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Filed Pursuant to Rule 424(b)(4)
Registration No. 333-251312

3,047,015 Shares

MONTAUK RENEWABLES, INC.

Common Stock

 

 

This is the initial public offering of shares of common stock, par value $0.01 per share (the “common stock”), of Montauk Renewables, Inc. We are offering 2,350,000 shares of our common stock and the selling stockholder identified in this prospectus is offering 697,015 shares of our common stock. We will not receive any proceeds from the sale of our common stock by the selling stockholder.

Prior to this offering, there has been no public market for our common stock. The initial public offering price for our common stock is $8.50 per share. We have been approved to list our common stock on The Nasdaq Capital Market (“Nasdaq”) under the symbol “MNTK.”

Certain stockholders, which are Messrs. John A. Copelyn’s and Theventheran (Kevin) G. Govender’s respective affiliates, informed us that they intend to enter into an agreement (the “Consortium Agreement”) whereby the parties thereto will agree to act in concert with respect to voting our common stock. After the Reorganization Transactions and prior to the completion of the offering, the parties to the Consortium Agreement will beneficially own, in the aggregate, approximately 54.2% of our common stock, and, after giving effect to this offering, will beneficially own approximately 53.2% of our common stock (or 53.1% if the underwriter exercises in full its option to purchase additional shares of our stock). As a result, we will be a “controlled company” within the meaning of the Nasdaq corporate governance standards. See “Management—Controlled Company Exception.”

We are an “emerging growth company” under the federal securities laws and, as such, we have elected to comply with certain reduced public company reporting requirements for this prospectus and may elect to do so in future filings. See “Prospectus Summary—Implications of Being an Emerging Growth Company.”

Investing in our common stock involves risk. See “Risk Factors” beginning on page 17 to read about factors you should consider before buying shares of our common stock.

 

 

Neither the Securities and Exchange Commission (the “SEC”), any state securities commission nor any other regulatory body has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

 

    Per Share     Total  

Initial public offering price

  $ 8.50     $ 25,899,628  

Underwriting discounts and commissions (1)

  $ 0.595     $ 1,398,250  

Proceeds, before expenses, to us

  $ 7.905     $ 18,576,750  

Proceeds, before expenses, to the selling stockholder

  $ 8.50     $ 5,924,628  

 

(1)

See the section titled “Underwriting” for additional information regarding total underwriter compensation.

We have granted the underwriter an option to purchase up to an additional 352,500 shares of common stock at the initial public offering price less the underwriting discounts and commissions, for 30 days after the date of this prospectus.

The underwriter expects to deliver the shares of common stock to purchasers on or about January 26, 2021.

 

 

Roth Capital Partners

 

 

The date of this prospectus is January 21, 2021.


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1  

RISK FACTORS

     17  

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     45  

THE REORGANIZATION TRANSACTIONS

     47  

USE OF PROCEEDS

     50  

DIVIDEND POLICY

     51  

CAPITALIZATION

     52  

DILUTION

     53  

SELECTED CONSOLIDATED FINANCIAL DATA

     55  

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     57  

INDUSTRY OVERVIEW

     81  

BUSINESS

     95  

MANAGEMENT

     120  

EXECUTIVE COMPENSATION

     127  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     137  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     140  

DESCRIPTION OF CAPITAL STOCK

     143  

DESCRIPTION OF INDEBTEDNESS

     149  

SHARES ELIGIBLE FOR FUTURE SALE

     150  

CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS

     152  

UNDERWRITING

     156  

LEGAL MATTERS

     162  

EXPERTS

     162  

WHERE YOU CAN FIND MORE INFORMATION

     162  

GLOSSARY OF KEY TERMS

     162  

CONSOLIDATED FINANCIAL STATEMENTS

     F-1  

Information in this Prospectus

You should rely only on the information contained in this prospectus or in any related free writing prospectus we may specifically authorize to be delivered or made available to you. Neither we, the selling stockholder nor the underwriter (or any of our or their respective affiliates) have authorized anyone to provide you with information different from, or in addition to, the information contained in this prospectus or any related free writing prospectus. Neither we, the selling stockholder nor the underwriter (or any of our or their respective affiliates) take any responsibility for, and neither we, the selling stockholder nor the underwriter (or any of our or their respective affiliates) provide any assurance as to the reliability of, any other information that others may give you. Neither we, the selling stockholder nor the underwriter (or any of our or their respective affiliates) are making an offer to sell these securities in any jurisdiction where the offer or sale is not permitted. The information contained in this prospectus or in any applicable free writing prospectus is current only as of its date, regardless of its time of delivery or any sale of shares of our common stock. Our business, financial condition, results of operations, and prospects may have changed since that date.

 

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For Investors Outside the United States

The underwriter is offering to sell, and seeking offers to buy, shares of our common stock only in jurisdictions where offers and sales are permitted. Neither we, the selling stockholder nor the underwriter have done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction where action for that purpose is required, other than in the United States. Persons outside the United States who come into possession of this prospectus must inform themselves about, and observe any restrictions relating to, the offering of the shares of our common stock and the distribution of this prospectus outside the United States.

Industry, Market, and Other Data

This prospectus 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 prospectus, this information could prove to be inaccurate.

Basis of Presentation

In this prospectus, we present historical consolidated financial statements of Montauk USA (as defined below). During the year ended December 31, 2019, MNK (as defined below) and its subsidiaries (including Montauk USA) changed their financial year-end date from March 31 to December 31. As a result, MNK’s and its subsidiaries’ prior reporting period consisted of the twelve months ended March 31, 2019 and MNK’s and its subsidiaries’ most recent reporting period consisted of the nine months ended December 31, 2019. In connection with the preparation of the registration statement of which this prospectus forms a part, Montauk USA recast its historical financial statements for 2018 and 2019 to present its financial results on the basis of a fiscal year ended December 31. We also present a consolidated balance sheet as of November 15, 2020 for Montauk Renewables, Inc. Unless otherwise noted, any reference to a year not preceded by “fiscal” refers to a twelve-month calendar year ended December 31.

The functional currency for MNK is the South African Rand (“ZAR”) and certain information contained in the “Executive Compensation” section of this prospectus, including the exercise prices of executive officers’ outstanding stock option awards issued by MNK, is denominated in ZAR. The figures denominated in ZAR have been converted to U.S. Dollars (“USD”) based on the exchange rate on the relevant day noted in each case.

Non-GAAP Financial Measures

We refer to the terms “EBITDA” and “Adjusted EBITDA” in various places in this prospectus. These terms, as used in this prospectus, may be calculated differently from EBITDA as defined for purposes of any indebtedness we incur, including under our Amended Credit Agreement (as defined below). These measures are supplemental financial measures not prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). These financial measures are not intended to serve as an alternative to GAAP measures of performance and may not be comparable to similarly titled measures presented by other companies.

We present these non-GAAP measures because we believe these 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.

Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Non-GAAP Financial Measures” for reconciliations of the non-GAAP measures we present to the most closely comparable financial measures calculated in accordance with GAAP.

 

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PROSPECTUS SUMMARY

The following summary highlights selected information contained elsewhere in this prospectus and does not contain all of the information that you should consider in making your investment decision. Before investing in our common stock, you should carefully read the entire prospectus, including the consolidated financial statements and the related notes included in this prospectus and the information set forth under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Unless the context requires otherwise, the words “Montauk,” the “Company,” “we,” “us” and “our” refer to Montauk Renewables, Inc. and its consolidated subsidiaries from and following the Reorganization Transactions. For a glossary of key industry terms used herein, see “Glossary of Key Terms.”

Our Company

Overview

Montauk Renewables, Inc., a Delaware corporation (“Montauk”), is a renewable energy company specializing in the recovery and processing of environmentally detrimental methane (“biogas”) from landfills and other non-fossil fuel sources for beneficial use as a replacement to fossil fuels. We develop, own, and operate renewable natural gas (“RNG”) projects, using proven technologies that supply RNG into the transportation industry and use RNG to produce electrical power for the electrical grid (“Renewable Electricity”). Having participated in the industry for over 30 years, we are one of the largest U.S. producers of RNG. 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 $34.0 million in 2014 to $107.4 million in 2019.

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 landfill gas (“LFG”) and anaerobic digester gas (“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 (as defined below), which we are able to monetize under federal and state initiatives.

Based on our analysis, 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.

Reorganization Transactions

Montauk Holdings Limited, a corporation formed under the laws of the Republic of South Africa (“MNK”), is a holding company whose ordinary shares are currently traded on the Johannesburg Stock Exchange



 

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(“JSE”) under the symbol “MNK.” Prior to this offering, 100% of MNK’s business and operations were conducted through its U.S. subsidiaries, and it held no assets other than the equity of its subsidiaries. Prior to January 4, 2021, Montauk Holdings USA, LLC was a direct wholly owned subsidiary of MNK (“Montauk USA”), and Montauk Energy Holdings LLC was a direct wholly owned subsidiary of Montauk USA until such date (“MEH”). 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. 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 Reorganization Transactions and this offering, the existing shareholders of MNK will become stockholders of Montauk. After the Reorganization Transactions and the closing of this offering, MNK will not own any significant assets and we expect that MNK will be delisted from the JSE and liquidated. Accordingly, MNK’s business is the business in which you are investing if you buy shares of our common stock in this offering. For more information, see “The Reorganization Transactions.”

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 U.S. public and federal, state and local regulatory authorities on reducing the emission of greenhouse gases (“GHG”), such as methane, and increasing the energy independence of the United States. According to the Environmental Protection Agency (“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 the Energy Independence and Security Act of 2007 (“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.”

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 waste water resource recovery facilities (“WRRFs”).



 

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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 EPA Landfill Methane Outreach Program (“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 the 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 presents, 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 with power purchase agreements (“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 returns 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 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. 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 biogas processing and our market leadership in RNG, we believe 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 waste water, 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 U.S. federal, state and local government incentives (collectively, “Environmental Attributes”). These Environmental Attributes are provided for under a variety of programs, including the national Renewable Fuel Standards (“RFS”) and state-level Renewable Portfolio Standards (“RPS”) and Low Carbon Fuel Standard (“LCFS”).



 

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The RFS program requires transportation fuel to contain a minimum volume of renewable fuel. To fulfill this regulatory mandate, the EPA obligates refiners and importers (“Obligated Parties”) to blend renewable fuel with standard fuel to meet renewable volume obligations (“RVOs”). Obligated Parties can comply with RVOs by either blending RNG into their existing fuel supply or purchasing Renewable Identification Numbers (“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 2019, our projects generated approximately 15% 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. California’s LCFS (“CA LCFS”) program requires fuel producers and importers to reduce the carbon intensity (“CI”) of their products, with goals of a 10% reduction in carbon emissions from 1990 levels by 2020 and a 20% reduction by 2030. The California Air Resources Board (“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 Renewable Energy Credits (“RECs”), which provide an additional revenue stream to RNG projects that produce electricity from biogas.

The development of these governmental programs provide us with valuable Environmental Attribute revenue streams that we intend to continue to pursue and take advantage of as biogas continues to be fostered as a renewable source of energy in the United States.

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 application, including membranes, media, and solvent-based gas cleanup technologies. We are actively engaged in the management of each project site and regularly serve 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.



 

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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 requests for proposals (“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 projects.

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 afford 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 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 environmental health and safety (“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 providing further assurances to our host landfills. As of October 25, 2020, excluding two incidents related to COVID-19, our year-to-date Total Recordable Incident Rate (“TRIR”) was 1.11, 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 September 2020, we have not received any U.S. Occupational Health and Safety Administration (“OSHA”) or state OSHA citations in the last five years.



 

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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 Renewable Natural Gas Coalition (“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.

Expanding Our Existing Project Portfolio and Developing New Project 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 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.

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. Additionally, we are evaluating opportunities to utilize excess gas for RNG production at some of our electricity projects.

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



 

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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 given the favorable economics for RNG plus RIN sales relative to merchant electricity rates plus REC sales. To date, we have converted two projects from LFG-to-electricity to LFG-to-RNG and one project from ADG-to-electricity to ADG-to-RNG, and we are currently evaluating a fourth conversion opportunity for LFG-to-RNG.

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 operational costs, optimize efficiencies and improve operations. Our full suite of capabilities allows us to serve as 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. 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.

Our Projects

The map below shows the locations of our 15 operating projects. As of October 2020, approximately 73% of our expected 2020 RNG production has been monetized under fuel supply agreements with a remaining



 

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term of more than 15 years. Additionally, as of October 2020, approximately 89% of our expected 2020 Renewable Electricity production has been monetized under fuel supply agreements with a remaining term of more than 15 years.

 

LOGO

 

 

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

 

    
 

 

 

   LOGO

  

 

=  Renewable Natural Gas Project

 

   LOGO

 

  

 

=  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 14 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.

In the last five years, we have developed six new projects, consisting of three greenfield LFG projects, two LFG projects that converted existing LFG-to-electricity projects to LFG-to-RNG projects, and one project that converted an existing ADG-to-electricity project to an ADG-to-RNG project. 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.

Eleven of our current RNG operating projects generate RNG from LFG, and our newest project generates RNG from ADG (livestock waste). Our RNG projects collectively have approximately 33,850 MMBtu/day of design capacity, which equates to emissions reductions of 624,000 tons of carbon dioxide, 252,822 tons



 

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of methane, and 6.30 million metric tons of carbon dioxide equivalents annually over using fossil fuels, or the equivalent of the carbon dioxide, methane, and carbon dioxide equivalents emissions from consuming approximately 1,940,000 gallons of gasoline per day. In 2020, our RNG landfill sites had daily MMBtu/day generation design capacity ranging from approximately 7,271 MMBtu/day to 928 MMBtu/day.

Our LFG projects typically include vertical wells or horizontal trenches at landfills, conveyance pipe, pretreatment, processing and compression. ADG projects consist of an enclosed anaerobic digester as the source of biogas, with downstream pretreatment, processing and compression. 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.

Our Renewable Electricity projects utilize reciprocating engine generator sets to generate electricity at landfills. Our Renewable Electricity projects collectively have a design capacity of 30.2 MW, which equates to emissions reductions of 175,600 tons of carbon dioxide, 60,160 tons of methane, and 1.52 million metric tons of carbon dioxide equivalents annually over using fossil fuels, or the equivalent of the carbon dioxide, methane, and carbon dioxide equivalents emissions from consuming approximately 469,000 gallons of gasoline per day. During 2019, our Renewable Electricity projects collectively produced approximately 236,000 MWh.

How We Generate Revenue

We generate revenue from the sale of RNG and Renewable Electricity under short-, medium-, and long-term contracts that include the Environmental Attributes associated with these products. While RNG has the same chemical composition as natural gas from fossil sources, it has unique Environmental Attributes assigned to it due to its origin from low-carbon, renewable sources.

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, which are 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.

Our customers for RNG and RINs include large, long-term owner-operators of landfills and livestock farms, local utilities, and large refiners in the natural gas and refining sectors, such as Royal Dutch Shell plc and Exxon Mobil, and commercial RIN off-take parties. 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 that purchase electricity pursuant to fixed-price agreements.

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 may 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 Attributes under medium-and long-term indexed pricing and margin sharing arrangements designed to give us optimal price and revenue certainty. On the



 

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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 generally in the form of royalties based on realized revenues, or, in some select cases, based on production volumes.

Selected 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” immediately following this prospectus summary. 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 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.

 

   

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.

 

   

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.



 

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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 have identified a material weakness in our internal control over financial reporting. If we are unable to remediate this material weakness, or 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.

 

   

No public market for our common stock currently exists in the United States, and an active public trading market may not develop or be sustained following this offering.

 

   

Our shares of common stock may 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.

Implications of Being a Controlled Company

After the Reorganization Transactions and prior to the completion of the offering, certain parties to the current consortium agreement will beneficially own, in the aggregate, approximately 54.2% of our common stock and, after completion of this offering, they will beneficially own, in the aggregate, approximately 53.2% of our common stock (or 53.1% if the underwriter exercises in full its option to purchase additional shares of our common stock). Certain stockholders, which are Messrs. Copelyn’s and Govender’s respective affiliates, 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 will be 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 is beneficially owned by an individual, group, or other company is a “controlled company” and may elect not to comply with certain corporate governance standards, including the requirements that (1) a majority of its board of directors consist of independent directors, (2) its board of directors have a compensation committee that is composed entirely of independent directors, and (3) its director nominees be selected, or recommended to the board of directors, by a majority of independent directors or by a nominations committee that consists entirely of independent directors and that has adopted a written charter or board resolution addressing the nominations process. Accordingly, our stockholders will not have the same protections afforded to stockholders of companies that are subject to these corporate governance requirements. In the event that we cease to be a “controlled company” and our common stock continues to be listed on Nasdaq, we will be required to comply with these provisions within the applicable transition periods.



