Summary of California Low Carbon Fuel Standard Workshop – April 2024
The California Air Resources Board (CARB) held a workshop on April 10, 2024, addressing the proposed regulatory amendments to the California Low Carbon Fuel Standard (LCFS) program. This workshop discussed potential revisions to the rule, as well as sought additional feedback and comments from stakeholders. EcoEngineers is providing the following summary to highlight potential changes and areas of re-evaluation from the initial proposal.
CARB proposed four new step-down scenarios under consideration for the final rule. In creation of the new scenarios, CARB has updated the modeling to reflect:
Increased tailpipe emissions factors for methane (CH4) and nitrous oxide (N2O) affecting renewable diesel, biodiesel, and ultra-low sulfur diesel (ULSD);
Increased supply assumptions for renewable diesel from virgin oils and waste oils;
Energy demand from plug-in hybrid electric vehicles (PHEVs) and medium-duty vehicles (MDVs).
The first three of the new scenarios being analyzed reflect step-downs at 5%, 7%, and 9%. All three of the scenarios result in a 30% carbon intensity (CI) reduction by 2030 and a 90% CI reduction by 2045. The fourth scenario being analyzed is a 5% step-down in 2025 with the auto-acceleration mechanism triggered twice. This results in a 39% CI reduction by 2030 and 90% CI reduction in 2043. EcoEngineers had recommended a steeper step-down rate in the company’s written comments to CARB, and several commenters in attendance also supported a steeper step-down, many with preference for 9%.
The following chart from compares the modeled scenarios:
Source: CARB, LCFS Workshop Slide #47
Feedback was requested from CARB to determine the appropriate scenario to implement.Specific feedback requested is shown in the following:
Source: CARB, LCFS Workshop Slide #49
Sustainability Criteria
In addition to the originally proposed regulation, CARB is evaluating an increase in LUC values for high-risk feedstocks and methods to increase traceability, verification, and/or enforcement of waste feedstock. LUC changes may be based on empirical sub-national data, such as remote sensing or satellite monitoring. CARB requested feedback for potential data sources.
Additionally, CARB indicated several times throughout the workshop that they are interested in obtaining feedback for how the proposed sustainability certification should be implemented. Originally proposed regulations were based on existing certification programs, for example, International Sustainability and Carbon Certification (ISCC).
MDV/HDV Infrastructure
Though not a focus of the staff’s presentation, many commenters spoke with concern for the MDV/HDV infrastructure crediting regulations. Specifically, regulations regarding the number of eligible chargers at a specific site, which must be less than 10 under the current proposal, is too low, and geographic siting is a major hinderance. CARB expressed openness to obtaining feedback and updating the rules.
Timeline
The timeline for the implementation of the LCFS amendments was provided and is demonstrated below.
Three Priority Takeaways from the USEPA’s RFS Set Rule Implementation Webinar – April 2024
The U.S. Environmental Protection Agency (USEPA) hosted a webinar on April 12, 2024, that served to further clarify the Biogas Regulatory Reform Rule (BRRR) provisions of the Renewable Fuel Standard (RFS) program. EcoEngineers submitted many questions on behalf of our clients for this presentation, and a number of employees attended in the live event.
Overall, our experts have highlighted three priority takeaways for biogas and renewable natural gas (RNG) producers from the webinar:
The USEPA reinforced the implementation process and timeline for the BRRR over the next six to eight months. The USEPA will work to re-register existing RNG facilities between July and October. All facilities must be compliant under the new rules by January 1, 2025.
Eco believes that most existing facilities will need to submit an Alternative Measurement Protocol (AMP) with their registration. The AMP will demonstrate how the facility is measuring and metering the gas flows to provide the necessary data within the regulation if all meters do not meet the published specifications per 40 CFR 80.155. Facilities should start drafting these plans now to be submitted with their registration packages.
Facilities will need to provide information in their RIN generation protocols outlining data substitution methodologies in the event data is not collected from an out of service or failed piece of metering equipment which often occurs at some point in a facilities operation. Biogas and RNG producers should begin work on these plans and understand how they may affect other programs they participate in like CA-LCFS and others.
EcoEngineers is following these RFS developments throughout the year, and we are here to help you understand the regulations though our education, engagement, and compliance services we offer.
The European Commission’s (EC’s) recent implementation of the Union Database (UDB) represents a significant development in facilitating the traceability of renewable fuels in the European Union (EU) Member States (MS). While currently operational for liquid biofuels, the UDB is set to encompass gaseous renewable fuels such as biomethane by November 21, 2024, aligning with the Renewable Energy Directive III (RED). Since the need to satisfy renewable energy quotas drives a large part of the incremental value of these molecules compared to existing fossil fuel products, this change is relevant to all suppliers of biomethane to the EU market, potentially impacting the commercial feasibility of projects currently under development.
