “Distribution”), subject to any tax

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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 Company’s common stock. The Transaction Implementation Agreement with MNK governed the Distribution, the allocation of assets and liabilities between MNK and Montauk, and MRI’s relationship with MNK following the Reorganization Transactions. Following the Distribution, MRI’s common stock was secondarily listed on the Johannesburg Stock Exchange under the symbol “MKR.”

• On January 26, 2021, MRI closed its initial public offering of its common stock on the Nasdaq Capital Market under the symbol “MNTK.” MRI issued 2,702,500 shares at $8.50 per share and received gross proceeds of $22,971. These proceeds were reduced by approximately $2,324 in costs associated with the initial public offering and were recorded within additional paid-in capital in the Consolidated Balance Sheet of MRI. An additional $5,054 in initial public offering costs were reclassified from prepaid expense and other current assets to additional paid-in capital in the Consolidated Balance Sheet of MRI at the closing of the initial public offering.

In connection with the initial public offering, MNK as a selling shareholder sold 697,015 shares of Common stock of MRI at $8.50 per share with the proceeds being received by MNK.

After full completion of the Reorganization Transactions and the initial public offering, (i) Montauk USA ceased to own any substantial assets and (ii) all entities through which MNK’s business and operations were conducted are owned, directly or indirectly, by MRI. Additionally, MNK adopted a plan contemporaneously with the completion of the Reorganization Transactions that authorized the liquidation and dissolution of MNK. As a result, MNK was delisted from the JSE on January 26, 2021. MNK will be liquidated within 24 months of the Distribution.

In connection with the completion of the Reorganization Transactions and the initial public offering, the Company entered into the Third Amendment to the Amended Credit Agreement. This amendment permitted the Change of Control provisions, as defined in the underlying agreement, to permit the Reorganization Transactions and initial public offer to be completed with respect to MRI. The amendment also added LIBOR cessation fallback language for a transition to specified alternative SOFR-based rates, or, if those alternatives cannot be determined, to another rate selected by the administrative agent and the borrower under the Amended Credit Agreement as well as provisions that allow one or more parties to transition in advance of the dates set forth above where specified conditions are met.

In connection with the Distribution, MNK cancelled the Options held by the Company’s officers that had been granted by MNK’s board of directors to them under MNK’s Employee Share Appreciation Rights Scheme for US Affiliates, dated October 29, 2015. The Company accounted for the cancellation of the Options in connection with FASB ASC 718 and recognized in general and administrative expenses in the Consolidated Statement of Operations approximately $2,050 of previous unrecognized compensation expense.

After full completion of the Reorganization Transactions and the initial public offering, (i) the Company ceased to own any substantial assets and (ii) all entities through which MNK’s business and operations were conducted are owned, directly or indirectly, by MRI.

In March 2021, MRI received notice from a landfill host amending the underlying gas rights agreement to remove and begin decommissioning activities related to one of the MRI’s renewable electric generation sites. MRI recorded an impairment of approximately $690 in the Renewable Electric Generation segment related to this notice.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Montauk Renewables, Inc.

Opinion on the financial statements

We have audited the accompanying balance sheet of Montauk Renewables, Inc. (a Delaware corporation) (the “Company”) as of December 31, 2020 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, 2020 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 audit. 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 audit 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 audit 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 audit 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 audit 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 audit provides a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2020.

Pittsburgh, Pennsylvania

March 31, 2021

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MONTAUK RENEWABLES, INC.

CONSOLIDATED BALANCE SHEET

(in thousands):	As of December 31, 2020
ASSETS
Current assets:
Cash	$	10.00
Total current assets		10.00
Total assets	$	10.00
STOCKHOLDER’S EQUITY
Common Stock, par value $0.01 per share, 1,000 shares authorized, 10 shares issued and outstanding	$	0.10
Additional paid-in capital		9.90
Total stockholder’s equity	$	10.00

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

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NOTE 1—DESCRIPTION OF BUSINESS

Operations and organization

Montauk Renewables, Inc. (or the “Company”) was organized as a Delaware corporation on September 21, 2020. Pursuant to a series of reorganization transactions, the Company will continue to conduct the business and operations now conducted by Montauk Holdings USA, LLC (“Montauk USA”). See Note 4 for additional information for a reorganization transaction and initial public offering that took place after the year ended December 31, 2020.

