OPAL Fuels Inc. [OPAL] Filings

10-K 1 wdq-20231231.htm 10-K wdq-20231231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


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

For the fiscal year ended December 31, 2023


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

For the transition period from _______________ to ____________

Commission file number 001-40272

OPAL FUELS INC.

(Exact name of registrant as specified in its charter)


Delaware						98-1578357
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

One North Lexington Avenue, Suite 1450
White Plains, New York						10601
(Address of principal executive offices)						(Zip Code)

(Registrant's telephone number, including area code): (914) 705-4000

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


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, par value $0.0001 per share	OPAL	The Nasdaq Stock Market LLC

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ☐ No ☒

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

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

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

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


Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☒
		Emerging growth company	☒

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

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

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

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant on June 30, 2023, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $159,858,572 based on the closing price of the registrant's Class A ordinary shares on The Nasdaq Capital Market on that date.

As of March 13, 2024, a total of 28,082,832 shares of Class A common stock, par value $0.0001 per share, 71,500,000 shares of Class B common stock, par value $0.0001 per share and 72,899,037 shares of Class D common stock, par value $0.0001 per share were issued and outstanding.

TABLE OF CONTENTS


PART I		Page
Item 1.	Business	2
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	53
Item 1C.	Cybersecurity	5 3
Item 2.	Properties	54
Item 3.	Legal Proceedings	54
Item 4.	Mine Safety Disclosure	55
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	55
Item 6.	[Reserved]	55
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	56
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	72
Item 8.	Financial Statements and Supplementary Data	73
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	73
Item 9A.	Controls and Procedures	73
Item 9B.	Other Information	74
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	74
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	74
Item 11.	Executive Compensation	74
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	75
Item 13.	Certain Relationships and Related Transactions and Director Independence	75
Item 14.	Principal Accountant Fees and Services	75
PART IV
Item 15.	Exhibit and Financial Statement Schedules	75
	Signatures	80

References in this Annual Report on Form 10-K (this “Form 10-K” or “Annual Report”) to “we,” “us,” “our,” “OPAL Fuels,” “OPAL,” the “Company” and similar terms all refer to OPAL Fuels Inc. and its subsidiaries, unless otherwise stated or the context otherwise requires.

A glossary of terms (the “Glossary”) that should be used as a reference when reading this Annual Report can be found immediately prior to Item 1A.

Capitalized terms that are used in this Annual Report are either defined when they are first used or in the Glossary.

All dollar amounts are stated in United States (“U.S.”) dollars unless otherwise stated.

FORWARD-LOOKING STATEMENTS AND RISK FACTOR SUMMARY

This Form 10-K contains forward-looking statements within the meaning of the federal securities laws. All statements other than statements of historical facts contained in this Annual Report on Form 10-K, including statements regarding our future results of operations or financial condition, business strategy and plans and objectives of management for future operations, are forward-looking statements. Words such as “estimates,” “projected,” “expects,” “estimated,” “anticipates,” “forecasts,” “plans,” “intends,” “believes,” “seeks,” “may,” “will,” “would,” “future,” “propose,” “target,” “goal,” “objective,” “outlook” and variations of these words or similar expressions (or the negative versions of such words or expressions) are intended to identify forward-looking statements. These forward-looking statements are not guarantees of future performance, conditions or results, and involve a number of known and unknown risks, uncertainties, assumptions and other important factors, many of which are outside our control, that could cause actual results or outcomes to differ materially from those discussed in the forward-looking statements. Important factors, among others, that may affect actual results or outcomes include:

•Our ability to grow and manage growth profitably, maintain relationships with customers and suppliers and retain key employees;

•our success in retaining or recruiting, our principal officers, key employees or directors;

•intense competition and competitive pressures from other companies in the industry in which we operate;

•increased costs of, or delays in obtaining, key components or labor for the construction and completion of LFG and livestock waste projects that generate electricity and renewable natural gas (“RNG”) and compressed natural gas (“CNG”) and hydrogen dispensing stations;

•factors relating to our business, operations and financial performance, including market conditions and global and economic factors beyond our control;

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

•factors associated with companies, such as us, that are engaged in the production and integration of RNG, including (i) anticipated trends, growth rates and challenges in those businesses and in the markets in which they operate (ii) contractual arrangements with, and the cooperation of, landfill and livestock biogas conversion project site owners and operators, on which we operate our LFG and livestock waste projects that generate electricity and (iii) RNG prices for Environmental Attributes, LCFS credits and other incentives;

•the ability to identify, acquire, develop and operate renewable projects and fueling stations ("Fueling Stations");

•our ability to issue equity or equity-linked securities or obtain or amend debt financing;

•the demand for renewable energy not being sustained;

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

•the effect of legal, tax and regulatory changes; and

•other factors detailed under the section entitled “Risk Factors.”

The forward-looking statements contained in this Form 10-K are based on current expectations and beliefs concerning future developments and their potential effects on us. There can be no assurance that future developments affecting us will be those that we have anticipated. These forward-looking statements involve a number of risks, uncertainties (some of which are beyond our control) or other assumptions that may cause actual results or performance to be materially different from those expressed or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to, those factors described under the heading “Risk Factors” in this Form 10-K. Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward-looking statements. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws.

PART 1

ITEM 1. BUSINESS

OPAL Fuels Inc. (including its subsidiaries, the “Company”, “OPAL”, “we,” “us” or “our”) is a vertically integrated leader in the capture and conversion of biogas into low carbon intensity renewable natural gas (RNG) and Renewable Power. OPAL Fuels is also a leader in the marketing and distribution of RNG to heavy duty trucking and other hard to de-carbonize industrial sectors. RNG is chemically identical to the natural gas used for cooking, heating homes and fueling natural gas engines, with one significant difference: RNG is produced by recycling harmful methane emissions created by decaying organic waste as opposed to natural gas which is a fossil fuel pumped from the ground. We have participated in the biogas-to-energy industry for over 20 years.

Biogas is generated by microbes as they break down organic matter in the absence of oxygen. Biogas is comprised of non-fossil waste gas, with high concentrations of methane, which is the primary component of RNG and the source for combustion utilized by Renewable Power plants to generate electricity. 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 fossil fuel-based natural gas. Partially treated biogas can be used directly in heating applications (as a form of medium-Btu fuel) or in the production of Renewable Power. Our principal sources of biogas are (i) landfill gas, which is produced by the decomposition of organic waste at landfills, and (ii) dairy manure, which is processed through anaerobic digesters to produce the biogas.

We also design, develop, construct, operate and service Fueling Stations for trucking fleets across the country that use natural gas to displace diesel as their transportation fuel. We have participated in the alternative vehicle fuels industry for approximately 13 years and have established an expanding network of Fueling Stations for dispensing RNG. In addition, we have recently begun implementing design, development, and construction services for hydrogen fueling stations, and we are pursuing opportunities to diversify our sources of biogas to other waste streams.

Recent Developments

Investment Tax Credits

On November 17, 2023, the U.S. Department of Treasury (the, "Treasury") and the U.S. Internal Revenue Service (the, "IRS") proposed regulations regarding Investment Tax Credits ("ITCs") on renewable energy projects where the IRS specified certain types of RNG equipment are ineligible for ITCs which could negatively impact the profitability of our RNG business and our ability to finance our RNG projects. On February 16, 2024, the Treasury and the IRS released a correction to the proposed regulations clarifying that certain of such equipment may be eligible for ITCs. These regulations are merely proposed, and Treasury and the IRS are collecting and reviewing comments received regarding the proposed regulations. The proposed regulations also contain provisions that we believe create uncertainty relating to the ownership, installation or modification of equipment and property on which ITCs can be claimed. If the final regulations are enacted in a form that limits, in whole or in part, the amount of ITCs for certain of our construction costs, this would reduce the amount of ITCs available and thus could have a material adverse effect on our operations and our business.

ATM Program

On November 17, 2023, we entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with each of B. Riley Securities, Inc., Cantor Fitzgerald & Co. and Stifel, Nicolaus & Company, Incorporated (each, an “Agent,” and collectively, the “Agents”) pursuant to which we may issue and sell shares of our Class A common stock having an aggregate offering price of up to $75 million from time to time through the Agents.

The issuance and sale of Class A common stock under the Sales Agreement are effected pursuant to the registration statement on Form S-3 (File No. 333-273584) that we filed with the United States Securities and Exchange Commission (the “SEC”) on August 1, 2023 as amended on August 11, 2023, and declared effective by the SEC on September 6, 2023, together with a related prospectus supplement. Sales of our Class A common stock through the Agents may be made by any method that is deemed an “at the market offering” as defined in Rule 415(a)(4) promulgated under the Securities Act of 1933, as amended. We will pay each Agent, upon the sale by such Agent of Class A common stock pursuant to the Sales Agreement, an amount equal to up to 3.0% of the gross proceeds of each such sale of Class A common stock.

From the date of execution of the Sales Agreement through December 31, 2023, we issued and sold 90,103 shares of Class A common stock for total proceeds, net of commissions and related costs of $0.4 million.

Asset Sale and Purchase Agreement

On October 20, 2023, our wholly-owned subsidiary entered into an Asset Purchase and Sale Agreement (for the purposes of this paragraph, the “Agreement”) with Washington Gas Light Company ("WGL"). The subsidiary is currently constructing a production facility at the Prince William County landfill located in Manassas, Virginia, to process landfill gas into RNG. The Agreement obligates the subsidiary to develop, plan and permit a gas pipeline extension and associated interconnection facilities (the “Pipeline Project”) to deliver RNG from the facility to an interconnection point on WGL’s pipeline. Per the terms and conditions of the Agreement, WGL will purchase the Pipeline Project from the subsidiary after its final completion at a purchase price of $25 million. The closing is contingent upon approval of the Agreement by the Virginia State Corporation Commission, as well as the satisfaction of customary closing conditions, and the outside closing date is on or prior to October 20, 2024. As of December 31, 2023, we have recorded capital expenditure of $1.8 million which is included in its Property, Plant and Equipment on our consolidated balance sheet.

Class D Common Stock Exchange

On March 12, 2024, Fortistar, through its subsidiary OPAL Holdco, converted 71,500,000 shares of Class D common stock of the Company held by it, each of which is entitled to five votes per share on all matters on which stockholders generally are entitled to vote, for an equal number of shares of newly issued Class B common stock, each of which is entitled to one vote per share on such matters. The share conversion had no effect on the economic interest in the Company held by Fortistar or OPAL Holdco. Fortistar converted such shares in order that the Company’s Class A common stock would become eligible for inclusion in certain stock market indices, on which many broad-based mutual funds and exchange-traded index funds are based. There can be no assurance that the Company’s Class A common stock will be included in any stock market index as a result of the share conversion, or that if the Company’s Class A common stock is included in any such index, that the price per share of the Company’s Class A common stock will be positively affected.

Our Strategy

We aim to maintain and grow our position as a leading producer and dispenser of RNG in the United States and maintain and increase our position as a leading provider of RNG to the heavy and medium-duty commercial vehicle market in the U.S. We support these objectives through a multi-pronged strategy of:

•Promoting the reduction of methane and GHG 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 offering products with high economic and ecological value. By simultaneously replacing fossil-based fuels and reducing overall methane emissions, our projects have a positive environmental impact. We are committed to the sustainable development, deployment, and utilization of RNG to reduce the country’s dependence on fossil fuels. We strive to optimize the economics of capturing biogas from our host landfills and dairy farms for conversion to RNG by balancing the capital and operating costs with the current and future quality and quantity of biogas.

•Expanding our industry position as a full-service partner for development opportunities, including through strategic transactions: Throughout our over 20-years of biogas conversion experience, we have developed the full range of biogas conversion project related capabilities from landfill gas collection system expertise, to engineering, construction, management and operations, through EHS oversight and Environmental Attributes management. Our full suite of capabilities allows us to serve as a multi-project partner, including through strategic transactions.

•Expanding our capabilities to new feedstock sources and technologies: We believe we will be able to enter new markets for our products. With our experience and industry expertise, we believe 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 both domestic and internationally. We are actively reviewing opportunities beyond our core LFG and dairy RNG business. Specifically, we intend to diversify our project portfolio beyond landfill biogas through the expansion into additional methane producing assets.

•Empowering our customers to achieve their sustainability and carbon reduction objectives: We are well positioned to empower our customers to achieve their sustainability and carbon reduction goals, by, for example, reducing GHG emissions from their commercial transportation activities, at a cost to customers that is competitive to other fuels like diesel. We also assist our customers in their transition to cleaner transportation fuels by helping them obtain federal, state and local tax credits, grants and incentives, vehicle financing, and facilitating customer selection of vehicle specifications to meet their needs.

Vertical Integration of Business

Our combination of Biogas Conversion Projects and Fueling Stations, together with our dispensing, generation, and monetization of associated Environmental Attributes, differentiates us from our principal competitors. This vertical integration allows for a direct pathway to qualify biogas for Environmental Attributes and offers an attractive network of Fueling Stations to heavy and medium-duty trucking fleets running on natural gas.

Our involvement across the RNG value chain, from production to dispensing of RNG, gives us the opportunity to avoid value leakage that competitors may incur by having to rely upon third-parties for either RNG supply or dispensing. The additional value captured benefits us by allowing us to offer better terms to our transportation customers. The increasing adoption of RNG as a fuel for transportation use amongst our customers subsequently gives us more opportunities to secure additional gas rights for Biogas Conversion Projects.

Our vertical integration also attracts low carbon intensity ("CI") project developers that need partners to market and dispense their fuel to obtain LCFS credits and provide the required economic returns on their projects. As a result, we gain opportunities to source new Biogas Conversion Projects as well as secure RNG marketing agreements from these developers. In addition, fleet owners are attracted to our biogas conversion and dispensing resources which results in the growth of dispensing, station construction and service businesses.

Management and Project Expertise

Our management team has decades of combined experience in the design, development, construction, maintenance, and operation of Biogas Conversion Projects and Fueling Stations that dispense RNG, as well as the monetization of associated Environmental Attributes. We believe our team’s proven track record and focus give us a strategic advantage in continuing to grow our business. Our diverse experience and integration of key technical, environmental, and administrative support functions underpin our ability to design and operate projects and execute their day-to-day activities.

Our experience and existing project portfolio have provided access to a wide spectrum of available biogas-to-RNG and biogas-to-Renewable Power 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. At LFG-to-RNG projects, technologies deployed at each project are relatively consistent and mature and management has extensive experience with such technologies. At livestock waste-to-RNG projects, digester technologies may be different from site to site, but upgrading technology is generally consistent from site to site and they have both been widely used in the past several decades. Additionally, we also work with key vendors on initiatives to develop and test upgrades to existing technologies. We apply our experience and knowledge to identify new sources of biogas.

We also have a network of experienced and creditworthy EPC contractors to perform design, development, procurement and construction services under our supervision. Typically, our contracts for EPC services contain fixed price, date certain provisions and liquidated damages provisions, which greatly reduce the risks typically associated with construction projects. We also work with key vendors on initiatives to develop and test upgrades to existing technologies.

Access to Development Opportunities

We have many relationships throughout the industry supply chain including technology and equipment providers, feedstock owners and RNG off-takers. We believe the strong reputation we have attained and our understanding

of the various and complex requirements for generating and monetizing Environmental Attributes gives us a competitive advantage relative to new market entrants. We further benefit from our vertical integration by offering dispensing and monetization services to third-party developers, which can lead to project acquisition or partnership opportunities for us.

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 and dairy developers who value our long operating history and strong reputation in the biogas conversion industry. This includes new projects and referrals from existing partners. We actively seek to extend the term of our contracts at project sites and views our positive relationships with the owners and managers of host landfills and dairy farms as a contributing factor to our ability to extend contract terms as they come due.

Large and Diverse Project Portfolio

We have a large, technologically optimized Biogas Conversion Project portfolio. Our ability to solve complex project development challenges and integrate such solutions across our entire project portfolio has supported the long-term successful partnerships we have with our Biogas Conversion Project 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 the ability to achieve priority service and pricing from contractors, service providers, and equipment suppliers.

EHS and Compliance

Our executive team places the highest priority on the health and safety of our staff and third parties at our project 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, performance of regular EHS audits and the use of 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 our commitment to high EHS standards is shared by our subcontractors which provides further assurances to our host landfills.

Nature of Business

Capture and Conversion Business

We typically secure our Biogas Conversion Projects through a combination of long-term gas rights, manure supply agreements, and property lease agreements with biogas site hosts. Our Biogas Conversion Projects provide our landfill and dairy farm partners with a variety of benefits, including (i) a means to monetize biogas from their sites, (ii) regulatory compliance for landfills, (iii) a source of environmentally beneficial waste management practices for dairy farms and (iv) a valuable revenue stream. Once we have negotiated gas rights or manure supply agreements, we then design, develop, build, own and operate facilities that convert the biogas into RNG or uses the processed biogas to produce Renewable Power. We sell the RNG produced by the Biogas Conversion Projects through RNG marketing and dispensing agreements and generate associated Environmental Attributes. These Environmental Attributes are then sold to obligated parties as defined under the RFS promulgated by the U.S. federal government and Low Carbon Fuel Standard Programs established by several states. We also sell Renewable Power to public utilities through power purchase agreements.

We believe there are other sources of biogas in the United States, and internationally, that could be utilized for potential future Biogas Conversion Project opportunities. We expect to continue our growth by taking advantage of these opportunities while also continuing to capitalize on additional vertical integration opportunities. Our evaluation and execution of project opportunities will benefit from our ability to leverage our industry experience, relationships with customers and vendors, knowledge about transmission and distribution utility interconnections, and capabilities to design, develop, construct, operate, maintain and service Biogas Conversion Projects and Fueling Stations. We exercise financial discipline in pursuing these projects by targeting project returns that are in line with the relative risk of the specific projects.

Our current Biogas Conversion Projects generate RNG from landfill sites and dairy farms. We view the acquisition of new landfill gas, dairy farm, and other biogas waste projects as significant opportunities for us to expand our RNG business, complementing the ongoing conversion of certain of our existing Renewable Power plants to RNG production facilities. We believe our business is scalable, which is expected to continue to support growth through development and acquisitions.

We differentiate ourselves from our competitors based on our vertically integrated business model and long history of working with leading vendors, technologies and utilities. Our competitive advantage is further strengthened by our expertise in designing, developing, constructing and operating Biogas Conversion Projects and Fueling Stations.

Dispensing and Monetization Business

We are a leading provider of RNG marketing and dispensing in the alternative vehicle fuels market for heavy and medium-duty trucking fleets throughout the United States. In this sector, we focus on dispensing RNG through Fueling Stations that serve fleets that use natural gas instead of diesel fuel. These Fueling Stations and dispensing services are key for our business because Environmental Attributes are generated through dispensing RNG at these stations for use as vehicle fuel for transportation, and, once generated, the Environmental Attributes can then be monetized.

During 2023, we dispensed 35.3 million gasoline gallon equivalent ("GGEs") of RNG to the transportation market, generating corresponding Environmental Attributes, utilizing our current network of Fueling Stations across the United States.

Hydrogen Fuel

In the coming years, we believe we will be able to provide hydrogen fuel to vehicle fleets by constructing and servicing hydrogen fueling stations as well as providing RNG for hydrogen production.

How We Generate Revenue

Overview. Our revenues are driven principally from the sale of Environmental Attributes that are generated from dispensing RNG as transportation fuel for heavy and medium-duty trucking fleets at Fueling Stations. In addition, we generate revenue from (i) the sale of Renewable Power, (ii) design, development, construction and service of Fueling Stations, and (iii) sales of RNG produced by OPAL and third parties as pipeline quality natural gas.

Environmental Attributes. Currently, our Environmental Attributes revenue stream is primarily comprised of RINs, LCFS credits, ISCC Carbon Credits and RECs. If RNG is dispensed into vehicles as transportation fuel, RINs will be generated under the RFS program. In certain states, there are LCFS programs, which allow a credit to be generated based on a fuel’s carbon intensity score. If RNG is used to produce hydrogen which is consumed in the transportation market in a state where an LCFS program is available, an LCFS credit may be generated as well. Lastly, LFG-to-Renewable Power projects can create Environmental Attributes, in the form of a REC, in certain states and can be bundled with electricity off-take or monetized separately. See "Biogas RNG Market Opportunity".

Power Purchase Agreements. Our Renewable Power projects have associated Power Purchase Agreements (“PPAs”) with creditworthy utility off-takers or municipalities. Nearly all of our Renewable Power off-takers have investment grade credit ratings with either S&P or Moody’s. As discussed above, we also generate RECs from Renewable Power projects through the conversion of biogas to Renewable Power.

Fueling Station Construction and Services. We have significant experience in the engineering, design, construction and operation of Fueling Stations that dispense RNG. We use a combination of custom designed and off-the-shelf equipment to build these stations. We also perform in-house manufacturing and modularized portable CNG compressor packages for smaller dispensing stations, utilizing our patented technology that allows faster and easier station installations. These portable packages can include defueling panels that allow smaller fleet owners to avoid expensive maintenance shop upgrades. In addition, we also generate revenues by providing operations and maintenance services for customer stations; and by helping our customers obtain federal, state and local tax credits, grants and incentives.

Biogas Conversion Projects

Typically, a Biogas Conversion Project includes two phases: (i) biogas collection, and (ii) processing and purifying biogas.

At landfills, biogas collection systems can be configured as vertical wells and horizontal collectors. 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. Collection system operators “tune” or adjust the wellfield to maximize the volume and quality of biogas collected while maintaining environmental compliance. The existing compliance structure for landfills in the United States benefits us because the EPA requires larger landfills to have collection systems in place to collect and destroy biogas emissions. We turn this compliance cost into a revenue stream for the landfill and are able to leverage existing collection infrastructure in biogas plant design.

A basic biogas processing plant includes: (i) a moisture removal system, (ii) blowers to provide a vacuum to “pull” the gas and pressure to convey the gas and (iii) a flare for destroying unutilized gas. System operators monitor parameters to maximize system efficiency. Using biogas in a Renewable Power facility usually requires some treatment of the landfill 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 Renewable Power facility. This partially cleaned biogas can be burned on-site to generate Renewable Power which can be immediately used or deployed into the grid. To further upgrade the gas to pipeline quality RNG, the partially treated biogas then goes through a process that separates CO2 from the methane molecules. Further treatment of the biogas is often required to remove residual nitrogen and/or oxygen to meet pipeline specifications.

For dairy waste-to-RNG projects, manure is collected and then scraped or flushed into a reception pit or lagoon, and may be fed into a digester. The biogas equipment then anaerobically digests the manure and produces biogas. There are three different types of anaerobic digesters: (i) covered lagoons (existing lagoons that use large cover to capture methane); (ii) complete mix (large tanks that heat and mix manure), and (iii) plug-flow (long rectangular tanks; unmixed). The biogas is then upgraded to meet pipeline quality specifications.

If a biogas capture and conversion project is not within close proximity to a pipeline, the RNG is transported by road using tube trailers to a gas injection point. This is referred to as a virtual pipeline.

Biogas RNG Market Opportunity

Biogas can be collected and processed to remove impurities for use as RNG (a form of high-Btu fuel) and can be injected into existing natural gas pipelines because it is fully interchangeable with fossil fuel-based natural gas. Partially treated biogas can be used directly in heating applications (as a form of medium-Btu fuel) or in the production of Renewable Power. Our current primary sources of biogas are landfills and dairy farms.

Landfill and livestock-sourced biogas serve as the base to produce RNG, while also reducing GHG emissions. While landfill projects for RNG and Renewable Power 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, we believe additional sources of biogas will become available for RNG production.

Overview of Landfill Gas Sources

LFG, or landfill gas, is created through the naturally occurring anaerobic decomposition of organic matter. Large landfills have been required by the EPA to capture municipal solid waste landfill emissions for decades due to various regulatory requirements aimed at reducing GHG emissions. The amount of LFG produced from a landfill generally increases as more waste is added to the site. Once a permitted landfill site is completely filled, the landfill will place a cap over the waste. Gas production then follows a generally predictable and modest decline over the next 30 or more years. As a result, LFG has a predictable long-term production profile which, when coupled with the expectation of continued landfill waste growth in the United States for the next 30 years, creates predictable long-term LFG feedstock.

To capitalize on this feedstock opportunity, and to help landfill owners meet growing regulatory requirements for curbing GHG emissions, we enter into long-term gas rights and site lease agreements with landfill owners. The agreement terms are typically at least 20-years. In most cases, the agreements contain renewal provisions. With respect to all of our existing or proposed LFG-to-RNG Biogas Conversion Projects currently in operation or under construction (a total of 14 projects), all but one relates to landfills that are currently open and accepting more waste, which we believe

provides a high degree of visibility into the long-term volumes of RNG capable of being generated at each of these projects.

Using proven biogas purification technology, biogas can be processed onsite to remove impurities, and used at around 50% methane to generate Renewable Power. Biogas can be further processed and upgraded to remove CO2 as well as remaining contaminants to increase the methane content and reach pipeline quality specifications, creating RNG. The resulting RNG can be used for all purposes suitable for traditional fossil fuel-based natural gas such as vehicle fuel (e.g., for consumer, industrial and transportation uses, or further converted to renewable hydrogen). RNG can be transported using existing natural gas pipeline infrastructure or through tube trailers. This is an important factor that enables OPAL to design, develop and operate RNG projects to generate value from production of RNG and the associated Environmental Attributes (i.e., RINs and LCFS credits) throughout the United States and exported to international markets.

Overview of Livestock Sources

Livestock are the top agricultural source of GHG worldwide, according to the EPA. Livestock waste, particularly from dairies, produces methane which can be converted to RNG. After being converted to RNG, it can be sold as RNG for consumer, industrial and transportation uses, or further converted to renewable hydrogen. When RNG is produced from livestock waste and used as a vehicle fuel, it effectively reduces emissions from the transportation fleets and also from the livestock facilities that otherwise do not have to collect such methane and is often considered carbon negative. Additionally, revenues generated from dispensing RNG produced from livestock farms can be significantly higher than dispensing revenue from RNG produced from landfills due to state-level low-carbon fuel incentives for these projects.

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.

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 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 and/or adding a revenue stream for the dairy farmer when sold to third parties.

Highly Fragmented Market

The LFG market is heavily fragmented, which we believe represents an opportunity for companies like us to find project opportunities. The top players in the industry account for the majority of installed LFG capacity. This market dynamic creates the opportunity for consolidation by well capitalized, experienced market participants such as OPAL.

While LFG has accounted for most of the growth in Biogas Conversion Projects to date, we believe additional economically viable LFG project opportunities exist. According to the EPA LMOP project database, as of July 2023, there were 532 LFG projects in operation in the United States, including 359 operating LFG-to-electricity projects that may be converted to produce RNG as well as 470 additional candidate landfills. Based on EPA data, these 470 candidate landfills have the potential to collect a combined 342.9 million standard cubic feet of LFG per day. Based on our industry experience, technical knowledge and analysis we believe many of these sites are potentially economically viable for RNG project acquisitions.

Well-Established Regulatory Framework

RINs are credits used by Obligated Parties for regulatory compliance as part of the RFS program. The RFS program is a federal law introduced in 2005 and updated in 2007 to incorporate renewable content into various transportation fuels. Through the RFS program, RINs can be sold to counterparties in order for them to meet their renewable standard requirements. RNG from landfills and livestock waste, among other sources, qualifies as a cellulosic biofuel with a 60% GHG reduction requirement (“D3”) RIN, which is currently the highest priced RIN and commands a premium compared to non-cellulosic renewable fuels such as ethanol and renewable diesel.

We generate RINs when RNG is dispensed into vehicles as transportation fuel, and the RINs can then be sold to, and traded with, market participants who can either retire them or trade them again. By using the RINs, Obligated Parties

retire the RINs for compliance purposes. Market participants in the RIN program typically include Obligated Parties and registered RIN market participants. Participants include both domestic and foreign companies.

LCFS programs are state-level market-based programs designed to decrease CI and GHG emissions from the transportation sector. Currently, California and Oregon have established LCFS programs. Additionally, multiple jurisdictions are considering implementation of LCFS programs; for example Canada has proposed programs and Washington state’s program began in 2023.

LCFS programs are attractive because LCFS credits can be additive to RINs. In California, the most established program, the LCFS program is administered by CARB, which sets annual CI standards. Fuel producers in the transportation fuel pool that have lower CI scores than the target established by CARB generate LCFS credits, and those with higher CI scores than the annual standard will generate deficits. A fuel producer with deficits must have enough LCFS credits through either generation or acquisitions to be in annual compliance with the annual standard. We are poised to take advantage of these LCFS programs because RNG from dairies has very low or negative CI, and therefore generates valuable credits in states with LCFS programs.

Currently, it is estimated that RNG production in the United States can only cover about 1.5% of the U.S. heavy and medium-duty vehicles fuel market. RNG production is projected to triple by 2027, increasing the RNG industry share to as much as 2.5%. Although it is likely that utilities and other consumers will compete with the vehicle fuel market to acquire such RNG, we believe there is adequate potential to continue placing RNG volumes into the transportation market. The legislated D3 RIN requirements are many multiples of current industry production. The EPA sets an RVO each year generally in excess of what the industry is expected to produce but well below the statutory requirement. The EPA has sharply increased the required volume of the D3 RINs in recent years, with the current D3 RIN RVO level encouraging growth in the industry.

Economic Benefits Incentivize Switching to RNG

RNG vehicles, especially heavy and medium-duty commercial vehicles, not only have a lower cost of ownership than similar vehicles running on diesel, they also have a lower cost of ownership than their renewable energy peers, especially hydrogen and battery electric vehicles, assuming expected D3 RINs and LCFS pricing. This comparative advantage creates significant economic incentives for heavy and medium-duty commercial vehicle owners to favor RNG.

Our Projects

As of December 31, 2023, we owned and operated 25 projects, eight of which are RNG projects and 17 of which are Renewable Power Projects. As of that date, our RNG projects in operation had a design capacity of 5.2 million MMBtus per year and our Renewable Power Projects in operation had a nameplate capacity of 112.5 MW per hour. In addition to these projects in operation, we are actively pursuing expansion of our RNG-generating capacity and, accordingly, have a portfolio of RNG projects in construction or in development, with eight of our current Renewable Power Projects being considered candidates for conversion to RNG projects in the foreseeable future.

Below is a table setting forth the RNG projects in operation and construction in our portfolio:

OPAL's Share of Design Capacity (MMbtus per year) (1)

Source of Biogas

Ownership

Expected Commercial Operation Date (5)

RNG Projects in Operation:

Greentree

1,061,712

LFG

100%

N/A

Imperial

1,061,712

LFG

100%

N/A

Emerald (2) (3)

1,327,140

LFG

50%

N/A

New River

663,570

LFG

100%

N/A

Noble Road (2)

464,499

LFG

50%

N/A

Pine Bend (2)

424,685

LFG

50%

N/A

Biotown (2)

48,573

Dairy

10%

N/A

Sunoma (4)

192,350

Dairy

90%

N/A

Total

5,244,241

RNG Projects in Construction:

Prince William

1,725,282

LFG

100%

First quarter 2024

Hilltop (6)

255,500

Dairy

100%

Not Determined

Vander Schaaf (6)

255,500

Dairy

100%

Not Determined

Polk County

1,060,000

LFG

100%

Fourth quarter 2024

Sapphire (2)

796,284

LFG

50%

Third quarter 2024

Atlantic (2)

331,785

LFG

50%

Mid 2025

Total

4,424,351

(1) Reflects the Company’s ownership share of design capacity for projects that are not 100% owned by the Company (i.e., net of joint venture partners’ ownership). Design capacity is measured as the volume of feedstock biogas that the plant is capable of accepting at the inlet for processing and may not reflect actual production of RNG from the projects, which will depend on many variables including, but not limited to, (i) quantity and quality of the biogas, (ii) operational up-time of the facility and (iii) actual efficiency of the facility.

(2) We record our ownership interests in these projects as equity method investments in our consolidated financial statements.

(3) Emerald completed commissioning and commenced operations during the third quarter of 2023.

(4) This project has provisions that will adjust or “flip” the percentage of distributions to be made to us over time, typically triggered by achievement of hurdle rates that are calculated as internal rates of return on capital invested in the project.

(5) Expected Commercial Operation Date (“COD”) for commencement of the RNG projects in construction is based on the Company’s estimate as of the date of this report. CODs are estimates and are subject to change as a result of, among other factors out of the Company’s control: (i) regulatory/permitting approval timing, (ii) disruption in supply chains and (iii) construction timing.

(6) Please see Item 3: Legal Proceedings and Note 17 - Commitments and Contingencies to the financial statements.

Renewable Power Projects

Below is a table setting forth the Renewable Power projects in operation in our portfolio:


	Nameplate capacity (MW per hour) (1)	Current RNG conversion candidate (2)
Renewable Power projects in operation:
Sycamore	5.2	Yes
Lopez	3.0	—
Miramar Energy	3.2	Yes
San Marcos	1.8	—
Santa Cruz	1.6	—
San Diego - Miramar	6.5	Yes
West Covina	6.5	—
Port Charlotte	2.9	—
Taunton	3.6	—
Arbor Hills (3)	28.9	N/A
C&C	6.3	Yes
Albany	5.9	—
Concord and CMS	14.4	Yes
Pioneer	8.0	—
Prince William I (4)	1.9	Yes
Prince William II (5)	4.8	Yes
Old Dominion	8.0	Yes
Total	112.5
Renewable Power projects in construction:
Fall River	2.4	—

(1) Nameplate capacity is the manufacturer’s expected capacity at ISO conditions for each facility and may not reflect actual production from the projects, which depends on many variables including, but not limited to, (i) quantity and quality of the biogas, (ii) operational up-time of the facility and (iii) actual productivity of the facility.

(2) We have determined that some of our Renewable Power Projects are currently RNG conversion candidates. The Company identifies suitable RNG conversion candidates based on highest return of capital which is driven by certain factors including, but not limited to (i) the quantity and quality of LFG, (ii) the proximity to pipeline interconnect and (iii) the ability to enter into contracts, including site leases and gas rights agreements, with host sites. The Company may change its decision to convert a Renewable Power Project into an RNG project in the future. The Company believes disclosing renewable power conversion candidates provides visibility into the effect of those conversions on the existing Renewable Power portfolio.

(3) Although the RNG conversion is completed, it is currently contemplated that the Arbor Hills renewable power plant will continue limited operations on a stand-by, emergency basis through March of 2031.

(4) Prince William I renewable power plant discontinued operations in Q1 2024.

(5) Prince William II discontinued operations in Q1 2024.

Competition

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 based on (i) our status as one of the largest operators of LFG-to-RNG projects, (ii) our over 20-year track record of operating and developing projects, (iii) our vertically integrated business platform, (iv) our deep relationships with some of the largest landfill owners and (v) our relationships with dairy farms in the country, we are well-positioned to continue to operate and grow our portfolio and respond to competitive pressures. We have demonstrated a track record of strategic flexibility over our greater than 20-year history which has allowed us to pivot towards projects and markets that we believe deliver optimal returns and shareholder value in response to changes in market, regulatory and competitive pressures.

The biogas market is highly fragmented. We believe both our size compared to other LFG companies and our capital structure puts us in a strong position to compete for new project development opportunities or acquisitions of existing projects. However, competition for such opportunities, including the prices being offered for gas supply, will impact the expected profitability of projects, 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 and dairy farm owners may seek to install their own RNG production facilities 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 position us to compete strongly amongst our industry peers.

Governmental Regulation

General

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

Our RNG projects are subject to federal RFS program regulations, including the Energy Policy Act of 2005 (the “EPACT 2005”) and EISA. The EPA administers the RFS program with volume requirements for several categories of renewable fuels. The EPA’s RFS regulations establish rules for fuel supplied and administer the RIN system for compliance, trading credits and rules for waivers. The EPA calculates a blending standard for each year based on estimates of gasoline usage from the Department of Energy’s Energy Information Agency. Separate quotas and blending requirements are determined for cellulosic biofuels, biomass-based diesel, advanced biofuels and total renewable fuel. Further, we are required to register each RNG project with the EPA and relevant state regulatory agencies. We qualify our RINs through a voluntary Quality Assurance Plan, which typically takes from three to five months from first injection of RNG into the commercial pipeline system. Further, we typically make a large investment in the project prior to receiving the regulatory approval and RIN qualification. In addition to registering each RNG project, we are subject to quarterly audits under the Quality Assurance Plan of our projects to validate our qualification.

Our RNG projects are also subject to state renewable fuel standard regulations. By way of example, the LCFS program in California required producers of petroleum-based fuels to reduce the CI of their products by at least 10% by 2020 and requires a reduction of at least 20% by 2030 from a 2010 baseline. Petroleum importers, refiners and wholesalers can either develop their own low-carbon fuel products or buy California LCFS credits from other companies that develop and sell low-carbon alternative fuels, such as biofuels, electricity, natural gas or hydrogen. We are subject to a qualification process similar to that for RINs, including verification of CI levels and other requirements that currently exists for LCFS credits in California.

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

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

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

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

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

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

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

FERC

FERC regulates the sale of electricity at wholesale and the transmission of electricity in interstate commerce pursuant to its regulatory authority under the Federal Power Act. FERC also regulates certain natural gas transportation and storage facilities and services, and regulates the rates and terms of service for natural gas transportation in interstate commerce under the Natural Gas Act and the Natural Gas Policy Act.

With respect to electricity transmission and sales, FERC’s jurisdiction includes, among other things, authority over the rates, charges and other terms for the sale of electricity at wholesale by public utilities (entities that own or operate projects subject to FERC jurisdiction) and for transmission services. With respect to its regulation of the transmission of electricity, FERC requires transmission providers to provide open access transmission services, which supports the development of competitive markets by assuring nondiscriminatory access to the transmission grid. FERC has also encouraged the formation of RTOs to allow greater access to transmission services and certain competitive wholesale markets administered by ISOs and RTOs.

In 2005, the U.S. federal government enacted the EPACT 2005 conferring new authority for FERC to act to limit wholesale market power if required and strengthening FERC’s civil penalty authority (including the power to assess

fines of up to $1.3 million per day per violation, as adjusted due to inflation), and adding certain disclosure requirements. EPACT 2005 also directed FERC to develop regulations to promote the development of transmission infrastructure, which provides incentives for transmitting utilities to serve renewable energy projects and expanded and extended the availability of U.S. federal tax credits to a variety of renewable energy technologies, including wind power. EPACT 2005’s market conduct, penalty and enforcement provisions also apply to fraud and certain other misconduct in the natural gas sector.

Qualifying Facilities

The Public Utility Regulatory Policies Act established a class of generating facilities that would receive special rate and regulatory treatment, termed QFs. There are two categories of QFs: qualifying small power production facilities and qualifying cogeneration facilities. A small power production facility is a generating facility of 80 MW or less whose primary energy source is hydro, wind, solar, biomass, waste, or geothermal. A cogeneration facility is a generating facility that produces electricity and another form of useful thermal energy (such as heat or steam) in a way that is more efficient than the separate production of both forms of energy. QFs are generally subject to reduced regulatory requirements. Small power production facilities up to 20 MW and “eligible” facilities as defined by section 3(17)(E) of the Federal Power Act are exempt from rate regulation under Sections 205 and 206 of the Federal Power Act.

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

State Utility Regulation

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

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

RNG Production and Sale

Our projects typically convert biogas to RNG for sale as a fuel product. FERC regulates the natural gas pipelines that transport gas in interstate commerce, and specifies or approves a gas pipeline’s tariff that sets the rates, terms and conditions, gas quality, and other requirements applicable to transportation of natural gas on the pipelines, including shipping RNG. Our sites are not permitted, and may not be physically able, to deliver RNG to a FERC-regulated pipeline unless the pipeline’s receipt of the gas is consistent with the standards adopted in the pipeline’s FERC tariff. State regulators determine whether RNG may be purchased by the state’s local gas utilities, and whether a site operator may directly sell gas to a retail, or direct end-use, customer. Purely local gas sales not utilizing FERC-regulated or certificated facilities are typically not subject to FERC gas regulation. The local distribution of gas to end-use customers by a state-regulated gas utility is also typically outside the scope of FERC’s gas regulatory jurisdiction. The opening and operation of a landfill or dairy farm that is expected to produce gas does not ordinarily require a FERC certificate or the acceptance by FERC of a gas tariff.

Future Regulations

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

The Inflation Reduction Act (the “IRA”) was signed into law on August 16, 2022. The bill invests nearly $369 billion in energy and climate policies. The provisions of the IRA are intended to, among other things, incentivize domestic clean energy investment, manufacturing, and deployment. The IRA incentivizes the deployment of clean energy technologies by extending and expanding federal incentives such as ITCs and the Production Tax Credit (the "PTC"). We view the enactment of the IRA as favorable for the overall business climate for the renewable energy industry. However, there is uncertainty related to the applicability of the IRA to our current and planned projects and the scope of the IRA and its interpretations may change if there is a change in the U.S. administration or if government agencies’ authority to interpret federal law is restricted as a result of the Supreme Court’s review of the Chevron doctrine under which federal government agencies have been awarded board authority to interpret broad or ambiguous legislation. We may also continue to experience a delay in our sales cycles and new award activity as our customers consider the applicability of the IRA and as financing projects may take longer as result of this uncertainty. The IRA may increase the competition in our industry and as such increase the demand and cost for labor, equipment and commodities needed for our projects.

On November 17, 2023, the Treasury and the IRS proposed regulations regarding ITCs on renewable energy projects where the IRS specified certain types of RNG equipment is ineligible for the ITC which could negatively impact the profitability of our RNG business and our ability to finance our RNG projects. On February 16, 2024, the Treasury and the IRS released a correction to the proposed regulations clarifying that certain of such equipment may be eligible for ITCs. These regulations are merely proposed, and the Treasury and the IRS are collecting and reviewing comments received regarding the proposed regulations. The proposed regulations also contain provisions that we believe create uncertainty relating to the ownership, installation or modification of equipment and property on which ITCs can be claimed. If the final regulations are enacted in a form that limits, in whole or in part, the amount of ITC Credits for certain of our construction costs, this would reduce the amount of ITCs available and thus could have a material adverse effect on our operations and our business.

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

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

Facilities

Our corporate headquarters are located in White Plains, New York, where we occupy approximately 13,600 square feet of shared office space with an affiliate of Fortistar pursuant to an Administrative Services Agreement. We believe this office space is adequate for our needs for the immediate future and that, should it be necessary, we can lease additional space to accommodate any future growth.

Our services office and maintenance facility is located in Oronoco, Minnesota, where we own and occupy a 20,000 square foot building of combined office space, maintenance shop and loading dock located on 3.25 acres. The

building was acquired in September 2018 and is adequate for our needs for the immediate future. Should it be necessary, we believe we can expand the building to accommodate future growth.

Our construction office and maintenance facility is located in Rancho Cucamonga, California, where we occupy approximately 29,935 square feet of combined office space, maintenance shop and loading dock. In March 2022, we entered into an amendment to the lease which extended the lease term to January 2026. We believe the space that we currently lease is adequate for our needs for the immediate future but we may seek additional space to accommodate future growth, which we believe will be available to us on satisfactory terms.

Human Capital

As of December 31, 2023, we had approximately 326 full-time employees, all of whom are located in the United States. Our employee work force consists of field operations personnel as well as office-based employees. None of our employees are subject to a collective bargaining agreement or a labor union and we believe we have a good relationship with our employees. We value a diverse workforce. We are committed to a culture of integrity, inclusivity, and excellence. We are an Equal Opportunity Employer in our hiring and promoting practices, benefits and wages.

Our values

•SAFETY - Passion for safety

•INTEGRITY - Straightforward, open and honest

•RELATIONSHIPS - Engaging all stakeholders

•EXCELLENCE - Quality and creativity

Talent management and leadership

We take a systemic approach to hiring, training and developing our employees based on our code of ethics. This includes creating individual goals based on company priorities and providing employees periodic feedback in order to assess individual performance. We have developed internal promoting practices based on objective annual performance evaluations, encouraging employees to develop within their chosen career path and providing necessary professional trainings as needed.

Human rights, health and safety

Safety, including the health of our employees is one of our values and we perform all of our operations with safety in mind. We maintain and update our safety manual for all field personnel on an annual basis and conduct safety training sessions to all of our employees on a regular basis. We encourage near miss reporting from all of our employees so that we can take preventative steps before accidents occur. We continuously strive to provide a secure working environment for both our office-based and field operations personnel.

Available Information

Our website can be found at www.opalfuels.com. We make available, free of charge through our website, our Annual Report on Form 10‑K, Quarterly Reports on Form 10‑Q, Current Reports on Form 8‑K, our proxy statement, our registration statements and Forms 3, 4 and 5 filed on behalf of directors and executive officers, and amendments to these reports, as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. We are not including the information contained on our website or any other website as a part of, or incorporating it by reference into, this Annual Report on Form 10‑K or any other filing we make with the SEC. The filings are also available through the SEC’s website at www.sec.gov. Our Board of Directors (the “Board”) has documented its governance practices by adopting several corporate governance policies. These governance policies, including our Corporate Governance Guidelines and Code of Business Conduct and Ethics, as well as the charter for the Audit Committee of the Board may also be viewed on our website. Copies of such documents will be provided to stockholders without charge upon written request to the corporate secretary at the address shown on the cover page of this Annual Report on Form 10‑K.

Glossary of Terms

The following are definitions of terms used in this Form 10-K.

“ArcLight” refers to ArcLight Clean Transition Corp. II, a blank check company incorporated as a Cayman Islands exempt company, and our previous name prior to the Closing.

“Ares” refers to ARCC Beacon LLC, a Delaware limited liability company.

“BCA” refers to the Business Combination Agreement dated as of December 2, 2021 (as the same has been or may be amended, modified, supplemented or waived from time to time), by and among ArcLight, OPAL Fuels and OPAL Holdco.

“Business Combination” refers to the transaction contemplated by the BCA.

“Bylaws” refers to the bylaws of OPAL.

“Class A common stock” refers to the shares of Class A common stock, par value $0.0001 per share, of OPAL.

“Class A Units” refers to the Class A Units as defined in the Second A&R LLC Agreement.

“Class B common stock” refers to the shares of Class B common stock, par value $0.0001 per share, of OPAL.

“Class B Units” refers to the Class B Units as defined in the Second A&R LLC Agreement.

“Class C common stock” refers to the shares of Class C common stock, par value $0.0001 per share, of OPAL.

“Class D common stock” refers to the shares of Class D common stock, par value $0.0001 per share, of OPAL.

“Closing” refers to the closing of the Business Combination.

“Closing Date” refers to July 21, 2022.

“Company”, “we”, “our”, “us” or similar terms refers to OPAL Fuels Inc. individually or on a consolidated basis, as the context may require.

“Exchange Act” refers to the Securities Exchange Act of 1934, as amended.

“FASB” refers to the Financial Accounting Standards Board.

“Fortistar” refers to Fortistar LLC, a Delaware limited liability company.

“Fueling Stations” refers to facilities where (i) natural gas is dispensed into fuel tanks of vehicles for use as transportation fuel, and (ii) transactional data from the dispensing of the fuel is recorded so that Environmental Attributes can be subsequently reported, matched with the dispensed fuel to the extent sourced from RNG, and generated under the federal or state RFS or LCFS programs and other current and potential future programs aimed at providing support for RNG into the transportation market. At the Fueling Stations, the natural gas is pressurized using compressor systems and, in this state, is referred to as CNG. Because Environmental Attributes associated with RNG are nominated/assigned to the physical quantity of CNG dispensed at the Fueling Station, when the CNG is dispensed into to fuel tanks for use as transportation fuel and subsequently reported to the EPA and/or state environmental agency and matched with the production of RNG, the respective RINs and LCFS credits are generated. Some of these stations are designed, developed, constructed, operated and maintained by us while others are third party stations where we may only provide maintenance services.

“Hillman” refers to Hillman RNG Investments, LLC, a Delaware limited liability company and an affiliate of Fortistar.

“Investment Company Act” refers to the Investment Company Act of 1940, as amended.

“Sarbanes-Oxley Act” refers to the Sarbanes-Oxley Act of 2002.

“Securities Act” refers to the Securities Act of 1933, as amended.

