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, 2024

 or

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

 For the transition period from _______________ to ____________

 Commission file number 001-40272

 (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 28, 2024, the last business day of the registrant's most recently completed second fiscal quarter, was approximately $ 107,075,893 based on the closing price of the registrant's Class A common stock on The Nasdaq Capital Market on that date.

 As of March 13, 2025, a total of 28,429,477 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 outstanding.

 Page

 Item 1.
 Business

 Item 1A.
 Risk Factors

 Item 1B.
 Unresolved Staff Comments

 Item 1C.
 Cybersecurity

 Item 2.
 Properties

 Item 3.
 Legal Proceedings

 Item 4.
 Mine Safety Disclosures

 Item 5.
 Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 Item 6.
 [Reserved]

 Item 7.
 Management's Discussion and Analysis of Financial Condition and Results of Operations

 Item 7A.
 Quantitative and Qualitative Disclosures About Market Risk

 Item 8.
 Financial Statements and Supplementary Data

 Item 9.
 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 Item 9A.
 Controls and Procedures

 Item 9B.
 Other Information

 Item 9C.
 Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 Item 10.
 Directors, Executive Officers and Corporate Governance

 Item 11.
 Executive Compensation

 Item 12.
 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 Item 13.
 Certain Relationships and Related Transactions and Director Independence

 Item 14.
 Principal Accountant Fees and Services

 Item 15.
 Exhibits and Financial Statement Schedules

 Signatures

 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, and maintain relationships with customers and suppliers;

 • 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 and sell 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.

 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 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 over a decade 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.
 Our Strategy
 We aim to maintain and grow our position as a leading producer and dispenser of RNG in the United States and 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 twenty 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 environmental health and safety ("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 use 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 and will 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 2024, we dispensed 74 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 carbon dioxide 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 on-site to remove impurities, and used at around 50% methane to generate Renewable Power. Biogas can be further processed and upgraded to remove carbon dioxide 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 is the top agricultural source of GHG worldwide, according to the EPA. Livestock waste, particularly from dairies, produces methane that can be converted to RNG and 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 343 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 the California Air Resources Board 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 increase by 2027, bringing 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, 2024, we owned and operated 26 projects, 11 of which are RNG projects and 15 of which are Renewable Power projects. As of that date, our RNG projects in operation had a design capacity of 8.8 million MMBtus per year and our Renewable Power projects in operation had a nameplate capacity of 105.8 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 as well as a portfolio of projects in development, with six 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 (4)

 RNG Projects in Operation:

 Greentree
 1,061,712
 LFG
 100%
 N/A

 Imperial
 1,061,712
 LFG
 100%
 N/A

 Emerald (2)

 1,327,140
 LFG
 50%
 N/A

 Sapphire (2)

 796,284
 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)

 43,750
 Dairy
 10%
 N/A

 Sunoma (3)

 176,297
 Dairy
 90%
 N/A

 Prince William

 1,725,282
 LFG
 100%
 N/A

 Polk County (7)

 1,060,000
 LFG
 100%
 N/A

 Total
 8,804,931

 RNG Projects in Construction:

 Hilltop (5)

 255,500
 Dairy
 100%
 (5)

 Vander Schaaf (5)

 255,500
 Dairy
 100%
 (5)

 Burlington (6)

 459,900
 LFG
 50%
 (6)

 Atlantic (2)

 331,785
 LFG
 50%
 Third quarter 2025

 Cottonwood (6)

 664,884
 LFG
 100%
 (6)

 Kirby Canyon (6)

 663,570
 LFG
 100%
 (6)

 Total
 2,631,139

 (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) 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.
 (4) 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.
 (5) Please see Part I, Item 3: Legal Proceedings and Note 17 - Commitments and Contingencies to the financial statements.
 (6) The construction of the Cottonwood, Burlington and Kirby Canyon projects began in the second, third and fourth quarters of 2024, respectively.
 (7) The Polk County project began commercial operations in October 2024.
 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
 —

 Richmond (previously "Old Dominion")

 8.0
 Yes

 Total
 105.8

 Renewable Power projects in construction:

 Fall River (4)

 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) Construction of the Fall River project has been delayed due to permitting issues.
 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 producers 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 ("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 under the new 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 broad 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. Similarly, recent presidential executive orders directing the review and potential termination of funds appropriated through the IRA are also creating uncertainty of whether these financial incentives could be reduced or repealed in the future.
 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.
 Facilities
 Our corporate headquarters are located in White Plains, New York, where we occupy approximately 13,600 square feet of shared office space with 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, 2024, we had approximately 1 part-time employee and 341 full-time employees, nearly 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 of the Business Combination.
 "Business Combination" refers to the transactions contemplated by 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.
 "Class A common stock" refers to the shares of Class A common stock, par value $0.0001 per share, of OPAL.
 "Class B common stock" refers to the shares of Class B common stock, par value $0.0001 per share, of OPAL.
 "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.
 "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.
 "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:
 "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.

 "CI" refers to carbon intensity.
 "CNG" refers to compressed natural gas.
 "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.

 ITEM 1A. RISK FACTORS
 Risks Related to 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. 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 and Executive Order N-79-20 issued by the Governor of the State of California in September 2020. 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.

 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.
 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 current regulatory regime also creates uncertainty related to the future market for such Environmental Attributes and this could have an adverse effect on the earnings we generate from such attributes.
 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 ISOs and 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.
 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 that may result due to recent regulatory changes or otherwise;
 • 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 Energy Marketing, LLC ("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 carbon dioxide 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.
 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;
 • 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.
 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 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.
 Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and operating results. In addition, current and potential stockholders could lose confidence in our financial reporting, which could have a material adverse effect on the price of our Class A common stock.
 Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal control over financial reporting and a report by our independent registered public accounting firm on the effectiveness of internal control over financial reporting as of year-end. We are required to report, among other things, control deficiencies that constitute material weaknesses or changes in internal control that, or that are reasonably likely to, materially affect internal control over financial reporting. A "material weakness" is a significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.
 We have identified and remediated control deficiencies in the past, and we cannot assure you that we will at all times in the future be able to report that our internal controls are effective. If we cannot provide reliable financial reports or prevent fraud, our results of operation could be harmed. Our failure to maintain the effective internal control over financial reporting could cause the cost related to remediation to increase and could cause our stock price to decline. In addition, we may not be able to accurately report our financial results, may be subject to regulatory sanctions, and investors may lose confidence in our financial statements. No material weaknesses were identified during the year ended December 31, 2024.
 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.
 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.
 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' 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.
 Our increasing reliance on information technology and other systems subjects us to risks associated with cybersecurity. Cybersecurity incidents or our failure to maintain the security and integrity of Company, employee, associate, customer or third-party data could have a disruptive effect on our business and adversely affect our reputation and financial performance.
 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.
 Risks Related to Regulations or Governmental Actions
 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 or any future 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 Resources Board 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 CO 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. The California Air Resources Board 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. The U.S. Congress may look to alter or repeal various energy tax incentives included in the IRA, which could potentially impact projects in development or future project economics. Similarly, recent presidential executive orders directing the review and potential termination of funds appropriated through the IRA are also creating uncertainty of whether these financial incentives could be reduced or repealed in the future.
 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 uncertainty if IRA incentives may be reduced or repealed in the future, especially in light of the 2024 election results. 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.
 The Company may incur contractual obligations from the indemnification of third parties if tax authorities challenge the amount or availability of ITCs or related tax benefits that the Company is obligated to provide to such third parties under such contractual arrangements.

 The Company from time-to-time enters into arrangements with third parties that acquire tax credits, including ITCs, from, the Company where tax credits and related tax benefits represent a material portion of the economic benefit of the arrangement to such other party. In certain circumstances, as is customary in the industry, the Company has guaranteed and may have to guarantee the economic benefit of such tax credits and other tax benefits to such party. A reduction in expected tax credits or tax benefits resulting from successful challenges by the IRS could result in an obligation under the Company's contractual arrangements that could have a material impact on the Company's financial condition, results of operations and liquidity.

 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.
 On July 12, 2023, the EPA issued final rule 88 Fed. Reg. 44468 (July 12, 2023) to, in part, implement biogas regulatory reform to the EPA's Renewable Fuel Standard Program ("RFS") (the "Biogas Regulatory Reform Rule" or "BRRR"). BRRR significantly changed the method by which RINs are generated from biogas feedstock and how market participants are required to administer RINs. BRRR required all parties in the chain of title to biogas, renewable natural gas, and RINs to register with the EPA by January 1, 2025.
 The Company timely completed and received approval of its required registrations under BRRR. As part of this registration process, with respect to fueling stations, the Company registered as RNG RIN separator for stations that accounted for approximately 57% of the Company's CNG dispensing capacity. Wherever the Company is not registered as the RNG RIN separator, it will rely on the owner/operator of the fueling station to perform the role as RNG RIN separator (i.e., separating the RINs and transferring them to the Company for monetization). There can be no assurance that these owners/operators will timely provide the necessary administrative services and transactional data required for the separation and transfer of RINs from these stations. If we are unable to receive RINs from stations representing a material proportion of our dispensing capacity, it would have a material adverse effect on our financial results.
 Risks Related to Our Indebtedness
 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, 2024, our total indebtedness was $307.5 million, excluding deferred financing costs. Additionally, we have redeemable preferred non-controlling interests outstanding of $130.0 million.
 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;
 • 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 will have certain rights and remedies.
 For example, upon written notice from NextEra at any time after November 29, 2025, we would be required to redeem the Series A preferred units. In the event we do not redeem the Series A preferred units when requested, Nextera will have the following rights and remedies: (1) NextEra's affiliate may extend the RNG Marketing Agreement by 12 months; or (2) the dividend rate would increase depending on the length of time the Series A preferred units remain unredeemed to up to 20% per annum, and if more than $25,000,000 preferred equity is outstanding for more than six months after November 29, 2025, NextEra may appoint a director to our Board of Directors; or (3) NextEra may convert the Series A preferred equity into common equity of the OPAL Fuels LLC at a conversion price at a 20% to 30% discount to their value (the discount is 20% during the first 12 months after November 29, 2025, 25% for the next 12 months thereafter and 30% thereafter). For more information related to our obligation to redeem the Series A preferred units, please refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.
 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.
 Risks Related to Ownership of Our Class A Common Stock

 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 or our subsidiaries issue additional 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, ArcLight CTC Holdings II, L.P. and its 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. We originally registered for resale up to 163,676,735 shares of our Class A common stock pursuant to our registration statement on Form S-3 filed under the Securities Act (File No. 333-266757), which was declared effective on August 10, 2023.
 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.
 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 145,336,349 shares of OPAL, comprising 83.7% of our outstanding common stock as of March 14, 2025. All of these shares (with the exception of 880,600 shares of Class A common stock purchased by Fortistar in the PIPE Investment and 56,712 shares of Class A common stock held directly by Mr. Comora) are Class B common stock, or Class D common stock which have no economic rights but are entitled to five votes per share, giving Mr. Mark Comora control over 93.9% 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 certificate of incorporation or bylaws, 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.
 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 our certificate of incorporation that could delay or prevent a change of control.
 Certain provisions of our certificate of incorporation 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 our 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.
 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, including as a result of increased and/or new tariffs on equipment supply and raw materials. 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.
 In addition, uncertainty surrounding potential tariff increases on imported products and possible retaliatory measures by other countries could negatively impact our business. On February 1, 2025, the U.S. government proposed tariffs of up to 25% on imports from certain countries, including Mexico and Canada, and implemented additional tariffs on imports from China. As of the date of this report, these tariffs are set to take effect on April 2, 2025. In response, countries such as Mexico have indicated they may impose retaliatory tariffs on U.S. exports.
 At this time, it is unclear whether these tariffs will apply to imports of equipment and machinery upon which our business is reliable. Any new or increased tariffs, trade sanctions, or changes in U.S. trade policy could lead to higher operational costs. If we are unable to pass these additional costs to our customers and/or effectively manage higher operational expenses, our financial performance could be adversely affected.
 While we continue to assess the potential impact of these proposed tariffs and explore mitigation strategies, we do not currently anticipate a material adverse effect on our cost of goods sold or gross profit. This expectation assumes that the financial burden of increased tariffs will be absorbed primarily by market adjustments.
 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.
 Central Valley Project
 In September 2021, an indirect subsidiary of the Company, MD Digester, LLC ("MD"), entered into a fixed-price Engineering, Procurement and Construction Contract (an "EPC Contract") with VEC Partners, Inc. d/b/a CEI Builders ("CEI") for the design and construction of a turn-key renewable natural gas production facility using dairy cow manure as feedstock in California's Central Valley. In December 2021, a second indirect subsidiary of the Company, VS Digester, LLC ("VS") entered into a nearly identical EPC Contract (collectively, the "EPC Contracts") with CEI for the design and construction of a second facility, also in California's Central Valley. CEI's performance under both of the EPC Contracts is fully bonded by licensed sureties.
 CEI has submitted a series of change order requests seeking to increase the EPC Contract Price by approximately $14 million, per project, primarily due to: (1) modifications to CEI's design drawings which are required to meet its contracted performance guaranties, and (2) a default by one of CEI's major equipment manufacturers. The Company disputes the vast majority of the change order requests.
 In January 2024, the Company filed a civil lawsuit captioned, MD Digester, LLC. et. al. vs. VEC Partners, Inc. et. al.; with the 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 has been stayed, pending the conclusion of the arbitration. In the meantime, the AAA has empaneled three experienced arbitrators and has set the hearing date for the matter, currently schedule in May 2026.
 The EPC Agreement requires that CEI, continue working during the course of the litigation and related arbitration proceedings; however, CEI effectively stopped working. Between May and August 2024, MD issued a series of Notices of Default and Demands to Cure to CEI. CEI failed to cure, and on July 30, 2024, MD terminated CEI for default. MD notified CEI's performance bond surety, Atlantic Specialty Insurance Company of the termination and demanded that it perform under the bond. Atlantic has denied the claim.
 On July 11, 2024, VS issued a Notice of Default and Demand to Cure, advising CEI of its defaults and giving it an opportunity to cure. CEI failed to do so, and on August 27, 2024, VS terminated CEI for default. VS has notified CEI's bond surety, also Atlantic, of the second termination and demanded that it perform under the performance bond. The surety has denied the claim.
 As a result of CEI's default and Atlantic's denial of the claims, MD and VS have amended their claims in the AAA arbitration to include breach of contract claims against CEI and breach of performance bond claims against Atlantic (who was formally joined into the arbitration on November 20, 2024) in the AAA Arbitration with CEI.
 CEI has since recorded mechanic's liens against each of the projects for $4.9 million (MD) and $2 million (VS), and recently filed actions with the Stanislaus and San Joaquin County Superior Courts, respectively, to enforce their liens. It is expected that these claims will be stayed and consolidated with the pending arbitration proceeding.
 In addition to the above-referenced action and arbitration, several of CEI's subcontractors have recorded mechanic's liens against the MD and VS projects, which the Company is obligated to defend and indemnify the dairy owners from and against. Several of liens were untimely and have been released.
 The Company believes its claims against CEI (and the surety where bond claims are denied) have substantial merit, and intends to prosecute the claims vigorously. However, due to the incipient stage of the litigation and related arbitration, the recency of the termination, and the ongoing status of the proceedings and discussions with the bond surety, as well as

 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, if any, on the Central Valley projects or the Company's business, financial condition or results of operations.
 Former Development Partner/Construction Manager
 In March 2024, the Company filed an action in the Orange County Superior Court (Case No. 30- 2024-01415510-CU-BC-CXC) against its former development partner and construction manager, Sierra Renewable Organics Management, LLC, as well as its principal (Ethan Werner) and affiliated engineering firm (CH Four Biogas) for Breach of Contract, Indemnity, Declaratory Relief, Intentional Misrepresentation and Negligent Misrepresentation relating to the design and development of the Projects. The case is not yet at issue, so no answer or cross claims have been filed yet, and no discovery has been conducted.

 ITEM 4. MINE SAFETY DISCLOSURES

 Not applicable.

 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, 2025, the closing sale price of our shares of Class A common stock, as reported on the Nasdaq Stock Market LLC, was $2.17 per share.
 The number of shareholders of record of our shares of Class A common stock was approximately 12 on March 13, 2025.
 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, 2023 as compared to the year ended December 31, 2022, 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, 2023, as filed with the SEC on March 15, 2024. 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 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 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.
 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 over a decade 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.
 As of December 31, 2024, we owned and operated 26 projects, 11 of which are RNG projects and 15 of which are Renewable Power Projects. As of that date, our RNG projects in operation had a design capacity of 8.8 million MMBtus per year and our Renewable Power Projects in operation had a nameplate capacity of 105.8 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 six of our current Renewable Power Projects being considered candidates for conversion to RNG projects in the foreseeable future.
 Recent Developments
 Wasatch Resource Recovery Facility
 On March 17, 2025, Fortistar, through its subsidiary Wasatch RNG LLC ("Wasatch RNG"), acquired all of the limited liability company interests outstanding in Alpro SD, LLC ("Alpro" and such acquired interest, the "Alpro Interest"). Alpro owns a 50% limited liability company interest in Wasatch Resource Recovery, LLC (the "Project" or "Wasatch" and such ownership interest, the "Wasatch Interest") and a 50% tenancy-in-common interest in certain real estate and operating assets used by Wasatch (the "Project Interest"). As a result of the acquisition, Wasatch RNG has the option to increase the Wasatch Interest and the Project Interest.
 The Project captures and converts biogas generated from food waste to produce pipeline quality renewable natural gas (RNG). The Project generates revenue from long-term contracted gas sales, tipping fees, and digestate (fertilizer) sales. The conversion of food waste to RNG presents a potential growth and diversification opportunity for OPAL Fuels.