COVID-19

In March 2020, the World Health Organization classified the outbreak of COVID-19 as a pandemic and recommended containment and mitigation measures worldwide. The Company is considered an essential company under the U.S. Federal Cybersecurity and Infrastructure Security Agency guidance and various state or local jurisdictions in which we operate. In response to the COVID-19 pandemic, the Infectious Disease and Response Plan (“IDRC”) was activated to lead the development and response to any infectious disease event.

Although the Company has not experienced any material disruptions in its ability to continue its business operations or a material impact to its financial results to date due to COVID-19, the potential future impact cannot be predicted with certainty.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting

The Balance Sheet has been prepared in accordance with United States generally accepted accounting principles (“GAAP”). Separate statements of operations, changes in stockholders’ equity and cash flows have not been presented in the financial statements because there have been no activities in this entity or because the single transaction is fully disclosed below.

Cash

Cash includes highly liquid investments with maturity dates of three months or less from the date of purchase and are recorded at cost. From time to time, the Company holds cash in banks in excess of federally insured limits.

NOTE 3—STOCKHOLDER’S EQUITY

The Company is authorized to issue 1,000 shares of Common Stock, par value $0.01 per share, under the Company’s certificate of incorporation in effect as of September 21, 2020. In exchange for $10.00, the Company issued 10 shares of Common Stock as of December 31, 2020.

NOTE 4—SUBSEQUENT EVENTS

Subsequent Events

The Company evaluated its December 31, 2020 consolidated financial statements through March 31, 2021, 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, except for the matters discussed below.

Reorganization transaction and initial public offering

Starting January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC and subsidiaries (“Montauk USA”, as a direct wholly-owned subsidiary of MNK at the time) entered into a

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series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” (as detailed further below) that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by 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 described below. The key steps involved in the Reorganization Transactions included:

• On January 4, 2021, Montauk USA transferred to the Company all of the issued and outstanding equity of MEH in exchange for all of the outstanding shares of the Company common stock (the “Transfer”). Subsequently, Montauk USA became the sole stockholder of the Company and MEH became a wholly owned subsidiary of the Company.

• On January 4, 2021, Montauk USA distributed all of the shares of the Company’s common stock to the Montauk USA’s sole equity holder, MNK, and elected to be disregarded for U.S. tax purposes (collectively, with the Transfer, the “Equity Exchange”). Subsequently, the Company became a direct wholly owned subsidiary of MNK until the Distribution (as defined below) and Montauk USA remained a direct wholly-owned subsidiary of MNK but without any substantial assets.

• On January 15, 2021, MNK sold the membership interest of Montauk USA to a third party after completing the Reorganization Transactions, Transfer, and Equity Exchange.

• 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. The Transaction Implementation Agreement with MNK governed the Distribution, the allocation of assets and liabilities between MNK and Montauk USA, and the Company’s relationship with MNK following the Reorganization Transactions. Following the Distribution, the Company’s common stock was secondarily listed on the Johannesburg Stock Exchange under the symbol “MKR.”

• On January 26, 2021, the Company closed its initial public offering of its common stock on the Nasdaq Capital Market under the symbol “MNTK.” The Company issued 2,702,500 shares at $8.50 per share and received gross proceeds of $22,971. These proceeds were reduced by approximately $2,324 in costs associated with the initial public offering and were recorded within additional paid-in capital in the Consolidated Balance Sheet of the Company. An additional $5,054 in initial public offering costs were reclassified from prepaid expense and other current assets to additional paid-in capital in the Consolidated Balance Sheet of the Company at the closing of the initial public offering.

In connection with the initial public offering, MNK as a selling shareholder sold 697,015 shares of Common stock of the Company at $8.50 per share with the proceeds being received by MNK.

After full completion of the Reorganization Transactions and the initial public offering, (i) the Company ceased to own any substantial assets and (ii) all entities through which MNK’s business and operations were conducted are owned, directly or indirectly, by MRI. Additionally, MNK adopted a plan contemporaneously with the completion of the Reorganization Transactions that authorized the liquidation and dissolution of MNK. As a result, MNK was delisted from the JSE on January 26, 2021. MNK will be liquidated within 24 months of the Distribution.

In connection with the completion of the Reorganization Transactions and the initial public offering, the Company entered into the Third Amendment to the Amended Credit Agreement. This amendment permitted the Change of Control provisions, as defined in the underlying agreement, to permit the Reorganization Transactions and initial public offer to be completed with respect to MRI. The amendment also added LIBOR cessation

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fallback language for a transition to specified alternative SOFR-based rates, or, if those alternatives cannot be determined, to another rate selected by the administrative agent and the borrower under the Amended Credit Agreement as well as provisions that allow one or more parties to transition in advance of the dates set forth above where specified conditions are met.