 

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Implications of Being an Emerging Growth Company

As a company with less than $1.07 billion in revenue during our last completed fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). An emerging growth company may take advantage of certain reduced reporting requirements that are otherwise applicable generally to public companies. These reduced reporting requirements include:

 

   

an exemption from compliance with the auditor attestation requirement on the effectiveness of our internal control over financial reporting;

 

   

an exemption from compliance with any requirement that the Public Company Accounting Oversight Board (“PCAOB”) may adopt regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements;

 

   

reduced disclosure about our executive compensation arrangements;

 

   

an exemption from the requirements to obtain a non-binding advisory vote on executive compensation or any golden parachute arrangements;

 

   

extended transition periods for complying with new or revised accounting standards; and

 

   

the ability to present more limited financial data, including presenting only two years of selected financial data in this registration statement of which this prospectus is a part.

We will remain an emerging growth company until the earliest to occur of: (i) the end of the first fiscal year in which our annual gross revenue is $1.07 billion or more; (ii) the end of the fiscal year in which the market value of our common stock that is held by non-affiliates is at least $700.0 million as of the last business day of our most recently completed second fiscal quarter; (iii) the date on which we have, during the previous three-year period, issued more than $1.0 billion in non-convertible debt; and (iv) the end of the fiscal year during which the fifth anniversary of this offering occurs. We may choose to take advantage of some, but not all, of the available benefits under the JOBS Act.

We currently intend to take advantage of all of the exemptions discussed above, including the extended transaction periods for complying with new or revised accounting standards. Accordingly, the information contained herein may be different than the information you receive from other public companies in which you invest.

See “Risk Factors—Emerging Growth Company Risks” for certain risks related to our status as an emerging growth company.

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. Our website address is www.montaukenergy.com. Information contained in, or connected to, our website does not and will not constitute part of this prospectus or the registration statement of which this prospectus is a part.



 

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The Offering

 

Issuer

Montauk Renewables, Inc.

 

Common stock offered by us

2,350,000 shares of common stock (or 2,702,500 shares of common stock if the underwriter exercises its option to purchase additional shares in full).

 

Common stock offered by the selling stockholder

697,015 shares of common stock.

 

Common stock to be outstanding after this offering

140,662,713 shares of common stock (or 141,015,213 shares of common stock if the underwriter exercises its option to purchase additional shares in full).

 

Option to purchase additional shares of common stock

The underwriter has an option to purchase an additional 352,500 shares of common stock from us. The underwriter can exercise this option at any time within 30 days from the date of this prospectus.

 

Use of proceeds

We estimate that the net proceeds from the sale of our common stock in this offering, after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, will be approximately $12.2 million ($15.0 million if the underwriter exercises its option to purchase additional shares in full) based on the initial public offering price of $8.50 per share.

 

  We intend to use the net proceeds that we receive in this offering to fund the identification of, and diligence activities with respect to, potential new projects, which include evaluating new project sites, project conversions and strategic acquisitions. The timing of our use of the net proceeds received in this offering may vary significantly depending on numerous factors. While we have no current agreements, commitments or understandings for any specific use of the net proceeds at this time, we continue to actively consider potential opportunities.

We will not receive any proceeds from the sale of shares of our common stock by the selling stockholder.

See “Use of Proceeds” for a complete description of the intended use of proceeds from this offering.

 

Underwriter warrants

Upon the closing of this offering, we will issue to the underwriter, warrants (the “underwriter warrants”) entitling it to purchase a number of shares of common stock equal to 5% of the shares of common stock sold in this offering by us at an exercise price equal to 110% of the public offering price of the common stock in this offering. The underwriter warrants will expire five (5) years after the



 

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effective date of the registration statement of which this prospectus forms a part. See “Underwriting.”

 

Reorganization Transactions

Montauk has completed the Equity Exchange (as defined below) and will complete the Distribution (as defined below) prior to the completion of this offering. See “The Reorganization Transactions.”

 

Dividend policy

We declared dividends of $7.6 million and $4.1 million in May 2018 and October 2018, respectively. We did not declare any cash dividends in 2019 or 2020. 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 may deem relevant. See “Dividend Policy.”

 

Risk factors

Investing in our common stock involves a high degree of risk. See the “Risk Factors” section of this prospectus for a discussion of factors you should carefully consider before investing in our common stock.

 

Listing

We intend to apply to have our common stock listed on Nasdaq under the symbol “MNTK.”

Except as otherwise indicated, the number of shares of our common stock outstanding after this offering:

 

   

gives effect to the Distribution of 138,312,713 shares of our common stock as a pro rata dividend to holders of MNK’s ordinary shares in connection with the Reorganization Transactions;

 

   

assumes no exercise of the underwriter’s option to purchase additional shares and no exercise of the underwriter warrants;

 

   

gives effect to the initial public offering price of $8.50 per share;

 

   

excludes an aggregate of 20,000,000 shares of our common stock that will be available for future equity awards under the Equity Plan (as defined below); and

 

   

gives effect to our Amended and Restated Certificate of Incorporation and our Amended and Restated Bylaws.



 

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Summary Consolidated Financial Data

The following tables set forth a summary of the historical consolidated financial data of Montauk USA for the years ended December 31, 2019 and 2018 and the nine months ended September 30, 2020 and 2019. The consolidated financial statements of Montauk USA, our predecessor for accounting purposes, will be our historical financial statements following this offering. The historical summary consolidated financial data set forth in the following tables for the years ended December 31, 2019 and 2018 and the nine months ended September 30, 2020 and 2019 has been derived from Montauk USA’s consolidated financial statements included elsewhere in this prospectus. You should read this data together with Montauk USA’s financial statements and the related notes appearing elsewhere in this prospectus and the information included under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Montauk USA’s historical results are not necessarily indicative of our future results.

Statement of Operations Data:

 

    Year ended December 31,     Nine months ended
September 30,
 
    2019     2018     2020     2019  
    (in thousands, except per share data)  

Total revenues

  $ 107,383     $ 116,433     $ 75,559     $ 83,703  

Operating expenses

       

Operating and maintenance expenses

    39,783       29,073       30,884       30,306  

General and administrative expenses

    13,632       11,953       11,336       10,593  

Royalties, transportation, gathering and production fuel expenses

    20,558       22,359       14,769       16,197  

Depreciation and amortization

    19,760       16,195       16,120       14,754  

Impairment loss

    2,443       854       278       1,550  

Gains on insurance proceeds

    —         —         (3,444     —    

Transaction costs

    202       176       —         202  
 

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

  $ 96,378     $ 80,610     $ 69,943     $ 73,602  
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating profit

  $ 11,005     $ 35,823     $ 5,616     $ 10,101  
 

 

 

   

 

 

   

 

 

   

 

 

 

Other expenses (income):

       

Interest expense

  $ 5,576     $ 3,083     $ 3,510     $ 5,293  

Equity loss (gain) of nonconsolidated investments

    (94     224       —         (94

Net loss (gain) on sale of assets

    10       (266     —         10  

Other expense (income)

    47       (3,781     250       (17
 

 

 

   

 

 

   

 

 

   

 

 

 

Total other expenses (income)

  $ 5,539     $ (740   $ 3,760     $ 5,192  

Income tax expense (benefit)

    (354     7,796       (291     (539
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 5,820     $ 28,767     $ 2,147     $ 5,448  
 

 

 

   

 

 

   

 

 

   

 

 

 

Pro forma earnings per share (unaudited):

       

Basic

  $ 0.04       $ 0.02    

Diluted

  $ 0.04       $ 0.02    

Balance Sheet Data:

 

    As of December 31,     As of September 30,  
    2019     2018     2020     2019  
    (in thousands)  

Cash and cash equivalents

  $     9,788     $   54,032     $ 19,537     $   3,003  

Working capital (deficit)

    (154     34,790       6,537       (8,661


 

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    As of December 31,     As of September 30,  
    2019     2018     2020     2019  
    (in thousands)  

Property, plant and equipment—net

    193,498       168,418       189,957       187,868  

Total assets

    243,613       261,732       251,527       230,809  

Long-term debt

    57,256       74,649       58,656       43,577  

Member’s equity

    154,257       147,941       156,867       154,050  

Other Financial and Operating Data:

 

    Year ended on December 31,     Nine months ended
September 30,
 
    2019     2018     2020     2019  
    (in thousands, unless otherwise indicated)  

Renewable Natural Gas total revenues

  $ 85,826     $ 98,584     $ 62,192     $ 67,322  

Renewable Electricity Generation total revenues

  $ 19,859     $ 18,207     $ 13,282     $ 14,927  

CY RNG production volumes (MMBtu)

    5,361       4,485       4,451       4,040  

Total RINs Available for Sale

    37,866       21,841       30,767       29,851  

Adjusted EBITDA (1)

  $ 33,615     $ 56,921     $ 21,376     $ 27,038  

 

  (1)

EBITDA Reconciliation:

The following table is a reconciliation of Montauk USA’s net income from continuing operations to Adjusted EBITDA for the years ended December 31, 2019 and 2018 and the nine months ended September 30, 2020 and 2019:

 

    Year ended December 31,     Nine months ended
September 30,
 
    2019     2018     2020     2019  
    (in thousands)  

Net income

  $ 5,820     $ 28,767     $ 2,147     $ 5,448  

Depreciation and amortization

    19,760       16,195       16,120       14,754  

Interest expense

    5,576       3,083       3,510       5,293  

Income tax expense (benefit)

    (354     7,796       (291     (539
 

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

    30,802       55,841       21,486       24,956  
 

 

 

   

 

 

   

 

 

   

 

 

 

Impairment loss (1)

    2,443       854       278       1,550  

Transaction costs

    202       176       —         202  

Equity loss (gain) of nonconsolidated investments

    (94     224       —         (94

Net loss (gain) on sale of assets

    10       (266     —         10  

Non-cash hedging charges

    252       92       (388     414  
 

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 33,615     $ 56,921     $ 21,376     $ 27,038  
 

 

 

   

 

 

   

 

 

   

 

 

 

 

  (1)

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 an asset distribution from Red Top Renewable AG, LLC (“Red Top”) for the year ended December 31, 2018. For the nine months ended September 30, 2020, we recorded an impairment loss of $0.3 million related to the termination of a development agreement related to our Pico acquisition. We recorded an impairment loss of $1.6 million for the nine months ended September 30, 2019 related to the cancellation of a site conversion agreement and conversion of existing Renewable Electricity to RNG sites as well as the write-off of Red Top assets.



 

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RISK FACTORS

Investing in our common stock is speculative and involves a high degree of risk. You should carefully consider the following risk factors, as well as the other information in this prospectus, including the consolidated financial statements and the related notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” before deciding to invest in our common stock. If any of the events described in the following risk factors actually occur, or if additional risks and uncertainties that are not presently known to us or that we currently deem immaterial later materialize, then our business, financial condition and results of operations could be adversely affected, the trading price of our common stock could decline, and you could lose all or part of your investment.

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 into 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. We have 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. 56% and 53% of our revenues for 2019 and 2018, 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, the current U.S. presidential administration may continue to create regulatory uncertainty in the renewable energy sector generally. Members of the current U.S. presidential administration, including representatives of the U.S. Department of Energy, have made public statements that indicate that the administration may not be supportive of various clean energy programs and initiatives designed to curtail climate change. For example, the United States announced its withdrawal from the 2015 Paris Agreement on climate change mitigation that will be effective on November 4, 2020. 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. The ACE rule is currently subject to legal challenges and may be subject to future challenges. The ultimate resolution of such legal challenges, and the ultimate impact of the ACE rule, is uncertain. As a result of the new ACE rule and other policies or actions of the current U.S. administration or the U.S. Congress, we may be subject to significant additional risks, including the following:

 

   

a reduction or removal of clean energy programs and initiatives and the incentives they provide could diminish the market for renewable energy, slow the retirement of aging fossil fuel plants, including the retirements of coal generation plants, and reduce the ability for renewable energy project developers to compete for future projects, which may reduce incentives for such parties to develop renewable energy projects; and

 

   

any effort to overturn federal and state laws, regulations, or policies that are supportive of renewable energy generation or that remove costs or other limitations on other types of electricity generation that compete with renewable energy projects could adversely affect our ability to compete with traditional forms of electricity generation and adversely affect our business, financial condition and results of operations.

The outcome of the 2020 election could lead to significant legislative and regulatory reforms affecting the regulation of our projects. If the current U.S. presidential administration or the U.S. Congress were to take action to eliminate or reduce legislation, regulations and incentives supporting renewable energy, such actions could decrease demand for renewable energy in the United States, which could adversely affect our business, financial condition and results of operations.

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

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

 

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

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

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

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

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

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

The market for renewable energy is influenced by U.S. federal, state and local government regulations and policies concerning renewable energy. These regulations and policies are continuously being modified, which could result in a significant future reduction in the potential demand for renewable energy, including RINs, RECs and LCFS credits, renewable energy project development and investments. Any new government regulations applicable to our renewable energy projects or markets for renewable energy may result in significant

 

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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 current U.S. presidential administration has created price volatility and illiquidity in the RIN market and the inability to sell RINs on a forward basis beyond the current calendar year. 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.

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

We are required to register an RNG project with the EPA and relevant state regulatory agencies. Further, we qualify our RINs through a voluntary Quality Assurance Plan, which typically takes from three to five months from first injection of RNG into the commercial pipeline system. Although no similar qualification process currently exists for LCFS credits, we expect such a process to be implemented and would expect to seek qualification on a state by state basis under such future programs. 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.

 

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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, 2019 and 2018, excluding the effect of derivative instruments, approximately 80.4% and 77.2%, respectively, of operating revenues were derived from these locations. During 2019, RNG production at our McCarty, Rumpke, Atascocita and Apex facilities accounted for approximately 22.6%, 29.8%, 20.3%, and 8.2% of our RNG revenues, respectively, and 29.5%, 22.6%, 20.2% and 10.4% of the RNG we produced during 2019, respectively. During 2019, Renewable Electricity production at our Bowerman Power LFG, LLC (“Bowerman”) facility accounted for approximately 88.6% of our Renewable Electricity Generation revenues and 82.0% of the Renewable Electricity we produced during 2019. 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.

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.

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, our Bowerman facility is located in California near major earthquake faults and fire zones. Recent California wild fires, which occurred in October of 2020, have forced our Bowerman facility to temporarily shut down and caused limited damage to our facility and equipment. We expect our production to be reduced by approximately 50% at the Bowerman facility during the fourth quarter of 2020 and we anticipate resuming full operations in January 2021. We expect that our Bowerman revenues will be reduced by approximately 25% in the fourth quarter of 2020 and by less than 10% through the first half of 2021.

 

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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. 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.

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

 

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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 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

 

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which increase over time. Fluctuations in the price of LCFS credits or the number of LCFS credits assigned will have a significantly greater impact on the success of our dairy farm project than the value that RINs have on our landfill facilities. A significant decline in the value of LCFS credits could require us to incur an impairment charge on our dairy farm project and could adversely affect our business, financial condition and results of operations.

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

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

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

We expect future acquisitions of companies, purchases of assets and other strategic relationships to be an important part of our growth strategy. We plan to use acquisitions to expand our capabilities, expand our geographic markets, add experienced management and add to our project portfolio. However, we may not be able to identify suitable acquisition or investment candidates, reach agreements with acquisition targets on acceptable terms or arrange for any required financing for an acquisition on acceptable terms, any of which would materially impact our present strategy. 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;

 

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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.

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. 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

 

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

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

We currently operate or are developing 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 30.7% and 23.7%, respectively, of our revenues for 2019. 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 2019, sales to Royal Dutch Shell plc, ACT Fuels, Inc., and the City of Anaheim each represented approximately 14% of our operating revenues and sales to Victory Renewables, LLC and BP Products North America each represented approximately 11% of our operating revenues, respectively. In addition, five customers made up approximately 67% and 72% of our accounts receivable as of December 31, 2019 and December 31, 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

 

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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.

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

 

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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.

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.

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

 

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corrective actions at our properties, to comply with the requirements of these environmental laws and regulations or the terms or conditions of our permits. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required environmental regulatory permits or approvals, which may delay or interrupt our operations and limit our growth and revenue.

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

New laws, changes to existing laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make significant additional expenditures. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls at our plants. Present and future environmental laws and regulations, and interpretations of those laws and regulations, applicable to our operations, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial expenditures that could have a material adverse effect on our results of operations and financial condition.

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.

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

 

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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 under “Description of Indebtedness,” imposes 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 (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

 

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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 prospectus.