Once the UDB opens for gaseous renewable fuels, certification of biomethane from third countries’ grid will only be possible if the foreign grid meets the conditions described in Article 31a of the RED and the implementing regulation. The foreign grid must ensure full traceability of the biomethane injected and withdrawn from the grid in a mass balance system. In particular, information on sustainability and any support provided for the production of a specific consignment of fuel will have to be recorded in the UDB.
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Based on the RED and EC’s guidelines, the U.S. grid is not compliant with the European definition of interconnected infrastructure and is not considered a single mass balance system and therefore is not part of the UDB system. The limiting factor in the U.S. is the lack of a federal database to track the sustainability, production, transfer of title, and retirement of the environmental attributes of biomethane.
Recent developments around the UDB present serious challenges for the trade of biomethane between the U.S. and the EU and carry significant repercussions that can jeopardize access of the U.S. biomethane to the EU. There are currently several working groups within the U.S. reviewing alternatives to comply with EU regulations. Whether it is amending the U.S. Environmental Protection Agency (USEPA) Moderated Tracking System (EMTS) to track non-transportation biomethane and include the functionality to capture the emission reduction benefits or utilizing the Midwest Renewable Energy Tracking System (M-RETS®), a registry platform that tracks voluntary biomethane in the U.S., many industry participants feel there is a solution to meeting the EU requirements.
EcoEngineers is your strategic partner in navigating this intricate regulatory landscape, advising you on proactive essential measures to access European market. We bring expertise in both the U.S. and EU regulatory and market developments to help U.S. biomethane suppliers streamline compliance efforts and ensure market integration and business growth on both sides of Atlantic. We also developed an in-depth educational program on the EU’s renewable energy and cap-and-trade systems to help our clients position themselves in the expanding European biomethane market and make strategic business decisions.
About EcoEngineers
EcoEngineers is a consulting, auditing, and advisory firm with an exclusive focus on the energy transition. From innovation to impact, we help you navigate the disruption caused by carbon emissions and climate change. We help you stay informed, measure emissions, make investment decisions, maintain compliance, and manage data through the lens of carbon accounting. Our team of engineers, scientists, auditors, consultants, and researchers live and work at the intersection of low-carbon fuel policy, innovative technologies, and the carbon marketplace. Eco was established in 2009 to steer low-carbon fuel producers through the complexities of emerging energy regulations in the United States. Today, our global team is shaping the response to climate change by advising businesses across the energy transition. Together, we can create a world where clean energy fuels a healthy planet.
EcoEngineers is accredited by ANSI National Accreditation Board (ANAB) as a greenhouse gas (GHG) verification body in accordance with ISO standards ISO/IEC 17029:2019, ISO 14065:2020, and ISO 14064-3:2019.
For more information, please contact:
Urszula Szalkowska, Managing Director, Europe | uszalkowska@ecoengineers.us
We answer questions from our most recent M-RETS webinar
With market uncertainty on the rise, many renewable natural gas (RNG) players are looking to diversify their credit pools. This EcoEngineers webinar aired for the public on March 5, 2024. It introduced an audience of more than 250 attendees to the Midwest Renewable Energy Tracking System (M-RETS) and its third-party verification process. Our experts examined the similarities and differences between audits under M-RETS, the California Low Carbon Fuel Standard (LCFS), and the U.S. Renewable Fuel Standard (RFS).
Current and prospective renewable thermal certificate (RTC) generators received new insight into the process from one of the industry’s top verification bodies and learned how it could apply to their businesses. This comparative approach guided generators through the process by using familiar programs to build their understanding in an easy-to-digest manner.
Due to time constraints, many questions went unanswered during the presentation, and we wanted to make sure we addressed them. Keep in mind without proper due diligence and knowledge gathering required to answer specific projects, we are speaking mostly in industry generalities. Watch the full webinar here.
Q: Are there any accreditation requirements for the Professional Engineer (P.E.) certifying the production, such as accreditation by the ANSI National Accreditation Board?
A: In the United States, the P.E. will need to be certified in the state where the facility is located. In Canada and Mexico, the engineer can be certified in any U.S. state or those respective countries.
Q: Would M-RETS qualify to meet the energy attribute certificate (EAC) requirements to reduce the carbon intensity (CI) of hydrogen under the 45V clean hydrogen tax credit program?
A: Much is still unknown about this tax program, but according to the proposed 45V rules: “The EPA has advised that EACs are an established mechanism for substantiating the purchase of electricity from zero GHG-emitting sources and that the use of EACs with attributes that meet certain criteria is an appropriate way for the Treasury Department and the IRS to document electricity inputs to electrolytic hydrogen production. Such EACs can also serve as a reasonable methodological proxy for quantifying certain indirect emissions associated with electricity for purposes of the section 45V credit. Similarly, the EPA and the DOE have advised that it would be appropriate for EACs with attributes that meet certain criteria to be included as part of the basis for assessing emissions for purposes of the section 45V credit.”