“Sponsor” refers to ArcLight CTC Holdings II, L.P., a Delaware limited partnership.

“Tax Receivable Agreement” refers to the Tax Receivable Agreement, dated July 21, 2022, by and among OPAL Fuels Inc, Opal Holdco LLC and the Parties named therein as included in Exhibit 10.6 to the Current Report on Form 8-K, filed with the SEC on July 27, 2022, as the same may be amended, modified, supplemented or waived from time to time in accordance with its terms.

In addition, the following is a glossary of key industry terms used herein:

“Advanced Clean Trucks Regulation” refers to the rules adopted by the California Air Resources Board on June 25, 2020 requiring the sale of zero-emission heavy-duty trucks.

“Biogas Conversion Projects” refers to projects derived from the recovery and processing of biogas from landfills and other non-fossil fuel sources, such as livestock and dairy farms, for beneficial use as a replacement to fossil fuels.

“Btu” refers to British thermal units.

“CARB” refers to the California Air Resources Board.

“CI” refers to carbon intensity.

“CNG” refers to compressed natural gas.

“CO2” refers to carbon dioxide.

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

“EHS” refers to environment, health and safety.

“EISA” refers to the Energy Independence and Security Act of 2007.

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

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

“EPACT 2005” refers to the Energy Policy Act of 2005.

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

“GHG” refers to greenhouse gases.

“ISOs” refers to independent system operators.

“LCFS” refers to Low Carbon Fuel Standard or similar types of federal and state programs.

“LFG” refers to landfill gas.

“MBR Authority” refers to (a) authorization by FERC pursuant to the Federal Power Act to sell electric energy, capacity and/or ancillary services at market-based rates, (b) acceptance by FERC of a tariff providing for such sales, and (c) granting by FERC of such regulatory waivers and blanket authorizations as are customarily granted by FERC to holders of market-based rate authority, including blanket authorization under section 204 of the Federal Power Act to issue securities and assume liabilities.

“Obligated Parties” means refiners or importers of gasoline or diesel fuel under the RFS program.

“QFs” refers to qualifying small power production facilities under the Federal Power Act and the Public Utility Regulatory Policies Act of 1978, as amended

“RECs” refers to renewable energy credits.

"ISCC Carbon Credits" refers to Environmental Attributes associated with renewable biomethane.

“Renewable Power” refers to electricity generated from renewable sources.

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

“RINs” refers to Renewable Identification Numbers.

“RNG” refers to renewable natural gas.

“RPS” refers to Renewable Portfolio Standards.

“RTOs” refers to regional transmission organizations.

“RVOs” refers to renewable volume obligations.

“September 2020 Executive Order” refers to Executive Order N-79-20 issued by the Governor of the State of California in September 2020.

ITEM 1A. RISK FACTORS

Risks Related to Our Business

Risks Related to Our Third Party Relationships and Government Regulation of Our Business

We are dependent on contractual arrangements with, and the cooperation of, owners and operators of biogas project sites where our Biogas Conversion Projects are located for the underlying biogas rights granted to us in connection with our Biogas Conversion Projects and for access to and operations on the biogas project sites where we utilize those underlying biogas rights.

We do not own any of the biogas project sites from which our Biogas Conversion Projects collect biogas, and therefore we depend on contractual relationships with, and the cooperation of, site owners and operators for our operations. The invalidity of, or any default or termination under, any of our gas rights agreements, leases, easements, licenses and rights-of-way may interfere with our rights to the underlying biogas and our ability to use and operate all or a portion of our Biogas Conversion Projects facilities, which may have an adverse impact on our business, financial condition and results of operations.

We obtain rights to utilize the biogas and the biogas project sites on which our projects operate under contractual arrangements, with the associated biogas rights generally being for fixed terms of 20 years or more, with certain additional renewal options. The gas rights associated with our 31 projects in operation or under construction, two of which include Renewable Power projects that are in the process of conversion to RNG, are due to expire at varying points over the next 25 years. See “Business — Our Projects.” Because the rights we hold in connection with our projects typically include the right to produce electricity generated from Renewable Power, or RNG, but not both, when we pursue conversion of a project from the production of Renewable Power to the production of RNG, which has been part of our strategy over recent periods, we must secure the associated biogas rights for the production of RNG. While we have generally been successful in renewing biogas rights and in securing additional rights necessary in connection with conversion from production of Renewable Power to RNG, we cannot guarantee that this success will continue in the future on commercial terms that are attractive to us or at all, and any failure to do so, or any other disruption in the relationship with any of the site owners and operators from whose biogas project sites our Biogas Conversion Projects obtain biogas or for whom we operate biogas facilities, may have a material adverse effect on our business operations, financial condition and operational results.

In addition, the ownership interests in the land subject to the licenses, easements, leases and rights-of-way necessary for the operation of our business may be subject to mortgages securing loans or other liens (such as tax liens) and other easements, lease rights and rights-of-way of third parties (such as leases of mineral rights). As a result, certain of our rights under these licenses, easements, leases or rights-of-way may be subject, and subordinate, to the rights of those third parties in certain instances. 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 Biogas Conversion 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.

The owners and operators of biogas project sites generally make no warranties to us as to the quality or quantity of gas produced.

The Biogas Conversion Project site owners and operators generally do not make any representation or warranty to us as to the quality or quantity of biogas produced at their sites. Accordingly, we may be affected by operational issues encountered by biogas conversion project site owners and operators in operating their facilities that may affect the quantity and quality of biogas, including, among other things: (i) their ability to perform in accordance with their commitments to third parties (other than us) under agreements and permits; (ii) transportation of source materials, (iii) herd health and labor issues at the dairy farms generating the manure to be processed at our digester facilities; (iv) gas collection issues at landfill projects such as broken pipes, ground water accumulation, inadequate landcover and labor issues, and (v) the particular character and mix of trash received. We cannot guarantee that our production will be free from operational risks, nor can we guarantee the production of a sufficient quantity and quality of biogas from the owners and operators of biogas conversion project sites.

From time to time, we face disputes or disagreements with owners and operators of biogas project sites which could materially impact our ability to continue to develop and/or operate an existing Biogas Conversion Project on its current

basis, or at all, and could materially delay or eliminate our ability to identify and successfully secure the rights to construct and operate other future Biogas Conversion Projects.

The success of our business depends, in part, on maintaining good relationships with biogas conversion project site owners and operators. As a result, our business may be adversely affected if we are unable to maintain these relationships.

We may disagree with owners and operators about a number of concerns, including, without limitation, the operations of the biogas project sites, easement and access rights, the renewal of gas and manure rights on favorable terms, and temporary shutdowns for routine maintenance or equipment upgrades. Biogas conversion project site owners and operators may make unilateral decisions beneficial to them to address business concerns without consulting with us, including in circumstances where they have a contractual obligation to do so. Such decisions made by the biogas conversion project site owners and operators could impact our ability to produce RNG or Renewable Power and generate the associated Environmental Attributes.

In addition, the financial condition of the biogas conversion project sites may be affected by conditions and events that are beyond our control. Significant deterioration in the financial condition of any biogas conversion project waste site could cause the biogas conversion project site owners and operators to shut down or reduce their landfill or livestock waste operations. Any such closure or reduction of operations at a waste site could impact our ability to produce RNG or Renewable Power, and generate the associated Environmental Attributes, and we may not have an opportunity to propose a solution to protect our infrastructure in any existing Biogas Conversion Project.

If we are unable to maintain good relationships with these site owners and operators, or if they take any actions that disrupt or halt production of RNG or Renewable Power, our business, financial condition and results of operations could be materially and adversely affected.

For the U.S. transportation fuel market, we are dependent on the production of vehicles and engines capable of running on natural gas and we have no control over these vehicle and engine manufacturers. We are also dependent on the willingness of owners of truck fleets to adopt natural gas-powered vehicles and to contract with us for the provision of compressed natural gas to these fleets.

We are dependent on vehicle and engine manufacturers to succeed in our target RNG fuel dispensing markets, and we have no influence or control over their activities. These manufacturers may decide not to expand or maintain, or may decide to discontinue or curtail, their product lines for a variety of reasons, including, without limitation, as a result of the adoption of governmental policies or programs such as the rules adopted by the California Air Resources Board on June 25, 2020 requiring the sale of zero-emission heavy-duty trucks (the “Advanced Clean Trucks Regulation”) and Executive Order N-79-20 issued by the Governor of the State of California in September 2020 (the “September 2020 Executive Order”). The supply of engines or vehicle product lines by these vehicle and engine manufacturers may also be disrupted due to delays, restrictions or other business impacts related to supply chain disruptions, crises or other developments. The limited production of engines and vehicles that run on natural gas increases their cost and limits availability, which restricts large-scale adoption, and may reduce resale value. These factors may also contribute to operator reluctance to convert their vehicles to be compatible with natural gas fuel.

Failure of third parties to manufacture quality products or provide reliable services in a timely manner could cause delays in developing, constructing, bringing online and operating our Biogas Conversion Projects and Fueling Stations, which could damage our reputation, adversely affect our partner relationships or adversely affect our growth.

Our success depends on our ability to design, develop, construct, maintain and operate Biogas Conversion Projects and Fueling Stations 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 Biogas Conversion Projects and Fueling Stations, we rely on products meeting our design specifications, components manufactured and supplied by third parties and services performed by our subcontractors. We also rely on subcontractors to perform some of the construction and installation work related to our Biogas Conversion Projects and Fueling Stations, and we sometimes need to engage subcontractors with whom we have no prior experience in connection with these matters.

If our subcontractors are unable to provide services that meet or exceed our counterparties’ 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 our suppliers and service providers, we may incur liability to our counterparties 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 our ability to timely bring a project online, the quality and performance of our Biogas Conversion Projects and Fueling Stations, and may require considerable expense to find replacement products and to maintain and repair these facilities. These circumstances could cause us to experience interruption in our production and distribution of RNG and Renewable Power or the generation of related Environmental Attributes or RNG dispensing at Fueling Stations, potentially harming our brand, reputation and growth prospects.

Our operations are subject to numerous stringent EHS laws and regulations that may expose us to significant costs and liabilities. From time to time, we have been issued notices of violations from government entities that our operations have failed to comply with such laws and regulations. Failure to comply with such 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.

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, and the health and safety of our employees and other persons.

These laws and regulations impose numerous obligations applicable to our operations, including the acquisition of permits before construction and operation of our Biogas Conversion Projects and Fueling Stations; 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 operation of our Biogas Conversion Projects and Fueling Stations. In addition, construction and operating permits issued pursuant to environmental laws are necessary to operate our business. Such permits are obtained through applications that require considerable technical documentation and analysis, and sometimes require long time periods to obtain or review. Delays in obtaining or renewing such permits, or denial of such permits and renewals, are possible, and would have a negative effect on our financial performance and prospects for growth. These laws, regulations and permitting requirements can necessitate expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment.

Our operations inherently risk incurring significant environmental costs and liabilities due to the need to manage waste and emissions from our Biogas Conversion Projects and Fueling Stations. Spills or other releases of regulated substances, including spills and releases that may 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, rules 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 of Biogas Conversion Projects and Fueling Stations, 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.

Environmental laws, rules and regulations have changed rapidly in recent years and generally have become more stringent over time, and we expect this trend to continue. The most material of these changes relate to the control of air emissions from the combustion equipment and turbine engines we use to generate Renewable Power from landfill biogas. Such equipment, including internal combustion engines, are subject to stringent federal and state permitting and air emissions requirements. California has taken an aggressive approach to setting standards for engine emissions, and standards already in place have caused us to not be able to operate some of our electric generating equipment in areas of that state. If other states were to follow California’s lead, we could face challenges in maintaining our electric generating operations and possibly, other operations in such jurisdictions.

Continued governmental and public emphasis on environmental issues can be expected to result in increased future investments for environmental control compliance at our facilities. Present and future environmental laws, rules and regulations, and interpretations of such laws, rules and regulations, applicable to our operations, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial costs or expenditures that could have a material adverse effect on our business, results of operations and financial condition. In January 2021, the current US presidential administration signed multiple executive orders related to the climate and environment. These executive orders (i) direct federal agencies to review and reverse more than one hundred actions taken by the previous US

presidential administration on or relating to the environment, (ii) instruct the Director of National Intelligence to prepare a national intelligence estimate on the security implications of the climate crisis and direct all agencies to develop strategies for integrating climate considerations into their international work, (iii) establish the National Climate Task Force, which assembles leaders from across twenty one federal agencies and departments, (iv) commit to environmental justice and new, clean infrastructure projects, (v) commence development of emissions reduction targets and (vi) establish the special presidential envoy for climate on the National Security Council. At this time, we cannot predict the outcome of any of these executive orders on our operations.

Existing and future changes to federal, state and local regulations and policies, including permitting requirements applicable to us, and enactment of new regulations and policies, may present technical, regulatory and economic barriers to the generation, purchase and use of Renewable Power and RNG, and may adversely affect the market for the associated Environmental Attributes. A failure on our part to comply with any laws, regulations or rules applicable to us may adversely affect our business, investments and results of operations.

The markets for Renewable Power, RNG and the associated Environmental Attributes are influenced by US federal and state governmental regulations and policies concerning such resources. These regulations and policies are frequently modified, which could result in a significant future reduction in the potential demand for Renewable Power, RNG and the associated Environmental Attributes. Any new governmental regulations applicable to our Biogas Conversion Projects or markets for Renewable Power, RNG or the associated Environmental Attributes may result in significant additional expenses or related development costs and as a result, could cause a significant reduction in demand by our current and future counterparties. Failure to comply with such requirements could result in (i) the disconnection and/or shutdown of the non-complying facility, (ii) our inability to sell Renewable Power or RNG from the non-complying facility, (iii) penalties and defaults arising from contracts with respect to production from the non-complying facility, (iv) the imposition of liens, fines, refunds and interest, and/or civil or criminal liability and (v) delays or failures in the development of new Biogas Conversion Projects and Fueling Stations.

The EPA annually sets proposed and actual RVOs for the RIN market 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 may be needed to stabilize the RIN market. The EPA annually sets proposed RVOs for D3 (cellulosic biofuel with a 60% GHG reduction requirement) RINs in accordance with the mandates established by the EISA. In June 2023, the EPA set RVOs for 2023 through 2025 via a new Set rule.

There can be no assurance that the EPA will timely set annual RVOs in the future or that the RVOs will continue to increase or be sufficient to satisfy the growing supply of RNG which may be targeted for the U.S. transportation fuel market. The EPA may set RVOs inaccurately or inconsistently, and the manner in which the EPA sets RVOs may change under legislative or regulatory revisions. Uncertainty as to how the Renewable Fuel Standard (“RFS”) program will continue to be administered and supported by the EPA under the current US presidential administration can create price volatility in the RIN market. Given this regulatory uncertainty, we cannot assure that (i) we will be able to monetize RINs at the same price levels as we have in the past, (ii) production shortfalls will not impact our ability to monetize RINs at favorable current pricing, and (iii) the rising price environment for RINs will continue.

On the state level, the economics of RNG are enhanced by low-carbon fuel initiatives, particularly a well-established LCFS program in California and similar developing programs in Oregon and Washington (with several other states also actively considering similar initiatives). In California’s case, in 2009, the California Air Resource Board (“CARB”) adopted LCFS regulations aimed at reducing the CI of transportation fuel sold and purchased in the state. A CI score is calculated as grams of CO₂ equivalent per megajoule of energy by the fuel. Under the California and California-type LCFS programs, the CI score is dependent upon a full lifecycle analysis that evaluates the GHG emissions associated with producing, transporting, and consuming the fuel. LCFS credits can be generated in three ways: (i) fuel pathway crediting that provides low carbon fuels used in California transportation, (ii) project-based crediting that reduces GHG emissions in the petroleum supply chain, and (iii) zero emission vehicle crediting that supports the build out of infrastructure. CARB awards these credits to RNG projects based on such project’s CI score relative to the targeted CI score for both gasoline and diesel fuels. The number of monetizable LCFS credits per unit of fuel increases with a lower CI score. We cannot assure that we will be able to maintain or reduce our CI score to monetize LCFS credits generated from our Biogas Conversion Projects. If we are unable to sell LCFS credits, it could adversely affect our business.

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 in general, or at unattractive prices, could adversely affect our business.

Additionally, our business is influenced by laws, rules and regulations that require reductions in carbon emissions and/or the use of renewable fuels, such as the programs under which we generate Environmental Credits. These programs and regulations, which encourage the use of RNG as a vehicle fuel, could expire or be repealed or amended for a variety of reasons. For example, parties with an interest in gasoline and diesel, electric or other alternative vehicles or vehicle fuels, including lawmakers, regulators, policymakers, environmental or advocacy organizations, producers of alternative vehicles or vehicle fuels or other powerful groups, may invest significant time and money in efforts to delay, repeal or otherwise negatively influence programs and regulations that promote RNG. Many of these parties have substantial resources and influence. Further, changes in 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 alternative fuels or alternative vehicles over RNG, could reduce the market demand for RNG as a vehicle fuel and harm our operating results, liquidity, and financial condition.

For instance, in certain states, including California, lawmakers and regulators have implemented various measures designed to increase the use of electric, hydrogen and other zero-emission vehicles, including establishing firm goals for the number of these vehicles operating on state roads by specified dates and enacting various laws and other programs in support of these goals. Although the influence and applicability of these or similar measures on our business remains uncertain, a focus on “zero tailpipe emissions” vehicles over vehicles such as those operating on RNG that have an overall net carbon negative emissions profile, but some tailpipe emissions, could adversely affect the market for our fuels.

All of our current electric generating facilities are qualifying small power production facilities (“QFs”) under the Federal Power Act and the Public Utility Regulatory Policies Act of 1978, as amended. We are permitted to make wholesale sales (that is, sales for resale) of renewable electricity, capacity, and ancillary services from our QFs with a net generating capacity that does not exceed 20 megawatts or that is an “eligible” facility as defined by section 3(17)(E) of the Federal Power Act without (a) obtaining authorization by FERC pursuant to the Federal Power Act to sell electric energy, capacity and/or ancillary services at market-based rates, (b) acceptance by FERC of a tariff providing for such sales, and (c) granting by FERC of such regulatory waivers and blanket authorizations as are customarily granted by FERC to holders of market-based rate authority, including blanket authorization under section 204 of the Federal Power Act to issue securities and assume liabilities (“MBR Authority”) or any other approval from the U.S. Federal Energy Regulatory Commission (“FERC”). A QF typically may not use any fuel other than a FERC-approved alternative fuel, but for limited use of commercial-grade fuel for certain specified start-up, emergency and reliability purposes. We are required to document the QF status of each of our facilities in applications or self-certifications filed with FERC, which typically requires disclosure of upstream facility ownership, fuel and size characteristics, power sales, interconnection matters, and related technical disclosures Congress could amend the Federal Power Act and eliminate QF status, in which case we would likely have to obtain MBR Authority and sell competitively in the market. If this were to happen, in all likelihood our QFs would not be competitive in the market place.

We currently do not intend to develop, construct or operate electric generating facilities that would require us to apply for and receive MBR Authority from FERC. Nevertheless, if we were to do so, eligibility for MBR Authority is predicated on a variety of factors, primarily including the overall market power that the power seller — together with all of its FERC-defined “affiliates” — has in the relevant market. FERC defines affiliates as entities with a common parent that own, directly or indirectly, 10% or more of the voting securities in the two entities. Accordingly, our eligibility and the eligibility of our affiliates to obtain and maintain MBR Authority for additional facilities, were we or such affiliate required to obtain such authority, would require an evaluation of the energy assets owned directly or indirectly by us and each of our affiliates, satisfying market-power limitations established by FERC. If our affiliates invest heavily in generating or other electric facilities in a particular geographic market, their market presence could make it difficult for us or our affiliates to obtain and maintain such MBR Authority, or to secure FERC authorization to acquire additional generating facilities, in that market.

Our market-based sales are subject to certain market behavior rules established by FERC, and if any of our Biogas Conversion Projects that generate Renewable Power are deemed to have violated such rules, we will be subject to potential disgorgement of profits associated with the violation, penalties, refunds of unlawfully collected amounts with interest, and, if a facility obtains MBR Authority, suspension or revocation of such MBR Authority. If such projects that had MBR

Authority were later to lose their MBR Authority, they would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and could become subject to the significant accounting, record-keeping, and reporting requirements that are typically imposed on vertically-integrated utilities with cost-based rate schedules. This could have a material adverse effect on the rates we are able to charge for power from our facilities maintaining MBR Authority, if any, that generate Renewable Power.

The regulatory environment for electric generation has undergone significant changes in the last several years due to federal and state policies affecting wholesale competition and the creation of incentives for the addition of large amounts of new renewable generation and, in some cases, transmission assets. These changes are ongoing, and we cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on our business.

Our biogas conversion project site owners and operators are also subject to extensive federal, state and local regulations and policies, including permitting requirements. Any failure on their part to comply with any laws, regulations, rules or permits, applicable to them may also adversely affect our business, investments and results of operations.

The operations of biogas conversion project site owners and operators are also subject to stringent and complex governmental regulations and policies at the federal, state and local level in the United States. Many complex laws, rules, orders and interpretations govern environmental protection, health, safety, land use, zoning, transportation and related matters. At times, such governmental regulations and policies may require biogas conversion project site owners and operators to curtail their operations or close sites temporarily or permanently, which may adversely impact our business, investments and results of operations.

Certain permits are required to build, operate and expand sites owned by biogas conversion project site owners and operators, and such permits have become more difficult and expensive to obtain and maintain. Permits may often take years to obtain as a result of numerous hearing and compliance requirements with regard to zoning, environmental and other regulations and are commonly subject to resistance from citizen or other groups and other political pressures, including allegations by such persons that a site is in violation of any applicable permits, laws or regulations. Failure by project site owners and operators to obtain or maintain any required permit to operate its site would adversely affect our production of Renewable Power, RNG and generation of the associated Environmental Attributes, as applicable.

A failure by biogas conversion project site owners and operators to comply with extensive federal, state and local regulations and policies, including permitting requirements, may result in the suspension or cessation of site operations, which would reduce or halt Renewable Power or RNG production and generation of the associated Environmental Attributes. Any such disruption could also damage the reputation of our brand. In the event our production of Renewable Power or RNG is disrupted, we may fail to meet the contractual obligations to some of our counterparties to deliver Renewable Power, RNG and the associated Environmental Attributes, in which case we would be subject to financial damage and/or penalty claims from these counterparties.

The financial performance of our business depends upon tax and other government incentives for the generation of RNG and Renewable Power, any of which could change at any time and such changes may negatively impact our growth strategy.

Our financial performance and growth strategy depend in part on governmental policies that support renewable generation and enhance the economic viability of owning Biogas Conversion Projects or Fueling Stations. These projects currently benefit from various federal, state and local governmental incentives such as investment tax credits, cash grants in lieu of investment tax credits, loan guarantees, Renewable Portfolio Standards (“RPS”) programs, modified accelerated cost-recovery system of depreciation and bonus depreciation. RNG specifically generates meaningful revenue through generation and monetization of Environmental Attributes provided for under several different programs, most commonly, RFS, LCFS and RPS.

Our provision for income taxes is subject to volatility and could be adversely affected by changes in tax laws or regulations, particularly changes in tax incentives in support of energy efficiency. The IRA contains extended and expanded clean energy tax credits such as ITCs, the PTC, and created other financial incentives designed to promote the development of certain domestic clean energy projects. In order to receive the full value of such credits and incentives, our projects must satisfy a number of requirements including prevailing wage and apprenticeship requirements. If we fail to comply with these requirements, the value of the credits may be limited, and we may become subject to financial penalties. Uncertainty remains under the IRA on which types of projects are eligible for the tax credits and incentives and how

projects can demonstrate compliance with the requirements, we may not receive full value of the tax credits and incentives, which could increase our income tax expense, reduce our net income and adversely impact the profitability of our projects or our ability to finance our projects.

On November 17, 2023, the Treasury and the IRS proposed regulations regarding ITCs on renewable energy projects where the IRS specified certain types of RNG equipment are ineligible for ITCs which could negatively impact the profitability of our RNG business and our ability to finance our RNG projects. On February 16, 2024, the Treasury and the IRS released a correction to the proposed regulations clarifying that certain of such equipment may be eligible for ITCs. These regulations are merely proposed, and the Treasury and the IRS are collecting and reviewing comments received regarding the proposed regulations. The proposed regulations also contain provisions that we believe create uncertainty relating to the ownership, installation or modification of equipment and property on which ITCs can be claimed. If the final regulations are enacted in a form that limits, in whole or in part, the amount of ITCs for certain of our construction costs, this would reduce the amount of ITCs available and thus could have a material adverse effect on our operations and our business.

There is also uncertainly if IRA incentives may be reduced or repealed in the future, especially following the 2024 elections. In addition, the timing of when assets are placed in service has in the past and could in the future impact our tax rate. If we experience unexpected delays in this timing, we may not be able to take advantage of ITCs as expected. If we are not able to utilize the ITCs as expected this could have an adverse effect of our financial results.

Many states have adopted RPS programs mandating that a specified percentage of electricity sales come from eligible sources of renewable energy. However, the regulations that govern the RPS programs, including pricing incentives for renewable energy and reasonableness guidelines for pricing that increase valuation compared to conventional power (such as a projected value for carbon reduction or consideration of avoided integration costs), may change. If the RPS requirements are reduced or eliminated, it could lead to fewer future power contracts or lead to lower prices for the sale of power in future power contracts, which could have a material adverse effect on our future prospects. Such material adverse effects may result from decreased revenues, reduced economic returns on Biogas Conversion Projects and other potential future investments or joint ventures, increased financing costs, and/or difficulty obtaining financing.

If we are unable to utilize various federal, state and local governmental incentives to acquire additional Biogas Conversion Projects or Fueling Stations in the future, or the terms of such incentives are revised in a manner that is less favorable to us, we may suffer a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, we face similar risks with respect to the RFS program. Any future changes to, federal, state and local regulations and policies, including permitting requirements applicable to us, and enactment of new regulations and policies, may present technical, regulatory and economic barriers to the generation, purchase and use of Renewable Power and RNG, and may adversely affect the market for the associated Environmental Attributes. A failure on our part to comply with any laws, regulations or rules, applicable to us may adversely affect our business, investments and results of operations.

We rely on interconnection, transmission and pipeline facilities that we do not own or control and that are subject to constraints within a number of our regions. If these facilities fail to provide us with adequate capacity or have unplanned disruptions, we may be restricted in our ability to deliver Renewable Power and RNG to our counterparties and we may either incur additional costs or forego revenues.

We depend on electric interconnection and transmission facilities and gas pipelines owned and operated by others to deliver the energy and fuel we generate at our Biogas Conversion Projects to our counterparties. Some of our electric generating Biogas Conversion Projects may need to hold electric transmission rights in order to sell power to purchasers that do not have their own direct access to our generators. Our access to electric interconnection and transmission rights is subject to tariffs developed by transmission owners, ISOs and RTOs, which have been filed with and accepted by FERC or the Public Utility Commission in the jurisdictions in question. These tariffs establish the price for transmission service, and the terms under which transmission service is rendered. Under FERC’s open access transmission rules, tariffs developed and implemented by transmission owners, ISOs and RTOs must establish terms and conditions for obtaining interconnection and transmission services that are not unduly discriminatory or preferential. However, as a generator and seller of power, we do not have any automatic right, in any geographic market, to firm, long-term, grid-wide transmission service without first requesting such service, funding the construction of any upgrades necessary to provide such service, and paying a transmission service rate. Physical constraints on the transmission system could limit the ability of our electric generating projects to dispatch their power output and receive revenue from sales of Renewable Power.

A failure or delay in the operation or development of these distribution channels or a significant increase in the costs charged by their owners and operators could result in the loss of revenues or increased operating expenses. Such failures or delays could limit the amount of Renewable Power our operating facilities deliver or delay the completion of our construction projects, which may also result in adverse consequences under our power purchase agreements and LFG rights agreements. Further, such failures, delays or increased costs could have a material adverse effect on our business, financial condition and results of operations.

Our RNG production projects are similarly interconnected with gas distribution and interstate pipeline systems that are necessary to deliver RNG. A failure or delay in the operation or development of these distribution or pipeline facilities could result in a loss of revenues or breach of contract because such a failure or delay could limit the amount of RNG that we are able to produce or delay the completion of our construction projects. In addition, certain of our RNG transportation capacity may be curtailed without compensation due to distribution and pipeline 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 contractual obligations and adversely affect our business. Additionally, we experience work interruptions from time to time due to federally required maintenance shutdowns of distribution and pipeline facilities.

We may acquire or develop RNG projects that require their own pipeline interconnections to available interstate pipeline and distribution networks. In some cases, these pipeline and distribution networks to which such projects are connected may cover significant distances. A failure in the construction or operation of these pipeline and distribution networks that causes the RNG project to be out of service, or subject to reduced service, could result in lost revenues because it could limit our production of RNG and the associated Environmental Attributes that we are able to generate.

We rely on third-party utility companies to provide our Biogas Conversion Projects with adequate utility supplies, including sewer, water, gas and electricity, in order to operate our Biogas Conversion Project facilities. Any failure on the part of such companies to adequately supply our facilities with such utilities, including any prolonged period of loss of electricity, may have an adverse effect on our business and results of operations.

We are dependent on third-party utility companies to provide sufficient utilities including sewer, water, gas and electricity, to sustain our operations and operate our Biogas Conversion Projects. Any major or sustained disruptions in the supply of utilities may disrupt our operations or damage our production facilities or inventories and could adversely affect our business, financial condition and results of operations. In addition, we consume a significant amount of electricity in connection with our Biogas Conversion Projects and any increases in costs or reduced availability of such utilities could have a negative impact on our business, financial condition and results of operations.

We are subject to risks associated with litigation or administrative proceedings that could materially impact our operations, including proceedings in the future related to our projects we subsequently acquire.

We are subject to risks and costs, including potential negative publicity, associated with lawsuits, in particular with respect to environmental claims and lawsuits or claims contesting the construction or operation of our Biogas Conversion Projects and Fueling Station projects. The result of and costs associated with defending any such lawsuit or claim, regardless of the merits and eventual outcome, may be material and could have a material adverse effect on our operations. In the future, we may be involved in legal proceedings, disputes, administrative proceedings, claims and other litigation that arise in the ordinary course of our business related to Biogas Conversion Projects or Fueling Stations. For example, individuals and interest groups may sue to challenge the issuance of a permit for a Biogas Conversion Project or a Fueling Station project, or seek to enjoin construction or operation of that facility. We may also become subject to claims from individuals who live in the proximity of our Biogas Conversion Projects and Fueling Stations based on alleged negative health effects related to our operations. In addition, we have been and may subsequently become subject to legal proceedings or claims contesting the construction or operation of our Biogas Conversion Projects and Fueling Stations.

Any such legal proceedings or disputes could delay our ability to complete construction of a Biogas Conversion Project or Fueling Station in a timely manner or at all, or materially increase the costs associated with commencing or continuing commercial operations of such projects. Settlement of claims and unfavorable outcomes or developments relating to such proceedings or disputes, such as judgments for monetary damages, injunctions or denial or revocation of permits, could have a material adverse effect on our ability to implement our growth strategy and, ultimately, our business, financial condition and results of operations.

We currently own, and in the future may acquire, certain assets in which we have limited control over management decisions, including through joint ventures, and our interests in such assets may be subject to transfer or other related restrictions.

We own, and in the future may acquire, certain Biogas Conversion Projects and Fueling Stations through joint ventures. In the future, we may invest in other projects with a joint venture or strategic partner. Joint ventures inherently involve a lesser degree of control over business operations, which could result in an increase in the financial, legal, operational or compliance risks associated with a Biogas Conversion Project or Fueling Station, including, but not limited to, variances in accounting internal control requirements. Our co-venture partners may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these assets optimally. To the extent we do not have a controlling interest in a Biogas Conversion Project or Fueling Station, our joint venture partners could take actions that decrease the value of our investment and lower our overall return. In addition, conflicts of interest may arise in the future with our joint venture partners, where our joint venture partners’ business interests are inconsistent with our and our stockholders’ interests. Further, disagreements or disputes with our joint venture partners could result in litigation, resulting in increase of expenses incurred and potentially limit the time and effort our officers and directors are able to devote to remaining aspects of our business, all of which could have a material adverse effect on our business, financial condition and results of operations. The approval of our joint venture partners also may be required for us to receive distributions of funds from assets or to sell, pledge, transfer, assign or otherwise convey our interest in such assets. Alternatively, our joint venture partners may have rights of first refusal, rights of first offer or other similar rights in the event of a proposed sale or transfer of our interests in such assets. In addition, we may have, and correspondingly our joint venture partners may have, rights to force the sale of the joint venture upon the occurrence of certain defaults or breaches by the other partner or other circumstances, and there may be circumstances in which our joint venture partner can replace our affiliated entities that provide operation and maintenance and asset management services if they default in the performance of their obligations to the joint venture. These restrictions and other provisions may limit the price or interest level for our interests in such assets, in the event we want to sell such interests.

Our gas rights agreements, power purchase agreements, fuel-supply agreements, interconnection agreements, RNG dispensing agreements and other agreements, including contracts with owners and operators of biogas conversion project sites, often contain complex provisions, including those relating to price adjustments, calculations and other terms based on gas price indices and other metrics, as well as other terms and provisions, the interpretation of which could result in disputes with counterparties that could materially affect our results of operations and customer or other business relationships.

Certain of our gas rights agreements, power purchase agreements, fuel supply agreements, interconnection agreements, RNG dispensing agreements and other agreements, including contracts with owners and operators of biogas conversion project sites, require us to make payments or adjust prices to counterparties based on past or current changes in natural gas price indices, project productivity or other metrics and involve complex calculations.

Moreover, the underlying indices governing payments under such 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 such agreements. Any such disputes could adversely affect Biogas Conversion Project revenues, including revenue from associated Environmental Attributes, profit margins, customer or supplier relationships, or lead to costly litigation, the outcome of which we would be unable to predict.

Market Risks Related to Our Business

A reduction in the prices we can obtain for the Environmental Attributes generated from RNG, which include RINs, ISCC Carbon Credits, LCFS credits, and other incentives, could have a material adverse effect on our business prospects, financial condition and results of operations.

A significant portion of our revenues comes from the sale of Environmental Attributes, which exist because of legal and governmental regulatory requirements. A change in law or in governmental policies concerning renewable fuels, landfill or animal waste site biogas or the sale of Environmental Attributes could be expected to affect the market for, and the pricing of, the Environmental Attributes that we can generate through production at our Biogas Conversion Projects. A reduction in the prices we receive for Environmental Attributes, or a reduction in demand for them, whether through market forces generally, through the actions of market participants generally, or through the consolidation or elimination of

participants competing in the market for the purchase and retirement of Environmental Attributes, could have a material adverse effect on our results of operations.

The volatility in the price of oil, gasoline, diesel, natural gas, RNG, or Environmental Attribute prices could adversely affect our business.

Historically, the prices of Environmental Attributes, RNG, natural gas, crude oil, gasoline and diesel have been volatile and this volatility may continue to increase in future. Factors that may cause volatility in the prices of Environmental Attributes, RNG, natural gas, crude oil, gasoline and diesel include, among others, (i) changes in supply and availability of crude oil, RNG and natural gas; (ii) governmental regulations; (iii) inventory levels; (iv) consumer demand; (v) price and availability of alternatives; (vi) weather conditions; (vii) negative publicity about crude oil or natural gas drilling; (viii) production or transportation techniques and methods; (ix) macro-economic environment and political conditions; (x) transportation costs; and (xi) the price of foreign imports. If the prices of crude oil, gasoline and diesel decline, or if the price of RNG or natural gas increases without corresponding increases in the prices of crude oil, gasoline and diesel or Environmental Attributes, we may not be able to offer our counterparties an attractive price advantage for our vehicle fuels. The market adoption of our vehicle fuels could be slowed or limited, and/or we may be forced to reduce the prices at which we sell our vehicle fuels in order to try and attract new counterparties or prevent the loss of demand from existing counterparties. In addition, we expect that natural gas and crude oil prices will remain volatile for the near future because of market uncertainties over supply and demand, including but not limited to the current state of the world economies, energy infrastructure and other factors. Fluctuations in natural gas prices affect the cost to us of the natural gas commodity. High natural gas prices adversely affect our operating margins when we cannot pass the increased costs to our counterparties. Conversely, lower natural gas prices reduce our revenue when the commodity cost is passed to our counterparties.

Pricing conditions may also exacerbate the cost differential between vehicles that use our vehicle fuels and gasoline or diesel-powered vehicles, which may lead operators to delay or refrain from purchasing or converting to vehicles running on our fuels. Generally, vehicles that use our fuels cost more initially than gasoline or diesel-powered vehicles because the components needed for a vehicle to use our vehicle fuels add to the vehicle’s base cost. Operators then seek to recover the additional base cost over time through a lower cost to use alternative vehicle fuels. Operators may, however, perceive an inability to timely recover these additional initial costs if alternative vehicle fuels are not available at prices sufficiently lower than gasoline and diesel. Such an outcome could decrease our potential customer base and harm our business prospects.

We face significant upward pricing pressure in the market with respect to our securing the biogas rights necessary for proposed new Biogas Conversion Projects and our conversion of existing Renewable Power rights to RNG rights on existing Biogas Conversion Projects that we plan to convert.

We must reach agreement with the prospective biogas project site owner or developer in order to secure the biogas rights necessary for each proposed Biogas Conversion Project. Additionally, each project typically requires a site lease, access easements, permits, licenses, rights of way or other similar agreements. Historically, in exchange for the biogas rights and additional agreements, we have paid the site owner and/or developer a royalty or other similar payment based on revenue generated by the project or volume of biogas used by the project. Over recent years, as competition for development of biogas conversion project sites has increased and biogas project site owners and developers have become more sophisticated, it has become increasingly common for the prospective biogas project site owners and developers to ask for or require larger royalties or similar payments in order to secure the biogas rights. In addition, it is becoming increasingly common for some prospective biogas project site owners or developers to ask for or require equity participation in the prospective project.

In addition, we face similar pricing pressures when we attempt to renew our biogas rights on existing Biogas Conversion Projects at the end of their contractual periods and in situations where we plan to convert existing Renewable Power projects to RNG projects.

These pricing pressures could lead us to decide not to pursue certain prospective Biogas Conversion Projects or not to pursue the renewal or conversion of one or more existing Renewable Power projects and, accordingly, negatively impact our overall financial condition, results of operations and prospects. These pricing pressures could also impact the profitability of prospective Biogas Conversion Projects, and, accordingly, negatively impact our overall financial condition, results of operations and prospects.

We currently face declining market prices for LCFS credits specifically within California as well as significant upward pressure on the costs associated with dispensing RNG specifically within California to generate the LCFS credits.

The market prices for LCFS credits specifically within California have declined over the past year, and the market for dispensing RNG with relatively low CI scores in California has become increasingly competitive because of increasing supply of RNG with these relatively low CI scores. As such, fleet operators using vehicles fueled by natural gas have been able to demand RNG marketers like us provide them with greater economic incentives for allowing us to dispense the fuel at the Fueling Stations, typically in the form of a greater share of our marketing fee or a greater share in the monetary value of the Environmental Attributes we generate when dispensing the fuel. The persistence of the current California dynamic is dependent upon future market developments, and as such the LCFS credits that we generate and sell may or may not produce future revenue that is comparable to historical LCFS revenue.

A prolonged environment of low prices or reduced demand for Renewable Power could have a material adverse effect on our business prospects, financial condition and results of operations.

Long-term Renewable Power and RNG prices may fluctuate substantially due to factors outside of our control. The price of Renewable Power and RNG can vary significantly for many reasons, including: (i) increases and decreases in generation capacity in our markets; (ii) changes in power transmission or fuel transportation capacity constraints or inefficiencies; (iii) power supply disruptions; (iv) weather conditions; (v) seasonal fluctuations; (vi) changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices; (vii) development of new fuels or new technologies for the production of power; (viii) federal and state regulations; and (ix) actions of the Independent System Operators (“ISOs”) and regional transmission organizations (“RTOs”) that control and administer regional power markets.

Increased rates of recycling and legislation encouraging recycling, increased use of waste incineration, advances in waste disposal technology, decreased demand for meat and livestock products could decrease the availability or change the composition of waste for biogas conversion project gas.

The volume and composition of LFG produced at open landfill sites depends in large part on the volume and composition of waste sent to such landfill sites, which could be affected by a number of factors. For example, increased rates of recycling or increased use of waste incineration could decrease the volume of waste sent to landfills, while organics diversion strategies such as composting can reduce the amount of organic waste sent to landfills. There have been numerous federal and state regulations and initiatives over the recent years that have led to higher levels of recycling of paper, glass, plastics, metal and other recyclables, and there are growing discussions at various levels of government about developing new strategies to minimize the negative environmental impacts of landfills and related emissions, including diversion of biodegradable waste from landfills. Although many recyclable materials other than paper do not decompose and therefore do not ultimately contribute to the amount of LFG produced at a landfill site, recycling and other similar efforts may have negative effects on the volume and proportion of biodegradable waste sent to landfill sites across the United States. As a consequence, the volume and composition of waste sent to landfill sites from which our Biogas Conversion Projects collect LFG could change, which could adversely affect our business operations, prospects, financial condition and operational results.

In addition, research and development activities are currently ongoing to provide alternative and more efficient technologies to dispose of waste, to produce by-products from waste and to produce energy, and an increasing amount of capital is being invested to find new approaches to waste disposal, waste treatment and energy generation.

It is possible that this deployment of capital may lead to advances which could adversely affect our sources of LFG or provide new or alternative methods of waste disposal or energy generation that become more accepted, or more attractive, than landfills.

We currently use, and may continue in the future to use, forward-sale and hedging arrangements, to mitigate certain risks, but the use of such arrangements could have a material adverse effect on our results of operations.

We currently use, and may continue in the future to use, forward sales transactions to sell Environmental Attributes and Renewable Power before they are generated. In addition, we use interest rate swaps to manage interest rate risk. We may use other types of hedging contracts, including foreign currency hedges if we expand into other countries. If we elect to enter into such hedges, the related asset could recognize financial losses on these arrangements as a result of volatility in the market values of the underlying asset or if a counterparty fails to perform under a contract. If actively quoted market

prices and pricing information from external sources are not available, the valuation of such contracts would involve judgment or the use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of such contracts. If the values of such contracts change in a manner that we do not anticipate, or if a counterparty fails to perform under such a contract, it could harm our business, financial condition, results of operations and cash flows.

Risks Related to Our Business and Industry

Additional Risk Factors Relating to Our Biogas Capture Business

Our ability to acquire, convert, develop and operate Biogas Conversion Projects, as well as expand production at current Biogas Conversion Projects, is subject to many risks.

Our business strategy includes (i) the conversion of LFG projects from Renewable Power to RNG production where we already controls biogas gas rights, (ii) growth through the procurement of LFG rights and manure rights to develop new RNG projects, (iii) the acquisition and expansion of existing Biogas Conversion Projects, and (iv) growth through the procurement of rights to other sources of biogas for production of additional transportation fuels and generation of associated Environmental Attributes. This strategy depends on our ability to successfully convert existing LFG projects and identify and evaluate acquisition opportunities and complete new Biogas Conversion Projects or acquisitions on favorable terms. However, we cannot guarantee that we will be able to successfully identify new opportunities, acquire additional biogas rights and develop new RNG projects or convert existing projects on favorable terms or at all. In addition, we may compete with other companies for these development and acquisition opportunities, which may increase our costs or cause us to refrain from making acquisitions at all.

We may also achieve growth through the expansion of production at certain of our current Biogas Conversion Projects as the related landfills and dairy farms are expanded or otherwise begin to produce more gas or manure, respectively, but we cannot guarantee that we will be able to reach or renew the necessary agreements with site owners on economically favorable terms or at all. If we are unable to successfully identify and consummate future Biogas Conversion Project opportunities or acquisitions of Biogas Conversion Projects, or expand RNG production at our current Biogas Conversion Projects, it will impede our ability to execute our growth strategy. Further, we may also experience delays and cost overruns in converting existing facilities from Renewable Power to RNG production. During the conversion of existing projects, there may be a gap in revenue while the electricity project is offline until the conversion is completed and the new RNG facility commences operations, which may adversely affect our financial condition and results of operations.

Our ability to acquire, convert, develop and operate Biogas Conversion Projects, as well as expand production at current Biogas Conversion Projects, is subject to several additional risks, including:

•regulatory changes that affect the value of RNG and the associated Environmental Attributes, which could have a significant effect on the financial performance of our Biogas Conversion Projects and the number of potential Biogas Conversion 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 and expenses;

•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 limit the LFG resource that we currently target for our Biogas Conversion Projects;

•substantial construction risks, including the risk of delay, that may arise due to forces outside of our control, such as those related to engineering and environmental problems, inclement weather, inflationary pressures on materials and labor, and supply chain and labor disruptions;

•operating risks and the effect of disruptions on our business, including the effects of global health crises, weather conditions, catastrophic events, such as fires, explosions, earthquakes, droughts and acts of terrorism, and other force majeure events that impact us, our counterparties, suppliers, distributors and subcontractors;

•accidents involving personal injury or the loss of life;

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

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

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

•a decrease in the availability, increased pricing on, and a delay in the timeliness of delivery of raw materials and components, necessary for the Biogas Conversion Projects to function or necessary for the conversion of a Biogas Conversion Projects from Renewable Power to RNG production;

•obtaining and keeping in good standing permits, authorizations and consents from local city, county, state and US federal government agencies and organizations;

•penalties, including potential termination, under short-term and long-term contracts for failing to produce or deliver a sufficient quantity and acceptable quality of RNG in accordance with our contractual obligations;

•unknown regulatory changes related to the transportation of RNG, which may increase the transportation cost for delivering under our contracts then in effect;

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

•difficulties in identifying, obtaining and permitting suitable sites for new Biogas Conversion Projects.

Any of these factors could prevent us from acquiring, developing, converting, operating or expanding our Biogas Conversion Projects, or otherwise adversely affect our business, growth potential, financial condition and results of operations.

Acquiring Biogas Conversion Projects involves numerous risks, including potential exposure to pre-existing liabilities, unanticipated costs in acquiring and implementing the project, and lack of or limited experience in new geographic markets.

The acquisition of existing Biogas Conversion Projects involves numerous risks, many of which may not be discoverable through the due diligence process, including exposure to previously existing liabilities and unanticipated costs associated with the pre-acquisition period; difficulty in integrating the acquired projects into our existing business; and, if the projects are in new markets, the risks of entering markets where we have limited experience, less knowledge of differences in market terms for gas rights agreements and dispensing agreements, and, for international projects, possible exposure to exchange-rate risk to the extent we need to finance development and operations of foreign projects to repatriate earnings generated by such projects. While we perform due diligence on prospective acquisitions, we may not be able to discover all potential operational deficiencies in such projects. A failure to achieve the financial returns we expect when we acquire Biogas Conversion Projects could have a material adverse effect on our ability to implement our growth strategy and, ultimately, our business, financial condition and results of operations.

Additional risks related to acquiring existing projects, include:

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

•the acquired companies or assets may 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 counterparties 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 certain areas, such as tax planning and financial reporting;

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

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

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

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

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

•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.

Our Biogas Conversion Projects face operational challenges, including among other things the breakdown or failure of equipment or processes or performance below expected levels of output or efficiency due to wear and tear of our equipment, latent defects, design or operator errors, force majeure events, or lack of transmission capacity or other problems with third party interconnection and transmission facilities.