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 September 30, 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 and certain of our project loans are indexed to the London Interbank Offered Rate (“LIBOR”) to calculate the loan interest rate. In 2017, the United Kingdom’s Financial Conduct Authority (“FCA”), a regulator of financial services firms and financial markets in the United Kingdom, stated that it will plan for a phase out of regulatory oversight of LIBOR interest rate indices. The FCA has indicated that they will support the LIBOR indices through 2021 to allow for an orderly transition to alternative reference rates. However, this announcement indicated that the continuation of LIBOR on the current basis cannot and will not be guaranteed after 2021. Consequently, at this time, it is not possible to predict whether and to what extent banks will continue to provide submissions for the calculation of LIBOR. Similarly, it is not possible to predict whether LIBOR will continue to be viewed as an acceptable market benchmark, 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.

Regulators, industry groups and certain committees (e.g., the ARRC) have published recommended fallback language for LIBOR-linked financial instruments, identified recommended alternatives for certain LIBOR rates (e.g., the SOFR as the recommended alternative to USD LIBOR), and proposed implementations of the recommended alternatives in floating rate instruments. However, at this time, it is not possible to predict whether these recommendations and proposals will be broadly accepted, whether they will continue to evolve and what the effect of their implementation may be on the markets for floating-rate financial instruments. The language in our LIBOR-based contracts and financial instruments has developed over time and may have various

 

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events that trigger when a successor rate to the designated rate would be selected. If a trigger is satisfied, contracts and financial instruments may give the calculation agent discretion over the substitute index or indices for the calculation of interest rates to be selected. The implementation of a substitute index or indices for the calculation of interest rates under the Amended Credit Agreement and 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 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 2018, we recorded impairment charges of $0.9 million related to two Renewable Electricity facilities. 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, 2019, we had U.S. federal net operating loss (“NOL”) carryforwards of approximately $60.4 million, of which $42.9 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 $17.5 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.

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, this offering 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.

 

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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.

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.

 

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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 we 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 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

 

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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.

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 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

 

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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 have identified a material weakness in our internal control over financial reporting. If we are unable to remediate this material weakness, or 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 this offering, 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 deficiency could result in a misstatement of our accounts or disclosures that would result 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 constitute material weaknesses.

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 nine months ended September 30, 2020 and 2019, which were recorded prior to their issuance.

Prior to the completion of this offering, 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. We are in the process of implementing measures designed to improve our internal control over financial reporting and remediate the control deficiencies that led to the material weaknesses, including increasing review of our tax calculations 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 processes around preparation of the tax provision.

As a public company, we will be 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 may need to undertake various actions, such as implementing additional internal controls and procedures and hiring additional accounting or internal audit staff. 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

 

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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;

 

   

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

 

   

natural disasters 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; 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.

No public market for our common stock currently exists in the United States, and an active public trading market may not develop or be sustained following this offering.

No public market for our common stock currently exists in the United States. An active public trading market for our common stock may not develop following the completion of this offering or, if developed, may not be sustained. The lack of an active market may impair your ability to sell your shares at the time you wish to sell them or at a price that you consider reasonable. The lack of an active market may also reduce the fair value of your shares. An inactive market may also impair our ability to raise capital to continue to fund operations by selling shares and may impair our ability to acquire other companies by using our shares as consideration.

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

We expect that our common stock will have a secondary listing on the JSE. Trading in our common stock will take place in USD on Nasdaq and ZAR on the JSE, and at different times, resulting from different time

 

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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 the JSE could cause a corresponding decrease in the trading price of the common stock on Nasdaq.

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 following the completion of this offering, 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 this offering, 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 the date of this prospectus, subject to certain exceptions. 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 this offering 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.

In addition, there were 2,580,647 shares of MNK common stock issuable upon the exercise of outstanding stock options as of December 31, 2020 which will be cancelled in connection with the Reorganization Transactions. We intend to register shares under the Securities Act issuable pursuant to the terms of an equity incentive plan for awards to be granted in the future.

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 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.

After the Reorganization Transactions and prior to the completion of the offering, the parties to the Consortium Agreement will beneficially own, in the aggregate, approximately 54.2% of our common stock and, after completion of this offering, they will beneficially own, in the aggregate, approximately 53.2% of our common stock (or 53.1% if the underwriter exercises in full its option to purchase additional shares of our common stock). 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

 

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election of directors, among other matters. See “Certain Relationships and Related Person Transactions—Consortium Agreement” for a complete description of the Consortium Agreement. As a result, we will continue to be 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 will 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.

You will incur immediate and substantial dilution in your investment because our earlier investors paid less than the initial public offering price when they purchased their shares.

If you purchase shares in this offering, you will incur immediate dilution of $7.40 in net tangible book value per share (or $7.38 if the underwriter exercises its option to purchase additional shares in full), based on the initial public offering price of $8.50 per share because the price that you pay will be greater than the net tangible book value per share of the shares acquired. This dilution arises because our earlier investors paid less than the initial public offering price when they purchased their shares of our common stock. See “Dilution.”

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.

In connection with this offering, we adopted an Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws, which 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. See “Description of Capital Stock—Anti-takeover Effects of Certain Provisions of Our Amended and Restated Certificate of Incorporation, Amended and Restated Bylaws and Delaware Law” for more information.

 

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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 will have broad discretion in the use of the net proceeds to us from this offering and may not use them effectively.

We will have broad discretion in the application of the net proceeds that we receive from this offering, including for any of the purposes described in the section titled “Use of Proceeds,” and you will not have the opportunity as part of your investment decision to assess whether the net proceeds are being used appropriately. Because of the number and variability of factors that will determine our use of the net proceeds that we receive from this offering, our ultimate use may vary substantially from our currently intended use. Investors will need to rely upon the judgment of our management with respect to the use of such proceeds. Pending use, we may invest the net proceeds that we receive from this offering in short-term, investment-grade, interest-bearing securities, such as money market accounts, certificates of deposit, commercial paper, and guaranteed obligations of the U.S. government that may not generate a high yield for our stockholders. If we do not use the net proceeds that we receive in this offering effectively, our business, financial condition and results of operations could be harmed, and the market price of our common stock could 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. See “Dividend Policy.”

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains “forward-looking statements” that involve substantial risks and uncertainties. All statements other than statements of historical or current fact included in this prospectus 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 regulation 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 the 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 prospectus 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 this prospectus and hereafter in our other 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 prospectus 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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THE REORGANIZATION TRANSACTIONS

Prior Organizational Structure

MNK is a holding company that is the ultimate parent of various subsidiaries through which its business is operated. Until January 4, 2021, its subsidiaries included Montauk USA as shown below.

 

 

LOGO

The Reorganization Transactions

MNK is a holding company whose ordinary shares are currently traded on the JSE under the symbol “MNK.” MNK’s sole asset consists of our business. Our operations, however, have always been and remain based in the United States. We are pursuing the Reorganization Transactions and this offering to raise the profile of our operations in the United States by obtaining a primary listing on a stock exchange in the country where our core operations are located. In particular, the market for RNG generated from landfill methane, which generation comprises our primary business, is not currently well-developed in South Africa for various reasons, most notably quality constraints in respect of existing landfill sites. The lack of public and market awareness in South Africa regarding this sector diminishes MNK’s ability to raise capital in South Africa. We believe that access to a liquid and informed U.S. equity market will be of great benefit to our operations as a potential future source of funding for growth, including through acquisitions, new developments, and redevelopments of existing sites.

Montauk, the issuer of the common stock offered hereby, is a newly formed holding company that is participating in a series of Reorganization Transactions with MNK and its subsidiaries. Montauk had no significant operations or assets prior to January 4, 2021 when it engaged in the Equity Exchange with Montauk USA described below.

Montauk USA owned 100% of the shares of MEH. Prior to this offering and the Reorganization Transactions, MNK’s business and operations were conducted entirely through MEH and its U.S. subsidiaries, and MNK held no assets other than equity of its subsidiaries.

On January 4, 2021, MNK and its subsidiaries were reorganized through a series of transactions that resulted in Montauk owning all of the assets and entities through which MNK’s business and operations are conducted. The key steps involved in this reorganization included or will include:

 

   

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

 

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On January 4, 2021, Montauk USA distributed all of the shares of Montauk common stock to Montauk USA’s sole equity holder, MNK, and elected to be disregarded for U.S. tax purposes (collectively, with the Transfer, the “Equity Exchange”). Montauk is now a direct wholly owned subsidiary of MNK and Montauk USA ceased to own any assets.

 

   

MNK will distribute all of the outstanding shares of Montauk common stock as a pro rata dividend to holders of MNK’s ordinary shares (the “Distribution”), subject to any tax witholding 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”), will entitle the holder thereof to receive one share of Montauk common stock. The Transaction Implementation Agreement with MNK will govern the Distribution, the allocation of assets and liabilities between MNK and Montauk, and Montauk’s relationship with MNK following the Reorganization Transactions. See “Certain Relationships and Related Party Transactions—Relationship with MNK—Transaction Implementation Agreement.”

 

   

Following the Distribution, MNK and Montauk USA will be liquidated.

We refer to the Equity Exchange and the Distribution collectively as the “Reorganization Transactions.” We have completed the Equity Exchange and intend to complete the Distribution prior to the closing of this offering. All material approvals and actions required to execute each of the Reorganization Transactions have been or will have been obtained or taken, as appropriate, prior to the commencement of this offering. This offering will not be consummated unless each of the Reorganization Transactions is completed.

Following the completion of the Reorganization Transactions, but immediately prior to the consummation of this offering, MNK and holders of MNK’s ordinary shares will hold 100% of the outstanding shares of our common stock. Immediately following the consummation of this offering, MNK and holders of MNK’s ordinary shares will hold approximately 98.3% of the outstanding shares of our common stock, or approximately 98.1% if the underwriter exercises its option to purchase additional shares in full.

After full completion of the Reorganization Transactions and this offering, (i) Montauk USA will not own any assets and (ii) all entities through which MNK’s business and operations are currently conducted will be owned, directly or indirectly, by Montauk. Additionally, MNK will adopt a plan contemporaneously with the completion of the Reorganization Transactions that will authorize the liquidation and dissolution of MNK. As a result, we expect that MNK will be delisted from the JSE and liquidated subsequent to the consummation of this offering. Accordingly, MNK’s business is the business in which you are investing if you buy shares of common stock in this offering.

 

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Following the completion of Reorganization Transactions and this offering, Montauk will be the parent holding company of MEH and its subsidiaries as shown below:

 

 

LOGO

We will provide further information regarding the Reorganization Transactions in subsequent amendments to this registration statement of which this prospectus forms a part and prior to the completion of this offering.

 

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USE OF PROCEEDS

We estimate that the net proceeds to us from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, will be approximately $12.2 million, or approximately $15.0 million if the underwriter exercises in full its option to purchase additional shares, based on the initial public offering price of $8.50 per share.

We intend to use the net proceeds that we receive in this offering to fund the identification of, and diligence activities with respect to, potential new projects, which include evaluating new project sites, project conversions and strategic acquisitions. The timing of our use of the net proceeds received in this offering may vary significantly depending on numerous factors. While we have no current agreements, commitments or understandings for any specific use of the net proceeds at this time, we continue to actively consider potential opportunities.

We will not receive any proceeds from the sale of shares of our common stock by the selling stockholder.

Assuming no exercise of the underwriter’s option to purchase additional shares, each $1.00 increase (decrease) in the initial public offering price of $8.50 per share would increase (decrease) the net proceeds to us from this offering by $2,185,500, after deducting underwriting discounts and commissions and estimated expenses payable by us. Similarly, an increase (decrease) of one million shares of common stock sold in this offering by us would increase (decrease) our net proceeds by $7,905,000, based on the initial public offering price of $8.50 per share and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.

The foregoing represents our current intentions with respect to the use and allocation of the net proceeds of this offering based upon our present plans and business condition, but our management will have significant flexibility and discretion in applying the net proceeds. The occurrence of unforeseen events or changed business conditions could result in application of the net proceeds of this offering in a manner other than as described in this prospectus.

 

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DIVIDEND POLICY

We declared dividends of $7.6 million and $4.1 million in May 2018 and October 2018, respectively. We did not declare any cash dividends in 2019 or 2020. 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. 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.

Because we are a holding company and have no direct operations, we will only be able to pay dividends from our available cash on hand and any funds we receive from our subsidiaries. In addition, under Delaware law, our Board of Directors may declare dividends only to the extent of our surplus (which is defined as total assets at fair market value minus total liabilities, minus statutory capital) or, if there is no surplus, out of our net profits for the then current or immediately preceding fiscal year.

Accordingly, you may need to sell your shares of our common stock to realize a return on your investment, and you may not be able to sell your shares at or above the price you paid for them. See “Risk Factors—General Risk Factors—Our ability to pay regular dividends on our common stock is subject to the discretion of our Board of Directors.”

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of September 30, 2020:

 

   

on an actual basis;

 

   

on a pro forma basis to give effect to the Reorganization Transactions as if such transactions had occurred on September 30, 2020; and

 

   

on a pro forma as adjusted basis to give effect to (i) the pro forma adjustments set forth above; (ii) our receipt of the estimated net proceeds from the sale of common stock by us in the offering, after deducting the underwriting discounts and commissions and estimated fees and expenses payable by us, based on the initial public offering price of $8.50 per share; and (iii) the application of the net proceeds of this offering, as described in “Use of Proceeds.”

You should read this information in conjunction with “Use of Proceeds,” “Selected Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and related notes included elsewhere in this prospectus.

 

    As of September 30, 2020  
    Actual (1)     Pro Forma     Pro Forma as
Adjusted (2)
 
    (in thousands, except per share data)  

Cash and cash equivalents

  $ 19,537     $ 19,537     $
31,729
 
 

 

 

   

 

 

   

 

 

 

Debt:

     

Term Loans

    32,500       32,500       32,500  

Revolving Credit Facility

    36,698       36,698       36,698  

Total debt

    69,198       69,198       69,198  

Stockholders’/Member’s equity:

     

Common stock, $0.01 par value: 1,000 shares authorized, 10 shares issued and outstanding, actual; 690,000,000 shares authorized, 138,312,713 shares issued and outstanding, pro forma; 690,000,000 shares authorized, 140,662,713 shares issued and outstanding, pro forma as adjusted

    —         1,383       1,407  

Preferred stock, $0.01 par value: 10,000,000 shares authorized, no shares issued and outstanding, pro forma; 10,000,000 shares authorized, no shares issued and outstanding pro forma as adjusted

    —         —         —    

Additional paid-in capital

    —         155,484       167,864  

Member’s equity

    156,867       —         —    
 

 

 

   

 

 

   

 

 

 

Total stockholders’ / member’s equity

    156,867       156,867       169,271  
 

 

 

   

 

 

   

 

 

 

Total capitalization

  $ 226,065     $ 226,065     $ 238,469  
 

 

 

   

 

 

   

 

 

 

 

(1)

Reflects historical consolidated financial data of Montauk USA derived from Montauk USA’s unaudited consolidated financial statements included elsewhere in this prospectus.

(2)

Each $1.00 increase or decrease in the public offering price per share would increase or decrease, as applicable, our net proceeds, after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, by $2.2 million (assuming no exercise of the underwriter’s option to purchase additional shares). Similarly, an increase or decrease of one million shares of common stock sold in this offering by us would increase or decrease, as applicable, our net proceeds, after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, by $7.9 million, based on the initial public offering price of $8.50 per share.

 

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DILUTION

If you invest in our common stock in this offering, your ownership interest will be immediately diluted to the extent of the difference between the offering price per share and the pro forma as adjusted net tangible book value per share after this offering. Historical net tangible book value per share represents the amount of our total tangible assets less total liabilities, divided by the number of shares of common stock outstanding. Dilution in pro forma net tangible book value per share represents the difference between the amount per share paid by purchasers of our common stock in this offering and the pro forma as adjusted net tangible book value per share of common stock immediately after the consummation of this offering.

Our historical net tangible book value as of September 30, 2020 was $142.4 million, or $1.03 per share. Our pro forma net tangible book value as of September 30, 2020 was approximately $154.6 million, or $1.10 per share.

After giving effect to the sale of 2,350,000 shares of common stock in this offering at the initial public offering price of $8.50 per share, less the underwriting discounts and commissions and estimated offering expenses payable by us, our pro forma as adjusted net tangible book value as of September 30, 2020 would have been approximately $154.6 million, or approximately $1.10 per share. This represents an immediate increase in net tangible book value of $0.07 per share to existing stockholders and an immediate dilution in net tangible book value of $7.40 per share to new investors of common stock in this offering. The following table illustrates this per share dilution:

 

Initial public offering price per share

      $ 8.50  

Historical net tangible book value per share as of September 30, 2020

     1.03     

Increase in pro forma net tangible book value per share attributable to new investors in this offering

     0.07     
  

 

 

    

Pro forma net tangible book value per share immediately after this offering

        1.10  
     

 

 

 

Dilution per share to new investors in this offering

      $ 7.40  
     

 

 

 

Each $1.00 increase (decrease) in the initial public offering price of $8.50 per share, would increase (decrease) our as adjusted net tangible book value, after this offering by $2.2 million, or $0.02 per share and the dilution per share to new investors by $0.02, in each case after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.