 In connection with the acquisition, Fortistar Services 2 LLC and OPAL Fuels LLC entered into an amendment to its existing Administrative Services Agreement, pursuant to which OPAL Fuels will provide certain services to Wasatch RNG in exchange for certain agreed upon fees and expense reimbursements. These services include oversight of the plan to improve the operations and productivity of the Project.
 Additionally, Wasatch RNG and OPAL Fuels entered into an Option Agreement, pursuant to which Wasatch RNG granted an option to OPAL Fuels to purchase the Alpro Interest. The exercise period of the option commenced upon closing of the acquisition and will terminate on the third anniversary of the closing of the acquisition, or ninety days following a change of control of OPAL Fuels. The exercise price of the option would be determined such that Wasatch RNG would earn an internal rate of return on its invested capital of 10% percent per year if the option is exercised in the first year, 15% per year if exercised in the second year, and 20% per year if exercised in the third year.
 OPAL Term Loan Amendment
 On March 3, 2025, OPAL Fuels Intermediate HoldCo LLC, as the borrower (the "Borrower"), certain subsidiaries of the Borrower, as guarantors (the "Guarantors"), the lenders and issuers of letters of credit party thereto and Bank of America, N.A. as the administrative agent (the "Administrative Agent") entered into that certain Amendment No. 1 to Credit and Guarantee Agreement (the "Credit Agreement Amendment"), with respect to that certain Credit and Guarantee Agreement (the "Credit Agreement") dated September 1, 2023, by and among the Borrower, the Administrative Agent, the financial institutions from time to time parties thereto as lenders and as issuers of letters of credit, and the other agents and persons from time to time party thereto (as amended, restated, amended and restated, supplemented or otherwise modified and in effect from time to time).
 The Credit Agreement Amendment makes certain changes to the applicability of certain financial covenants and modifies other covenants to clarify the use of loan proceeds. Additionally, the Credit Agreement Amendment permits the organizational restructuring of the Guarantors in a manner designed to facilitate the sale of federal investment tax credits and the ability to raise additional future capital.
 The Credit Agreement Amendment also eases the conditions precedent to making new Projects eligible for borrowing under the Credit Agreement, extends the availability period for delay draw term loans under the Credit Agreement through March 5, 2026, and extends the commencement of repayment of such term loans until March 31, 2026.
 In connection with the Credit Agreement Amendment, the Borrower paid the Administrative Agent, for the account of each lender, a one-time nonrefundable fee of $1,250,000.
 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
 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.
 The Company provides all third-party construction contracts with a warranty, typically for a period of one year after substantial completion of the construction project. Based on the guidance and indicative factors provided by ASC 606, the Company concluded that it offers assurance-type warranties as it does not provide a service to the customer beyond fixing defects that existed at the time of completion. Therefore, these warranties are accounted for under ASC Topic 460, Guarantees ("ASC 460"), and not as a separate performance obligation.
 Generally, the company estimates warranty costs based on historical claims experience, and other factors. Actual warranty claims may differ from the estimates, and adjustments to the liability are made as necessary.
 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 as of December 31 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.
 When applying a quantitative assessment, we use a combination of income and market valuation methodologies. Specifically, we employ a discounted cash flow analysis (DCF) and the guideline public company method. This approach results in a fair value measurement based on significant inputs that are not observable in the market, categorizing it within Level 3 of the fair value hierarchy. Key assumptions in the DCF projection include growth in RIN prices, future sales volumes based on production capacities, and terminal value based on a range of terminal earnings before interest, taxes, depreciation, and amortization (EBITDA). The future cash flows are discounted to present value using the weighted average cost of capital (WACC) of the company and its closest competitors.
 As of December 31, 2024, we performed a quantitative assessment for Goodwill in our RNG Fuel segment and determined that there is no impairment necessary on the goodwill recorded in the books as of December 31, 2024.
 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. Alternatively, we use cost approach to measure fair value of our assets or asset groups. The cost approach is based on the premise that a prudent investor would pay no more for an asset of similar utility than its replacement or reproduction cost. The cost to replace the asset would include the cost of constructing a similar asset of equivalent utility at prices applicable at the time of the valuation date. To arrive at an estimate of the fair value using the cost approach, the replacement cost new is determined and reduced for depreciation of the asset. Replacement cost new is defined as the current cost of producing or constructing a similar new item having the nearest equivalent utility as the property being valued. 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, 2024, the impairment recorded on our Plant, Property and Equipment amounted $2.0 million.
 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.
 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 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 carbon dioxide 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 on 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:
 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.

 Through our Fuel Station Services segment, we provide construction and maintenance services to third-party owners of vehicle Fueling Stations and perform 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.
 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:
 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.
 Includes equipment supplier costs; service provider costs; and salaries and other indirect expenses.
 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, 2024 and 2023. No other single customer accounted for 10% or greater of our consolidated accounts receivables in these periods:

 2024
 2023

 Customer A (1)

 %
 %

 Customer B

 *
 %

 Customer C
 %
 *

 (1) Relates to sales of environmental attributes under Purchase and Sale agreement and Renewable Power sale agreements with NextEra.
 *Less than 10%
 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:

 2024
 2023

 Customer A

 %
 %

 Customer C

 %
 %

 Results of Operations for the years ended December 31, 2024 and 2023:
 Operational data
 The following table summarizes the operational data achieved for the years ended December 31, 2024 and 2023:
 Landfill RNG Facility Capacity and Utilization Summary

 2024
 2023

 Landfill RNG Facility Capacity and Utilization

 Design Capacity (Million MMBtus) (1) (4)

 6.6
 4.1

 Volume of Inlet Gas (Million MMBtus) (2)

 4.6
 3.2

 Inlet Design Capacity Utilization % (2)

 %
 %

 RNG Fuel volume produced (Million MMBtus) (4)

 3.7
 2.6

 Utilization of Inlet Gas % (3)

 %
 %

 (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) Excludes Sunoma and Biotown.

 2024
 2023

 Nameplate Capacity (MW per hour)(1)

 105.8
 112.5

 Nameplate Capacity for the period (Millions MWh) (1)

 0.93
 0.98

 Renewable Power produced ( Millions MWh)

 0.36
 0.44

 Design Capacity Utilization (%) (2)

 %
 %

 (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%.

 2024
 2023

 RNG Fuel volume produced (Million MMBtus)

 3.8
 2.7

 RNG Fuel volume sold (Million GGEs)

 74.0
 43.8

 Total volume delivered (Million GGEs)

 150.2
 133.2

 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 (4)

 RNG Projects in Operation:

 Greentree
 1,061,712
 LFG
 100%
 N/A

 Imperial
 1,061,712
 LFG
 100%
 N/A

 Emerald (2)

 1,327,140
 LFG
 50%
 N/A

 Sapphire (2)

 796,284
 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)

 43,750
 Dairy
 10%
 N/A

 Sunoma (3)

 176,297
 Dairy
 90%
 N/A

 Prince William

 1,725,282
 LFG
 100%
 N/A

 Polk County (7)

 1,060,000
 LFG
 100%
 N/A

 Total
 8,804,931

 RNG Projects in Construction:

 Hilltop (5)

 255,500
 Dairy
 100%
 (5)

 Vander Schaaf (5)

 255,500
 Dairy
 100%
 (5)

 Burlington (6)

 459,900
 LFG
 50%
 (6)

 Atlantic (2)

 331,785
 LFG
 50%
 Third quarter 2025

 Cottonwood (6)

 664,884
 LFG
 100%
 (6)

 Kirby Canyon (6)

 663,570
 LFG
 100%
 (6)

 Total
 2,631,139

 (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) 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.
 (4) 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.
 (5) Please see Part I, Item 3: Legal Proceedings and Note 17 - Commitments and Contingencies to the financial statements.
 (6) The construction of the Cottonwood, Burlington and Kirby Canyon projects began in the second, third and fourth quarters of 2024, respectively.
 (7) The Polk County project began commercial operations in October 2024.

 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
 —

 Richmond (previously "Old Dominion")

 8.0
 Yes

 Total
 105.8

 Renewable Power projects in construction:

 Fall River (4)

 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) Construction of the Fall River project has been delayed due to permitting issues.
 Comparison of the Years Ended December 31, 2024 and 2023
 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 December 31, 2024 and 2023.

 $
 Change
 %
Change

 2024
 2023

 Revenues:

 RNG fuel
 $
 $
 $
 22,128
 %

 31,863
 %

 (10,127)
 (18)
 %

 Total revenues
 43,864
 %

 Operating expenses:

 Cost of sales - RNG fuel
 38,552
 32,028
 6,524
 %

 Cost of sales - Fuel Station Services

 128,804
 115,322
 13,482
 %

 Cost of sales - Renewable Power

 32,495
 36,550
 (4,055)
 (11)
 %

 4,866
 14,243
 %

 Selling, general, and administrative
 53,124
 51,262
 1,862
 %

 Depreciation, amortization, and accretion
 17,885
 14,565
 3,320
 %

 Impairment loss

 2,016
 —
 2,016
 %

 Income from equity method investments

 (13,235)
 (5,525)
 (7,710)
 (140)
 %

 Total expenses
 278,750
 249,068
 29,682
 %

 Operating income

 21,222
 7,040
 14,182
 %

 Other income (expense):

 (19,610)
 (9,306)
 (10,304)
 (111)
 %

 Change in fair value of derivative instruments, net
 1,596
 7,346
 (5,750)
 (78)
 %

 2,211
 124,472
 (122,261)
 (98)
 %

 Loss on debt extinguishment
 —
 (2,190)
 2,190
 %

 Loss on warrant exchange
 —
 (338)
 %

 Income before provision for income taxes

 5,419
 (121,605)
 (96)
 %

 Income tax benefit

 8,906
 —
 8,906
 %

 (112,699)
 (89)
 %

 Net income attributable to redeemable non-controlling interests
 2,851
 97,426
 (94,575)
 (97)
 %

 Net income (loss) attributable to non-redeemable non-controlling interests

 (349)
 %

 Dividends on Redeemable preferred non-controlling interests
 10,470
 11,011
 (541)
 (5)
 %

 Net income attributable to Class A common stockholders

 $
 $
 18,936
 $
 (18,375)
 (97)
 %

 Revenues

 2024
 2023
 $ Change

 Brown gas sales
 $
 4,745
 $
 4,231
 $

 Environmental Attributes (1)

 82,316
 61,221
 21,095

 Other
 1,359

 Total RNG Fuel
 $
 $
 $
 22,128

 OPAL owned stations
 $
 25,804
 $
 18,958
 $
 6,846

 RNG marketing (2)

 76,320
 45,277
 31,043

 Third party station service and maintenance
 25,053
 21,857
 3,196

 Construction
 39,698
 48,920
 (9,222)

 Total Fuel Station Services
 $
 $
 $
 31,863

 Electricity sales
 $
 27,249
 $
 34,680
 $
 (7,431)

 Environmental Attributes (3)

 17,428
 20,124
 (2,696)

 Total Renewable Power
 $
 $
 $
 (10,127)

 Total Revenues
 $
 $
 $
 43,864

 (1) Revenues from Environmental Attributes in RNG Fuel segment relate to revenues earned from sales of RINs and LCFSs
 (2) Revenues from RNG marketing in Fuel Station Services segment relate to revenues earned from sales of RINs and LCFSs as well as revenue from Environmental Attribute generation and monetization services.
 (3) Revenues from Environmental Attributes in Renewable Power segment include revenues earned from sales of ISCC carbon sales and RECs.
 Revenue from RNG Fuel increased by $22.1 million, or 33%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This is primarily due to a $21.1 million increase in Environmental Attributes, driven by $9.1 million of higher price and $12.0 million from increased volume, primarily from commencement of operations at Prince William and Polk. Revenue from Brown Gas Sales increased $0.5 million, also primarily due to the impact of Prince William and Polk coming online in 2024. Additionally, there was $0.5 million increase in revenues earned from providing management services to unconsolidated entities.
 Revenue from Fuel Station Services increased by $31.9 million, or 24%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This was primarily attributable to a $31.0 million increase in RNG marketing revenues, driven by a $17.1 million increase in RIN and LCFS minting services from higher RNG volumes (Emerald ramp-up, Prince William), and an $18.0 million increase in RIN sales from higher volume and pricing, and a $4.1 million decrease in 3rd party LCFS sales as the company chose to hold some unsold LCFS credits in inventory at the end of 2024. Also within Fuel Station Service there was a $6.8 million increase in OPAL owned stations due to higher volumes, and a $3.2 million increase in service and maintenance revenues from an increased number of stations serviced, partially offset by a $9.2 million decrease in construction revenues primarily related to timing as new 2024 projects started construction later in the year.

 Revenue from Renewable Power decreased by $10.1 million, or 18%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This change was attributable primarily to a $7.4 million decrease in Electricity Sales, of which a $4.6 million decrease was related to facility shutdowns for conversion to RNG Fuel and $2.8 million was related to lower price. Also within Renewable Power was a $2.7 million decrease in Environmental Attributes, primarily related to the same facility shutdowns mentioned above. Regulatory changes implemented by the European Union Commission took effect on November 21, 2024 that excluded biomethane produced outside of the European Union from being certified as eligible to be sold in accordance with the European Union Renewable Energy Directive. As a result, all of our contracts governing sales of ISCC Carbon Credits were terminated on November 21, 2024. Following such terminations, we expect to continue to earn revenues from sale of electricity generated by these Renewable Power facilities and the associated Environmental Attributes.
 Cost of sales
 Cost of sales from RNG Fuel increased by $6.5 million, or 20%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. The increase was primarily related to start of operations at our Prince William and Polk RNG facilities in 2024.
 Cost of sales from Fuel Station Services increased by $13.5 million, or 12%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This change was attributable primarily to a $18.3 million increase in dispensing fees to generate Environmental Attributes, $3.3 million increase in FPA tolling expense, and a $2.0 million increase in Service and maintenance expenses, partially offset by an $11.0 million decrease in construction expense, in line with the decrease in construction revenues.
 Cost of sales from Renewable Power decreased by $4.1 million, or 11%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This savings is primarily related to converting some of our projects from Renewable Power facilities to RNG facilities.
 Project development and start up costs increased by $14.2 million or 293%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This is primarily due to a $13.9 million increase in virtual pipeline costs for Prince William and ITC transaction related expenses.
 Selling, general, and administrative
 Selling, general, and administrative increased $1.9 million or 4% for the year ended December 31, 2024 compared to the year ended December 31, 2023. This increase was primarily due to increases in corporate spending for professional services, marketing, and support for new RNG facilities.
 Depreciation, amortization, and accretion
 Depreciation, amortization, and accretion expense increased by a total of $3.3 million, or 23%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This change was primarily due to new RNG facilities and OPAL owned dispensing stations, both starting operations in 2024.
 Impairment loss
 Impairment loss increased by a total of $2.0 million, or 100%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This change was primarily due to the impairment of Renewable Energy facility in 2024.

 Income from equity method investments
 Net income attributable to equity method investments increased by $7.7 million, or 140%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This is primarily attributable to Emerald, which had its first full year of operations in 2024 after coming online in the second half of 2023.
 Interest and financing expenses, net increased by $10.3 million, or 111%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This is primarily due to an increase in interest expense on the OPAL Term Loan of $9.8 million primarily due to an increase in outstanding debt, increase of $1.2 million in commitment and other fees, decrease of $1.0 million in interest income, partially offset by a decrease of $1.6 million on the Convertible Note Payable.
 Change in fair value of derivatives, net
 Change in fair value of derivatives, net decreased by $5.8 million, or 78%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This change was attributable primarily to a lower gain in the current year associated with the mark-to-market adjustments to the earnout liabilities. These liabilities were recorded in the consolidated balance sheet upon completion of the Business Combination.
 Other income decreased by $122.3 million, or 98%, for the year ended December 31, 2024 compared to the year ended December 31, 2023. This change is primarily related to a gain $122.9 million recognized on deconsolidation of VIEs, Emerald and Sapphire in 2023.
 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, 2024.
 Loss on warrant exchange
 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. No such loss has been recorded in 2024.
 Net income attributable to redeemable non-controlling interests
 Net income attributable to redeemable non-controlling interests for the year ended December 31, 2024 and 2023 is $2.9 million and $97.4 million, respectively. The net income for the years ended December 31, 2024 and 2023 reflects the net income belonging to OPAL Fuels equity holders based on pro-rata ownership.
 Net income (loss) attributable to non-redeemable non-controlling interests
 Net income (loss) attributable to non-redeemable non-controlling interests for the year ended December 31, 2024 increased by $0.8 million or 227%, compared to the year ended December 31, 2023. This reflects the joint venture partners'

 income (loss) in certain RNG facilities in which we sold a portion of our ownership interests but are consolidated in our financial statements. These entities for the year ended December 31, 2024, were Sunoma and Central Valley. These entities for the year ended December 31, 2023, were Sunoma and Central Valley as well as Emerald, Sapphire for the first five months of 2023. The increase was primarily attributable to higher net income earned by Sunoma.
 Dividends on redeemable preferred non-controlling interests
 The dividends on redeemable preferred non-controlling interests for the year ended December 31, 2024 decreased by $0.5 million or 5%. They carry an 8% dividend payable quarterly. This decrease is primarily due to lower interest accrued on paid-in-kind interest in the current period compared to the same prior-year period as the dividends are being paid quarterly instead of being paid-in-kind.

 Liquidity and Capital Resources
 Liquidity
 As of December 31, 2024, our liquidity was $223.6 million consisting of $178.4 million of unused capacity under our $450 million senior secured credit facility, $20.9 million of unused capacity under the associated revolver, and 24.3 million of cash, cash equivalents. Refer to Note 7.
 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 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.
 On March 3, 2025, OPAL Fuels Intermediate HoldCo LLC, as the borrower (the "Borrower"), certain subsidiaries of the Borrower, as guarantors (the "Guarantors"), the lenders and issuers of letters of credit party thereto and Bank of America, N.A. as the administrative agent (the "Administrative Agent") entered into that certain Amendment No. 1 to Credit and Guarantee Agreement (the "Credit Agreement Amendment"), with respect to that certain Credit and Guarantee Agreement (the "Credit Agreement") dated September 1, 2023, by and among the Borrower, the Administrative Agent, the financial institutions from time to time parties thereto as lenders and as issuers of letters of credit, and the other agents and persons from time to time party thereto (as amended, restated, amended and restated, supplemented or otherwise modified and in effect from time to time).
 The Credit Agreement Amendment makes certain changes to the applicability of certain financial covenants and modifies other covenants to clarify the use of loan proceeds. Additionally, the Credit Agreement Amendment permits the organizational restructuring of the Guarantors in a manner designed to facilitate the sale of federal investment tax credits and the ability to raise additional future capital.
 The Credit Agreement Amendment also eases the conditions precedent to making new Projects eligible for borrowing under the Credit Agreement, extends the availability period for delay draw term loans under the Credit Agreement through March 5, 2026, and extends the commencement of repayment of such term loans until March 31, 2026.