The ongoing operation of our Biogas Conversion Projects involves risks that include the breakdown or failure of equipment or processes or performance below expected levels of output or efficiency due to wear and tear of our equipment, latent defects, design or operator errors or force majeure events, among other factors. Operation of our Biogas Conversion Projects also involves risks that we will be unable to transport our product to our counterparties in an efficient manner due to a lack of capacity or other problems with third party interconnection and transmission facilities. Unplanned outages of equipment, including extensions of scheduled outages due to mechanical failures or other problems, occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenue. Biogas conversion project site owners and operators can also impact our production if, in the course of ongoing operations, they damage the site’s biogas collection systems. Our inability to operate our facilities efficiently, manage capital expenditures and costs and generate earnings and cash flow could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are generally also required under many of our agreements to deliver a minimum quantity of Renewable Power, RNG and/or the associated Environmental Attributes to the counterparty. Unless we can rely on a force majeure or other provisions in the related agreements, falling below such a threshold could subject us to financial expenses and penalties, as well as possible termination of key agreements and potential violations of certain permits, which could further impede our ability to satisfy production requirements. Therefore, any unexpected reduction in output at any of our Biogas Conversion Projects that leads to any of these outcomes could have a material adverse effect on our business, financial condition and results of operations.

An unexpected reduction in RNG production by third-party producers of RNG with whom we maintain marketing agreements to purchase RNG and/or the associated Environmental Attributes, or their inability or refusal to deliver such RNG or Environmental Attributes as provided under such agreements, may have a material adverse effect on our results of operations and could adversely affect or performance under associated dispensing agreements.

The success of our RNG business depends, in large part, on our ability to (i) secure, on acceptable terms, an adequate supply of RNG and/or Environmental Attributes from third-party producers, (ii) sell RNG in sufficient volumes and at prices that are attractive to counterparties and produce acceptable margins for us, and (iii) generate and monetize Environmental Attributes under applicable federal or state programs at favorable prices. If we fail to maintain and build new relationships with third party producers of RNG, we may be unable to supply RNG and the associated Environmental Attributes to meet the demand of our counterparties, which could adversely affect our business.

Our ability to dispense an adequate amount of RNG is subject to risks affecting RNG production. Biogas Conversion Projects that produce RNG often experience unpredictable production levels or other difficulties due to a variety of factors, including, among others, (i) problems with equipment, (ii) severe weather, pandemics, or other health crises, (iii) construction delays, (iv) technical difficulties, (v) high operating costs, (vi) limited availability, or unfavorable composition of collected feedstock gas, and (vii) plant shutdowns caused by upgrades, expansion or required maintenance. In addition, increasing demand for RNG will result in more robust competition for supplies of RNG, including from other vehicle fuel providers, gas utilities (which may have distinct advantages in accessing RNG supply including potential use of ratepayer funds to fund RNG purchases if approved by a utility’s regulatory commission) and other users and providers. If we or any of our third party RNG suppliers experience these or other difficulties in RNG production processes, or if competition for RNG development projects and supply increases, then our supply of RNG and our ability to resell it as a vehicle fuel and generate the associated Environmental Attributes could be jeopardized.

Construction, development and operation of our Biogas Conversion Projects involves significant risks and hazards.

Biogas Conversion Projects as well as construction and operation of Fueling Stations involve hazardous activities, including acquiring and transporting fuel, operating large pieces of rotating equipment and delivering our renewable electricity and RNG to interconnection and transmission systems, including gas pipelines. Hazards such as fire, explosion, structural collapse and machinery failure are inherent risks in our operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment and contamination of, or damage to, the environment. The occurrence of any one of these hazards may result in curtailment or termination of our operations or liability to third parties for damages, environmental cleanup costs, personal injury, property damage and fines and/or penalties, any of which could be substantial.

Our Biogas Conversion Projects facilities and Fueling Stations or those that we otherwise acquire, construct or operate may be targets of terrorist activities, as well as events occurring in response to or in connection with them, that could result in full or partial disruption of our facilities’ ability to generate, transmit, transport or distribute electricity or RNG. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. Hostile cyber intrusions, including those targeting information systems, as well as electronic control systems used at the generating plants and for the related distribution systems, could severely disrupt our business operations and result in loss of service to our counterparties, as well as create significant expense to repair security breaches or system damage. In the past we have experienced cyber security breaches, which we believe have not had a significant impact on the integrity of our systems or the security of data, including personal information maintained by us, but there can be no assurance that any future breach or disruption will not have a material adverse effect on our business, financial condition or operations.

Furthermore, some of our facilities are located in areas prone to extreme weather conditions, most notably extreme cold. Certain of our other Biogas Conversion Projects and Fueling Stations as well as certain key vendors conduct their operations in other locations, such as California and Florida, that are susceptible to natural disasters. The frequency of weather-related natural disasters may be increasing due to the effects of greenhouse gas emissions or related climate change effects. The occurrence of natural disasters such as tornados, earthquakes, droughts, floods, wildfires or localized extended outages of critical utilities or transportation systems, or any critical resource shortages, affecting us could cause a significant interruption in our business or damage or destroy our facilities.

We rely on warranties from vendors and obligate contractors to meet certain performance levels, but the proceeds from such warranties or performance guarantees may not cover lost revenues, increased expenses or liquidated damages payments, should we experience equipment breakdown or non-performance by our contractors or vendors. We also maintain an amount of insurance protection that we consider adequate to protect against these and other risks, but we cannot provide any assurance that our insurance will be sufficient or effective under any or all circumstances and against any or all hazards or liabilities to which we may be subject. Also, our insurance coverage is subject to deductibles, caps, exclusions and other limitations. A loss for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations and cash flows. Because of rising insurance costs and changes in the

insurance markets, we cannot provide any assurance that our insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Our insurance policies are subject to annual review by our insurers and may not be renewed on similar or favorable terms or at all. Any losses not covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our failure to dispense a specified quality or quantity of RNG could have a material adverse effect on our financial condition and results of operations, by subjecting us to, among other things, possible penalties or terminations under the various contractual arrangements under which we operate, including pursuant to a purchase and sale agreement related to the sale of our Environmental Attributes.

Our RNG business consists of producing RNG from Biogas Conversion Projects, procuring RNG from third party producers, and dispensing this RNG to counterparties through Fueling Stations and other potential end markets to generate and monetize the associated Environmental Attributes. If we fail to produce and dispense a specified quality or quantity of RNG, our business may be adversely impacted.

As an RNG supplier the quality and quantity of RNG we produce at our Biogas Conversion Projects may be negatively affected by, among other things, lack of feedstock or the relative mix in the components of the feedstock, mechanical breakdowns, faulty technology, competitive markets or changes to the laws and regulations that mandate the use of renewable energy sources. In addition, we rely in part on third party suppliers to provide us with certain amounts of the specified quality and quantity of RNG that we are obligated to deliver under contractual commitments to our distribution counterparties but that we have not otherwise produced at our Biogas Conversion Projects.

If we are unable to obtain an adequate supply of RNG through a combination of Biogas Conversion Project production and supplies from third party RNG producers, we may be forced to pay a financial penalty under such contracts, including under a purchase and sale agreement under which we market a substantial majority of our Environmental Attributes through NextEra. Even if we are able to produce and obtain an adequate supply of RNG to satisfy the quantity requirements of our counterparties, RNG and the associated Environmental Attributes must also meet or exceed quality standards. If we and our third party suppliers are unable to meet applicable quality standards, through one or more of the factors discussed above or otherwise, we could be subject to financial penalties under such contracts.

In connection with the marketing of the Environmental Attributes generated from our activities, in November 2021, we signed a purchase and sale agreement with NextEra providing for the exclusive purchase by NextEra of 90% of our Environmental Attributes (RINs and LCFS credits), including those generated by our owned Biogas Conversion Projects and those granted to us in connection with dispensing of RNG on behalf of third-party projects. Under the agreement, we are to receive the net proceeds paid to NextEra by NextEra customers for the purchase of such Environmental Attributes (or in certain circumstances an index-based price or pre-negotiated price) less a specified discount. The agreement provides for an initial five year term, followed by automatic one-year renewals unless terminated by either party at least 90 days prior to the last day of the initial term or then-current renewal term.

Under the agreement, we have committed to sell a minimum quarterly volume of Environmental Attributes to NextEra, which if not satisfied on a cumulative basis (giving credit for certain excess volume sold to NextEra during the contract term) as of the end of the contract term (or upon an early termination of the agreement) would result in our paying NextEra a shortfall payment calculated by (i) multiplying the amount of the volume shortfall by a fraction of the then-current index price of the Environmental Attribute and (ii) adding a specified premium (the “Shortfall Amount”). Similarly, if the agreement is terminated by NextEra due to an event of default (generally defined as a failure by us to pay any undisputed amounts under the agreement, a material uncured breach of our representations or warranties or other obligations under the agreement, or the dissolution, bankruptcy or insolvency of us or certain of our affiliates), NextEra would be entitled to receive, without any duplication, any then-current Shortfall Amount plus an accelerated payment calculated based off of the remaining minimum quarterly volume commitments for the balance of the initial term (or for the next four quarters of the next renewal term, if neither party had provided notice of non-renewal as described above prior to the commencement of such renewal term), which accelerated payment would be similarly calculated by (i) multiplying such remaining minimum quarterly volume commitments by a fraction of the then-current index price of the Environmental Attribute and (ii) adding a specified premium. The amount of such potential payments declines over the course of the contract term as we deliver Environmental Attribute volume under the contract. Were, however, the agreement to be terminated as of the date of this report and we were not to deliver any further Environmental Attribute volume to NextEra under the agreement, the maximum potential payment to NextEra under these provisions would be approximately $9.9 million based on current market prices for such Environmental Attributes.

The success of our RNG projects depends on our ability to timely generate and ultimately receive certification of the Environmental Attributes associated with our RNG production and sale. A delay or failure in the certification of such Environmental Attributes could have a material adverse effect on the financial performance of our Biogas Conversion Projects.

We are required to register our RNG projects 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.

Maintenance, expansion and refurbishment of our Biogas Conversion Projects involve the risk of unplanned outages or reduced output, resulting from among other things periodic upgrading and improvement, unplanned breakdowns in equipment, and forced outages.

Our Biogas Conversion Project facilities may require periodic upgrading and improvement. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce our facilities’ generating capacity below expected levels, reducing our revenues and jeopardizing our ability to earn profits and adversely affect our business, financial condition and results of operations. If we make major modifications to our facilities, such modifications may result in material additional capital expenditures. We may also choose to repower, refurbish or upgrade our facilities based on our assessment that such expenditures will provide adequate financial returns. Such facility modifications require time before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future power and renewable natural gas prices. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In order to secure development, operational, dispensing and other necessary contract rights for our Biogas Conversion 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 Biogas Conversion Projects generally lasts from 20 to 48 months, on average. Prior to signing a development agreement, 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 Biogas Conversion Project on that site. 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 4 to 12 months or longer for the Biogas Conversion 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.

Our Biogas Conversion Projects may not produce expected levels of output, and the amount of Renewable Power or RNG actually produced at each of our respective projects will vary over time, and, therefore so will generation of associated Environmental Attributes.

Our Biogas Conversion Projects rely on organic material, the decomposition of which causes the generation of gas consisting primarily of methane. The Biogas Conversion Projects use such methane gas to generate Renewable Power or RNG. The estimation of biogas production volume is an inexact process and dependent on many site-specific conditions, including the estimated annual waste volume, composition of waste, regional climate and the capacity and construction of

the site. Production levels are subject to a number of additional risks, including (i) a failure or wearing out of our or our landfill operators’, counterparties’ or utilities’ equipment; (ii) an inability to find suitable replacement equipment or parts; (iii) less than expected supply or quality of the project’s source of biogas and faster than expected diminishment of such biogas supply; or (iv) volume disruption in our fuel supply collection system. As a result, the volume of Renewable Power or RNG generated from such sites may in the future vary from our initial estimates, and those variations may be material. In addition, we have in the past incurred, and may in the future incur, material asset impairment charges if any of our Biogas Conversion Projects incur operational issues that indicate our expected future cash flows from the relevant project are less than the project’s carrying value. Any such impairment charge could adversely affect our operating results in the period in which the charge is recorded.

In addition, in order to maximize collection of LFG, we may need to take various measures, such as drilling additional gas wells in the landfill sites to increase LFG collection, balancing the pressure on the gas field based on the data collected by the landfill site operator from the gas wells to ensure optimum LFG utilization and ensuring that we match availability of engines and related equipment to availability of LFG. There can be no guarantee that we will be able to take all necessary measures to maximize collection. In addition, the LFG available to our LFG projects is dependent in part on the actions of the landfill site owners and operators. We may not be able to ensure the responsible management of the landfill site by owners and operators, which may result in less than optimal gas generation or increase the likelihood of “hot spots” occurring. Hot spots can temporarily reduce the volume of gas that may be collected from a landfill site, resulting in a lower gas yield.

Biogas projects utilizing other types of feedstock, specifically livestock waste and dairy farm projects, typically produce significantly less RNG than landfill facilities. As a result, the commercial viability of such projects is more dependent on various factors and market forces outside of our control, such as changes to law or regulations that could affect the value of such projects or the incentives available to them. In addition, there are other factors currently unknown to us that may affect the commercial viability of other types of feedstock. Moreover, fluctuations in manure supply, the end use markets and the spread of diseases among herds could have a material impact on the success and completion of our Biogas Conversion Projects. As such, continued expansion into other types of feedstock could adversely affect our business, financial condition, and results of operations.

Our business plans include expanding from Renewable Power and RNG production projects into additional transportation-related infrastructure, including production and development of hydrogen vehicle Fueling Stations. Any such expansions may present unforeseen challenges and result in a competitive disadvantage relative to our more-established competitors in the markets into which we wish to expand.

We currently operate Biogas Conversion Projects that convert primarily landfill biogas into Renewable Power and RNG. However, we are actively developing projects that use anaerobic digesters to capture and convert emissions into low-carbon RNG, electricity and green hydrogen, and may expand into additional feedstocks in the future. We are also actively developing hydrogen fueling infrastructure. In addition, we are actively considering expansion into other lines of business, including carbon sequestration and Renewable Power for our projects, and the production of green hydrogen. These initiatives could expose us to increased operating costs, unforeseen liabilities or risks, and regulatory and environmental concerns associated with entering new sectors of the energy industry, including requiring a disproportionate amount of our management’s attention and resources, which could have an adverse impact on our business as well as place us at a competitive disadvantage relative to more established non-LFG market participants.

Sequestering CO2 is subject to numerous laws and regulations with uncertain permitting timelines and costs. We also intend to explore the production of renewable hydrogen sourced from a number of our projects’ RNG, and we may enter into long-term fixed price off-take contracts for green hydrogen that we may produce at our projects.

We are currently working with a leading developer of on-site hydrogen generators to put in place construction design and services agreements in order to develop hydrogen gas-as-a-service offerings at Fueling Stations. We do not have an operating history in the green hydrogen market and our forecasts are based on uncertain operations in the future.

Some LFG projects in which we might invest in the future may be subject to cost-of-service rate regulation, which would limit our potential revenue from such LFG projects. If we invest, directly or indirectly, in an electric transmitting LFG project that allows us to exercise transmission market power, FERC could require our affiliates with MBR Authority to implement mitigation measures as a condition of maintaining our or our affiliates’ MBR Authority. FERC regulations limit using a transmission project for proprietary purposes, and we may be required to offer others (including competitors)

open-access to our transmission asset, should we acquire one. Such acquisitions could have a material adverse effect on our business, financial condition and results of operations.

Our gas and manure rights agreements for Biogas Conversion Projects are subject to certain conditions. A failure to satisfy such conditions could result in the loss of such rights.

Our gas and manure rights agreements for Biogas Conversion Projects generally require that we achieve commercial operations for a project as of a specified date. If we do not satisfy such a deadline, the agreement may be terminated at the option of the biogas conversion project site owner without any reimbursement of any portion of the purchase price paid for the gas or manure rights or any other amounts we have invested in the project. Delays in construction or delivery of equipment may result in our failing to meet the commercial operations deadline in a gas or manure rights agreement. The denial or loss of a permit essential to a Biogas Conversion Project could impair our ability to construct or operate a project as required under the relevant agreement. Delays in the review and permitting process for a project can also impair or delay our ability to construct or acquire a project and satisfy any commercial operations deadlines, or increase the cost such that the project is no longer attractive to us.

Furthermore, certain of our gas and manure rights agreements for Biogas Conversion Projects require us to purchase a certain amount of LFG and manure, respectively. Any issues with our production at the corresponding projects, including due to weather, unplanned outages or transmission problems, to the extent not caused by the landfill or dairy farm, or covered by force majeure provisions in the relevant agreement, could result in failure to purchase the required amount of LFG or manure and the loss of these gas rights. Our gas and manure rights agreements often grant us the right to build additional generation capacity in the event of increased supply, but failure to use such increased supply after a prescribed period of time can result in the loss of these rights. In addition, we typically need approval from landfill owners in order to implement Renewable Power-to-RNG conversion projects, and we are also dependent on landfill owners for additional gas rights as well as land leases and easements for these conversion projects.

Additional Risk Factors Relating to Our Dispensing Business

Our commercial success depends in part on our ability to identify, acquire, develop and operate public and private Fueling Stations for public and commercial fleet vehicles in order to dispense RNG for use as vehicle fuel and generate the associated Environmental Attributes.

Our specific focus on RNG to be used as a transportation fuel in the United States exposes us to risks related to the supply of and demand for RNG and the associated Environmental Attributes, the cost of capital expenditures, governmental regulation, and economic conditions, among other factors. As an RNG dispenser we may also be negatively affected by lower RNG production resulting from lack of feedstock, mechanical breakdowns, faulty technology, competitive markets or changes to the laws and regulations that mandate the use of renewable energy sources.

In addition, other factors related to the development and operation of renewable energy projects could adversely affect our business, including: (i) changes in pipeline gas quality standards or other regulatory changes that may limit our ability to transport RNG on pipelines or increase the costs of processing RNG; (ii) construction risks, including the risk of delay, that may arise because of inclement weather or labor disruptions; (iii) operating risks and the effect of disruptions on our business; (iv) budget overruns and exposure to liabilities because of unforeseen environmental, construction, technological or other complications; (v) failures or delays in obtaining desired or necessary rights, including leases and feedstock agreements; and (vi) failures or delays in obtaining and keeping in good standing permits, authorizations and consents from local city, county, state and US federal government agencies and organizations. Any of these factors could prevent completion or operation of projects, or otherwise adversely affect our business, financial condition, and results of operations.

Our success is dependent on the willingness of commercial fleets and other counterparties to adopt, and continue use of RNG, which may not occur in a timely manner, at expected levels or at all. Our vehicle fleet counterparties may choose to invest in renewable vehicle fuels other than RNG.

Our success is highly dependent on the adoption by commercial fleets and other consumers of natural gas vehicle fuels, which has been slow, volatile and unpredictable in many sectors. For example, adoption and deployment of natural gas in heavy and medium-duty trucking has been slower and more limited than we anticipated. If the market for natural gas vehicle fuels does not develop at improved rates or levels, or if a market develops but we are not able to capture a

significant share of the market or the market subsequently declines, our business, growth potential, financial condition, and operating results would be harmed.

Additional factors that may influence the adoption of natural gas vehicle fuels, many of which are beyond our control, include, among others:

•lack of demand for trucks that use natural gas vehicle fuels due to business disruptions and depressed oil prices;

•adoption of governmental policies or programs or increased publicity or popular sentiment in favor of vehicles or fuels other than natural gas, including long-standing support for gasoline and diesel-powered vehicles, changes to emissions requirements applicable to vehicles powered by gasoline, diesel, natural gas, or other vehicle fuels and/or growing support for electric and hydrogen-powered vehicles;

•perceptions about the benefits of natural gas vehicle fuels relative to gasoline, diesel and other alternative vehicle fuels, including with respect to factors such as supply, cost savings, environmental benefits and safety;

•the volatility in the supply, demand, use and prices of crude oil, gasoline, diesel, RNG, natural gas and other vehicle fuels, such as electricity, hydrogen, renewable diesel, biodiesel and ethanol;

•inertia among fleets and fleet vehicle operators, who may be unable or unwilling to prioritize converting a fleet to our vehicle fuels over an operator’s other general business concerns, particularly if the operator is not sufficiently incentivized by emissions regulations or other requirements or lacks demand for the conversion from its counterparties or drivers;

•vehicle cost, fuel efficiency, availability, quality, safety, convenience (to fuel and service), design, performance and residual value, as well as operator perception with respect to these factors, generally and in our key customer markets and relative to comparable vehicles powered by other fuels;

•the development, production, cost, availability, performance, sales and marketing and reputation of engines that are well-suited for the vehicles used in our key customer markets, including heavy and medium-duty trucks and other fleets;

•increasing competition in the market for vehicle fuels generally, and the nature and effect of competitive developments in such market, including improvements in or perceived advantages of other vehicle fuels and engines powered by such fuels;

•the availability and effect of environmental, tax or other governmental regulations, programs or incentives that promote our products or other alternatives as a vehicle fuel, including certain programs under which we generate Environmental Attributes by selling RNG as a vehicle fuel, as well as the market prices for such credits; and

•emissions and other environmental regulations and pressures on producing, transporting, and dispensing our fuels.

Acquisition, financing, construction, and development of Fueling Station projects by us or our partners that own projects may not commence on anticipated timelines or at all.

Our strategy is to continue to expand, including through the acquisition of additional Fueling Station projects and by signing additional supply agreements with third party project owner partners. From time to time we and our partners enter into nonbinding letters of intent for projects. Until the negotiations are final, however, and the parties have executed definitive documentation, we or our partners may not be able to consummate any development or acquisition transactions, or any other similar arrangements, on the terms set forth in the applicable letter of intent or at all.

The acquisition, financing, construction and development of 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;

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

•inaccuracy of assumptions with respect to the biogas potential, including quality, volume, and asset life;

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

•delays in deliveries or increases in the price of equipment or other materials;

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

•increases in the cost of labor, labor disputes and work stoppages or the inability to find an adequate supply of workers;

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

•unforeseen engineering and environmental problems;

•cost overruns or supply chain disruptions;

•accidents involving personal injury or the loss of life;

•weather conditions, health crises, pandemics, catastrophic events, including fires, explosions, earthquakes, droughts and acts of terrorism, and other force majeure events; and

•interconnection and access to utilities.

In addition, new projects have no operating history. A new project may be unable to fund principal and interest payments under its debt service obligations or may operate at a loss.

Our Fueling Station construction activities for commercial fleets and other counterparties are subject to business and operational risks, including predicting demand in a particular market or markets, land use, permitting or zoning difficulties, responsibility for actions of sub-contractors on jobs in which we serve as general contractor, potential labor shortages and cost overruns.

As part of our business activities, we design and construct Fueling Stations that we either own and operate ourselves or provide these services for our counterparties. These activities require a significant amount of judgment in determining where to build and open Fueling Stations, including predictions about fuel demand that may not be accurate for any of the locations we target. As a result, we may build Fueling Stations that we may not open for fueling operations, and we may open Fueling Stations that fail to generate the volume or profitability levels we anticipate, either or both of which could occur due to a lack of sufficient customer demand at the specific locations or for other reasons. For any Fueling Stations that are completed but unopened, we would have substantial investments in assets that do not produce revenue, and for Fueling Stations that are open and underperforming, we may decide to close them.

We also face many operational challenges in connection with our Fueling Station design and construction activities. For example, we may not be able to identify suitable locations for the Fueling Stations we or our counterparties seek to build. Additionally, even if preferred sites can be located, we may encounter land use or zoning difficulties, problems with utility services, challenges obtaining and retaining required permits and approvals or local resistance, including due to

reduced operations of permitting agencies because of the COVID-19 pandemic, any of which could prevent us or our counterparties from building new stations on such sites or limit or restrict the use of new or existing stations. Any such difficulties, resistance or limitations or any failure to comply with local permit, land use or zoning requirements could restrict our activities or expose us to fines, reputational damage or other liabilities, which would harm our business and results of operations.

In addition, we act as the general contractor and construction manager for new Fueling Station construction and facility modification projects, and we typically rely on licensed subcontractors to perform the construction work. We may be liable for any damage we or our subcontractors cause or for injuries suffered by our employees or our subcontractors’ employees during the course of work on our projects. Additionally, shortages of skilled subcontractor labor and any supply chain disruptions affecting access to and cost of construction materials could significantly delay a project or otherwise increase our costs. Further, our expected profit from a project is based in part on assumptions about the cost of the project, and cost overruns, delays or other execution issues may, in the case of projects we complete and sell to counterparties, result in our failure to achieve our expected margins or cover our costs, and in the case of projects we build and own, result in our failure to achieve an acceptable rate of return. If any of these events occur, our business, operating results and cash flows could be negatively affected.

Additional Risk Factors Relating to Our Business in General

Certain of our Biogas Conversion Projects and Fueling Stations are newly constructed or are under construction and may not perform as we expect.

We have a number of Biogas Conversion Projects under construction that will begin production over the next 18-24 months. Therefore, our expectations of the operating performance of these facilities are based on assumptions and estimates made without the benefit of operating history. Our forecasts with respect to our new and developing projects, and related estimates and assumptions, are based on limited operating history or expected operating results. These facilities also include digesters under development for which we have no operating history. The ability of these facilities to meet our performance expectations is subject to the risks inherent in newly constructed energy generation and RNG production facilities and the construction of such facilities, including delays or problems in construction, degradation of equipment in excess of our expectations, system failures, and outages. The failure of these facilities to perform as we expect could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our contracts with government entities may be subject to unique risks, including possible termination of or reduction in the governmental programs under which we operate, instances in which our contract provisions allow the government entity to terminate, amend or change terms at their convenience, and competitive bidding processes for the award of contracts.

We have, and expect to continue to seek, long-term Fueling Station construction, maintenance and fuel sale contracts with various government entities. In addition to normal business risks, including the other risks discussed in these risk factors, our contracts with government entities are often subject to unique risks, some of which are beyond our control. For example, long-term government contracts and related orders are subject to cancellation if adequate appropriations for subsequent performance periods are not made. Further, the termination of funding for a government program supporting any of our government contracts could result in the loss of anticipated future revenue attributable to such contract. Moreover, government entities with which we contract are often able to modify, curtail or terminate contracts with us at their convenience and without prior notice, and would only be required to pay for work completed and commitments made at or prior to the time of termination.

In addition, government contracts are frequently awarded only after competitive bidding processes, which are often protracted. In many cases, unsuccessful bidders for government contracts are provided the opportunity to formally protest the contract awards through various agencies or other administrative and judicial channels. The protest process may substantially delay a successful bidder’s contract performance, result in cancellation of the contract award entirely and distract management. As a result, we may not be awarded contracts for which we bid, and substantial delays or cancellation of government contracts may follow any successful bids as a result of any protests by other bidders. The occurrence of any of these risks could have a material adverse effect on our results of operations and financial condition.

Our level of indebtedness and preferred stock redemption obligations could adversely affect our ability to raise additional capital to fund our operations and acquisitions. It could also expose us to the risk of increased interest rates

and limit our ability to react to changes in the economy or our industry. We may be unable to obtain additional financing to fund our operations or growth.

As of December 31, 2023, our total indebtedness was $209.1 million, excluding deferred financing costs. Additionally, we have redeemable preferred non-controlling interests outstanding of $130.0 million plus accrued and unpaid dividends thereon.

Our substantial indebtedness and preferred units redemption obligations could have important consequences, including, for example:

•being required to accept then-prevailing market terms in connection with any required refinancing of such indebtedness or redemption obligations, which may be less favorable than existing terms;

•failure to refinance, or to comply with the covenants in the agreements governing, these obligations could result in an event of default under those agreements, which could be difficult to cure or result in our bankruptcy;

•our debt service and dividend obligations require us to dedicate a substantial portion of our cash flow to pay principal and interest on our debt and dividends on our preferred units, thereby reducing the funds available to us and our ability to borrow to operate and grow our business;

•increase in interest rates on our existing debt facilities or a reduction in the supply of project debt financing could reduce our ability to construct and operate new RNG projects or fueling stations;

•our limited financial flexibility could reduce our ability to plan for and react to unexpected opportunities; and

•our substantial debt service obligations make us vulnerable to adverse changes in general economic, credit and capital markets, industry and competitive conditions and adverse changes in government regulation and place us at a disadvantage compared with competitors with less debt or mandatory redeemable preferred units.

Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. If we do not comply with our obligations under our debt instruments or with respect to our preferred units, we may be required to refinance all or part of our existing debt and preferred units, borrow additional amounts or sell securities, which we may not be able to do on favorable terms or at all. In addition, increases in interest and dividend rates and changes in debt and preferred equity covenants may reduce the amounts that we can borrow or otherwise finance, reduce our cash flows and increase the equity investment we may be required to make to complete construction of our Biogas Conversion Projects and Fueling Stations. These increases could cause some of our projects to become economically unattractive. If we are unable to raise additional capital or generate sufficient operating cash flow to repay our indebtedness and preferred unit obligations, we could be in default under our lending agreements and preferred unit designations and could be required to delay construction of new projects, reduce overhead costs, reduce the scope of our projects or abandon or sell some or all of our projects, all of which could have a material adverse effect on our business, financial condition and results of operations.

Our existing credit facilities contain financial covenants and our credit facilities and preferred stock designations contain other restrictive covenants that limit our ability to return capital to equity holders or otherwise engage in activities that may be in our long-term best interests. Our inability to comply with those covenants could result in an event of default or material breach which, if not cured or waived, may entitle the related lenders or preferred unit holders to higher interest or dividend payment to demand repayment or enforce their security interests (in the case of indebtedness) and other remedies, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, failure to comply with such covenants may entitle the related lenders to demand repayment and accelerate all such indebtedness. Further, in certain circumstances following a failure to timely redeem our preferred stock, holders of such preferred stock have the right to designate a director to our board of directors.

In connection with certain project development opportunities, we have utilized project-level financing in the past and may need to do so again in the future; however, we may not be able to obtain such financing on commercially reasonable terms or at all. The agreements governing such financings typically contain financial and other restrictive covenants that

limit a project subsidiary’s ability to make distributions to its parent or otherwise engage in activities that may be in its long-term best interests. Project-level financing agreements generally prohibit distributions from the project entities to us unless certain specific conditions are met, including the satisfaction of certain financial ratios or a facility achieving commercial operations. Our inability to comply with such covenants may prevent cash distributions by the particular project or projects to us and could result in an event of default which, if not cured or waived, may entitle the related lenders to demand repayment or enforce their security interests, which could result in a loss of project assets and/or otherwise have a material adverse effect on our business, results of operations and financial condition.

Our cash could be adversely affected if the financial institutions in which we hold our cash fail.

The Company maintains domestic cash deposits in Federal Deposit Insurance Corporation (“FDIC”) insured banks. The domestic bank deposit balances may exceed the FDIC insurance limits. These balances could be impacted if one or more of the financial institutions in which we deposit monies fails or is subject to other adverse conditions in the financial or credit markets.

Liabilities and costs associated with hazardous materials and contamination and other environmental conditions may require us to conduct investigations or remediation at the properties underlying our projects, may adversely impact the value of our projects or the underlying properties, and may expose us to liabilities to third parties.

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, which means that we may be assigned liabilities for hazardous substance conditions that exceed our action contributions to the contamination conditions. 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. We may incur substantial investigation costs, remediation costs or other damages, thus harming our business, financial condition and results of operations, as a result of the presence or release of hazardous substances at locations where we operate or as a result of our own operations.

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

We may also face liabilities in cases of exposure to hazardous materials, and claims for such exposure can be brought by any third party, including workers, employees, contractors and the general public. Claims can be asserted by such persons relating to personal injury or property damage, and resolving such claims can be expensive and time consuming, even if there is little or no basis for the claim.

We have a history of accounting losses and may incur additional losses in the future.

We have incurred net losses historically. We may incur losses in future periods, and we may never sustain profitability, either of which would adversely affect our business, prospects and financial condition and may cause the price of common stock to fall. Furthermore, historical losses may not be indicative of future losses due to many factors outside of our control and our future losses may be greater than our past losses. In addition, to try to achieve or sustain profitability, we may choose or be forced to take actions that result in material costs or material asset or goodwill impairments. We review our assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset or asset group may not be recoverable, and we perform a goodwill impairment test on an annual basis and between annual tests in certain circumstances, in each case in accordance with applicable accounting guidance and as described in the financial statements and notes to the financial statements included in this report. Changes to the use of our assets, divestitures, changes to the structure of our business, significant negative industry or economic trends, disruptions to our operations, inability to effectively integrate any acquired businesses, further market capitalization declines, or other similar actions or conditions could result in additional asset impairment or goodwill impairment charges or other adverse consequences, any of which could have material adverse effects on our financial condition, our results of operations and the trading price of common stock.

Loss of our key management could adversely affect our business performance. Our management team has limited experience in operating a public company such as us.

We are dependent on the efforts of our key management. Although we believe qualified replacements could be found for any departures of key executives, the loss of their services could adversely affect our performance and the value of our Class A common stock.

Any failure to maintain effective internal control over financial reporting could adversely affect us.

Section 404 of the Sarbanes-Oxley Act of 2002 requires us to include in our annual reports on Form 10-K an assessment by management of the effectiveness of our internal control over financial reporting. We have previously reported material weaknesses in our internal control over financial reporting related to certain control deficiencies in accounting and disclosures of significant and unusual transactions, timely and effective reviews of accounts reconciliations and application of ASC 606. As a result of these material weaknesses, we concluded that our internal control over financial reporting were not operating effectively for each of the years ended December 31, 2022 and 2021.

During the year ended December 31, 2023, management of the Company successfully completed the testing necessary to conclude that the material weaknesses have been remediated. We will continue to monitor the effectiveness of these and other processes, procedures, and controls and will make any further changes that management determines to be appropriate.

However, we cannot guarantee that these steps have been or will be sufficient to remediate the deficiencies or that in the future we will not have a material weakness that prevents us from concluding that our internal control financial reporting is effective. If our remedial measures are insufficient to address the material weaknesses or if additional material weaknesses arise in the future, this could result in a loss of investor confidence in the reliability of our financial statements,which in turn, could negatively affect the market price of our securities, including the Class A common stock. Furthermore, our interim or annual financial statements may contain material misstatements or omissions and we could be required to restate our financial results. In addition, any such failures could result in litigation or regulatory actions by the SEC or other regulatory authorities, delisting of our securities and harm to our reputation and financial condition, or diversion of financial and management resources from the operation of our business.

Risks Related to the Company

Future sales and issuances of our Class A common stock could result in additional dilution of the percentage ownership of our shareholders and could cause our share price to fall.

We expect that significant additional capital will be needed in the future to pursue our growth plan. To raise capital, we may sell shares of our Class A common stock, convertible securities or other equity securities in one or more transactions at prices and in a manner we determine from time to time. If we sell shares of our Class A common stock, convertible securities or other equity securities, investors may be materially diluted by subsequent sales. Such sales may also result in material dilution to our existing shareholders, and new investors could gain rights, preferences, and privileges senior to existing holders of our Class A common stock.

Future sales of a substantial number of shares of our Class A common stock, or the perception in the market that the holders of a large number of shares of Class A common stock intend to sell shares, could reduce the market price of our Class A common stock.

Sales of a substantial number of shares of our Class A common stock in the public market, including the resale of the shares of held by our stockholders, could occur at any time. These sales, or the perception in the market that the holders of a large number of shares of Class A common stock intend to sell shares, could reduce the market price of our Class A common stock.

Pursuant to that certain Investor Rights Agreement, dated July 21, 2022, by and among OPAL Fuels Inc., each of the sellers named therein, the Sponsor and the sponsor principals, those stockholders are entitled to have the registration statement under the Securities Act kept effective for a prolonged period of time such that registered resales of their shares of Class A common stock can be made. Sales of up to 163,676,735 shares of our Class A common stock may be effected

pursuant to our registration statement on Form S-3 filed under the Securities Act (file number 333-266757), which was declared effective on August 10, 2023, or in reliance upon an exemption from registration under the Securities Act.

The resale, or expected or potential resale, of a substantial number of shares of our Class A common stock in the public market could adversely affect the market price for our Class A common stock and make it more difficult for you to sell your holdings at times and prices that you determine are appropriate. Furthermore, we expect that, because a large number of shares were registered pursuant to such registration statement, the selling holders thereunder will continue to offer the securities covered thereby for a significant period of time, the precise duration of which cannot be predicted. Accordingly, the adverse market and price pressures resulting from an offering pursuant to the registration statement may continue for an extended period of time.

Litigation or legal proceedings could expose us to significant liabilities and have a negative impact on our reputations or business.

We may become subject to claims, litigation, disputes and other legal proceedings from time to time. We evaluate these claims, litigation, disputes and other legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these assessments and estimates, we may establish reserves, as appropriate. These assessments and estimates are based on the information available to each management team at the time of its respective assessment and involve a significant amount of management judgment. Actual outcomes or losses may differ materially from our assessments and estimates.

Even when not merited or whether or not we ultimately prevail, the defense of these lawsuits may divert management’s attention, and we may incur significant expenses in defending these lawsuits. The results of litigation and other legal proceedings are inherently uncertain, and adverse judgments or settlements in some of these legal disputes may result in adverse monetary damages, penalties or injunctive relief against us which could negatively impact any of our financial positions, cash flows or results of operations. Further, any liability or negligence claim against us in US courts may, if successful, result in damages being awarded that contain punitive elements and therefore may significantly exceed the loss or damage suffered by the successful claimant. Any claims or litigation, even if fully indemnified or insured, could damage our reputation and make it more difficult to compete effectively or to obtain adequate insurance in the future. A settlement or an unfavorable outcome in a legal dispute could have an adverse effect on our business, financial condition, results of operations, cash flows and/or prospects.

Furthermore, while we maintain insurance for certain potential liabilities, such insurance does not cover all types and amounts of potential liabilities and is subject to various exclusions as well as caps on amounts recoverable. Even if we believe a claim is covered by insurance, insurers may dispute its entitlement to recovery for a variety of potential reasons, which may affect the timing and, if the insurers prevail, the amount of our recovery.

Our business and operations could be negatively affected if we become subject to any securities litigation or shareholder activism, which could cause us to incur significant expense, hinder execution of business and growth strategy and impact its stock price.

In the past, following periods of volatility in the market price of a company’s securities, securities class action litigation has often been brought against that company. Shareholder activism, which could take many forms or arise in a variety of situations, has been increasing recently. Volatility in the stock price of our Class A common stock or other reasons may in the future cause it to become the target of securities litigation or shareholder activism. Securities litigation and shareholder activism, including potential proxy contests, could result in substantial costs and divert management’s and our board’s attention and resources from our business. Additionally, such securities litigation and shareholder activism could give rise to perceived uncertainties as to our future, adversely affect our relationships with service providers and make it more difficult to attract and retain qualified personnel. Also, we may be required to incur significant legal fees and other expenses related to any securities litigation and activist shareholder matters. Further, our stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks and uncertainties of any securities litigation and shareholder activism.

We are subject to changing law and regulations regarding regulatory matters, corporate governance and public disclosure that will increase both our costs and the risk of noncompliance.

We are subject to rules and regulations by various governing bodies, including, for example, the SEC, which are charged with the protection of investors and the oversight of companies whose securities are publicly traded, and to new

and evolving regulatory measures under applicable law. Our efforts to comply with new and changing laws and regulations has resulted in increased general and administrative expenses.

Moreover, because these laws, regulations and standards are subject to varying interpretations, their application in practice may evolve over time as new guidance becomes available. This evolution may result in continuing uncertainty regarding compliance matters and additional costs necessitated by ongoing revisions to our disclosure and governance practices. If we fail to address and comply with these regulations and any subsequent changes, we may be subject to penalty and our business may be harmed.

We are an “emerging growth company,” and our election to comply with the reduced disclosure requirements as a public company may make our Class A common stock less attractive to investors.

For so long as we remain an “emerging growth company,” as defined in the JOBS Act, we may take advantage of certain exemptions from various requirements that are applicable to public companies that are not “emerging growth companies,” including not being required to comply with the independent auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, being required to provide fewer years of audited financial statements, and exemptions from the requirements of holding a non-binding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved.

We may lose our emerging growth company status and become subject to the SEC’s internal control over financial reporting auditor attestation requirements. If we are unable to certify the effectiveness of our internal controls, or if our internal controls have a material weakness, we could be subject to regulatory scrutiny and a loss of confidence by stockholders, which could harm our business and adversely affect the market price of the common stock. We will cease to be an “emerging growth company” upon the earliest to occur of: (i) the last day of the fiscal year in which we have more than $1.235 billion in annual revenue; (ii) the date we qualify as a large accelerated filer, with at least $700.0 million of equity securities held by non-affiliates; (iii) the date on which we have, in any three-year period, issued more than $1.0 billion in non-convertible debt securities; and (iv) December 31, 2026 (the last day of the fiscal year following the fifth anniversary of ArcLight becoming a public company).

As an emerging growth company, we may choose to take advantage of some but not all of these reduced reporting burdens. Accordingly, the information we provide to our stockholders may be different than the information you receive from other public companies in which you hold stock. In addition, the JOBS Act also provides that an “emerging growth company” can take advantage of an extended transition period for complying with new or revised accounting standards. We have elected to take advantage of this extended transition period under the JOBS Act. As a result, our operating results and financial statements may not be comparable to the operating results and financial statements of other companies who have adopted the new or revised accounting standards. It is possible that some investors will find our Class A common stock less attractive as a result, which may result in a less active trading market for our Class A common stock and higher volatility in our stock price.

Our current majority stockholder has control over all stockholder decisions because it controls a substantial majority of our voting power through “high vote” voting stock. Such majority stockholder, and the persons controlling such majority stockholder, including Fortistar and Mr. Mark Comora, our Chairman of the board of directors, may have potential conflicts of interest in connection with existing or proposed business relationships and decisions impacting us and, even in situations where it does not have a conflict of interest, its interests in such matters may be different than the other stockholders.

The dual-class structure of our common stock has the effect of concentrating voting control with Mr. Mark Comora who, through his control of OPAL Holdco and Hillman, beneficially owns in the aggregate a substantial majority of the voting power of our capital stock on most issues of corporate governance. Mr. Mark Comora beneficially owns 145,289,762 shares of OPAL, comprising 84.2% of our outstanding common stock as of March 13, 2024. All of these shares (with the exception of 880,600 shares of Class A common stock purchased by Fortistar in the PIPE Investment and 10,125 shares of Class A common stock held directly by Mr.Comora) are Class B common stock and Class D common stock, which have no economic rights but are entitled to five votes per share, respectively, giving Mr. Mark Comora control over 94.1% of our voting power. OPAL Holdco and Hillman are controlled, indirectly, by Mr. Mark Comora through entities affiliated with Mr. Mark Comora, including Fortistar and certain of its other affiliates. Mr. Mark Comora is the Chairman of our board of directors.

Accordingly, Mr. Mark Comora is able to control most matters submitted to our stockholders for approval. This concentrated control will limit or preclude your ability to influence corporate matters for the foreseeable future, including the election of directors, amendments to our organizational documents, and any merger, consolidation, sale of all or substantially all of our assets, or other major corporate transaction requiring stockholder approval. This may prevent or discourage unsolicited acquisition proposals or offers for our capital stock that you may feel are in your best interest as one of our stockholders. More specifically, Mr. Mark Comora has the ability to control our management and our major strategic investments and decisions as a result of his ability to control the election or, in some cases, the replacement of our directors. In the event of the death of Mr. Mark Comora, control of the shares of common stock controlled by Mr. Mark Comora will be transferred to the persons or entities that he has designated. In his position as the Chairman of our board, Mr. Mark Comora owes a fiduciary duty to our stockholders and must act in good faith in a manner he reasonably believes to be in the best interests of our stockholders. As a beneficial owner of our common stock, even as a controlling stockholder Mr. Mark Comora is entitled to vote the shares he controls, in his own interests, which may not always be in the interests of our stockholders generally.

Future transfers by holders of Class C common stock and Class D common stock, which carry five votes per share, will generally result in those shares converting to Class A common stock and Class B common stock, respectively, which carry only one vote per share, unless in each case made to a Qualified Stockholder (as defined in the Second A&R LLC Agreement). The conversion of Class D common stock to Class B common stock and the conversion of Class C common stock to Class A common stock, as the case may be, means that no third party stockholders can leverage the high vote to offset the voting power held by the OPAL Holdco and Hillman.

In addition, Fortistar and certain of its affiliates (other than our subsidiaries), which are controlled by Mr. Mark Comora (who also controls OPAL Holdco and Hillman), manage numerous investment vehicles and separately managed accounts. Fortistar and these affiliates may compete with us for acquisition and other business opportunities, which may present conflicts of interest for these persons. If these entities or persons decide to pursue any such opportunity, we may be precluded from procuring such opportunities. In addition, investment ideas generated within Fortistar and these affiliates may be suitable both for us and for current or future investment vehicles managed by Fortistar and these affiliates and may be directed to such investment vehicles rather than to us. Neither Fortistar nor members of our management team who are also members of the management of Fortistar or of any of these affiliates, including Mr. Mark Comora and Mr. Nadeem Nisar (who serves on our board), have any obligation to present us with any potential business opportunity of which they become aware, unless, (i) such opportunity is expressly offered to such person solely in his or her capacity as a one of our directors or officers, (ii) such opportunity is one we are legally and contractually permitted to undertake and would otherwise be reasonable for us to pursue, and (iii) the director or officer is permitted to refer that opportunity to us without violating another legal obligation. Fortistar and/or members of our management team, such as Mr. Mark Comora or Mr. Nisar in their capacities as management of Fortistar or in their other endeavors, may be required to present potential business opportunities to the related entities described above, current or future affiliates of Fortistar, or third parties, before they present such opportunities to us. The personal and financial interests of such persons described above may be in conflict with the interests of ours and influence their motivation in identifying and selecting our business opportunities, their support or lack thereof for pursuing such business opportunities and our operations.

The existence of a family relationship between Mr. Mark Comora, as our Chairman of our board, and Mr. Adam Comora, as our Co-Chief Executive Officer, may result in a conflict of interest on the part of such persons between what they, in their capacity as Chairman or Co-Chief Executive Officer, respectively, may believe is in our best interests and the interests of our stockholders in connection with a decision to be made by us through our board, standing committees thereof, and management and what he may believe is best for himself or his family members in connection with the same decision.

Mr. Mark Comora and Mr. Adam Comora are father and son. In his position as the Chairman of our board, Mr. Mark Comora owes a fiduciary duty to our stockholders and must act in good faith in a manner he reasonably believes to be in the best interests of the stockholders. And in his position as our Co-Chief Executive Officer, Mr. Adam Comora owes a fiduciary duty to our stockholders and must act in good faith in a manner he reasonably believes to be in the best interests of the stockholders. Nevertheless, the existence of this family relationship may result in a conflict of interest on the part of such persons between what he may believe is in our best interests and the best interests of our stockholders and what he may believe is best for himself or his family members in connection with a business opportunity or other matter to be decided by OPAL through its board, standing committees thereof, and management. Moreover, even if such family relationship does not create an actual conflict, the perception of a conflict in the press or the financial or business community generally could create negative publicity or other reaction with respect to the business opportunity or other matters to be decided by us through our board, standing committees thereof, and management, which could adversely affect

the business generated by us and our relationships with its existing customers and other counterparties, impact the behavior of third party participants or other persons in the proposed business opportunity or other matter to be decided, otherwise negatively impact our business prospects related to such matter, or negatively impact the trading market for our securities.

Our only material assets are our direct interests in OPAL Fuels, and we are accordingly dependent upon distributions from OPAL Fuels to pay dividends and taxes and other expenses.

We are a holding company and have no material assets other than our ownership of Class A Units in OPAL Fuels. We therefore have no independent means of generating revenue. We intend to cause our subsidiaries (including OPAL Fuels) to make distributions in an amount sufficient to cover all applicable taxes and other expenses payable and dividends, if any, declared by us. The agreements governing our debt facilities impose, and agreements governing our future debt facilities are expected to impose, certain restrictions on distributions by such subsidiaries to us, and may limit our ability to pay cash dividends. The terms of any credit agreements or other borrowing arrangements that we may enter into in the future may impose similar restrictions. To the extent that we need funds, and any of our direct or indirect subsidiaries is restricted from making such distributions under these debt agreements or applicable law or regulation, or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition.

If we are deemed an “investment company” under the Investment Company Act as a result of our ownership of OPAL Fuels, applicable restrictions could make it impractical for us to continue our business as contemplated and could have a material adverse effect on its business.