If the underwriter were to fully exercise its option to purchase additional shares of our common stock, including pursuant to the underwriter warrants, our pro forma net tangible book value would be $1.12 per share. This represents an increase in pro forma as adjusted net tangible book value of $0.09 per share to our existing investors and an immediate dilution of $7.38 per share to new investors.

A one million share increase (decrease) in the number of shares offered by us would increase (decrease) our as adjusted net tangible book value by approximately $7.9 million, or $0.06 per share, and the dilution per share to new investors by approximately $(0.05), in each case based on the initial public offering price of $8.50 per share and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.

The following table summarizes, on an as adjusted basis as of September 30, 2020, after giving effect to this offering, the total number of shares of common stock purchased from us, the total cash consideration paid to

 

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us, or to be paid, and the average price per share paid, or to be paid, by new investors purchasing shares in this offering, at the initial public offering price of $8.50 per share before deducting the estimated underwriting discounts and commissions:

 

     Shares Purchased     Total Consideration     Average Price
Per Share
 
     Number      Percent     Amount      Percent  

Existing stockholders

     —          —     $ —          —     $ —    
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

New investors

     2,350,000        100   $ 19,975,000        100   $ 8.50  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Total

     2,350,000        100   $ 19,975,000        100   $ 8.50  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

If the underwriter were to fully exercise its option to purchase 352,500 additional shares of our common stock, the percentage of shares of our common stock held by existing investors would be 98.1%, and the percentage of shares of our common stock held by new investors would be 1.9%.

Sales of shares of our common stock by the selling stockholder in this offering will reduce the number of shares held by the existing stockholders to 137,615,698, or approximately 97.8% of the total shares of common stock outstanding after this offering (or approximately 97.6% of the total shares of common stock outstanding after this offering, if the underwriter exercises its option to purchase additional shares in full) and will increase the number of shares held by new investors to 3,047,015, or approximately 2.2% of the total shares of common stock outstanding after this offering (or 3,399,515 shares, or approximately 2.4% of the total shares of common stock outstanding after this offering, if the underwriter exercises its option to purchase additional shares in full).

The foregoing tables and calculations exclude 20,000,000 shares of our common stock, reserved for future issuance under the Equity Plan as of the date hereof, which will be effective upon the completion of this offering. To the extent equity awards are granted and exercised, there will be further dilution to new investors.

The above discussion and tables are based on the number of shares outstanding at September 30, 2020, after giving effect to the Reorganization Transactions. In addition, we may choose to raise additional capital due to market conditions or strategic considerations even if we believe we have sufficient funds for our current or future operating plans. To the extent that additional capital is raised through the sale of equity or convertible debt securities, the issuance of such securities could result in further dilution to our stockholders.

 

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SELECTED CONSOLIDATED FINANCIAL DATA

The following tables set forth a summary of the historical consolidated financial data of Montauk USA for the years ended December 31, 2019 and 2018 and the nine months ended September 30, 2020 and 2019. The consolidated financial statements of Montauk USA, our predecessor for accounting purposes, will be our historical financial statements following this offering. The historical summary consolidated financial data set forth in the following tables for the years ended December 31, 2019 and 2018 and the nine months ended September 30, 2020 and 2019 have been derived from Montauk USA’s consolidated financial statements included elsewhere in this prospectus. You should read this data together with Montauk USA’s financial statements and the related notes appearing elsewhere in this prospectus and the information included under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Montauk USA’s historical results are not necessarily indicative of our future results.

Statement of Operations Data:

 

     Year ended
December 31,
     Nine months ended
September 30,
 
     2019      2018      2020      2019  
     (in thousands, except per share data)  

Total revenues

   $ 107,383      $ 116,433      $ 75,559      $ 83,703  

Operating expenses

           

Operating and maintenance expenses

     39,783        29,073        30,884        30,306  

General and administrative expenses

     13,632        11,953        11,336        10,593  

Royalties, transportation, gathering and production fuel expenses

     20,558        22,359        14,769        16,197  

Depreciation and amortization

     19,760        16,195        16,120        14,754  

Impairment loss

     2,443        854        278        1,550  

Gains on insurance proceeds

     —          —          (3,444      —    

Transaction costs

     202        176        —          202  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses

   $ 96,378      $ 80,610      $ 69,943      $ 73,602  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating profit

   $ 11,005      $ 35,823      $ 5,616      $ 10,101  
  

 

 

    

 

 

    

 

 

    

 

 

 

Other expenses (income):

           

Interest expense

   $ 5,576      $ 3,083      $ 3,510      $ 5,293  

Equity loss (gain) of nonconsolidated investments

     (94      224        —          (94

Net loss (gain) on sale of assets

     10        (266      —          10  

Other expense (income)

     47        (3,781      250        (17
  

 

 

    

 

 

    

 

 

    

 

 

 

Total other expenses (income)

   $ 5,539      $ (740    $ 3,760      $ 5,192  

Income tax expense (benefit)

     (354      7,796        (291      (539

Net income

   $ 5,820      $ 28,767      $ 2,147      $ 5,448  
  

 

 

    

 

 

    

 

 

    

 

 

 

Pro forma earnings per share (unaudited):

           

Basic

   $ 0.04         $ 0.02     

Diluted

   $ 0.04         $ 0.02     

 

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Balance Sheet Data:

 

     As of December 31,      As of September 30,  
     2019      2018      2020      2019  
     (in thousands)  

Cash and cash equivalents

   $ 9,788      $ 54,032      $ 19,537      $ 3,003  

Working capital (deficit)

     (154      34,790        6,537        (8,661

Property, plant and equipment—net

     193,498        168,418        189,957        187,868  

Total assets

     243,613        261,732        251,527        230,809  

Long-term debt

     57,256        74,649        58,656        43,577  

Member’s equity

     154,257        147,941        156,867        154,050  

Non-GAAP measures:

 

     Year ended on
December 31,
     Nine months ended
September 30,
 
     2019      2018      2020      2019  
     (in thousands)  

EBITDA (1)

   $ 30,802      $ 55,841      $ 21,486      $ 24,956  

Adjusted EBITDA (1)

   $ 33,615      $ 56,921      $ 21,376      $ 27,038  

 

(1)

See “Summary Consolidated Financial Data” for a reconciliation of Montauk USA’s income from continuing operations to EBITDA and Adjusted EBITDA for the periods presented.

 

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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 prospectus. 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, will be our historical financial statements following this offering. 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 “Special Note Regarding Forward-Looking Statements” and “Risk Factors” and elsewhere in this prospectus.

Our Company

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. Having participated in the industry for over 30 years, we are one of the largest U.S. producers of RNG. 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 $34.0 million in 2014 to $107.4 million in 2019.

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 Environmental Attributes sales. 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, such as RINs and LCFS credits, derived from RNG. Our RNG revenues from Environmental Attributes are recorded net of a portion of

 

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Environmental Attributes shared with off-take counterparties as consideration for such counterparties using the RNG as a transportation fuel. We monetize a portion of our RNG production under fixed-price 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 most 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 address any issues that may arise proactively through preventative maintenance, process improvement and flexible redeployment of equipment to maximize production and useful life.

 

   

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 will benefit from the consistency of feedstock and controlled environment of collection of waste to improve biogas quality.

 

   

RNG Production from Our Growth Projects: We employ a multi-pronged growth strategy that enables us to pursue growth through: (i) expanding, converting and optimizing our existing portfolio, (ii) acquiring and developing new projects and (iii) broadening our sources of fuel supply. We also anticipate increased production at certain of our existing projects as open landfills continue to take in additional waste and the 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

 

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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. We are considering conversion to RNG for one Renewable Electricity site in our portfolio.

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 and the following calendar year. The EPA set the 2020 RVOs for D3 RINs at 590 million gallons, representing a 41% increase over the 2019 RVOs, and is expected to promulgate final 2021 RVOs by June 2021.

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 end users. These expenses include payments to pipeline operators and other agencies that allow for the transmission of our gas and electricity commodities to end users. Production fuel expenses generally represent alternative royalty payments based on quantity usage of biogas feedstock.

 

   

General and Administrative Expenses: General and administrative expenses primarily consist of corporate expenses and unallocated support functions for our operating facilities, including personnel costs for executive, finance, accounting, investor relations, legal, human resources, operations, engineering, environmental registration and reporting, health and safety, IT and other administrative personnel and professional fees and general corporate expenses.

 

   

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.

 

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Transaction Costs: Transaction costs primarily consist of expenses incurred for due diligence and other activities related to potential acquisitions and other strategic transactions.

Key Operating Metrics

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

 

   

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. A majority of our Renewable Electricity Generation segment commodity production is 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.

 

     Year ended
December 31,
             
     2019     2018     Change $     Change %  
     (in thousands, unless otherwise indicated)  

Revenues

      

Renewable Natural Gas Total Revenues

   $ 85,926     $ 98,584     $ (12,658     (12.8 )% 

Renewable Electricity Generation Total Revenues

   $ 19,859     $ 18,207     $ 1,652       9.1

RNG Metrics

        

CY RNG production volumes (MMBtu)

     5,361       4,485       876       19.5

Less: Current period RNG volumes under fixed/floor-price contracts

     (1,987     (1,952     (35     1.8

Plus: Prior period RNG volumes dispensed in current period

     371       154       217       140.9

Less: Current period RNG production volumes not dispensed

     (266     (371     105       28.3

Total RNG volumes available for RIN generation (1)

     3,479       2,316       1,163       50.2

RIN Metrics

        

Current RIN generation (x 11.727) (2)

     40,791       27,146       13,645       50.3

Less: Counterparty share (RINs)

     (3,729     (5,389     1,660       30.8

Plus: Prior period RINs carried into CY

     1,690       1,774       (84     (4.7 )% 

Less: CY RINs carried into next CY

     (886     (1,690     804       47.6

Total RINs available for sale (3)

     37,866       21,841       16,025       73.4

Less: RINs sold

     (36,767     (22,091     (14,676     (66.4 )% 

RIN Inventory

     1,099       (250     1,349       539.6

RNG Inventory (volumes not dispensed for RINs) (4)

     (266     (371     105       28.3

Average Realized RIN price

   $ 1.45     $ 2.37     $ (0.92     (38.8 )% 

Operating Expenses

        

Renewable Natural Gas Operating Expenses

   $ 46,853     $ 37,997     $ 8,856       23.3

Operating Expenses per MMBtu (actual)

   $ 8.74     $ 8.47     $ 0.27       3.2

Renewable Electricity Generation Operating Expenses

   $ 13,299     $ 11,969     $ 1,330       11.1

$/MWh (actual)

   $ 56.36     $ 48.71     $ 7.65       15.7

Other Metrics

        

Renewable Electricity Generation Volumes Produced (MWh)

     236       246       (10     (4.1 )% 

Average Realized Price $/MWh (actual)

   $ 84.16     $ 74.10     $ 10.06       13.6

 

(1)

RINs are generated in the month following the month that gas is produced and dispensed. 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 for which RINs are not generated.

 

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Results of Operations

Comparison of Years Ended December 31, 2019 and 2018

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

 

     Year ended
December 31,
             
     2019     2018     Change $     Change %  
     (in thousands)  

Total operating revenues

   $ 107,383     $ 116,433     $ (9,050     (7.8 )% 

Operating expenses:

        

Operating and maintenance expenses

   $ 39,783     $ 29,073     $ 10,710       36.8

General and administrative expenses

     13,632       11,953       1,679       14.0  

Royalties, transportation, gathering and production fuel

     20,558       22,359       (1,801     (8.1

Depreciation and amortization

     19,760       16,195       3,565       22.0  

Impairment loss

     2,443       854       1,589       186.1  

Transaction costs

     202       176       26       14.8  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

   $ 96,378     $ 80,610     $ 15,768       19.6
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating profit

     11,005       35,823       (24,818     (69.3 )% 

Other expenses (income):

     5,539       (740     6,279       848.6

Income tax expense (benefit)

     (354     7,796       (8,150     (104.5 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 5,820     $ 28,767     $ (22,947     (79.8 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Revenues for the Years Ended December 31, 2019 and 2018

Total revenues in 2019 were $107.4 million, a decrease of $9.0 million (7.8%) compared to $116.4 million in 2018. The primary driver for this decrease related to falling D3 RIN index pricing in 2019 as compared to 2018. Partially offsetting the unfavorable price environment was our ability to increase RNG production. In addition to commissioning a new facility during the fourth quarter of 2019, 2019 included a full year of production from two facilities commissioned during the second and third quarters of 2018. Specifically, the following facilities and their commercial operation dates (“COD”) were: Atascocita, May 2018; Apex, August 2018; and Galveston, October 2019.

Renewable Natural Gas Revenues

We produced 5.4 million MMBtu of RNG during 2019, an increase over the 4.5 million MMBtu (20%) produced in 2018. Of this increase, 0.9 million MMBtu of RNG were produced from development sites commissioned during 2018. A site commissioned in 2019 produced 0.1 million MMBtu of RNG.

Revenues from the Renewable Natural Gas segment in 2019 were $85.8 million, a decrease of $12.8 million (13%) compared to $98.6 million in 2018. Average commodity pricing for natural gas for 2019 was 34.7% lower than the prior year. During 2019, we self-monetized 36.8 million RINs, representing a 14.7 million increase (67%) compared to 22.1 million in 2018. The increase was attributable to a shift in our strategy to a self-marketing strategy to sell Environmental Attributes based on index pricing rather than under contract arrangements. Average pricing realized on RIN sales during 2019 was $1.44 as compared to $2.38 in 2018, a decrease of 39.6%. This decrease of the D3 RIN index was driven by a drop in RIN demand due to 2018 RIN carryover, small refinery exceptions to RVOs, and industry production. This compares to the average D3 RIN index price for 2019 of $1.15 being approximately 49.9% lower than the average D3 RIN index price in 2018. The CWC price in 2019 was $1.77, a 9.6% decrease from $1.96 from 2018. RIN sales in 2019 were priced generally on the D3 RIN index while 2018 RIN sales also included sales based on the D5 RIN index plus a portion of the CWC.

 

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At December 31, 2019, we had approximately 0.9 million RINs generated and unsold in inventory as well as 0.3 million MMBtu available for RIN generation. We had to purchase RINs in 2019 to satisfy 2018 commitments and had 1.7 million RINs generated and unsold at December 31, 2018. We had 0.4 million MMBtu available for RIN generation at December 31, 2018.

Renewable Electricity Generation Revenues

We produced 0.2 million MWh in Renewable Electricity in 2019, consistent with the prior year. 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. In 2018, we ended electricity production at our Atascocita location during its conversion to an RNG site. Finally, in 2018, we acquired Pico and began reporting our electricity production in the Renewable Electricity Generation segment. 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 2019 were $19.9 million, an increase of $1.7 million (9.1%) compared to $18.2 million in 2018. Pico accounted for $1.0 million of the $1.7 million increase in 2019. For 2019, 93.9% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices as compared to 88.9% in 2018.

Corporate Revenue

Our gas hedge program during 2019 was priced at rates in excess of the actual index price resulting in realized gains of $1.7 million, an increase of $2.1 million (574.9%) compared to realized losses of $0.4 million in 2018.

Expenses for the Years Ended December 31, 2019 and 2018

General and Administrative Expenses

Total general and administrative expenses of $13.6 million in 2019 increased by $1.7 million (14.0%) compared to $12.0 million in 2018. Employee related costs, including severance, increased approximately $1.3 million (28.9%) in 2019 as compared to the prior year period. Additionally, our insurance premiums increased approximately $0.6 million (48.3%) in 2019 over 2018. Third-party consulting fees decreased approximately $0.7 million (45.6%) in 2019 resulting from our previous efforts at completing a transaction to change securities exchanges.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities in 2019 were $28.6 million, an increase of $10.5 million (57.9%) compared to $18.1 million in 2018. Of the total, $6.1 million related to development sites commissioned during 2018. A site commissioned in 2019 contributed $0.8 million to the total. Exclusive of the effects of these development sites, operating and maintenance expenses in 2019 were $17.7 million, an increase of $3.7 million (26.0%) compared to $14.1 million in 2018. The increase is attributable to the timing of equipment maintenance and expenses relating to gas cleaning component materials. Royalties, transportation, gathering and production fuel expenses for our RNG facilities for 2019 were $18.2 million, a decrease of $1.6 million (8.3%) compared to $19.8 million in 2018; however, royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues from 20.1%, or $19.8 million, in 2018 to 21.2%, or $18.2 million, in 2019. Of the total, $5.7 million related to development sites commissioned during 2018. A site commissioned in 2019 contributed $0.1 million to the total. Exclusive of the effects of the development sites, royalty related costs in 2019 were $12.5 million, a decrease of $5.1 million (28.8%) compared to $17.6 million in 2018. This decrease correlates to the decrease in revenue recognized by non-development sites in 2019 from 2018.