Q: Over what period is the CI score verified? Can a prior year CI score be used for later years?
A: CI is verified annually. Eco’s verification process includes verifying the CI score as soon as it is provided to us, and then every year afterward.
Q: With the new RFS set rule on gas storage, would it be practical to enter the program while trying to get RFS registration, so the value of gas is not lost?
A: Yes, we see this as one of the best opportunities M-RETS offers.
Q: Are there any specific metering quality or continuous measurement requirements under M-RETS for quantifying the biogas volume/quality? Is this similar or different from LCFS or RFS’s Biogas Regulatory Reform Rule (BRRR)?
A: This process is similar to LCFS and RFS requirements. Inlet biogas flow and methane content data must be monitored continuously, but there is not a 15-minute requirement as there is for the LCFS.
Q: Is the M-RETS program only applicable in Canada, Mexico, and the U.S.? Can it extend to other Central American and Caribbean Island nations?
A: Currently, there are no facilities outside of those three countries, but M-RETS is open to all nations in North America.
Q: How is double counting avoided if a generator is selling into the voluntary markets?
A: Generators must provide supporting documentation, including attestations, to demonstrate that double counting is not occurring. The verifier reviews this evidence as part of the audit process and checks it against other information at our disposal.
Q: If a dairy digester generated gas five years ago, and the gas was not eligible for RFS or LCFS credits at that time, would that gas be eligible for credits under M-RETS?
A: It depends on the reason for the gas not being eligible for the RFS or LCFS. If it was not eligible because it did not meet the feedstock requirements, it may be eligible in M-RETS. However, if the facility did not have meters in place to measure the flow of inlet biogas or the product gas volume, it is likely ineligible in M-RETS.
Q: Does gas qualify if it is being used by an end user and displacing natural gas — even though it is not pipeline-quality?
A: It may qualify, but since it is not pipeline-quality, it will have to be approved by M-RETS. Reach out to M-RETS with the specifics of the project, and they will be able to tell you if the project qualifies.
Q: Does your CI score impact the value of the RTC?
A: The value of your RTC depends on the contract with a particular buyer/end user and if they are willing to pay a premium for a lower CI attached to the certificate.
Q: If a project is participating in the LCFS program, why must that production be reported for M-RETS too?
A: M-RETS requires that all production be reported into their portal, so they can track all the production from generators in the program. This helps prevent double counting.
Q: Does M-RETS require audits to create RTCs? If not, does M-RETS show which RTCs were audited, and which were not?
A: If a generator is not splitting their production between multiple programs (i.e., they are sending all their production to M-RETS), a verification body is not required. However, any generation that occurs without being verified receives a higher level of scrutiny from the M-RETS system administrator.
Q: Where are the values of traded RTCs published?
A: The credits are not traded on an open market (as they are with RINs or Renewable Identification Numbers). The prices are much less transparent because they are individual agreements between an end user and the producer. M-RETS is merely the matchmaking platform for these two entities.
Red Trail Energy LLC (RTE) is now the first ethanol producer to enter the voluntary carbon markets – and the largest carbon removal project registered to date.
RTE is a 64 million-gallon-per-year corn ethanol production facility located near Richardton, North Dakota. In March 2024, RTE became the first producer in the U.S. to generate carbon dioxide (CO2) Removal Certificates (CORCs) in the Puro.earth registry for capturing and injecting the CO2 produced during the fermentation process at its plant. RTE captures the CO2, which would otherwise be emitted into the atmosphere, and injects it for permanent storage into an underground Class VI well located approximately 6,500 feet directly beneath its facility.
“We have not only achieved a groundbreaking milestone as one of the first bioenergy facilities with carbon capture and storage (CCS) but have also emerged as pioneers in bringing verified carbon dioxide removal (CDR) credits to the market. This program strengthened our position in the ethanol industry and has set a new standard for sustainability and innovation, driving positive change and demonstrating the viability of proactive environmental stewardship within our industry,” said Jodi Johnson, Chief Executive Officer, Red Trail Energy.
This case study demonstrates the opportunity for corn ethanol producers in the U.S. to take advantage of voluntary carbon markets (VCMs) and create alternate revenue streams that reduce project risks and create optionality for bioenergy with carbon capture and storage (BECCS) projects. It also sets the standard for other industries to follow.
“Monetizing CDR credits in the voluntary markets can be an important complementary revenue stream for companies across industries to support decarbonization efforts. Our goal was to help set RTE up for success in the regulated markets while helping them break new ground in voluntary markets. This gives RTE a significant competitive advantage within the ethanol sector and serves as a new industry standard for others to follow,” said Shashi Menon, Chief Executive Officer, EcoEngineers.