A person may be deemed to be an “investment company” for purposes of the Investment Company Act if it owns investment securities having a value exceeding 40% of the value of its total assets (exclusive of U.S. government securities and cash items), absent an applicable exemption. We have no material assets other than our interests in OPAL Fuels. As managing member of OPAL Fuels, we generally have control over all of the affairs and decision making of OPAL Fuels. On the basis of our control over OPAL Fuels, we believe our direct interest in OPAL Fuels is not an “investment security” within the meaning of the Investment Company Act. If we were to cease participation in the management of OPAL Fuels, however, our interest in OPAL Fuels could be deemed an “investment security,” which could result in our being required to register as an investment company under the Investment Company Act and becoming subject to the registration and other requirements of the Investment Company Act.

The Investment Company Act and the rules thereunder contain detailed parameters for the organization and operations of investment companies. Among other things, the Investment Company Act and the rules thereunder limit or prohibit transactions with affiliates, impose limitations on the issuance of debt and equity securities, prohibit the issuance of stock options and impose certain governance requirements. We intend to conduct our operations so that we will not be deemed to be an investment company under the Investment Company Act. However, if anything were to happen which would require us to register as an investment company under the Investment Company Act, requirements imposed by the Investment Company Act, including limitations on its capital structure, ability to transact business with affiliates and ability to compensate key employees, could make it impractical for us to continue our business as currently conducted, impair the agreements and arrangements between and among us, OPAL Fuels, members of their respective management teams and related entities or any combination thereof and materially adversely affect our business, financial condition and results of operations.

We are a controlled company, and thus not subject to all of the corporate governance rules of Nasdaq. You will not have the same protections afforded to stockholders of companies that are subject to such requirements.

We are considered a “controlled company” under the rules of Nasdaq. Controlled companies are exempt from the Nasdaq corporate governance rules requiring that listed companies have (i) a majority of the board of directors consist of “independent” directors under the listing standards of Nasdaq, (ii) a nominating/corporate governance committee composed entirely of independent directors and a written nominating/corporate governance committee charter meeting the Nasdaq requirements and (iii) a compensation committee composed entirely of independent directors and a written compensation committee charter meeting the requirements of Nasdaq. We expect to take advantage of some or all of the exemptions described above for so long as we are a controlled company. If we use some or all of these exemptions, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of Nasdaq.

The dual-class structure of our common stock may adversely affect the trading market for the shares of Class A common stock.

We cannot predict whether our dual class structure, which affords the shares of Class A common stock and Class B common stock one vote per share while affording the shares of Class C common stock and Class D common stock with five votes per share, combined with our concentrated voting control by OPAL Holdco due to its ownership of shares of Class D common stock, will result in a lower or more volatile market price of the shares of Class A common stock or in adverse publicity or other adverse consequences. For example, certain index providers have announced restrictions on including companies with multiple-class share structures in certain of their indexes. Under any such announced policies or future policies, our dual class capital structure could make us ineligible for inclusion in certain indices, and as a result, mutual funds, exchange-traded funds and other investment vehicles that attempt to passively track those indices will not be investing in our stock. It is unclear what effect, if any, these policies will have on the valuations of publicly traded companies excluded from such indices, but it is possible that they may depress valuations as compared to similar companies that are included. As a result, the market price of shares of Class A common stock could be adversely affected.

There can be no assurance that we will be able to comply with the continued listing standards of Nasdaq.

Our shares of Class A common stock are listed on Nasdaq under the symbol “OPAL”. If Nasdaq delists our securities from trading on its exchange for failure to meet the listing standards, we and our stockholders could face significant negative consequences. The consequences of failing to meet the listing requirements include:

•limited availability of market quotations for our securities;

•a determination that the Class A common stock is a “penny stock” which will require brokers trading in the Class A common stock to adhere to more stringent rules;

•possible reduction in the level of trading activity in the secondary trading market for shares of the Class A common stock;

•a limited amount of analyst coverage; and

•a decreased ability to issue additional securities or obtain additional financing in the future.

Because there are no current plans to pay cash dividends on shares of common stock for the foreseeable future, you may not receive any return on investment unless you sell your shares of common stock for a price greater than that which you paid for it.

We intend to retain future earnings, if any, for future operations, expansion and debt repayment and there are no current plans to pay any cash dividends for the foreseeable future. The declaration, amount and payment of any future dividends on shares of common stock will be at the sole discretion of our board, who may take into account general and economic conditions, our financial condition and results of operations, our available cash and current and anticipated cash needs, capital requirements, contractual, legal, tax, and regulatory restrictions, implications on the payment of dividends by us to our its stockholders or by our subsidiaries to us and such other factors our board may deem relevant. In addition, our ability to pay dividends is limited by covenants of any indebtedness we incur. As a result, you may not receive any return on an investment in the shares of Class A common stock unless you sell your shares of Class A common stock for a price greater than that which you paid for it.

Anti-takeover provisions are contained in the Organizational Documents that could delay or prevent a change of control.

Certain provisions of the Organizational Documents may have an anti-takeover effect and may delay, defer or prevent a merger, acquisition, tender offer, takeover attempt or other change of control transaction that a stockholder of ours might consider is in its best interest, including those attempts that might result in a premium over the market price for the shares of our Class A common stock.

These provisions, among other things:

•authorize our board to issue new series of preferred stock without stockholder approval and create, subject to applicable law, a series of preferred stock with preferential rights to dividends or our assets upon liquidation, or with superior voting rights to the existing shares of common stock;

•eliminate the ability of stockholders to call special meetings of stockholders;

•eliminate the ability of stockholders to fill vacancies on our board;

•establish advance notice requirements for nominations for election to our board or for proposing matters that can be acted upon by stockholders at annual stockholder meetings;

•permit our board to establish the number of directors;

•provide that our board is expressly authorized to make, alter or repeal the Bylaws; and

•limit the jurisdictions in which certain stockholder litigation may be brought.

These anti-takeover provisions, together with the control of the voting power of by OPAL Holdco, could make it more difficult for a third-party to acquire us, even if the third party’s offer may be considered beneficial by many of our stockholders. As a result, our stockholders may be limited in their ability to obtain a premium for their shares. These provisions could also discourage proxy contests and make it more difficult for you and other stockholders to elect directors of your choosing and to cause us to take other corporate actions you desire.

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits that we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we determine, and the IRS or another tax authority may challenge all or a part of the existing tax basis, tax basis increases, or other tax attributes subject to the Tax Receivable Agreement, and a court could sustain such challenge. The parties to the Tax Receivable Agreement will not reimburse us for any payments previously made if such tax basis is, or other tax benefits are, subsequently disallowed, except that any excess payments made to a party under the Tax Receivable Agreement will be netted against future payments otherwise to be made under the Tax Receivable Agreement, if any, after the determination of such excess.

If we experience a change of control (as defined under the Tax Receivable Agreement, which includes certain mergers, any plan of liquidation and other forms of business combinations or changes of control) or the Tax Receivable Agreement terminates early (at our election or as a result of a breach, including a breach for our failing to make timely payments under the Tax Receivable Agreement for more than three months, except in the case of certain liquidity exceptions), we could be required to make a substantial, immediate lump-sum payment based on the present value of hypothetical future payments that could be required under the Tax Receivable Agreement. The calculation of the hypothetical future payments would be made using certain assumptions and deemed events set forth in the Tax Receivable Agreement, including (i) the sufficiency of taxable income to fully utilize the tax benefits, (ii) any OPAL Fuels Common Units (other than those held by us) outstanding on the termination date are exchanged on the termination date and (iii) the utilization of certain loss carryovers over a certain time period. Our ability to generate net taxable income is subject to substantial uncertainty. Accordingly, as a result of the assumptions, the required lump-sum payment may be significantly in advance of, and could materially exceed, the realized future tax benefits to which the payment relates.

As a result of either an early termination or a change of control, we could be required to make payments under the Tax Receivable Agreement that exceed our actual cash savings. Consequently, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control. For example, assuming no material changes in the relevant tax law, we expect that if we experienced a change of control the estimated Tax Receivable Agreement lump-sum payment would be approximately $133.0 million depending on OPAL Fuels’s rate of recovery of the tax basis increases associated with the deemed exchange of the OPAL Fuels Common Units (other than those held by us). This estimated Tax Receivable Agreement lump-sum payment is calculated using a discount rate equal to 7.47%, applied against an undiscounted liability of approximately $240.8 million. These amounts are estimates and have been prepared for informational purposes only. The actual amount of deferred tax assets and related liabilities that we will recognize will differ based on, among other things, the timing of the exchanges, the price of the shares of Class A common

stock at the time of the exchange, and the tax rates then in effect. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

It is more likely than not that the deferred tax assets will not be realized in accordance with ASC Topic 740, ‘Income Taxes’. As such, the Company has reduced the full carrying amount of the deferred tax assets with a valuation allowance under both scenarios. Management will continue to monitor and consider the available evidence from quarter to quarter, and year to year, to determine if more or less valuation allowance is required at that time.

Finally, because we are a holding company with no operations of our own, our ability to make payments under the Tax Receivable Agreement depends on the ability of OPAL Fuels to make distributions to us. To the extent that OPAL is unable to make payments under the Tax Receivable Agreement for any reason, such payments will be deferred and will accrue interest until paid, which could negatively impact our results of operations and could also affect our liquidity in periods in which such payments are made.

Cybersecurity and Information Technology Risks

A failure of our IT and data security infrastructure could have a material adverse effect on our business and operations. We rely upon the expertise, reliability and security of our outsourced IT provider and their services to expand and continually update this infrastructure in response to the changing needs of our business. Our existing IT systems and any new IT systems may not perform as expected. If we experience a problem with the functioning of any important IT system or a security breach of our network, including during system upgrades or new system implementations, the resulting disruptions could have a material adverse effect on our business.

We and some of our third-party vendors receive and store personal information in connection with our human resources operations and other aspects of our business. Despite our implementation of reasonable security measures, our IT systems, like those of other companies, are vulnerable to damages from computer viruses, natural disasters, fire, power loss, telecommunications failures, personnel misconduct, human error, unauthorized access, physical or electronic security breaches, cyber-attacks (including malicious and destructive code, phishing attacks, ransomware, and denial of service attacks), and other similar disruptions. Cybersecurity threat actors employ a wide variety of methods and techniques that are constantly evolving, increasingly sophisticated, and difficult to detect and successfully defend against.

Cybersecurity incidents could expose us to claims, litigation, regulatory or other governmental investigations, administrative fines and potential liability. A material network breach in the security of our IT systems could include the theft of our trade secrets, customer information, human resources information or other confidential data, including but not limited to personally identifiable information, that could have a material adverse effect on our business, financial condition, or results of operations.

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

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

We take various steps to identify and mitigate potential cybersecurity threats. As cyber incidents become more frequent and the sophistication of threat actors increases, our associated cybersecurity costs are expected to increase. Specifically, we expect to implement several incremental cybersecurity improvements over the next 18 to 36 months to enhance our defensive capabilities and resilience. Despite our ongoing and anticipated cybersecurity efforts, a successful cybersecurity incident could lead to additional material costs, including those related to the loss of sensitive information,

repairs to infrastructure or capabilities essential to our operations, responding to litigation or regulatory investigations, and those related to a material and adverse impact on our reputation, financial position, results of operations, or cash flows.

Our business may be impacted by macroeconomic conditions, including fears concerning the financial services industry, inflation, rising interest rates and volatile market conditions, and other uncertainties beyond our control.

Actual events involving limited liquidity, defaults, non-performance or other adverse developments that affect financial institutions, transactional counterparties or other companies in the financial services industry or the financial services industry generally, or concerns or rumors about any events of these kinds or other similar risks, have in the past and may in the future lead to market-wide liquidity problems. For example, on March 10, 2023, Silicon Valley Bank failed and was taken into receivership by the Federal Deposit Insurance Corporation; on March 12, 2023, Signature Bank and Silvergate Capital Corp. were each swept into receivership; the following week, a syndicate of U.S. banks infused $30 billion in First Republic Bank; and later that same week, the Swiss Central Bank provided $54 billion in covered loan and short-term liquidity facilities to Credit Suisse Group AG, all in an attempt to reassure depositors and calm fears of a banking contagion. Our ability to effectively run our business could be adversely affected by general conditions in the global economy and in the financial services industry. Various macroeconomic factors could adversely affect our business, including fears concerning the banking sector, changes in inflation, interest rates and overall economic conditions and uncertainties. A severe or prolonged economic downturn could result in a variety of risks, including our ability to raise additional funding on a timely basis or on acceptable terms. A weak or declining economy could also impact third parties upon whom we depend on to run our business. Increasing concerns over bank failures and bailouts and their potential broader effects and potential systemic risk on the banking sector generally and on the biotechnology industry and its participants may adversely affect our access to capital and our business and operations more generally. Although we assess our banking relationships as we believe necessary or appropriate, our access to funding sources in amounts adequate to finance or capitalize our current and projected future business operations could be significantly impaired by factors that affect us, the financial institutions with which we have arrangements directly, or the financial services industry or economy in general.

Currently, we do not have a business relationship with any of the banking institutions mentioned above, and our cash, cash equivalents and short term investments have been unaffected by the turmoil in the financial industry; however, we cannot guaranty that the banking institution with which we do business will not face similar circumstances in the future, or that the third parties with whom we do business will not be negatively affected by such circumstances.

The trading price of the Class A common stock has been, and is likely to continue to be, volatile and could fluctuate in response to a number of factors, many of which are beyond our control.

The trading price of the Class A common stock may fluctuate significantly in response to a number of factors, many of which are beyond our control. For instance, if our financial results are below the expectations of securities analysts and investors, the market price of the Class A common stock could decrease, perhaps significantly. Factors that may affect the market price of the Class A common stock include changes in market prices of oil, natural gas and natural gas liquids; announcements relating to significant corporate transactions; fluctuations in our quarterly and annual financial results; operating and stock price performance of companies that investors deem comparable to us; and changes in government regulation or proposals relating to us. In addition, the U.S. securities markets have experienced significant price and volume fluctuations, and these fluctuations often have been unrelated to the operating performance of companies in these markets. Any volatility of, or a significant decrease in, the market price of the Class A common stock could also negatively affect our ability to make acquisitions using Class A common stock. Further, if we were to be the object of securities class action litigation as a result of volatility in the Class A common stock price or for other reasons, it could result in substantial costs and diversion of our management’s attention and resources, which could negatively affect our financial results.

A credit ratings downgrade or other negative action by a credit rating organization could adversely affect the trading price of the shares of our Class A common stock.

Credit rating agencies continually revise their ratings for companies they follow. The condition of the financial and credit markets and prevailing interest rates have fluctuated in the past and are likely to fluctuate in the future.

In addition, developments in our business and operations could lead to a ratings downgrade for us or our subsidiaries. Any such fluctuation in our or our subsidiaries’ ratings may impact our ability to access debt markets in the future or increase our cost of future debt, which could have a material adverse effect on our operations and financial condition, which in return may adversely affect the trading price of shares of our Class A common stock.

Our certificate of incorporation provides that the Court of Chancery of the State of Delaware will be the exclusive forum for substantially all disputes between us and our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or employees.

Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternate forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the exclusive forum for (i) any derivative action, suit or proceeding brought on behalf of the Company; (ii) any action, suit or proceeding (including any class action) asserting a claim of breach of a fiduciary duty owed by any current or former director, officer, other employee, agent or stockholder of the Company to the Company or the Company’s stockholders; (iii) any action, suit or proceeding (including any class action) asserting a claim against the Company or any current or former director, officer, other employee, agent or stockholder of the Company arising out of or pursuant to any provision of the General Corporation Law, this Certificate of Incorporation or the By-laws (as each may be amended from time to time); (iv) any action, suit or proceeding (including any class action) to interpret, apply, enforce or determine the validity of this Certificate of Incorporation or the By-laws (including any right, obligation or remedy thereunder); (v) any action, suit or proceeding as to which the General Corporation Law confers jurisdiction to the Court of Chancery of the State of Delaware; or (vi) any action asserting a claim against the Company or any director, officer or other employee of the Company governed by the internal affairs doctrine, in all cases to the fullest extent permitted by law and subject to the court’s having personal jurisdiction over the indispensable parties named as defendants.

The choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and our directors, officers and other employees. Alternatively, if a court finds the choice of forum provision contained in our certificate of incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could materially and adversely affect our business, financial condition, and results of operations.

Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. In addition, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. To prevent having to litigate claims in multiple jurisdictions and the threat of inconsistent or contrary rulings by different courts, among other considerations, our certificate of incorporation provides that, unless we consent in writing to the selection of an alternate forum, the federal district courts of the United States of America will be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the federal securities laws. We note that there is uncertainty as to whether a court would enforce the choice of forum provision with respect to claims under the federal securities laws, and that investors cannot waive compliance with the federal securities laws and the rules and regulations thereunder.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Risk Management and Strategy

We rely on information technology and data to operate our business and develop, market, and deliver our products and services to our customers. We have implemented and maintain various information security processes designed to identify, assess and manage material risks from cybersecurity threats to critical computer networks, third party hosted services, communications systems, hardware, software, and our confidential, personal, proprietary, and sensitive data (collectively, “Information Assets”). Accordingly, we maintain certain risk assessment processes intended to identify cybersecurity threats. We have implemented an information technology security policy, which includes cybersecurity vulnerability management designed to protect the confidentiality, integrity, and availability of our Information Assets and mitigate harm to our business.

We engage in processes designed to identify such threats by, among other things, monitoring the threat environment using manual and automated tools. We subscribe to reports and services that identify cybersecurity threats, analyze reports of threats and conduct vulnerability assessments to identify vulnerabilities.

Depending on the environment, we implement and maintain various technical, physical and organizational measures designed to manage and mitigate material risks from cybersecurity threats to our Information Assets. We work with third parties, including cybersecurity software providers and managed cybersecurity service providers, to identify and assess cybersecurity risks and conduct penetration testing.

Governance

Our cybersecurity risk assessment and management processes are implemented and maintained by a third-party service provider reporting to the Company's management. Management is also responsible for integrating cybersecurity considerations into our overall risk management strategy, communicating key priorities to employees, approving budgets, helping to prepare for cybersecurity incidents, approving cybersecurity processes, reviewing security assessments and making required disclosures. Management participates in cybersecurity incident response efforts by being a member of the incident response team and helping direct our response to cybersecurity incidents.

Our board of directors addresses our cybersecurity risk management as part of its general oversight function. The Audit Committee of the board of directors is responsible for overseeing our cybersecurity risk management processes, including oversight and mitigation of risks from cybersecurity threats.

ITEM 2. PROPERTIES

We do not own any real property. Our corporate headquarters are located in White Plains, New York, where we occupy approximately 13,600 square feet of shared office space with an affiliate of Fortistar pursuant to an Administrative Services Agreement. In addition, we lease office and maintenance facilities in Oronoco, Minnesota and Rancho Cucamonga, California. Our interests in our RNG and Renewable Power projects are our only material properties. See Item 1. Business — Our projects for additional information.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we are involved in various legal proceedings, lawsuits and claims incidental to the conduct of our business, some of which may be material. Our businesses are also subject to extensive regulation, which may result in regulatory proceedings against us. We do not believe that the outcome of any of our current legal proceedings will have a material adverse impact on our business, financial condition and results of operations.

Set forth below is information related to the Company’s material pending legal proceedings as of the date of this report, other than ordinary routine litigation incidental to the business.

Central Valley Project

In September 2021, an indirect subsidiary of the Company, MD Digester, LLC, entered into a fixed-price Engineering, Procurement and Construction Contract (an “EPC Contract”) with VEC Partners, Inc. d/b/a CEI Builders (“Contractor”) for the design and construction of a turn-key renewable natural gas production facility using dairy cow manure as feedstock. In December 2021, a second indirect subsidiary of the Company, VS Digester, LLC entered into a nearly identical EPC Contract for the design and construction of a second facility in connection with the same project.

Contractor has submitted a series of change order requests seeking to increase the EPC Contract price under each contract by approximately $14 million (i.e., approximately $28 million in total), primarily due to modifications to Contractor’s design drawings that are required to meet its contracted performance guaranties and a termination (for default) of one of Contractor’s major equipment manufacturers. The Company disputes substantially all of the change order requests.

On January 5, 2024, the Company filed a civil lawsuit captioned, MD Digester, LLC. et. al. vs. VEC Partners, Inc. et. al.; California Superior Court, County of San Joaquin; Action No. STK-CV-UCC-2024-0000185 and commenced a related arbitration proceeding in order to obtain a formal determination on the claims, AAA Case No. 01-24-0000-0775. The Superior Court Action will be stayed, pending an award in the AAA proceeding. The AAA proceeding has not been set for hearing. Contractor is required to select an arbitrator who will in concert with the Company’s selected arbitrator nominate a Chair for the AAA, three-person arbitration panel. As a result of the procedural status of these matters, no discovery has occurred. The EPC Agreement provides that Contractor is obligated to continue working during the course of

the litigation and related arbitration proceedings. Contractor’s performance under both of the EPC Contracts is fully bonded by licensed sureties.

Despite informal settlement discussions with Contractor, the parties have not been able as of yet to resolve the claims. The Company believes its claims against Contractor have substantial merit, and intends to prosecute its claims vigorously. However, due to the incipient stage of the litigation and related arbitration, its ongoing status, and the uncertainties involved in all litigation and arbitration, the Company does not believe it is feasible at this time to assess the likely outcome of the litigation and related arbitration, the timing of its resolution, or its ultimate impact on the Central Valley projects or the Company's business, financial condition or results of operations.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

Common Stock

Our shares of Class A common stock are traded on the Nasdaq Stock Market LLC under the symbol "OPAL".

On March 13, 2024, the closing sale price of our shares of Class A common stock, as reported on the Nasdaq Stock Market LLC, was $4.91 per share.

The number of shareholders of record of our shares of Class A common stock was approximately 11 on March 13, 2024.

Payment of Dividends

We have never declared or paid cash dividends on our capital stock. Our Board of Directors currently intends to retain any future earnings to support operations and to finance the growth and development of our business, and therefore does not intend to pay cash dividends on our common stock in the near term.

Unregistered Sales of Equity Securities; Use of Proceeds from Registered Offerings

None

Purchases of Equity securities by the Issuer and Affiliated Purchasers

None.

ITEM 6. RESERVED

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

In this Management's Discussion and Analysis of Financial Condition and Results of Operations section, references to "OPAL", "we", "us", "our", and the "Company" refer to OPAL Fuels Inc. and its consolidated subsidiaries. The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes set forth in Part II, Item 8 - "Financial Statements and Supplementary Data" and the risk factors identified in Part I, Item 1A - "Risk Factors" of this Annual Report. For further discussion regarding our results of operations for the year ended December 31, 2022 as compared to the year ended December 31, 2021, refer to Part II, Item 7 - "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022, as filed with the SEC on March 29, 2023. In addition to historical information, this discussion and analysis includes certain forward-looking statements which reflect our current expectations. The Company's actual results may materially differ from these forward-looking statements.

Overview

The Company is a vertically integrated leader in the capture and conversion of biogas into low carbon intensity Renewable Power and renewable natural gas (RNG). OPAL Fuels is also a leader in the marketing and distribution of RNG to heavy duty trucking and other hard to de-carbonize industrial sectors. RNG is chemically identical to the natural gas used for cooking, heating homes and fueling natural gas engines, with one significant difference: RNG is produced by recycling harmful methane emissions created by decaying organic waste as opposed to natural gas which is a fossil fuel pumped from the ground. We have participated in the biogas-to-energy industry for over 20 years.

Biogas is generated by microbes as they break down organic matter in the absence of oxygen, and comprised of non-fossil waste gas, with high concentrations of methane, which is the primary component of RNG and the source for combustion utilized by Renewable Power plants to generate electricity. Biogas can not only 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 fossil natural gas, but partially treated biogas can be used directly in heating applications (as a form of medium-Btu fuel) or in the production of Renewable Power. Our principal sources of biogas are (i) landfill gas, which is produced by the decomposition of organic waste at landfills, and (ii) dairy manure, which is processed through anaerobic digesters to produce the biogas.

Recent developments

Inflation Reduction Act

The Inflation Reduction Act (the "IRA") was signed into law on August 16, 2022. The bill invests nearly $369 billion in energy and climate policies. The provisions of the IRA are intended to, among other things, incentivize domestic clean energy investment, manufacturing, and deployment. The IRA incentivizes the deployment of clean energy technologies by extending and expanding federal incentives such as ITCs and the PTC. We view the enactment of the IRA as favorable for the overall business climate for the renewable energy industry. However, there is uncertainty related to the applicability of the IRA to our current and planned projects and the scope of the IRA and its interpretations may change if there is a change in the U.S. administration or if government agencies’ authority to interpret federal law is restricted as a result of the Supreme Court’s review of the Chevron doctrine under which federal government agencies have been awarded board authority to interpret broad or ambiguous legislation. We may also continue to experience a delay in our sales cycles and new award activity as our customers consider the applicability of the IRA and as financing projects may take longer as

result of this uncertainty. The IRA may increase the competition in our industry and as such increase the demand and cost for labor, equipment and commodities needed for our projects.

On November 17, 2023, the Treasury and the IRS proposed regulations regarding ITCs on renewable energy projects where IRS specified certain types of RNG equipment are ineligible for ITCs which could negatively impact the profitability of our RNG business and our ability to finance our RNG projects. On February 16, 2024, the Treasury and the IRS released a correction to the proposed regulations clarifying that certain of such equipment may be eligible for ITCs. These regulations are merely proposed, and Treasury and the IRS are collecting and reviewing comments received regarding the proposed regulations. The proposed regulations also contain provisions that we believe create uncertainty relating to the ownership, installation or modification of equipment and property on which ITCs can be claimed.

If the final regulations are enacted in a form that limits, in whole or in part, the amount of ITCs for certain of our construction costs, this would reduce the amount of ITCs available and thus could have a material adverse effect on our operations and our business.

ATM Program

Asset Sale and Purchase Agreement

On October 20, 2023, our wholly-owned subsidiary entered into an Asset Purchase and Sale Agreement (for the purposes of this paragraph, the “Agreement”) with Washington Gas Light Company ("WGL"). The subsidiary is currently constructing a production facility (the “Facility”) at the Prince William County landfill located in Manassas, Virginia, on a parcel located on the landfill, to process landfill gas into RNG. The Agreement obligates the subsidiary to develop, plan and permit a gas pipeline extension and associated interconnection facilities (the “Pipeline Project”) to deliver RNG from the Facility to an interconnection point on WGL’s pipeline. Per the terms and conditions of the Agreement, WGL will purchase the Project from the subsidiary after the final completion of the Project at a purchase price of $25 million. The closing is contingent upon approval of the Agreement by the Virginia State Corporation Commission, as well as the satisfaction of customary closing conditions, and the outside closing date is on or prior to October 20, 2024. As of December 31, 2023, the Company recorded capital expenditure of $1.8 million which is included in its Property, Plant and Equipment on our consolidated balance sheet.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") and the rules and regulations of the SEC, which apply to interim financial statements. The preparation of those financial statements requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, revenues, expenses and warrants and related disclosure of contingent assets and liabilities at the date of our financial statements. Actual results may differ from these estimates under different assumptions and conditions.

Critical accounting policies are those that reflect significant judgments of uncertainties and potentially result in materially different results under different assumptions and conditions. We have described below what we believe are our most critical accounting policies, because they generally involve a comparatively higher degree of judgment in their

application. For a detailed description of all our accounting policies, see Note 2. Summary of Significant Accounting Policies, to our consolidated financial statements included herein.

Revenue Recognition

Renewable Power

We sell Renewable Power produced from LFG-fueled power plants to utility companies through our PPAs. Revenue is recognized based on contract specified rates per MWh when delivered to the customer, as this considered to be completion of the performance obligation. Certain PPAs contain a lease element which we account for as operating lease revenue on a straight-line basis over the lease term. The Company utilizes commodity swap contracts to hedge against the unfavorable price fluctuations in market prices of electricity. The Company does not apply hedge accounting to these contracts. As such, unrealized and realized gain (loss) is recognized as component of Renewable Power revenues in the consolidated statement of operations.

Transportation fuel — Fuel Purchase Agreements

We own Fueling Stations for use by customers under fuel sale agreements. We bill these customers at an agreed upon price for each gallon sold and recognize revenue based on the amounts invoiced in accordance with the “right to invoice” practical expedient. These contracts may contain an embedded lease of the equipment which we account for as operating lease revenue. For some public stations where there is no contract with the customer, we recognize revenue at the point in time that the customer takes control of the fuel.

Interstate Gas Pipeline Delivery

We have agreements with two natural gas producers whereby we are contracted to transport the producers’ gas to an agreed delivery point on an interstate gas pipeline via our RNG gathering system. Revenue is recognized over time using the output method which is based on quantity of natural gas transported.

Environmental Attributes

We generate RECs, RINs, ISCC Carbon Credits and LCFS credits. These Environmental Attributes are sold to third parties that utilize these credits in order to comply with federal and state requirements. Revenue is recognized at the point in time when the credits are transferred to and accepted by the third party buyer. We also provide Environmental Attributes generation and monetization services to customers that own renewable gas generation facilities and we recognize revenues from these services when the credits are minted on behalf of the customer.

Operation and Maintenance

We have operating and maintenance agreements pursuant to which we operate, maintain, and repair landfill site gas collection systems. Revenue is based on the volume per million British thermal units (“MMBtu”) of landfill gas collected and the MWhs produced at that site. This revenue is recognized as Renewable Power revenue when landfill gas is collected and Renewable Power is delivered. In addition, we have operations and maintenance agreements in which we are contracted to maintain and repair Fueling Stations. Revenue is based on the volumes of gas dispensed at the site. This revenue is recognized as Fuel Station Services revenue when the site dispenses gas.

Construction Type Contracts — Third Party

We have various fixed price contracts for the construction of fueling stations for customers. Revenue from these contracts, including change orders, are recognized over time, with progress measured by the percentage of cost incurred to date to estimated total cost for each contract.

Impairment of Goodwill

When a business is acquired, goodwill is recognized to reflect any future economic benefits that are not separately recognized, such as synergies. For the purposes of impairment testing, U.S. GAAP requires goodwill to be allocated to reporting unit(s) at the acquisition date and to be tested for impairment at least annually, and in between annual tests whenever events or changes in circumstances indicate that the respective reporting unit’s fair value is less than its

carrying value. Significant judgment is required when identifying the reporting units for goodwill allocation, during our assessment of relevant events and circumstances for qualitative impairment indicators, and when estimating the undiscounted cash flows of reporting unit(s) for quantitative impairment assessments.

Our goodwill impairment assessment is performed during the fourth quarter of each year or at the time facts or circumstances indicate that a reporting unit’s goodwill may be impaired. In conformity with GAAP, we generally first perform a qualitative assessment over whether it is more likely than not that a reporting unit’s fair value is less than its carrying value to determine if a quantitative assessment is required. If, after performing the qualitative assessment, we conclude it is more likely than not that the fair value of the reporting unit is less than its carrying value, then a quantitative test is required. Our qualitative assessment includes evaluation of relevant events and circumstances, such as, macroeconomic conditions, industry and market considerations, cost factors, overall performance, and other relevant events.

If applying a quantitative assessment, we would estimate a reporting unit’s fair value based on the income approach. With this approach, the fair value measurement is based on significant inputs that are not observable in the market and thus the fair value measurement is categorized within Level 3 of the fair value hierarchy. Our assumptions include future cash flow projections, a discount rate range based on the weighted average cost of capital, and a terminal value based on a range of terminal earnings before interest, taxes, depreciation, and amortization.

As of December 31, 2023, we performed a qualitative assessment for Goodwill in our RNG Fuel and Fuel Station Services segments and determined that there are no impairment triggers present and therefore no quantitative assessment was performed. Based on the qualitative assessment, we determined that no impairment is necessary on the goodwill recorded in the books as of December 31, 2023.

Impairment of Long-Lived Assets

Our long-lived assets held and used with finite useful lives including plant equipment, buildings, patents, and PPAs are reviewed for impairment whenever events or changes in circumstances indicate that the asset group may not be recoverable. In determining the asset group, we assess the interdependency of revenues between assets, shared cost structures, the interchangeability of assets used in operations, and how assets are managed and utilized by the business. Events that may trigger a recoverability assessment include a significant adverse change in the extent or manner in which the long-lived asset group is being used or in its physical condition, and the expectation that, more likely than not, the long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. Recoverability of long-lived assets to be held and used is measured by a comparison of the carrying amount of an asset group to future net undiscounted cash flows expected to be generated by the asset group. Our cash flow estimates reflect conditions and assumptions that existed as of the measurement date which is the same as the triggering event date. The assets are considered recoverable and an impairment loss is not recognized when the undiscounted net cash flows exceed the net carrying value of the asset group. If the assets are not recoverable, then an impairment loss is recognized to the extent that the carrying value of the asset group exceeds its fair value. We base the fair value of our assets or asset groups off of the estimated discounted future cash flows using market participant assumptions. Assets disposed of are reported at the lower of the carrying amount or fair value less selling costs. Significant judgment is required when determining asset group composition, during our assessment of relevant events and circumstances, when determining an appropriate discount rate, and when estimating the undiscounted and discounted future cash flows of the asset group.

Based on our assessment for the year ended December 31, 2023, there is no impairment recorded on our Plant, Property and Equipment.

Fair Value Measurements

The objective of a fair value measurement is to estimate the exit price, which is the price that would be received to sell an asset or paid to transfer a liability that the Company holds, in an orderly market transaction at the measurement date. We follow GAAP guidance which establishes a three-tier hierarchy for inputs used in fair value measurements, as well as prioritizes valuation techniques that maximize the use of observable inputs and minimizes the use of unobservable inputs. In summary, level 1 inputs are considered the most observable inputs and are more specifically the unadjusted quoted price for identical assets or liabilities in an active market the Company has access to. Level 2 inputs are considered less observable inputs such as quoted prices for similar assets or liabilities in an active market the Company has access to. Lastly, level 3 inputs are unobservable inputs in which little to no market activity exists for the asset or liability at the measurement date. As such, level 3 estimates are subject to a more significant level of estimation uncertainty. Furthermore,

when multiple inputs are used and are categorized in different levels of the input hierarchy, then the fair value measurement in its entirety is categorized in the same level as its lowest level input that is significant to the fair value measurement. Our assessment of the significance of an input to a fair value measurement requires judgment and may affect the fair value measurement’s placement in the fair value hierarchy.

Refer to Note 9. Derivative Financial Instruments and Fair Value Measurements, to our consolidated financial statements, for details on our assets and liabilities regularly recorded at fair value and the respective placements in the fair value hierarchy.

Income Taxes

The Company accounts for income taxes in accordance with ASC Topic 740, Accounting for Income Taxes (“ASC Topic 740”), which requires the recognition of tax benefits or expenses on temporary differences between the financial reporting and tax bases of its assets and liabilities by applying the enacted tax rates in effect for the year in which the differences are expected to reverse. Such net tax effects on temporary differences are reflected on the Company’s consolidated balance sheets as deferred tax assets and liabilities. Deferred tax assets are reduced by a valuation allowance when the Company believes that it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. The Company calculates the interim tax provision in accordance with the provisions of ASC Subtopic 740-270, Income Taxes; Interim Reporting. For interim periods, the Company estimates the annual effective income tax rate and applies the estimated rate to the year-to-date income or loss before income taxes.

Refer to Note 15. Income Taxes, to our consolidated financial statements, for additional information.

Emerging Growth Company Status

We are an emerging growth company as defined in the JOBS Act. The JOBS Act provides emerging growth companies with certain exemptions from public company reporting requirements for up to five fiscal years while a company remains an emerging growth company. As part of these exemptions, we need only provide two fiscal years of audited financial statements instead of three, we have reduced disclosure obligations such as for executive compensation, and we are not required to comply with auditor attestation requirements from Section 404(b) of the Sarbanes-Oxley Act regarding our internal control over financial reporting. Additionally, the JOBS Act has allowed us the option to delay adoption of new or revised financial accounting standards until private companies are required to comply with new or revised financial accounting standards.

Use of Estimates

The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The significant estimates and assumptions of the Company relate to the useful lives of property, plant and equipment, goodwill impairment, fair value of the deconsolidated VIEs, the value of stock-based compensation, asset retirement obligations and the fair value of derivatives including earnout liabilities and commodity swap contracts.

Key Factors and Trends Influencing our Results of Operations

The principal factors affecting our results of operations and financial condition are the markets for RNG, Renewable Power, and associated Environmental Attributes, and access to suitable biogas production resources. Additional factors and trends affecting our business are discussed in "Risk Factors" elsewhere in this report.

Market Demand for RNG

Demand for our converted biogas and associated Environmental Attributes, including RINs and LCFS credits, is heavily influenced by United States federal and state energy regulations together with commercial interest in renewable energy products. Markets for RINs and LCFS credits arise from regulatory mandates that require refiners and blenders to incorporate renewable content into transportation fuels. The EPA annually sets proposed renewable volume obligations ("RVOs") for D3 (cellulosic biofuel with a 60% greenhouse gas (“GHG”) reduction requirement) RINs in accordance with the mandates established by the Energy Independence and Security Act of 2007. In June 2023, the EPA set RVOs for 2023 through 2025 via a new Set rule. This 3 year RVO is expected to reduce volatility in RIN pricing for the associated period. On the state level, the economics of RNG are enhanced by low-carbon fuel initiatives, particularly well-established

programs in California and Oregon (with several other states also actively considering LCFS initiatives similar to those in California, Washington and Oregon). Federal and state regulatory developments could result in significant future changes to market demand for the RINs and LCFS credits we produce. This would have a corresponding impact to our revenue, net income, and cash flow.

Transportation, including heavy-duty trucking, generates approximately 30% of overall CO₂ and other climate-harming GHG emissions in the United States, and transitioning this sector to low and negative carbon fuels is a critical step towards reducing overall global GHG emissions. The adoption rate of RNG-powered vehicles by commercial transportation fleets will significantly impact demand for our products.

We are also exposed to the commodity prices of natural gas and diesel, which serve as alternative fuel for RNG and therefore impact the demand for RNG.

Renewable Power Markets

We also generate revenues from sales of Renewable Power generated by our biogas-to-Renewable Power projects, and associated ISCC Carbon Credits and RECs. ISCC Carbon Credits and RECs exist because of legal and governmental regulatory requirements in Europe and the United States, respectively, and a change in law or in governmental policies concerning Renewable Power, LFG, or ISCC Carbon Credits or RECs could affect the market for, and the pricing of, such power and credits.

We periodically evaluate opportunities to convert existing Renewable Power projects to RNG production. We have been negotiating with several of our landfill and Renewable Power counterparties to enter into arrangements that would enable the LFG resource to produce RNG. Changes in the price we receive for Renewable Power, associated ISCC Carbon Credits and RECs, together with the revenue opportunities and conversion costs associated with converting our LFG sites to RNG production, could have a significant impact on our future profitability.

Regulatory landscape

We operate in an industry that is subject to and currently benefits from environmental regulations. Government policies can increase demand for our products by providing incentives to purchase RNG and Environmental Attributes. These government policies are modified and in flux constantly and any adverse changes to these policies could have a material effect the demand for our products. For more information, see our risk factor titled "The financial performance of our business depends upon tax and other government incentives for the generation of RNG and Renewable Power, any of which could change at any time and such changes may negatively impact our growth strategy." Government regulations have become increasingly stringent and complying with changes in regulations may result in significant additional operating expenses.

Seasonality

We experience seasonality in our results of operations. Sale of RNG may be impacted by higher consumption by some of our customers during summer months. Additionally, the price of RNG is higher during the fall and winter months due to increase in overall demand for natural gas during the winter months. Revenues generated from our renewable electricity projects in the northeast U.S., all of which sell electricity at market prices, are affected by warmer and colder weather, and therefore a portion of our quarterly operating results and cash flows are affected by pricing changes due to regional temperatures. These seasonal variances are managed in part by certain off-take agreements at fixed prices.

Key Components of Our Results of Operations

We generate revenues from the sale of RNG fuel, Renewable Power, and associated Environmental Attributes, as well as from the construction, fuel supply, and servicing of Fueling Stations for commercial transportation vehicles using natural gas to power their fleets. These revenue sources are presented in our statement of operations under the following captions:

•RNG Fuel. The RNG Fuel segment includes RNG supply as well as the associated generation and sale of commodity natural gas and environmental credits, and consists of:

◦RNG Production Facilities – the design, development, construction, maintenance and operation of facilities that convert raw biogas into pipeline quality natural gas; and

◦Our interests in both operating and construction projects.

•Fuel Station Services. Through our Fuel Station Services segment, we provide construction and maintenance services to third-party owners of vehicle Fueling Stations and performs fuel dispensing activities including generation and minting of environmental credits. This segment includes:

◦Manufacturing division that builds Compact Fueling Systems and Defueling systems;

◦Design/Build contracts where we serve as general contractor for construction of Fueling Stations, typically structured as Guarantee Maximum Price or fixed priced contracts for customers, generally lasting less than one year;

◦Service and maintenance contracts for RNG/CNG Fueling Stations; and

◦RNG and CNG Fuel Dispensing Stations - This includes both the dispensing (or sale) of RNG, CNG, and environmental credit generation and monetization. We operate Fueling Stations that dispense both CNG and RNG fuel for vehicles.

•Renewable Power. The Renewable Power segment generates renewable power and associated Environmental Attributes such as ISCC Carbon Credits and RECs through combustion of biogas from landfills which is then sold to public utilities throughout the United States.

Our costs of sales associated with each revenue category are as follows:

•RNG Fuel. Includes royalty payments to biogas site owners for the biogas we use; service provider costs; salaries and other indirect expenses related to the production process, utilities, transportation, storage, and insurance; and depreciation of production facilities.

•Fuel Station Services. Includes equipment supplier costs; service provider costs; and salaries and other indirect expenses.

•Renewable Power. Includes royalty payments, land usage costs; service provider costs; salaries and other indirect expenses related to the production process; utilities; and depreciation of production facilities.

Project development and start up costs includes certain development costs such as legal, consulting fees for joint venture structuring, royalties to the landfill owner, fines, settlements, site lease expenses and certification costs on our RNG projects under construction. Additionally, the Company also incurs certain expenses on new RNG projects that went operational for the first two years such as virtual pipeline costs (incurred until a physical interconnect pipeline is built) and ramp up costs incurred during the certification period.

Selling, general, and administrative expense consists of costs involving corporate overhead functions, including the cost of services provided to us by an affiliate, and marketing costs.

Depreciation and amortization primarily relate to depreciation associated with property, plant, and equipment and amortization of acquired intangibles arising from PPAs and interconnection contracts. We are in the process of expanding our RNG and Renewable Power production capacity and expect depreciation costs to increase as new projects are placed into service.

Concentration of customers and associated credit risk

The following table summarizes the percentage of consolidated accounts receivable, net by customers that equal or exceed 10% of the consolidated accounts receivable, net as of December 31, 2023 and 2022. No other single customer accounted for 10% or greater of our consolidated accounts receivables in these periods:


	Twelve Months Ended December 31,
	2023		2022
Customer A (1)	40	%	29	%
Customer B	14	%	—	%
Customer C	—	%	16	%

(1) Relates to sales of environmental attributes under Purchase and Sale agreement with NextEra.

The following table summarizes the percentage of consolidated revenues from customers that equal 10% or greater of the consolidated revenues in the period. No other single customer accounted for more than 10% of consolidated revenues in these periods:


	Twelve Months Ended December 31,
	2023		2022
Customer A	36	%	35	%
Customer B	11	%	14	%

Results of Operations for the years ended December 31, 2023 and 2022:

Operational data

The following table summarizes the operational data achieved for the years ended December 31, 2023 and 2022:

Landfill RNG Facility Capacity and Utilization Summary


	Three Months Ended December 31,				Twelve Months Ended December 31,
	2023		2022		2023		2022
Landfill RNG Facility Capacity and Utilization(1)(2)(3)(4)
Design Capacity (Million MMBtus)	1.3		0.9		4.1		3.2
Volume of Inlet Gas (Million MMBtus)	1.0		0.7		3.2		2.4
Inlet Design Capacity Utilization %	80	%	75	%	78	%	75	%
RNG Fuel volume produced (Million MMBtus)	0.7		0.6		2.6		2.0
Utilization of Inlet Gas %	79	%	84	%	83	%	86	%

(1) Design Capacity for RNG facilities is measured as the volume of feedstock biogas that the facility is capable of accepting at the inlet and processing during the associated period. Design Capacity is presented as OPAL’s ownership share (i.e., net of joint venture partners’ ownership) of the facility and is calculated based on the number of days in the period. New facilities that come online during a quarter are pro-rated for the number of days in commercial operation.

(2) Inlet Design Capacity Utilization is measured as the Volume of Inlet Gas for a period, divided by the total Design Capacity for such period. The Volume of Inlet Gas varies over time depending on, among other factors, (i) the quantity and quality of waste deposited at the landfill, (ii) waste management practices by the landfill, and (iii) the construction, operations and maintenance of the landfill gas collection system used to recover the landfill gas. The Design Capacity for each facility will typically be correlated to the amount of landfill gas expected to be generated by the landfill during the term of the related gas rights agreement. The Company expects Inlet Design Capacity Utilization to be in the range of 75-85% on an aggregate basis over the next several years. Typically, newer facilities perform at the lower end of this range and demonstrate increasing utilization as they mature and the biogas resource increases at open landfills.

(3) Utilization of Inlet Gas is measured as RNG Fuel Volume Produced divided by the Volume of Inlet Gas. Utilization of Inlet Gas varies over time depending on availability and efficiency of the facility and the quality of landfill gas (i.e., concentrations of methane, oxygen, nitrogen, and other gases). The Company generally expects Utilization of Inlet Gas to be in the range of 80% to 90%.

(4) Data not available for the Company's dairy projects, i.e., Sunoma and Biotown. Total RNG fuel design capacity for the three and twelve months ended December 31, 2023 is 1.3 million MMBtu and 4.3 million MMBtu, respectively. Including Sunoma and Biotown, RNG fuel volume produced is 0.8 and 2.7 million MMBtu for the three and twelve months ended December 31, 2023, respectively.


	Twelve Months Ended December 31,
	2023		2022
Renewable Power
Nameplate Capacity (MW per hour)(1)	112.5		112.5
Nameplate Capacity for the period (Millions MWh) (1)	0.98		0.98
Renewable Power produced ( Millions MWh)	0.44		0.47
Design Capacity Utilization (%) (2)	45	%	48	%

(1) Design Capacity for Renewable Power facilities is the manufacturer’s expected capacity at ISO conditions for each facility and may not reflect actual production from the projects, which depends on many variables including, but not limited to, (i) quantity and quality of the biogas, (ii) operational up-time of the facility, including dispatch and maintenance downtime and (iii) actual efficiency of the facility.

(2) Design Capacity Utilization for Renewable Power facilities is measured as Renewable Power Produced divided by Design Capacity for the period. Given (i) built-in un-utilized capacity from historical designs, (ii) availability (a function of higher maintenance requirements compared to RNG facilities) and (iii) commencement of operations of the Emerald RNG facility, which will result in low levels of dispatch for the Arbor Hills facility (which will operate on a standby basis but remain in the operating portfolio), the Company’s Design Capacity Utilization is expected to remain below 50%.