 In connection with the Credit Agreement Amendment, the Borrower paid the Administrative Agent, for the account of each lender, a one-time nonrefundable fee of $1.2 million.
 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 million. Sunoma paid $0.635 million in financing fees. The amounts outstanding under the Sunoma Loan are secured by the assets of Sunoma. On July 19, 2022, Sunoma completed the conversion of the construction loan into a permanent loan and increased the commitment from $20 to $23 million. The maturity date is July 19, 2033. The outstanding loans under the Sunoma Loan Agreement bear interest at an annual fixed rates of 7.8%, and 8.2% per annum during the term.
 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. As of December 31, 2024, Sunoma is in compliance with the financial covenants under the Sunoma Loan Agreement.
 As of December 31, 2024 and December 31, 2023, the outstanding loan balance (current and non-current) excluding deferred financing costs was $20.8 and $22.5 million, respectively.
 The significant assets of Sunoma are parenthesized in the consolidated balance sheets as of December 31, 2024 and December 31, 2023. See Note 12. Variable Interest Entities for additional information.
 Redeemable Series A Preferred Units of OPAL Fuels LLC
 In November 2021, NextEra subscribed for an aggregate of $100,000,000 of Series A preferred units issued by OPAL Fuels LLC. The Series A preferred units have limited rights to prevent OPAL Fuels LLC 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 disposition of assets and (iv) major acquisition of assets outside of OPAL Fuels LLC's primary business. The Series A 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 was allowed to elect to issue additional Series A preferred units ( paid-in-kind) in lieu of cash for the first eight dividend payment dates. As of December 31, 2024 and 2023, there was accrued preferred dividend payable of $0 and $2,013, respectively.
 At any time after issuance, OPAL Fuels LLC may redeem the Series A preferred units for a price equal to original issue price of $100 per unit plus any accrued and unpaid dividends. Upon written notice from NextEra at any time after November 29, 2025, we would be required to redeem the Series A preferred units. In the event the Company does not redeem the Series A preferred units when requested, Nextera will have the following rights and remedies: (1) NextEra's affiliate may extend the RNG Marketing Agreement by 12 months; or (2) the dividend rate would increase depending on the length of time the Series A preferred units remain unredeemed to up to 20% per annum, and if more than $25,000,000 preferred equity is outstanding for more than six months after November 29, 2025, NextEra may appoint a director to OPAL Fuel Inc.'s Board of Directors; or (3) NextEra may convert the Series A preferred equity into common equity of the OPAL Fuels LLC at a conversion price at a 20% to 30% discount to their value (the discount is 20% during the first 12 months after November 29, 2025, 25% for the next 12 months thereafter and 30% thereafter).
 Cash Flows
 The following table presents the Company's cash flows for the years ended December 31, 2024 and 2023:

 2024
 2023

 Net cash provided by operating activities

 $
 33,033
 $
 38,269

 Net cash used in investing activities
 (134,551)
 (74,147)

 Net cash provided by financing activities
 83,504
 5,899

 Net decrease in cash, restricted cash, and cash equivalents

 $
 (18,014)
 $
 (29,979)

 Net Cash Provided by Operating Activities
 Net cash provided by operating activities for the year ended December 31, 2024 was $33.0 million, a decrease of $5.2 million compared to net cash used in operating activities of $38.3 million for the year ended December 31, 2023. The decrease in cash provided by operating activities was primarily due to lower year over year operating income of $112.7 million and a negative working capital changes of $16.6 million offset by increase of $122.3 million in non-cash expenses and $2.1 million increase of portion of distributions from equity method investments allocated to operating activities.
 Net Cash Used in Investing Activities
 Net cash used in investing activities for the year ended December 31, 2024 was $134.6 million, an increase of $60.4 million compared to the $74.1 million used in investing activities for the year ended December 31, 2023. This was primarily driven by a decrease in cash from sale of short term investments of $45.2 million, higher payments made for the construction of various RNG generation and dispensing facilities in 2024 compared to 2023 of $13.4 million, an increase of $13.3 million in contributions to equity method investments, a $0.5 million decrease in distributions from equity method investments, offset by a decrease from deconsolidation of VIEs of $11.9 million in 2023.
 Net Cash Provided by Financing Activities
 Net cash provided by financing activities for the year ended December 31, 2024 was $83.5 million, an increase of $77.6 million compared to the $5.9 million provided by financing activities for the year ended December 31, 2023. This increase was primarily driven by an increase of $158.9 million due to lower repayments on the Senior Secured Facility, the Convertible Note payable and OPAL Term Loan facilities in current year, an increase of $16.4 million due to no payment on termination of put options in current year, an increase of $3.4 million due to lower preferred dividend payments in the current year, offset by a $87.2 million decrease in proceeds from the OPAL Term Loan, net of issuance costs, decrease in proceeds from non-controlling interests of $12.8 million, and a decrease of $0.8 million in reimbursement of financing costs by a joint venture partner.
 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, 2024, we currently anticipate spending approximately $194 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, 2024, our Co-Chief Executive Officers and 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, 2024.
 Changes in Internal Control Over Financial Reporting
 There were no changes in our internal control over financial reporting during the quarter ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 ITEM 9B. OTHER INFORMATION

 Insider Trading Arrangements
 During the fiscal quarter ended December 31, 2024, 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."
 Wasatch Resource Recovery Facility
 On March 17, 2025, Fortistar, through its subsidiary Wasatch RNG LLC ("Wasatch RNG"), acquired all of the limited liability company interests outstanding in Alpro SD, LLC ("Alpro" and such acquired interest, the "Alpro Interest"). Alpro owns a 50% limited liability company interest in Wasatch Resource Recovery, LLC (the "Project" or "Wasatch" and such ownership interest, the "Wasatch Interest") and a 50% tenancy-in-common interest in certain real estate and operating assets used by Wasatch (the "Project Interest"). As a result of the acquisition, Wasatch RNG has the option to increase the Wasatch Interest and the Project Interest.
 The Project captures and converts biogas generated from food waste to produce pipeline quality renewable natural gas (RNG). The Project generates revenue from long-term contracted gas sales, tipping fees, and digestate (fertilizer) sales. The conversion of food waste to RNG presents a potential growth and diversification opportunity for OPAL Fuels.
 In connection with the acquisition, Fortistar Services 2 LLC and OPAL Fuels LLC entered into an amendment to its existing Administrative Services Agreement, pursuant to which OPAL Fuels will provide certain services to Wasatch RNG in exchange for certain agreed upon fees and expense reimbursements. These services include oversight of the plan to improve the operations and productivity of the Project.
 Additionally, Wasatch RNG and OPAL Fuels entered into an Option Agreement, pursuant to which Wasatch RNG granted an option to OPAL Fuels to purchase the Alpro Interest. The exercise period of the option commenced upon closing of the acquisition and will terminate on the third anniversary of the closing of the acquisition, or ninety days following a change of control of OPAL Fuels. The exercise price of the option would be determined such that Wasatch RNG would earn an internal rate of return on its invested capital of 10% percent per year if the option is exercised in the first year, 15% per year if exercised in the second year, and 20% per year if exercised in the third year.
 On March 3, 2025, OPAL Fuels Intermediate HoldCo LLC, as the borrower (the "Borrower"), certain subsidiaries of the Borrower, as guarantors (the "Guarantors"), the lenders and issuers of letters of credit party thereto and Bank of America, N.A. as the administrative agent (the "Administrative Agent") entered into that certain Amendment No. 1 to Credit and Guarantee Agreement (the "Credit Agreement Amendment"), with respect to that certain Credit and Guarantee Agreement (the "Credit Agreement") dated September 1, 2023, by and among the Borrower, the Administrative Agent, the financial institutions from time to time parties thereto as lenders and as issuers of letters of credit, and the other agents and persons from time to time party thereto (as amended, restated, amended and restated, supplemented or otherwise modified and in effect from time to time).
 The Credit Agreement Amendment makes certain changes to the applicability of certain financial covenants and modifies other covenants to clarify the use of loan proceeds. Additionally, the Credit Agreement Amendment permits the organizational restructuring of the Guarantors in a manner designed to facilitate the sale of federal investment tax credits and the ability to raise additional future capital.
 The Credit Agreement Amendment also eases the conditions precedent to making new Projects eligible for borrowing under the Credit Agreement, extends the availability period for delay draw term loans under the Credit Agreement through March 5, 2026, and extends the commencement of repayment of such term loans until March 31, 2026.
 In connection with the Credit Agreement Amendment, the Borrower paid the Administrative Agent, for the account of each lender, a one-time nonrefundable fee of $1.2 million.

 ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 Not applicable.

 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 2025 annual meeting of shareholders, to be filed within 120 days after December 31, 2024, 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 2025 annual meeting of shareholders, to be filed within 120 days after December 31, 2024, 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 2025 annual meeting of shareholders, to be filed within 120 days after December 31, 2024, 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 2025 annual meeting of shareholders, to be filed within 120 days after December 31, 2024, 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 2025 annual meeting of shareholders, to be filed within 120 days after December 31, 2024, and is incorporated by reference to this Form 10-K.

 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*"

 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).

 4.2*"

 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).

 4.3*"

 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*

 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).

 10.15*

 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).

 10.16*

 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).

 10.17*

 Promissory Note, dated as of May 16, 2022, by and between Arclight and Arclight CTC Holdings II, L.P. (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q filed by the Company on August 10, 2022).

 10.18*

 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).

 10.19*

 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).

 10.20*

 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).

 10.21*+#

 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).

 10.22*+#

 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).

 10.23*+#

 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).

 10.24*+#

 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).

 10.25*+#

 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).

 10.26*+#

 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).

 10.27*+#

 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).

 10.28*+#

 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).

 10.29*

 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).

 10.30*

 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).

 10.31*

 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).

 10.32*

 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).

 10.33*

 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).

 10.34*

 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).

 10.35*

 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).

 10.36*

 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).

 10.37*

 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).

 10.38*

 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).

 10.39*

 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).

 10.40*

 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).

 10.41*

 First Amendment to Amended and Restated Credit and Guaranty Agreement, dated March 5, 2024, by and among Paragon RNG LLC, as Borrower, the guarantors, the lenders party thereto, and Bank of Montreal, as administrative agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on March 11, 2024).

 10.42*

 First Amendment to Depositary Agreement, dated March 5, 2024, by Paragon RNG LLC, as Borrower, Bank of Montreal, as administrative agent, and Wilmington Trust, National Association, as collateral agent and depositary agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by the Company on March 11, 2024).

 10.43+*

 First Amendment to Landfill Gas Purchase Agreement, dated March 27, 2024 (effective as of March 6, 2024) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on March 28, 2024).

 10.44+*

 Lease and Access Agreement, dated March 27, 2024 (effective as of March 20, 2024) (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by the Company on March 28, 2024).

 10.45+#*

 Tax Credit Purchase Agreement, dated September 13, 2024 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on September 19, 2024).

 10.46*

 Guaranty, dated September 13, 2024 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by the Company on September 19, 2024).

 10.47
 Amendment No. 1 to Credit and Guarantee Agreement, dated March 3, 2025 by and among OPAL Fuels Intermediate HoldCo LLC, as Borrower, the Guarantors, the Lenders, the LC Issuers, and Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company on March 5, 2025).

 19.1
 Insider Trading Policy

 21.1*

 List of subsidiaries of the registrant (incorporated by reference to Exhibit 21.1 to the Annual Report on Form 10-K filed by the Company on March 17, 2025).

 23.1
 Consent of BDO USA, P.C, independent registered accounting firm.

 24.1
 Power of Attorney (included on the signature page of this Annual Report on Form 10-K).

 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 (incorporated by reference to Exhibit 97.1 to the Annual Report on Form 10-K filed by the Company on March 15, 2024).

 101.INS

 101.SCH

 101.CAL

 101.LAB

 101.PRE

 101.DEF

 *
 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.

 March 17, 2025

 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, Kazi Hasan 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

 /s/ Betsy L. Battle

 Betsy L. Battle

 /s/ Scott Dols

 Scott Dols

 /s/ Kevin M. Fogarty

 Kevin M. Fogarty

 /s/ James Martell

 James Martell

 /s/ Nadeem Nisar

 Nadeem Nisar

 /s/ Ashok Vemuri

 Ashok Vemuri

 /s/ Adam Comora
 Co-Chief Executive Officer

 Adam Comora

 /s/ Jonathan Maurer
 Co-Chief Executive Officer

 Jonathan Maurer

 /s/ Kazi Hasan

 Chief Financial Officer

 Kazi Hasan

 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 Report of Independent Registered Public Accounting Firm (BDO USA, P.C; Melville, NY; PCAOB ID No. 243)

 Consolidated Balance Sheets as of December 31, 2024 and 2023

 Consolidated Statements of Operations for the years ended December 31, 2024 and 2023

 Consolidated Statements of Comprehensive Income for the years ended December 31, 2024 and 2023

 Consolidated Statements of Changes in Redeemable non-controlling interests, Redeemable preferred non-controlling interest and Stockholders' (Deficit) Equity for the years ended December 31, 2024 and 2023

 Consolidated Statements of Cash Flows for the years ended December 31, 2024 and 2023

 Notes to Consolidated Financial Statements

 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, 2024 and 2023, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2024, 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, the Company has 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.
 Melville, NY
 March 17, 2025

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

2024

 Assets

 Current assets:

 Cash and cash equivalents (includes $ 358 and $ 166 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 $
 24,310
 $
 38,348

 Accounts receivable, net (includes $ 435 and $ 33 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 32,013
 27,623

 Accounts receivable, related party
 14,522
 18,696

 Restricted cash - current (includes $ 972 and $ 4,395 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 4,395

 Short term investments
 —
 9,875

 Fuel tax credits receivable
 5,639
 5,345

 Contract assets
 11,075
 6,790

 Parts inventory (includes $ 29 and $ 29 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 10,294
 10,191

 Convertible note receivable
 —

 Environmental credits held for sale
 6,314

 Prepaid expense and other current assets (includes $ 144 and $ 107 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 11,051
 6,005

 Derivative financial assets, current portion

 Total current assets
 117,188
 128,073

 Capital spares
 4,380
 3,468

 Property, plant, and equipment, net (includes $ 25,428 and $ 26,626 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 458,258
 339,493

 Operating right-of use assets
 12,731
 12,301

 Investment in other entities
 223,594
 207,099

 Note receivable - variable fee component
 2,509
 2,302

 Derivative financial assets, non-current portion
 —

 Other long-term assets
 2,085
 1,162

 Intangible assets, net
 1,330
 1,604

 Restricted cash - non-current (includes $ 2,315 and $ 1,850 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 3,946
 4,499

 Goodwill
 54,608
 54,608

 Total assets
 $
 881,077
 $
 754,609

 Liabilities and Equity

 Current liabilities:

 Accounts payable (includes $ 22 and $ 744 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 16,419
 13,901

 Accounts payable, related party (includes $ 426 and $ 1,046 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 7,932
 7,024

 Fuel tax credits payable
 4,422
 4,558

 Accrued payroll (includes $ 45 and $ — at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 9,580
 9,023

 Accrued capital expenses

 23,238
 15,128

 Accrued environmental credit rebates

 5,391
 4,057

 Accrued expenses and other current liabilities (includes $ 974 and $ 647 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 9,529
 10,188

 Contract liabilities
 9,276
 6,314

 OPAL Term Loan, current portion
 10,865
 —

 Sunoma loan, current portion (includes $ 1,756 and $ 1,608 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 1,756
 1,608

 Derivative financial liability, current portion
 —

 Operating lease liabilities - current portion

 Other current liabilities (includes $ — and $ 92 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 1,595

 Asset retirement obligation, current portion
 2,804
 1,812

 Total current liabilities
 103,596
 74,343

 Asset retirement obligation, non-current portion
 5,082
 4,916

 OPAL Term Loan, net of debt issuance costs
 266,630
 176,532

 Sunoma loan, net of debt issuance costs (includes $ 18,373 and $ 20,010 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 18,373
 20,010

 Operating lease liabilities - non-current portion
 12,155
 11,824

 Earn out liabilities
 1,900

 Derivative liabilities - non-current portion
 —

 Other long-term liabilities (includes $ 2,495 and $ 211 at December 31, 2024 and December 31, 2023, respectively, related to consolidated VIEs)

 9,842
 7,599

 Total liabilities
 416,045
 297,124

 Commitments and contingencies

 Redeemable preferred non-controlling interests
 130,000
 132,617

 Redeemable non-controlling interests
 482,863
 802,720

 Stockholders' (deficit) equity

 Class A common stock, $ 0.0001 par value, 340,000,000 shares authorized as of December 31, 2024; shares issued: 30,065,260 and 29,701,146 at December 31, 2024 and December 31, 2023, respectively; shares outstanding: 28,429,477 and 28,065,363 at December 31, 2024 and December 31, 2023

 Class B common stock, $ 0.0001 par value, 160,000,000 shares authorized as of December 31, 2024; 71,500,000 and none issued and outstanding as of December 31, 2024 and December 31, 2023

 —

 Class C common stock, $ 0.0001 par value, 160,000,000 shares authorized as of December 31, 2024; No ne issued and outstanding as of December 31, 2024 and December 31, 2023

 —
 —

 Class D common stock, $ 0.0001 par value, 160,000,000 shares authorized as of December 31, 2024; 72,899,037 and 144,399,037 issued and outstanding at December 31, 2024 and December 31, 2023

 Additional paid-in capital
 —
 —

 Accumulated deficit
 ( 137,004)
 ( 467,195)

 Accumulated other comprehensive (loss) income
 ( 15)

 Class A common stock in treasury, at cost; 1,635,783 and 1,635,783 shares at December 31, 2024 and December 31, 2023, respectively

 Total Stockholders' (deficit) equity attributable to the Company
 ( 148,449)
 ( 478,807)

 Non-redeemable non-controlling interests

 Total Stockholders' (deficit) equity
 ( 147,831)
 ( 477,852)

 Total liabilities, Redeemable preferred, Redeemable non-controlling interests and Stockholders' (deficit) equity

 $
 881,077
 $
 754,609

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

 CONSOLIDATED STATEMENTS OF OPERATIONS
 (In thousands of U.S. dollars, except per unit data)

 2024
 2023

 Revenues:

 RNG fuel (includes revenues from related party of $ 68,416 and $ 56,069 for the years ended December 31, 2024 and 2023, respectively)

 $
 $

 Fuel Station Services (includes revenues from related party of $ 38,841 and $ 28,468 for the years ended December 31, 2024 and 2023, respectively)

 Renewable Power (includes revenues from related party of $ 6,912 and $ 6,614 for the years ended December 31, 2024 and 2023, respectively)

 Total revenues

 Operating expenses:

 Cost of sales - RNG fuel
 38,552
 32,028

 Cost of sales - Fuel Station Services

 128,804
 115,322

 Cost of sales - Renewable Power
 32,495
 36,550

 4,866

 Selling, general, and administrative
 53,124
 51,262

 Depreciation, amortization, and accretion
 17,885
 14,565

 Impairment loss

 2,016
 —

 Income from equity method investments
 ( 13,235)
 ( 5,525)

 Total expenses
 278,750
 249,068

 Operating income

 21,222
 7,040

 Other (expense) income:

 ( 19,610)
 ( 9,306)

 Change in fair value of derivative instruments, net
 1,596
 7,346

 2,211
 124,472

 Loss on debt extinguishment
 —
 ( 2,190)

 Loss on warrant exchange
 —
 ( 338)

 Income before provision for income taxes
 5,419

 Income tax benefit

 8,906
 —

 Net income attributable to redeemable non-controlling interests
 2,851
 97,426

 Net income (loss) attributable to non-redeemable non-controlling interests

 ( 349)

 Dividends on Redeemable preferred non-controlling interests (1)

 10,470
 11,011

 Net income attributable to Class A common stockholders
 $
 $
 18,936

 Weighted average shares outstanding of Class A common stock:

 Basic
 27,617,335
 27,148,538

 Diluted
 27,694,650
 27,494,016

 Per share amounts:

 Basic
 $
 0.02
 $
 0.70

 Diluted
 $
 0.02
 $
 0.69

 (1) Dividends on redeemable preferred non-controlling interests is allocated between redeemable non-controlling interests and Class A common stockholders based on their weighted average percentage of ownership. Please see Note. 13 Redeemable non-controlling interests, redeemable preferred non-controlling interests and Stockholders' Deficit for additional information.
 The accompanying notes are an integral part of these consolidated financial statements.