In connection with the Distribution, MNK cancelled the Options held by the Company’s officers that had been granted by MNK’s board of directors to them under MNK’s Employee Share Appreciation Rights Scheme for US Affiliates, dated October 29, 2015. The Company accounted for the cancellation of the Options in connection with FASB ASC 718 and recognized in general and administrative expenses in the Consolidated Statement of Operations approximately $2,050 of previous unrecognized compensation expense.

The board of directors of the Company approved on January 28, 2021 the grant of 2,092,836 restricted stock and 950,214 non-qualified stock awards under the Equity and Incentive Compensation Plan (“EICP”) to the officers of the Company. The restricted stock and option awards are subject to vesting schedules that commence or conclude, in the case of the option awards, on the one-year anniversary of the grant date and are subject to the terms and conditions of the EICP and related award agreements. Additionally, the Company board of directors approved the grants of 264 restricted stock units (with each unit representing one share of Common Stock) to approximately 112 employees of the Company, including the aforementioned officers, under the EICP and which awards generally vest on the one-year anniversary of the grant date and are subject to the terms and conditions of the EICP and the related award agreement. The closing price of the Company was $11.38 on the date of grant. The Company will account for these awards under the provisions of ASC 718 by recognizing the fair value of the award and grants over the requisite service periods.

In connection with the grants of the restricted stock, the officers of the Company made elections under Section 83(b) of the Internal Revenue Code. On January 28, 2021, the Company repurchased 950,214 as treasury shares at a purchase price of $11.38 per share related to these elections.

In connection with the completion of the Reorganization Transaction and the initial public offering, the Company entered into a Loan Agreement and Secured Promissory Note (the “Initial Promissory Note”) with 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 Distribution under the South African Income Tax Act, 1962 (Act No. 58 of 1962), as amended. 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 $7,000, in the aggregate, 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 Amended Promissory Note , among other things, (1) allows MNK (as borrower) to pay interest by increasing the outstanding principal amount of the note or by paying cash to the Company (or both), (2) grant the Company a pledge over 800,000 shares of its common stock withheld by MNK to satisfy tax obligations arising from the Distribution as security for MNK’s loan obligations and (3) require MNK to use the proceeds of any sale of such shares to prepay the amounts due to the Company under the Amended Promissory Note.

Other Events

In March 2021, the Company received notice from a landfill host amending the underlying gas rights agreement to remove and begin decommissioning activities related to one of the company’s renewable electric generation sites. The Company recorded a $690 impairment charge in the first quarter of 2021 in the Renewable Electric Generation segment related to this notice.

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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, 2020 (the end of the period covered by this Annual Report on Form 10-K), the Company’s disclosure controls and procedures were not effective based on the material weakness in internal control over financial reporting described below.

Previously Reported Material Weakness.

During the preparation of our interim financial statements in connection with our IPO, as well as the preparation of our year-end financial statements we and our independent public accounting firm identified a material weakness in internal control over financial reporting. As defined in Rule 12b-2 under the Exchange Act, a “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Specifically, we did not have adequate procedures and controls with respect to complete and accurate recording of inputs to the consolidated income tax provision and related accruals.

The identified control deficiencies could have resulted in a misstatement of our accounts or disclosures that could have resulted in a material misstatement of our annual or interim consolidated financial statements that would not be prevented or detected, and accordingly, we determined that these control deficiencies constituted a material weakness.

The material weakness also resulted in adjustments to deferred tax assets, income tax payable, member’s equity and income tax expense (benefit) in our consolidated financial statements as of the year ended December 31, 2020 and for the nine months ended September 30, 2020 and 2019, which were recorded prior to their issuance.

Under “Changes in Internal Control over Financial Reporting” below, we describe our remediation plan to address the identified material weakness.

Management’s Annual Report on Internal Control Over Financial Reporting.

This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Company’s registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.

Changes in Internal Control over Financial Reporting.

There have been changes in our internal control over financial reporting during the quarter ended December 31, 2020, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. During the quarter ended December 31, 2020, we continued to implement

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remediation initiatives in response to the previously identified material weakness in connection with our material weakness remediation plan as noted below.

As part of our ongoing remediation initiatives we continue to implement measures designed to improve our internal control over financial reporting in order to remediate the control deficiencies that led to the material weakness, including outsourcing the parallel preparation and review of our tax calculations and related disclosures by external specialists, and initiating design and implementation of our financial control environment which includes creation of additional controls including those designed to strengthen our review and reconciliation processes around preparation of the annual and interim tax provision and related disclosures.