	Twelve Months Ended December 31,
	2023	2022

RNG Fuel volume produced (Million MMBtus)	2.7	2.2
RNG Fuel volume sold (Million GGEs)	43.8	29.4
Total volume delivered (Million GGEs)	133.2	115.9

RNG projects

Below is a table setting forth the RNG projects in operation and construction in our portfolio:

OPAL's Share of Design Capacity (MMbtus per year) (1)

Source of Biogas

Ownership

Expected Commercial Operation Date (5)

RNG Projects in Operation:

Greentree

1,061,712

LFG

100%

N/A

Imperial

1,061,712

LFG

100%

N/A

Emerald (2) (3)

1,327,140

LFG

50%

N/A

New River

663,570

LFG

100%

N/A

Noble Road (2)

464,499

LFG

50%

N/A

Pine Bend (2)

424,685

LFG

50%

N/A

Biotown (2)

48,573

Dairy

10%

N/A

Sunoma (4)

192,350

Dairy

90%

N/A

Sub total

5,244,241

RNG Projects in Construction:

Prince William

1,725,282

LFG

100%

First quarter 2024

Hilltop (6)

255,500

Dairy

100%

Not Determined

Vander Schaaf (6)

255,500

Dairy

100%

Not Determined

Polk County

1,060,000

LFG

100%

Fourth quarter 2024

Sapphire (2)

796,284

LFG

50%

Third quarter 2024

Atlantic (2)

331,785

LFG

50%

Mid 2025

Sub total

4,424,351

(1) Reflects the Company’s ownership share of design capacity for projects that are not 100% owned by the Company (i.e., net of joint venture partners’ ownership). Design capacity is measured as the volume of feedstock biogas that the plant is capable of accepting at the inlet and processing and may not reflect actual production of RNG from the projects, which will depend on many variables including, but not limited to, (i) quantity and quality of the biogas, (ii) operational up-time of the facility and (iii) actual efficiency of the facility.

(2) We record our ownership interests in these projects as equity method investments in our consolidated financial statements.

(3) Emerald completed commissioning and commenced operations during the third quarter of 2023.

(6) Please see Item 3: Legal Proceedings and Note 17 - Commitments and Contingencies to the financial statements.

Renewable Power Projects

Below is a table setting forth the Renewable Power projects in operation in our portfolio:


	Nameplate capacity (MW per hour) (1)	Current RNG conversion candidate (2)
Renewable Power projects in operation:
Sycamore	5.2	Yes
Lopez	3.0	—
Miramar Energy	3.2	Yes
San Marcos	1.8	—
Santa Cruz	1.6	—
San Diego - Miramar	6.5	Yes
West Covina	6.5	—
Port Charlotte	2.9	—
Taunton	3.6	—
Arbor Hills (3)	28.9	N/A
C&C	6.3	Yes
Albany	5.9	—
Concord and CMS	14.4	Yes
Pioneer	8.0	—
Prince William I (4)	1.9	Yes
Prince William II (5)	4.8	Yes
Old Dominion	8.0	Yes
Total	112.5
Renewable Power projects in construction:
Fall River (6)	2.4	—

(4) Prince William I renewable power plant discontinued operations in Q1 2024.

(5) Prince William II discontinued operations in Q1 2024.

(6) It is expected to complete construction in fourth quarter of 2024.

Comparison of the Years Ended December 31, 2023 and 2022

The following table presents the period-over-period change for each line item in the Company's consolidated statements of operations for the twelve months ended months ended December 31, 2023 and 2022 .


	Twelve Months Ended December 31,				$ Change		% Change
(in thousands)	2023		2022
Revenues:
RNG fuel	$	66,292	$	73,158	$	(6,866)	(9)	%
Fuel station services	135,012		117,415		17,597		15	%
Renewable Power	54,804		44,958		9,846		22	%
Total revenues	256,108		235,531		20,577		9	%
Operating expenses:
Cost of sales - RNG fuel	32,028		32,367		(339)		(1)	%
Cost of sales - Fuel station services	115,322		98,845		16,477		17	%
Cost of sales - Renewable power	36,550		31,580		4,970		16	%
Project development and start up costs	4,866		6,438		(1,572)		(24)	%
Selling, general, and administrative	51,262		51,386		(124)		—	%
Depreciation, amortization, and accretion	14,565		13,136		1,429		11	%
Income from equity method investments	(5,525)		(5,784)		259		(4)	%
Total expenses	249,068		227,968		21,100		9	%
Operating income	7,040		7,563		(523)		(7)	%
Other income (expense)
Interest and financing expense, net	(9,306)		(6,640)		(2,666)		(40)	%
Change in fair value of derivative instruments, net	7,346		33,081		(25,735)		(78)	%
Other income	124,472		1,943		122,529		6306	%
Loss on debt extinguishment	(2,190)		—		(2,190)		100	%
Loss on warrant exchange	(338)		(3,368)		3,030		90	%
Net income before provision for income taxes	127,024		32,579		94,445		290	%
Provision for income taxes	—		—		—		—	%
Net income	127,024		32,579		94,445		290	%
Net income attributable to redeemable non-controlling interests	97,426		22,409		75,017		335	%
Net loss attributable to non-redeemable non-controlling interests	(349)		(1,153)		804		70	%
Dividends on Redeemable preferred non-controlling interests	11,011		7,932		3,079		39	%
Net income attributable to common stockholders	$	18,936	$	3,391	$	15,545	458	%

Revenues


(in thousands)	Twelve Months Ended December 31,
	2023		2022		$ Change
RNG Fuel
Brown gas sales	$	4,231	$	11,863	$	(7,632)
Environmental Attributes (1)	61,221		61,049		172
Other	840		246		594
Total RNG Fuel	$	66,292	$	73,158	$	(6,866)
Fuel Station Services
OPAL owned stations	$	18,958	$	19,263	$	(305)
RNG marketing (1)	45,277		28,912		16,365
Third party station service and maintenance	21,857		19,602		2,255
Construction	48,920		49,638		(718)
Total Fuel Station Services	$	135,012	$	117,415	$	17,597
Renewable Power
Electricity sales	$	34,680	$	39,461	$	(4,781)
Environmental Attributes (2)	20,124		5,497		14,627
Total Renewable Power	$	54,804	$	44,958	$	9,846

Total Revenues	$	256,108	$	235,531	$	20,577

(1) Revenues from Environmental Attributes in RNG Fuel segment and RNG marketing in Fuel Station Services segment relate to revenues earned from sales of RINs and LCFSs.

(2) Revenues from Environmental Attributes in Renewable Power segment include revenues earned from sales of ISCC carbon sales and RECs.

RNG Fuel

Revenue from RNG Fuel decreased by $6.9 million, or 9%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. This is primarily due to a decrease of $7.1 million in pricing and $0.5 million due to decrease in volumes relating to brown gas sales. The revenues from sale of Environmental Attributes remained flat year over year as lower RIN pricing was offset by higher volumes of sales. Additionally, there was $0.6 million increase in revenues earned from providing management services to unconsolidated entities.

Fuel Station Services

Revenue from Fuel Station Services increased by $17.6 million, or 15%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. This was primarily attributable to increase of $16.4 million in RNG marketing revenues due to higher Environmental Credit sales and marketing services, $2.3 million increase in service and maintenance revenues from increase in number of sites offset by decrease in construction revenues of $0.7 million.

Renewable Power

Revenue from Renewable Power increased by $9.8 million, or 22%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. This change was attributable primarily to an increase of $14.6 million from sale of ISCC Carbon Credits and REC sales, offset by decrease of $2.6 million from shutdown of one of our facilities and $2.7 million decrease in revenues at two of our Renewable Power facilities due to conversion into RNG facilities. Additionally, the increase also resulted from one facility which was shut down for maintenance for majority of the year in 2022 but was operational in 2023.

Cost of sales

RNG Fuel

Cost of sales from RNG Fuel marginally decreased by $0.3 million, or 1%, for the year ended December 31, 2023 compared to the year ended December 31, 2022.

Fuel Station Services

Cost of sales from Fuel Station Services increased by $16.5 million, or 17%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. This change was attributable primarily to an increase of $13.4 million of dispensing fees to generate Environmental Attributes, $0.9 million in construction costs, $2.7 million in service related costs offset by decrease in $1.2 million due to lower brown gas pricing.

Renewable Power

Cost of sales from Renewable Power increased by $5.0 million, or 16%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. This is primarily due to an increase of $1.3 million due to PPA termination expense, $2.5 million in planned maintenance expense and an $0.7 million increase in royalty expense at one of our facilities related to royalties on ISCC Carbon Credit sales.

Project development and start up costs

Project development and start up costs decreased by $1.6 million or 24%, for the year ended December 31, 2023compared to the year ended December 31, 2022. This is primarily due to decrease in virtual pipeline costs incurred on New River in 2022 which were not incurred after first quarter of 2023.

Selling, general, and administrative

Selling, general, and administrative expenses remained flat for the year ended December 31, 2023 compared to the year ended December 31, 2022.

Depreciation, amortization, and accretion

Depreciation, amortization, and accretion expense increased by a total of $1.4 million, or 11%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. This change was primarily due to an $0.3 million increase from New River as depreciation for New River represented a partial year in 2022, $1.0 million increase in Beacon and our Renewable Power facilities and a $0.2 million increase from amortization of right-of-use assets for finance leases and increase in depreciation expense in our Fuel Station Services segment due to increase in the number of owned stations.

Income from equity method investments

Net income attributable to equity method investments decreased by $0.3 million, or 4%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. This is primarily due to the recording of a $3.2 million gain on settlement of commodity swap contracts as our portion from GREP in the third quarter of 2022 and an increase in net income from Pine Bend and Noble Road offset by the amortization of basis differences of $3.0 million in 2023.

Interest and financing expense, net

Interest and financing expenses, net increased by $2.7 million, or 40%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. This is primarily due to an increase in interest expense on the OPAL Term Loan of $3.3 million primarily due to an increase in outstanding debt, $1.2 million on the Convertible Note Payable (we recorded a gain of $2.9 million in 2022) and $0.5 million in commitment fees offset by a decrease of $3.5 million in interest expense on our Senior Secured Credit Facility as the debt was repaid in full in March 2023.

Change in fair value of derivatives, net

Change in fair value of derivatives, net decreased by $25.7 million, or 78%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. This change was attributable primarily to a decrease in gain of $30.2 million on our earnout liabilities, change in the fair value of a contingent payment to a non-controlling interest in one of our VIEs of $4.3 million, change in fair value of interest rate swaps and put option, offset by a negative change in fair

value of warrant liabilities of $9.0 million. These liabilities were recorded in the consolidated balance sheet upon completion of the Business Combination.

Other income

Other income increased by $122.5 million, or 6306%, for the year ended December 31, 2023 compared to the year ended December 31, 2022. This change is primarily related to a gain $122.9 million recognized on deconsolidation of VIEs, Emerald and Sapphire.

Loss on debt extinguishment

On May 30, 2023, OPAL Intermediate Holdco 2 assigned to Paragon its rights and obligations under OPAL Term Loan II. The joint venture partner of Paragon reimbursed OPAL Intermediate Holdco 2 $0.8 million as its portion of the transaction costs incurred.

The Company expensed the remaining deferred financing costs of $1.9 million as loss on debt extinguishment in its consolidated statement of operations for the year ended December 31, 2023. Additionally, we completed a debt restructuring of the OPAL Term Loan in third quarter of 2023 which was accounted for as a debt modification for the existing lenders by performing an analysis on a lender by lender basis under ASC 470-50 Debt modifications and exchanges. As a result, the Company recorded debt extinguishment of $0.3 million representing the fees allocated to the lenders who were repaid in full as part of loss on debt extinguishment in the consolidated statement of operations for the year ended December 31, 2023.

There was no loss on debt extinguishment for the year ended December 31, 2022.

Loss on warrant exchange

On December 22, 2022, we completed the exchange offer of outstanding Public Warrants and Private Warrants and issued 3,309,296 shares of Class A common stock in exchange for the warrants tendered in the Offer. Pursuant to the Warrant Amendment dated December 21, 2022, we exercised our right to exchange the remaining outstanding Warrants and issued 497,080 shares of Class A common stock on December 23, 2022. Following the completion of the exchange, the Public Warrants were suspended from trading on the Nasdaq and delisted. There are no longer any Warrants outstanding. We recorded $3.4 million as a loss on exchange of Warrants in our consolidated statement of operations for the year ended December 31, 2022.

In March 2023, we issued 49,633 shares to certain warrant holders as consideration for their prior agreement to tender all warrants held by the warrant holders in the voluntary exchange offer which closed on December 22, 2022. We recorded $338 thousand representing the fair value of the shares issued based on the closing price on March 30, 2023 as part of Loss on warrant exchange on its consolidated statement of operations for the year ended December 31, 2023.

Net income attributable to redeemable non-controlling interests

Net income attributable to redeemable non-controlling interests for the year ended December 31, 2023 and 2022 is $97.4 million and $22.4 million, respectively. The net income for the years ended December 31, 2023 and 2022 reflects the net income belonging to OPAL Fuels equity holders based on pro-rata ownership.

Net loss attributable to non-redeemable non-controlling interests

Net loss attributable to non-redeemable non-controlling interests for the year ended December 31, 2023 decreased by $0.8 million or 70%, compared to the year ended December 31, 2022. This reflects the joint venture partners' loss in those entities we sold a portion of our membership interests in certain RNG facilities which are consolidated in our financial statements. The decrease is primarily due to deconsolidation of Emerald and Sapphire which were previously recorded as non-controlling interests but are now accounted for as equity method investments. These entities for the year ended December 31, 2023, were Sunoma, Central Valley and Emerald, Sapphire for the first four months of 2023. The entities accounted for as non-redeemable non-controlling interests for the year ended December 31, 2022 were Sunoma, Emerald, Sapphire and Central Valley.

Dividends on redeemable preferred non-controlling interests

On November 29, 2021, we entered into an exchange agreement with Hillman whereby Hillman exchanged its ownership interests in the four RNG projects of $30.0 million into 300,000 series A-1 preferred units at a par value of $100 per unit and 1.4% of the common units of OPAL Fuels. On the same day, we entered into a subscription agreement with NextEra for up to 1,000,000 Series A preferred units, which were issued to NextEra during first and second quarters of

2022 for total proceeds of $100.0 million. Upon completion of the Business Combination, these were converted to redeemable preferred non-controlling interests.

Redeemable preferred non-controlling interests carry an 8% dividend payable quarterly either in cash or paid-in-kind for the first eight quarters at our option. During the third quarter of 2023, the Company repaid $16.5 million of paid-in-kind preferred dividend. As of December 31, 2023, there was $2.6 million of accrued dividend for the fourth quarter of 2023 which was paid in January 2024.

The dividends on redeemable preferred non-controlling interests for the year ended December 31, 2023 increased by $3.1 million or 39% primarily due to full year of dividends on Series A preferred units with NextEra compared to partial year in 2022.

Liquidity and Capital Resources

Liquidity

As of December 31, 2023, our liquidity consisted of cash and cash equivalents including restricted cash of $47.2 million and $9.9 million of short term investments. Additionally, we have availability of $263.4 million under the delayed draw term loan and $36.2 million under the revolver facility under the OPAL Term Loan.

We expect that our available cash together with our other assets, expected cash flows from operations, and access to expected sources of capital will be sufficient to meet our existing commitments for a period of at least twelve months from the date of this report. Any reduction in demand for our products or our ability to manage our production facilities may result in lower cash flows from operations which may impact our ability to make investments and may require changes to our growth plan.

To fund future growth, we anticipate seeking additional capital through equity or debt financings. The amount and timing of our future funding requirements will depend on many factors, including the pace and results of our project development efforts. We may be unable to obtain any such additional financing on acceptable terms or at all. Our ability to access capital when needed is not assured and, if capital is not available when, and in the amounts, needed, we could be required to delay, scale back or abandon some or all of our development programs and other operations, which could materially harm our business, prospects, financial condition, and operating results.

As of December 31, 2023, we had total indebtedness excluding deferred financing costs of $209.1 million which primarily consists of $186.6 million under the OPAL Term Loan and $22.5 million under Sunoma Loan.

As part of our operations we have arrangements for office space for our corporate headquarters under the Administrative Services Agreement as well as operating leases for office space, warehouse space, and our vehicle fleet.

We intend to make payments under our various debt instruments when due and pursue opportunities for earlier repayment and/or refinancing if and when these opportunities arise.

See Note 7. Borrowings, to our consolidated financial statements.

Cash Flows

The following table presents the Company's cash flows for the years ended December 31, 2023 and 2022:


	Twelve Months Ended December 31,
(in thousands)	2023		2022
Net cash provided by (used in) operating activities	$	38,269	$	(1,355)
Net cash used in investing activities	(74,147)		(184,028)
Net cash provided by financing activities	5,899		220,550
Net (decrease) increase in cash, restricted cash, and cash equivalents	$	(29,979)	$	35,167

Net Cash Provided by Operating Activities

Net cash provided by operating activities for the year ended December 31, 2023 was $38.3 million, an increase of $39.6 million compared to net cash used in operating activities of $1.4 million for the year ended December 31, 2022. The

increase in cash provided by operating activities was primarily attributable to positive capital changes primarily related to accounts receivable, accounts receivable, related party, accounts payable, related party, environmental credits held for sale and contract assets.

Net Cash Used in Investing Activities

Net cash used in investing activities for the year ended December 31, 2023 was $74.1 million, a decrease of $109.9 million compared to the $184.0 million used in investing activities for the year ended December 31, 2022. This was primarily driven by a decrease in cash invested in short term investments of $120.1 million, deconsolidation of VIEs net cash of $11.9 million, an increase in distribution from equity method investment of $2.7 million, a decrease in payments made for the construction of various RNG generation and dispensing facilities of $17.6 million offset by an increase in cash paid for investments in other entities of $7.7 million and the repayment of Note receivable of $10.8 million in the third quarter of 2022.

Net Cash Provided by Financing Activities

Net cash provided by financing activities for the year ended December 31, 2023 was $5.9 million, a decrease of $214.7 million compared to the $220.6 million provided from financing activities for the year ended December 31, 2022. This was primarily due to a decrease of $138.9 million from closing of the Business Combination and $100.0 million decrease from proceeds from issuance of Redeemable Preferred Units to NextEra in the prior year, the repurchase of $16.4 million of shares of our Class A common stock in connection with the exercise of the put option and decrease of $10.4 million proceeds from non-redeemable non-controlling interests.This was offset by an increase in proceeds of $144.1 million from OPAL Term Loan post amendment in September 2023, accompanied by repayment of existing balance of $87.6 million on the OPAL Term Loan, Convertible Note Payable of $30.1 million and paid-in-kind preferred dividends of $16.6 million. Additionally, the Company paid $10.9 million in transaction fees.

Capital expenditures and other cash commitments

We require cash to fund our capital expenditures, operating expenses, working capital and other requirements, including costs associated with fuel sales; outlays for the design and construction of new Fueling Stations and RNG production facilities; debt repayments and repurchases; maintenance of our electrification production facilities supporting our operations, including maintenance and improvements of our infrastructure; supporting our sales and marketing activities, including support of legislative and regulatory initiatives; any investments in other entities; any mergers or acquisitions, including acquisitions to expand our RNG production capacity; pursuing market expansion as opportunities arise, including geographically and to new customer markets; to fund other activities or pursuits and for other general corporate purposes.

As of December 31, 2023, we anticipate spending approximately $179.3 million in capital expenditures for the next 12 months for projects and fuel stations currently under construction and our share of contributions in our equity method investment projects. These expenditures do not include any expected contributions from our joint venture partners and primarily relate to our development and construction of new renewable energy facilities and the purchase of equipment used in our Fueling Station services and Renewable Power operations.

In addition to the above, we also have lease commitments on our vehicle fleets and office leases and quarterly amortization payment obligations under various debt facilities. Please see Note 7. Borrowings and Note 8. Leases to our consolidated financial statements for additional information.

We plan to fund these expenditures primarily through cash on hand, cash generated from operations and availability under existing debt facilities.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is not required to provide the information required by this Item as it is a “smaller reporting company.” However, we note that we are exposed to market risks related to Environmental Attribute pricing, commodity pricing, changes in interest rates and credit risk with our contract counterparties. We currently have no foreign exchange risk and do not hold any derivatives or other financial instruments purely for trading or speculative purposes.

We employ various strategies to economically hedge these market risks, including derivative transactions relating to commodity pricing and interest rates. Any realized or unrealized gains or losses from our derivative transactions

are reported within corporate revenue and other income/expense in our consolidated financial statements. For information about our gains or losses with respect to our derivative transactions and the fair value of such financial instruments, see Note 9. Derivative Financial Instruments and Fair Value Measurements, to our consolidated financial statements.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item is contained in the financial statements set forth in Item 15(a) under the caption "Consolidated Financial Statements" as part of this Annual Report on Form 10-K.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our Co-Chief Executive Officers and our Chief Financial Officer (our co- principal executive officers and principal financial officer, respectively), evaluated, as of the end of the period covered by this Annual Report on Form 10-K, the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. The term “disclosure controls and procedures,” as defined in the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosures. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Based on that evaluation of our disclosure controls and procedures as of December 31, 2023, our Co-Chief Executive Officers and Interim Chief Financial Officer concluded that, as of such date, our disclosure controls and procedures were effective for the period covered by this report.

Management's Annual Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our co-chief executive officers and chief financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting. Management has adopted the framework in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the results of our evaluation, our management including our co-chief executive officers and chief financial officer concluded that our internal control over financial reporting was effective as of December 31, 2023.

Remediation of Material Weakness

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of its annual or interim consolidated financial statements will not be prevented, or detected and corrected, on a timely basis. In connection with the preparation and audit of our consolidated financial statements for each of the years ended December 31, 2022 and 2021, material weaknesses were identified in our internal control over financial reporting related reviews for the accounting and disclosures of significant transactions, lack of timely and effective reviews over accounts reconciliations and application of ASC 606. These deficiencies in internal control over financial reporting were detailed in Item 9A of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

During the fourth quarter of 2023, we successfully completed the testing necessary to conclude that the material weaknesses have been remediated. We will continue to monitor the effectiveness of these and other processes, procedures, and controls and will make any further changes that management determines to be appropriate.

Changes in Internal Control Over Financial Reporting

We have taken actions to remediate the material weaknesses related to our internal control over financial reporting, as described in the Remediation of Material Weakness above. During the year ended December 31, 2023, we implemented new controls and modified existing controls around accounting for significant transactions, reviews of accounts reconciliations and application of ASC 606. We have therefore augmented ICFR as follows:

a) Designed and implemented new controls for capturing and identifying significant and unusual transactions in a timely manner.

b) Designed and implemented new controls to strengthen the internal review processes for accounting of significant and unusual transactions.

c) Designed and implemented new controls by creating new or enhancing existing reconciliation templates for balance sheet accounts including accrued construction in progress, accrued dispensing payables and inter company eliminations.

d) Implemented general information technology controls over our financial reporting system by disabling the functionality for the same employee to prepare and post journal entries.

e) Designed and implemented new controls over revenue accounting and application of ASC 606.

While we believe these efforts have remediated the material weaknesses identified, we cannot guarantee that these steps have been or will be sufficient to remediate the deficiencies or that in the future we will not have a material weakness that prevents us from concluding that our internal control financial reporting is effective. The effectiveness of our internal control over financial reporting is subject to various inherent limitations, judgments used in decision making, assumptions about the likelihood of future events, the possibility of human error and the risk of fraud. If our remedial measures are insufficient to address the material weaknesses or if additional material weaknesses arise in the future, this could adversely affect our reputation and business and the market price of our securities. In addition, any such failures could result in litigation or regulatory actions by the SEC or other regulatory authorities, loss of investor confidence, delisting of our securities and harm to our reputation and financial condition, or diversion of financial and management resources from the operation of our business.

ITEM 9B. OTHER INFORMATION

During the fiscal quarter ended December 31, 2023, none of our directors or executive officers adopted or terminated any contract, instruction or written plan for the purchase or sale of Company securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding our directors, executive officers and certain corporate governance items will be included in the proxy statement for the 2024 annual meeting of shareholders, to be filed within 120 days after December 31, 2023, and is incorporated by reference to this Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

Information regarding executive compensation will be included in the proxy statement for the 2024 annual meeting of shareholders, to be filed within 120 days after December 31, 2023, and is incorporated by reference to this Form 10-K.

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

Information regarding (i) security ownership of certain beneficial owners and management and related stockholder matters and (ii) securities authorized for issuance under equity compensation plans will be included in the proxy statement for the 2024 annual meeting of shareholders, to be filed within 120 days after December 31, 2023, and is incorporated by reference to this Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information regarding certain relationships and related transactions and director independence will be included in the proxy statement for the 2024 annual meeting of shareholders, to be filed within 120 days after December 31, 2023, and is incorporated by reference to this Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding principal accounting fees and services billed to us by our principal accountant, BDO USA, P.C will be included in the proxy statement for the 2024 annual meeting of shareholders, to be filed within 120 days after December 31, 2023, and is incorporated by reference to this Form 10-K.

PART IV

ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES.

(a) Documents filed as part of this Annual Report on Form 10-K

1.Consolidated Financial Statements: See accompanying Index to Consolidated Financial Statements.

2.Consolidated Financial Statement Schedules: Financial statement schedules are omitted either due to the absence of conditions under which they are required or because the information required is included in the notes to the Company’s consolidated financial statements.

(b) Exhibit Index


Exhibit Number						Description
2.1†*						Business Combination Agreement, dated as of December 2, 2021, by and among ArcLight, OPAL Fuels and OPAL Holdco (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed with the SEC on December 3, 2021).
3.1*						Restated Certificate of Incorporation of OPAL Fuels Inc. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K/A filed by the Company on August 10, 2022).
3.2*						Bylaws of OPAL Fuels Inc. (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed by the Company on July 27, 2022)
4.1*						Specimen Warrant Certificate (incorporated by reference to Exhibit 4.3 to the Registration Statement on Form S-1 (File No. 333-252730) filed by the registrant on March 8, 2021).
4.2*						Warrant Agreement between Continental Stock Transfer & Trust Company and ArcLight Clean Transition Corp. II, dated March 22, 2021 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by the Company on March 26, 2021).
4.3*						Amendment No. 1 to Warrant Agreement, dated December 19, 2022, by and between the Company and Continental Stock Transfer & Trust Company (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed with the SEC on December 19, 2022)


4.4*"						OPAL Fuels Inc. Short-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to the Annual Report on Form 10-K filed by the Company on March 29, 2023).
4.5*"						Form of Stock Option Grant Notice and Option Agreement (incorporated by reference to Exhibit 4.5 to the Annual Report on Form 10-K filed by the Company on March 29, 2023).
4.6*"						Form of Performance Restricted Stock Unit Award Grant Notice and Award Agreement (incorporated by reference to Exhibit 4.6 to the Annual Report on Form 10-K filed by the Company on March 29, 2023).
10.1*						Form of OPAL Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-4 (File No. 333-262583), filed on May 6, 2022).
10.2*						2022 Omnibus Equity Incentive Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by the Company on July 27, 2022).
10.3*						Sponsor Letter Agreement, dated as of December 2, 2021, by and among OPAL Fuels LLC, ArcLight Clean Transition Corp. II and certain other parties thereto (incorporated by reference to incorporated by referenced to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed by the registrant on December 3, 2021)
10.4*						Form of Subscription Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed with the SEC on December 3, 2021).
10.5*						Form of Amendment No. 1 to the Subscription Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed with the SEC on May 12, 2022).
10.6*						Tax Receivable Agreement, dated July 21, 2022, by and among OPAL Fuels Inc. and the persons named therein (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K filed by the Company on July 27, 2022).
10.7*						Investor Rights Agreement, dated July 21, 2022, by and among OPAL Fuels Inc., ArcLight CTC Holdings II, L.P., and the other persons named therein (incorporated by reference to Exhibit 10.7 to the Current Report on Form 8-K filed by the Company on July 27, 2022).
10.8*						Second A&R LLC Agreement of OPAL Fuels, including any Certificates of Designations (incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K filed by the Company on July 27, 2022).
10.9*						Delayed Draw Term Loan and Guaranty Agreement, dated October 22, 2021, by and among OPAL Fuels Intermediate Holdco LLC, the Guarantors named on the signature pages thereto, and the Lenders (as defined therein), and Bank of America, N.A., as Administrative Agent for the Lenders (incorporated by reference to Exhibit 10.8 to the Registration Statement on Form S-4 (File No. 333-262583), filed on March 25, 2022).
10.10*						Amendment No. 1 to Delayed Draw Term Loan and Guaranty Agreement and Waiver, dated February 1, 2022 (incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-4 (File No. 333-262583), filed on March 25, 2022).
10.11#*						Environmental Attributes Purchase and Sale Agreement, dated November 29, 2021, by and between, on the one hand, NextEra Energy Marketing, LLC and, on the other hand, TruStar Energy LLC and OPAL Fuels LLC (incorporated by reference to Exhibit 10.10 to the Registration Statement on Form S-4 (File No. 333-262583), filed on March 25, 2022).
10.12#*						Administrative Services Agreement, dated December 31, 2021, by and between OPAL Fuels and Fortistar Services 2 LLC (incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-4 (File No. 333-262583), filed on March 25, 2022).
10.13#*						Indemnification and Hold Harmless Agreement, dated December 31, 2020, by and between OPAL Fuels LLC and Fortistar LLC (incorporated by reference to Exhibit 10.12 to the Registration Statement on Form S-4 (File No. 333-262583), filed on March 25, 2022).
10.14#*						Flue Gas Offtake and Preferred Partner Agreement, dated November 29, 2021, by and between CarbonFree Chemicals Holdings, LLC and OPAL Fuels LLC (incorporated by reference to Exhibit 10.13 to the Registration Statement on Form S-4 (File No. 333-262583), filed on March 25, 2022).
10.15*						Amendment No. 3 to Delayed Draw Term Loan and Guaranty Agreement, dated September 29, 2022 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on October 3, 2022).
10.16*						Form of Stock Award Agreement dated September 15, 2022 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on September 19, 2022).
10.17*						Forward Purchase Agreement, dated July 18, 2022, among ArcLight Clean Transition Corp. II, Meteora Special Opportunity Fund I, LP, Meteora Select Trading Opportunities Master, LP and Meteora Capital Partners, LP (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on July 18, 2022).


10.18*						Credit Agreement, dated August 4, 2022, made by and among OPAL Intermediate Holdco 2 as Borrower, the guarantors, the lenders thereto, Bank of Montreal as the administration agent, Wilmington Trust as collateral agent and Bank of Montreal, Investec Inc. and Comerica Bank as joint lead arrangers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on August 8, 2022).
10.19*						Promissory Note, dated as of May 16, 2022, by and between Arclight and Sponsor (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q filed by the Company on August 10, 2022).
10.20*						Service Contract Agreement , dated December 15, 2022, by and between OPAL Fuels Inc. and United Parcel Service Oasis Supply Corporation (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on December 21, 2022).
10.21*						FM3 Credit Agreement, dated December 19, 2022, by and between Fortistar Methane LLC, OPAL Fuels LLC and a syndicate of lenders led by MUFG Union Bank N.A. as administrative agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by the Company on December 21, 2022).
10.22*						Securities Purchase Agreement, dated March 30, 2023, by and between the Company and the purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on April 5, 2023).
10.23*+#						Landfill Gas Purchase and Sale Agreement dated April 13, 2023 (effective as of March 13, 2023) (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed by the Company on May 15, 2023).
10.24*+#						Piggyback Agreement for Landfill Gas Purchase Agreement dated May 2, 2023 (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q filed by the Company on May 15, 2023).
10.25*+#						Amended and Restated Credit and Guaranty Agreement, dated May 30, 2023, among Paragon RNG LLC as Borrower, the Guarantors, the lenders thereto, Bank of Montreal as the administrative agent, Wilmington Trust as collateral agent and BMO Capital Markets Corp., Investec Inc. and Comerica Bank as joint lead arrangers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on June 2, 2023).
10.26*+#						Third Amended and Restated Gas Sale and Purchase Agreement, dated August 11, 2023 (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q filed by the Company on August 14, 2023).
10.27*+#						Landfill Gas Purchase and Sale Agreement, dated August 28, 2023 with Waste Management of California, Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on August 31, 2023).
10.28*+#						Lease Agreement, dated August 28, 2023 with Waste Management of California, Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by the Company on August 31, 2023).
10.29*+#						Landfill Gas Purchase and Sale Agreement, dated August 28, 2023 with Guadalupe Rubbish Disposal Co., Inc. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed by the Company on August 31, 2023).
10.30*+#						Lease Agreement, dated August 28, 2023 with Guadalupe Rubbish Disposal Co., Inc. (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed by the Company on August 31, 2023).
10.31*						Credit Agreement, dated September 1, 2023, by and among Intermediate HoldCo as Borrower, the guarantors, the lenders party thereto, Bank of America, N.A. as the administration agent, and Apterra Infrastructure Capital LLC, Barclays Bank PLC, BofA Securities, Inc., Celtic Bank Corporation, JP Morgan Chase Bank, N.A. and Investec Inc., as joint lead arrangers (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on September 5, 2023).
10.32*						Pledge Agreement, dated September 1, 2023, by OPAL Fuels Parent HoldCo 3 LLC in favor of Bank of America, N.A. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by the Company on September 5, 2023).
10.33*						Security Agreement, dated September 1, 2023, by OPAL Fuels Intermediate HoldCo LLC and the other grantors listed on the signature pages thereto in favor of Bank of America, N.A. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed by the Company on September 5, 2023).
10.34*						Note (Term), dated September 1, 2023, between OPAL Fuels Intermediate HoldCo LLC and BankUnited, N.A. (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed by the Company on September 5, 2023).


10.35*						Note (Revolving), dated September 1, 2023, between OPAL Fuels Intermediate HoldCo LLC and BankUnited, N.A. (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K filed by the Company on September 5, 2023).
10.36*						Agreement, dated September 14, 2023, by and among OPAL L2G and SJI (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on September 20, 2023).
10.37*						Interim Services Agreement dated October 12, 2023, between the Company and Fortistar (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on October 12, 2023).
10.38*						Separation Agreement and General Release dated October 19, 2023 between the Company and Ann Anthony (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K/A filed by the Company on October 20, 2023).
10.39*						Asset Purchase and Sale Agreement, dated October 20, 2023, with Washington Gas Light Company (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on October 26, 2023).
10.40*						Base Contract for Sale and Purchase of Natural Gas (San Diego), dated September 15, 2023 (incorporated by reference to Exhibit 10.12 to the Quarterly Report on Form 10-Q filed by the Company on November 14, 2023).
10.41*						Base Contract for Sale and Purchase of Natural Gas (Richmond), dated September 15, 2023 (incorporated by reference to Exhibit 10.13 to the Quarterly Report on Form 10-Q filed by the Company on November 14, 2023).
10.42*						At Market Issuance Sales Agreement, dated November 17, 2023, among OPAL Fuels Inc., B. Riley Securities, Inc., Cantor Fitzgerald & Co. and Stifel, Nicolaus & Company, Incorporated (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on November 17, 2023).
21.1						List of subsidiaries of the registrant.
23.1						Consent of BDO USA, P.C, independent registered accounting firm.
31.1						Certification of Co-Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2						Certification of Co-Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3						Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**						Certification of Co-Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**						Certification of Co-Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.3**						Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
97.1						Clawback Policy
101.INS						Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
101.SCH						Inline XBRL Taxonomy Extension Schema Document
101.CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB						Inline XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE						Inline XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document.
104						Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101).


*						Previously filed.
**						This certification is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act.
"						Indicates a management contract or compensatory plan.
†						Schedules and exhibits to this Exhibit omitted pursuant to Regulation S-K Item 601(b)(2). The Company agrees to furnish supplementally a copy of any omitted schedule or exhibit to the SEC upon request.
+						Certain of the schedules and exhibits to this exhibit have been omitted pursuant to Regulation S-K Item 601(a)(5). The Company agrees to furnish supplementally a copy of any omitted schedule or exhibit to the SEC upon its request.
#						Certain confidential information contained in this document has been redacted in accordance with Item 601(b)(10)(iv) of Regulation S-K.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

OPAL FUELS INC.

March 15, 2024

By: /s/ Jonathan Maurer

Name: Jonathan Maurer

Title: Co-Chief Executive Officer

Each person whose signature appears below constitutes and appoints Jonathan Maurer, Adam Comora, Ann Anthony and John Coghlin, acting alone or together with another attorney-in-fact, as his or her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign any or all further amendments, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature						Title

/s/ Mark Comora						Chairman
Mark Comora
Date: March 15, 2024

/s/ Betsy L. Battle						Director
Betsy L. Battle
Date: March 15, 2024

/s/ Scott Dols						Director
Scott Dols
Date: March 15, 2024

/s/ Kevin M. Fogarty						Director
Kevin M. Fogarty
Date: March 15, 2024

/s/ James Martell						Director
James Martell
Date: March 15, 2024

/s/ Nadeem Nisar						Director
Nadeem Nisar


Date: March 15, 2024

/s/ Ashok Vemuri						Director
Ashok Vemuri
Date: March 15, 2024

/s/ Adam Comora						Co-Chief Executive Officer
Adam Comora
Date: March 15, 2024

/s/ Jonathan Maurer						Co-Chief Executive Officer
Jonathan Maurer
Date: March 15, 2024

/s/ Scott Contino						Interim Chief Financial officer
Scott Contino
Date: March 15, 2024

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firm (BDO USA, P.C ; Stamford, CT; PCAOB ID No.243)						F-1

Consolidated Balance Sheets as of December 31, 2023 and 2022						F-2

Consolidated Statements of Operations for the years ended December 31, 2023 and 2022						F-4

Consolidated Statements of Comprehensive Income for the years ended December 31, 2023 and 2022						F-5

Consolidated Statements of Changes in Redeemable non-controlling interests, Redeemable preferred non-controlling interest and Stockholders' (D eficit) Equity for the years ended December 31, 2023 and 2022						F-6

Consolidated Statements of Cash Flows for the years ended December 31, 2023 and 2022						F-8

Notes to Consolidated Financial Statements						F-10

Report of Independent Registered Public Accounting Firm

Shareholders and Board of Directors

OPAL Fuels Inc.

White Plains, NY

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of OPAL Fuels Inc. and its subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of operations and comprehensive income, changes in redeemable non-controlling interest, redeemable preferred non-controlling interest and stockholders’(deficit) equity, and cash flows for each of the two years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

Related Parties

As discussed in Note 10. Related Parties to the consolidated financial statements, OPAL Fuels Inc. and its subsidiaries have entered into significant transactions with NextEra Energy Marketing, LLC (“NextEra”) and Fortistar LLC (“Fortistar”), which are related parties. Our opinion is not modified with respect to this matter.

Basis for Opinion

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

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

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

/s/ BDO USA, P.C.

We have served as the Company’s auditor since 2016.

Stamford, CT

March 15, 2024

F-1

OPAL FUELS INC.

CONSOLIDATED BALANCE SHEETS

(In thousands of U.S. dollars, except per share data)


	December 31, 2023		December 31, 2022
Assets
Current assets:
Cash and cash equivalents (includes $166 and $12,506 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	$	38,348	$	40,394
Accounts receivable, net (includes $33 and $966 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	27,623		31,083
Accounts receivable, related party	18,696		12,421
Restricted cash - current (includes $4,395 and $6,971 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	4,395		32,402
Short term investments	9,875		64,976
Fuel tax credits receivable	5,345		4,144
Contract assets	6,790		9,771
Parts inventory (includes $29 and $— at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	10,191		7,311
Environmental credits held for sale	172		1,674
Prepaid expense and other current assets (includes $107 and $415 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	6,005		7,625
Derivative financial assets, current portion	633		182
Total current assets	128,073		211,983
Capital spares	3,468		3,443
Property, plant, and equipment, net (includes $26,626 and $73,140 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	339,493		297,323
Operating right-of use assets	12,301		11,744
Investment in other entities	207,099		51,765
Note receivable - variable fee component	2,302		1,942
Derivative financial assets, non-current portion	—		954
Deferred financing costs	—		3,013
Other long-term assets	1,162		1,489
Intangible assets, net	1,604		2,167
Restricted cash - non-current (includes $1,850 and $2,923 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	4,499		4,425
Goodwill	54,608		54,608
Total assets	$	754,609	$	644,856
Liabilities and Equity
Current liabilities:
Accounts payable (includes $744 and $4,896 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	13,901		17,649
Accounts payable, related party (includes $1,046 and $433 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	7,024		6,376
Fuel tax credits payable	4,558		3,320
Accrued payroll	9,023		8,979
Accrued capital expenses (includes $— and $7,821 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	15,128		11,922
Accrued expenses and other current liabilities (includes $647 and $646 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	14,245		9,573
Contract liabilities	6,314		8,013
Senior Secured Credit Facility - term loan, current portion, net of debt issuance costs	—		15,250

F-2


Senior Secured Credit Facility - working capital facility, current portion	—		7,500
OPAL Term Loan, current portion	—		27,732
Sunoma loan, current portion (includes $1,608 and $380 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	1,608		380
Convertible Note Payable	—		28,528
Municipality Loan	—		76
Derivative financial liability, current portion	—		4,596
Operating lease liabilities - current portion	638		630
Other current liabilities (includes $92 and $— at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	92		1,085
Asset retirement obligation, current portion	3,860		1,296
Total current liabilities	76,391		152,905
Asset retirement obligation, non-current portion	2,868		4,960
OPAL Term Loan, net of debt issuance costs	176,532		66,600
Sunoma loan, net of debt issuance costs (includes $20,010 and $21,712 at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	20,010		21,712
Operating lease liabilities - non-current portion	11,824		11,245
Earn out liabilities	1,900		8,790
Other long-term liabilities (includes $211 and $— at December 31, 2023 and December 31, 2022, respectively, related to consolidated VIEs)	7,599		825
Total liabilities	297,124		267,037
Commitments and contingencies
Redeemable preferred non-controlling interests	132,617		138,142
Redeemable non-controlling interests	802,720		1,013,833
Stockholders' (deficit) equity
Class A common stock, $0.0001 par value, 340,000,000 shares authorized as of December 31, 2023; 29,701,146 and 29,477,766 shares, issued and outstanding at December 31, 2023 and December 31, 2022, respectively	3		3
Class B common stock, $0.0001 par value, 160,000,000 shares authorized as of December 31, 2023; None issued and outstanding as of December 31, 2023 and December 31, 2022	—		—
Class C common stock, $0.0001 par value, 160,000,000 shares authorized as of December 31, 2023; None issued and outstanding as of December 31, 2023 and December 31, 2022	—		—
Class D common stock, $0.0001 par value, 160,000,000 shares authorized as of December 31, 2023; 144,399,037 issued and outstanding at December 31, 2023 and December 31, 2022	14		14
Additional paid-in capital	—		—
Accumulated deficit	(467,195)		(800,813)
Accumulated other comprehensive (loss) income	(15)		195
Class A common stock in treasury, at cost; 1,635,783 and — shares at December 31, 2023 and December 31, 2022, respectively	(11,614)		—
Total Stockholders' (deficit) equity attributable to the Company	(478,807)		(800,601)
Non-redeemable non-controlling interests	955		26,445
Total Stockholders' (deficit) equity	(477,852)		(774,156)
Total liabilities, Redeemable preferred, Redeemable non-controlling interests and Stockholders' (deficit) equity	$	754,609	$	644,856

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

F-3

OPAL FUELS INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands of U.S. dollars, except per unit data)


	Twelve Months Ended December 31,
	2023		2022
Revenues:
RNG fuel (includes revenues from related party of $56,069 and $58,185 for the years ended December 31, 2023 and 2022, respectively)	$	66,292	$	73,158
Fuel station services (includes revenues from related party of $28,468 and $18,735 for the years ended December 31, 2023 and 2022, respectively)	135,012		117,415
Renewable Power (includes revenues from related party of $6,614 and $5,495 for the years ended December 31, 2023 and 2022, respectively)	54,804		44,958
Total revenues	256,108		235,531
Operating expenses:
Cost of sales - RNG fuel	32,028		32,367
Cost of sales - Fuel station services	115,322		98,845
Cost of sales - Renewable Power	36,550		31,580
Project development and start up costs	4,866		6,438
Selling, general, and administrative	51,262		51,386
Depreciation, amortization, and accretion	14,565		13,136
Income from equity method investments	(5,525)		(5,784)
Total expenses	249,068		227,968
Operating income	7,040		7,563

Interest and financing expense, net	(9,306)		(6,640)
Change in fair value of derivative instruments, net	7,346		33,081
Other income	124,472		1,943
Loss on debt extinguishment	(2,190)		—
Loss on warrant exchange	(338)		(3,368)
Income before provision for income taxes	127,024		32,579
Provision for income taxes	—		—
Net income	127,024		32,579
Net income attributable to redeemable non-controlling interests	97,426		22,409
Net loss attributable to non-redeemable non-controlling interests	(349)		(1,153)
Dividends on Redeemable preferred non-controlling interests (1)	11,011		7,932
Net income attributable to Class A common stockholders	$	18,936	$	3,391

Weighted average shares outstanding of Class A common stock :
Basic	27,148,538		25,774,312
Diluted	27,494,016		26,062,398
Per share amounts:
Basic	$	0.70	$	0.13
Diluted	$	0.69	$	0.12

(1) Paid-in-kind preferred dividend is allocated between redeemable non-controlling interests and Class A common stockholders basis their weighted average percentage of ownership. Please see Note 13. Redeemable non-controlling interests, Redeemable preferred non-controlling interests and Stockholders' Equity for additional information.

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

F-4

OPAL FUELS INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands of U.S. dollars)


	Twelve Months Ended December 31,
	2023		2022
Net income	$	127,024	$	32,579
Other comprehensive income:
Effective portion of the cash flow hedge attributable to equity method investments	(8)		334
Reclassification adjustments included in earnings (1)	(1,146)		—
Net unrealized (loss) gain on cash flow hedges	(142)		954
Total other comprehensive (loss) income	(1,296)		1,288
Total comprehensive income	125,728		33,867
Less:
Net income attributable to Redeemable non-controlling interests	106,645		29,597
Other comprehensive (loss) income attributable to Redeemable non-controlling interests	(1,086)		1,093
Comprehensive loss attributable to non-redeemable non-controlling interests	(349)		(1,153)
Dividends on Redeemable preferred non-controlling interests	1,792		744
Comprehensive income attributable to Class A common stockholders	$	18,726	$	3,586

(1) Represents the reclassification of the gain on termination of interest rate swaps of $812 on May 30, 2023. See Note 9. Derivative Financial Instruments and Fair Value Measurements for additional information. Additionally, there is a $334 reclassification into earnings from our equity method investments.

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

F-5

OPAL FUELS INC.