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 (In thousands of U.S. dollars)

 2024
 2023

 $
 $

 Other comprehensive income (loss):

 Effective portion of the cash flow hedge attributable to equity method investments
 ( 8)

 Reclassification adjustments included in earnings (1)

 —
 ( 1,146)

 Net unrealized gain (loss) on cash flow hedges

 ( 142)

 Total other comprehensive income (loss)

 1,017
 ( 1,296)

 Total comprehensive income
 15,342
 125,728

 Less:

 Net income attributable to Redeemable non-controlling interests(2)

 11,598
 106,645

 Other comprehensive income (loss) attributable to Redeemable non-controlling interests

 ( 1,086)

 Comprehensive income (loss) attributable to Non-redeemable non-controlling interests

 ( 349)

 Dividends on Redeemable preferred non-controlling interests
 1,722
 1,792

 Comprehensive income attributable to Class A common stockholders
 $
 $
 18,726

 (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.
 (2) Includes $ 8,748 and $ 9,219 of dividends on redeemable preferred non-controlling interests for the year ended December 31, 2024 and 2023, respectively.
 The accompanying notes are an integral part of these consolidated financial statements.

 CONSOLIDATED STATEMENTS OF CHANGES IN REDEEMABLE NON-CONTROLLING INTEREST, REDEEMABLE PREFERRED NON-CONTROLLING INTEREST AND STOCKHOLDERS' DEFICIT
 (In thousands of U.S. dollars, except per unit data)
 Class A common stock
 Class B common stock
 Class D common stock
 Class A common stock in treasury
 Mezzanine Equity

 Shares
 Shares
 Shares
 Additional paid-in capital
 Accumulated deficit
 Accumulated other comprehensive income (loss)

 Non-redeemable non-controlling interests
 Shares
 Total Stockholders' Deficit

 Redeemable Preferred non-controlling interests
 Redeemable non-controlling interests

 December 31, 2022
 29,477,766

 144,399,037
 —
 ( 800,813)
 26,445
 —
 —
 ( 774,156)
 138,142
 1,013,833

 —
 —
 —
 —
 —
 —
 —
 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
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 Cancellation of fractional shares on warrant exchange
 ( 26)
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 Exercise of put option on forward purchase contract - Meteora
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 ( 1,635,783)
 —
 —

 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 (3)

 90,103
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 Stock-based compensation
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 4,943

 Proceeds from non-redeemable non-controlling interest
 —
 —
 —
 —
 —
 —
 2,899
 —
 —
 9,854
 —
 —
 12,753
 —
 —

 Deconsolidation of entities (2)

 —
 —
 —
 —
 —
 —
 ( 1,383)
 —
 —
 ( 34,662)
 —
 —
 ( 36,045)
 —
 —

 Distributions to non-redeemable non-controlling interests
 —
 —
 —
 —
 —
 —
 —
 —
 —
 ( 333)
 —
 —
 ( 333)
 —
 —

 Payment of paid-in-kind preferred dividends
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 ( 16,536)
 —

 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
 $
 —
 $
 —
 144,399,037
 $
 $
 —
 $
 ( 467,195)
 $
 ( 15)
 $
 ( 1,635,783)
 $
 ( 477,852)
 $
 132,617
 $
 802,720

 —
 —
 —
 —
 —
 —
 —
 2,284
 —
 —
 —
 2,727
 —
 11,598

 Other comprehensive income
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 Issuance of Class A common stock under the ATM program (3)

 36,353
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —

 Issuance of Class A common stock for vesting of equity awards (1)

 327,761
 —
 —
 —
 —
 —
 ( 627)
 —
 —
 —
 —
 —
 ( 627)
 —
 —

 Share conversion
 —
 —
 71,500,000
 ( 71,500,000)
 ( 7)
 —
 —
 —
 —
 —
 —
 —
 —

 Stock-based compensation
 —
 —
 —
 —
 —
 —
 1,061
 —
 —
 —
 —
 —
 1,061
 —
 5,391

 Distributions to non-redeemable non-controlling interests
 —
 —
 —
 —
 —
 —
 —
 —
 ( 780)
 —
 —
 ( 703)
 —
 —

 Dividends on redeemable preferred non-controlling interests
 —
 —
 —
 —
 —
 —
 —
 ( 1,722)
 —
 —
 —
 —
 ( 1,722)
 10,470
 ( 8,748)

 Change in redemption value of Redeemable non-controlling interests
 —
 —
 —
 —
 —
 —
 ( 681)
 329,629
 —
 —
 —
 —
 328,948
 —
 ( 328,948)

 Payment of preferred dividend
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 ( 13,087)
 —

 30,065,260
 $
 71,500,000
 72,899,037
 $
 $
 —
 $
 ( 137,004)
 $
 $
 ( 1,635,783)
 $
 ( 147,831)
 $
 130,000
 $
 482,863

 (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) 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 Investments—Equity Method and Joint Ventures. Please see Note 3. Investment in Other Entities and Note 12. Variable Interest Entities for additional information.
 (3) During the years ended December 31, 2024 and December 31, 2023, the Company issued 36,353 and 90,103 shares of Class A common stock under the Company's ATM program. Please see Note 2. Summary of Significant Accounting Policies and Note 13. Redeemable non-controlling interests, Redeemable preferred non-controlling interests and Stockholders' Deficit for additional information.
 The accompanying notes are an integral part of these consolidated financial statements.

 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (In thousands of U.S. dollars)

 2024
 2023

 Cash flows from operating activities:

 $
 $

 Adjustments to reconcile net income to net cash provided by (used in) operating activities:

 Income from equity method investments
 ( 13,235)
 ( 5,525)

 Gain from disposal of plant and equipment

 ( 311)
 —

 Distributions from equity method investments
 14,336
 12,242

 Change in fair value of Convertible note receivable

 ( 10)
 —

 Impairment of property, plant and equipment

 2,016
 —

 Loss on warrant exchange

 —

 Depreciation and amortization
 17,450
 14,044

 Amortization of deferred financing costs
 1,094
 1,720

 Amortization of operating lease right-of-use assets

 Loss on debt extinguishment
 —
 2,190

 Accretion expense related to asset retirement obligation

 Stock-based compensation
 6,452
 5,904

 Provision for bad debts

 Paid-in-kind interest income
 ( 207)
 ( 360)

 Change in fair value of commodity swaps

 —

 Change in fair value of Convertible Note Payable
 —
 1,579

 Change in fair value of the earnout liabilities
 ( 1,596)
 ( 6,890)

 Unrealized gain on derivative financial instruments
 —
 ( 270)

 Gain on deconsolidation of VIEs
 —
 ( 122,873)

 Changes in operating assets and liabilities:

 Accounts receivable
 ( 4,475)
 2,942

 Accounts receivable, related party
 4,174
 ( 6,275)

 Fuel tax credits receivable
 ( 294)
 ( 1,201)

 Capital spares
 ( 912)
 ( 25)

 Parts inventory
 ( 103)
 ( 2,880)

 Environmental credits held for sale
 ( 6,142)
 1,502

 Prepaid expense and other current and long-term assets

 ( 5,312)
 2,200

 Contract assets
 ( 4,285)
 2,981

 Accounts payable
 2,519
 6,686

 1,228

 Fuel tax credits payable
 ( 136)
 1,238

 Accrued payroll

 Accrued expenses
 3,273

 Operating lease liabilities - current and non-current
 ( 636)
 ( 613)

 Asset retirement obligations
 —
 ( 49)

 Other current and non-current liabilities
 1,917
 ( 1,910)

 Contract liabilities
 2,961
 ( 1,699)

 Net cash provided by operating activities

 33,033
 38,269

 Cash flows from investing activities:

 Purchase of property, plant, and equipment
 ( 127,239)
 ( 113,826)

 Proceeds from disposal of plant and equipment

 —

 Deconsolidation of VIEs, net of cash
 —
 ( 11,947)

 Proceeds from sale of short term investments

 9,875
 55,101

 Cash paid for investment in other entities
 ( 21,570)
 ( 8,314)

 Cash paid for Notes receivable
 ( 750)
 —

 Distributions received from equity method investment
 4,305
 4,839

 Net cash used in investing activities
 ( 134,551)
 ( 74,147)

 Cash flows from financing activities:

 Proceeds from OPAL Term Loan
 100,000
 196,617

 Financing costs paid to other third parties
 ( 629)
 ( 10,264)

 Repayment of Senior Secured Credit Facility
 —
 ( 22,750)

 Repayment of Convertible Note Payable
 —
 ( 30,107)

 Repayment of OPAL Term Loan
 —
 ( 106,090)

 Repayment of Sunoma Loan
 ( 1,621)
 ( 546)

 Repayment of Municipality loan
 —
 ( 76)

 Repayment of finance lease liabilities
 —
 ( 993)

 Proceeds from equipment loan
 —

 Proceeds from sale of non-redeemable non-controlling interest

 —
 12,753

 Reimbursement of financing costs by joint venture partner
 —

 Payment of preferred dividends

 ( 13,086)
 ( 16,536)

 Cash paid for taxes related to net share settlement of equity awards
 ( 627)
 ( 896)

 Cash paid for purchase of shares upon exercise of put option
 —
 ( 16,391)

 Distribution to non-redeemable non-controlling interest
 ( 703)
 ( 333)

 Proceeds from issuance of shares of Class A common stock under the ATM program, net

 Net cash provided by financing activities
 83,504
 5,899

 Net decrease in cash, restricted cash, and cash equivalents

 ( 18,014)
 ( 29,979)

 Cash, restricted cash, and cash equivalents, beginning of period
 77,221

 Cash, restricted cash, and cash equivalents, end of period
 $
 29,228
 $

 Supplemental disclosure of cash flow information

 Income taxes paid

 $
 $
 —

 Interest paid, net of $ 3,212 and $ 5,475 capitalized, respectively

 $
 22,907
 $
 6,929

 Noncash investing and financing activities:

 Fair value of Class A common stock issued for redemption of Public and Private warrants
 $
 —
 $

 Accrual for asset retirement obligation included in Property, plant and equipment
 $
 $
 —

 Right-of-use assets arising from lease modifications
 $
 1,109
 $
 —

 Paid-in-kind dividend on redeemable preferred non-controlling interests
 $
 —
 $
 2,617

 Right-of-use assets for finance leases included in Property, Plant and equipment, net

 $
 2,403
 $
 9,049

 Accrual for purchase of Property, plant and equipment included in Accounts payable and Accrued capital expenses
 $
 23,238
 $
 15,128

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

 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 electricity from renewable sources ("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. The term "Environmental Attributes" refers to federal, state and local government incentives in the United States, provided in the form of renewable identification numbers ("RINs"), RECs, LCFS credits, ISCC Carbon Credits, rebates, tax credits and other incentives to end users, distributors, system integrators and manufacturers of renewable energy projects. 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 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 three operating segments based on the characteristics and the nature of products and services. The three operating segments are - RNG Fuel, Fuel Station Services and Renewable Power.
 All amounts in these footnotes are presented in thousands of dollars except share and 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), Sunoma Holdings, LLC ("Sunoma"), Central Valley LLC ("Central Valley"), Reynolds RNG LLC ("Reynolds"), Beacon RNG LLC ("Beacon"), New River LLC ("New River"), Prince William RNG LLC ("Prince William"), Cottonwood RNG LLC ("Cottonwood"), 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 audited 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.
 The Company reclassified certain Asset retirement obligations from current to non-current in its consolidated balance sheet as of December 31, 2023.
 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 Consolidation 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 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.
 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.
 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.
 As of December 31, 2024 and 2023, the Company accounted for its ownership interests in Pine Bend RNG LLC ("Pine Bend"), Noble Road RNG LLC ("Noble Road"), Paragon RNG LLC ("Paragon"), Emerald RNG LLC ("Emerald"), Sapphire RNG LLC ("Sapphire"), Land2Gas LLC (the "SJI Joint Venture"), Atlantic RNG LLC ("Atlantic"), Burlington RNG LLC ("Burlington") and GREP BTB Holdings LLC ("GREP") under the equity method.
 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, and the fair value of derivative instruments. Actual results could differ from those estimates.
 Accounting Pronouncements Adopted
 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 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 adopted ASU 2023-07 in the year ended December 31, 2024 and applied the standard retrospectively for all periods presented. Please see Note 11. Reportable Segments, for additional information.
 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 adopted ASU 2023-06 in the year ended

 December 31, 2024. The adoption did not have a material effect on the Company's financial position, results of operations, cash flows or disclosures.
 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 adopted ASU 2023-01 in the year ended December 31, 2024. The adoption did not have a material effect on the Company's financial position, results of operations, cash flows or disclosures.
 Accounting Pronouncements Not Yet Adopted
 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 December 2023, the FASB issued Accounting Standards Update No. 2023-09, Income Taxes ("Topic 740"): Improvements to Income Tax Disclosures, to enhance the transparency and decision usefulness of income tax disclosures in order to provide information to assist key stakeholders in better assessing how the Company's operations and related tax risks and tax planning and operational opportunities affect the Company's tax rate and prospects for future cash flows. The standard requires disaggregated information about a reporting entity's effective tax rate reconciliation as well as information on income taxes paid. This ASU becomes effective for public companies for annual periods beginning after December 15, 2024. Early adoption is permitted for annual financial statements that have not yet been issued or made available for issuance. The Company is currently evaluating the impact this ASU will have on its consolidated financial statements and related disclosures.
 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.
 Cash, Cash Equivalents, and Restricted Cash
 Cash and cash equivalents primarily consist of money market accounts, cash on deposit with banks and highly liquid investments with original maturities of three months or less from the date of purchase.
 Cash, cash equivalents, and restricted cash consisted of the following as of December 31, 2024 and December 31, 2023:

2024
2023

 Current assets:

 Cash and cash equivalents
 $
 24,310
 $
 38,348

 Restricted cash - current (1)

 4,395

 Long-term assets:

 Restricted cash - non - current (2)

 3,946
 4,499

 Total cash, cash equivalents, and restricted cash
 $
 29,228
 $

 (1) Restricted cash - current as of December 31, 2024 consists of $ 972 related to debt reserve on Sunoma Loan. Restricted cash - current as of December 31, 2023 consists of $ 3,361 related to debt reserve on the Sunoma Loan and $ 1,034 related to deposit on our interconnections payments. Restricted cash is classified as short term when the restriction is expected to be lifted within 12 months.
 (2) Restricted cash - non - current as of December 31, 2024 includes restricted cash held as collateral related to the collateral requirements on our debt facilities and gas security deposit. Restricted cash - non - current as of December 31, 2023 includes restricted cash held as collateral related to 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 but less than one year at the time of purchase to be short term investments. The short term investments of $ — and $ 9,875 as of December 31, 2024 and December 31, 2023, respectively. 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 Liabilities
 In connection with the business combination completed in July 2022 ("Business Combination") and pursuant to a sponsor letter agreement, ArcLight CTC Holdings II, L.P. agreed to subject 10 % of its Class A common stock (received as a result of the conversion of its ArcLight Class B 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. As of December 31, 2024 and 2023 number of shares subject to forfeiture was 716,650 (the "Sponsor Earnout Awards"). The 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.
 OPAL Fuels equity holders were 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 "Opal Earnout Awards"). Earn-out events were not achieved as of December 31, 2024 and the earnout award has been expired.
 For the years ended December 31, 2024 and December 31, 2023, the Company recorded total gains from Earnout Awards of $ 1,596 and $ 6,890, respectively, in its consolidated statements of operations. As of December 31, 2024 and December 31, 2023, the Company recorded a Sponsor Earnout liability of $ 304 and $ 1,900, respectively, on its consolidated balance sheets.
 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 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 down to their maximum redemption value if necessary, with an offset in Stockholders' equity. As of December 31, 2024, the maximum redemption value was $ 482,863.
 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. Forfeitures are recognized as they occur. Please see Note 16. Stock-based Compensation, for additional information.
 Project development and startup 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, 2024 and 2023, 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:

 2024
 2023

 Virtual pipeline costs (1)

 $
 14,769
 $
 1,295

 Site lease expenses
 1,142
 1,021

 Legal and professional fees
 2,114
 1,141

 Royalties
 —

 Other
 1,084

 Total Project development and startup costs

 $
 $
 4,866

 (1) Relates to virtual pipeline costs on our Prince William facility. These are temporary transportation costs incurred until a permanent pipeline is completed, which we currently anticipate in the second half of 2025.
 Net income per share
 The basic income per share of Class A common stock is computed by dividing the net income (loss) attributable to Class A common stockholders by the weighted average number of Class A common stock outstanding during the period.
 The Class B common stock and D common stock do 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 B common stock and Class D common stock under the two-class method has not been presented.
 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 for which the Company has an unconditional right to payment. The accounts receivable are the net estimate realizable value between the invoiced accounts receivable and allowance for credit losses. 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 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 did not have an allowance for credit losses as of December 31, 2024 and December 31, 2023.
 Fuel Tax Credit Receivable/Payable
 At December 31, 2024, the Company accrued federal fuel tax credits of $ 0.50 per gasoline gallon equivalent of CNG that the Company sold as vehicle fuel in 2024. At December 31, 2024 and 2023, fuel tax credits receivable were $ 5,639 and $ 5,345, 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, 2024 and 2023, the amounts of fuel tax credits owed to customers were $ 4,422 and $ 4,558, 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 is 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. An asset retirement obligation is classified as short-term if it is expected to be settled within one year. If the obligation is expected to be settled beyond one year, it is classified as long-term.
 As of December 31, 2024 and 2023, the Company estimated the value of its total asset retirement obligations to be $ 7,886 and $ 6,728, respectively.
 The changes in the asset retirement obligations were as follows as of December 31, 2024:

2024

 Balance, December 31, 2023 - Current and non-current
 $
 6,728

 Additions during the year
 1,048

 Deletion
 ( 325)

 Accretion expense

 Total asset retirement obligation
 7,886

 Less: current portion
 ( 2,804)

 Total asset retirement obligation, net of current portion
 $
 5,082

 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 ASC 606 Revenue from Contracts with Customers ("ASC 606") 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 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 reader. 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 Energy Marketing, LLC (together with its affiliates, "NextEra") 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 fee per Environmental Attribute in addition to the specified discount. The agreement was effective beginning January 1, 2022. For the years ended December 31, 2024 and 2023, the Company earned net revenues after discount and fees of $ 68,416 and $ 56,069, respectively, under this contract which was recorded as part of Revenues - RNG Fuel. For the years ended December 31, 2024 and 2023, the Company earned net revenues after discount and fees of $ 38,841 and $ 28,468, respectively, which was recorded as part of Revenues - Fuel Station Services.
 During 2020, the Company entered into an agreement with a counterparty to sell LCFSs at one of our RNG facilities for a period of 7 years at a fixed contract price which has a certain predetermined floor and ceiling price per LCFS. The counterparty has the right to apply any excess payment made calculated as the difference between the adjusted Oil Price Information Service price and the floor price per the contract, against future sales of LCFSs during the contract term. Therefore, it includes a variable consideration that is constrained and is incorporated into the contract price only to the extent that it is probable that a significant reversal of the cumulative revenue recognized under the contract will not occur in a future period. As of December 31, 2024, the Company recorded $ 2,185 related to this agreement as part of Other long-term liabilities on the consolidated balance sheet.
 During the third and fourth quarters 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 ("MMBtus"). 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, 2024 and 2023, the Company earned net revenues of $ 16,286 and $ 16,325, respectively under this contract which were recorded as part of Revenues - Renewable Power in the consolidated statement of operations.