 

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Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities in 2019 were $11.0 million, an increase of $1.5 million (15.5%) compared to $9.5 million in 2018. We reported the results of Pico within the Renewable Electricity Generation segment until October 2020. Of the total, Pico contributed $1.2 million in 2019 and, exclusive of Pico, Renewable Electricity facility operating and maintenance expenses increased by $0.7 million (7.4%). The increase is largely attributed to non-capitalized optimization costs for the Bowerman electricity generation facility and to a lesser extent the timing of equipment maintenance at the Security electricity generation location. Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for 2019 were $2.4 million, a decrease of $0.1 million (4.1%) compared to $2.5 million in 2018 and as a percentage of Renewable Electricity Generation segment revenues decreased from 13.9% to 13.1%. This decrease relates to reduced royalty related expenses at sites converted to RNG sites during 2018 and from a site vacated in 2019.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses in 2019 were $20.6 million, a decrease of $1.8 million (8.1%) compared to $22.4 million in 2018. 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 2019 was $19.8 million, an increase of $3.6 million (22.0%) compared to $16.2 million in 2018. The increase was due to approximately $52.9 million in development site assets being placed into service during 2018 at the time of 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 $2.4 million for 2019, an increase of $1.6 million (186.1%) compared to $0.9 million in 2018. The impairment loss was due to the cancellation of a site conversion agreement and conversion of existing Renewable Electricity to RNG sites in 2019 and the write-off of assets distributed from our Red Top joint venture. In 2018, the impairments related to the conversion of existing Renewable Electricity to RNG sites and continued deterioration in market pricing for electricity. We calculated impairments based upon replacement cost, if applicable, and pre-tax cash flow projections.

Other Expenses (Income)

Other expenses in 2019 were $5.5 million, an increase of $4.8 million (685.7%) compared to income of $0.7 million in 2018. During 2018, we realized a gain of $2.6 million attributable to one-time settlement proceeds from arbitration related to the construction of a facility as well as a non-cash gain of $1.2 million related to an outstanding liability for the construction of the same facility which was not required to be paid.

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. We recorded our share of losses from Red Top in 2018 of ($0.2) million.

 

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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 sometime after 2022 and thus have not recorded a valuation allowance against such NOLs.

Our effective income tax rate for 2019 was a benefit of 6.5% compared to an expense of 21.3% for the prior year period. We recorded a deferred tax asset related to disallowed interest expense which was fully offset by a deferred tax liability related to bonus depreciation. In 2018, we revalued our deferred tax assets associated with the enactment of the Tax Act resulting in a reduction of approximately $6.3 million of its existing deferred tax assets.

Operating Profit for the Years Ended December 31, 2019 and 2018

Operating profit in 2019 was $11.0 million, a decrease of $24.8 million (69.3%) compared to $35.8 million in 2018. RNG operating profit for 2019 was $25.7 million, a decrease of $25.1 million (49.5%) compared to $50.8 million in 2018. Renewable Electricity Generation operating loss for 2019 was $2.4 million, an increase of $0.1 million (4.7%) compared to $2.3 million in 2018.

Results of Operations

Comparison of Nine Months Ended September 30, 2020 and 2019

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

 

     Nine months ended
September 30,
             
     2020     2019     Change $     Change %  
     (in thousands)  

Total operating revenues

   $ 75,559     $ 83,703     $ (8,144     (9.7 )% 

Operating expenses:

        

Operating and maintenance expenses

   $ 30,884     $ 30,306     $ 578       1.9

General and administrative expenses

     11,336       10,593       743       7.0  

Royalties, transportation, gathering and production fuel

     14,769       16,197       (1,428     (8.8

Depreciation and amortization

     16,120       14,754       1,366       9.3  

Impairment loss

     278       1,550       (1,272     (82.1

Gains on insurance proceeds

     (3,444     —         (3,444     (100

Transaction costs

     —         202       (202     (100
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     69,943       73,602       (3,659     (5.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating profit

   $ 5,616     $ 10,101     $ (4,485     (44.4 )% 

Other expenses:

        

Interest expense

   $ 3,510     $ 5,293     $ (1,783     (33.7 )% 

Equity loss (gain) of nonconsolidated investments

     —         (94     94       100  

Net loss (gain) on sale of assets

     —         10       (10     (100

Other expense (income)

     250       (17     267       1,571  

Income tax benefit

     (291     (539     248       46.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 2,147     $ 5,448     $ (3,301     (60.6 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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

 

     Nine months ended
September 30,
             
     2020     2019     Change $     Change %  
Revenues    (in thousands, unless otherwise indicated)  

Renewable Natural Gas Total Revenues

   $ 62,192     $ 67,322     $ (5,130     (7.6 )% 

Renewable Electricity Generation Total Revenues

   $ 13,282     $ 14,927     $ (1,645     (11.0 )% 

RNG Metrics

        

CY RNG production volumes (MMBtu)

     4,451       4,040       411       10.2

Less: Current period RNG volumes under fixed/floor-price contracts

     (1,579     (1,480     (99     (6.7 )% 

Plus: Prior period RNG volumes dispensed in current period

     266       371       (105     (28.3 )% 

Less: Current period RNG production volumes not dispensed

     (320     (282     (38     (13.5 )% 

Total RNG volumes available for RIN generation (1)

     2,818       2,649       169       6.4

RIN Metrics

        

Current RIN generation (x 11.727) (2)

     33,049       31,065       1,984       6.4

Less: Counterparty share (RINs)

     (3,612     (2,904     (708     (24.4 )% 

Plus: Prior period RINs carried into CY

     1,330       1,690       (360     (21.3 )% 

Less: CY RINs carried into next CY

     —         —         —         —    

Total RINs available for sale (3)

     30,767       29,851       916       3.1

Less: RINs sold

     (30,269     (26,686     (3,583     (13.4 )% 

RIN Inventory

     498       3,165       (2,667     (84.3 )% 

RNG Inventory (volumes not dispensed for RINs) (4)

     320       282       38       13.5

Average Realized RIN price

   $ 1.25     $ 1.59     $ (0.34     (21.4 )% 

Operating Expenses

        

Renewable Natural Gas Operating Expenses

   $ 23,015     $ 21,719     $ 1,296       6.0

Operating Expenses per MMBtu (actual)

   $ 5.17     $ 5.38     $ (0.21     (3.9 )% 

Renewable Electricity Generation Operating Expenses

   $ 9,216     $ 10,309     $ (1,093     (10.6 )% 

$/MWh (actual)

   $ 60.62     $ 56.41     $ 4.21       7.5

Other Metrics

        

Renewable Electricity Generation Volumes Produced (MWh)

     152       183       (31     (16.9 )% 

Average Realized Price $/MWh (actual)

   $ 87.14     $ 81.69     $ 5.45       6.7

 

(1)

RINs are generated the month following the month gas is produced and dispensed. 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 on which RINs are not generated.

Revenues for the Nine Months Ended September 30, 2020 and 2019

Total revenues for the nine months ended September 30, 2020 were $75.6 million, a decrease of $8.1 million (9.7%) compared to $83.7 million for the nine months ended September 30, 2019. The primary driver for this decrease related to a 7.6% decrease in RNG revenues related to decreased commodity prices of approximately 29.6% and realized RIN pricing of 21.4% as compared to the prior year period. Improved volumes and related increased RIN sales partially offset this decrease. To a lesser extent, reduced renewable electricity volumes in the current year period led to a decrease of 11.0% over the prior year period.

 

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Renewable Natural Gas Revenues

We produced 4.5 million MMBtu of RNG during the nine months ended September 30, 2020, an increase over the 4.0 million MMBtu (10.2%) produced during the nine months ended September 30, 2019. Of this increase, 0.2 million MMBtu of RNG were produced from a development site commissioned after the nine months ended September 30, 2019. Wellfield improvement initiatives at our Apex site yielded an increase of 0.1 million MMBtu over the prior year period. Our McCarty site was unfavorably impacted by the loss of one of its production engines leading to a reduction in 2020 of 0.1 million MMBtu over the 2019 period.

Revenues from the Renewable Natural Gas segment for the nine months ended September 30, 2020 were $62.2 million, a decrease of $5.1 million (7.6%) compared to $67.3 million for the nine months ended September 30, 2019. Average commodity pricing for natural gas for the nine months ended September 30, 2020 was 29.6% lower than the comparative period. During the nine months ended September 30, 2020, we self-monetized 30.3 million RINs, representing a 3.6 million increase (13.4%) compared to 26.7 million during the nine months ended September 30, 2019. The increase was primarily related to increased MMBtu production over the prior year period. D3 RIN pricing continued its decline through 2019, with the third quarter of 2019 experiencing the largest decline with a D3 RIN price index average of $0.68. The negative impact of the COVID-19 pandemic on D3 RIN pricing in the second quarter of 2020 has decreased, and D3 RIN pricing has continued to improve throughout 2020 with a third quarter D3 RIN price index average of $1.55. Average pricing realized on RIN sales during the nine months ended September 30, 2020 was $1.25 as compared to $1.59 during the nine months ended September 30, 2019, a decrease of 21.4%. This compares to the average D3 RIN index price for the nine months ended September 30, 2020 of $1.39 being approximately 10.6% higher than the average D3 RIN index price during the nine months ended September 30, 2019. Approximately 8.0 million of our RIN sales during the nine months ended September 30, 2019 were based on D5 RIN index pricing and the cellulosic waiver credit which results in a RIN sales price in excess of the D3 RIN index.

At September 30, 2020, we had approximately 0.4 million RINs generated and unsold in inventory as well as 0.3 million MMBtu available for RIN generation. We had approximately 3.2 million RINs generated and unsold at September 30, 2019. We had 0.3 million MMBtu available for RIN generation at September 30, 2019.

Renewable Electricity Generation Revenues

We produced 0.2 million MWh in Renewable Electricity during the nine months ended September 30, 2020, consistent with the comparative period. During the nine months ended September 30, 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.

Revenues from Renewable Electricity facilities for the nine months ended September 30, 2020 were $13.3 million, a decrease of $1.6 million (11.0%) compared to $14.9 million for the nine months ended September 30, 2019. The exit of Monmouth and conversion of Coastal Plains resulted in approximately $1.1 million of the decrease. Pico accounted for $0.4 million of the $1.6 million decrease between the nine months ended September 30, 2020 and 2019. For 2020, 100% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices as compared to 70.7% during the nine months ended September 30, 2019.

Corporate Revenue

Our gas hedge program during the nine months ended September 30, 2020 was priced at rates in excess of the actual index price resulting in realized gains of $0.1 million, a decrease of $1.4 million (94.2%) compared to realized gain of $1.5 million during the nine months ended September 30, 2019.

 

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Expenses for the nine months ended September 30, 2020 and 2019

General and Administrative Expenses

Total general and administrative expenses of $11.3 million for the nine months ended September 30, 2020 increased by $0.7 million (7.0%) compared to $10.6 million for the nine months ended September 30, 2019. Employee related costs, including severance, increased approximately $0.2 million (4.1%) for the nine months ended September 30, 2020 as compared to the prior comparative period. Additionally, our insurance premiums increased approximately $0.5 million (40.4%) for the nine months ended September 30, 2020 over the nine months ended September 30, 2019.

Renewable Natural Gas Expenses

Operating and maintenance expenses for our RNG facilities for the nine months ended September 30, 2020 were $23.0 million, an increase of $1.3 million (6.0%) compared to $21.7 million for the nine months ended September 30, 2019. Of the total, $2.4 million related to a development site commissioned after the nine months ended September 30, 2019. A site commissioned during the nine months ended September 30, 2020 contributed $0.1 million to the total. Exclusive of the effects of these development sites, operating and maintenance expenses for the nine months ended September 30, 2020 were $20.3 million, a decrease of $1.2 million (5.6%) compared to $21.5 million for the nine months ended September 30, 2019. The decrease is primarily attributable to reduced media change-outs at our McCarty location. Partially offsetting this decrease were increased utility expenses at our Rumpke location. Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the nine months ended September 30, 2020 were $13.4 million, a decrease of $0.9 million (6.7%) compared to $14.3 million for the nine months ended September 30, 2019; however, royalties, transportation, gathering and production fuel expenses increased as a percentage of RNG revenues from 21.2% for the nine months ended September 30, 2020 to 21.4% for the nine months ended September 30, 2019. Of the total, $0.7 million related to development sites commissioned during October 2019. A site commissioned during the nine months ended September 30, 2020 contributed an immaterial amount. Exclusive of the effects of the development sites, royalty related costs for the nine months ended September 30, 2020 were $12.6 million, a decrease of $1.7 million (11.7%) compared to $14.3 million for the nine months ended September 30, 2019. This decrease correlates to the decrease in revenue recognized by non-development sites for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019.

Renewable Electricity Expenses

Operating and maintenance expenses for our Renewable Electricity facilities for the nine months ended September 30, 2020 were $7.9 million, a decrease of $0.5 million (6.4%) compared to $8.4 million for the nine months ended September 30, 2019. We reported the results of Pico within the Renewable Electricity Generation segment until October 2020. Of the total, Pico contributed $1.4 million for the nine months ended September 30, 2020 and, exclusive of Pico, Renewable Electricity facility operating and maintenance expenses decreased by $1.1 million (14.4%). The decrease is largely attributed to a reduction of $0.7 million associated with the exit and conversion of our Monmouth and Coastal Plains, respectively, sites. Our Bowerman site also had decreased planned maintenance during the current period. Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the nine months ended September 30, 2020 were $1.4 million, a decrease of $0.5 million (29.4%) compared to $1.9 million for nine months ended September 30, 2019 and as a percentage of Renewable Electricity Generation segment revenues decreased from 13.9% for the nine months ended September 30, 2019 to 10.8% in the nine months ended September 30, 2020. This decrease relates to $0.6 million in royalty related expenses incurred in 2019 associated with Monmouth and Coastal Plains.

Royalty Payments

Royalties, transportation, gathering, and production fuel expenses for the nine months ended September 30, 2020 were $14.8 million, a decrease of $1.4 million (8.8%) compared to $16.2 million for the nine

 

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months ended September 30, 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 for the nine months ended September 30, 2020 was $16.1 million, an increase of $1.3 million (9.3%) compared to $14.8 million for the nine months ended September 30, 2019. The increase was due to approximately $21.3 million in development site assets being placed into service after the nine months ended September 30, 2019 at the time of COD. For the nine months ended September 30, 2020, approximately $35.3 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 the nine months ended September 30, 2020, a decrease of $1.3 million (82.1%) compared to $1.6 million for the nine months ended September 30, 2019. The impairment loss for the nine months ended September 30, 2020 was related to the termination of a development agreement related to our Pico acquisition. The impairment loss for the nine months ended September 30, 2019 was due to the cancellation of a site conversion agreement and conversion of existing Renewable Electricity to RNG sites in 2019 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.

Gains on Insurance Proceeds

During the nine months ended September 30, 2020, we received insurance proceeds related to an engine failure at our McCarty RNG location. During the fourth quarter of 2019, one of the McCarty production engines failed resulting in reduced production. The engine was replaced and commissioning began during the first quarter of 2020. We submitted this claim to our insurance carrier and have received total proceeds of $3.4 million for business interruption and property loss, net of deductibles. These proceeds were recorded within “Operating expenses” in the consolidated statements of operations.

Other Expense (Income)

Other expense was $3.8 million for the nine months ended September 30, 2020, a decrease of $1.4 million (27.6%) compared to $5.2 million for the nine months ended September 30, 2019. Other expense for the comparative periods was primarily comprised of interest expense.

Income Tax Benefit

Income tax benefit decreased $248 for the nine months ended September 30, 2020 compared with the nine months ended September 30, 2019 primarily due to the impact of generated tax credits compared to lower pre-tax earnings in the current year. We recorded a tax benefit of ($2,251) in connection with the January 1, 2020 dissolution of the Montauk Energy Capital, LLC partnership which will allow all entities under Montauk Energy Capital, LLC to file as part of our consolidated federal tax group.

See Note 14, “Income Taxes” to our unaudited consolidated financial statements for more information on the computation of the income tax expense in interim periods.

The CARES Act, enacted by the United States on March 27, 2020, did not have a material impact on our provision for income taxes for the nine months ended September 30, 2020. The Company is continuing to analyze the ongoing impact of the CARES Act.