Pivotal Year for the Nation’s Largest Transportation Fuel Markets
By Lyndsey Nielsen, EcoEngineers
With the recent news of the state of New Mexico starting the process of developing its own Clean Transportation Fuels Standard, knowledge of the country’s low-carbon transportation fuel markets is more important than ever. These markets continue to drive the world toward decarbonization, and EcoEngineers has been the go-to consultant and auditor in these programs since 2009.
Eco is passionate about educating our clients on their journey to clean energy. The experts on our EcoUniversity team have been working in the regulatory landscape for decades, and they have analyzed data from two of the most influential low-carbon fuels programs in the United States transportation fuel markets in our two annual outlooks. Coming in March 2024, Eco is proud to publish our fourth edition of our California Low Carbon Fuel Standard (CA-LCFS) Fuel Supply and Credit Pricing Analysis and the third edition of our U.S. Environmental Protection Agency’s (USEPA) Renewable Fuel Standard (RFS) Credit Pricing Analysis.
The CA-LCFS remains the largest market in the country for low-carbon fuels despite the recent dip in credit prices. Over the next three years, there will be an increasing oversupply of credits in this market. The price reduction from the previous report is primarily the result of two factors: 1) the increased value of cap-at-the-rack, and 2) strategic choices by refiners to move toward a low-carbon future. Modeling performed by Eco’s experts also shows an increasing contribution to the gasoline credit pool from electric vehicle (EV) energy consumption that is likely to become more important over the second half of this decade. We are poised to follow the regulation’s progress throughout the year, in a volume and credit market capacity.
In June 2023, the USEPA published the first post-2022 RFS rulemaking schedule, called the Set Rule, which was the most comprehensive rulemaking in 10 years. The rule changed annual rulemakings that had previously adjusted biofuel volume mandates to accommodate trends in biofuel production. Instead, the USEPA issued three years of preset volumes across 2023-2025, attempting to create more market certainty for the Renewable Volume Obligations (RVO) compliance requirements within the RFS. The imperfections and difficulty of its estimates have created sectors of oversupply and undersupply in the Renewable Identification Number (RIN) market, which has caused significant RIN pricing variations within biofuel markets throughout 2023 and early 2024.
The analyses’ authors, Dr. Roxby Hartley and Paul Niznik, have been working in the low-carbon fuels field for decades, analyzing and modeling potential markets for low-carbon transportation fuel credits. Dr. Hartley is Eco’s Climate Risk Director. He focuses on both compliance and voluntary carbon methodologies, building carbon models, and researching how biodiesel and renewable diesel fuel types integrate into regulatory markets. He has more than a decade of experience in scientific research, development, and management of low-carbon diesel substitutes. Mr. Niznik is a Senior Carbon Consultant for Eco and is an expert on biofuel markets and mandates. His due diligence work has been used in the financing of some of the most capital-intensive low-carbon fuel projects in the nation.
This expertise, combined with Eco’s presence as engineers, regulatory experts, and renowned scientists is invaluable in the volatile election year market we are facing in the U.S. this year. These two outlooks — and their periodic updates provided throughout 2024 — will give your business an advantage regarding regulatory changes occurring in the transportation fuel markets in which you operate.
Understanding and Measuring the Environmental Impact of Clean Hydrogen Production with LCA
New Policies and Tax Credits Require Quantifiable Emissions
By Tanya Peacock, EcoEngineers
As the world seeks sustainable energy solutions, clean hydrogen is emerging as a promising option among various approaches to decarbonization. Its potential to revolutionize energy consumption is particularly notable in heavy industries and transportation sectors where decarbonization poses significant challenges. To better understand hydrogen’s role in the energy transition alongside other decarbonization strategies, we need to understand the environmental aspects of producing, transporting, and using clean hydrogen.
The Importance of Life-Cycle Analysis (LCA)
LCA has emerged as a key tool in understanding the environmental impacts of not only hydrogen production but also a myriad of low-carbon fuels and pathways. This methodical approach accounts for the emissions across a product’s life stages. From extraction to disposal, LCA quantifies carbon emissions across various production pathways and is essential for transitioning to cleaner energy.
Recent policies, including the Inflation Reduction Act (IRA), have made it imperative to quantify life-cycle greenhouse gas (GHG) emissions for hydrogen on a well-to-gate life-cycle basis to qualify for the new 45V clean hydrogen production tax credit. This guidance, which offers up to $3 per kilogram of hydrogen with a carbon intensity (CI) below certain thresholds, underscores the importance of LCA models like the Argonne National Laboratory’s Greenhouse Gases, Regulated Emissions, and Energy Use in Technologies (GREET) model used in government support mechanisms such as the 45V clean hydrogen production tax credit.