CONSOLIDATED STATEMENTS OF CHANGES IN REDEEMABLE NON-CONTROLLING INTEREST, REDEEMABLE PREFERRED NON-CONTROLLING INTEREST AND STOCKHOLDERS' (DEFICIT) EQUITY

(In thousands of U.S. dollars, except per unit data)


	Class A common stock			Class D common stock											Class A common stock in treasury					Mezzanine Equity
	Shares	Amount		Shares	Amount		Additional paid-in capital		Accumulated deficit		Other comprehensive income		Non-redeemable non-controlling interests		Shares	Amount		Total Stockholders' Equity (deficit)		Redeemable Preferred non-controlling interests		Redeemable non-controlling interests
December 31, 2021	—	$	—	144,399,037	$	14	$	—	$	—	$	—	$	1,188	—	$	—	$	1,202	$	30,210	$	63,545
Net income	—	—		—	—		—		4,135		—		(1,153)		—	—		2,982		—		29,597
Unrealized gain on cash flow hedges	—	—		—	—		—		—		195		—		—	—		195		—		1,093
Redeemable preferred non-controlling interest issuance	—	—		—	—		—		—		—		—		—	—		—		100,000		(267)
Issuance of common stock from the reverse recapitalization and PIPE Investments, net of warrant liability, put option and earnout liability	22,611,857	2		—	—		68,357		—		—		—		—	—		68,359		—		—
Conversion of Convertible Note Payable to common shares	3,059,533	—		—	—		30,595		—		—		—		—	—		30,595		—		—
Conversion of Private and Public Warrants	3,806,376	1		—	—		7,858		—		—		—		—	—		7,859		—		18,061
Change in redemption value of Redeemable non-controlling interests	—	—		—	—		(103,804)		(804,204)		—		—		—	—		(908,008)		—		908,008
Proceeds from non-redeemable non-controlling interest	—	—		—	—		(3,176)		—		—		26,410		—	—		23,234		—		(132)
Amortization on payment to acquire non-redeemable non-controlling interest	—	—		—	—		—		—		—		—		—	—		—		—		(183)
Stock-based compensation	—	—		—	—		170		—		—		—		—	—		170		—		1,299
Paid-in-kind preferred dividend	—	—		—	—		—		(744)		—		—		—	—		(744)		7,932		(7,188)
December 31, 2022	29,477,766	3		144,399,037	14		—		(800,813)		195		26,445		—	—		(774,156)		138,142		1,013,833
Net income	—	—		—	—		—		20,728		—		(349)		—	—		20,379		—		106,645
Other comprehensive loss	—	—		—	—		—		—		(210)		—		—	—		(210)		—		(1,086)
Issuance of Class A common stock on warrant exchange	49,633	—		—	—		338		—		—		—		—	—		338		—		—
Cancellation of fractional shares on warrant exchange	(26)	—		—	—		—		—		—		—		—	—		—		—		—
Exercise of put option on forward purchase contract - Meteora	—	—		—	—		—		—		—		—		(1,635,783)	(11,614)		(11,614)		—		—
Forfeiture of Class A common stock	(197,258)	—		—	—		—		—		—		—		—	—		—		—		—
Issuance of Class A common stock for vesting of equity awards (1)	280,928	—		—	—		(896)		—		—		—		—	—		(896)		—		—
Issuance of Class A common stock under the ATM program (2)	90,103	—		—	—		366		—		—		—		—	—		366		—		—
Stock-based compensation	—	—		—	—		961		—		—		—		—	—		961		—		4,943
Proceeds from non-redeemable non-controlling interest	—	—		—	—		2,899		—		—		9,854		—	—		12,753		—		—
Deconsolidation of entities (3)	—	—		—	—		(1,383)		—		—		(34,662)		—	—		(36,045)		—		—
Distributions to non-redeemable non-controlling interests	—	—		—	—		—		—		—		(333)		—	—		(333)		—		—
Payment of paid-in-kind preferred dividends	—	—		—	—		—		—		—		—		—	—				(16,536)		—

F-6


Dividends on Redeemable preferred non-controlling interests	—	—		—	—		—		(1,792)		—		—		—	—		(1,792)	11,011		(9,219)
Change in redemption value of Redeemable non-controlling interests	—	—		—	—		(2,285)		314,682		—		—		—	—		312,397	—		(312,396)
	29,701,146	$	3	144,399,037	$	14	$	—	$	(467,195)	$	(15)	$	955	(1,635,783)	$	(11,614)	(477,852)	$	132,617	$	802,720

(1) Represents the equity awards vested net of shares of Class A common stock withheld for taxes. Please see Note 16. Stock-based Compensation for additional information.

(2) During the fourth quarter of 2023, the Company issued shares of Class A common stock under the Company's ATM program. Please see Note 2. Summary of Significant Accounting Policies for additional information.

(3) As of May 30, 2023, two of our RNG facilities, Emerald and Sapphire were deconsolidated and accounted for under equity method as per ASC 323. Please see Note 3. Investment in Other Entities and Note 12. Variable Interest Entities for additional information.

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

F-7

OPAL FUELS INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands of U.S. dollars)


	Twelve Months Ended December 31,
	2023		2022

Cash flows from operating activities:
Net income	$	127,024	$	32,579
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Income from equity method investments	(5,525)		(5,784)
Distributions from equity method investments	12,242		—
Loss on exchange of Warrants	338		3,368
Depreciation and amortization	14,044		13,015
Amortization of deferred financing costs	1,720		1,943
Amortization of operating lease right-of-use assets	643		770
Loss on debt extinguishment	2,190		—
Accretion expense related to asset retirement obligation	521		121
Stock-based compensation	5,904		1,469
Provision for bad debts	518		499
Paid-in-kind interest income	(360)		(286)
Change in fair value of Convertible Note Payable	1,579		413
Change in fair value of the earnout liabilities	(6,890)		(37,111)
Unrealized gain on derivative financial instruments	(270)		3,867
Gain on repayment of Note receivable	—		(1,943)
Gain on deconsolidation of VIEs	(122,873)		—
Changes in operating assets and liabilities:
Accounts receivable	2,942		(6,191)
Accounts receivable, related party	(6,275)		(12,421)
Proceeds received on previously recorded paid-in-kind interest income	—		288
Fuel tax credits receivable	(1,201)		(1,751)
Capital spares	(25)		(418)
Parts inventory	(2,880)		(2,168)
Environmental credits held for sale	1,502		(1,288)
Prepaid expense and other current assets	2,200		(3,108)
Contract assets	2,981		(1,287)
Accounts payable	6,686		10,143
Accounts payable, related party	1,228		1,180
Fuel tax credits payable	1,238		1,342
Accrued payroll	66		127
Accrued expenses	3,273		3,237
Operating lease liabilities - current and non-current	(613)		(640)
Asset retirement obligations	(49)		—
Other current and non-current liabilities	(1,910)		452
Contract liabilities	(1,699)		(1,772)
Net cash provided by (used in) operating activities	38,269		(1,355)
Cash flows from investing activities:
Purchase of property, plant, and equipment	(113,826)		(131,410)
Deconsolidation of VIEs, net of cash	(11,947)		—
Proceeds (purchase) of short term investments	55,101		(64,976)
Cash paid for investment in other entities	(8,314)		(597)
Proceeds received from repayment of Note receivable	—		10,855
Distributions received from equity method investment	4,839		2,100
Net cash used in investing activities	(74,147)		(184,028)

F-8


Cash flows from financing activities:
Proceeds from Sunoma loan	—		4,593
Proceeds from OPAL Term Loan	196,617		40,000
Proceeds received from Business Combination	—		138,850
Financing costs paid to other third parties	(10,264)		(8,321)
Repayment of Senior Secured Credit Facility	(22,750)		(58,603)
Repayment of Convertible Note Payable	(30,107)		—
Repayment of OPAL Term Loan	(106,090)		(18,910)
Repayment of Sunoma Loan	(546)		—
Repayment of Municipality loan	(76)		(202)
Repayment of finance lease liabilities	(993)		—
Proceeds from equipment loan	303		—
Proceeds from sale of non-redeemable non-controlling interest, related party	12,753		23,143
Reimbursement of financing costs by joint venture partner	842		—
Payment of paid-in-kind preferred dividends	(16,536)		—
Cash paid for taxes related to net share settlement of equity awards	(896)		—
Cash paid for purchase of shares upon exercise of put option	(16,391)		—
Distribution to non-redeemable non-controlling interest	(333)		—
Proceeds from issuance of shares of Class A common stock under the ATM program, net	366		—
Proceeds from issuance of redeemable preferred non-controlling interests, related party	—		100,000
Contributions from members	—		—
Net cash provided by financing activities	5,899		220,550
Net (decrease) increase in cash, restricted cash, and cash equivalents	(29,979)		35,167
Cash, restricted cash, and cash equivalents, beginning of period	77,221		42,054
Cash, restricted cash, and cash equivalents, end of period	$	47,242	$	77,221
Supplemental disclosure of cash flow information
Interest paid, net of $5,475 and $3,678 capitalized, respectively	$	6,929	$	7,013
Noncash investing and financing activities:
Fair value of Class A common stock issued for redemption of Convertible Note Payable	$	—	$	30,595
Fair value of Class A common stock issued for redemption of Public and Private warrants	$	338	$	25,919
Fair value of Derivative warrant liabilities assumed related to Business Combination	$	—	$	13,524
Fair value of Earnout liabilities related to Business Combination	$	—	$	45,900
Fair value of put option on a forward purchase agreement related to Business Combination	$	—	$	4,600
Paid-in-kind dividend on redeemable preferred non-controlling interests	$	2,617	$	7,932
Right-of-use assets for finance leases included in Property, Plant and equipment, net	$	9,048	$	801
Lease liabilities for finance leases included in Accrued expenses and other current liabilities	$	1,398	$	316
Lease liabilities for finance leases included in Other long-term liabilities	$	7,388	$	485
Accrual for purchase of Property, plant and equipment included in Accounts payable and Accrued capital expenses	$	15,128	$	11,922

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

F-9

1. Organization and Description of Business

OPAL Fuels Inc. (including its subsidiaries, the "Company", “OPAL,” “we,” “us” or “our”) is a renewable energy company specializing in the capture and conversion of biogas for the (i) production of RNG for use as a vehicle fuel for heavy and medium-duty trucking fleets, (ii) generation of Renewable Power for sale to utilities, (iii) generation and sale of Environmental Attributes associated with RNG and Renewable Power, and (iv) sales of RNG as pipeline quality natural gas. OPAL also designs, develops, constructs, operates and services Fueling Stations for trucking fleets across the country that use natural gas to displace diesel as their transportation fuel. The biogas conversion projects ("Biogas Conversion Projects") currently use landfill gas and dairy manure as the source of the biogas. In addition, we have recently begun implementing design, development, and construction services for hydrogen Fueling Stations, and we are pursuing opportunities to diversify our sources of biogas to other waste streams.

The Company is organized into four operating segments based on the characteristics and the nature of products and services. The four operating segments are - RNG Fuel, Fuel Station Services, Renewable Power and Corporate. During the first and third quarters of 2023, the Company changed its internal reporting to its executive leadership team ("Chief Operating Decision Makers") to change the composition of revenues included in our reportable segments. Please see Note 11. Reportable Segments and Geographic Information for additional information.

All amounts in these footnotes are presented in thousands of dollars except per share data.

2. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

These consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") and includes the accounts of the Company and all other entities in which the Company has a controlling financial interest: OPAL Renewable Power LLC (formerly Fortistar Methane 3 LLC (“FM3”) and Fortistar Methane 4 LLC), Beacon RNG LLC (“Beacon”) Sunoma Holdings, LLC (“Sunoma”), New River LLC (“New River”), Reynolds RNG LLC (“Reynolds”), Central Valley LLC (“Central Valley”), Prince William RNG LLC (“Prince William”), Cottonwood RNG LLC, Polk County RNG LLC (“Polk County”), OPAL Contracting LLC (formerly Fortistar Contracting LLC), OPAL RNG LLC (formerly Fortistar RNG LLC), and OPAL Fuel station services LLC (“Fuel Station Services”). The Company’s unaudited consolidated financial statements include the assets and liabilities of these subsidiaries. All intercompany transactions and balances have been eliminated in consolidation. The non-controlling interest attributable to the Company's variable interest entities ("VIE") are presented as a separate component from the Stockholders' deficit in the consolidated balance sheets and as a non-redeemable non-controlling interests in the consolidated statements of changes in redeemable non-controlling interests, redeemable preferred non-controlling interests and Stockholders' (deficit) equity.

Certain prior period amounts have been reclassified to conform with the current period presentation including reclassification of the Company’s proportional share of income in equity investments into operating income. See Note 3. Investment in Other Entities for further discussion. The Company reclassified certain project development and start up costs as a separate line within Operating expenses, which were previously included in Cost of sales - RNG Fuel and Selling, general and administrative expenses. Please see the Project development and start up costs section within Note 2. Additionally, the Company also reclassified certain Accounts Payable to equity method investments from Accounts Payable to Accounts payable, related party. Please see Note 10. Related Parties for additional information.

Variable Interest Entities

Our policy is to consolidate all entities that we control by ownership of a majority of the outstanding voting stock. In addition, we consolidate entities that meet the definition of a variable interest entity (“VIE”) for which we are the primary beneficiary. The Company applies the VIE model from ASC 810 when the Company has a variable interest in a legal entity not subject to a scope exception and the entity meets any of the five characteristics of a VIE. The primary beneficiary of a VIE is considered to be the party that both possesses the power to direct the activities of the entity that most significantly impact the entity’s economic performance and has the obligation to absorb losses or the rights to receive benefits of the VIE that could be significant to the VIE. To the extent a VIE is not consolidated, the Company evaluates its interest for application of the equity method of accounting. Equity method investments are included in the consolidated

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balance sheets as “Investments in other entities.” Investments in unconsolidated entities in which the Company has influence over the operating or financial decisions are accounted for under the equity method.

On May 30, 2023, the Company together with a third-party environmental solutions company formed Paragon RNG LLC ("Paragon"), a new joint venture holding company. The Company owns 50% of the ownership interest in Paragon. Concurrent to the formation of Paragon, the Company contributed its 50% ownership interests in Emerald and Sapphire to Paragon. Upon the execution of the above transaction, the Company reassessed its equity interests in Emerald RNG LLC ("Emerald") and Sapphire RNG LLC ("Sapphire") under ASC 810, Consolidation and determined that the Company did not have a controlling financial interest in Paragon under ASC 810 because the governance of Paragon is driven by a board jointly controlled equally by the joint venture partner and the Company and there are substantive participating rights held by the joint venture partner in the significant activities of Paragon. As a result of the reassessment, the Company deconsolidated these two entities effective May 30, 2023. Prior to May 30, 2023, the Company consolidated these two entities in accordance with the variable interest entity model guidance under ASC 810, Consolidation.

On September 14, 2023, OPAL Land2Gas LLC (“OPAL L2G”), a wholly-owned indirect subsidiary of OPAL Fuels Inc. (the “Company”), entered into a Limited Liability Company Agreement (for purposes of this paragraph, the “Agreement”) with SJI Landfill RNG LLC (“SJI LRNG”), a wholly-owned indirect subsidiary of South Jersey Industries (“SJI”), establishing the terms and conditions of governance and operation of Land2Gas LLC (the “ SJI Joint Venture”). The purpose of the Joint Venture, which is owned 50/50 by OPAL L2G and SJI LRNG, is to develop, construct, own and operate facilities (“Facilities”) to produce RNG using biogas generated by certain landfills. The Agreement governs the terms and conditions of capital contributions to be made by the SJI Joint Venture members to fund the development, construction and operations of the Facilities. The Agreement requires members of the SJI Joint Venture to contribute their respective share (50% each) of such capital requirements. The Agreement initially contemplates two RNG projects (RNG Atlantic and RNG Burlington) in New Jersey with each RNG project represented as a separate series of membership interests, also owned 50-50 by the members. Further, the Agreement provides for the SJI Joint Venture to enter into a Management Services Agreement (“MSA”), Operations and Maintenance Agreement (“O&M Agreement”), and dispensing agreement with certain wholly-owned, indirect subsidiaries of the Company. The MSA establishes the terms and conditions for the day-to-day administration of the projects, including responsibility for managing the development and overseeing the construction of the Facilities. The O&M Agreement establishes the terms and conditions for operating and maintaining the Facilities once construction is completed. The Dispensing Agreement provides for the acquisition, marketing and sale of the Environmental Attributes associated with RNG produced by the Facilities.

Upon the execution of the above transaction, the Company assessed its equity interests in the SJI Joint Venture under ASC 810, Consolidation and determined that the Company does not have a controlling financial interest in SJI Joint Venture under ASC 810 because the governance of the joint venture is driven by a board jointly controlled by the joint venture partner and OPAL equally and there are substantive participating rights held by the joint venture partner in the significant activities of SJI Joint Venture. As of December 31, 2023, the Company contributed $2,115 towards RNG Atlantic.

As of December 31, 2023, the Company accounted for its ownership interests in Pine Bend RNG LLC ("Pine Bend"), Noble Road RNG LLC ("Noble Road"), Emerald, Sapphire, Paragon, SJI Joint Venture (RNG Atlantic and RNG Burlington) and GREP BTB Holdings LLC ("GREP") under the equity method.

As of December 31, 2022, the Company accounted for its ownership interests in Pine Bend, Noble Road and GREP under the equity method. Please see Note 3. Investment in Other Entities, for additional information.

Use of estimates

The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The significant estimates and assumptions of the Company include the residual value of the useful lives of our property, plant and equipment, the fair value of stock-based compensation, asset retirement obligations, the estimated losses on our trade receivables, percentage completion for revenue recognition, incremental borrowing rate for calculating the right-of-use assets and lease liabilities, the impairment assessment of goodwill, the fair value of deconsolidated VIEs and the fair value of derivative instruments. Actual results could differ from those estimates.

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Accounting Pronouncements Adopted

In June 2016, the Financial Standards Accounting Board ("FASB") issued ASU 2016-13, Financial Instruments — Credit Losses ("ASC 326"), with the objective of providing information about the credit risk inherent in an entity’s financial statements as well as to explain management’s estimate of expected credit losses and the changes in the allowance for such losses. The accounting standard amends the current financial instrument impairment model by requiring entities to use a forward-looking approach based on expected losses to estimate credit losses on certain types of financial instruments, including trade receivables. Under the new guidance, an entity recognizes as an allowance, its estimate of lifetime expected credit losses, which will result in more timely recognition of such losses. The Company adopted the accounting standard using the modified retrospective transition approach as of January 1, 2023. There was no cumulative effect upon adoption to report to our consolidated financial statements.

The adoption of ASC 326 primarily impacted our trade receivables and the Note receivable - variable fee component recorded on our consolidated balance sheet as of December 31, 2023. Upon adoption of ASC 326, the Company assessed collectability by reviewing accounts receivable on a collective basis where similar characteristics exist and on an individual basis when we identify specific customers with known disputes or collectability issues. In determining the amount of the allowance for credit losses, the Company considered historical collectability based on past due status and made judgments about the creditworthiness of customers based on ongoing credit evaluations. The Company also considered customer-specific information, current market conditions and reasonable and supportable forecasts of future economic conditions to inform adjustments to historical loss data. The carrying value of the Note receivable - variable fee component on the consolidated balance sheet as of December 31, 2023 is based on a discounted expected cash flows model which is adjusted on a quarterly basis. Therefore, the Company determined that the credit risk component is included in the carrying value at each reporting period. The adoption of ASC 326 did not have any material impact on our consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

In March 2023, the FASB issued Accounting Standards Update No. 2023-01, Leases (Topic 842) (the "Update"). The Update requires the entities to classify and account for a leasing arrangement between entities under common control on the same basis as an arrangement with an unrelated party. The Update also requires that leasehold improvements associated with common control leases be amortized by the lessee over the useful life of the leasehold improvements to the common control group (regardless of the lease term) as long as the lessee controls the use of the underlying asset and accounts for the underlying asset as a transfer between entities under common control through an adjustment to equity if and when the lessee no longer controls the use of the underlying asset. The amendments in this Update are effective for fiscal years beginning after December 15, 2023 including interim fiscal periods within those fiscal years. The Company is currently evaluating the impact of the adoption of this Update on its consolidated financial statements.

In August 2023, the FASB issued Accounting Standards Update No. 2023-05, Business Combinations- Joint Venture Formations (Subtopic 805-60) ("ASU 2023-05"). The update requires all joint ventures formed after January 1, 2025, upon formation, to apply a new basis of accounting and initially measure its assets and liabilities at fair value. ASU 2023-05 is effective prospectively for joint ventures with a formation date on or after January 1, 2025. The Company is currently evaluating the impact of the adoption of ASU 2023-05 on its consolidated financial statements.

In October 2023, the FASB issued Accounting Standards Update No. 2023-06, Disclosure Improvements - Codification Amendments in response to SEC's Disclosure Update and Simplification Initiative ("ASU 2023-06).The update requires certain additional disclosures including but not limited to accounting policy on relating to cash flows associated with derivative instruments and their related gains and losses in statement of cash flows, methods used in the diluted earnings per share computation for each dilutive security, disclosures related to assets mortgaged, pledged or otherwise subject to lien and collateralized obligations, disclosure of amounts and terms of unused lines of credit, unfunded commitments, weighted average interest rate on short-term borrowings, preference of preferred stock in an involuntary liquidation if the liquidation preference is other than par or stated value and disclosure of amounts at risk with an individual counterparty if the amount exceeds 10% of stockholder's equity. The Company is currently evaluating the impact of the adoption of ASU 2023-06 on its consolidated financial statements.

In November 2023, the FASB issued Accounting Standards Update No. 2023-07, Segment Reporting (Topic 280) ("ASU 2023-07"). The update improves the reportable segment disclosure requirements by requiring all entities to disclose significant segment expenses that are regularly provided to the chief operating decision maker (CODM), report other segment items ( segment revenue less the significant expenses disclosed and profit or loss) by reportable segment, title and

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position of the CODM and an explanation of how the CODM uses the reported measure of segment profit or loss in assessing segment performance and deciding how to allocate resources. Additionally, ASU 2023-07 requires that if the CODM uses more than one measure of a segment's net income or loss in assessing segment performance and deciding how to allocate resources, the entity may report one or more of those additional measures. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024 and should be applied retrospectively for all periods presented. The Company is currently evaluating the impact of the adoption of ASU 2023-07 on its consolidated financial statements.

Emerging Growth Company Status

Cash, Cash Equivalents, and Restricted Cash

Cash, cash equivalents, and restricted cash consisted of the following as of December 31, 2023 and December 31, 2022:


	December 31, 2023		December 31, 2022
Current assets:
Cash and cash equivalents	$	38,348	$	40,394
Restricted cash - current (1)	4,395		32,402
Long-term assets:
Restricted cash held as collateral (2)	4,499		4,425
Total cash, cash equivalents, and restricted cash	$	47,242	$	77,221

(1) Restricted cash - current as of December 31, 2023 primarily consists of debt reserve on Sunoma Loan. Restricted cash - current as of December 31, 2022 consists of (i) $16,849 held in escrow to secure the Company's purchase obligations under the forward purchase agreement with Meteora (ii) $5,845 equity contribution to a joint venture in connection with the closing of OPAL Term Loan II (iii) $1,127 relates to interest reserve on Sunoma Loan and (iv) $8,581 held in a restricted account for funding one of our RNG projects.

(2) Restricted cash held as collateral represents the collateral requirements on our debt facilities.

Short term investments

The Company considers highly liquid investments such as time deposits and certificates of deposit with an original maturity greater than three months at the time of purchase to be short term investments. The short term investments of $9,875 consists of cash invested in money market accounts with maturities ranging between 1 and 12 months as of December 31, 2023. The amounts in these money market accounts are liquid and available for general use.

Our short term investments are generally invested in commercial paper issued by highly credit worthy counter parties and government backed treasury bills. Investments are generally not FDIC insured and we take counter party risk on these investments.

Earnout Awards

In connection with the Business Combination completed in July 2022 and pursuant to a sponsor letter agreement, the Sponsor agreed to subject 10% of its Class A common stock (received as a result of the conversion of its ArcLight Class B

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ordinary shares immediately prior to the closing) to vesting and forfeiture conditions relating to VWAP targets for the Company's Class A common stock sustained over a period of 60 months following the closing. OPAL Fuels equity holders are eligible to receive an aggregate of 10,000,000 shares of Class B and Class D common stock upon the Company achieving each earn-out event during the earn-out period. The earnout awards (the "Earnout Awards") were recognized at fair value on the closing date and classified as a liability which is remeasured at each balance sheet date and any change in fair value is recognized in the Company's consolidated statement of operations as part of change in fair value of derivative instruments, net. For the year ended December 31, 2023, the Company recorded a total gain of $6,890 from the Sponsor and OPAL earn-out awards in its consolidated statement of operations.

Put option on forward purchase agreement

Prior to the closing of the Business Combination, the Company entered into a Forward Purchase Agreement with Meteora pursuant to which Meteora agreed to purchase 2,000,000 shares of Class A common stock from shareholders who had previously tendered such shares for redemption but agreed to reverse their redemption and sell such shares to Meteora at the redemption price. The Company placed $20,040 in escrow at the closing of the Business Combination to secure its purchase obligation to repurchase these 2,000,000 shares at Meteora’s option for a price of $10.02 per share on the date that is six months after closing of the Business Combination. The put option written to Meteora on 2,000,000 shares of Class A common stock is recorded as a liability under Topic 480 Distinguishing Liabilities from Equity with the change in the fair market value recognized in the statement of operations as part of change in fair value of derivative instruments, net.

On January 23, 2023, pursuant to the terms of the Forward Purchase Agreement, Meteora exercised its option to sell back 1,635,783 shares to the Company. $16,391 of the funds held in escrow which were previously recorded as part of Restricted Cash - current on the Company's consolidated balance sheet as of December 31, 2022 were released to Meteora (excluding accrued interest). In connection with the above, the Sponsor forfeited 197,258 shares of Class A common stock on January 26, 2023 pursuant to the terms of that certain Letter Agreement dated July 21, 2022. The Company treated the repurchased shares as treasury shares and recorded $11,614 representing the fair value of those shares at the closing share price of $7.01 as an adjustment to Stockholders' deficit. Additionally, the Company recorded $4,777 as an offset to the Derivative financial liability - current in its consolidated balance sheet as of December 31, 2023.

Redeemable non-controlling interests

Redeemable non-controlling interests represent the portion of OPAL Fuels that the Company controls and consolidates but does not own. The Redeemable non-controlling interest was created as a result of the Business Combination and represents 144,399,037 Class B Units issued by OPAL Fuels to the prior investors. The Company allocates net income or loss attributable to Redeemable non-controlling interest based on weighted average ownership interest during the period. The net income or loss attributable to Redeemable non-controlling interests is reflected in the consolidated statement of operations.

At each balance sheet date, the mezzanine equity classified Redeemable non-controlling interests is adjusted up to their maximum redemption value if necessary, with an offset in Stockholders' equity. As of December 31, 2023, the maximum redemption value was $802,720.

Stock-based compensation

The Company issues stock-based compensation utilizing stock options, performance units and restricted stock units. In accordance with ASC 718, Stock Compensation, ("ASC 718"), stock-based compensation is measured at the fair value of the award at the date of grant and recognized over the period of vesting on a straight-line basis using the graded vesting method. The grant-date fair value of stock options is estimated using the Black-Scholes option pricing model. Expense for stock-based compensation awards that include performance conditions are initially calculated and subsequently remeasured based on the outcome deemed probable of occurring, and recognized over the vesting period, with the ultimate amount of expense recognized based on the actual performance outcome. Please see Note 16. Stock-based Compensation, for additional information. Forfeitures are recognized as they occur.

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Project development and start up costs

The Company has multiple RNG projects under construction for which the Company incurs certain development costs such as legal, consulting fees for joint venture structuring, royalties to the landfill owner, fines, settlements, site lease expenses and certification costs. Additionally, the Company also incurs certain expenses on new RNG projects that started operating for the first two years such as virtual pipeline costs (trucking costs incurred until a physical pipeline is connected) and ramp up costs. These costs are temporary and non-recurring over the project lifetime. Historically, the Company included these expenses in Cost of sales - RNG Fuel and Selling, general and administrative expenses with no associated revenues. For the years ended December 31, 2023 and 2022, the Company is presenting these expenses in a separate line within operating expenses to provide additional information to the readers of the financial statements regarding the ongoing profitability of our RNG projects in operation.

The following table provides information on the types of expenses classified under this expense category:


	Twelve Months Ended December 31,
	2023		2022
Site lease expenses	$	1,021	$	1,000
Legal and professional fees	1,141		124
Royalties	833		1,444
Virtual pipeline costs (1)	1,295		3,200
Management services (2)	237		109
Other	339		561
Total Project development and startup costs (3)	$	4,866	6,438

(1) Virtual pipeline costs for the year ended December 31, 2023 relate to New River and Prince William. For the year ended December 31, 2022, they relate to New River which came online in May 2022.

(2) Relates to charges billed to the individual projects by Fortistar. See Note. 10 Related parties for additional information.

(3) Excludes 1,454 of expenses for the year ended December 31, 2023 incurred on our equity method investment entities which are not consolidated.

Net income per share

The Business Combination was accounted for as a reverse recapitalization as OPAL Fuels was determined to be the accounting acquirer under FASB ASC Topic 805, Business Combinations. Accordingly, for accounting purposes, the transaction is treated as the equivalent of OPAL Fuels issuing stock for the net assets of ArcLight, accompanied by a recapitalization.

The Company's basic earnings per share of Class A common stock is computed based on the average number of outstanding shares of Class A common stock for the period.

The Company's diluted earnings per share includes effects of the Company's outstanding Redeemable non-controlling interests (OPAL Fuels Class B units), Restricted Stock Units, the put option a forward purchase agreement, redeemable preferred non-controlling interests, Sponsor Earnout Awards and OPAL Earnout Awards.

Accounts Receivable, Net

Accounts receivable represent amounts due from the sale of RNG, natural gas, gas transportation, construction contracts, service contracts, environmental attributes, electricity, capacity, and LFG. The accounts receivable are the net estimate realizable value between the invoiced accounts receivable and allowance for credit losses. Upon adoption of ASC 326, the Company assesses collectability by reviewing accounts receivable on a collective basis where similar characteristics exist and on an individual basis when we identify specific customers with known disputes or collectability issues. In determining the amount of the allowance for credit losses, the Company considers historical collectability based

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on past due status and made judgments about the creditworthiness of customers based on ongoing credit evaluations. The Company also considers customer-specific information, current market conditions and reasonable and supportable forecasts of future economic conditions to inform adjustments to historical loss data.

The Company's allowance for credit losses was $0 and $0 at December 31, 2023 and December 31, 2022.

Fuel Tax Credit Receivable/Payable

At December 31, 2023, the Company accrued federal fuel tax credits of $0.50 per gasoline gallon equivalent of CNG that the Company sold as vehicle fuel in 2023. At December 31, 2023 and 2022, fuel tax credits receivable were $5,345 and $4,144, respectively. Under the terms of its fuel sales agreements with certain of its customers, the Company is obligated to share portions of these tax credits. At December 31, 2023 and 2022, the amounts of fuel tax credits owed to customers were $4,558 and $3,320, respectively. The Company recorded its portion of tax credits earned as a reduction to cost of sales — RNG fuel in the consolidated statements of operations.

Asset Retirement Obligation

The Company accounts for asset retirement obligations in accordance with FASB ASC 410, Asset Retirement and Environmental Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and when a reasonable estimate of fair value can be made. The fair value of the estimated asset retirement obligations is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The discounted asset retirement costs capitalized amount are accreted over the life of the sublease or site lease agreement. Asset retirement obligations are deemed Level 3 fair value measurements as the inputs used to measure the fair value are unobservable. The Company estimates the fair value of asset retirement obligations by calculating the estimated present value of the cost to retire the asset. This estimate requires assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental, and political environments. In addition, the Company determines the Level 3 fair value measurements based on historical information and current market conditions.

As of December 31, 2023 and 2022, the Company estimated the value of its total asset retirement obligations to be $6,728 and $6,256, respectively.

The changes in the asset retirement obligations were as follows as of December 31, 2023:


	December 31, 2023
Balance, December 31, 2022	$	6,256
Payment of Asset retirement obligations during the year	(49)
Accretion expense	521
Total asset retirement obligation	6,728
Less: current portion	(3,860)
Total asset retirement obligation, net of current portion	$	2,868

Revenue Recognition

The Company’s revenue arrangements generally consist of a single performance obligation to transfer goods or services. Revenue from the sale of RNG, CNG and, electricity is recognized by applying the “right to invoice” practical expedient within the accounting guidance for Revenue from Contracts with Customers that allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer. For some public CNG Fueling Stations where there is no contract with the customer, the Company recognizes revenue at the point in time that the customer takes control of the fuel.

The Company also performs maintenance services throughout the country. Maintenance consists of monitoring equipment and replacing parts as necessary to ensure optimum performance. Revenue from service agreements is

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recognized over time as services are provided. Capacity payments fluctuate based on peak times of the year and revenues from capacity payments are recognized monthly as earned.

The Company has agreements with two natural gas producers ("Producers") to transport Producers' natural gas using the Company's RNG gathering system. The performance obligation is the delivery of Producers' natural gas to an agreed delivery point on an interstate gas pipeline. The quantity of natural gas transported for the Producers is measured at a certain specified meter. The price is fixed at contracted rates and the Producers pay approximately 30 days after month-end. As such, transportation sales are recognized over time, using the output method to measure progress.

The Company provides credit monetization services to customers that own renewable gas generation facilities. The Company recognizes revenue from these services as the credits are minted on behalf of the customer. The Company receives non-cash consideration in the form of RINs or LCFSs for providing these services and recognizes the RINs or LCFSs received as Environmental credits held for sale within current assets based on their estimated fair value at contract inception. When the Company receives RINs or LCFSs as payment for providing credit monetization services, it records the non-cash consideration in inventory based on the fair value of RINs or LCFSs at contract commencement.

On November 29, 2021, the Company entered into a purchase and sale agreement with NextEra, a related party, for the environmental attributes generated by the RNG Fuels business. Under this agreement, the Company is committed to sell a minimum of 90% of the environmental attributes generated and will receive net proceeds based on the agreed upon price less a specified discount. A specified volume of environmental attributes sold per quarter will incur a discount fee per environmental attribute in addition to the specified discount. The agreement was effective beginning January 1, 2022. For the years ended December 31, 2023 and 2022, the Company earned net revenues after discount and fees of $56,069 and $58,185, respectively, under this contract which was recorded as part of Revenues - RNG Fuel. For the years ended December 31, 2023 and 2022, the Company earned net revenues after discount and fees of $28,468 and $18,735, respectively, which was recorded as part of Revenues - Fuel Station Services.

During third and fourth quarter of 2022, two of the wholly-owned subsidiaries from our Renewable Power portfolio entered into a purchase and sale agreement with an environmental attribute marketing firm to sell environmental attributes associated with renewable biomethane ("ISCC Carbon Credits") and purchase brown gas back at contracted fixed prices per million British thermal units ("MMbtu"). One of these contracts has a term of 3-years from the date of certification of the facility with an auto-renewal option. The other contract was terminated in August 2023. During the third quarter of 2023, three additional Renewable Power facilities entered into purchase and sale agreements with 3 year terms and similar terms and conditions as the previous contracts. For the years ended December 31, 2023 and 2022, the Company earned net revenues of $16,325 and $3,114, respectively under this contract which were recorded as part of Revenues - Renewable Power in the consolidated statement of operations.

Sales of Environmental Attributes such as RINs, renewable energy credits ("RECs"), ISCC Carbon Credits and LCFS are generally recorded as revenue when the certificates related to them are delivered to a buyer. However, the Company may recognize revenue from the sale of such Environmental Attributes at the time of the related renewable power sales when the contract provides that title to the Environmental Attributes transfers at the time of production, the Company's price to the buyer is fixed, and collection of the sales proceeds is certain.

Management operating fees are earned for the operation, maintenance, and repair of the gas collection system of a landfill site. Revenue is calculated on the volume of per million British thermal units of LFG collected and the megawatt hours ("MWhs") produced at that site. This revenue is recognized when LFG is collected and renewable power is delivered.

The Company has various fixed price contracts for the construction of Fueling Stations for customers. Revenues from these contracts, including change orders, are recognized over time, with progress measured by the percentage of costs incurred to date compared to estimated total costs for each contract. This method is used as management considers costs incurred to be the best available measure of progress on these contracts. Costs capitalized to fulfill certain contracts were not material in any of the periods presented.

The Company owns Fueling Stations for use by customers under fuel sale agreements. The Company bills these customers at an agreed upon price for each gallon sold and recognizes revenue based on the amounts invoiced in accordance with the "right to invoice" practical expedient. For some public stations where there is no contract with the customer, the Company recognizes revenue at the point-in-time that the customer takes control of the fuel.

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The Company from time-to-time enters into fuel purchase agreements with customers whereby the Company is contracted to design and build a Fueling Station on the customer's property in exchange for the Company providing CNG/RNG to the customer for a determined number of years. In accordance with the standards of ASC 840, Leases, the Company has concluded these agreements meet the criteria for a lease and are classified as operating leases. Typically, these agreements do not require any minimum consumption amounts and, therefore, no minimum payments. Upon adoption of ASC 842, the Company adopted the practical expedient not to reassess the classification. For additional information on lease revenues earned, please see Note 8. Leases.

Disaggregation of Revenue

The following table shows the disaggregation of revenue according to product line:


	Twelve Months Ended December 31,
	2023		2022
Renewable power sales	$	33,648	$	33,881
Third party construction	49,318		49,458
Service	16,711		16,449
Brown gas sales	19,587		38,356
Environmental credits (1)	126,573		86,901
Parts sales	4,680		4,391
Operating agreements	—		893
Other	632		328
Total revenue from contracts with customers	251,149		230,657
Lease revenue (2)	4,959		4,874
Total revenue	$	256,108	$	235,531

(1) Includes revenues of $16,325 and $3,114 for the years ended December 31, 2023 and 2022, from customers domiciled outside of United States.

(2) Lease revenue relates to approximately twenty-two fuel purchasing agreements our of which we have two of our RNG fuel stations with minimum take or pay provisions and revenue from power purchase agreements at two of our Renewable Power facilities where we determined that we transferred the right to control the use of the power plant to the purchaser.

For the years ended December 31, 2023 and 2022, 19% and 21%, respectively of revenue was recognized over time, and the remainder was for products and services transferred at a point in time.

Other income

The following table shows the items consisting of items recorded as Other income:


	Twelve Months Ended December 31,
	2023		2022
Gain on deconsolidation of VIEs (1)	$	122,873	$	—
Gain on redemption of Note receivable	—		1,943
Gain on transfer of non-financial asset in exchange for services received (2)	1,599		—
Other income	$	124,472	$	1,943

(1) Represents non-cash gain on deconsolidation of Emerald and Sapphire on May 30, 2023.

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(2) Represents the fair value of RINs transferred as consideration for services received.

Contract Assets

Contract assets consist primarily of costs and estimated earnings in excess of billings and retainage receivables. Costs and estimated earnings in excess of billings represent unbilled amounts earned and reimbursable under construction contracts and arise when revenues have been recognized but amounts are conditional and have yet to be billed under the terms of the contract. Included in costs and estimated earnings in excess of billings are amounts the Company will collect from customers, changes in contract specifications or design, costs associated with contract change orders in dispute or unapproved as to scope or price, or other customer-related causes of unanticipated contract costs. Amounts become billable according to contract terms, which consider the progress on the contracts as well as achievement of certain milestones and completion of specified units of work. Except for claims, such amounts will be billed over the remaining life of the contract.

Contract Liabilities

Contract liabilities consist of billings in excess of costs and estimated earnings, other deferred construction revenue and general provisions for losses, if any. Billings in excess of costs and estimated earnings represent cash collected from customers and billings to customers in advance of work performed. Such unearned project-related costs will be incurred over the remaining life of the contract.

Contract Balances

The following table provides information about receivables, contract assets, and contract liabilities from contracts with customers:


	December 31, 2023		December 31, 2022
Accounts receivable, net	$	27,623	$	31,083
Contract assets:
Cost and estimated earnings in excess of billings	$	4,630	$	7,027
Accounts receivable retainage, net	2,160		2,744
Contract assets total	$	6,790	$	9,771
Contract liabilities:
Billings in excess of costs and estimated earnings	$	6,314	$	8,013
Contract liabilities total	$	6,314	$	8,013

During the twelve months ended December 31, 2023, the Company recognized revenue of $8,013 that was included in "Contract liabilities" at December 31, 2022. During the twelve months ended December 31, 2022, the Company recognized revenue of $9,785 that was included in "Contract liabilities" at December 31, 2021.

Parts Inventory

Parts inventory, also referred to as supplies inventory, consists of shop spare parts inventory and construction site parts inventory. Inventory is stated at the lower of cost or net realizable value. The substantial amount of inventory is identified, tracked and treated as finished goods. An annual review of inventory is performed to identify obsolete items. The Company’s inventory reserves were $20 and $3 as of December 31, 2023 and 2022, respectively. Cost is determined using the average cost method.

Capital Spares

Capital spares consist primarily of large replacement parts and components for the RNG facilities and power plants. These parts, which are vital to the continued operation of the RNG facilities and power plants and require a substantial lead time to acquire, are maintained on hand for emergency replacement. Capital spares are recorded at cost and

F-19

expensed when placed into service as part of a routine maintenance project or capitalized when part of a plant improvement project.

Property, Plant, and Equipment, net

Property, plant, and equipment are recorded at cost, except for the portion related to asset retirement obligations, which are recorded at estimated fair value at the time of inception. Direct costs related to the construction of assets and renewals and betterments that materially improve or extend the life of the assets are capitalized. Additionally, any interest expense incurred on any outstanding construction loans such as interest on our Sunoma loan is capitalized to the specific project. Replacements, maintenance, and repairs that do not improve or extend the life of the respective assets are expensed as incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets as follows:


Plant and equipment						5 - 30 years
CNG/RNG fueling stations						10-20 years
Construction in progress						N/A
Buildings						40 years
Land						N/A
Service equipment						5-10 years
Leasehold improvements						shorter of lease term or useful life
Vehicles						7 years
Office furniture and equipment						5-7 years
Computer software						3 years
Land lease - finance lease						Lease term
Vehicles - finance lease						shorter of lease term or useful life
Other						7 years

When plant and equipment are retired or otherwise disposed of, the related cost and accumulated depreciation or amortization is removed, and a gain or loss is recognized in the consolidated statements of operations. The Company capitalizes costs related to the development and construction of new projects when there is a significant likelihood that the project will be constructed for its intended use. This is determined based on the attainment of certain milestones, including, but not limited to, the receipt of permits; final negotiation of major contracts including gas rights agreements, gas transportation and engineering, procurement and construction contracts. Costs incurred prior to this time are expensed. Additionally, the Company capitalizes any interest incurred on its generic borrowings during the construction phase until the project becomes operational.

Deferred financing costs

Fees incurred for obtaining new loans or debt restructuring are deferred and amortized to interest expense over the life of the related debt using effective interest method. Unamortized financing costs are written off when the related debt is extinguished. Deferred financing costs (or debt issuance costs) are reported as a reduction of the carrying value of the long-term debt in the consolidated balance sheets.

Environmental credits held for sale

The Company provides credit monetization services to customers that own renewable gas generation facilities. The Company recognizes revenue from these services as the credits are minted on behalf of the customer. The Company receives non-cash consideration in the form of RINs or LCFSs for providing these services and recognizes the environmental credits received as part of Revenues - Fuel Station Services and Environmental credits held for sale within current assets based on their estimated fair value at contract inception. It is recorded at historical fair value at contract inception and adjusted to its net realizable value at each balance sheet date. Due to the historically higher LCFS pricing, the

F-20

fair value at contract inception may be significantly higher than the net realizable value of the environmental credits generated. For the years ended December 31, 2023 and 2022, the Company recorded $7,354 and $3,523 and as part of Cost of sales - Fuel Station Services.

Fuel Station Services Construction Backlog

The Company's remaining performance obligations ("backlog") represent the unrecognized revenue value of its contract commitments. The Company's backlog may significantly vary each reporting period based on the timing of major new contract commitments. At December 31, 2023, the Company had a backlog of $37,531 of which $29,450 is anticipated to be recognized as revenue in the next 12-months.

Major Maintenance

Major maintenance is a component of maintenance expense and encompasses overhauls of internal combustion engines, gas compressors and electrical generators. Major maintenance is expensed as incurred. Major maintenance expense was $7,240 and $4,701 for the years ended December 31, 2023 and 2022 respectively, and is included in cost of sales — renewable power in the consolidated statements of operations.

Goodwill

Goodwill represents the excess of purchase price of an acquisition over the fair value of net assets acquired in a business combination subject to ASC 805, Business Combinations. Goodwill is not amortized, but the potential impairment of goodwill is assessed at least annually and on an interim basis whenever events or changes in circumstances indicate that the carrying value may not be fully recoverable. Accounting rules require that the Company test at least annually, or more frequently when a triggering event occurs that indicates that the fair value of the reporting unit may be below its carrying amount, for possible goodwill impairment in accordance with the provisions of ASC 350-10. The Company performs its annual test in fourth quarter of each year.

During 2020, the Company has adopted the provisions of the Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) 2017-04, Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment. Under this guidance, the Company performed qualitative test for goodwill on Beacon and Trustar for the year ended December 31, 2023. As a result of these tests, the Company determined that the fair value of its reporting unit exceeded its carrying value and, thus, the Company determined that goodwill was not impaired.

Intangible Assets and Liabilities

Identifiable intangible assets consist of three PPAs, one fueling station contract, one transmission/distribution interconnection, and the cost of intellectual property all of which are amortized using the straight-line method over the underlying applicable contract periods or useful lives which range from five to twenty years.

The PPA intangible liabilities are amortized using the straight-line method over their contract life. Amortization related to these intangible liabilities is included in RNG fuel revenue and Renewable power revenue, respectively, in the consolidated statements of operations.

Impairment of Long-Lived Assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be fully recoverable. Recoverability of long-lived assets to be held and used is measured by a comparison of the carrying amount of an asset to future net undiscounted cash flows expected to be generated by the asset. If such assets are impaired, the impairment to be recognized is measured by the amount that the carrying amounts of the assets exceed the fair value of the assets. Assets disposed of are reported at the lower of the carrying amount or fair value less selling costs. There was no material impairment expense booked for the years ended December 31, 2023 and 2022.

Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, and/or (ii) information available regarding the current market value for such assets. We use our best estimates in

F-21

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.

Derivative Instruments

The Company estimates the fair value of its derivative instruments using available market information in accordance with ASC 820 for fair value measurements and disclosures of derivatives. Derivative instruments are measured at their fair value and recorded as either assets or liabilities unless they qualify for an exemption from derivative accounting measurement such as normal purchases and normal sales. All changes in the fair value of recognized derivatives are recognized currently in earnings.

The Company enters into electricity forward sale agreements. Some of these electricity forward sale agreements meet the definition of a derivative but qualify for the normal purchases and normal sales exception from derivative accounting treatment. In accordance with authoritative guidance for derivatives, the Company considers both qualitative and quantitative factors when determining whether a contract qualifies for the normal purchases and normal sales exception. There are two electricity forward sales agreements during 2022 that were recorded under the normal purchases and normal sales exception and, therefore, fair value adjustments were not required for the year ended December 31, 2023. Additionally, there were two electricity forward purchase agreements during 2023 that were recorded under the normal purchases and normal sales exception, and therefore, fair value adjustments were not required for the year ended December 31, 2023. Please see Note 9. Derivative Financial Instruments and Fair Value Measurements for additional information.

The Company enters into commodity swap arrangements as economic hedges against market price volatility of Renewable power sales. These commodity swap agreements do not qualify for the normal purchases and normal sales exception and therefore are accounted for as derivatives under ASC 815, Derivatives and Hedging. The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, these commodity swap agreements are measured at their fair value and recorded as either current or non-current assets or liabilities and any changes in fair value are recorded as part of Revenues in its consolidated statements of operations for the years ended December 31, 2023 and 2022.

The Company maintains a risk management strategy that incorporates the use of interest rate swaps to minimize significant fluctuation in cash flows and/or earnings that are caused by interest rate volatility. The Company designated the interest rate swaps as cash flow hedges applies hedge accounting. The Company records the fair value of the interest rate swap as an asset or liability on its consolidated balance sheet. The effective portion of the swap is recorded in Accumulated other comprehensive income.

Vulnerability Due to Certain Concentrations

Financial instruments that potentially subject the Company to concentration of credit risk consist principally of cash, cash equivalents, restricted cash, short term investments, derivative instruments and trade accounts receivable. The Company holds cash, cash equivalents and restricted cash at several major financial institutions, much of which exceeds FDIC insured limits. Historically, the Company has not experienced any losses due to such concentration of credit risk. The Company’s temporary cash investments policy is to limit the dollar amount of investments with any one financial institution and monitor the credit ratings of those institutions. While the Company may be exposed to credit losses due to the nonperformance of the holders of its deposits, the Company does not expect the settlement of these transactions to have a material effect on its results of operations, cash flows or financial condition.

Income Taxes

As a result of the Business Combination, the Company is the sole managing member of OPAL Fuels. OPAL Fuels is a limited liability company that is treated as a partnership for U.S. federal income tax purposes and for most applicable state and local income taxes. Any taxable income or loss generated by OPAL Fuels is passed through to and included in the taxable income or loss of its members, including the Company, on a pro-rata basis, subject to applicable tax regulations.

F-22

differences are expected to reverse. Such net tax effects on temporary differences are reflected on the Company’s consolidated balance sheets as deferred tax assets and liabilities. Deferred tax assets are reduced by a valuation allowance when the Company believes that it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. The Company calculates the interim tax provision in accordance with the provisions of ASC Subtopic 740-270, Income Taxes; Interim Reporting. For interim periods, the Company estimates the annual effective income tax rate and applies the estimated rate to the year-to-date income or loss before income taxes.