 

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Operating Profit for the Nine Months Ended September 30, 2020 and 2019

Operating profit for the nine months ended September 30, 2020 was $5.6 million, a decrease of $4.5 million (44.4%) compared to $10.1 million for the nine months ended September 30, 2019. RNG operating profit for the nine months ended September 30, 2020 was $18.8 million, a decrease of $3.2 million (14.5%) compared to $22.0 million for the nine months ended September 30, 2019. Renewable Electricity Generation operating loss for the nine months ended September 30, 2020 was $1.8 million, a decrease of $0.7 million (27.8%) compared to $2.5 million for nine months ended September 30, 2019. The aforementioned decreased revenues within our RNG and Renewable Electricity Generation segments drove the decrease in operating profit. The primary reason for the reduced RNG revenues was related to index price declines of both our commodity sales and our RIN sales. To a lesser extent, the lower Renewable Electricity Generation revenues were related to site exits and conversions in the prior year period.

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.

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

 

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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 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 is expected to promulgate final 2021 RVOs by June 2021, which will affect the market price of RINs for 2021. 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 Adjusted EBITDA, a non-GAAP financial measure for each of the periods presented below. We present Adjusted EBITDA because we believe the measure assists 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, Adjusted EBITDA is a financial measurement 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. Adjusted EBITDA is a supplemental performance measure that is not required by, or presented in accordance with, GAAP. Adjusted EBITDA should not be considered an alternative 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,
     Nine months ended
September 30,
 
     2019      2018      2020      2019  
     (in thousands)  

Net income

   $ 5,820      $ 28,767      $ 2,147      $ 5,448  

Depreciation and amortization

     19,760        16,195        16,120        14,754  

Interest expense

     5,576        3,083        3,510        5,293  

Income tax expense (benefit)

     (354      7,796        (291      (539
  

 

 

    

 

 

    

 

 

    

 

 

 

EBITDA

     30,802        55,841        21,486        24,956  
  

 

 

    

 

 

    

 

 

    

 

 

 

Impairment loss (1)

     2,443        854        278        1,550  

Transaction costs

     202        176        —          202  

Equity loss (gain) of nonconsolidated investments

     (94      224        —          (94

Net loss (gain) on sale of assets

     10        (266      —          10  

Non-cash hedging charges

     252        92        (388      414  
  

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $ 33,615      $ 56,921      $ 21,376      $ 27,038  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

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 an asset distribution from Red Top for the year ended December 31, 2018. For the nine months ended September 30, 2020, we recorded an impairment loss of $0.3 million related to the termination of a development agreement related to our Pico acquisition. We recorded an impairment loss of $1.6 million for the nine months ended September 30, 2019 related to the cancellation of a site conversion agreement and conversion of existing Renewable Electricity to RNG sites as well as the write-off of Red Top assets.

Liquidity and Capital Resources

Sources of Liquidity

At December 31, 2019 and 2018, our cash and cash equivalents, net of restricted cash, was $9.8 million and $54.0 million, respectively. At September 30, 2020 and 2019, our cash and cash equivalents, net of restricted cash, was $19.5 million and $3.0 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 24 months. However, we are subject to business and operational risks that could adversely affect our cash flows and liquidity.

At December 31, 2019, we had debt before debt issuance costs of $68.2 million, compared to debt before debt issuance costs of $95.0 million at December 31, 2018. In September 2019, we repaid $38.2 million in term loan debt associated with the Second Amendment (as defined below). These debt maturities are reflected in the contractual obligations table below. The debt is subject to various financial covenants. At September 30, 2020, we had debt before debt issuance costs of $69.2 million, compared to debt before issuance costs of $68.2 million at December 31, 2019. As of September 30, 2020, we were in compliance with all financial covenants associated with the borrowings.

 

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Our debt before issuance costs is as follows:

 

     As of  
     September 30,
2020
     December 31,
2019
     December 31,
2018
 
     (in thousands)  

Term Loans

   $ 32,500      $ 40,000      $ 95,000  

Revolving Credit Facility

     36,698        28,198        —    
  

 

 

    

 

 

    

 

 

 

Debt before debt issuance costs

   $ 69,198      $ 68,198      $ 95,000  
  

 

 

    

 

 

    

 

 

 

In addition, we had $36.7 million available to be borrowed under our revolving credit facility at September 30, 2020.

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, 2019, $40.0 million was outstanding under the term loan and $28.2 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 4.642% and 5.511% at December 31, 2019 and 2018, 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.

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 September 30, 2020, we were in compliance with all financial covenants related to the Amended Credit Agreement.

 

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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 2, “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. 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, 2019 and 2018 and the nine months ended September 30, 2020 and 2019:

 

     Year ended
December 31,
    Nine months ended
September 30,
 
     2019     2018     2020     2019  
     (in thousands)  

Net cash flows provided by operating activities

   $ 27,464     $ 49,681     $
21,947
 
  $ 21,662  

Net cash flows used in investing activities

     (44,566     (52,886    
(13,054

    (32,057

Net cash flows (used in) provided by financing activities

     (27,515     34,231       1,000       (41,014

Net (decrease) increase in cash, cash equivalents and restricted cash

     (44,617     31,026       9,893       (51,409

Restricted cash, end of period

     574       947       718       567  

Cash and cash equivalents and restricted cash, end of period

     10,362       54,979       20,255       3,570  

For 2019, we generated $27.5 million of cash from operating activities, a 44.7% decrease from the prior year primarily due to increased operating costs associated with new operating locations being commissioned. 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 adversely affected by lower RIN pricing in 2019 over the prior year period. Our net cash flows used in investing activities has historically focused on project development and facility maintenance. For 2019, our capital expenditures were $45.2 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. For 2018, our capital expenditures were $40.2 million, of which $6.1 million related to the construction of the Atascocita RNG facility, $9.3 million for the Galveston RNG facility, $6.4 million for the Coastal Plains RNG facility, and $9.8 million for the Apex RNG facility. Our net cash flows used in financing activities of $27.5 million for 2019 increased by $61.8 million (180.4%) compared to 2018, primarily due to lower borrowings in 2019. 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 2019 as compared to $11.8 million in 2018. Higher debt issuance costs in the prior year period related to closing of the Amended Credit Agreement.

For the nine months ended September 30, 2020, we generated $21.9 million of cash from operating activities, a 1.3% increase from the prior comparative period primarily due to the receipt of insurance proceeds related to the McCarty engine failure of $3.4 million. The proceeds reimbursed the Company for the lost operating profit during the period of reduced production. Without the receipt of these insurance proceeds, cash from operating activities for the nine months ended September 30, 2020 would have decreased $3.0 million compared to the nine months ended September 30, 2019. This decrease would have been driven primarily from reduced commodity and attribute index pricing which negatively impacted operating profit. Our net cash flows

 

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used in investing activities has historically focused on project development and facility maintenance. For the nine months ended September 30, 2020, our capital expenditures were $14.2 million, of which $4.6 million, $4.1 million and $2.0 million related to the construction of our Coastal Plains, McCarty, and Pico RNG facilities, respectively. For the nine months ended September 30, 2019, our capital expenditures were $33.6 million, of which $9.8 million related to the construction of the Coastal Plains RNG facility, $9.0 million for the Galveston RNG facility, $6.4 million for the Pico RNG facility, and $1.7 for the Apex RNG facility. Our net cash flows provided by financing activities of $1.0 million for the nine months ended September 30, 2020 increased by $42.0 million (102.4%) compared to $41.0 million of cash flows used in financing activities the nine months ended September 30, 2019, primarily due to borrowing and repayment activities associated with the September 2019 amendment to our Amended Credit Agreement.

Contractual Obligations and Commitments

The following table summarizes our outstanding contractual obligations as of December 31, 2019 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
 
     (in thousands)  

Long-term debt (1)

   $ 66,566      $ 9,310      $ 19,140      $ 38,116      $ —    

Operating lease obligations (2)

     856        301        527        28        —    

Minimum obligation under gas rights agreements (3)

     57,500        3,408        10,224        10,224        33,644  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total (4) (5)

   $ 124,922      $ 13,019      $ 29,891      $ 48,368      $ 33,644  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(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 $5.9 million. See Note 10, “Asset Retirement Obligations” to our audited 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 financial statements to meet the requirements of this offering, we determined a material weakness in our internal control over financial reporting existed during 2019 and remained unremediated as of September 30, 2020. See “Risk Factors-Emerging Growth Company Risks-We have identified a material weakness in our internal control over financial reporting. If we are unable to remediate this material weakness, or 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.

 

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Revenue Recognition

The Financial Accounting Standards Board (“FASB”) issued Revenue from Contracts with Customers (“ASC 606”) superseding virtually all existing revenue recognition guidance. We adopted this new standard in the first quarter of 2018 using the modified retrospective approach. Revenue from our point in time product sales continue to be recognized when products are shipped or services are invoiced. Revenue from our product and service sales provided under long-term agreements is recognized as we transfer control of the product or renders service to its customers, which approximates the time when the customer is invoiced. The adoption of ASC 606 had no material effect on our financial position, results of operations, or cash flows, and no adjustment to January 1, 2018 opening retained earnings was needed.

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 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.

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.

 

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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 deferred tax assets are a result of NOLs, the difference between book and tax basis in property, plant, and equipment 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 15, “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 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

 

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circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results, including considering project specific assumptions for long-term credit prices, escalated future project operating costs and expected site operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, (ii) third-party valuations, and/or (iii) information available regarding the current market value for such assets. We use our best estimates in making these evaluations and consider various factors, including future pricing and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates and the impact of such variations could be material.

We recorded impairment of $2.4 million and $0.9 million for the years ended December 31, 2019 and 2018, respectively. See Note 4, “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 2019, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $7.6 million. During 2018, we did not have off-balance sheet arrangements other than outstanding letters of credit and operating leases of approximately $8.3 million and $0.4 million, respectively.

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 the risks related to 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.

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.

 

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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 2020 estimated D3 RIN Index price of approximately $1.35 and our actual 2019 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 $4.0 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 2018 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 2020 estimated NYMEX average Index Price of approximately $2.10/MMBtu and our actual 2019 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 $0.6 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, 2019, we had $65.6 million outstanding under the Amended Credit Facility. Our weighted average interest rate on variable debt balances during 2019 was approximately 3.76%. 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.

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

 

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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.

 

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INDUSTRY OVERVIEW

This section includes market and industry data that we have developed from publicly available information; various industry publications and other published industry sources and our internal data and estimates. Although we believe the publications and reports are reliable, we have not independently verified the data. Our internal data, estimates and forecasts are based upon information obtained from trade and business organizations and other contacts in the market in which we operate and our management’s understanding of industry conditions.

Biogas

Biogas is naturally produced from the decomposition of organic waste in the absence of oxygen. Biogas can be collected and processed for use as RNG (a form of high-Btu fuel), electricity, or boiler heat (a form of medium-Btu fuel). RNG has the same applications as natural gas produced from fossil fuels and can serve as a replacement for pipeline-quality natural gas. Common sources of biogas include landfills, livestock waste and WRRFs.

Biogas is produced from anaerobic digestion either as LFG or as ADG. An anaerobic digester is an airtight tank that creates an oxygen-free environment to enable the breakdown of organic matter and other products into usable products such as biogas.

Methane is the primary component of biogas and natural gas, though the composition of biogas varies depending upon the source and anaerobic conditions. Methane from the decomposition of organic matter in landfills or in digesters from livestock waste and WRRFs can be harvested to produce RNG. Methane is one of the main GHGs, in addition to carbon dioxide and nitrous oxide, and accounts for roughly 9.5 % of all GHG emissions in the United States according to the EPA. Furthermore, methane is a more potent GHG with a global warming potential about 25 times more powerful than that of carbon dioxide according to the EPA. The main sources of methane emissions in the United States include the production and transport of coal, natural gas and petroleum systems, livestock waste and other agricultural practices, and landfills, as outlined in the chart below. Biogas processing facilities can play a key role in reducing methane emissions produced by landfills and livestock waste, which together accounted for 27% of U.S. methane emissions in 2018.

Sources of U.S. Methane Emissions

 

2018 U.S. Methane Emissions, By Source

 

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Source: EPA

LFG typically has methane concentrations around 50% while biogas sourced from manure and processed in an anaerobic digester commonly has methane concentrations as high as 55% to 75%. Biogas can replace natural gas in almost any application, but first it must be processed to remove non-methane compounds. The level of processing varies depending on the source of the biogas and the final application of the RNG.

 

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Advantages of Biogas as a Source of Renewable Energy

Due to low feedstock cost and natural production, LFG and ADG are likely to be more economical than ethanol or biodiesel in the renewable fuel market according to the Energy Information Administration (“EIA”). Unlike intermittent forms of renewable energy, such as wind and solar, electricity produced from LFG or ADG is a baseload resource that generally can run 24 hours a day, seven days a week. Gas flows continuously from landfills and anaerobic digesters, which enables LFG and ADG projects to typically have capacity factors between 79% and 98%. In comparison, wind and solar had capacity factors of 35% and 25% in 2019, respectively, according to the EIA. Capacity factor is the ratio between what the project is capable of generating at maximum output versus the project’s actual generation output over a period of time.

Biogas Pathways to Renewable Energy

 

 

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RNG

Overview

Biogas can be processed into RNG through treatment processes that reduce the presence of moisture, contaminates, and other gases such as carbon dioxide, hydrogen sulfide and oxygen. Post-processing, RNG has the same chemical composition as fossil fuel based natural gas. RNG can be transported and distributed via existing natural gas pipeline infrastructure, providing natural gas customers access to RNG while requiring no extra capital outlay from the customer or the transmission supplies. RNG can be injected into natural gas pipelines for use as a transportation fuel or for fueling combustion equipment. In the case of transportation fuel, RNG is used to produce the equivalent of CNG and LNG. While RNG can be blended with traditional natural gas for any purpose that natural gas alone can be used, the sale of RNG for end-use as a transportation industry fuel offers a distinct economic benefit driven by government incentives under the RFS program and state-level carbon reduction initiatives.

Environmental Attributes of RNG

The RFS program is a federal program administered by the EPA requiring transportation fuel sold in the United States to contain a minimum volume of renewable fuel. Under the RFS program, refiners and importers of gasoline or diesel fuel are obligated to blend renewable fuels into transportation fuel to meet an EPA-specified RVO, which is based on the Clean Air Act (“CAA”) volume requirements and projections of gasoline and diesel production for the coming year. The original RFS program was created by the Energy Policy Act of 2005 (“EPACT 2005”). In 2007, EISA created the RIN to track compliance by gasoline and diesel refiners and

 

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importers, also known as Obligated Parties, with the RFS. RINs are generated when eligible renewable fuels are produced or imported and blended with a petroleum product for use as a transportation fuel. Obligated Parties can evidence their compliance with the RFS by either blending RNG into their existing fuel supply or purchasing RINs. RINs can be sold along with the physical volume of RNG or purchased separately in the market. If RINs are not sold in the year they were generated, they can be saved (“banked”) for compliance in the following year. Note that EPA generated RIN price data quotes a RIN price as of the date of the contract, unlike price data provided by certain industry subscription services, which quote the EPA Moderated Transaction System transfer date price.

The RFS program was expanded under the EISA to require 36 billion gallons of renewable fuel blended into gasoline or diesel by 2022 of which 16 billion gallons must be cellulosic biofuel. A cellulosic biofuel must be produced from cellulose, hemicelluloses, or lignin and must meet a 60% lifecycle GHG reduction. In 2014, the EPA ruled that RNG produced from landfills, municipal WRRF digesters, agricultural digesters and separated Municipal Solid Waste (“MSW”) digesters would qualify as a biofuel under the cellulosic and advanced fuel pathways of the RFS. This action made RNG, when used as transportation fuel, eligible for D3 RINs.

In addition to federal incentives for RNG production through RINs, some states offer additional incentives for the production and sale of RNG. For example, RNG falls under CA LCFS, which uses a market-based cap and trade approach aiming to lower GHG emissions from fossil fuels. CA LCFS requires producers of petroleum-based fuels to reduce the CI of their products, beginning with a quarter of a percent in 2011, culminating in a 10% total reduction in 2020 and a 2030 target of 20% emissions reductions below 1990 levels. 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 RNG.