Making Clean Hydrogen Cleaner
The quest for cleaner hydrogen has drawn attention to blue and grey hydrogen projects, and its sustainability continues to be a point of focus. One innovative strategy for improving hydrogen’s environmental attributes involves leveraging renewable natural gas (RNG) credits. Market mechanisms like California’s Low Carbon Fuel Standard (LCFS) encourage RNG’s use for CI reduction by employing a book-and-claim system — a common accounting method where a sustainability claim made by a company is separated from the physical flow of these commodities. Yet, the proposed 45V clean hydrogen tax credit guidance from the U.S. Treasury and Internal Revenue Service (IRS), while allowing RNG use, awaits further clarification on compliance. The U.S. Department of Energy (DOE) also requires additional validation if RNG feedstock does not fit within the parameters of the 45VH2-GREET model.
Carbon capture and storage (CCS) is another critical component in the clean hydrogen narrative, and its potential to enable large-scale clean hydrogen production is significant. By utilizing established infrastructure and benefiting from economies of scale, CCS can be a powerful ally toward net-zero goals, especially with the financial incentive of 45V tax credits.
The U.S. Environmental Protection Agency (USEPA) has not yet approved any hydrogen pathways for Renewable Identification Number (RIN) generation under the Renewable Fuel Standard (RFS). Multiple pathway petitions have been filed by EcoEngineers and others on behalf of their hydrogen clients.
Clean Hydrogen Future Hinges on Low-Carbon Pathways
Hydrogen production from unconventional sources, such as dairy manure, requires detailed LCAs to calculate the CI accurately. The technology choice for hydrogen production, from steam methane reforming (SMR) to electrolysis powered by renewable energy, directly influences the CI score derived from LCA. Producers are motivated to lower their CI not just to comply with regulations but to monetize credits and/or tax incentives and to meet sustainability targets.
The 45V clean hydrogen production tax credit guidance also outlines criteria for sourcing renewable power for hydrogen production. While on-site production is an option for some projects, any grid power used must be verified as renewable through Energy Attribute Certificates (EACs), adhering to strict registration and accounting standards.
Additionally, producers of clean hydrogen face the ongoing task of updating their LCA in alignment with GREET model revisions. The IRA mandates annual LCA updates, ensuring that life-cycle GHG emissions rate calculations are based on the latest data. Additionally, the LCA must address co-products and their emissions, with a clear methodology from regulatory bodies to ensure fair assessments, especially regarding emission allocations to co-products or crediting clean hydrogen production when displacing less clean hydrogen. Also required are annual verification reports performed by an unrelated party.
Summary
Understanding the CI of hydrogen is not just about regulatory compliance; it’s a business imperative. Project developers are incentivized to explore technology options and process improvements to reduce the CI of their hydrogen. Comprehensive LCA services are invaluable, assessing hydrogen CI and identifying strategies for carbon reduction. These services support project developers and policymakers in making informed decisions that align with environmental and economic objectives, aiming to create a transparent, consistent, and fair clean hydrogen market that reflects the true environmental costs and benefits of production methods.
Integrating RNG credits, alongside strategic use of CCS and meticulous LCAs is critical for hydrogen production’s evolution towards sustainability. The interplay of regulations, market incentives, and technological advancements will determine the pace and scale of hydrogen’s role in the energy transition. As the clean hydrogen economy expands, our approach to measuring and managing its environmental impact must evolve in tandem, ensuring that a greener future is within reach.
For more information about our clean hydrogen services, contact:
There has been a growing focus on Scope 1, 2, and 3 carbon emissions, both in governmental body legislation and individual company climate goals. But what do they really mean? And how does a company search up and down its supply chain to account for its emissions? The carbon experts at EcoEngineers will describe these scopes and how to measure and report them, with an emphasis on Scope 3 demands. Through the lens of a plastic bottle manufacturer, we will discuss the reporting options, potential uses of the data, next steps for companies facing greenhouse gas reporting requirements, and how these measurements can put your company at a competitive advantage above other firms. We hope you can join us!
Summary of the Production of Clean Hydrogen Credits Under Section 45V of the Internal Revenue Code
The U.S. Department of the Treasury (Treasury Department) and the Internal Revenue Service (IRS) on December 22, 2023, released proposed regulations for the Section 45V Credit for the Production of Clean Hydrogen. The proposal contains rules for lifecycle greenhouse gas (GHG) emissions, verification of projects, and modification/retrofitting of clean hydrogen facilities in relation to the tax credit.
Highlights
Lifecycle GHG emissions will be calculated through the point of production (well-to-gate) using the most recent version of the 45VH2—GREET (Greenhouse gases, Regulated Emissions, and Energy use in Technologies) model, considering hydrogen production pathways and feedstocks included in the new 45VH2-GREET model.
Taxpayers can show that electricity used in the hydrogen production process is from a specific source, rather than the grid, by acquiring and retiring Energy Attribute Certificates (EACs) for each unit of energy produced and used. Eligible EACs are to be recorded through a registry/accounting system and meet requirements on incrementality, temporal matching, and delivery.
Third-party verification of the production and sale of the hydrogen is required for each tax year. Verification is also needed for EACs purchased and retired.