Significant Customers, Vendors and Concentration of Credit Risk

For the year ended December 31, 2023 two customer accounted for 47% of revenue. For the year ended December 31, 2022, two customers accounted for 49% of revenue. At December 31, 2023, two customers accounted for 54% of accounts receivable. At December 31, 2022, two customers accounted for 45%, of accounts receivable.

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents, and trade receivables. The Company places its cash with high credit quality financial institutions located in the United States of America. The Company performs ongoing credit evaluations of its customers.

As of December 31, 2023 one vendor accounted for 32% of the accounts payable. As of December 31, 2022, one vendor accounted for 19% of the accounts payable.

Investment in other entities

Investment in other entities includes the Company’s interests in certain investees which are accounted for under the equity method of accounting as the Company has determined that the investment provides the Company with the ability to exercise significant influence, but not control, over the investee. The Company’s investments in these nonconsolidated entities are reflected in the Company’s consolidated balance sheet at cost. The amounts initially recognized are subsequently adjusted for the impacts of impairment, capitalized interest and Company’s share of earnings (losses) which are recognized as income (loss) from equity method investments in the consolidated statement of operations after adjustment for the effects of any basis differences. Investments are also increased for contributions made to the investee and decreased by distributions from the investee and classified in the statement of cash flows using the cumulative earnings approach.

The Company evaluates its equity method investments for impairment whenever events or changes in circumstances indicate that a decline in value has occurred that is other than temporary. Evidence considered in this evaluation includes, but would not necessarily be limited to, the financial condition and near-term prospects of the investee, recent operating trends and forecasted performance of the investee, market conditions in the geographic area or industry in which the investee operates and the Company’s strategic plans for holding the investment in relation to the period of time expected for an anticipated recovery of its carrying value. If the investment is determined to have a decline in value deemed to be other than temporary, it is written down to estimated fair value in the same period the impairment was identified. For the years ended December 31, 2023 and 2022, the Company did not identify any impairments on its investments in other entities.

3. Investment in Other Entities

The Company uses the equity method to account for investments in affiliates that it does not control, but in which it has the ability to exercise significant influence over operating and financial policies. The Company's investments in these nonconsolidated affiliates are reflected in the Company's consolidated balance sheets under the equity method, and the Company's proportionate net income, if any, is included in the Company's consolidated statements of operations as income from equity method investments.

We continue to evaluate operational developments and the impact of the anticipated significant expansion of the operations of our existing equity method investments. As discussed below, the impact of formation of two new joint ventures which increased our number of RNG projects accounted for under equity method was a significant factor in our consideration of how to reflect the income (loss) from equity method investments appropriately within our consolidated statement of operations. Based on our analysis, it was determined that our equity method investments have evolved into a critical, integral part of our RNG segment business operations as they provide critical additional production capacity. Therefore, we have determined that the presentation of income (loss) from equity method investments as part of the operating income is more meaningful and useful information to the readers of our financial statements. As a result, we

F-23

have reclassified our portion of income (loss) from equity method investments to Operating income for all periods presented.

Formation Of A New Joint Venture

On September 14, 2023, OPAL L2G, a wholly-owned indirect subsidiary of the Company, entered into the Agreement with SJI LRNG, a wholly-owned indirect subsidiary of SJI, establishing the terms and conditions of governance and operation of the SJI Joint Venture. The purpose of the SJI Joint Venture, which is owned 50/50 by OPAL L2G and SJI LRNG, is to develop, construct, own and operate Facilities to produce RNG using biogas generated by certain landfills. The Agreement governs the terms and conditions of capital contributions to be made by the SJI Joint Venture members to fund the development, construction and operations of the Facilities. The Agreement requires members of the SJI Joint Venture to contribute their respective share (50% each) of such capital requirements. The Agreement initially contemplates two RNG projects (RNG Atlantic and RNG Burlington) in New Jersey with each RNG project represented as a separate series of membership interests, also owned 50-50 by the members. Further, the Agreement provides for the SJI Joint Venture to enter into a MSA, O&M Agreement, and dispensing agreement with certain wholly-owned, indirect subsidiaries of the Company. The MSA establishes the terms and conditions for the day-to-day administration of the projects, including responsibility for managing the development and overseeing the construction of the Facilities. The O&M Agreement establishes the terms and conditions for operating and maintaining the Facilities once construction is completed. The Dispensing Agreement provides for the acquisition, marketing and sale of the Environmental Attributes associated with RNG produced by the Facilities.

Upon the execution of the above transaction, the Company reassessed its equity interests in the SJI Joint Venture under ASC 810, Consolidation and determined that the Company does not have a controlling financial interest in SJI Joint Venture under ASC 810 because the governance of the joint venture is driven by a board jointly controlled by the joint venture partner and OPAL equally and there are substantive participating rights held by the joint venture partner in the significant activities of SJI Joint Venture. As of December 31, 2023, the Company contributed $2,115 towards RNG Atlantic.

Deconsolidation of Emerald and Sapphire

On May 30, 2023, the Company together with a third-party environmental solutions company formed Paragon. The Company owns 50% of the ownership interest in Paragon. Concurrent to the formation of Paragon, the Company contributed its 50% ownership interests in Emerald and Sapphire to Paragon.

On May 30, 2023, OPAL Fuels Intermediate Holdco 2 LLC (“OPAL Intermediate Holdco 2”), a wholly-owned indirect subsidiary of the Company, assigned to Paragon its rights and obligations under its existing senior secured credit facility, OPAL Term Loan II.

Upon the execution of the above two transactions, the Company reassessed its equity interests in Emerald and Sapphire under ASC 810, Consolidation and determined that the Company does not have a controlling financial interest in Paragon under ASC 810 because the governance of the Paragon is driven by a board jointly controlled by the joint venture partner and OPAL equally and there are substantive participating rights held by the joint venture partner in the significant activities of Paragon.

Based on the above analysis, the Company determined that it should account for its ownership interests in Paragon under the equity method of accounting pursuant to ASC 323, Investments Equity Method and Joint Ventures, prospectively, as the Company has the ability to exercise significant influence, but not control over the joint venture company.

Prior to May 30, 2023, the Company consolidated these two entities in accordance with the variable interest entity model guidance under ASC 810, Consolidation. Additionally, the Company deconsolidated $2,765 capitalized interest on these two projects. Upon deconsolidation, the Company remeasured the fair value of the retained investment and recognized a gain of $122,873 in the consolidated statement of operations for the year ended December 31, 2023 and a corresponding increase in its basis in Investment in Other Entities on its consolidated balance sheet as of December 31, 2023. The Company determined that the gain on deconsolidation is attributable to the construction in progress and, therefore, will be amortized over the useful life of the asset which begins on the date the asset is placed in service. The fair value of the retained investment was measured based on a discounted cash flows model in which the future net cash flows from the two RNG facilities were discounted to their present value using a discount factor of 14%.

F-24

The following table shows the movement of Investment in other entities:


	Pine Bend			Noble Road			GREP			SJI			Paragon			Total
Percentage of ownership	50		%	50		%	20		%	50		%	50		%

Balance at December 31, 2021	$	21,188		$	24,516		$	1,446		$	—		$	—		$	47,150
Additional investment representing capitalized interest	597			—			—			—			—			597
Other comprehensive income	—			—			334			—			—			334
Net income from equity method investments	733			2,749			2,302			—			—			5,784
Distributions from return of investment in equity method investment (2)	—			(2,100)			—			—			—			(2,100)
Balance at December 31, 2022	22,518			25,165			4,082			—			—			51,765
Deconsolidation of Emerald and Sapphire	—			—			—			—			34,662			34,662
Deconsolidation of deferred financing costs and capitalized interest	—			—			—			—			1,383			1,383
Net income from equity method investment	4,333			5,642			(1,212)			(547)			364			8,580
Reclassification of adjustments into earnings	—			—			(334)			—			—			(334)
Contribution by the Company	—			—			—			2,114			6,200			8,314
Distributions from return on investment in equity method investment (1)	(5,066)			(6,291)			(521)			—			(364)			(12,242)
Distributions from return of investment in equity method investment (2)	(459)			(1,159)			—			—			(3,221)			(4,839)
Accumulated other comprehensive loss	—			—			—			—			(8)			(8)
Gain on deconsolidation of Emerald and Sapphire (3)	—			—			—			—			122,873			122,873
Amortization of basis difference (4)	(264)			(1,183)			—			—			(1,608)			(3,055)
	$	21,062		$	22,174		$	2,015		$	1,567		$	160,281		$	207,099

(1) Recorded as part of cash flows from operating activities for the year ended December 31, 2023.

(2) Recorded as part of cash flows from investing activities for the years ended December 31, 2023 and 2022.

(3) Recorded as part of Other income in our consolidated statement of operations for the year ended December 31, 2023.

(4) Reflected in Income from equity method investments in the consolidated statement of operations for the year ended December 31, 2023.

Note receivable

In August 2021, the Company acquired 100% ownership interest in Reynolds which held a note receivable of $10,450 to Biotown. The Note receivable had a maturity date of July 15, 2027 and carried an interest rate of 12.5% of which 8% is payable in cash on a quarterly basis from the inception of the loan and 4.5% payment-in-kind interest adding to the outstanding debt balance until the facility becomes operational.

F-25

On July 15, 2022, Biotown repaid the total amount outstanding under the Note receivable including paid-in-kind interest and prepayment penalty.

The Note receivable also entitles Reynolds to receive 4.25% of any revenue-based distributions made up to a maximum of $4,500 over the term of the debt. The Company recorded the fair value of the Note receivable — variable fee component of $1,538 as an allocation of the initial investment balance of $10,450 and recorded payment-in-kind interest income of $413 and $288 as a reduction to interest and financing expense, net in the consolidated statement of operations for the years ended December 31, 2023 and 2022, respectively.

The Note receivable - variable fee component of $2,302 and $1,942 is recorded as a long-term asset on its consolidated balance sheets as of December 31, 2023 and December 31, 2022, respectively.

The following table summarizes financial information of the unconsolidated entities:


	December 31, 2023		December 31, 2022
Current assets	$	25,114	$	14,563
Non-current assets	171,633		109,414
Current liabilities	26,205		6,765
Non-current liabilities	34,021		13,825
Members' equity	136,521		103,388

The following table summarizes the income from equity method investments:


	Twelve Months Ended
		December 31, 2023		December 31, 2022
Revenue (1)		$	50,074	$	58,013
Gross profit		12,065		41,932
Net income		6,323		29,983

Net income from equity method investments (2)		$	5,525	$	5,784

(1) Revenues for the year ended December 31, 2022 include a realized gain of $32,796 from commodity swap contracts on our equity method investment, GREP for the year ended December 31, 2022.

(2) Net income from equity method investments represents our portion of the net income from equity method investments.

4. Property, Plant, and Equipment, Net

Property, plant, and equipment, net, consisted of the following as of December 31, 2023 and December 31, 2022:

F-26


	December 31, 2023		December 31, 2022
Plant and equipment	$	205,188	$	201,655
CNG/RNG fueling stations	51,749		34,567
Construction in progress (1)	175,060		152,105
Buildings	2,585		2,585
Land	1,303		1,303
Service equipment	2,481		1,888
Leasehold improvements	815		815
Vehicles	489		313
Office furniture and equipment	307		307
Computer software	277		277
Land Lease - finance lease	6,469		—
Vehicles - finance leases	2,580		1,236
Other	591		487
	449,894		397,538
Less: accumulated depreciation	(110,401)		(100,215)
Property, plant, and equipment, net	$	339,493	$	297,323

(1) Includes $5,475 of interest capitalized from our general borrowings for the year ended December 31, 2023 and $3,678 for the year ended December 31, 2022.

As of December 31, 2023, construction in progress primarily consists of capital expenditure incurred for the construction of RNG generation facilities including, but not limited to Polk County, Prince William, Central Valley and RNG dispensing facilities. The majority of these facilities, for which costs are in construction in progress as of December 31, 2023, are expected to be operational in early 2024.

Depreciation expense on property, plant, and equipment for the years ended December 31, 2023 and December 31, 2022 was $13,481 and $11,892 respectively.

5. Intangible Assets, Net

Intangible assets, net, consisted of the following at December 31, 2023 and December 31, 2022:


	December 31, 2023
	Cost		Accumulated Amortization		Intangible Assets, Net		Weighted Average Amortization Period (Years)
Power purchase agreements	$	8,999	$	(7,926)	$	1,073	18.1
Transmission/distribution interconnection	1,600		(1,076)		524		15.1
Intellectual property	43		(36)		7		5.0
Total intangible assets	$	10,642	$	(9,038)	$	1,604

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	December 31, 2022
	Cost		Accumulated Amortization		Intangible Assets, Net		Weighted Average Amortization Period (years)
Power purchase agreements	$	8,999	$	(7,488)	$	1,511	18.1
Transmission/distribution interconnection	1,600		(971)		629		15.1
CNG sales contract	807		(799)		8		10.0
Intellectual property	43		(24)		19		5.0
Total intangible assets	$	11,449	$	(9,282)	$	2,167

Amortization expense for the twelve months ended December 31, 2023 and 2022 was $563 and $694, respectively. At December 31, 2023, estimated future amortization expense for intangible assets is as follows:


Fiscal year:
2024	267
2025	267
2026	239
2027	238
Thereafter	593
	$	1,604

6. Goodwill

The following table summarizes the changes in goodwill, if any, by reporting segment from the beginning of the period to the end of the period:


	RNG Fuel		Fuel Station Services		Total
Balance at December 31, 2023	$	51,155	$	3,453	$	54,608
Balance at December 31, 2022	$	51,155	$	3,453	$	54,608

7. Borrowings

The following table summarizes the borrowings under the various debt facilities as of December 31, 2023 and December 31, 2022:

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	December 31, 2023		December 31, 2022
Senior Secured Credit Facility, term loan	$	—	$	15,250
Less: current portion	—		(15,250)
Senior Secured Credit Facility, term loan	—		—
Senior Secured Credit Facility, working capital facility	—		7,500
Less: current portion	—		(7,500)
Senior Secured Credit Facility, working capital facility	—		—
OPAL Term Loan	186,618		96,090
Less: unamortized debt issuance costs	(10,086)		(1,758)
Less: current portion	—		(27,732)
OPAL Term Loan, net of debt issuance costs	176,532		66,600
Sunoma Loan	22,453		23,000
Less: unamortized debt issuance costs	(835)		(908)
Less: current portion	(1,608)		(380)
Sunoma Loan, net of debt issuance costs	20,010		21,712
Convertible Note Payable	—		28,528
Less: current portion	—		(28,528)
Convertible Note Payable	—		—
Municipality Loan	—		76
Less: current portion	—		(76)
Municipality Loan	—		—
Non-current borrowings total	$	196,542	$	88,312

As of December 31, 2023, principal maturities of debt are expected as follows, excluding any undrawn debt facilities as of the date of the consolidated balance sheet:


	OPAL Term Loan		Sunoma Loan		Total
Fiscal year:
2024	$	—	$	1,608	$	1,608
2025	22,394		1,743		24,137
2026	22,394		1,883		24,277
2027	22,394		2,036		24,430
2028	119,436		4,232		123,668
Thereafter	—		10,951		10,951
	$	186,618	$	22,453	$	209,071

Senior Secured Credit Facility

On March 20, 2023, the Company repaid in full the remaining outstanding loan under this facility.

On September 21, 2015, FM3, an indirect wholly-owned subsidiary of the Company, entered into a senior secured credit facility (the "Senior Secured Credit Facility") as a borrower and a syndicate of lenders, which provides for an aggregate principal amount of $150,000, consisting of (i) a term loan of $125,000 and a (ii) working capital letter of credit facility of up to $19,000 and a (iii) debt service reserve and liquidity facility of up to $6,000. The Company paid $14,300 to the lenders in connection with the transaction.

The loans under the Senior Secured Credit Facility had an interest rate of a fixed margin plus the secured overnight financing rate ("SOFR") for the relevant interest period. The fixed margin is 2.75% for the first four years, then 3.0% until October 8, 2021, and 3.25% thereafter.

F-29

On December 19, 2022, FM3 entered into an Omnibus and Consent Agreement (the “FM3 Amendment”). The FM3 Amendment amended the credit agreement, among other things, to (a) extend the maturity date of the obligations thereunder from December 20, 2022 to March 20, 2023, (b) permit OPAL Fuels to purchase the rights and obligations of certain exiting lenders at par, (c) prepay a portion of the outstanding loans made by the remaining lenders and (d) permit the release of certain project company subsidiaries of FM3 from the collateral securing the obligations under the credit agreement. Upon consummation of the FM3 Amendment, the Company repaid $54,929 of the outstanding term loan.

Patronage dividends

The Company is eligible to receive annual patronage dividends from one of its lenders, Cobank ACB under a profit sharing program. For the years ended December 31, 2023 and 2022, the Company received cash dividends of $125 and $126, respectively, which were recorded as credits to interest expense in the consolidated statements of operations. Additionally, the Company recorded $489 and as a long-term asset in the consolidated balance sheets at December 31, 2023 and 2022, which represents the Company's equity interest in Cobank SCB. These interests will be redeemed for cash beginning in 2024.

OPAL Term Loan

On October 22, 2021, OPAL Fuels Intermediate Holding Company LLC (“OPAL Intermediate Holdco”), an indirect wholly-owned subsidiary of the Company, entered into a $125,000 term loan agreement (the "OPAL Term Loan") with a syndicate of lenders. As of September 1, 2023, the total outstanding balance on the debt facility was $87,602.

On September 1, 2023, OPAL Intermediate Holdco restructured its existing credit agreement and entered into a new senior secured credit facility (the "Credit Agreement") with OPAL Intermediate HoldCo as the Borrower, direct and indirect subsidiaries of the Borrower as guarantors (the “Guarantors”), the lenders party thereto, as lenders, Apterra Infrastructure Capital LLC, Barclays Bank PLC, BofA Securities, Inc., Celtic Bank Corporation, Citibank, N.A., JP Morgan Chase Bank, N.A. Investec Inc. and ICBC Standard Bank PLC, as joint lead arrangers, and Bank of America, N.A., as administrative agent. Four of the existing lenders participated in the new credit facility.

The Credit Agreement provides for up to $450.0 million of initial and delayed draw term loans (with such delayed draw term loans available for up to 18 months after closing) and $50.0 million of revolving loans. On September 1, 2023, the Company drew down $144,118 and repaid (1) Intermediate HoldCo’s existing secured indebtedness in the amount of approximately $87,602 plus accrued interest, (2) certain accrued but unpaid returns in the amount of $15,669 of the paid-in-kind preferred dividend on our Redeemable preferred non-controlling interests, and (3) approximately $30,107 of indebtedness on Convertible Note Payable. Additionally, the Company utilized $9,000 of availability under the revolver loan to provide for the issuance of letters of credit to support the operations of the Borrower and Guarantors. The proceeds from the facility are expected to be used to fund other general corporate purposes of the Borrower and Guarantors. The Company paid transaction fees and expenses in the amount of approximately $9,976. The Company accounted for the above debt restructuring as debt modification for the existing lenders by performing an analysis on a lender by lender basis under ASC 470-50 Debt modifications and exchanges. As a result, the Company recorded debt extinguishment of $295 representing the fees allocated to the lenders who were repaid in full as part of Loss on debt extinguishment in the consolidated statement of operations for the year ended December 31, 2023. The remaining costs have been presented as a reduction of the outstanding loan.

The Company drew down an additional $42,500 under the term loan during the year ended December 31, 2023 to fund capital expenditure on construction of our RNG projects.

The outstanding loans under the Credit Agreement initially bear interest at an annual rate of Term SOFR plus 3.5%, increasing by 0.25% per annum during the term. Accrued interest on amounts outstanding under the delayed draw term loan facility must be paid on the last day of each applicable interest period. Commencing after the 18-month delayed draw term loan availability period expires, the outstanding principal amount of the term loans amortizes at a rate of 1% per quarter and the Borrower is obligated to pay a leverage based cash sweep ranging from 25% to 100% of distributable cash of Borrower and the Guarantors, and subject to certain other mandatory prepayment requirements. The term loans and revolving loans mature on September 1, 2028.

F-30

The Borrower’s and the Guarantors’ obligations under the Credit Agreement are secured by substantially all of their personal property assets (other than certain excluded assets identified in the Credit Agreement) and by a non-recourse pledge of the membership interests of the Borrower.

The Credit Agreement requires the Borrower to maintain a consolidated debt service coverage ratio of not less than 1.2:1.0, as tested on a trailing four quarters basis as of the last day of each fiscal quarter during the term commencing with the quarter ending December 31, 2023, and to maintain a consolidated debt to cash flow ratio of not greater than 4.5 to 1.0 during the delayed draw availability period, and not greater than 4.0 to 1.0 thereafter.

The Credit Agreement includes certain customary and project-related affirmative and negative covenants, including restrictions on distributions, and events of default, which include payment defaults breaches of covenants; changes of control materially incorrect or misleading representations or warranties bankruptcy or other events of insolvency and certain project-related defaults. As of December 31, 2023, the Company is in compliance with the financial covenants under the OPAL Term Loan. Additionally, the OPAL Term Loan contains restrictions on distributions and additional indebtedness.

The Company has the ability, during the delayed draw availability period and subject to the satisfaction of certain credit and project-related conditions precedent, to join other newly acquired subsidiaries with comparable renewable projects in development under the Credit Facility for comparable funding.

As of December 31, 2023 and 2022, the outstanding loan balance (current and non-current) excluding deferred financing costs was $186,618 and $96,090, respectively.

Sunoma Loan

On August 27, 2020, Sunoma, an indirect wholly-owned subsidiary of the Company entered into a debt agreement (the "Sunoma Loan Agreement") with Live Oak Banking Company for an aggregate principal amount of $20,000. Sunoma paid $635 in financing fees. The loan bears interest at the greater of prime rate plus 3.50%, or 7.75%. The amounts outstanding under the Sunoma Loan are secured by Sunoma's assets.

The Sunoma Loan Agreement contains certain financial covenants which require Sunoma to maintain (i) a maximum debt to net worth ratio not to exceed 5:1, (ii) a minimum current ratio not less than 1.0 and (iii) a minimum debt service coverage ratio of trailing four quarters not less than 1.25. On July 19, 2022, Sunoma completed the conversion of the construction loan into a permanent loan and increased the commitment from $20,000 to $23,000.

The loans under the Sunoma Loan Agreement bear interest at a rate of 7.68% and have a maturity date of July 19, 2033. The Company is required to pay a quarterly amortization of principal of $380 beginning in October 2023.

The significant assets of Sunoma are parenthesized in the consolidated balance sheets as December 31, 2023 and 2022. See Note 12. Variable Interest Entities for additional information.

Convertible Note Payable

On May 1, 2021, the Company acquired the remaining ownership interests in Beacon and signed an unsecured, contingently convertible note (the "Convertible Note Payable") with ARCC Beacon LLC ("Ares") for a total aggregate amount for $50,000 at an interest rate of 8.00% per annum. The Company had the option to pay interest on the Convertible Note in cash on a quarterly basis or payment-in-kind. The Company chose the option of payment-in-kind interest.

Upon the consummation of the Business Combination, Ares was permitted to choose to convert the total amount outstanding under the Convertible Note to shares of Class A common stock based on a pre-determined conversion formula. Upon completion of the Business Combination in July 2022, Ares elected to convert 50% of the outstanding amount under the Convertible Note to shares of Class A common stock. The Company issued 3,059,533 shares of Class A common stock and redeemed outstanding debt of $30,595.

The Company elected to account for the Convertible Note Payable using the fair value option in accordance with ASC 820, Fair Value Measurement. The fair value was subsequently remeasured on each reporting date and the change in fair value recorded as interest expense in the consolidated statement of operations for each reporting period. The Company repaid the outstanding balance in full on September 1, 2023.

F-31

The Company recorded $1,579 and $413 as change in fair value of Convertible Note for the years ended December 31, 2023 and 2022, respectively as interest and financing expense, net.

Municipality Loan

FM3, an indirect wholly-owned subsidiary of the Company, entered into a loan agreement for the construction of an interconnection that was initially funded by the municipality. The Company made payments to a municipality in the amount of $1,600 plus interest at a fixed annual rate of 3.00% through April 1, 2023. The loan was fully repaid in April 2023.

OPAL Term Loan II

On August 4, 2022, OPAL Intermediate Holdco 2 entered into a new Senior Secured Credit Facility (the "OPAL Term Loan II") with a syndicate of lenders. The indebtedness is guaranteed by certain of the direct and indirect subsidiaries of OPAL Intermediate Holdco 2. The OPAL Term Loan II provides for an approximately two-year delayed term loan facility (the "DDTL Facility") of up to a maximum aggregate principal amount of $100,000 and debt service reserve facility (the "DSR Facility") of up to a maximum aggregate principal amount of $5,000. The proceeds of the DDTL Facility were to be used to fund a portion of the construction of the RNG projects owned, either in full or through a joint venture with a third party, by the subsidiary guarantors. The proceeds of the DSR Facility are to be used solely to satisfy the balance to be maintained in the debt service reserve account. In connection with the transaction, the Company paid $2,200 in financing fees to the lenders and incurred $1,376 in third party fees.

On May 30, 2023, OPAL Intermediate Holdco 2 assigned to Paragon its rights and obligations under OPAL Term Loan II. The joint venture partner of Paragon reimbursed the Company $826 as its portion of the transaction costs incurred.

The Company expensed the remaining deferred financing costs of $1,895 as loss on debt extinguishment in its consolidated statement of operations for the year ended December 31, 2023. There were no amounts outstanding under the OPAL Term Loan II as of May 30, 2023.

Interest rates

2023

For the year ended December 31, 2023, the weighted average effective interest rate including amortization of debt issuance costs on the Senior Secured Credit Facility was 5.1% including a margin plus SOFR. The debt was repaid in full in March 2023.

For the year ended December 31, 2023, the weighted average effective interest rate including amortization of debt issuance costs on OPAL Term Loan was 7.4%.

For the year ended December 31, 2023, the interest rate on the Sunoma Loan was 9.00%.

For the year ended December 31, 2023, the payment-in-kind interest rate on Convertible Note Payable was 8.00%. The loan was fully repaid in September 2023.

2022

For the year ended December 31, 2022, the weighted average effective interest rate on the Senior Secured Credit Facility including amortization of debt issuance costs on Senior Secured Credit Facility was 6.9% including a margin plus LIBOR.

For year ended December 31, 2022, the weighted average effective interest rate on the OPAL Term Loan including amortization of debt issuance costs was 6.1%.

For year ended December 31, 2022, the interest rate on the Sunoma loan was 8.3%, respectively.

For the year ended December 31, 2022, the payment-in-kind interest rate on Convertible Note Payable was 8.0%.

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For the year ended December 31, 2022, the weighted average interest rate on the Municipality Loan was 3.6%.

The following table summarizes the Company's total interest and financing expense, net for the year ended December 31, 2023 and 2022:


	Twelve Months Ended December 31,
	2023		2022
Senior Secured Credit Facility	$	311	$	3,779
Municipality loan	—		7
Convertible Note Payable	1,579		413
Sunoma Loan	1,803		1,810
OPAL Term Loan (1)	5,231		894
Commitment fees and other finance fees	1,491		1,027
Interest expense on finance leases	105		45
Amortization of deferred financing cost	1,720		1,943
Interest income	(2,934)		(3,278)
Total interest and financing expense, net	$	9,306	$	6,640

(1) Excludes $5,475 and $3,678 of interest capitalized and recorded as part of Property, Plant and Equipment for the years ended December 31, 2023 and 2022, respectively. Includes $953 of lenders fees expensed in relation to debt modification.

8. Leases

The following are the type of contracts that fall under ASC 842:

Lessor contracts

Fuel Provider agreements

Fuel provider agreements ("FPAs") are for the sale of brown gas, service and maintenance of sites. The Company is contracted to design and build a Fueling Station on the customer's property in exchange for the Company providing CNG/RNG to the customer for a determined number of years. These are considered to be operating leases with variable consideration. As per ASC 842, the revenue is recognized in the period earned.

Power Purchase agreements

Power purchase agreements ("PPAs") are for the sale of electricity generated at our Renewable Power facilities. All of our Renewable Power facilities operate under fixed pricing or indexed pricing based on market prices. Two of our Renewable Power facilities transfer the right to control the use of the power plant to the purchaser and are therefore classified as operating leases. The Company elected not to reassess the lease classification due to change in criteria under ASC 842 for these two PPAs. There were no amendments to these two contracts after the Adoption Date.

Included in Fuel Station Services revenues are $3,943 and $3,510 related to the lease portion of the FPAs for the years ended December 31, 2023 and 2022, respectively.

Included in Renewable Power revenues are $1,016 and $1,364 related to the lease element of the PPAs for the years ended December 31, 2023 and 2022, respectively.

Lessee contracts

Ground/Site leases

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The Company through various of its indirectly owned subsidiaries holds site leases on landfills/dairy farms to build RNG generation facilities. Typically, the lease payments over the lease term are immaterial except for three of our RNG facilities - Beacon and two sites at our Central Valley project - MS Digester ("MS") and VS Digester ("VS").

–As of the Adoption Date, the lease at Beacon facility is for 20 years at a monthly rent of $11.

–The lease term for MD and VS is for a period of 20 years from their commercial operation date at a quarterly rent of $125.

On July 5, 2023, the Company through one of its indirectly owned subsidiary entered into a site lease on a dairy farm to build a facility to collect, process and deliver feedstock to an RNG facility. The lease term is 20 years from its commercial operations date at a quarterly rent of $21,250 with a 5% escalator on the calendar quarter in which the fifth anniversary occurs and every fifth anniversary thereafter. The Company recorded $782 as right-of-use operating lease and corresponding lease liability on its consolidated balance sheet as of December 31, 2023 using an incremental borrowing rate of 8.44%.

Additionally, the Company revised the commercial operation date for its leases for MD and VS by 10 months which changed the lease term for both the leases. Beginning in the fourth quarter of 2023 the Company treated this as a lease modification and increased its right-of-use asset and corresponding lease liability by $175 on its consolidated balance sheet as of December 31, 2023, using the incremental borrowing rate of 8.35%.

On August 25, 2022, the Company entered into a site lease to own and build fueling station. The Lease provided that OPAL shall pay a rent of $1 per year and $1 per GGE of CNG produced and a royalty of $0.30 per GGE for the amount of such excess volumes sold to third party contracted customers and general public. The term of the Lease was for ten years with an option to renew up to two additional five year periods. Such renewals are to commence automatically unless either Party elects not to renew this Agreement by giving the other party written notice at least 90 days prior to the end of the term. During 2022, the Company analyzed this contact and determined that the payments were considered variable consideration as the actual volumes were unknown at the lease inception and therefore expensed as incurred.

On December 27, 2023, OPAL entered into an Amended and Restated Lease Agreement where by the only payment terms have been amended to include minimum volume requirement there by requiring OPAL to pay lease payments of $1 per GGE of CNG pumped with annual minimum volumes for the lease term.

The Company determined that the site lease is a finance lease because the present value of the sum of the lease payments is substantially greater than the fair value of the parcel of land. Therefore, the Company recorded right-of-use asset and related lease liability on December 27, 2023 of $6,469 on its consolidated balance sheet as of December 31, 2023, using the incremental borrowing rate of 6.5%.

Office lease

The Company entered into a lease for office and warehouse space that became effective upon the termination of the original lease term on January 31, 2018. The term of the lease renewal was 36 months and contained an option to renew for an additional 24 months. In September 2020, the Company exercised this option. In March, 2022, the Company entered into an amendment to the lease which extended the lease term till January 2026. The rent for the lease is $26 per month with a built in escalation to $27 from February 1, 2022 to February 1, 2023, $43 from February 1, 2023 - February 1, 2024, $45 from February 1 2024 - February 1, 2025 and $46 for the remaining lease term. The Company accounted the change in the lease term as a lease modification and reassessed the right-of-use assets and corresponding lease liabilities as of March 31, 2022.

The Company currently shares office space with Fortistar and reimburses Fortistar on a monthly basis at a predetermined rate. The Company determined that this is not a lease under ASC 842 as there is no exclusive right-of-use and the Company does not have the right to control the use of the office space.

The Company determined that the three site leases and the one office lease are operating leases.

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Under ASC 842, leases are classified as either finance or operating arrangements, with such classification affecting the pattern and classification of expense recognition in an entity's income statement. For operating leases, ASC 842 requires recognition in an entity’s income statement of a single lease expense, calculated so that the cost of the lease is allocated over the lease term, generally on a straight-line basis. Right-of-use assets represent a right to use

an underlying asset for the lease term and the related lease liability represents an obligation to make lease payments pursuant to the contractual terms of the lease agreement.

Based on the above guidance, the lease expense for the site leases is included as part of Cost of sales - RNG Fuel in its consolidated statement of operations for the years ended December 31, 2023 and 2022. The lease expense for the office lease is recorded as part Selling, general and administrative expenses in its consolidated statement of operations for the years ended December 31, 2023 and 2022.

Vehicle leases

The Company leases approximately 79 vehicles in our FM3 and OPAL Fuel Station Services subsidiaries. The leases contain repurchase options at the end of the lease term and the sum total of the lease payments represents substantially the fair value of the asset.

Under ASC 842, the Company determined that the vehicle leases are finance leases. For finance leases, ASC 842 requires recognition of amortization of right-of-use asset as part of depreciation and amortization expense and the interest on the finance lease liability as interest expense in the income statement. The Company accordingly recognized its lease expense on the vehicle leases as part of Depreciation, amortization and accretion expense and interest and financing expense, net in its statement of operations for the year ended December 31, 2023.

Lease Disclosures Under ASC 842

The objective of the disclosure requirements under ASC 842 is to enable users of an entity’s financial statements to assess the amount, timing and uncertainty of cash flows arising from lease arrangements. In addition to the supplemental qualitative leasing disclosures included above, below are quantitative disclosures that are intended to meet the stated objective of ASC 842.

Right-of-use assets and Lease liabilities as of December 31, 2023 and December 31, 2022 are as follows:

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Description	Location in Balance Sheet	December 31, 2023		December 31, 2022
Assets:
Operating leases (1):
Site leases	Right-of-use assets	$	11,330	$	10,338
Office lease	Right-of-use assets	971		1,406
		12,301		11,744
Finance leases (1):
Vehicle leases	Property, plant and equipment, net	2,580		1,236
Site leases	Property, plant and equipment, net	6,468		—
		9,048		1,236

Total right-of-use assets		$	21,349	$	12,980
Liabilities (1):
Sites leases - operating	Operating lease liabilities - current portion	$	130	$	181
Office lease - operating	Operating lease liabilities - current portion	508		449
Vehicle leases - finance	Accrued expenses and other current liabilities	827		449
Site leases - finance	Accrued expenses and other current liabilities	571		—
		2,036		1,079

Sites leases - operating	Operating lease liabilities - non-current portion	11,222		10,135
Office lease - operating	Operating lease liabilities - non-current portion	602		1,110
Vehicle leases - finance	Other long-term liabilities	1,801		825
Site leases - finance	Other long-term liabilities	5,587		—
		19,212		12,070

Total lease liabilities		$	21,248	$	13,149

(1) The Operating and Finance lease right-of-use asset and corresponding lease liabilities represent the present value of lease payments for the remaining term of the lease. The discount rate used ranged from 3.59% to 8.44%.

The table below presents components of the Company's lease expense for the year ended December 31, 2023:

Description

Location in Statement of Operations

Amount (1)

Operating lease expense for site leases

Cost of sales - RNG Fuel

1,087

Operating lease expense for office lease

Selling, general, administrative expenses

484

Amortization of right-of-use assets - finance leases

Depreciation, amortization and accretion expense

667

Interest expense on lease liabilities - finance leases

Interest and financing expense, net

105

2,343

(1) The Company does not have material short term lease expense for the year ended December 31, 2023

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Weighted average remaining lease term (years)	December 31, 2023
Operating leases	19.3 years
Financing leases	7.0 years
Weighted average discount rate
Operating leases	7.81	%
Financing leases	6.60	%

The table below provides the total amount of lease payments on an undiscounted basis on our lease contracts as of December 31, 2023:


	Site leases Operating			Office leases Operating			Vehicle leases Finance			Site leases Finance			Total

Weighted average discount rate	7.6		%	3.6		%	6.3		%	6.5		%

2024	$	1,058		$	540		$	1,044		$	963		$	3,605
2025	1,129			562			937			963			3,591
2026	1,129			47			782			963			2,921
2027	1,129			—			400			963			2,492
2028 and beyond	19,266			—			—			4,250			23,516
	23,711			1,149			3,163			8,102			36,125

Present value of lease liability	11,352			1,110			2,628			6,158			21,248

Lease liabilities - current portion	130			508			827			571			2,036
Lease liabilities - non-current portion	11,222			602			1,801			5,587			19,212
Total lease liabilities	$	11,352		$	1,110		$	2,628		$	6,158		$	21,248

Discount based on incremental borrowing rate	$	12,359		$	39		$	535		$	1,944		$	14,877

9. Derivative Financial Instruments and Fair Value Measurements

Interest rate swaps

During August 2022, the Company entered into two interest rate swaps for the notional amount of $61,926 of the OPAL Term Loan II at a fixed interest rate of 2.47% to hedge the SOFR-based floating interest rate. On August 16, 2022, the Company entered into a swaption for a notional amount of $13,074 with fixed rate of 2.32% with a maturity date of May 31, 2023. The Company accounted for the swaption as an economic hedge and included the change in the fair market value in the consolidated statement of operations.

The two interest rate swaps were designated and qualified as cash flow hedges. The Company uses interest rate swaps for the management of interest rate risk exposure, as an interest rate swap effectively converts a portion of the Company’s debt from a floating to a fixed rate. The interest rate swap is an agreement between the Company and counterparties to pay, in the future, a fixed-rate payment in exchange for the counterparties paying the Company a variable payment. The amount of the net payment obligation is based on the notional amount of the interest rate swap and the prevailing market interest

F-37

rates. The Company may terminate the interest rate swaps prior to their expiration dates, at which point a realized gain or loss may be recognized, or may be amortized over the original life of the interest rate swap if the hedged debt remains outstanding. The value of the Company’s commitment would increase or decrease based primarily on the extent to which interest rates move against the rate fixed for each swap.

The Company records the fair value of the interest rate swap as an asset or liability on its consolidated balance sheet. The effective portion of the swap is recorded in Accumulated other comprehensive income.

On May 30, 2023, OPAL Intermediate Holdco 2, assigned to Paragon its rights and obligations under the OPAL Term Loan II. Concurrently, the Company terminated the two interest rate swaps outstanding under this loan and received $812 as settlement from the swap counterparty. Paragon entered into four interest rate swaps for a notional amount of $56,914 at a fixed interest rate of 3.52%. The Company terminated the swaption on the same date.

After the transaction, the Company recognized a gain of $812 in the consolidated statement of operations for the year ended December 31, 2023 as part of Change in fair value of derivative instruments. The Company received $136 as a settlement from the swaption counterparty and recognized $46 as loss on termination of the swaption as part of change in fair value of derivative instruments. Additionally, the Company recognized $(8) as its share of the Accumulated other comprehensive loss from Paragon and decreased its basis in equity method investment on its consolidated balance sheet as of December 31, 2023.

The following table summarizes the interest rate swaps in place as of December 31, 2023 and December 31, 2022:


Interest rate swap detail					Notional Amount
Trade date	Fixed rate		Start date	End date	December 31, 2023		December 31, 2022

August 15, 2022	2.47	%	June 28, 2024	August 4, 2027	$	—	$	41,284
August 15, 2022	2.47	%	June 28, 2024	August 4, 2027	—		20,642
					$	—	$	61,926

The location and amounts of derivatives fair values in the consolidated balance sheets are:


	December 31, 2023		December 31, 2022		Location of Fair Value Recognized in Balance Sheet
Derivatives designated as economic hedges:
Current portion of swaption	$	—	$	182	Derivative financial assets, current portion

Derivatives designated as cash flow hedges:
Non current portion of the interest rate swaps	—		954		Derivative financial assets, non-current portion
	$	—	$	1,136

The effect of interest rate swaps on the consolidated statement of operations were as follows:

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	Twelve Months Ended December 31,				Location of (Loss) Gain Recognized in Operations from Derivatives
	2023		2022
Interest rate swaps	$	—	$	992
Swaption	(46)		182
Net periodic settlements - interest rate swaps (1)	1,146		(676)
	$	1,100	$	498	Change in fair value of derivative instruments, net

(1) Includes $334 reclassification into earnings from our equity method investments and $812 reclassification on the gain on termination of interest rate swaps on May 30, 2023.

The Company may be exposed to credit risk on any of the derivative financial instruments that are in an asset position. Credit risk relates to the risk of loss that the Company would incur because of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate this risk, management monitors counterparty credit exposure on an annual basis and enters into these arrangements with large financial institutions. The necessary credit adjustments have been reflected in the fair value of financial derivative instruments. There are no credit-risk-related contingent features that could be triggered in derivative financial instruments that are in a liability position.

The Company enters into interest rate swap contracts with counterparties that allow for net settlement of derivative assets and derivative liabilities. The Company has made an accounting policy election to offset recognized amounts relating to these interest swaps within the consolidated balance sheets.

The following table summarizes the fair value of interest rate swaps on the Company's consolidated balance sheets and the effect of netting arrangements and collateral on its financial position:


	Gross Amounts of Recognized Assets/(Liabilities)		Gross Amounts Offset in the Balance Sheet		Net Amounts of Assets/(Liabilities) in the Balance Sheet
Balance, December 31, 2023:
Interest rate swap asset	$	—	$	—	$	—
Swaption asset	—		—		—
	$	—	$	—	$	—
Balance, December 31, 2022:
Interest rate swap asset	$	954	$	—	$	954
Swaption asset	182		—		182
	$	1,136	$	—	$	1,136

There were no collateral balances with counterparties outstanding as of the period-end dates.

Commodity swap contracts

The Company utilizes commodity swap contracts to hedge against the unfavorable price fluctuations in market prices of electricity. The Company does not apply hedge accounting to these contracts. As such, unrealized and realized gain (loss) is recognized as a component of Renewable Power revenues in the consolidated statement of operations and Derivative financial asset — current and non-current in the consolidated balance sheets. These are considered to be Level 2 instruments in the fair value hierarchy. By using commodity swaps, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counter party to perform under the terms of the swap contract. When the fair value of the swap contract is positive, the counter party owes the Company creating a credit risk. The Company manages the credit risk by entering into contracts with financially sound counter parties. To mitigate this risk, management monitors counterparty credit exposure on an annual basis, and the necessary credit adjustments have been reflected in the fair value of financial derivative instruments. When the fair value of the swap contract is negative, the Company owes the counterparty creating a market risk that the market price is higher than the contract price resulting in the Company not participating in the opportunity to earn higher revenues.

F-39

Additionally, the Company entered into an ISDA agreement with Mendocino Capital LLC (“NextEra”), a related party in November 2019. Pursuant to the agreement, the Company entered into swaps with contract prices ranging between $35.75 and $51.25 per MWh. The swaps expired in December 2022. Upon the expiry of these swaps, the Company entered into two additional commodity swaps in October 2022 for a period of two years with contract prices ranging between $65.50 and $68.50 per MWh. The swaps are expected to be settled by physical delivery on a monthly basis. The Company elected the normal purchase normal sale exclusion and will not apply fair value accounting under ASC 815, Derivatives and hedging. The Company will continue to assess its normal purchase and normal sale election on a quarterly basis.

The Company entered into a new commodity swap with NextEra in November 2022 for a period of two years at a contract price of $81.50 per MWh.

In November 2023, the Company entered into an electricity supply agreement with a utility provider for purchase of electricity to be used at one of our RNG facilities for a period of two years with a monthly notional quantity ranging between 1,875 and 2,145 Kilo watt hour and with fixed contract price $0.0599 per Kwh. The forward contract is expected to be settled by physical delivery of electricity on a monthly basis. The Company elected the normal purchase normal sale exclusion and will not apply fair value accounting under ASC 815, Derivatives and hedging. The Company will continue to assess its normal purchase and normal sale election on a quarterly basis.

The following table summarizes the commodity swaps in place as of December 31, 2023 and December 31, 2022.

Trade Date

Period From

Period To

Notional Quantity per Year (“MWh”)

Average Contract Price (per MWh)

October 17, 2022

January 1, 2023

December 31, 2024

70,176

68.50

October 17, 2022

January 1, 2023

December 31, 2024

26,280

65.50

November 17, 2022

January 1, 2023

December 31, 2024

35,088

81.50

The following table summarizes the effect of commodity swaps on the consolidated statements of operations for the years ended December 31, 2023 and 2022:


Derivatives not designated as hedging instruments	Location of (loss) gain recognized	Twelve Months Ended December 31,
		2023		2022
Commodity swaps - realized gain (loss)	Revenues - Renewable power	$	1,839	$	(1,757)
Commodity swaps - unrealized gain (loss)	Revenues - Renewable power	763		(512)
Total realized and unrealized gain (loss)	Revenues - Renewable power	$	2,602	$	(2,269)

The following table summarizes the derivative assets and liabilities related to commodity swaps as of December 31, 2023 and December 31, 2022


	Fair Value				Location of Fair value recognized in Balance Sheet
	December 31, 2023		December 31, 2022
Derivatives designated as economic hedges
Current portion of unrealized gain on commodity swaps	$	633	$	—	Derivative financial asset, current portion
Current portion of unrealized loss on commodity swaps	—		(130)		Derivative financial liability, current portion

Other derivative liabilities

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On July 21, 2022, the Company recorded derivative liabilities for the outstanding public warrants and private warrants, put option to Meteora, the Sponsor Earnout Awards and the OPAL Earnout Awards. The private and public warrants were exchanged into Class A common stock in the four quarter of 2022. The put option with Meteora expired in January 2023. Please see Note 2. Summary of Significant Accounting Policies for additional information.The change in fair value on these derivative instruments is recorded as change in fair value of derivative instruments, net in the consolidated statement of operations for the years ended December 31, 2023 and 2022.

The following table summarizes the effect of change in fair value of other derivative liabilities on the consolidated statements of operations for the years ended December 31, 2023 and 2022:


Derivative liability	Twelve Months Ended December 31,				Location of (Loss) Gain Recognized in Operations from Derivatives
	2023		2022
Contingent liability payable to non-controlling interest	$	—	$	4,365
Put option to Meteora	(311)		134
Sponsor Earnout Awards	1,890		1,911
OPAL Earnout Awards	5,000		35,200
Public and Private Warrants	—		(9,027)
	$	6,579	$	32,583	Change in fair value of derivative instruments, net

Fair value measurements

The fair value of financial instruments, including long-term debt and derivative instruments is defined as the amount at which the instruments could be exchanged in a current transaction between willing parties. The carrying amount of cash and cash equivalents, accounts receivable, net, and accounts payable and accrued expenses approximates fair value due to their short-term maturities.

The carrying value of the Company's long-term debt of $196,542 and $88,312 as of December 31, 2023 and December 31, 2022, respectively, represents the total amount to be repaid if the debt has to be discharged in full and therefore approximates its fair value.

The Company follows ASC 820, Fair Value Measurement, regarding fair value measurements which establishes a three-tier fair value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. These tiers include:

Level 1 — defined as observable inputs such as quoted prices for identical instruments in active markets;

Level 2 — defined as quoted prices for similar instruments in active market, quoted prices for identical or similar instruments in markets that are not active, or model-derived valuations for which all significant inputs are observable market data;

Level 3 — defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of an input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The Company values its energy commodity swap contracts based on the applicable geographical market energy forward curve. The forward curves are derived based on the quotes provided by New York Mercantile Exchange, Amerex Energy Services and Tradition Energy. The Company does not consider that the pricing index used involves significant judgement on the part of management. Therefore, the Company classifies these commodity swap contracts within Level 2 of the valuation hierarchy based on the observable market rates used to determine fair value.