CARB awards CA LCFS credits to sources of low-carbon transportation fuels based on the CI score of the project pathway relative to CARB’s annual CI benchmark for gasoline, diesel and jet fuels. The CI score represents the overall net impact on carbon emissions to the environment for each low-carbon fuel pathway and is determined on a project by project basis taking into account the location and other project and operational specific factors that affect the project’s carbon emissions. The amount of CA LCFS credits awarded to each pathway is based on the differential between the pathway’s CI score and CARB annual CI benchmark, divided by the fuel’s Energy Economy Ratio (“EER”). CARB assigns a temporary pathway CI score to new pathways that have not yet obtained a CI score. The current CARB temporary pathway CI score for biomethane produced from livestock waste is -150 gCO2e/MJ, however, operating livestock waste biomethane projects have received approved modeled CI scores up to -532.74 gCO2e/MJ. As shown below, the net impact of carbon emissions from livestock ADG operations is negative due to the capturing and removal of carbon dioxide in the biomethane conversion process that would otherwise be released into the atmosphere. Thus, based on 2020 CI targets and average CA LCFS price per credit, the production of livestock waste biomethane earns a substantially larger amount of CA LCFS credits relative to other pathways. We anticipate that our livestock waste RNG projects could potentially earn two to three times the amount of revenue per MMBtu in credits relative to LFG based on our expected CI scores.

CA LCFS Value Breakdown by Registered Pathways

 

     2020 CARB
CI Diesel
Benchmark
     CI (gCO2e/MJ)     

CA LCFS

Differential

     2020
Average CA
LCFS Price
per Credit
     Est. Revenue per
MMBtu (3)
 

Livestock Waste

     92.92        (150.0) (1)        242.92      $ 198.9      $ 44.27  

Landfills

     92.92                60.4 (2)        32.52      $ 198.9      $ 4.40  

Source: CARB

 

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(1)

Represents the temporary CI score assigned by CARB because our Pico pathway(s) have not been assigned CI scores by CARB.

(2)

Represents the average CI score for all of our current LFG pathways, other than Atascocita, Coastal and Galveston, which have not been assigned CI scores.

(3)

Estimated revenue per MMBtu is calculated by dividing the value of our estimated CA LCFS credit awards by estimated pathway production.

RNG Use in Transportation Fuels

The growing use of natural gas as a transportation fuel further supports demand for RNG. Momentum in the use of natural gas as a transportation fuel has continued to develop since the mid-2000s. Under EPACT 2005, federal tax credits were provided through 2013 to help stimulate the shift of trucks and buses from diesel to natural gas fuel by covering up to 80% of the incremental costs of these new natural gas powered vehicles. A portion of the costs of new refueling infrastructure was also covered. The Transportation Equity Act enacted that same year included an excise tax credit encouraging the fuel shift further by making alternative fuels cheaper than petroleum-derived fuels for retailers and non-profit fuel purchasers. The use of natural gas as a vehicle fuel grew by over 70% between 2013 and 2019, according to the Natural Gas Vehicle Association, from approximately 237 to 404 million gallons of gasoline equivalents.

The shift towards adoption of low-carbon transportation fuels is also expected to remain a key driving factor for the global CNG market. CNG emerged as a substitute transportation fuel for gasoline, diesel and liquefied petroleum gas on account of its lower emission of GHG emissions on combustion. CNG can be used in traditional internal combustion engines that were originally designed for gasoline/diesel, but have been modified for CNG use, which has further propelled adoption of CNG vehicles.

According to the EIA, use of CNG transportation fuel in the United States grew at a five-year compound annual growth rate (“CAGR”) of 7.7% between 2014 and 2019. Globally, the CNG market is forecasted to grow at a 11.4% CAGR from 2019 to 2025, to a total market size of $46.6 billion by the end of 2025 according to the EIA. Though exploration of shale gas and other non-conventional sources of energy have brought down global CNG prices, increasing government regulation of fossil fuels due to environmental concerns is expected to positively impact the continued growth of the global CNG market.

LFG Fundamentals

LFG is a long-term baseload renewable energy resource that is an environmentally sound alternative to fossil fuels. The EPA endorses LFG as a renewable energy resource in the same category as wind, solar and geothermal resources. In addition to qualifying as a cellulosic biofuel under the RFS program, LFG is also recognized as a renewable resource by each state with an RPS.

Landfills are the main form of solid waste management in the United States. A landfill is an engineered excavation into which solid waste is placed. Solid waste landfills are constructed and operated on land with engineering safeguards and have highly regulated operating procedures that limit the possibility of water and air pollution. A landfill must meet federal, state and local regulations during its design, construction, operation and closure. The operation and closure activities of a solid waste landfill include excavation, construction of liners, continuous spreading and compacting of waste, covering of waste with earth or other acceptable material and constructing the final capping of the landfill. A landfill is divided into compaction areas, or cells, where solid waste is deposited within the landfill. After a cell is filled, it is compacted by heavy equipment, covered permanently with a polyethylene cap and then covered with soil. These operations are carefully planned to maintain environmentally safe conditions and to maximize the use of the space. Given the high level of planning and coordination involved in these operations, landfill owners typically seek to partner closely with LFG project operators with known track records and experience, creating barriers to entry for many new LFG developers without a known track record.

 

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LFG is produced naturally as waste decomposes in a landfill. The decomposition of organic material in landfills occurs under conditions where oxygen is absent (anaerobic). LFG contains roughly 50% methane and 50% carbon dioxide, with less than 1% non-methane organic compounds and trace amounts of inorganic compounds. When waste is first deposited in a landfill, it undergoes an aerobic decomposition stage during which little methane is generated. Then, typically within less than one year, anaerobic conditions are established and methane-producing bacteria decompose the waste and produce methane and carbon dioxide.

EPA regulations under the CAA require many larger landfills to collect and control LFG in order to minimize the environmental impact, though typically collection begins much sooner than required to maximize gas recovery while controlling odors. An LFG collection system consists of a series of pipes that are embedded in the landfill. A vacuum induction system is used to transport the gas to a collection facility. Subsequently, the gas is either transported to be flared or sent to an energy recovery system. Using LFG in an energy recovery system requires some treatment to remove excess moisture, particulates and other impurities. The type and extent of treatment depends on site-specific characteristics and the type of energy recovery system employed.

According to the EPA, landfills continue to produce LFG for as many as 20 to 30 years after being capped. The amount of gas produced generally increases for up to five to seven years after the waste has been buried, at which time the gas volume begins to gradually decline. Using certain parameters, production history and other statistical information for a given site, engineers can predict the estimated quantity of LFG that a landfill is expected to generate over time. As a result, LFG can provide a more steady, predictable and reliable source of energy relative to other intermittent renewable energy production methods, such as solar and wind. Capturing LFG and using it as an energy resource produces significant energy, environmental, economic and other benefits.

Overview of the LFG Industry

LFG is a reliable, renewable fuel option that remains untapped at many landfills across the United States. The LFG industry has grown rapidly over the last 30 years driven both by EPA regulations and the inclusion of LFG into renewable energy programs. According to the EPA, in 1982 there were only three known LFG projects in the United States. By 1990, the number of LFG projects had increased to 32. According to the EPA, as of August 2020, there were 565 LFG projects in operation in the United States, including 67 RNG projects, 399 operating LFG-to-energy electricity projects and 99 direct-use projects. While historically most LFG projects were used to produce electricity, more recent development has favored RNG facilities (where gas is typically used in industry applications), given the ability to generate D3 RINs beginning in 2014.

Operational LFG Projects by Type

 

 

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Source: EPA

 

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While the deployment of LFG projects has accelerated, there is still potential growth in the industry. The EPA has identified 477 landfills as candidate sites, meaning they meet high-level criteria for LFG project suitability and could have their gas turned into an energy source. In addition, there are 399 operating Renewable Electricity projects that have the potential to be converted to produce RNG. 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 the candidate landfills 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.

LFG Projects by State

 

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Source: EPA

The LFG market is heavily fragmented. According to the EPALMOP project database, the top ten players in the LFG industry account for approximately 53% of installed LFG capacity as of August 2020, and over 90% of developers own five or fewer projects. Aside from the top five players in this industry, including us, no company accounts for more than 5% of the total LFG to energy capacity.

The significant regulatory compliance requirements for developing and operating a landfill serve as a barrier to new landfill development and have resulted in a decrease in the number of operating landfills in the United States since 1986 and also in existing landfills becoming larger over time. As of 2019, there were approximately 2,627 Municipal Solid Waste Landfills in the United States. As a result, incumbent LFG operators on operating landfills that have secured long-term fuel supply agreements and established conversion facilities on site are well-positioned to benefit from future growth of existing landfills. These long-term contracts secure access to a steady source of biogas for LFG operators and offer a steady revenue stream in the form of royalties to landfill owners along with helping them to meet regulatory compliance requirements, resulting in a mutually beneficial arrangement.

LFG can be processed to produce pipeline-quality RNG, used to fuel power generation, or delivered by pipeline directly to industrial customers. The economics of an LFG project depend on several factors. Most importantly, RNG projects must have close proximity to off-take infrastructure. LFG-to-energy producers evaluate potential landfills to assess recovery potential, which are dependent on a variety of factors, including

 

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landfill size, age, local precipitation and landfill composition. LFG developers then evaluate the most profitable method of selling their RNG, either for power, pipeline use or direct use in industrial applications. Projects can then be structured in a variety of ways. Typically, the landfill owner operates the wellfield and the LFG operator obtains control at the gas inlet meter to the processing facility. We operate the wellfield collection system at five of our sites, which allows greater control over the quality and consistency of the collected biogas.

Under EPA standards, RNG qualifies as a renewable fuel resource and is therefore eligible for RINs when sold for end-use in the transportation fuel industry. Thus, LFG projects that produce RNG benefit from two revenue streams. The first revenue stream is from the commodity value of the natural gas generated by selling the RNG into the pipeline at market pricing. The second revenue stream is from the Environmental Attributes of RNG which are generated by the registration of a RIN once the RNG is used as a transportation fuel. Additionally, RNG generates revenue when used as a transportation fuel in states with LCFS programs. Since the 2014 EPA ruling that designated RNG produced from LFG facilities as a cellulosic biofuel and eligible for D3 RINs, development of new LFG facilities has trended towards RNG production over electricity production. While LFG-to-RNG facilities have grown at a five-year CAGR of 14.6% from 2014 to 2019, LFG-to-electricity facilities have grown at a 2.9% CAGR.

Historical Growth LFG-to-Electricity and LFG-to-RNG Projects

 

Historical Electric and RNG Project Growth

 

The number of RNG projects in the U.S. has grown at a 14.6% CAGR since 2014

 

 

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Source: EPA

Anaerobic Digester Fundamentals

Anaerobic digestion is a series of biological processes in which microorganisms break down organic matter in the absence of oxygen, which results in ADG. A range of anaerobic digestion technologies are converting livestock waste, municipal wastewater solids, food waste, high strength industrial wastewater and residuals, fats, oils and grease and various other organic waste streams into ADG. Currently, we are focused primarily on developing RNG from LFG and livestock waste due to the positive economics of cellulosic RINs under the RFS program which enables the generation of D3 RINs from our operations.

In order to generate RNG from livestock waste, manure from dairy cows, pigs or other livestock is collected and either flushed or scraped into an anaerobic digester resulting in the production of ADG. Captured biogas is transported via pipe from the digester, either directly to a gas use device or to a gas treatment system for moisture and hydrogen sulfide removal. Captured ADG can be further upgraded by removing carbon dioxide, nitrogen and oxygen to increase purity to meet requirements for pipeline injection. The ADG is then delivered into a processing plant where it is refined to meet the fuel quality standards of pipeline-quality natural gas.

 

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Separated digested solids can be composted, utilized for dairy bedding, directly applied to cropland or converted into other products. Nutrients in the liquid stream are used in agriculture as fertilizer.

There are several types of digesters. A digester can be wet, which means it processes feedstock with less than 15% solids content, whereas a dry digester processes 15% or more solids content. Certain digesters can only process one type of feedstock and other digesters are designed to process multiple feedstocks. Furthermore, in a batch digester, feedstock can be loaded into a digester all at once, whereas in a continuous flow digester, feedstocks are constantly fed into the digester and digested material is continuously removed. Standalone digesters process feedstock from one or more sources for a tipping fee, which is a fee paid by anyone disposing of waste at a landfill, where the primary feedstock is typically food waste. Digesters help farmers manage nutrients, reduce odors and generate additional revenue. Dairy, swine and poultry farms are the primary candidates for digesters given their significant production of livestock waste.

In addition to its economic potential, the increased use of anaerobic digesters has several environmental benefits. Anaerobically digested livestock waste produces significantly less odor than conventional storage and land application systems. The odor of stored livestock waste mainly comes from volatile organic acids and hydrogen sulfide, which has a “rotten egg” smell. In an anaerobic digester, volatile organic compounds are reduced to methane and carbon dioxide, which are odorless gases. The volatized fraction of hydrogen sulfide is captured with the collected ADG and destroyed.

Anaerobic digestion provides several water quality and land conservation benefits as well. Digesters, particularly heated digesters, can destroy more than 90% of disease-causing bacteria that might otherwise enter surface waters and pose a risk to human and animal health. Digesters also reduce biochemical oxygen demand (“BOD”). BOD is one measure of the potential for organic wastes to reduce dissolved oxygen in natural waters. Because fish and other aquatic organisms need minimum levels of dissolved oxygen for survival, farm practices that reduce BOD protect the health of aquatic ecosystems. In addition to protecting local water resources, implementing anaerobic digesters on livestock facilities improves soil health. The addition of digestate to soil increases the organic matter content, reduces the need for chemical fertilizers, improves plant growth and alleviates soil compaction. In addition, digestion converts nutrients in manure to a more accessible form for plants to use. The risks of water and soil contamination from flooding of open lagoons are also mitigated by digesters.

Digesters also significantly reduce emissions of GHG that are harmful to the environment. In 2018, the EPA estimated that livestock waste management was responsible for approximately 10% of annual U.S. methane emissions; the majority of those methane emissions came from dairy and swine operations. ADG recovery systems could capture and process methane, significantly reducing methane emissions. The use of ADG to generate energy can also offset fossil fuel use, which in turn lowers emissions of carbon dioxide, another critical GHG.

Overview of Anaerobic Digester Industry

The feasibility of anaerobic digestion projects varies state-to-state; however, advances in technological application and favorable legislative developments are driving investment interest in the space. As of January 2019, there were 255 anaerobic livestock digester systems in the United States operating on commercial livestock facilities, a portion of which could meet our criteria for future RNG projects.

While a large portion of RNG today in the United States is produced at landfills, the market to produce ADG using livestock waste from dairy and swine farms is almost entirely untapped, according to the American Biogas Council.

The dairy RNG market is highly concentrated in a few key states. The top ten states for dairy RNG represent roughly 79% of the market, while the top three states (California, Idaho, and Wisconsin) represent 62% of this share of the market and California alone holds 38% of this share.

 

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Potential Livestock RNG Market

RNG created by anaerobic digestion of livestock waste is among the lowest-carbon intensive transportation fuel options available today achieving up to a 91% reduction compared to petroleum gasoline. Nationwide, “manure management” —field spreading for fertilizer, storage in ponds, among others—is a major source of methane emissions, contributing to over 60 million metric tons of carbon dioxide equivalent (“CO2E”) annually or roughly 10% of total U.S. annual methane emissions according to the EPA.

Wastewater is another significant potential source of RNG. Over 1,200 WRRFs have anaerobic digesters according to the EPA. Food processing plants, resorts, universities and supermarkets are also other potential sites that produce significant volumes of organics that can be collected to put in anaerobic digesters.

Regulatory Incentives for RNG Production

The production and use of RNG as a transportation fuel generates additional revenue through the sale of Environmental Attributes under the EPA’s RFS program and state-level low-carbon initiatives. There are several federal and state-level programs that have historically incentivized the conversion of biogas from landfills and other waste sources into RNG and Renewable Electricity, including programs like RFS and LCFS for RNG production, and RPS for Renewable Electricity. Existing air quality laws and RPS targets are also regulatory drivers that incentivize the development of LFG projects.

RFS Program

The EPA administers the RFS program with volume requirements for several categories of renewable fuels. The EPA first issued regulations implementing the RFS program in 2007, which established rules for fuel supplied and created the RIN system for compliance and trading credits and rules for waivers. The EPA calculates a blending standard for each year based on estimates of gasoline usage from the EIA. Separate quotas and blending requirements are determined for cellulosic biofuels, biomass-based diesel (“BBD”), advanced biofuels and total renewable fuel.

The individual obligations for producers are called RVO. An RVO is determined by multiplying the output of the producer by the EPA’s announced blending ratios for cellulosic biofuels, bio-mass based diesel, advanced biofuels and total renewable fuel. In order to comply with the RFS, diesel and gasoline refiners and importers either blend renewable fuels into the U.S. supply of transportation fuel or buy renewable fuel credits to meet the minimum percentage of renewable fuel production annually under the RVO. The EPA has historically published an RVO target each November for the amount of renewable fuel gallons for the following year. The 2019 RVO for D3 RINs was 418 million gallons. The 2020 RVO for D3 RINs was 590 million gallons, representing a 41% increase over 2019. As the RVO determines the level of RNG that must be in the motor fuel mix in any given year, the RVO sets the demand for RINs, which in effect causes it to have a material effect on RIN pricing. As the RVO increases, a greater number of RINs must be purchased by Obligated Parties, which in turn drives demand for and pricing of RINs. The EPA is expected to promulgate final 2021 RVOs by June 2021.