If the steps we take do not remediate the material weakness in a timely manner, there could continue to be a reasonable possibility that these control deficiencies or others could result in a material misstatement of our annual or interim consolidated financial statements that would not be prevented or detected on a timely basis.

ITEM 9B. OTHER INFORMATION.

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is set forth in our Proxy Statement under the headings “Proposal No. 1—Election of Directors—Nominees for Election for a Term Expiring at the 2024 Annual Meeting,” “Proposal No. 1—Election of Directors—Information Regarding our Board of Directors and Corporate Governance—Code of Business Conduct and Ethics,” “Proposal No. 1—Election of Directors—Information Regarding our Board of Directors and Corporate Governance—Communications with the Board,” “Proposal No. 1—Election of Directors—Information Regarding our Board of Directors and Corporate Governance—Information Regarding Committees of the Board,” “Proposal No. 1—Election of Directors—Information Regarding our Board of Directors and Corporate Governance—Audit Committee,” and under the heading “Information About Our Executive Officers” in Part 1—Business of this Annual Report on Form 10-K and is incorporated by reference into this Annual Report on Form 10-K by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item is set forth 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” in our Proxy Statement and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item is set forth under the heading “Security Ownership of Certain Beneficial Owners and Management” in our Proxy Statement and is incorporated herein by reference. As of December 31, 2020, we did not have any securities authorized for issuance under equity compensation plans.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item is set forth under the headings “Proposal No. 1—Election of Directors—Information Regarding the Board of Directors and Corporate Governance—Director Independence and Controlled Company Exemption”, “Certain Relationships and Related Party Transactions—Certain

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Transactions” and “Certain Relationships and Related Party Transactions—Policies and Procedures for Related Party Transactions” in our Proxy Statement and are incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item is set forth under the headings “Proposal No. 2—Ratification of the Appointment of Grant Thornton LLP as Independent Auditor—Principal Accountant Fees and Services” and “Proposal No. 2—Ratification of the Appointment of Grant Thornton LLP as Independent Auditor—Pre-Approval Policies and Procedures” in our Proxy Statement and are 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

Exhibit Number	Description
2.1+	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)
2.2	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)
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)
4.1	Description of Securities
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 Nonqualified Stock Option Agreement (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 Restricted Stock Unit Award Agreement (Employees) (incorporated by reference to Exhibit  10.3 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)

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Exhibit Number	Description
10.4^	Form of Restricted Stock Unit Award Agreement (Non-Employee Directors) (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 Agreement (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 Option Cancellation 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 Indemnity Letter between Montauk Renewables, Inc. and each of its current directors and executive officers (incorporated by reference to Exhibit 10.7 to our Registration Statement on Form S-1 (File No. 333-251312), filed (incorporated by reference to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 23, 2021)
10.8^	Form of Indemnification Agreement between Montauk Renewables, Inc. and each of its directors and executive officers (incorporated by reference to Exhibit 10.8 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
10.9^+	Employment Agreement, effective September 25, 2019, between Montauk Energy Holdings LLC and Sean F. McClain
10.10^+	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)
10.11^+	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)
10.12^	Severance Agreement, effective September  30, 2019, between Montauk Energy Holdings LLC and Martin L. Ryan (incorporated by reference to Exhibit 10.12 to our Registration Statement on Form S-1 (File No.  333-251312), filed December 11, 2020)
10.13^+	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)
10.14^	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)
10.15+	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)
10.16	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)

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Exhibit Number	Description
10.17	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)
10.18	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)
10.19†+	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)
10.20†+	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)
10.21+	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)
10.22†+	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)
10.23+	Base Contract for Sale and Purchase of Natural Gas, dated as of August  24, 2018, by and between Trillium Transportation Fuels, LLC and GSF Energy, LLC (incorporated by reference to Exhibit 10.21 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
10.24†	Transaction Confirmation, dated as of August  24, 2018, by and between Trillium Transportation Fuels, LLC and GSF Energy, LLC (incorporated by reference to Exhibit 10.22 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
10.25†	First Amendment to Transaction Confirmation, dated as of June  26, 2019, by and between Trillium Transportation Fuels, LLC and GSF Energy, LLC (incorporated by reference to Exhibit 10.23 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
10.26†+	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)
10.27+	Base Contract for Sale and Purchase of Natural Gas, dated as of May  9, 2016, by and between Iogen D3 Biofuel Partners LLC and GSF Energy, LLC (incorporated by reference to Exhibit 10.25 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)