 Regulatory changes implemented by the European Union Commission took effect on November 21, 2024 that excluded biomethane produced outside of the European Union from being certified as eligible to be sold in accordance with the European Union Renewable Energy Directive. As a result, all of our contracts governing sales of ISCC Carbon Credits were terminated on November 21, 2024. Following such terminations, we expect to continue to earn revenues from sale of electricity generated by these Renewable Power facilities and the associated Environmental Attributes.
 Starting in October 2024, the Company initiated the generation of Renewable Thermal Certificates ("RTCs"). RTCs are generated from the conversion of biogas to any thermal application (including power generation, heating or otherwise) and work similarly to renewable energy certificates ("RECs") used in electricity markets. RTCs are verified and certified by the Midwest Renewable Energy Tracking System (M-RETS). The M-RETS Renewable Thermal Tracking System issues one RTC for every dekatherm of RNG injected into the gas system.
 Sales of Environmental Attributes such as RINs, RTCs, 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 RECs 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 provides all third-party construction contracts with a warranty, typically for a period of one year after substantial completion of the construction project. Based on the guidance and indicative factors provided by ASC 606, the Company concluded that it offers assurance-type warranties as it does not provide a service to the customer beyond fixing defects that existed at the time of completion. Therefore, these warranties are accounted for under ASC Topic 460, Guarantees ("ASC 460"), and not as a separate performance obligation.
 Generally, the company estimates warranty costs based on historical claims experience, and other factors. Actual warranty claims may differ from the estimates, and adjustments to the liability are made as necessary. The Company accrued $ 171 and $ 132 of warranty reserves under accrued expense and other current liabilities as of December 31, 2024, and December 31, 2023, respectively.
 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.
 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. 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:

 2024
 2023

 Renewable power sales
 $
 25,879
 $
 33,648

 Third party construction
 39,769
 49,318

 Service
 21,807
 16,711

 Brown gas sales
 22,402
 19,587

 Environmental credits (1)

 176,063
 126,573

 Parts sales
 3,769
 4,680

 Other (2)

 1,167

 Total revenue from contracts with customers
 290,856
 251,149

 Lease revenue (3)

 9,116
 4,959

 Total revenue
 $
 $

 (1) Includes revenues of $ 16,286 and $ 16,325 for the years ended December 31, 2024 and 2023, from customers domiciled outside of United States.
 (2) Includes management fee revenues earned from management of operations of equity method entities.
 (3) Lease revenue relates to approximately thirty-five fuel purchasing agreements out 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, 2024 and 2023, 13 % and 19 %, respectively of revenue was recognized over time, and the remainder was for products and services transferred at a point in time.
 The following table shows the items consisting of items recorded as Other income:

 2024
 2023

 Gain on deconsolidation of VIEs (1)

 $
 —
 $
 122,873

 Gain on transfer of non-financial asset in exchange for services received (2)

 1,656
 1,599

 Other

 $
 $
 —

 $
 2,211
 $
 124,472

 (1) Represents non-cash gain on deconsolidation of Emerald and Sapphire on May 30, 2023.
 (2) Represents the fair value of RINs transferred as consideration for services received.
 Contract Balances
 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 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.
 The following table provides information about receivables, contract assets, and contract liabilities from contracts with customers:

2024
2023

 Accounts receivable, net
 $
 32,013
 $
 27,623

 Contract assets:

 Cost and estimated earnings in excess of billings
 8,547
 4,630

 Accounts receivable retainage, net
 2,528
 2,160

 Contract assets total
 $
 11,075
 $
 6,790

 Contract liabilities:

 Billings in excess of costs and estimated earnings
 9,276
 6,314

 Contract liabilities total
 $
 9,276
 $
 6,314

 During the year ended December 31, 2024, the Company recognized revenue of $ 3,746 that was included in "Contract liabilities" at December 31, 2023. 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.
 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 as of December 31, 2024 and 2023, 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 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 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.
 Leases
 Under ASC 842, leases are classified as either finance or operating arrangements, with such classification affecting the pattern and classification of expense recognition in the Company's income statement. Leases consist primarily of operating leases for site leases on landfills/dairy farms, office facilities and finance leases for site leases and vehicles. The Company determines if an arrangement is or contains a lease at inception. The Company accounts for lease and non-lease components as a single lease component and does not recognize right-of-use assets and lease liabilities for leases with a term of 12 months or less.
 Operating and finance lease right-of-use assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. Lease payments consist primarily of the fixed payments under the arrangement, less any lease incentives. The Company generally uses an incremental borrowing rate estimated based on the information available at the lease commencement date or on the date of lease modification, if applicable, to determine the present value of lease payments unless the implicit rate is readily determinable. The Company estimates its incremental borrowing rate based on the rate of interest it would have to pay to borrow on a collateralized basis with an equal lease payment amount, over a similar term, and in a similar economic environment. Generally, the lease term is based on non-cancelable lease term when determining the lease assets and liabilities. The lease terms may include periods under options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option.
 Operating leases are included in operating lease right-of-use assets, operating lease liabilities, current, and operating lease liabilities, non-current on the Company's consolidated balance sheets. Finance leases are included in property and equipment, net, accrued and other current liabilities, and other non-current liabilities on the Company's consolidated balance sheets.
 Operating lease costs are recognized on a straight-line basis over the lease terms. Finance lease assets are amortized on a straight-line basis over the shorter of the estimated useful lives of the assets or the lease terms.
 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 dispensing and credit monetization services to OPAL owned facilities and third-party 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 reviewed to ensure it is recorded at lower of cost and net realizable value at each balance sheet date. Due to the historically higher LCFS pricing, the fair value at contract inception may be significantly higher than the net realizable value of the environmental credits generated at the period-end balance sheet date. For the years ended December 31, 2024 and 2023, the Company recorded $ 10,365 and $ 7,354 as part of Cost of sales - Fuel Station Services in its consolidated statements of operations to adjust environmental credits held for sale to lower of cost and net realizable value.
 Accrued environmental credit rebates
 Accrued environmental credit rebates represent the Company's liabilities for dispensing services provided by third-party vendors. As of December 31, 2024 and 2023, the balance of Accrued environmental credit rebates was $ 5,391 and $ 4,057 respectively.
 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, 2024, the Company had a backlog of $ 66,384.
 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 $ 7,637 and $ 7,240 for the years ended December 31, 2024 and 2023 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 Intangibles – Goodwill and Other. The Company performs its annual test on December 31.
 As of December 31, 2024, $ 51.2 million of the goodwill balance is attributable to the acquisition of Beacon and is included within the RNG segment. Beacon meets the definition of a business under ASC 805 and is considered a reporting unit for goodwill assessment purposes.
 The Company completed its annual goodwill impairment test for the Beacon reporting unit as of December 31, 2024. For this test, the Company bypassed the qualitative assessment and proceeded directly to the quantitative impairment test. The quantitative test used a combination of an income valuation methodology, using a discounted cash flow analysis ("DCF"), and a market valuation methodology, using the guideline public company method. 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. Significant assumptions used in the DCF projection included growth in RIN prices, future sales volumes based on production capacities and a terminal value based on a range of terminal earnings before interest, taxes, depreciation, and amortization. The future cash flows were discounted to present value using a weighted average cost of capital of the company and its closest competitors.
 The results of the quantitative assessment indicated that the fair value of the Company's reporting unit exceeded its carrying amount as of the measurement date, resulting in no impairment loss as of December 31, 2024.
 Intangible Assets and Liabilities
 Identifiable intangible assets consist of three Power Purchase Agreements ("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. The Company recorded $ 2,016 impairment expense for the year ended December 31, 2024. There was no material impairment expense recorded for the year ended December 31, 2023.
 Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, (ii) information available regarding the current market value for such assets and/or (iii) estimates of the costs to replace an asset. We use our best estimates in making these evaluations and consider various factors, including future pricing and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates and the impact of such variations could be material.
 Derivative Instruments
 The Company estimates the fair value of its derivative instruments using available market information in accordance with ASC 820 Fair Value Measurement 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.
 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 and 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
 The Company accounts for income taxes in accordance with ASC Topic 740, Accounting for Income Taxes ("ASC 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.
 We recognize interest and penalties related to unrecognized tax benefits on the interest expense line and other expense line, respectively, in the accompanying consolidated statement of operations. Accrued interest and penalties are included on the related liability lines in the consolidated balance sheet. As of December 31, 2024, the Company does not have any amounts recorded in connection to uncertain tax positions.
 The Company elects to account for investment tax credits using the flow-through method. Under this method, investment tax credits are recognized as a reduction of income tax expense in the period in which the credit is generated. The Company has elected not to defer the recognition of these credits as a deferred tax asset, which would otherwise be recognized under the deferral method. This accounting treatment is in accordance with the applicable financial reporting standards and reflects management's judgment that the flow-through method more accurately represents the economic benefits of the investment tax credits to the Company. During the third quarter of 2024, tax credits generated from the Emerald RNG facility were transferred to a third-party and net proceeds of $ 8,906 from the sale were distributed to The Company. As permitted under the flow-through method, the tax benefit associated with the transfer is recorded as a reduction of income taxes.
 Significant Customers, Vendors and Concentration of Credit Risk
 For the year ended December 31, 2024, two customers accounted for 52 % of revenue. For the year ended December 31, 2023, two customers accounted for 47 % of revenue. At December 31, 2024, two customers accounted for 50 % of accounts receivable. At December 31, 2023, two customers accounted for 54 % 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, 2024, one vendor accounted for 17 % of the accounts payable. As of December 31, 2023, one vendor accounted for 32 % of the accounts payable.
 Investment Tax Credits
 In the third quarter of 2024, the Company sold to a third-party purchaser certain transferable Investment Tax Credits ("ITCs") that had been generated by the Company from its investments in the Renewable Natural Gas segment.
 The Company elected to consider expected transfers of the credits in assessing their realizability as part of the valuation allowance analysis and recognize changes in the estimated proceeds as an adjustment to its valuation allowance. The Company accounted for the ITC sale in accordance with ASC 740 by electing the flow-through method to recognize the ITC benefit when it arises.
 The net proceeds from the sale of tax credits, totaling $ 8,906, were received in cash and recorded as a credit to income tax expense as of December 31, 2024. The cash flows related to the total income tax benefits are presented in the statement of cash flow in the 'Net income (loss)' line item in operating activities. Legal and insurance fees associated with the

 transaction, totaling $ 1,440, consisting of $ 1,182 of buyer's expenses paid by the Company which are recorded as part of Income Tax Benefit and $ 258 of the Company's costs have been recorded as Project development and startup costs. Transaction costs are deductible for income tax purposes.
 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, 2024 and 2023, 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 (loss) income, if any, is included in the Company's consolidated statements of operations as income (loss) from equity method investments.
 We continue to evaluate operational developments and the impact of the anticipated expansion of the operations of our existing equity method investments. 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 have classify our portion of income (loss) from equity method investments to Operating income.
 The Company has elected to apply the cumulative earnings approach for classifying distributions received from equity method investees. Distributions are classified as cash inflows from operating activities unless they exceed the investor's cumulative equity in earnings, in which case the excess is classified as cash inflows from investing activities.
 The following table shows the movement of Investment in Other Entities:

 Pine Bend
 Noble Road
 GREP
 SJI
 Paragon
 Total

 Percentage of ownership
 %
 %
 %
 %
 %

 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)
 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)

 Balance at December 31, 2023

 $
 21,062
 $
 22,174
 $
 2,015
 $
 1,567
 $
 160,281
 $
 207,099

 Net income from equity method investment
 3,956
 4,892
 ( 255)
 ( 845)
 11,323
 19,071

 Contribution by the Company
 —
 —
 —
 15,050
 5,906
 20,956

 Distributions from return on investment in equity method investment (1)

 ( 3,800)
 ( 4,298)
 —
 —
 ( 6,238)
 ( 14,336)

 Distributions from return of investment in equity method investment (2)

 ( 1,525)
 ( 1,077)
 —
 —
 ( 1,703)
 ( 4,305)

 Accumulated other comprehensive income
 —
 —
 —
 —

 Amortization of basis difference (4)

 ( 157)
 ( 594)
 —
 —
 ( 5,084)
 ( 5,835)

 Capitalized interest

 —
 —
 —
 —

 Balance at December 31, 2024

 $
 19,536
 $
 21,097
 $
 1,760
 $
 16,384
 $
 164,817
 $
 223,594

 (1) Recorded as part of cash flows from operating activities for the year ended December 31, 2024 and 2023.
 (2) Recorded as part of cash flows from investing activities for the years ended December 31, 2024 and 2023.
 (3) Represents gain on the deconsolidation of previously consolidated entities due to the loss of controlling financial interest in May 2023. 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 statements of operations for the year ended December 31, 2024 and 2023.
 The following table summarizes the income from equity method investments:

 Revenue (1)

 $
 111,296
 $
 50,074

 Gross profit
 45,803
 12,065

 36,100
 6,323

 Net income from equity method investments (1)

 $
 13,235
 $
 5,525

 (1) Net income from equity method investments represents our portion of the net income from equity method investments including amortization of any basis differences.
 A summary of financial information for our portion of the assets and liabilities in equity method investees in the aggregate is as follows:

 Current assets
 $
 10,554
 $
 12,604

 Non-current assets

 121,934
 91,215

 Total assets
 132,488
 103,819

 Current liabilities

 15,993
 14,358

 Non-current liabilities

 24,612
 19,194

 Total liabilities
 $
 40,605
 $
 33,552

 Biotown Note receivable
 In August 2021, the Company acquired 100 % ownership interest in Reynolds which held a note receivable of $ 10,450 to Biotown. On July 15, 2022, Biotown repaid the total amount outstanding under the Note receivable.
 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 initially 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. The Company and recorded payment-in-kind interest income of $ 207 and $ 413 as a reduction to interest and financing expense, net in the consolidated statement of operations for the years ended December 31, 2024 and 2023, respectively.
 The Note receivable - variable fee component of $ 2,509 and $ 2,302 is recorded as a long-term asset on its consolidated balance sheets as of December 31, 2024 and 2023, respectively.

 4. Property, Plant, and Equipment, Net
 Property, plant, and equipment, net, consisted of the following as of December 31, 2024 and December 31, 2023:

2024
2023

 Plant and equipment
 $
 317,926
 $
 205,188

 CNG/RNG fueling stations
 68,899
 51,749

 Construction in progress (1)

 169,571
 175,060

 Buildings
 2,585
 2,585

 Land
 1,303
 1,303

 Service equipment
 2,992
 2,481

 Leasehold improvements

 Vehicles

 Office furniture and equipment

 Computer software

 Land lease - finance lease

 5,567
 6,469

 Vehicles - finance leases
 3,983
 2,580

 Other

 575,634
 449,894

 Less: accumulated depreciation
 ( 117,376)
 ( 110,401)

 Property, plant, and equipment, net
 $
 458,258
 $
 339,493

 (1) Includes $ 3,212 of interest capitalized from our general borrowings for the year ended December 31, 2024 and $ 5,475 for the year ended December 31, 2023.
 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") with respect to a gas pipeline extension and associated interconnection facilities (the "Pipeline Project") that is contemplated as part of the subsidiary's RNG production facility at the Prince William County landfill located in Manassas, Virginia. The Agreement obligates the subsidiary to develop, plan and permit 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 was on or prior to October 20, 2024. During the second quarter of 2024, the agreement was amended to move the closing date to fourth quarter of 2025.
 The Company concluded that the arrangement does not constitute a transaction with a customer under ASC 606, and the Pipeline and its related easements represent a single distinct asset that will be derecognized at the point in time when the transferee gains control.
 As of December 31, 2024, the Company had $ 7.75 million capitalized as CIP related to the construction of the asset. In the fourth quarter of 2024, the Company noted an increase in the construction budget and considered the asset for impairment under ASC 360 Property, Plant and Equipment. The Company estimates that its capitalized costs, combined with remaining budgeted construction expenditures, will reach $ 37.0 million by the asset's completion date. In contrast, the Company expects to receive a payment of $ 23.1 million from WGL in exchange for the Pipeline, net of taxes. As a result, the asset does not meet the recoverability test as of December 31, 2024.
 To calculate the amount of impairment, the Company further assessed the fair value of the Pipeline using the replacement cost approach. This approach is based on the premise that a prudent investor would pay no more for an asset of similar utility than its replacement or reproduction cost. The cost to replace the asset would include the cost of constructing a similar asset of equivalent utility at prices applicable at the valuation date. To estimate the fair value, the Company used the current cost of producing or constructing a similar new item, reduced for depreciation. The results of the impairment assessment indicated that the fair value of the asset exceeded its carrying amount as of the measurement date, resulting in no impairment loss as of December 31, 2024.
 As of December 31, 2024, the Construction in progress consists of capital expenditures on construction of RNG generation facilities including, but not limited to Cottonwood, Central Valley RNG projects and RNG dispensing facilities.

 Polk County became operational in the fourth quarter of 2024. Regarding the Central Valley RNG projects, please refer to Note 17. Commitments and Contingencies for additional information.
 Depreciation expense on property, plant, and equipment for the years ended December 31, 2024 and December 31, 2023 was $ 17,176 and $ 13,481 respectively.