Credit for facility modification applies to facilities that did not produce clean hydrogen before January 1, 2023, or were modified to be able to produce under 4 kilograms CO2e per kilogram of hydrogen.
There are no proposed rules relating to renewable natural gas (RNG) used to produce hydrogen, although the final rules may require that for an emissions value to be consistent with the RNG/fugitive methane used, the gas must originate from the first productive use.
A Qualified Clean Hydrogen facility is defined as a single production line used to produce hydrogen to the point of production.
Section 45V credits are available for hydrogen produced in the U.S. or a U.S. territory and sold or used within or outside the U.S.
Comment Period
Comments on the NPRM are due by February 26, 2024. Given the need for additional clarity and guidance from Treasury/IRS on key issues, EcoEngineers is available to assist you with the analysis of the proposed regulations and the preparation of comments. Areas to focus on in written comments include the impact of the proposed regulations on project development plans, including how the proposed regulations may result in revised investment decisions, with associated impacts on domestic manufacturing, jobs, and participation in Regional Clean Hydrogen Hubs.
For more information, please contact Tanya Peacock, Managing Director, Hydrogen, at tpeacock@ecoengineers.us.
Full Summary
Proposed regulations for the Section 45V Credit for Production of Clean Hydrogen were released on December 22, 2023, containing rules for lifecycle GHG emissions, verification of projects, and modification/retrofitting of clean hydrogen facilities in relation to the tax credit. Comments on the proposed rule must be received by February 26, 2024. A proposed hearing is scheduled for March 25, 2024, at 10 a.m. ET. Requests to testify must be received by March 4, 2024.
In addition to the Notice of Proposed Rulemaking (NPRM), the Administration released the new 45VH2-GREET 2023 model and accompanying manual, a letter from the U.S. Environmental Protection Agency (USEPA) that outlines guidance to the Treasury Department regarding reference to the Clean Air Act in 45V, and a U.S. Department of Energy (DOE) whitepaper that supports the approach taken in the proposed regulations to assessing the lifecycle GHG emissions of electricity used to produce hydrogen.
Taxpayers may rely on these proposed regulations for taxable years beginning after December 31, 2022, and before the date the final regulations are published in the Federal Register, provided taxpayers follow the proposed regulations in their entirety and in a consistent manner.
Determination of Lifecycle GHG Emissions
Lifecycle GHG emissions will be calculated through the point of production (well-to-gate) using the most recent version of the 45VH2—GREET model. Factors considered in lifecycle emissions include feedstock growth, gathering, extracting, processing, and delivery to the facility, and emissions in the production process, including electricity used and carbon capture and sequestration (CCS) done by the facility.
The “most recent version” of the 45VH2-GREET model is considered the model that is publicly available on the first day of each taxable year of which the hydrogen claimed under 45Q was produced. If a newer version is available after the first day of the taxable year, it can be used at the taxpayers’ discretion.
Hydrogen Pathways and Feedstocks
Hydrogen production pathways and feedstocks included in the new 45VH2-GREET model include:
Steam methane reforming (SMR) of natural gas, with potential carbon capture and sequestration (CCS)
Autothermal reforming (ATR) of natural gas, with potential CCS
Steam methane reforming (SMR) of landfill gas with potential CCS
ATR of landfill gas with potential CCS
Coal gasification with potential CCS
Biomass gasification with corn stover and logging residue with no significant market value with potential CCS
Low-temperature water electrolysis using electricity
High-temperature water electrolysis using electricity and potential heat from nuclear power plants
Petitions can be filed for a Provisional Emissions Rate (PER) if the GHG emissions rate for feedstock or production technology is not included in the most recent GREET model. An emissions value will have to be requested from the DOE and then included with a PER petition. Following acceptance of the emissions value and PER, the emissions value may be used to calculate credit under 45V. The PER process will only address hydrogen production pathways using biogas and RNG not included in the 45VH2-GREET 2023 model after the final regulations are issued.
Electricity and Energy Attribute Credits (EACs)
Taxpayers may show electricity used in the hydrogen production process as being from a specific source, rather than the grid, by acquiring and retiring EACs for each unit of energy produced and used. Renewable Energy Certificates (RECs) are included as a form of EACs. Eligible EACs are to be recorded through a registry/accounting system and meet requirements on incrementality, temporal matching, and delivery.
To meet the incrementality requirement, the electric generating facility that supplies the electricity that the EAC is based upon must have a commercial operations date (COD) that is no more than 36 months before the hydrogen production facility is placed in service. An alternative test is the requirements may be met if the electricity generating facility has not had an uprate (increase in nameplate capacity) more than 36 months before the hydrogen facility was placed in service and that electricity is part of the uprated production. Other approaches are also being considered such as an avoided retirement approach, a zero or minimal induced grid emissions approach, and a formulaic approach that would allow a fixed percentage of electricity from all existing clean power generators to qualify based on expected curtailment rates. The Treasury Department is seeking comments on these approaches.