For every gallon equivalent of renewable fuel created, a RIN is issued to the producer which can then be sold to an Obligated Party (such as a fuel refiner). Cellulosic or D3 RINs can be generated by RNG produced through the conversion of organic matter and used as renewable fuel including LFG, ADG and sewage waste treatment. One MMBtu of renewable fuel represents approximately 11.7 RINs. RINs create an additional revenue stream for the developers of RNG assets as they provide an additional cash revenue stream with no additional capital.

 

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The below table lists the various types of RNG recognized by the EPA and the corresponding RIN compliance categories.

Sources of RNG and RIN Compliance

 

RNG Source   RNG Type   GHG Savings %  

 

RIN Compliance

Eligibility

 

     

 

Landfill Gas

 

 

Cellulosic Biofuel

 

 

60%

 

 

D3, D5, D6

 

Dairy I Swine Farms

 

 

Cellulosic Biofuel

 

 

60%

 

 

D3, D5, D6

             

 

Waste Water

 

 

Cellulosic Biofuel

 

 

60%

 

 

D3, D5, D6

 

Soybean I Canola I Waste Oil or Animal Fats

 

 

Biomass-Based Diesel

 

 

50%

 

 

D4, D5, D6

 

Sugar-Cane Based Ethanol

 

 

Advanced Biofuel

 

 

50%

 

 

D5, D6

 

Corn-Based Ethanol

 

 

Renewable Fuel

 

 

20%

 

 

D6

Source: EPA

RIN compliance is nested, such that cellulosic biofuel and BBD are part of the advanced mandate, and the advanced mandate is part of the renewable mandate. Cellulosic biofuel is further subdivided into “cellulosic biofuel” and “cellulosic diesel”; with both types counting towards the cellulosic mandate, and cellulosic diesel also counts towards the BBD mandate.

Historical Pricing of D3 and D5 RINs, Wholesale Gasoline Prices, and the CWC

 

Historical D3, D5, and U.S. Wholesale Gas Pricing     Historical CWC Pricing
LOGO     LOGO

 

D3 = D5 + CWC – Market Discount

Source: EPA and EIA

Production of cellulosic biofuels has not developed at the pace envisioned in the RFS program, creating a shortage of supply of cellulosic D3 RINs to meet blending requirements. When production volumes do not

 

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meet mandated volume obligations, instead of blending cellulosic biofuel, the EPA allows Obligated Parties to satisfy the RFS compliance obligation through the purchase of CWCs plus D5 RINs or the sole purchase of D3 RINs. D3 RIN prices are therefore a derivative of D5 RINs and CWCs with the D3 RIN price equal to the D5 RIN Price plus the CWC less a market discount. CWC prices are set annually as the greater of (i) $0.25 or (ii) $3.00 (as adjusted by the 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 and 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. Given that the CWC price is fixed by statutory formula in advance of each calendar year, D3 RIN price changes are determined by fluctuations in D5 RIN prices or changes in the market discount.

Annual Average RNG Price per MMBtu

 

Annual Average RNG Price per MMBtu

 

 

LOGO

Source: EPA

USDA Advanced Biofuel Payment Program

Through the Bioenergy Program for Advanced Biofuels, the U.S. Department of Agriculture sponsors the Advanced Biofuel Payment Program, which makes payments to eligible producers of advanced biofuels to support and ensure an expanding production of advanced biofuels. The Advanced Biofuel Payment Program provides quarterly payments based on actual production volumes. The amounts paid to individual producers depends on the number of producers, the amount of advanced biofuel produced and the amount of funds available during the fiscal year. $7.0 million per year has been set aside for 2019 through 2023. There is no minimum or maximum payment established for the program. Any entity that produces and sells advanced biofuel is eligible to apply.

State Low-Carbon Initiatives

In addition to federal incentives for RNG production through RINs, some states offer incentives for the production and sale of RNG.

California LCFS

Established in 2009, the CA LCFS is the first state-level low-carbon initiative aimed at encouraging the use and production of low-carbon fuels in order to reduce GHG emissions. The CA LCFS 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% reduction from 2010 levels 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.

 

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CA LCFS CI Compliance Standards for Diesel and Gasoline

 

CA LCFS Compliance Standards (gCO2/MJ)

 

Year    Diesel    Gasoline

 

2016

   99.97    96.50

2017

   98.44    95.02

2018

   96.91    93.55

2019

   94.17    93.23

2020

   92.92    91.98

Source: CARB

Under the CA LCFS, various low-carbon transportation fuel pathways, using feedstocks such as LFG, ADG, and wastewater, receive approved modeled CI scores by CARB based on the level of GHG emissions across the lifecycle of conversion to a low-carbon fuel (i.e. biomethane). The lifecycle includes the processing, production, transportation, and use of the pathway as biomethane. The number of CA LCFS credits received for the use of a certain pathway is calculated by taking the difference between the pathway’s CI score and CARB annual CI benchmark for gasoline or diesel (depending on the end use of the fuel), and dividing by the EER. Revenue from the CA LCFS program is based on the number of credits received for the use of a certain pathway as a low-carbon transportation fuel and the then-current CA LCFS trading price. Based on 2020 CI targets and average CA LCFS price per credit, the production of biomethane earns a substantially large amount of LCFS credits relative to other pathways. We anticipate that our livestock waste projects could potentially earn two to three times the amount of revenue per MMBtu relative to our LFG projects based on our expected CI scores.

Historical Monthly CA LCFS Credit Transfer Pricing

 

Historical LCFS Trading Price

 

LOGO

Source: CARB

 

(1)

Price performance measures the increase in the annual average CARB LCFS credit price between 2020 and the historical time periods indicated.

On September 23, 2020, the California Governor issued an Executive Order N-79-20 setting goals for expanding the sale and use of zero-emission vehicles within California, including 100% of in-state sales of new passenger cars and trucks to be zero-emission by 2035, and 100% of medium-, and heavy-duty truck vehicles in California to be zero-emission by 2045 for all operations where feasible. The Governor also directed CARB to develop and propose regulations to achieve these goals consistent with state and federal law. This order is the latest in a series of targets set by California to transform the energy and transportation fuel sectors and reduce GHG emissions. In September 2018, the state enacted Senate Bill 100, setting a statewide target for 100% of all retail sales of electricity to California end-use customers to be supplied from eligible renewable energy and

 

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zero-carbon resources by 2045. Executive Order B55-18 sets a statewide target to achieve carbon neutrality no later than 2045. The transitioning of California’s energy markets to increased reliance on renewable and carbon-free sources has the potential to create favorable market conditions for RNG. Future regulatory actions will be required to meet the state’s zero-emission and carbon neutrality targets. Additional incentive programs or mandates, if adopted, could create favorable market conditions or additional revenue streams to biogas projects that produce electricity from biogas.

Other Low-Carbon Initiatives

In 2009, the State of Oregon passed legislation to adopt its Clean Fuels Program (“CFP”), which requires a 10% reduction in average CI from 2015 levels by 2025. The program was fully implemented beginning in 2016. In March 2020, Oregon’s Governor signed Executive Order No. 20-04, directing the Oregon Department of Environmental Quality (“DEQ”) to amend the CFP target to a 20% reduction in average CI from 2015 levels by 2025 and a 25% reduction below 2015 levels by 2030. DEQ rulemaking in response to the executive order has been delayed by a lawsuit challenging the executive order. As of December 2018, California and Oregon were the only two states that had passed low-carbon initiatives related to RNG though several other states have been exploring the adoption of similar programs and are expected to pass legislation for implementation over the next several years.

To meet the mandates of the 2019 Climate Leadership and Community Protection Act, New York must reduce its GHG emissions from the transportation sector, the state’s largest source of emissions. Various stakeholders have advocated for the state to adopt a LCFS similar to California and Oregon and have supported proposals to require a 20% reduction in CI by 2030.

In 2018, a coalition of nine Northeast and Mid-Atlantic states and the District of Columbia announced their intention to create a program aimed at reducing GHG emissions from transportation fuels. These states and district are all members of the Transportation & Climate Initiative of the Northeast and Mid-Atlantic States (“TCI”), which is facilitating the development of this program. The participating TCI jurisdictions designed a regional low-carbon transportation policy proposal that proposes to cap and reduce carbon emissions from the combustion of transportation fuels through a cap-and-invest program or other pricing mechanism, and allow each TCI jurisdiction to invest proceeds from the program into low-carbon and more resilient transportation infrastructure. After the coalition solicited feedback on a draft memorandum of understanding, the final memorandum of understanding is expected to be complete in the fall of 2020, at which point each TCI jurisdiction is expected to decide whether to participate in the program.

Updates to the RPS Volume Standards

With many states looking to increase renewable energy capacity rapidly to meet increasingly stringent RPS targets, there has been heightened interest in the development of LFG facilities. In light of LFG’s low development costs and ability to reliably produce as a baseload form of generation, it presents an attractive option for states interested in supporting both the environment and the stability of their electricity grid.

U.S. state RPS and renewable portfolio targets have been a key driver of growth in the Renewable Electricity industry. As of July 2018, 30 states, the District of Columbia, and Puerto Rico have RPS in place, and seven other states have non-binding goals supporting renewable energy. RPS are enacted through the RECs, which is a commodity traded in MWh, representing the environmental and other non-power attributes of Renewable Electricity generation. RECs provide a significant revenue stream for renewable energy producers. Of the ten states with the largest number of operational LFG projects, eight have RPS and two have voluntary or targeted RPS. LFG projects’ high capacity factors also mean greater revenue from RECs per unit of capacity than renewables with lower capacity factors such as wind and solar.

 

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RFS Program Volume Standards

On December 9, 2019, the EPA finalized volume requirements under the RFS program for cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel for 2020. The volume requirements are listed in the table below.

Renewable Fuel Volume Requirements for 2019-2020

 

    

 

2019

 

  

 

2020

 

 

  Cellulosic Biofuel (mm gallons)

 

   418

 

   590

 

 

  Biomass-based Diesel (bn gallons)

 

   2.1

 

   2.43

 

 

  Advanced Biofuel (bn gallons)

 

   4.92

 

   5.09

 

 

  Renewable Fuel (bn gallons)

 

   19.92

 

   20.09

 

 

  Implied Conventional Biofuel (bn gallons)

   15    15

Source: EPA

The RFS program sets forth renewable fuel volumes through 2022 with volumes for subsequent years to be established under a new framework. Historically, the RNG industry has been unable to meet statutory mandates for cellulosic biofuel. When mandated cellulosic biofuel volumes cannot be met, the statute requires that the EPA reduce the annual volume requirement to an amount equal to the amount projected to be available during that calendar year. As permitted under the statute, the EPA reduces the required volume of cellulosic biofuel by allowing refineries and importers of transportation fuel to purchase CWCs to satisfy their RFS obligations through a waiver.

Under the statutory provisions governing the RFS program, the EPA is required to modify, or “reset”, the applicable annual volume targets specified in the statute for future years if waivers of those volumes in past years met certain specified thresholds.

For the years after 2022, required volumes of each renewable fuel will be determined by the EPA administrator in coordination with the Secretary of Energy and the Secretary of Agriculture. Although the framework for setting renewable fuel volumes will change, the mandate for cellulosic biofuel is required to be at least the same as it was in 2022 and “shall be based on the assumption that the EPA will not need to issue a waiver for such years.” Under this new framework, RFS volumes are to be established no later than 14 months before the first year for which applicable volumes will apply and the EPA, in coordination with the aforementioned government agencies, will consider the following six factors to renewable fuel volumes:

 

  1.

The impact of the production and use of renewable fuels on the environment, including on air quality, climate change, conversion of wetlands, ecosystems, wildlife habitat, water quality and water supply;

 

  2.

The impact of renewable fuels on the energy security of the United States;

 

  3.

The expected annual rate of future commercial production of renewable fuels, including advanced biofuels in each category (D3 cellulosic biofuel and BBD);

 

  4.

The impact of renewable fuels on the infrastructure of the Unites States, including deliverability of materials, goods and products other than renewable fuel, and the sufficiency of infrastructure to deliver and use renewable fuel;

 

  5.

The impact of the use of renewable fuels on the cost to consumers of transportation fuel and on the cost to transport goods; and

 

  6.

The impact of the use of renewable fuels on other factors, including job creation, the price and supply of agricultural commodities, rural economic development, and food prices.

 

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BUSINESS

Our Company

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. Having participated in the industry for over 30 years, we are one of the largest U.S. producers of RNG. 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 $34.0 million in 2014 to $107.4 million in 2019.

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 providing them 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.

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 end 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

 

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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

 

LOGO

Reorganization Transactions

MNK is a holding company whose ordinary shares are currently traded on the JSE under the symbol “MNK.” Prior to this offering, 100% of MNK’s business and operations were conducted through its U.S. subsidiaries, and, prior to January 4, 2021, Montauk USA and MEH and its subsidiaries, and MNK held no assets other than 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. 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 Reorganization Transactions and this offering, MNK and the existing stockholders of MNK will become stockholders of Montauk. After the Reorganization Transactions and the closing of this offering, MNK will not own any significant assets and we expect that MNK will be delisted from the JSE and liquidated. Accordingly, MNK’s business is the business in which you are investing if you buy shares of our common stock in this offering. For more information, see “The Reorganization Transactions.”

 

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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 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.”

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 the 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

 

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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 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 waste water, 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 2019, our projects generated approximately 15% 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

 

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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 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.

 

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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 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 October 25, 2020, excluding two incidents related to COVID-19, our year-to-date TRIR was 1.11 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 September 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

 

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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 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

 

LOGO

 

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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 94% at our RNG projects and 90% 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 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

 

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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 a RNG production facility with commercial operations that commenced commercial operations 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 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.

 

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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.

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.

 

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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 over 33 million gallons in 2014 and 250.6 million gallons in 2017. 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.

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

 

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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 6 to 23 years, with a weighted average remaining tenure of 15 years, as of March 31, 2020, based on 2020 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 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.

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 projects have an average expected remaining useful life of approximately 14 years, as weighted by 2020 expiration. Our operating electricity projects have an average expected remaining useful life of approximately 15 years, as weighted by 2020 expected expiration.

Approximately 73% of our expected 2020 RNG production has been monetized under fuel supply agreements with expiration dates more than 15 years from September 30, 2020. Additionally, approximately 89% of our expected 2020 Renewable Electricity production has been monetized under fuel supply agreements with expiration dates more than 15 years from September 30, 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

 

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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: 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.

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%.

 

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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 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

 

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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 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 2019, our Renewable Electricity projects collectively produced 236,000 MWh. Our Renewable Electricity projects utilize reciprocating engine generator sets to generate electricity at landfills.

Renewable Electricity Projects

 

Site

  

Location

  

Capacity*

 

Bowerman Power

   Irvine, CA      23.6 MW  

Security

   Cleveland, TX      3.4 MW  

Tulsa/AEL

   Sand Springs, OK        3.2 MW  

Total

        30.2 MW  

 

*

Assumes inlet methane content of 56% and process efficiency of 91%

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.

 

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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 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.

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 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 September 2020.

 

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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.

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 approximately 18,500 milking cows as of October 2020. 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.

 

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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 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
September 30,
2020
     % of
2019 Total
RNG
Production
 

Within 0-5 years

     0        0.0

Between 6-15 years

     3        7.3

Greater than 15 years (1)

     9        92.7

Renewable Electricity Projects

 

Fuel Supply Agreement Expiration Dates

   Current Sites
as of
September 30,
2020
     % of
2019 Total
Renewable
Electricity
Production
 

Within 0-5 years

     0        0.0

Between 6-15 years

     1        7.0

Greater than 15 years (1)

     3        93.0

 

(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

 

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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 expiration 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 2019, our sales to Royal Dutch Shell plc represented approximately 14% 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 BP Products North America each represented approximately 11% of our operating revenues in 2019 from the sale of Environmental Attributes. ACT Fuels, Inc. represented approximately 14% of our operating revenues in 2019 as the largest off-taker of RINs during this period. 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 14.1% of our operating revenues in 2019. 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 expect to convert 100% of the monetization of our Renewable Electricity production and Environmental Attributes to 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 2019 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, pressure swing adsorption (“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.

 

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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.

The biogas market is heavily fragmented. We believe our size relative to many other LFG companies and our expected capital structure upon the completion of this offering will leave 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