 5. Intangible Assets, Net
 Intangible assets, net, consisted of the following at December 31, 2024 and December 31, 2023:

 Cost
 Accumulated
Amortization
 Intangible
Assets,
Net
 Weighted
Average
Amortization
Period
(Years)

 Power purchase agreements
 $
 8,999
 $
 ( 7,669)
 $
 1,330
 18.1

 Transmission/distribution interconnection
 1,600
 ( 1,600)
 —
 15.1

 Intellectual property
 ( 43)
 —
 5.0

 Total intangible assets
 $
 10,642
 $
 ( 9,312)
 $
 1,330

 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)
 15.1

 Intellectual property
 ( 36)
 5.0

 Total intangible assets
 $
 10,642
 $
 ( 9,038)
 $
 1,604

 Amortization expense for the years ended December 31, 2024 and 2023 was $ 274 and $ 563, respectively. At December 31, 2024, estimated future amortization expense for intangible assets is as follows:

 Fiscal year:

 2025

 2026

 2027

 2028

 2029

 Thereafter

 $
 1,330

 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:

 Total

 Balance at December 31, 2024

 $
 51,155
 $
 3,453
 $
 54,608

 Balance at December 31, 2023

 $
 51,155
 $
 3,453
 $
 54,608

 7. Borrowings
 The following table summarizes the borrowings under the various debt facilities as of December 31, 2024 and December 31, 2023:

 OPAL Term Loan and Revolver

 286,617
 186,618

 Less: unamortized debt issuance costs
 ( 9,122)
 ( 10,086)

 Less: current portion
 ( 10,865)
 —

 OPAL Term Loan, net of debt issuance costs
 266,630
 176,532

 20,846
 22,453

 Less: unamortized debt issuance costs
 ( 717)
 ( 835)

 Less: current portion
 ( 1,756)
 ( 1,608)

 Sunoma Loan, net of debt issuance costs
 18,373
 20,010

 Non-current borrowings total
 $
 285,003
 $
 196,542

 As of December 31, 2024, principal maturities of debt are expected as follows, excluding any undrawn debt facilities as of the date of the consolidated balance sheet:

 Total

 Fiscal year:

 2025
 $
 10,865
 $
 1,756
 $
 12,621

 2026
 10,865
 1,898
 12,763

 2027
 10,865
 2,051
 12,916

 2028
 254,022
 2,213
 256,235

 2029
 —
 2,395
 2,395

 Thereafter
 —
 10,533
 10,533

 $
 286,617
 $
 20,846
 $
 307,463

 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.
 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. 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 amounts outstanding under the Credit Agreement are secured by the assets of the indirect subsidiaries of OPAL Intermediate Holdco.

 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. Commencing March 31, 2025, 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.
 The Credit Agreement requires the Borrower to maintain a consolidated debt service coverage ratio of not less than 1.2 to 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 ended 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, 2024, the Company is in compliance with the covenants under the OPAL Term Loan. Additionally, the OPAL Term Loan contains restrictions on distributions and additional indebtedness.
 On March 3, 2025, OPAL Fuels Intermediate HoldCo LLC, as the borrower (the "Borrower"), certain subsidiaries of the Borrower, as guarantors (the "Guarantors"), the lenders and issuers of letters of credit party thereto and Bank of America, N.A. as the administrative agent (the "Administrative Agent") entered into that certain Amendment No. 1 to Credit and Guarantee Agreement (the "Credit Agreement Amendment"), with respect to that certain Credit and Guarantee Agreement (the "Credit Agreement") dated September 1, 2023, by and among the Borrower, the Administrative Agent, the financial institutions from time to time parties thereto as lenders and as issuers of letters of credit, and the other agents and persons from time to time party thereto (as amended, restated, amended and restated, supplemented or otherwise modified and in effect from time to time).
 The Credit Agreement Amendment makes certain changes to the applicability of certain financial covenants and modifies other covenants to clarify the use of loan proceeds. Additionally, the Credit Agreement Amendment permits the organizational restructuring of the Guarantors in a manner designed to facilitate the sale of federal investment tax credits and the ability to raise additional future capital.
 The Credit Agreement Amendment also eases the conditions precedent to making new Projects eligible for borrowing under the Credit Agreement, extends the availability period for delay draw term loans under the Credit Agreement through March 5, 2026, and extends the commencement of repayment of such term loans until March 31, 2026.
 In connection with the Credit Agreement Amendment, the Borrower paid the Administrative Agent, for the account of each lender, a one-time nonrefundable fee of $ 1,250.
 As of December 31, 2024 and December 31, 2023, the outstanding loan balance (current and non-current) excluding deferred financing costs was $ 286,617 and $ 186,618, respectively. During the year ended December 31, 2024, the Company drew down $ 85,000 including $ 15,000 drawn under revolver loan. The Company utilized $ 29,088 of availability under the revolver loan. Of this amount, $ 14,088 was utilized for the issuance of letters of credit to support the operations of the Borrower and the Guarantors, while $ 15,000 was drawn to support working capital needs.
 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.
 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 amounts outstanding under the Sunoma Loan are secured by the assets of Sunoma. 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 maturity date is July 19, 2033. The outstanding loans under the Sunoma Loan Agreement bear interest at an annual fixed rates of 7.8 %, and 8.2 % per annum during the term.

 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. As of December 31, 2024, Sunoma is in compliance with the financial covenants under the Sunoma Loan Agreement.
 As of December 31, 2024 and December 31, 2023, the outstanding loan balance (current and non-current) excluding deferred financing costs was $ 20,846 and $ 22,453, respectively.
 The significant assets of Sunoma are parenthesized in the consolidated balance sheets as of December 31, 2024 and December 31, 2023. 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 ARCC Beacon LLC, a Delaware limited liability company and affiliate of Ares Management Corporation, for a total aggregate amount for $ 50,000 at an interest rate of 8.00 % per annum.
 The Company repaid the outstanding balance in full on September 1, 2023.
 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 loan was fully repaid in April 2023.
 Senior Secured Credit 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.
 On March 20, 2023, the Company repaid in full the remaining outstanding loan under this facility.
 Interest rates
 2024
 For the year ended December 31, 2024, the effective interest rate including amortization of debt issuance costs on OPAL Term Loan was 8.8 %.
 For the year ended December 31, 2024, the interest rate on the Sunoma Loan was 8.7 %.
 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.

 The following table summarizes the Company's total interest and financing expense, net for the year ended December 31, 2024 and 2023:

 2024
 2023

 Senior Secured Credit Facility
 $
 —
 $

 Convertible Note Payable mark-to-market

 —
 1,579

 1,769
 1,803

 OPAL Term Loan (1)

 15,063
 5,231

 Commitment fees and other finance fees
 2,730
 1,491

 Amortization of deferred financing cost
 1,395
 1,720

 Finance leases

 Interest income
 ( 1,921)
 ( 2,934)

 Total interest and financing expense, net
 $
 19,610
 $
 9,306

 (1) Excludes $ 3,212 and $ 5,475 of interest capitalized and recorded as part of Property, Plant and Equipment for the years ended December 31, 2024 and 2023, respectively.

 8. Leases
 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. The contractual term of these arrangements may include options to extend/renew, terminate the agreement upon the occurrence of certain actions by a government authority or regulatory agency or terminate the agreement and purchase the underlying station for fair market value. We determine if an arrangement contains a lease at inception by assessing whether an identified asset exists and if the customer has the right to control the use of the identified asset. Accordingly, we have determined that the FPAs contain a lease component for the use of the Fueling Station in addition to the non-lease components related to providing CNG/RNG as well as providing all-inclusive maintenance and warranty services. The lease components of the FPAs are considered to be operating leases with variable consideration. The adjustments to payments are based on a variety of factors including changes in an index or rate (such as the market price of natural gas and utilities), the amount of fuel dispensed from the station, annual escalators, volume discounts and discounts for tax and environmental credits retained by the Company. The Company excludes taxes assessed by a government authority that are imposed on and concurrent with the FPA transaction collected by the Company from the customer. As per ASC 842 Leases ("ASC 842"), the revenue is recognized in the period earned.
 We estimate the amount we expect to derive from the underlying asset following the end of the lease term based on the remaining economic life of the asset. Our FPAs generally do not include any residual value guarantees. The Company typically expects the underlying asset to have no residual value following the end of the lease term. Agreements which include renewal and termination options are included in the lease terms if we believe the options are "reasonably certain" to be exercised by the lessee or if an option to extend is controlled by the Company.
 Included in Fuel Station Service revenues are $ 8,146 and $ 3,943 related to the lease portion of the FPAs for the years ended December 31, 2024, and 2023, respectively. The Company allocated the contract consideration between the lease component and non-lease components on a relative standalone selling price basis. The Company utilized a combination of approaches to estimate the standalone selling prices when directly observable selling price was not available. These estimates were developed through the use of information available such as market conditions and prices, jurisdictional-specific facts, and internal estimates when market data is not available. In instances where there are no observable standalone selling prices for a component, significant judgement is required in determining the standalone selling price.

 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.
 Included in Renewable Power revenues are $ 970 and $ 1,016 related to the lease element of the PPAs for the years ended December 31, 2024 and 2023, respectively.
 Lessee contracts
 Ground/Site leases
 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 - MD Digester ("MD") and VS Digester ("VS"). During the year ended December 31, 2024, the Company revised the commercial operation date for its leases for MD and VS which changed the lease term for both the leases. The Company treated this as a lease modification and increased its right-of-use asset and corresponding lease liability by $ 1,109 on its consolidated balance sheet as of December 31, 2024, using the incremental borrowing rate from 7.28 % to 7.53 %.
 On December 27, 2023, OPAL entered into an Amended and Restated Lease Agreement with a counter party which amended the payment terms to include a minimum volume requirement that requires 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.
 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 Company determined that the three site leases and the one office lease are operating leases.
 The lease expense for the site leases is included as part of Cost of sales - RNG Fuel in its consolidated statements of operations for the years ended December 31, 2024 and 2023. The lease expense for the office lease is recorded as part Selling, general and administrative expenses in its consolidated statements of operations for the years ended December 31, 2024 and 2023.
 Vehicle leases
 The Company leases approximately 108 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.
 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, 2024 and December 31, 2023 are as follows:

 Description
 Location in Balance Sheet

 Assets:

 Operating leases (1):

 Site leases
 Right-of-use assets
 $
 12,213
 $
 11,330

 Office lease
 Right-of-use assets

 12,731
 12,301

 Finance leases (1):

 Vehicle leases
 Property, plant and equipment, net
 3,983
 2,580

 Site lease

 Property, plant and equipment, net
 5,567
 6,468

 9,550
 9,048

 Total lease right-of-use assets

 $
 22,281
 $
 21,349

 Liabilities (1):

 Sites leases

 Operating lease liabilities - current portion

 $
 $

 Office lease

 Operating lease liabilities - current portion

 Vehicle leases - finance
 Accrued expenses and other current liabilities
 1,427

 Site leases - finance
 Accrued expenses and other current liabilities
 1,157

 3,364
 2,036

 Sites leases

 Operating lease liabilities - non - current portion

 12,103
 11,222

 Office lease

 Operating lease liabilities - non - current portion

 Vehicle leases - finance
 Other long-term liabilities
 2,665
 1,801

 Site leases - finance
 Other long-term liabilities
 4,893
 5,587

 19,713
 19,212

 Total lease liabilities
 $
 23,077
 $
 21,248

 (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 8.01 %.
 The table below presents components of the Company's lease expense for the years ended December 31, 2024 and 2023:

 Description
 Location in Statement of Operations

 2024
 2023

 Operating lease expense for site leases
 $
 1,126
 $
 1,087

 Operating lease expense for office lease
 Selling, general, administrative expenses

 Amortization of right-of-use assets - finance leases
 Depreciation, amortization and accretion expense
 1,923

 Interest expense on lease liabilities - finance leases

 $
 4,128
 $
 2,343

 The Company does not have material short term lease expense for the years ended December 31, 2024 and 2023.
 The Company did not enter into any operating leases greater than 12 months for the year ended December 31, 2024.

 Weighted average remaining lease term (years)

 Operating leases
 20.6 years

 Finance leases

 5.9 years

 The table below provides the total amount of lease payments on an undiscounted basis on our lease contracts as of December 31, 2024:

 Site leases

 Office leases

 Vehicle and Equipment leases

 Site lease - Finance

 Total

 Weighted average discount rate
 7.3
 %
 3.6
 %
 6.9
 %
 6.5
 %

 2025
 $
 1,044
 $
 $
 1,711
 $
 $
 4,142

 2026
 1,051
 1,556
 3,617

 2027
 1,129
 —
 1,028
 3,120

 2028
 1,129
 —
 4,250
 5,716

 2029
 1,129
 —
 —
 —
 1,129

 Thereafter
 18,779
 —
 —
 —
 18,779

 24,261
 4,632
 7,001
 36,503

 Present value of lease liability
 12,334
 4,092
 6,050
 23,077

 Lease liabilities - current portion
 1,427
 1,157
 3,364

 Lease liabilities - non-current portion
 12,103
 2,665
 4,893
 19,713

 Total lease liabilities
 $
 12,334
 $
 $
 4,092
 $
 6,050
 $
 23,077

 Discount based on incremental borrowing rate
 $
 11,927
 $
 $
 $
 $
 13,426

 9. Derivative Financial Instruments and Fair Value Measurements
 Interest rate swap contract
 During the year ended December 31, 2024, the Company entered into an interest rate swap for the notional amount of $ 30,000 of the OPAL Term Loan at a fixed interest rate of 3.354 % with a maturity date of September 1, 2028 to hedge the SOFR-based floating interest rate.
 The interest rate swap was designated and qualified as a cash flow hedge. 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. 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 interest rate swap is an agreement between the Company and counterparties in which the Company agrees 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 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. By using commodity swaps, the Company exposes itself to credit 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 records the fair value of the interest rate swap as an asset or liability on its balance sheet. This instrument is classified as Level 2 in the fair value hierarchy. The effective portion of the swap is recorded in accumulated other comprehensive income. A periodic settlement of $ 96 was recorded under Prepaid expense and other current assets for the year ended December 31, 2024. The Company expects to release $ 238 from the Other Comprehensive Income in the next twelve months.

2024
2023
 Location of Fair Value Recognized in Balance Sheet

 Derivatives designated as cash flow hedges:

 Short term portion of the interest rate swaps
 $
 $
 —
 Derivative financial assets, current portion

 Long term portion of the interest rate swaps
 —
 Derivative financial assets, non-current

 $
 $
 —

 The effect of interest rate swaps on the consolidated statement of operations were as follows:

 Location of (Loss) Gain Recognized in Operations from Derivatives

 2024
 2023

 Swaption
 $
 —
 $
 ( 46)

 Net periodic settlements - interest rate swaps (1)

 1,146

 $
 $
 1,100
 Change in fair value of derivative instruments, net

 (1) The prior 2023 year 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 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. There were no amounts offset in the Balance Sheet

 as of the period-end dates. In addition, 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 and natural gas. 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.
 The Company entered into an International Swaps and Derivatives Association ("ISDA") agreement with NextEra, a related party, in November 2019. Pursuant to the agreement, the Company entered into two additional commodity swaps in October 2022 for a period of one to 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 and normal sale exclusion and will not apply fair value accounting under ASC 815, Derivatives and hedging ("ASC 815"). The Company continues to meet the normal purchase normal sale exclusion for all the reporting periods presented.
 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 ("kWh") 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. The Company continues to meet the normal purchase normal sale exclusion for all the reporting periods presented.
 In November 2024, the Company entered into a second confirmation under the ISDA to sell energy and related green attributes (i.e., RECs) to NextEra. Under this confirmation, the Company delivered a total of 5,000 MWh of power to NextEra on an hourly basis within the fourth quarter of 2024 between November and December 31, 2024. Sale of energy is accounted under ASC 815 with the contract settled as of December 31, 2024. The associated RECs will be delivered to NextEra on or before April 15, 2025 and are accounted for under ASC 606.
 In December 2024, the Company entered into an power purchase and sale agreement with a NextEra for sale of electricity with a fixed quantity of 30,660 MWH over a one-year term, with a contract price of $ 43.60 per MWH. 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.
 The Company entered into an ISDA agreement with NextEra, a related party in November 2022. Pursuant to the agreement, in December 2024 the Company entered in 15-month pay variable receive fixed cash settled electricity commodity swap with NextEra. The Company will receive Fixed Price $ 56.15 per MWh and pay Floating Price. Total notional quantity of the contract is 10,919 MWH. The Company applied fair value accounting under ASC 815 for this transaction.
 The Company entered into an ISDA agreement with JPMorgan Chase Bank, National Association, New York Branch ("JPMorgan") in September 2024. Pursuant to the agreement, in January 2025 the Company entered in two 17-month pay variable receive fixed cash settled natural gas commodity swaps with fixed price of $ 3.875 per MMBTU and total notional quantity of 850,000 MMBTUs each. The Company will apply fair value accounting under ASC 815 for these transactions.