The temporal matching requirement may be met by demonstrating that the EAC is generated within the same hour that it is consumed by the hydrogen facility. However, there is to be a transition rule in place, as the ability to track by the hour is currently limited. Until 2028, the transition rule will allow annual matching.
The deliverability requirement is met if the EAC electricity is generated by a source in the same region as the hydrogen facility. “Region” is defined as the U.S. regions defined in the DOE Needs Study. The region hydrogen facilities and generating sources are located is based on the location of the balancing authority to which it is electrically interconnected. The Treasury Department is seeking comments on whether the regions are appropriate as designed, per the table shown below.
Source: DOE
Verification of Production and Sale
Third-party verification of the production and sale of the hydrogen is required for each tax year. Verification is also needed for EACs purchased and retired.
A verification report is to include product attestation, sale or use attestation, conflict attestation, a qualifier verifier statement, general information about the facility (location, production description/method, feedstock, amount of feedstock used, list of metering devices and statement on quality control/calibration/activation), and documentation to substantiate the verification process.
A ”qualified verifier” is an individual or organization with active accreditation as a validation and verification body from the American National Standards Institute (ANSI) National Accreditation Board (ANAB), or a verifier, lead verifier, or verification body under California’s Low-Carbon Fuel Standard (LCFS) program. EcoEngineers has been granted accreditation from ANAB, in accordance with the International Organization for Standardization (ISO) standards ISO/IEC 17029:2019 Conformity assessment — General principles and requirements for validation and verification bodies.
Modification of an Existing Facility
Credit for facility modification applies to facilities that did not produce clean hydrogen before January 1, 2023, or were modified to be able to produce under 4 kilograms CO2e per kilogram of hydrogen. The date placed into service for modified facilities will be changed to the date the property required to complete the modification is placed in service. Existing facilities may have the date placed into service updated to the date that new property is added, so long as the used property is not more than 20% of the facility’s total value (80/20 rule). Replacing natural gas with biogas or renewable natural gas in the hydrogen production process does not qualify as a facility modification under the proposed rules.
RNG and Fugitive Sources of Methane
There are no proposed rules relating to RNG used to produce hydrogen, though it is suggested that the final rules may require that for an emissions value to be consistent with the RNG/fugitive methane used, the gas must originate from the first productive use. Otherwise, the gas would be given an emissions value consistent with natural gas. Attribute certificates would need to be acquired and retired to demonstrate procurement of the gas and that environmental attributes are not being sold to other parties or used for compliance with other policies and programs. Additionally, hydrogen producers would be required to have a pipeline interconnection and measurement using a revenue grade meter. There are 12 questions listed in the proposed rules asking for comments relating to RNG/fugitive methane used in hydrogen production.
Additional Rules
A Qualified Clean Hydrogen facility is defined as a single production line used to produce hydrogen to the point of production. A single production line is defined as all components of property that function interdependently to produce hydrogen. Electricity production equipment is not included in the definition of a facility. Components with purpose in addition to the production of hydrogen may be part of the facility if they function interdependently with other components to produce the hydrogen.
The “taxpayer” is who owns the hydrogen facility at the time of production to which the credit is claimed, regardless of if they are the “producer.” Credit is determined for all produced in a hydrogen taxable year, regardless of whether verification or sale of produced hydrogen occurred in that year. Still, the credit cannot be claimed until verification occurs. Thus, the taxpayer would have to file an amended return or administrative adjustment if verification occurs after the return filing deadline.
An anti-abuse rule is to be implemented to make credit unavailable if the purpose is to produce in a wasteful way. This includes if the taxpayer knows, or has reason to know, that the hydrogen produced is to be vented, flared, or used to create additional hydrogen.
Section 45V credits are available for hydrogen produced in the U.S. or a U.S. territory and sold or used within or outside the U.S.
Tanya Peacock
For more information, please contact Tanya Peacock, Managing Director, Hydrogen, at tpeacock@ecoengineers.us.
U.S. Treasury and IRS Release Guidance on Section 40B Sustainable Aviation Fuel (SAF) Credits
On December 15, 2023, the U.S. Treasury Department and the Internal Revenue Service (IRS) provided initial guidance regarding sustainable aviation fuel (SAF) tax credits under Section 40B of the Internal Revenue Code, enacted by the Inflation Reduction Act of 2022 (IRA). The following information contains highlights of this notice. Producers will find guidance in relation to SAF credits, lifecycle analysis, verification requirements, and an emissions-reduction safe harbor.
Specifically:
The Renewable Fuel Standard (RFS) methodology for calculating lifecycle emissions may be used to determine emission reductions for SAF credits and new Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) models to determine emission reductions for the credit to be released early in 2024.
SAF synthetic blending components must be Quality Assurance Program (QAP)-validated.