The Company accounts for asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which it is incurred and when a reasonable estimate of fair value can be made. The Company

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estimates the fair value of asset retirement obligations by calculating the estimated present value of the cost to retire the asset. This estimate requires assumptions and judgments regarding the existence of liabilities, the amount and timing of cash outflows required to settle the liability, inflation factors, credit adjusted discount rates, and consideration of changes in legal, regulatory, environmental, and political environments. In addition, the Company determines the Level 3 fair value measurements based on historical information and current market conditions. These assumptions represent Level 3 inputs, which can regularly change. As such, the fair value measurement of asset retirement obligations is subject to changes in these unobservable inputs as of the measurement date. The Company used a discounted cash flow model in which cash outflows estimated to retire the asset are discounted to their present value using an expected discount rate. A significant increase (decrease) in the discount rate in isolation could result in a significantly lower (higher) fair value measurement. The Company estimated the fair value of its asset retirement obligations based on discount rates ranging from 5.75% to 8.5%.

The Company accounted for the Convertible Note Payable at fair value at each reporting period. As of December 31, 2023, the Convertible Note Payable was repaid in full. As of December 31, 2022, the Company recorded the Convertible Note Payable at par plus accrued interest as it is payable on demand by either party and therefore represents fair value.

The fair value of the Sponsor Earnout Awards as of December 31, 2023 resulted in a gain of $1,890 due to decrease in stock price which was determined using a Monte Carlo valuation model with a distribution of potential outcomes on a daily basis over the five year post-close period. Assumptions used in the valuation are as follows:

•Current stock price — The Company's closing stock price of $5.52 as of December 31, 2023;

•Expected volatility —55% based on historical and implied volatilities of selected industry peers deemed to be comparable to our business corresponding to the expected term of the awards;

•Risk-free interest rate — 4.0% based on the U.S. Treasury yield curve in effect at the time of issuance for zero-coupon U.S. Treasury notes with maturities corresponding to the expected 3.5 year term of the earnout period;

•Dividend yield - zero.

The fair value of the OPAL Earnout Awards as of December 31, 2023 was determined using a Monte Carlo valuation model with a distribution of potential outcomes for stock price and EBITDA over the 2-year period commencing on January 1, 2023 and ending on December 31, 2024.

The change in fair value of the OPAL Earnout Awards for the year ended December 31, 2023 resulted in a gain of $5,000 due to decrease in the EBITDA projections over the remaining 1-year period. Assumptions used in the valuation are as follows:

•Current stock price — The Company's closing stock price of $5.52 as of December 31, 2023;

•Weighted average cost of capital - 16% based on an average of historical volatilities of selected industry peers deemed to be comparable to our business.

•Expected volatility —40% based on historical and implied volatilities of selected industry peers deemed to be comparable to our business corresponding to the expected term of the awards;

•Risk-free interest rate — 4.8% based on the U.S. Treasury yield curve in effect at the time of issuance for zero-coupon U.S. Treasury notes with maturities corresponding to the expected 1.0 year term of the earnout period;

•Dividend yield - zero.

The Company's assets and liabilities that are measured at fair value on a recurring basis include the following as of December 31, 2023 and December 31, 2022, set forth by level, within the fair value hierarchy:

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	Fair value as of December 31, 2023
	Level 1		Level 2		Level 3		Total
Liabilities:
Asset retirement obligation	$	—	$	—	$	6,728	$	6,728
Earnout liabilities	—		—		1,900		1,900
Assets:
Cash and cash equivalents and restricted cash - current and non-current (1)	47,242		—		—		47,242
Short term investments	9,875		—		—		9,875
Commodity swap contracts	—		633		—		633


	Fair value as of December 31, 2022
	Level 1		Level 2		Level 3		Total
Liabilities:
Asset retirement obligation	$	—	$	—	$	6,256	$	6,256
Convertible Note Payable	—		28,528		—		28,528
Put option with Meteora	—		—		4,466		4,466
Commodity swap contracts	—		130		—		130
Earnout liabilities	—		—		8,790		8,790
Assets:
Cash and cash equivalents and restricted cash - current and non-current (1)	77,221		—		—		77,221
Short term investments	64,976		—		—		64,976
Swaption	—		182		—		182
Interest rate swaps	—		954		—		954

(1) Includes balances in money market accounts of $31,965 and $6,769, respectively as of December 31, 2023 and 2022.

A summary of changes in the fair values of the Company’s Level 3 instruments, attributable to asset retirement obligations, for the year ended December 31, 2023 is included in Note 2. Summary of Significant Accounting Policies.

10. Related Parties

Related parties are represented by Fortistar and other affiliates, subsidiaries and entities under common control with Fortistar or NextEra.

Sale of non-controlling interests to Related Parties

On November 29, 2021, as part of an exchange agreement, OPAL Fuels issued 14 newly authorized common units and 300,000 Series A-1 preferred units to Hillman in return for Hillman’s non-controlling interest in four RNG project subsidiaries for total consideration of $30,000. Upon the consummation of the Business Combination, the Series A-1 preferred units have been converted to Redeemable preferred non-controlling interests. The Company recorded preferred dividend of $2,590 and $2,526 for the years ended December 31, 2023 and 2022, respectively. Please see Note 13. Redeemable non-controlling interests, Redeemable preferred non-controlling interests and Stockholders' Equity, for additional information. As of December 31, 2023 and 2022, there was accrued preferred dividend payable of $604 and $2,526, respectively.

Issuance of Redeemable preferred non-controlling interests

On November 29, 2021, NextEra subscribed for up to 1,000,000 Series A preferred units, which are issuable (in whole or in increments) at the Company’s discretion prior to June 30, 2022. During the year ended December 31, 2022, the

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Company had drawn $100,000 and issued 1,000,000 Series A preferred units. The Company recorded paid-in-kind preferred dividend of $8,421 and $5,406 for the years ended December 31, 2023 and 2022 respectively. As of December 31, 2023 and 2022, there was accrued preferred dividend payable of $2,013 and $5,406, respectively. Please see Note 13. Redeemable non-controlling interests, Redeemable preferred non-controlling interests and Stockholders' Equity, for additional information.

Purchase and sale agreement for environmental attributes

On November 29, 2021, the Company entered into a purchase and sale agreement with NextEra for the environmental attributes generated by the RNG Fuels business. Under this agreement, the Company plans to sell a minimum of 90% of the environmental attributes generated and will receive net proceeds based on the agreed upon price less a specified discount. A specified volume of environmental attributes sold per quarter will incur a fee per environmental attribute in addition to the specified discount. The agreement was effective beginning January 1, 2022. For the years ended December 31, 2023 and 2022, the Company earned net revenues after discount and fees of $84,537 and $76,920, respectively under this contract which was recorded as part of Revenues - RNG fuel and Fuel Station Services. Please see Note 2. Summary of Significant Accounting Policies for additional information.

Commodity swap contracts under ISDA and REC sales contracts

The Company entered into an ISDA agreement with NextEra in November 2019. Pursuant to the agreement, the Company entered into commodity swap contracts on a periodic basis. As of December 31, 2023 and 2022, there were three commodity swap contracts outstanding. The Company records the realized and unrealized gain (loss) on these commodity swap contracts as part of Revenues - Renewable Power. Please see Note 9. Derivative Instruments and Fair Value Measurements for additional information. Additionally, the Company has contracts to sell RECs and capacity to NextEra on multiple Renewable Power facilities at market price. The Company recorded $6,614 and $5,495 as revenues earned under these contracts.

Purchase of investments from Related Parties

In August 2021, the Company acquired a 100% of the ownership interests in Reynolds, an RNG production facility for $12,020 which was funded with cash on hand. Reynolds held an equity investment of 1,570 Class B units in GREP representing 20% interest for a cash consideration of $1,570 which owns 50% of Biotown, a power generation facility under development to convert to an RNG facility. The Reynolds transaction was an asset acquisition from an affiliate under common control. The Company accounts for its 20% equity investment in GREP under the equity method. The Company recorded $(1,212) and $2,302 as its share of net (loss) income for the years ended December 31, 2023 and 2022.

Sales contracts with Related Parties

The Company's wholly owned subsidiary, OPAL Fuel Station Services contracted with Pine Bend in December 2020, Noble Road in March 2021, Emerald in December 2021 to provide the same services. Additionally, OPAL Fuel Station Services provides the same services to all wholly-owned subsidiaries of the Company. The revenues earned from these entities are fully eliminated in the consolidated financial statements.

The term of this contract runs for a term of 10 years. The Company receives non-cash consideration in the form of RINs or LCFSs for providing these services and recognizes the RINs or LCFSs received as inventory based on their estimated fair value at contract inception. The Pine Bend and Noble Road came online in the first and third quarter of 2022 and Emerald in the third quarter of 2023. For the years ended December 31, 2023 and 2022, the Company earned environmental processing fees of $2,615 and $709, net of inter segment elimination under this agreement which are included in Fuel Station Services revenues in the consolidated statements of operations.

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Service agreements with Related Parties

On December 31, 2020, OPAL Fuels signed a management, operations, and maintenance services agreement (“Administrative Services Agreement”) with a subsidiary of Fortistar, pursuant to which Fortistar provides management, operations, and maintenance services to the Company. The agreement expires on December 31, 2023 with an auto renewal option on an annual basis, unless either party chooses to terminate with a written notice of 180 days termination occurs earlier due to dissolution of the Company or the agreement is terminated by the Company’s secured lenders in certain circumstances. The agreement provides for payment of service fees based on actual time incurred at contractually agreed rates provided for in the Administrative Services Agreement, as well as a fixed annual payment of $580 per year adjusted annually for inflation. Additionally, the agreement provides for the Company to receive credits for any services provided by the Company's employees to Fortistar. For the year ended December 31, 2023 and 2022, there have been no material services provided by the Company's employees to Fortistar.

In June 2021, the company entered into a management services agreement with Costar Partners LLC (“Costar”), an affiliate of Fortistar. Pursuant to the agreement, Costar provides information technology (“IT”) support services, software use, licensing services, management of third party infrastructure and security services and additional IT services as needed by the Company. The agreement provides for Costar to be compensated based on actual costs incurred and licensing fees per user for certain software applications. The agreement expires in June 2024 unless the termination occurs earlier due to dissolution of the Company or it is terminated by the Company’s secured lenders in certain circumstances.

On October 5, 2023, Ms.Ann Anthony gave notice of her intention to resign as Chief Financial Officer ("CFO") of the Company. On October 10, 2023, the board of directors of the Company appointed Mr.Scott Contino as Interim CFO. Mr.Contino has served as Fortistar's CFO for the past eighteen years. In connection with the appointment, the Company entered into an interim services agreement ("Interim Services Agreement") with Fortistar in accordance with the terms and conditions of the existing Administrative Services Agreement. Pursuant to the Interim Services Agreement, the Company will pay Fortistar an agreed hourly rate, such that the monthly fee does not exceed $50,000, on a cumulative basis. For the year ended December 31, 2023, the Company paid $128 which is included in Selling, general and administrative expenses in the consolidated statement of operations.

The following table summarizes the various fees recorded under the agreements described above which are included in "Selling, general, and administrative" expenses:


	Twelve Months Ended December 31,
	2023		2022
Staffing and management services	$	1,834	$	2,154
Rent - fixed compensation	668		604
IT services	2,954		2,205
Total	$	5,456	$	4,963

The following table presents the various balances for related parties included in our consolidated balance sheets as of December 31, 2023 and 2022.

F-45


		December 31,
	Location in Balance Sheet	2023		2022
Assets:
Trade AR - NextEra	Accounts receivable, related party	18,696		12,421
Liabilities:
Payables to equity method investment entities	Accounts payable, related party	5,692		5,030
NextEra	Accounts payable, related party	501		501
Staffing and management services - Fortistar	Accounts payable, related party	622		677
IT services - Costar	Accounts payable, related party	209		168
Total liabilities - related party		$	7,024	$	6,376

11. Reportable Segments and Geographic Information

The Company is organized into four operating segments based on the characteristics of its renewable power generation, dispensing portfolio, and the nature of other products and services. During the first quarter of 2023, the Company changed its internal reporting to its Chief Operating Decision Makers to change the composition of revenues included in our reportable segments. The internal reporting was changed to provide more visibility into our RNG fuel production and operations and to align fuel dispensing revenues with construction and service of fuel dispensing stations. Additionally, the Company changed its internal reporting to report revenues from RECs and ISCC Carbon Credits from RNG Fuel to Renewable Power segment during the third quarter of 2023. This is primarily to reflect a strategic business change to identify all revenues earned from environmental attributes generated from Renewable Power facilities in the same segment.

Therefore, the Company reclassified the revenues and the corresponding cost of sales for CNG tolling business which were previously presented as part of Revenues - RNG Fuel and Cost of sales - RNG Fuel to Revenues - Fuel station services and Cost of sales - Fuel station services, respectively. The Company reclassified revenues earned from sale of RECs and ISCC Carbon Credits from Revenues - RNG Fuel to Revenues - Renewable Power. The Company also adjusted the revenues and cost of sales for the prior year period presented for comparison purposes.

For the years ended December 31, 2023 and 2022, the Company classified revenues from fuel dispensing business of $64,504 and $48,175, respectively, as part of Revenues - Fuel station services.

For the years ended December 31, 2023 and 2022, the Company classified revenues from the sale of environmental attributes generated from Renewable Power facilities of $20,124 and $5,498, respectively, as part of Revenues - Renewable Power.

For the years ended December 31, 2023 and 2022, the Company classified cost of sales related to the fuel dispensing business of $51,032 and $37,331, respectively as part of Cost of sales - Fuel station services.

We aligned our reportable segments disclosure to align with the information and internal reporting that is provided to our Chief Operating Decision Makers. Therefore, the Company reassessed its reportable segments and revised all the prior periods to make the segment disclosures comparable.

•RNG Fuel. The RNG Fuel segment relates to all RNG supply directly related to the generation and sale of brown gas and environmental credits, and consists of:

◦Development and construction – RNG facilities in which long term gas right contracts have been, or are in the process of being ratified and the construction of RNG generation facilities.

◦RNG supply operating facilities – This includes the generation, extraction, and sale of RNG - plus associated RINs and LCFSs from landfills.

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For the year ended December 31, 2023 and 2022, the Company has accounted for its interests in Pine Bend, Reynolds Noble Road, GREP, Paragon and SJI under the equity method of accounting and the results of operations of Beacon, New River, Polk County, Cottonwood, Central Valley, Prince William and Sunoma were consolidated in its consolidated statement of operations. As of May 30, 2023, the Company deconsolidated Emerald and Sapphire. As a result, the Company consolidated Emerald and Sapphire for the period between January 1, 2023 and May 30, 2023 and recorded its ownership interests in Paragon which includes Emerald and Sapphire as equity method investment for the period between May 30, 2023 and December 31, 2023.

As of December 31, 2023, Central Valley, Prince William, Polk County, Cottonwood and Sapphire are not operational. Sunoma became operational in December 2021, Noble Road in January 2022, New River in April 2022 and Pine Bend in September 2022. Emerald began commercial operations in the third quarter of 2023.

•Fuel Station Services. Through its Fuel Station Services segment, the Company provides construction and maintenance services to third-party owners of vehicle Fueling Stations and performs fuel dispensing activities including generation and minting of environmental credits. This segment includes:

◦Service and maintenance contracts for RNG/CNG fueling sites and a manufacturing division that builds Compact Fueling Systems and Defueling systems.

◦Third Party CNG Construction of Fueling Stations - design/build and serve as general contractor for typically Guarantee Maximum Price or fixed priced contracts for customers usually lasting less than one year.

◦RNG and CNG fuel dispensing stations for vehicle fleets - This includes both the dispensing and sale of brown gas and the environmental credit generation and monetization. The Company operates Fueling Stations that dispense gas for vehicles. This also includes the development and construction of these facilities.

•Renewable Power Portfolio. The Renewable Power portfolio segment generates renewable power and associated environmental credits through methane-rich landfills which is then sold to public utilities throughout the United States. The Renewable Power portfolio operates primarily in Southern California.

•Corporate. This segment consists of activities managed and maintained at the Company corporate level primarily including but not limited to:

◦Executive, accounting, finance, sales activities such as: payroll, stock compensation expense, travel and other related costs.

◦Insurance, professional fees (audit, tax, legal etc.).

The Company has determined that each of the four operating segments meets the characteristics of a reportable segment under U.S. GAAP. The Company's activities and assets that are not associated with the four reportable segments are summarized in the "Other" category below. These include corporate investment income, interest income and interest expense, income tax expense, and other non-allocated costs.


	Twelve Months Ended December 31,
	2023		2022
Revenues:
Renewable Power	$	54,804	$	47,210
RNG Fuel	115,526		141,903
Fuel Station Services	149,408		117,735
Other (1)	840		131
Intersegment	(14,396)		(13,435)
Equity Method Investment(s)	(50,074)		(58,013)
	$	256,108	$	235,531

____________

(1) Other includes revenues of management fee revenues earned from operations and management of unconsolidated entities and Fortistar Contracting LLC.

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	Twelve Months Ended December 31,
	2023		2022
Interest and Financing Expense, Net:
Renewable Power	$	(280)	$	(5,261)
RNG Fuel	(9,324)		(899)
Fuel Station Services	134		—
Corporate	(192)		(480)
Equity Method Investment(s)	356		—
	$	(9,306)	$	(6,640)


	Twelve Months Ended December 31,
	2023		2022
Depreciation, Amortization, and Accretion:
Renewable Power	$	5,567	$	5,696
RNG Fuel	7,770		8,542
Fuel Station Services	3,730		846
Other(1)	—		125
Equity Method Investment(s)	(2,502)		(2,073)
	$	14,565	$	13,136

(1)Other includes amortization of intangible assets and depreciation expense not allocated to any segment.


	Twelve Months Ended December 31,
	2023		2022
Net income (loss):
Renewable Power	$	12,472	$	4,681
RNG Fuel	16,678		26,330
Fuel Station Services	17,908		18,245
Corporate	74,441		(22,461)
Equity Method Investment(s)	5,525		5,784
	$	127,024	$	32,579


	Twelve Months Ended December 31,
	2023		2022
Cash paid for Purchases of Property, Plant, and Equipment:
Renewable Power	$	—	$	2,001
Fuel Station Services	17,182		7,565
RNG Fuel	96,692		121,844
	$	113,874	$	131,410

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	December 31, 2023		December 31, 2022
Total Assets:
Renewable Power	$	37,479	$	43,468
RNG Fuel	342,176		376,933
Fuel Station Services	152,625		90,486
Corporate and other	15,230		82,204
Equity Method Investment(s)	207,099		51,765
	$	754,609	$	644,856

Geographic Information: The Company's assets and revenue generating activities are domiciled in the United States.

12. Variable Interest Entities

We determine whether we are the primary beneficiary of a VIE upon our initial involvement with the VIE and we reassess whether we are the primary beneficiary of a VIE on an ongoing basis. Our determination of whether we are the primary beneficiary of a VIE is based upon the facts and circumstances for each VIE and requires judgment. Our considerations in determining the VIE's most significant activities and whether we have power to direct those activities include, but are not limited to, the VIE's purpose and design and the risks passed through to investors, the voting interests of the VIE, management, service and/or other agreements of the VIE, involvement in the VIE's initial design, and the existence of explicit or implicit financial guarantees. If we are the party with the power over the most significant activities, we meet the "power" criteria of the primary beneficiary. If we do not have the power over the most significant activities or we determine that all significant decisions require consent of a third party, we do not meet the "power" criteria of the primary beneficiary.

We assess our variable interests in a VIE both individually and in aggregate to determine whether we have an obligation to absorb losses of or a right to receive benefits from the VIE that could potentially be significant to the VIE. The determination of whether our variable interest is significant to the VIE requires judgment. In determining the significance of our variable interest, we consider the terms, characteristics and size of the variable interests, the design and characteristics of the VIE, our involvement in the VIE, and our market-making activities related to the variable interests.

As of December 31, 2023, the Company held equity interests in seven VIEs — Sunoma, GREP, Emerald, Sapphire, Paragon, SJI Joint Venture (RNG Atlantic and RNG Burlington) and Central Valley. On May 30, 2023, the Company together with a third-party environmental solutions company formed Paragon. The Company owns 50% of ownership interest in Paragon. Concurrent with the formation of Paragon, the Company contributed its 50% ownership interests in Emerald and Sapphire to Paragon.

Upon the execution of the above the transaction, the Company reassessed its equity interests in Emerald and Sapphire under ASC 810, Consolidation and determined that the Company does not have a controlling financial interest in Paragon under ASC 810 because the governance of the joint venture is driven by an independent board jointly controlled by the joint venture partner and OPAL equally and there are substantive participating rights held by the joint venture partner in the significant activities of Paragon.

Prior to May 30, 2023, the Company consolidated these two entities in accordance with the variable interest entity model guidance under ASC 810, Consolidation.

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Venture under ASC 810 because the governance of the joint venture is driven by a board jointly controlled by the joint venture partner and OPAL equally and there are substantive participating rights held by the joint venture partner in the significant activities of SJI Joint Venture. As of December 31, 2023, the Company contributed $2,115 towards RNG Atlantic.

As of December 31, 2023, GREP, Paragon and SJI were presented as equity method investments and the remaining two VIEs Sunoma and Central Valley are consolidated by the Company.

At December 31, 2022, GREP has been presented as an equity method investment and the remaining four VIEs Sunoma, Emerald, Sapphire, and Central Valley are consolidated by the Company.

In 2020, the Company acquired a variable interest in Sunoma in a joint venture with a third-party who does not have any equity at risk but participates in proportionate share of income or losses, which may be significant. Additionally, the assets in Sunoma are collateralized under the Sunoma loan, the proceeds of which are used for partial financing of the construction of the Sunoma facility. Therefore, the significant assets and liabilities of Sunoma are parenthesized in the consolidated balance sheets as of December 31, 2023 and 2022.

The Company determined that each of these entities are VIEs and in its capacity as a managing member except for Emerald and Sapphire, the Company is the primary beneficiary. The Company is deemed as a primary beneficiary based on two conditions:

•The Company, as a managing member, has the power to order the activities that significantly impact the economic performance of the two entities including establishment of strategic, operating, and capital decisions for each of these entities; and

•The Company has the obligation to absorb the potential losses for the right to receive potential benefits, which could be significant to the VIE;

As a primary beneficiary, the Company consolidates these entities in accordance with the variable interest entity model guidance under ASC 810, Consolidation.

Our variable interests in each of our VIEs arise primarily from our ownership of membership interests, construction commitments, our provision of operating and maintenance services, and our provision of environmental credit processing services to VIEs.

The following table summarizes the major consolidated balance sheet items for consolidated VIEs as of December 31, 2023 and 2022. The information below is presented on an aggregate basis based on similar risk and reward characteristics and the nature of our involvement with the VIEs, such as:

•All of the VIEs are RNG facilities and they are reported under the RNG Fuel Supply segment;

•The nature of our interest in these entities is primarily equity based and therefore carry similar risk and reward characteristics;

The amount of assets that can only be used to settle obligations of the VIEs are parenthesized in the consolidated balance sheets and are included in the asset totals listed in the table below.

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	As of December 31, 2023		As of December 31, 2022
Assets
Current assets:
Cash and cash equivalents	$	166	$	12,506
Accounts receivable, net	33		966
Restricted cash - current	4,395		6,971
Environmental credits held for sale	29		—
Prepaid expenses and other current assets	107		415
Total current assets	4,730		20,858
Property, plant and equipment, net	26,626		73,140
Restricted cash, non-current	1,850		2,923
Total assets	$	33,206	$	96,921

Liabilities and equity
Current liabilities:
Accounts payable	$	744	$	4,896
Accounts payable, related party	1,046		433
Accrued expenses	647		646
Accrued capital expenses	—		7,821
Other current liabilities	92		—
Sunoma Loan- current portion	1,608		380
Total current liabilities	4,137		14,176
Sunoma loan, net of debt issuance costs	20,010		21,712
Other long-term liabilities	211		—
Total liabilities	24,358		35,888
Equity
Stockholders' equity	7,893		34,588
Non-redeemable non-controlling interests	955		26,445
Total equity	8,848		61,033
Total Liabilities and Equity	$	33,206	$	96,921

13. Redeemable non-controlling interests, Redeemable preferred non-controlling interests and Stockholders' Equity

Common stock

As of December 31, 2023, there are (i) 29,701,146 shares of Class A common stock issued and outstanding, (ii) 144,399,037 shares of New OPAL Class D common stock issued and outstanding, (iii) no shares of Class B common stock, par value $0.0001 per share, of (“Class B common stock”) issued and outstanding (shares of Class B common stock do not have any economic value except voting rights as described below) and (iv) no shares of Class C common stock, par value $0.0001 per share, (“ Class C common stock”) issued and outstanding (shares of Class D common stock do not have any economic value except voting rights as described below).

During the first quarter of 2023, Meteora exercised the put option pursuant to the terms of the Forward Purchase Contract. The Company repurchased 1,635,783 shares at a price of $10.02 per share. The Company recorded $11,614 representing the fair value of the treasury stock as part of stockholders' deficit and $4,777 as an offset to the derivative financial liability, current on its consolidated balance sheet as of December 31, 2023.

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In March 2023, the Company issued 49,633 shares to certain warrant holders as consideration for their prior agreement to tender all warrants held by the warrant holders in the Company's voluntary exchange offer which closed on December 22, 2022. The Company recorded $338 representing the fair value of the shares issued based on the closing price on March 30, 2023 as part of Loss on warrant exchange on its consolidated statement of operations for the year ended December 31, 2023.

ATM Program

On November 17, 2023, OPAL Fuels Inc. (the “Company”) entered into an At Market Issuance Sales Agreement (the “ATM Program”) with B. Riley Securities, Inc., Cantor Fitzgerald & Co. and Stifel, Nicolaus & Company, Incorporated (each, an “Agent,” and collectively, the “Agents”) pursuant to which the Company may issue and sell shares of its Class A common stock having an aggregate offering price of up to $75 million from time to time through the Agents. Pursuant to the terms and conditions of the agreement, the Agents will use commercially reasonable efforts consistent with their normal trading and sales practices and applicable state and federal laws, rules and regulations to sell the Company’s Class A common stock from time to time, based upon the Company’s instructions (including any price, time or size limits or other customary parameters or conditions the Company imposes). The Company is not obligated to make any sales of common stock under the Sales Agreement.

Unless earlier terminated as provided below, the Sales Agreement will automatically terminate upon the issuance and sale of all of the Class A common stock subject to the Sales Agreement. The Sales Agreement may also be terminated by the Company or the Agents at any time upon two days’ notice to the other party, or by the Agents at any time in certain circumstances, including the occurrence of a material adverse change in the Company.The Company will pay each Agent, upon the sale by such Agent of Class A common stock pursuant to the Sales Agreement, an amount equal to up to 3.0% of the gross proceeds of each such sale of Class A common stock. The Company has also provided the Agents with customary indemnification rights.

Under the ATM Program, the Company issued 90,103 shares of Class A common stock in December 2023 at prices ranging between $5.52 and $5.85 and received net proceeds of $366.

Redeemable preferred non-controlling interests

On November 29, 2021, as part of an Exchange Agreement, the Company issued 300,000 Series A-1 preferred units to Hillman in return for Hillman’s non-controlling interest in four RNG project subsidiaries.

Upon completion of the Business Combination, the Company assumed Series A-1 preferred units and Series A preferred units which were issued and outstanding by OPAL Fuels. The Company recorded the Series A-1 preferred units and Series A preferred units as Redeemable preferred non-controlling interests. The Company has elected to adjust the carrying value of the preferred units to the redemption value at the end of each reporting period by immediately amortizing the issuance costs in the first reporting period after issuance of the preferred units.

During the third quarter of 2023, the Company repaid all outstanding paid-in-kind preferred dividends at that time.

The following table summarizes the changes in the redeemable preferred non-controlling interests which represent Series A and Series A-1 preferred units outstanding at OPAL Fuels level from December 31, 2022 to December 31, 2023:

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	Series A-1 preferred units			Series A preferred units			Total
	Units	Amount		Units	Amount
Balance, December 31, 2022	300,000	$	32,736	1,000,000	$	105,406	$	138,142
Paid-in-kind dividends attributable to OPAL Fuels	—	2,168		—	7,051		9,219
Paid-in kind dividends attributable to Class A common stockholders	—	422		—	1,370		1,792
Repayment of paid-in-kind preferred dividends	—	(4,722)		—	(11,814)		(16,536)
Balance, December 31, 2023	300,000	$	30,604	1,000,000	$	102,013	$	132,617

Terms of Redeemable Preferred Units

The Series A and Series A-1 preferred units (together the “Preferred Units”) are subject to substantially the same terms and features which are listed below:

Voting: The Series A-1 preferred units to Hillman do not have any voting rights. The Series A preferred units issued to NextEra have limited rights to prevent the Company from taking certain actions including (i) major issuances of new debt or equity (ii) executing transactions with affiliates which are not at arm-length basis (iii) major dispositions of assets and (iv) major acquisitions of assets outside of the Company’s primary business.

Dividends: The Preferred Units are entitled to receive dividends at the rate of 8% per annum. Dividends begin accruing for each unit from the date of issuance and are payable each quarter end regardless of whether they are declared. The dividends are mandatory and cumulative. The Company is allowed to elect to issue additional Preferred Units (paid-in-kind) in lieu of cash for the first eight dividend payment dates. The Company elected to pay the dividends to be paid-in-kind for all periods presented. The annual dividend rate increases to 12% if certain events of defaults occur. Additionally, the dividend rate increases by 2% for each unrelated uncured event of default up to a maximum of 20%.

Liquidation preference: In the event of liquidation of the Company, each holder of Series A units and Series A-1 units is entitled to be paid on pro-rata basis the original issue price of $100 per unit plus any accrued and unpaid dividends out of the assets of the Company available for distribution after payment of the Company’s debt and liabilities and liquidation expenses.

Redemption: Any time after issuance, the Company may redeem the Redeemable preferred units for a price equal to original issue price of $100 per unit plus any accrued and unpaid dividends. Holders of the Preferred Units may redeem for an amount equal to original issue price of $100 per unit plus any accrued and unpaid dividends (i) upon the occurrence of certain change in control event (ii) at the end of four years from the date of issuance, except that the Preferred Units issued to Hillman can only be redeemed 30 days after the fourth year anniversary of the first issuance of Preferred Units to NextEra. The maturity date is determined to be the date at which the Holder’s redemption option becomes exercisable as this is the date on which both the Company and the Holder may redeem the Preferred Units. The maturity date may be as early as November 29, 2025 but shall not occur later than June 30, 2026.

Conversion: Holders may elect to convert Preferred Units into common units in the event that the Company fails to redeem the Preferred Units under an optional redemption. The annual dividend rate shall increase to 12% and will further increase to 14% after one year, and thereafter by 2% every 90 days up to a maximum of 20%. The Company must also redeem all NextEra Series A preferred units on which the redemption option has been exercised prior to redeeming any Hillman Series A-1 preferred units. If elected, the Holder may convert all or a portion of its Preferred Units into a number of common units equal to the number of Preferred Units, multiplied by $100, plus accrued and unpaid cash dividends, divided by the conversion price. The conversion price is equal to the value of the Company’s common units determined as follows, and reduced by (i) a 20% discount if conversion occurs during the first year of delayed redemption, (ii) a 25% discount during the 2nd year, and (iii) a 30% discount thereafter:

1. Using 20-day volume-weighted average price (“VWAP”) of the Company's common shares.

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2. Otherwise the estimated proceeds to be received by the Holder of a common unit if the net assets of the Company were sold at fair market value and distributed.

Redeemable non-controlling interests

Upon consummation of the Business Combination, OPAL Fuels and its members caused the existing Limited Liability Company Agreement to be amended and restated. In connection therewith, all of the common units of OPAL Fuels issued and outstanding immediately prior to the Business Combination were re-classified into 144,399,037 Class B Units. Each Class B Unit is paired with a single non-economic share of Class D common stock issued by the Company. Each pair of Class B Unit and a single share of Class D common stock is exchangeable to either a single share of Class A common stock or a single share of Class C common stock at the holder's option. Upon an exchange for Class A common stock, the Company has the option to redeem shares for cash at their market value.

Redeemable non-controlling interests have been presented as mezzanine equity in the consolidated statements of change in Redeemable non-controlling interests, Redeemable preferred non-controlling interests and stockholders' (deficit) equity. At each balance sheet date, the Redeemable non-controlling interests are adjusted up to their redemption value if necessary, with an offset in Stockholders' equity. As of December 31, 2023, the Company recorded $(312,396) to adjust the carrying value to their redemption value based on a five-day VWAP of $5.56 per share.

14. Net Income Per Share

The basic income per share of Class A common stock is computed by dividing the net income attributable to Class A common stockholders by the weighted average number of Class A common stock outstanding during the period. The basic income per share for year ended December 31, 2023 does not include 1,635,783 shares in treasury, 763,908 shares issued and outstanding but are contingent on achieving earnout targets. In the first quarter of 2023, the put option was exercised and 197,258 shares of Class A common stock were cancelled.

The diluted income per share of Class A common stock for the year ended December 31, 2023 does not include Redeemable preferred non-controlling interests because the substantive contingency for conversion has not been met as of December 31, 2023. It does not include 144,399,037 OPAL Fuels Class B units representing Redeemable non-controlling interest as its impact is anti-dilutive. It does not include 716,650 Sponsor Earnout Awards and 10,000,000 OPAL Earnout Awards as their target share price and adjusted EBITDA contingencies have not been met as of December 31, 2023. The outstanding stock options issued under the 2022 Plan are not included as their impact is antidilutive. The outstanding performance units under the 2022 Plan are not included as the performance conditions have not been met as of December 31, 2023.

The Class D common stock does not participate in the earnings or losses of the Company and are therefore not participating securities. As such, separate presentation of basic and diluted earnings per share of Class D common stock under the two-class method has not been presented.

The following table summarizes the calculation of basic and diluted net loss per share:

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	Twelve Months Ended December 31,
	2023		2022
Net loss attributable to Class A common stockholders	$	18,936	$	3,391
Less:change in fair value of the put option on the forward purchase agreement	—		(134)
Diluted Net loss attributable to Class A common stockholders	18,936		3,257

Weighted average number of shares of Class A common stock - basic	27,148,538		25,774,312
Effect of dilutive Restricted Stock Units	345,478		14,203
Effect of the dilutive put option on the forward purchase agreement	—		273,883
Weighted average number of shares of Class A common stock - diluted	27,494,016		26,062,398
Net loss per share of Class A common stock
Basic	$	0.70	$	0.13
Diluted	$	0.69	$	0.12

15. Income Taxes

As a result of the Company’s up-C structure effective with the Business Combinations, the Company expects to be a tax-paying entity. However, as the Company has historically been loss-making, any deferred tax assets created as a result of net operating losses and other deferred tax assets for the excess of tax basis in the Company's investment in Opal Fuels would be offset by a full valuation allowance. Prior to the Business Combination, OPAL Fuels was organized as a limited liability company, with the exception of one partially-owned subsidiary which filed income tax returns as a C-Corporation. The Company accounts for its income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the enactment date. Judgment is required in determining the provisions for income and other taxes and related accruals, and deferred tax assets and liabilities. In the ordinary course of business, there are transactions and calculations where the ultimate tax outcome is uncertain. Our federal and state income tax returns are subject to examination by federal and state tax authorities. Our 2022 and 2023 tax years remain open for all purposes of examination by the IRS and the state tax authorities. We do not anticipate that the outcome of any federal or state audit will have a significant impact on our financial position or results of operations.

For the years ended December 31, 2023 and 2022, the Company recognized federal and state income tax expense of $0 and $0, respectively.

The effective tax rate was 0% for the years ended December 31, 2023 and 2022. The difference between the Company's effective tax rate for the year ended December 31, 2023, and the U.S. statutory tax rate of 21% was primarily due to a full valuation allowance recorded on the Company's net U.S. and State deferred tax assets, income (loss) from pass-through entities not attributable to Class A common stock and state and local taxes.

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	Twelve Months Ended December 31,
	2023		2022
Expected income tax at statutory rate	$	26,639	$	6,884

State income taxes, net of federal	—		184
Gain on deconsolidation of entities	(25,803)		—
Earnings attributable to non-controlling interest	(1,063)		(6,172)
Change in valuation allowance	140		(896)
Other	87		—
Total tax expense - continuing operations	$	—	$	—

The components of the deferred tax assets and liabilities are as follows:


	Twelve Months Ended December 31,
	2023		2022
Deferred tax assets:
Investment in partnership	$	25,133	$	26,637
163j interest limitation	608		109
Federal NOL carryforward	1,165		3,094
State NOL carryforward	785		677
Total deferred tax assets	27,691		30,517

Valuation allowance for deferred tax assets	(27,691)		(30,517)
Deferred tax assets, net of valuation allowance	—		—
Deferred tax liabilities:
Total deferred tax liabilities	—		—
Net deferred income tax asset or liability	$	—	$	—

As of December 31, 2023, the Company is in a net deferred tax asset position. Based on all available positive and negative evidence, including projections of future taxable income, the Company believes it is more likely than not that the deferred tax assets will not be realized. As such, a full valuation allowance was recorded against the net deferred tax asset position for federal and state purposes as of December 31, 2023. For purposes of determining pre-tax income/(loss) for the pre Business Combination period, the Company relied on the historical financial statements of Opal Fuels, LLC as this is the best information to represent the historic pre-tax income/(loss) of Opal Fuels Inc. The Company is not forecasting significant ordinary income or capital gain to realize the Company's deferred tax assets. Should future results of operations demonstrate a trend of profitability, additional weight may be placed upon other evidence, such as forecasts of future taxable income. Additionally, future events and new evidence, such as the integration and realization of profit from recently acquired assets, could lead to increased weight being placed upon future forecasts and the conclusion that some or all of the deferred tax assets are more likely than not to be realizable. Therefore, the Company believes that there is a possibility that some or all of the valuation allowance could be released in the foreseeable future.

16. Stock-based Compensation

2022 Omnibus Equity Incentive Plan

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The Company adopted 2022 Omnibus Equity Incentive Plan (the "2022 Plan") in 2022 which was approved by our shareholders on July 21, 2022. The purposes of the 2022 Plan are to (i) provide an additional incentive to selected employees, directors, and independent contractors of the Company or its Affiliates whose contributions are essential to the growth and success of the Company, (ii) strengthen the commitment of such individuals to the Company and its Affiliates, (iii) motivate those individuals to faithfully and diligently perform their responsibilities and (iv) attract and retain competent and dedicated individuals whose efforts will result in the long-term growth and profitability of the Company. The 2022 Plan allows for granting of stock options, stock appreciation rights, restricted stock, restricted stock units and other stock-based awards. The Company registered 19,811,726 shares of Class A common stock that can be issued under this Plan.

On March 31, 2023, the Company issued 196,961 stock options, 888,831 restricted stock units and 274,617 performance units to certain employees of the Company. The fair value of the stock options was determined to be $5.26 based on Black Scholes model based on the share price of $6.97, exercise price of $6.97, expiration of 10 years, annual risk free interest rate of 4.04% and volatility of 65%. The performance units were contingent upon Company achieving certain Adjusted EBITDA and production targets. The grant date fair value of these awards was estimated using the closing share price of the Company's stock on the date of the grant and the compensation cost related to these awards is recognized based on the relative satisfaction of the performance condition as of the reporting date. Additionally, the Company issued 135,583 restricted stock units to the board of directors. The total fair value of the equity awards was $6,955.

A summary of the equity awards under the 2022 Plan for the year ended December 31, 2023 is as follows:

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	Restricted stock units	Weighted average fair value per restricted unit on grant date		Aggregate fair value		Vesting terms
Restricted Stock Units:
Unvested restricted stock units outstanding as of December 31, 2022	422,349	$	7.94			100% vesting on October 3, 2023
Granted in March 2023	1,024,414	6.97				Three equal installments vesting over 3 years
Granted in June 2023	13,933	7.38				100% vesting on June 28,2024
Vested during 2023	(280,928)	7.94
Withheld for settlement of taxes	(123,397)	7.94
Forfeitures during 2023	(106,435)	7.19
Unvested restricted stock units outstanding at December 31, 2023	949,936	$	6.98	$	6,627
Stock Options:
Unvested awards as of December 31, 2022	—	—
Granted in March 2023	196,961	5.26				Three equal installments vesting over 3 years
Forfeitures during 2023	(21,071)	5.26
Unvested Stock Options at December 31, 2023	175,890	$	5.26	$	925
Performance Stock Units:
Unvested awards as of December 31, 2022	—	—
Granted in March 2023	274,617	6.97				100% vesting on March 31, 2026
Vested during 2023	(83)	6.97
Shares withheld for settlement of taxes	(31)	6.97
Forfeitures	(34,823)	6.97
Performance Stock Units outstanding as of December 31, 2023	239,680	$	6.97	$	1,671
Total unvested awards outstanding as of December 31, 2023	1,365,506	$	6.75	$	9,223

Parent Equity Awards

During the years ended December 31, 2020 and 2019, Fortistar granted certain equity-based awards to certain employees of the Company in the form of residual equity interests (“Profit Interests”) in four wholly-owned subsidiaries of the Company. The Profit Interests do not have voting rights and shall participate in the income distributions when the subsidiaries achieve certain financial targets. These Profits Interests were restructured in December 2020, at which time they became based on a portion of Fortistar's indirect ownership in the Company, rather than in Fortistar's ownership interest in Company subsidiaries. The percentage of Profit Interests issued in the investment entities that were established to grant the incentive units ranged between 34%-37% in the four wholly-owned subsidiaries. These Profit Interests vest ratably over a period of five years from the grant date.

There were no new residual equity interest grants during the year ended December 31, 2023.

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As of December 31, 2023, 86% of the Profit Interests issued vested and there were 14% of Profit Interests unvested. There were no forfeitures during the year ended December 31, 2023.

As of December 31, 2022, 66% of the Profit Interests issued vested and there were 34% of Profit Interests unvested.

The stock-based compensation expense for the above stock awards under the 2022 Plan as well as Parent Equity Awards is included in the selling, general and administrative expenses:


	Twelve Months Ended December 31,
	2023		2022
2022 Plan	$	5,264	$	830
Parent Equity Awards	639		639
	$	5,903	$	1,469

Stock-based compensation expense related to unvested awards yet to be recognized as of December 31, 2023 totaled $6,308 and is expected to be recognized, on a weighted average basis, over 2.3 years.

The future compensation to be recognized for the Parent Equity Awards as of December 31, 2023 is $453 and will be recognized the remaining vesting period which ranges from one to two years.

17. Commitments and Contingencies

Letters of Credit

As of December 31, 2023 and December 31, 2022, the Company was required to maintain nine standby letters of credit totaling $13,750 and $2,292, respectively, to support obligations of certain Company subsidiaries. These letters of credit were issued in favor of a lender, utilities, a governmental agency, and an independent system operator under PPA electrical interconnection agreements, and in place of a debt service reserve. There have been no draws to date on these letters of credit.

Purchase Options

The Company has two contracts with customers to provide CNG for periods of seven and ten years, respectively. The customers have an option to terminate the contracts and purchase the Company's CNG Fueling Station at the customers' sites for a fixed amount that declines annually.

In July 2015, the Company entered into a ten year fuel sales agreement with a customer that included the construction of a CNG Fueling Station owned and managed by the Company on the customer's premises. At the end of the contract term, the customer has an option to purchase the CNG Fueling Station for a fixed amount. The cost of the CNG Fueling Station was recorded to Property, plant, and equipment and is being depreciated over the contract term.

On May 30, 2023, OPAL Intermediate Holdco 2 assigned to Paragon its rights and obligations under the OPAL Term Loan II.

Legal Matters

The Company is involved in various claims arising in the normal course of business. Management believes that the outcome of these claims will not have a material adverse effect on the Company's financial position, results of operations or cash flows.

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Set forth below is information related to the Company’s material pending legal proceedings as of the date of this report, other than ordinary routine litigation incidental to the business.

Central Valley Project

In September 2021, an indirect subsidiary of the Company, MD Digester, LLC, entered into a fixed-price Engineering, Procurement and Construction Contract (an “EPC Contract”) with VEC Partners, Inc. d/b/a CEI Builders (“Contractor”) for the design and construction of a turn-key renewable natural gas production facility using dairy cow manure as feedstock. In December 2021, a second indirect subsidiary of the Company, VS Digester, LLC entered into a nearly identical EPC Contract with Contractor for the design and construction of a second facility in connection with the same project.

18. Subsequent Events

On March 5, 2024, Paragon RNG LLC, a joint venture between OPAL Fuels Inc. and a third-party environmental solutions company (“Paragon”), as the Borrower, certain indirect subsidiaries of the Borrower as guarantors (the “Guarantors”), the lenders party thereto and Bank of Montreal as the administrative agent (the “Administrative Agent”) entered into the First Amendment to Amended and Restated Credit and Guaranty Agreement (the “Credit Agreement Amendment”), and Paragon, the Administrative Agent and Wilmington Trust, National Association as collateral and depositary agent entered into the First Amendment to Depositary Agreement (the “Depositary Agreement Amendment”), with respect to the Amended and Restated Credit and Guaranty Agreement (the “Credit Agreement”) and Depositary Agreement (the “Depositary Agreement”) entered into on May 30, 2023.

The Credit Agreement Amendment reclassifies the debt service reserve facility (the “DSR Facility”) under the Credit Agreement as a revolving loan facility of up to a maximum aggregate principal amount of $10.0 million (the “Revolving Loan Facility”) on substantially the same terms as the DSR Facility, with the proceeds of the Revolving Loan Facility to be used primarily to satisfy the balance to be maintained in the debt service reserve account. The Credit Agreement Amendment extends the outside date (the “Conversion Date”) for completion of construction of the Emerald RNG LLC (“Emerald”) and Sapphire RNG LLC (“Sapphire”) projects from June 30, 2024 to December 1, 2024, and requires the Borrower, prior to the Conversion Date, to maintain a debt service coverage ratio with respect to the Emerald project (the “Pre-Term Conversion Debt Service Coverage Ratio”) of not less than 1.2:1.0, as tested on a trailing four fiscal quarters basis as of the last day of each fiscal quarter commencing as of the effective date of the Credit Agreement

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Amendment. Availability under the Credit Agreement’s delayed term loan facility (the “DDTL Facility”) has been reduced from a maximum aggregate principal amount of $85.0 million to approximately $81.0 million to account for DDTL Facility borrowings under the Credit Agreement to date, and with certain exceptions, the DDTL Facility borrowings are no longer available for project costs related to the Emerald project.

The Credit Agreement Amendment and the Depositary Agreement Amendment together require prepayments of principal in the amount of $2.0 million each on the last business day of each fiscal quarter in 2024, and to the extent funds are available on such dates, additional prepayments in the amounts of $2.5 million, $6.0 million, $10.0 million and $15.0 million (each a “Target Aggregate Special Principal Prepayment Amount”), respectively, in each case net of the prepayments already paid as of such date since January 1, 2024. As a condition precedent to making certain restricted payments, all mandatory prepayments made in 2024, in the aggregate, must meet or exceed the Target Aggregate Special Principal Prepayment Amount for such fiscal quarter, and the Pre-Term Conversion Debt Service Coverage Ratio must be greater than or equal to 1.4:1.0 as of the last day of the fiscal quarter immediately preceding the proposed date of such restricted payment.

The Credit Agreement Amendment and the Depositary Agreement Amendment are subject to a $150,000 amendment fee paid at closing of such amendments.

On March 12, 2024, Fortistar, through its subsidiary OPAL Holdco, converted 71.5 million shares of Class D common stock of the Company held by it, each of which is entitled to five votes per share on all matters on which stockholders generally are entitled to vote, for an equal number of shares of newly issued Class B common stock of the Company, each of which is entitled to one vote on such matters. This transaction has no effect on the economic interest in the Company held by Fortistar or OPAL Holdco. Fortistar converted such shares in order that the Company’s Class A common stock would become eligible for inclusion in certain stock market indices, on which many broad-based mutual funds and exchange-traded index funds are based. There can be no assurance that the Company’s Class A common stock will be included in any stock market index as a result of the share conversion, or that if the Company’s Class A common stock is included in any such index, that the price per share of the Company’s Class A common stock will be positively affected.

Post this exchange, Fortistar holds 72,899,037 shares of Class D common stock and 71,500,000 shares of Class B common stock.

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