 The following table summarizes the effect of commodity swaps on the consolidated statements of operations for the years ended December 31, 2024 and 2023:

 Derivatives not designated as hedging instruments
 Location of (loss) gain recognized

 2024
 2023

 Commodity swaps - realized gain
 Revenues - Renewable Power
 $
 $
 1,839

 Commodity swaps - unrealized gain (loss)
 Revenues - Renewable Power
 ( 704)

 Total realized and unrealized gain
 Revenues - Renewable Power
 $
 $
 2,602

 The following table summarizes the derivative assets and liabilities related to commodity swaps as of December 31, 2024 and December 31, 2023:

 Fair Value
 Location of Fair value recognized in Balance Sheet

 Derivatives not designated as hedging instruments

 Current portion of unrealized gain on commodity swaps
 $
 —
 $
 Derivative financial asset, current portion

 Current portion of unrealized loss on commodity swaps

 ( 9)
 —
 Derivative financial liability, current portion

 Non - current portion of unrealized loss on commodity swaps

 ( 63)
 —
 Derivative financial liability, non - current portion

 Other derivative liabilities
 On July 21, 2022, the Company recorded derivative liabilities for the outstanding put option to Meteora Capital Partners and its affiliates "Meteora", the Sponsor Earnout Awards and the OPAL Earnout Awards. The put option with Meteora expired in January 2023. The change in fair value on Sponsor Earnout and OPAL Earnout Awards is recorded as change in fair value of derivative instruments, net in the consolidated statement of operations for the years ended December 31, 2024 and 2023.
 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, 2024 and 2023:

 Derivative liability
 Location of (Loss) Gain Recognized in Operations from Derivatives

 2024
 2023

 Put option to Meteora
 $
 —
 $
 ( 311)

 Sponsor Earnout Awards
 1,596
 1,890

 OPAL Earnout Awards
 —
 5,000

 $
 1,596
 $
 6,579
 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, which are considered Level 2 in the fair value hierarchy, of $ 297,624 and $ 196,542 as of December 31, 2024 and December 31, 2023, respectively, approximates its fair value because our interest rate is variable and reflects current market rates.
 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's interest rate swap contracts are valued with pricing models commonly used by the financial services industry using discounted cash flows of forecast future swap settlements based on projected three-month SOFR rates. The Company does not consider these models to involve significant judgment on the part of management and corroborated the fair value measurements with counterparty valuations. The Company's interest rate swaps are classified within Level 2 of the valuation hierarchy based on the observable market rates used to determine its fair value. The Company does not expect to change its valuation techniques and therefore does not anticipate any transfers into or out of different levels of hierarchy. These interest rate swaps are accounted for as derivative financial instrument assets.
 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 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 fair value of the Sponsor Earnout Awards as of December 31, 2024, was determined using a Monte Carlo valuation model with a distribution of potential outcomes on a daily basis over the 2.56 years remaining in the vesting window. Assumptions used in the valuation are as follows:
 • Current stock price — The Company's closing stock price of $ 3.39 as of December 31, 2024;

 • Expected volatility — 50 % 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 — 4.26 % 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 2.56 year term of the earnout period;
 • Dividend yield - zero.
 The fair value of the OPAL Earnout Awards as of December 31, 2024 and December 31, 2023 was determined to be zero as their expiration date is December 31, 2024 and the Company does not expect to achieve the earn-out target.
 Convertible note receivable
 In July, 2024, the Company purchased a convertible note pursuant to which the Company has the right to convert the note into shares of common stock of the investee. The note has a term of 12 months from the closing date, unless paid or converted earlier in accordance with the terms of the agreement. The convertible note receivable is classified as available-for-sale. The Company elected to measure the convertible note receivable initially and subsequently at fair value with changes reported in earnings to accurately reflect current market expectations and conditions. The convertible note receivable is accounted for based on "Level 3" inputs, which consist of unobservable inputs and reflect management's estimates of assumptions that market participants would use in pricing the asset. The Company reported the aggregate fair value as a separate line item in the consolidated balance sheets. Changes in fair value, including interest income, are presented under the Other Income line item in the consolidated statement of operations. As of December 31, 2024, fair value of the convertible note equaled to $ 760. The Company estimates the fair value of its convertible note receivable using a weighted probability model which considers two potential settlement scenarios over the term of the note, discounted to the reporting date. The valuation of the conversion option is determined using option pricing model, which incorporate key assumptions and estimates, including expected volatility, the anticipated term of the instrument, and applicable risk-free interest rate.
 There were no transfers of assets between Level 1, Level 2, or Level 3 of the fair value hierarchy as of December 31, 2024.
 The Company's assets and liabilities that are measured at fair value on a recurring basis include the following as of December 31, 2024 and December 31, 2023, set forth by level, within the fair value hierarchy:

 Fair value as of December 31, 2024

 Level 1
 Level 2
 Level 3
 Total

 Liabilities:

 Asset retirement obligation
 $
 —
 $
 —
 $
 7,886
 $
 7,886

 Earnout liabilities
 —
 —

 Commodity swap contracts
 —
 —

 Assets:

 Cash and cash equivalents and restricted cash - current and non-current (1)

 29,228
 —
 —
 29,228

 Interest rate swap contracts
 —
 —

 Convertible note receivable
 —
 —

 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)

 —
 —

 Short term investments
 9,875
 —
 —
 9,875

 Commodity swap contracts
 —
 —

 (1) Includes balances in money market accounts of $ 19,786 and $ 31,965, respectively as of December 31, 2024 and December 31, 2023.
 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, 2024 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 RNG Investments, LLC, a Delaware limited liability company and an affiliate of Fortistar ("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 $ 2,416 and paid-in-kind preferred dividend of $ 2,590 for the years ended December 31, 2024 and 2023, respectively. Please see Note 13. Redeemable non-controlling interests, Redeemable preferred non-controlling interests and Stockholders' Deficit, for additional information. As of December 31, 2024 and 2023, there was accrued preferred dividends payable of $ — and $ 604 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 Company had drawn $ 100,000 and issued 1,000,000 Series A preferred units. The Company recorded preferred dividend of $ 8,054 and paid-in-kind preferred dividend of $ 8,421 for the years ended December 31, 2024 and 2023 respectively. As of December 31, 2024 and 2023, there was accrued preferred dividends payable of $ 0 and $ 2,013, respectively. Please see Note 13. Redeemable non-controlling interests, Redeemable preferred non-controlling interests and Stockholders' Deficit, for additional information.
 The Series A preferred units have limited rights to prevent OPAL Fuels LLC 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 disposition of assets and (iv) major acquisition of assets outside of OPAL Fuels LLC's primary business. The Series A 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 was allowed to elect to issue additional Series A preferred units ( paid-in-kind) in lieu of cash for the first eight dividend payment dates. As of December 31, 2024 and 2023, there was accrued preferred dividend payable of $ 0 and $ 2,013, respectively.
 At any time after issuance, OPAL Fuels LLC may redeem the Series A preferred units for a price equal to original issue price of $ 100 per unit plus any accrued and unpaid dividends. Upon written notice from NextEra at any time after November 29, 2025, we would be required to redeem the Series A preferred units. In the event the Company does not redeem the Series A preferred units when requested, Nextera will have the following rights and remedies: (1) NextEra's affiliate may extend the RNG Marketing Agreement by 12 months; or (2) the dividend rate would increase depending on the length of time the Series A preferred units remain unredeemed to up to 20 % per annum, and if more than $ 25,000 preferred equity is outstanding for more than six months after November 29, 2025, NextEra may appoint a director to our Board of Directors; or (3) NextEra may convert the Series A preferred equity into common equity of the OPAL Fuels LLC at a conversion price at a 20 % to 30 % discount to their value (the discount is 20 % during the first 12 months after November 29, 2025, 25 % for the next 12 months thereafter and 30 % thereafter).
 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 year ended December 31, 2024, the Company earned net revenues after discount and fees of $ 68,416 under this contract which was recorded as part of Revenues - RNG Fuel and revenues of $ 38,841, under this contract which was recorded as part of Revenues - Fuel Station Services.
 For the year ended December 31, 2023, the Company earned net revenues after discount and fees of $ 56,069 under this contract which was recorded as part of Revenues - RNG Fuel and revenues of $ 28,468, under this contract which was recorded as part of Revenues - 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, 2024 and 2023, there were one and three commodity swap contracts outstanding respectively. 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 $ 6,912 and $ 6,614 as revenues earned under these contracts during the years ended December 31, 2024 and 2023 respectively.
 In October 2024, the Company entered into an ISDA confirmation to sell specified capacity attributes (5 MW/month) to NextEra for one year period from January to December 2025. The confirmation is expected to be settled by physical delivery on a monthly basis and is accounted for under ASC 606.
 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 $( 255) and $( 1,212) as its share of net (loss) income for the years ended December 31, 2024 and 2023.
 Revenues contracts with equity method investment entities
 The Company's wholly owned subsidiary, OPAL Fuel Station Services contracted with Pine Bend, Noble Road, Biotown, Emerald and Sapphire to dispense RNG and to generate and market resulting RINs. The Company receives non-cash consideration in the form of RINs or LCFSs for providing these services and recognizes the RINs and LCFSs received as inventory based on their estimated fair value at contract inception. Additionally, OPAL Fuel Station Services provides the same services to all wholly-owned subsidiaries of the Company. The revenues earned from the wholly-owned entities are fully eliminated in the consolidated financial statements.
 The term of these contracts each 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. For the years ended December 31, 2024 and 2023, the Company earned environmental processing fees of $ 9,677 and $ 2,615, net of intersegment elimination, under this agreement which are included in Fuel Station Services revenues in the consolidated statements of operations.

 Service agreements with Related Parties
 On December 31, 2020, OPAL Fuels signed a management, operations, and maintenance services agreement ("Administrative Services Agreement") with Fortistar, LLC ("Fortistar"), pursuant to which Fortistar provides management, operations, and maintenance services to the Company. The agreement automatically renews annually on January 1 of each year, unless either party chooses to terminate with a written notice of 180 days. Termination may also occur 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, 2024 and 2023, 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 initial term of the agreement was for thirty-six months and renews automatically on an annual basis 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, on a cumulative basis. The interim services agreement is expected to be terminated in second quarter of 2025 in connection with Opal's retention of Mr. Kazi as CFO in February 2025.
 The following table summarizes the various fees recorded under the agreements described above which are included in "Selling, general, and administrative" expenses:

 2024
 2023

 Staffing and management services
 $
 2,082
 $
 1,834

 Rent - fixed compensation

 IT services
 3,113
 2,954

 Total
 $
 5,906
 $
 5,456

 The following table presents the various balances for related parties included in our consolidated balance sheets as of December 31, 2024 and 2023.

 Location in Balance Sheet
 2024
 2023

 Assets:

 Trade AR - NextEra
 Accounts receivable, related party
 $
 14,522
 $
 18,696

 Liabilities:

 Payables to equity method investment entities
 6,946
 5,692

 NextEra

 Staffing and management services - Fortistar

 IT services - Costar

 Total liabilities - related party
 $
 7,932
 $
 7,024

 11. Reportable Segments and Geographic Information
 The Company is organized into three operating segments based on the characteristics of its renewable power generation, dispensing portfolio, production and sale of renewable gas, and nature of other products and services.
 Our reportable segments disclosure is aligned with the information and internal reporting provided to our Chief Operating Decision Makers ("CODM"). Our Co-CEOs, Adam Comora and Jon Maurer, jointly fulfill the role of the CODM. The CODM evaluates performance based on segment net income. For all of the segments, the CODM uses segment net income in the annual budgeting and monthly forecasting process. The CODM considers budget-to-current forecast and prior forecast-to-current forecast variances for segment net income on a monthly basis for evaluating performance of each segment and making decisions about allocating capital and other resources to each segment.
 The three operating segments are RNG Fuel, Fuel Station Services and Renewable Power. The Company has determined that each of the three operating segments meets the characteristics of a reportable segment under U.S. GAAP.
 • 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.
 For the year ended December 31, 2024 and 2023, the Company has accounted for its interests in Pine Bend, 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, 2024.
 As of December 31, 2024, Central Valley, Cottonwood and projects included in SJI Joint Venture (Atlantic and Burlington) are not operational. Prince William commenced operations during the second quarter of 2024, Sapphire commenced operations during the third quarter of 2024, Polk commenced operations during the fourth quarter of 2024.
 • 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. 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 following table reflect the financial data used to calculate each reportable segment's net income (loss) and includes reconciliations to Opal's consolidated revenue and consolidated net income (loss) for the year ended December 31, 2024:

 Corporate
 Total

 Revenue from external customers
 $
 $
 $
 $
 —
 $

 Intersegment revenues
 18,948
 —
 —
 19,466

 Reconciliation of Revenue

 Elimination of intersegment revenues
 ( 518)
 ( 18,948)
 —
 —
 ( 19,466)

 Total consolidated revenues
 —

 Less: (1)

 Cost of sales and other operating costs

 37,034
 128,804
 32,495
 45,911
 244,244

 Less:

 Income form equity method investments

 ( 13,235)
 —
 —
 —
 ( 13,235)

 19,574
 ( 132)
 —
 19,610

 —
 —
 —

 Other Income
 —
 —
 ( 349)
 ( 206)
 ( 555)

 Depreciation, amortization and accretion

 8,252
 5,612
 4,021
 —
 17,885

 Other segment items (2)

 —
 ( 1,222)
 1,577
 7,140
 7,495

 Segment Income (Loss)

 $
 17,686
 $
 33,513
 $
 7,065
 $
 ( 52,845)
 $
 5,419

 Reconciliation of profit or loss (segment income / (loss))

 Income tax benefit

 8,906

 Consolidated net income
 $

 (1) The significant expense categories and amounts align with the segment-level information that is regularly provided to the chief operating decision maker. Intersegment expenses are included within the amounts shown.
 (2) Other segment items for each reportable segment includes:
 • Fuel Station Services - gain on RNG dispensing, and gain on asset disposal
 • Renewable Power - asset impairment
 • Corporate - information technology expense, legal and professional advisor fees, and other overhead expenses
 Geographic Information: The Company's assets and revenue generating activities are domiciled in the United States.
 The following table reflects certain other financial data for the reportable segments for the year ended December 31, 2024:

 Corporate
 Total

 Other segment disclosures

 Equity method investment
 $
 223,594
 $
 —
 $
 —
 $
 —
 $
 223,594

 Segment assets
 635,927
 179,304
 30,517
 35,329
 881,077

 Cash paid for purchases of property, plant and equipment
 110,740
 18,414
 —
 —
 129,154

 The following table reflect the financial data used to calculate each reportable segment's net income (loss) and includes reconciliations to Opal's consolidated revenue and consolidated net income (loss) for the year ended December 31, 2023:

 Corporate
 Total

 Revenue from external customers
 $
 $
 $
 $
 —
 $

 Intersegment revenues
 14,396
 —
 —
 14,396

 Reconciliation of Revenue

 Elimination of intersegment revenues
 —
 ( 14,396)
 —
 —
 ( 14,396)

 Total consolidated revenues
 —

 Less: (1)

 Cost of sales and other operating costs

 29,694
 115,146
 36,393
 45,250
 226,483

 Less:(1)

 (Income) Loss from EMI
 ( 5,525)
 —
 —
 —
 ( 5,525)

 9,353
 ( 134)
 ( 193)
 9,306

 4,866
 —
 —
 —
 4,866

 Other Income
 —
 —
 —
 ( 122,535)
 ( 122,535)

 Depreciation, amortization and accretion

 5,268
 3,730
 5,567
 —
 14,565

 Other segment items (2)

 ( 1,638)
 3,036
 1,924

 Segment Income

 $
 22,203
 $
 17,908
 $
 12,471
 $
 74,442
 $

 Consolidated net income
 $

 (1) The significant expense categories and amounts align with the segment-level information that is regularly provided to the chief operating decision maker. Intersegment expenses are included within the amounts shown.
 (2) Other segment items for each reportable segment includes:
 • Fuel Station Services - gain on recognition of RINs
 • Corporate - gain on mark-to-market for OPAL and Sponsor Earnout Awards, loss on extinguishment of debt, insurance other overhead expenses
 Geographic Information: The Company's assets and revenue generating activities are domiciled in the United States.

 The following table reflects certain other financial data for the reportable segments:

 Corporate
 Other
 Total

 Other segment disclosures

 Equity method investment
 $
 207,099
 $
 —
 $
 —
 $
 —
 $
 —
 $
 207,099

 Segment assets
 549,275
 152,625
 37,479
 15,230
 —
 754,609

 Cash paid for purchases of property, plant and equipment
 96,692
 17,182
 —
 —
 —
 113,874

 The tables below outlines the revenue from our two major customers, along with their respective percentages of revenue by each segment.

 2024
 2023

 Customer A
 Revenue

 Percentage of total revenue

 Revenue

 Percentage of total revenue

 $
 68,416
 22.8
 %
 $
 56,069
 21.9
 %

 38,841
 12.9
 %
 28,468
 11.1
 %

 6,913
 2.3
 %
 6,614
 2.6
 %

 Total

 $
 114,170
 38.0
 %
 $
 91,151
 35.6
 %

 2024
 2023

 Customer B

 Revenue

 Percentage of total revenue

 Revenue

 Percentage of total revenue

 42,028
 14.0
 %
 28,581
 11.2
 %

 Total

 42,028
 14.0
 %
 28,581
 11.2
 %

 12. Variable Interest Entities
 As of December 31, 2024 and 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. GREP, Emerald, Sapphire, Paragon and SJI were presented as equity method investments and the remaining two VIEs — Sunoma and Central Valley are consolidated by the Company.
 The consolidated balance sheets summarizes the major consolidated balance sheet items for consolidated VIEs as of December 31, 2024 and 2023. The information 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. Equity is listed in the table below.

 As of
2024
 As of
2023

 Equity

 Stockholders' equity
 $
 4,959
 $
 7,893

 Non-redeemable non-controlling interests

 Total equity
 5,577
 8,848

 13. Redeemable non-controlling interests, Redeemable preferred non-controlling interests and Stockholders' Equity
 Common stock
 As of December 31, 2024, there are (i) 30,065,260 shares of Class A common stock issued and 28,429,477 outstanding, (ii) 71,500,000 shares of New OPAL 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), (iii) no shares of Class C common stock issued and outstanding and (iv) 72,899,037 shares of Class D common stock (shares of Class D common stock do not have any economic value except voting rights as described below).
 Share conversion
 On March 12, 2024, Fortistar, through its subsidiary OPAL Holdco LLC, 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 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 LLC. 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. Subsequent to the exchange, Fortistar holds 72,899,037 shares of Class D common stock and 71,500,000 shares of Class B common stock.
 ATM Program
 On November 17, 2023, OPAL Fuels Inc. (the "Company") entered into an At Market Issuance Sales Agreement (the "Sales Agreement") 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.
 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.
 The Company issued 36,353 shares of Class A common stock under the ATM Program during the year ended December 31, 2024 at prices ranging between $ 4.34 and $ 5.68 and received net proceeds of $ 170.
 The Company issued 90,103 shares of Class A common stock under the ATM Program during the year ended December 31, 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.
 On November 29, 2021, NextEra subscribed for up to 1,000,000 Series A preferred units, which were issuable (in whole or in increments) at the Company's discretion prior to June 30, 2022. During the year ended December 31, 2023, the Company had drawn $ 100,000 and issued 1,000,000 Series A preferred units.