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Exhibit Number	Description
10.28†+	Transaction Confirmation, dated as of May  9, 2016, by and between Iogen D3 Biofuel Partners LLC and GSF Energy, LLC (incorporated by reference to Exhibit 10.26 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
10.29+	First Amendment to Transaction Confirmation, dated as of May  20, 2016, by and between Iogen D3 Biofuel Partners LLC and GSF Energy, LLC (incorporated by reference to Exhibit 10.27 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
10.30†+	Second Amendment to Transaction Confirmation, dated as of May  22, 2018, by and between Iogen D3 Biofuel Partners LLC and GSF Energy, LLC (incorporated by reference to Exhibit 10.28 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
10.31†+	Third Amendment to Transaction Confirmation, dated as of September  17, 2019, by and between Iogen D3 Biofuel Partners LLC and GSF Energy, LLC (incorporated by reference to Exhibit 10.29 to Amendment No. 3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
10.32+	Base Contract for Sale and Purchase of Natural Gas, dated as of July  23, 2009, by and between Shell Energy North America (US), L.P. and GSF Energy, LLC (incorporated by reference to Exhibit 10.30 to Amendment No. 4 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 15, 2021)
10.33†+	Transaction Confirmation, dated as of May  6, 2016, by and between Shell Energy North America (US), L.P. and GSF Energy, LLC (incorporated by reference to Exhibit 10.31 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
10.34+	Amendment to Transaction Confirmation, dated as of May  24, 2016, by and between Shell Energy North America (US), L.P. and GSF Energy, LLC (incorporated by reference to Exhibit 10.32 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
10.35+	Base Contract for Sale and Purchase of Natural Gas, dated as of October  9, 2019, by and between Bluesource LLC and GSF Energy, LLC (incorporated by reference to Amendment No. 3 to Exhibit  10.33 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
10.36†	Transaction Confirmation, dated as of October  15, 2019, by and between Bluesource LLC and GSF Energy, LLC (incorporated by reference to Exhibit 10.34 to Amendment No.  3 to our Registration Statement on Form S-1 (File No. 333-251312), filed January 8, 2021)
10.37†+	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)
10.38+	Base Contract for Sale and Purchase of Natural Gas, dated as of February  27, 2017, by and between BP Energy Company and BP Products North America Inc. (formerly Clean Energy Renewable Fuels, LLC) and TX LFG Energy, LP (incorporated by reference to Exhibit 10.36 to Amendment No.  2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
10.39†	Transaction Confirmation, dated as of February  27, 2017, by and between BP Energy Company and BP Products North America Inc. (formerly Clean Energy Renewable Fuels, LLC) and TX LFG Energy, LP (incorporated by reference to Exhibit 10.37 to Amendment No.  2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)

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Exhibit Number	Description
10.40†+	First Amendment to Transaction Confirmation, dated as of February  7, 2018, by and between BP Energy Company and BP Products North America Inc. (formerly Clean Energy Renewable Fuels, LLC) and TX LFG Energy, LP (incorporated by reference to Exhibit 10.38 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 31, 2021)
10.41	Amended and Restated Loan Agreement and Promissory Note, by and between Montauk Holdings Limited and Montauk Renewables, Inc., dated February 22, 2021
21.1	List of subsidiaries of Montauk Renewables, Inc. (incorporated by reference to Exhibit 21.1 to our Registration Statement on Form S-1 (File No. 333-251312), filed December 11, 2020)
23.1	Consent of Independent Registered Public Accounting Firm
23.2	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	Administrative Services Agreement, dated as of January 25, 2021, by and between HCI Managerial Services Proprietary Limited and Montauk Renewables, Inc.
99.2+	Consortium Agreement, dated as of January 24, 2021, by and among the stockholders named therein

^ 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.

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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 31, 2021	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.

Signature	Title	Date
/s/ Sean F. McClain Sean F. McClain	President, Chief Executive Officer and Director (Principal Executive Officer)	March 31, 2021
/s/ Kevin A. Van Asdalan Kevin A. Van Asdalan	Chief Financial Officer (Principal Financial and Accounting Officer)	March 31, 2021
* Mohamed H. Ahmed	Lead Director	March 31, 2021
* John A. Copelyn	Chairman of the Board and Director	March 31, 2021
* Theventheran G. Govender	Director	March 31, 2021
*	Director	March 31, 2021
Michael A. Jacobson
* Bruce S. Raynor	Director	March 31, 2021

* 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