Synthetic blending components have been assigned an emission-reduction percentage of 50%-60%, depending on the D-Code it is produced under.
Full Summary
Section 13203 of Public Law 117-169, 136 Stat. 1818 (August 16, 2022), commonly referred to as the Inflation Reduction Act of 2022, added §§ 40b with amendments to §§ 38(b), 40A, 87, 4101(a), 6426, and 6427(e)(1), to establish credits for fuel mixtures containing Sustainable Aviation Fuel (SAF). The SAF credit is equal to 1) the number of gallons of SAF in a qualified mixture, multiplied by the sum of 2) $1.25 and 3) the “applicable supplementary amount.” The applicable supplementary amount is $0.01 for each percentage point the emissions reduction percentage of the SAF exceeds 50%. The maximum applicable supplementary amount is $0.50 per gallon.
Credit may be issued for SAF with emissions reductions of at least 50% as compared to petroleum-based jet fuel. Emissions reductions, as listed in the code, are defined by the most recent Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA), or similar methodology that satisfies § 211(o)(1)(H) of the Clean Air Act. Prior guidance of the rule has been released in Notice 2023-6 pertaining to credit and payment rules, as well as CORSIA-based safe harbors for emission-reduction percentage determination. The notice did not, however, provide guidance for calculating the emission-reduction percentage or the certification requirements. Notice 2024-6 sought to do so by allowing the methodology of the U.S. Renewable Fuel Standard (RFS) program to be employed for greenhouse gas (GHG) emissions calculations and providing guidance in relation to third-party validation.
Notice 2024-6 states the methodology employed by the RFS program for determining lifecycle GHG emissions is designed to satisfy § 211(o)(1)(H) of the Clean Air Act, and thus, is similar to and can be used for calculating the GHG emissions percentage reductions for the SAF credit. Existing GREET models have been determined insufficient to be used to calculate lifecycle GHG emissions for the purpose of this credit. The U.S. Department of Energy (DOE) is in the process of creating an updated GREET model which, subject to release and further guidance, is anticipated to satisfy the requirements of 40b(e)(2) and be used for the calculation of emission-reduction percentages for SAF sold and used after December 31, 2022, and before January 1, 2025. The release of the updated GREET model is expected in early 2024.
The U.S. Internal Revenue Service (IRS) will accept the emission-reduction percentage of SAF of a synthetic blending component that qualifies as a renewable fuel in the RFS program and is produced under ASTM International (ASTM) D7566. The synthetic blending component must be Quality Assurance Program (QAP)-validated. Producers of the SAF synthetic blending component must record the valid Q-RINs (Renewable Identification Numbers) on the Certificate for SAF Blending Component included in Appendix A of Notice 2024-6. This certificate supersedes the model certificate included in Appendix B of Notice 2023- 6. In addition to QAP validation, producers/importers must also show third-party certification demonstrating compliance with general requirements, supply chain traceability requirements, and information transmission requirements concerning the Life-Cycle Analysis (LCA).
Synthetic blending components produced under D-Codes 4 and 5 will be assigned an emissions-reduction percentage of 50%, and fuel produced under D-Codes 3 and 7 will be assigned a 60% emissions-reduction percentage. The IRS will accept emissions reduction percentages for facility-specific pathways for producers of jet fuel under D-Codes 3, 4, 5, and 7, so long as the fuel is QAP-verified. Specific LCA point estimates published by the U.S. Environmental Protection Agency (USEPA) beyond the 50%-60% safe harbor will not be accepted by the IRS.
The following crediting example was provided:
A blender used 100,000 gallons of a SAF synthetic blending component to produce a SAF-qualified mixture. The SAF synthetic blending component has generated cellulosic diesel (D-code 7) RINs under a pathway that qualifies under the RFS program, and these RINs were validated under a QAP. The final rule that added the pathway to the list of approved renewable fuel production pathways in the RFS regulations states that the jet fuel’s emissions reduction percentage compared to the baseline is 64%. However, for purposes of calculating the applicable supplementary amount, the emissions reduction percentage will be deemed to be 60% under the safe harbor described in section 3.01(2) of this notice, which corresponds to the emissions reduction threshold the fuel was required to meet to qualify as cellulosic diesel and thus generate D-code 7 RINs. The per-gallon amount of the SAF credit with respect to the SAF-qualified mixture described above is calculated by adding $1.25 and the applicable supplementary amount, if any, with respect to the SAF synthetic blending component used to produce the SAF-qualified mixture. Here, the SAF synthetic blending component qualifies for the applicable supplementary amount, because the emissions reduction percentage is deemed to be 60%. The applicable supplementary amount is calculated by subtracting 50 from the emissions reduction percentage (60), and then multiplying by the applicable rate ($0.01): (60 – 50) × $0.01 = $0.10 per gallon. The total amount of the SAF credit is calculated as follows: 100,000 gallons × ($1.25 + $0.10) = $135,000.00.