 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, 2023 to December 31, 2024:

 Series A-1 preferred units
 Series A preferred units
 Total

 Units
 Units

 Balance, December 31, 2023

 300,000
 $
 30,604
 1,000,000
 $
 102,013
 $
 132,617

 Preferred dividends attributable to OPAL Fuels
 —
 2,019
 —
 6,729
 8,748

 Preferred dividends attributable to Class A common stockholders
 —
 —
 1,325
 1,722

 Payment of Preferred dividends
 —
 ( 3,020)
 —
 ( 10,067)
 ( 13,087)

 Balance, December 31, 2024

 300,000
 $
 30,000
 1,000,000
 $
 100,000
 $
 130,000

 Terms of Redeemable Preferred Units
 The Series A and Series A-1 preferred units (together the "Preferred Units") have 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. In the occurrence of certain events of default, the annual dividend rate increases to 12 %. 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: At 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 upon (i) 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 in which both the Company and the holder may redeem the preferred units. The maturity date is November 29, 2025.
 Conversion: Holders may elect to convert Preferred Units into common units in the limited chance that the Company fails to redeem the Preferred Units under an optional redemption. The annual dividend rate increases to 12 % and is further increased to 14 % after one year, and thereafter by 2 % every 90 days up to a cap 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: (i) the number of Preferred Units, multiplied by (ii) $ 100, plus accrued and unpaid cash dividends, divided by (iii) conversion price. The conversion price is equal to the value of the Company's common units determined as follows, and reduced by a 20 % discount if conversion occurs during the first year of delayed redemption, a 25 % discount during the 2nd year, and a 30 % discount thereafter:
 1. Using 20-day volume-weighted average price ("VWAP") of the Company's common shares.
 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.
 The Series A preferred units have limited rights to prevent OPAL Fuels LLC 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 disposition of assets and (iv) major acquisition of assets outside of OPAL Fuels LLC's primary business. The Series A 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 was allowed to elect to issue additional Series A preferred units ( paid-in-kind) in lieu of cash for the first eight dividend payment dates. As of December 31, 2024 and 2023, there was accrued preferred dividend payable of $ 0 and $ 2,013, respectively.
 At any time after issuance, OPAL Fuels LLC may redeem the Series A preferred units for a price equal to original issue price of $ 100 per unit plus any accrued and unpaid dividends. Upon written notice from NextEra at any time after November 29, 2025, we would be required to redeem the Series A preferred units. In the event the Company does not redeem the Series A preferred units when requested, Nextera will have the following rights and remedies: (1) NextEra's affiliate may extend the RNG Marketing Agreement by 12 months; or (2) the dividend rate would increase depending on the length of time the Series A preferred units remain unredeemed to up to 20 % per annum, and if more than $ 25,000 preferred equity is outstanding for more than six months after November 29, 2025, NextEra may appoint a director to our Board of Directors; or (3) NextEra may convert the Series A preferred equity into common equity of the OPAL Fuels LLC at a conversion price at a 20 % to 30 % discount to their value (the discount is 20 % during the first 12 months after November 29, 2025, 25 % for the next 12 months thereafter and 30 % thereafter).
 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 LLC 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. At each balance sheet date, the Redeemable non-controlling interests are adjusted up to their redemption value if necessary, with an offset in stockholders' deficit. As of December 31, 2024, the Company recorded $ 482,863 to adjust the carrying value to their redemption value based on a five-day VWAP of $ 3.34 per share.

 14. Net Income Per Share
 The following table summarizes the calculation of basic and diluted net loss per share:

 2024
 2023

 Net loss attributable to Class A common stockholders
 $
 $
 18,936

 Diluted Net loss attributable to Class A common stockholders
 18,936

 Weighted average number of shares of Class A common stock - basic
 27,617,335
 27,148,538

 Effect of dilutive Restricted Stock Units
 77,315
 345,478

 Weighted average number of shares of Class A common stock - diluted
 27,694,650
 27,494,016

 Net loss per share of Class A common stock

 Basic
 $
 0.02
 $
 0.70

 Diluted
 $
 0.02
 $
 0.69

 The basic income per share for the year ended December 31, 2024 does not include 1,635,783 shares in treasury and 716,650 shares that are issued and outstanding but are contingent on achieving earnout targets.
 For the periods in which EPS is presented, the following securities were excluded from the computation of diluted EPS since their impact would have been antidilutive:

 As of

 2024
 2023

 Stock options
 498,661
 175,890

 Unvested PSUs

 716,650
 716,650

 Unvested RSUs
 1,761,558
 949,936

 OPAL Fuels Class B units

 144,399,037
 144,399,037

 Additionally, the diluted income per share of Class A common stock for the years ended December 31, 2024 and 2023 does not include Redeemable preferred non-controlling interests because the substantive contingency for conversion has not been met as of December 31, 2024. 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, 2024. It does not include 763,908 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. It also does not include redeemable non-controlling interests (OPAL Fuels Class B units) for the years ended December 31, 2024 and 2023.

 15. Income Taxes
 As a result of the Company's up-C structure effective with the Business Combination, 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 Opal Fuels Inc.'s investment in Opal Fuels LLC would be offset by a full valuation allowance. Prior to the Business Combinations, Legacy Fortistar and its subsidiaries were 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. Additionally, the Company's various tax returns are subject to audit by various tax authorities. Although the Company believes that its estimates are reasonable, actual results could differ from these

 estimates.

 2024
 2023

 Income tax benefit

 $
 ( 8,906)
 $
 —

 The year-to-date effective tax rate for the year ended December 31, 2024 and 2023 was - 62 % and — %, respectively. During the third quarter of 2024, the Company recognized the tax benefit associated with the sale of investment tax credits to a counterparty. Per ASC 740-10-25-46, the Company uses the flow-through method to account for investment tax credits (ITCs). Under the flow-through method, an entity immediately recognizes the cost savings from the tax credit. The entire investment tax credit is accounted for as a reduction in income tax expense in the year the asset is acquired. Accordingly, a temporary difference does not exist when an entity elects to use the flow-through method. Therefore, the Company recognized a total income tax benefit of $ 8,906 during the year ended December 31, 2024 and $ — for year ended December 31, 2023.

 2024
 2023

 Tax at Federal Statutory Rate
 $
 2,978
 %
 $
 26,639
 %

 Tax on Earnings attributable to noncontrolling interest
 ( 2,865)
 ( 20)
 %
 ( 1,063)
 ( 1)
 %

 Section 6418/ITC Sale
 ( 348)
 ( 2)
 %
 —
 —
 %

 Gain on deconsolidation of entities
 —
 —
 %
 ( 25,803)
 ( 20)
 %

 State Taxes, net
 —
 %
 —
 —
 %

 Stock based compensation
 —
 %
 —
 —
 %

 Proceeds from Sale of ITCs, net of selling taxes

 ( 8,906)
 ( 62)
 %
 —
 —
 %

 Other Adjustments
 —
 %
 —
 %

 Change in Valuation Allowance
 %
 —
 %

 Total income tax benefit - continuing operations

 $
 ( 8,906)
 ( 62)
 %
 $
 —
 —
 %

 The components of the deferred tax assets and liabilities are as follows:

 2024
 2023

 Deferred tax assets:

 Investment in partnership
 $
 19,828
 $
 25,133

 163j interest limitation
 1,328

 Federal NOL carryforward
 4,388
 1,165

 State NOL carryforward
 1,436

 Total deferred tax assets
 26,980
 27,691

 Valuation allowance for deferred tax assets
 ( 26,980)
 ( 27,691)

 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, 2024, Opal Fuels, Inc. 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, 2024. For purposes of determining pre-tax income/(loss) for the pre-IPO 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. As of December 31, 2024, Opal Fuels, Inc. is in a three-year cumulative income position, excluding non-recurring items, of approximately $ 1.1 million. However, the primary driver of the cumulative income position as of December 31, 2024, is the income statement impact of the mark-to-market earnout liability. The Company notes that mark-to-market ("MTM") adjustments are volatile and can fluctuate over time. As a result, management has determined that due to the fluctuation of this MTM adjustment and the near breakeven nature of the three-year cumulative income, the Company does not have sufficient positive evidence to release the valuation allowance. 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.
 The Company has deferred tax assets from state net operating loss carryforwards aggregating $ 30.3 million as of December 31, 2024 representing state tax benefits, net of federal taxes, of approximately $ 1.4 million. These loss carryforwards are subject to ten, fifteen, twenty-year, or indefinite carryforward periods, with $ 26.1 million expiring between 2032-2044, and $ 4.2 million with no expiration. The Company has provided valuation allowances of $ 30.3 million and $ 16.6 million as of December 31, 2024 and 2023, respectively, against the state tax loss carryforwards, representing the portion of carryforward losses that the Company believes are not likely to be realized.
 For Federal income tax purposes, the 2021 through 2024 tax years remain open for examination. For state tax purposes, the 2021 through 2024 tax years remain open for examination.

 16. Stock-based Compensation
 2022 Omnibus Equity Incentive Plan
 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.
 Stock Options
 Stock options generally vest over three years and expire ten years from the date of grant.
 The fair value of the stock options issued in 2024 was determined to be $ 3.40 based on Black Scholes model based on the share price of $ 4.96, exercise price of $ 5.02, expiration of 10 years, annual risk free interest rate of 3.96 % and volatility of 55 %.
 The fair value of the stock options issued in 2023 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 %.
 Stock option activity during the year ended December 31, 2024, consisted of the following (in thousands, except for share and per share data):

 Stock options
 Weighted-Average Exercise Price
 Weighted-Average Remaining Contractual Term (Years)

 Outstanding as of December 31, 2023

 175,890
 6.97
 9.24

 Granted

 360,298
 5.02

 Cancelled/Forfeited/Expired

 ( 37,527)
 4.73

 Outstanding as of December 31, 2024

 498,661
 5.65
 8.92

 Vested and exercisable as of December 31, 2024

 53,866
 6.97
 8.24

 The weighted-average grant date fair value of stock options granted during the year ended December 31, 2024 was $ 3.40 per share.
 The aggregate intrinsic value of the outstanding stock options is zero as of December 31, 2024 and December 31, 2023.
 Performance Units
 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. The applicable performance period for performance units granted in 2023 is January 1, 2023 to December 31, 2025, and all such performance units are scheduled to vest on March 31, 2026 subject to achievement of certain performance criteria. The applicable performance period for performance units granted in 2024 is January 1, 2024 to December 31, 2026, and all such performance units are scheduled to vest on March 31, 2027 subject to achievement of certain performance criteria.

 Number of Units

 Weighted-Average Grant-Date Fair Value

 Unvested as of December 31, 2023

 239,680
 $
 6.97

 Granted
 456,308
 4.97

 Vested
 ( 873)
 4.96

 Forfeited
 ( 51,524)
 5.67

 Unvested as of December 31, 2024

 643,591
 $
 5.66

 Restricted stock
 The Company's RSUs are convertible into shares of the Company's common stock upon vesting on a one-to-one basis, and generally contain time-based vesting conditions. The RSUs generally vest over the service period of one to three years.
 A summary of the unvested shares as of December 31, 2024, and changes during the year ended December 31, 2024, is presented below.

 Number of Units

 Weighted-Average Grant-Date Fair Value

 Unvested as of December 31, 2023

 949,936
 $
 6.98

 Granted

 1,470,202
 4.85

 Vested

 ( 326,888)
 7.00

 Withheld for settlement of taxes
 ( 115,843)
 6.98

 Forfeited

 ( 90,582)
 5.49

 Unvested as of December 31, 2024

 1,886,825
 $
 5.39

 The total fair value of shares vested during the years ended December 31, 2024 and 2023, was $ 3,095 and $ 3,210, respectively.
 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, 2024.
 As of December 31, 2024 96 % of the Profit Interests issued vested.
 As of December 31, 2023, 86 % of the Profit Interests issued vested. There were no forfeitures during the years ended December 31, 2023 and 2024.
 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:

 2024
 2023

 2022 Plan
 $
 6,128
 $
 5,264

 Parent Equity Awards

 $
 6,452
 $
 5,903

 Stock-based compensation expense related to unvested awards yet to be recognized as of December 31, 2024 totaled $ 10,986 and is expected to be recognized, on a weighted average basis, over 2 years.

 17. Commitments and Contingencies
 Letters of Credit
 As of December 31, 2024 and December 31, 2023, the Company was required to maintain fourteen and nine standby letters of credit totaling $ 15,120 and $ 14,783, 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.
 Guaranty
 On September 13, 2024, OPAL Paragon entered into a tax credit purchasing agreement with Apollo Management Holdings, L.P., ("Buyer"), pursuant to which OPAL Paragon sold $ 11,096 investment tax credits to the buyer for net proceeds of $ 8,906. If the tax credits are disallowed or recaptured from the Buyer, OPAL Paragon will be required to return the purchase price and pay any taxes, interests or penalties incurred.
 In connection with the above transaction, the Company entered into an agreement that guarantees Opal Paragon's obligations up to $ 16,644. This amount decreases 20 % annually for five years.
 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.
 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 ("MD"), entered into a fixed-price Engineering, Procurement and Construction Contract (an "EPC Contract") with VEC Partners, Inc. d/b/a CEI Builders ("CEI") for the design and construction of a turn-key renewable natural gas production facility using dairy cow manure as

 feedstock in California's Central Valley. In December 2021, a second indirect subsidiary of the Company, VS Digester, LLC ("VS") entered into a nearly identical EPC Contract (collectively, the "EPC Contracts") with CEI for the design and construction of a second facility, also in California's Central Valley. CEI's performance under both of the EPC Contracts is fully bonded by licensed sureties.
 CEI has submitted a series of change order requests seeking to increase the EPC Contract Price by approximately $ 14,000, per project, primarily due to: (1) modifications to CEI's design drawings which are required to meet its contracted performance guaranties, and (2) a default by one of CEI's major equipment manufacturers. The Company disputes the vast majority of the change order requests.
 In January 2024, the Company filed a civil lawsuit captioned, MD Digester, LLC. et. al. vs. VEC Partners, Inc. et. al.; with the 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 has been stayed, pending the conclusion of the arbitration. In the meantime, the AAA has empaneled three experienced arbitrators and has set the hearing date for the matter, currently schedule in May 2026.
 The EPC Agreement requires that CEI, continue working during the course of the litigation and related arbitration proceedings; however, CEI effectively stopped working. Between May and August 2024, MD issued a series of Notices of Default and Demands to Cure to CEI. CEI failed to cure, and on July 30, 2024, MD terminated CEI for default. MD notified CEI's performance bond surety, Atlantic Specialty Insurance Company of the termination and demanded that it perform under the bond. Atlantic has denied the claim.
 On July 11, 2024, VS issued a Notice of Default and Demand to Cure, advising CEI of its defaults and giving it an opportunity to cure. CEI failed to do so, and on August 27, 2024, VS terminated CEI for default. VS has notified CEI's bond surety, also Atlantic, of the second termination and demanded that it perform under the performance bond. The surety has denied the claim.
 As a result of CEI's default and Atlantic's denial of the claims, MD and VS have amended their claims in the AAA arbitration to include breach of contract claims against CEI and breach of performance bond claims against Atlantic (who was formally joined into the arbitration on November 20, 2024) in the AAA Arbitration with CEI.
 CEI has since recorded mechanic's liens against each of the projects for $ 4,900 (MD) and $ 2,000 (VS), and recently filed actions with the Stanislaus and San Joaquin County Superior Courts, respectively, to enforce their liens. It is expected that these claims will be stayed and consolidated with the pending arbitration proceeding.
 In addition to the above-referenced action and arbitration, several of CEI's subcontractors have recorded mechanic's liens against the MD and VS projects, which the Company is obligated to defend and indemnify the dairy owners from and against. Several of liens were untimely and have been released.
 The Company believes its claims against CEI (and the surety where bond claims are denied) have substantial merit, and intends to prosecute the claims vigorously. However, due to the incipient stage of the litigation and related arbitration, the recency of the termination, and the ongoing status of the proceedings and discussions with the bond surety, as well as the uncertainties involved in all litigation and arbitration, the Company is unable at this time to assess the likely outcome of the litigation and related arbitration, the timing of its resolution, or its ultimate impact, if any, on the Central Valley projects or the Company's business, financial condition or results of operations.
 Former Development Partner/Construction Manager
 In March 2024, the Company filed an action in the Orange County Superior Court (Case No. 30- 2024-01415510-CU-BC-CXC) against its former development partner and construction manager, Sierra Renewable Organics Management, LLC, as well as its principal (Ethan Werner) and affiliated engineering firm (CH Four Biogas) for Breach of Contract, Indemnity, Declaratory Relief, Intentional Misrepresentation and Negligent Misrepresentation relating to the design and development of the Projects. The case is not yet at issue, so no answer or cross claims have been filed yet, and no discovery has been conducted.

 18. Subsequent Events

 Wasatch Resource Recovery Facility
 On March 17, 2025, Fortistar, through its subsidiary Wasatch RNG LLC ("Wasatch RNG"), acquired all of the limited liability company interests outstanding in Alpro SD, LLC ("Alpro" and such acquired interest, the "Alpro Interest"). Alpro owns a 50 % limited liability company interest in Wasatch Resource Recovery, LLC (the "Project" or "Wasatch" and such ownership interest, the "Wasatch Interest") and a 50 % tenancy -in -common interest in certain real estate and operating assets used by Wasatch (the "Project Interest"). As a result of the acquisition, Wasatch RNG has the option to increase the Wasatch Interest and the Project Interest.
 The Project captures and converts biogas generated from food waste to produce pipeline quality renewable natural gas (RNG). The Project generates revenue from long-term contracted gas sales, tipping fees, and digestate (fertilizer) sales. The conversion of food waste to RNG presents a potential growth and diversification opportunity for OPAL Fuels.
 In connection with the acquisition, Fortistar Services 2 LLC and OPAL Fuels LLC entered into an amendment to its existing Administrative Services Agreement, pursuant to which OPAL Fuels will provide certain services to Wasatch RNG in exchange for certain agreed upon fees and expense reimbursements. These services include oversight of the plan to improve the operations and productivity of the Project.
 Additionally, Wasatch RNG and OPAL Fuels entered into an Option Agreement, pursuant to which Wasatch RNG granted an option to OPAL Fuels to purchase the Alpro Interest. The exercise period of the option commenced upon closing of the acquisition and will terminate on the third anniversary of the closing of the acquisition, or ninety days following a change of control of OPAL Fuels. The exercise price of the option would be determined such that Wasatch RNG would earn an internal rate of return on its invested capital of 10 % percent per year if the option is exercised in the first year, 15 % per year if exercised in the second year, and 20 % per year if exercised in the third year.
 On March 3, 2025, OPAL Fuels Intermediate HoldCo LLC, as the borrower (the "Borrower"), certain subsidiaries of the Borrower, as guarantors (the "Guarantors"), the lenders and issuers of letters of credit party thereto and Bank of America, N.A. as the administrative agent (the "Administrative Agent") entered into that certain Amendment No. 1 to Credit and Guarantee Agreement (the "Credit Agreement Amendment"), with respect to that certain Credit and Guarantee Agreement (the "Credit Agreement") dated September 1, 2023, by and among the Borrower, the Administrative Agent, the financial institutions from time to time parties thereto as lenders and as issuers of letters of credit, and the other agents and persons from time to time party thereto (as amended, restated, amended and restated, supplemented or otherwise modified and in effect from time to time).
 The Credit Agreement Amendment makes certain changes to the applicability of certain financial covenants and modifies other covenants to clarify the use of loan proceeds. Additionally, the Credit Agreement Amendment permits the organizational restructuring of the Guarantors in a manner designed to facilitate the sale of federal investment tax credits and the ability to raise additional future capital.
 The Credit Agreement Amendment also eases the conditions precedent to making new Projects eligible for borrowing under the Credit Agreement, extends the availability period for delay draw term loans under the Credit Agreement through March 5, 2026, and extends the commencement of repayment of such term loans until March 31, 2026.
 In connection with the Credit Agreement Amendment, the Borrower paid the Administrative Agent, for the account of each lender, a one-time nonrefundable fee of $ 1,250.