On January 15, 2025, Department of Energy (DOE) released updated versions of the 45VH2-GREET lifecycle greenhouse gas (GHG) emissions model and accompanying instructional manual. The updates are crucial to the Inflation Reduction Act's (IRA) Clean Hydrogen Production Tax Credit, Section 45V. Hydrogen producers must demonstrate that their hydrogen meets specific lifecycle emissions thresholds to qualify for the 45V credit. You can find the updated model here and the updated instructions here.
This post focuses on the model's assumptions for biogas and coal mine methane (methane released during coal mining activities) used as feedstocks to produce hydrogen. Understanding those assumptions is vital for hydrogen producers aiming to qualify for the 45V credit. The assumptions will also be important for other IRA energy incentives and, potentially, other federal and state clean fuels programs that credit fuels based on lifecycle emissions. 45ZCF-GREET, a separate iteration of the GREET model DOE just released for the Clean Fuel Production Credit, Section 45Z, relies on similar assumptions for biogas feedstocks.
Modeling Lifecycle GHG Emissions under 45V
The amount of the 45V credit depends on lifecycle emissions as follows:
Carbon Intensity (kg CO2e per kg H2) | Carbon Intensity (kg CO2e per kg H2) |
---|---|
4-2.5 | $0.60 |
2.5-1.5 | $0.75 |
1.5-0.45 | $1.00 |
<0.45 | $3.00 |
*Amounts assume prevailing wage and apprenticeship requirements
are met
Section 45V identifies two methods for determining lifecycle emissions: (1) the most recent version of Argonne National Laboratory's GREET model or (2) a "successor model" approved by the Treasury Secretary. Recently released Treasury regulations identify 45VH2-GREET as the "successor model" that hydrogen producers must use to determine lifecycle emissions across a range of production pathways.
Importantly, 45VH2-GREET applies only to certain combinations of feedstocks and hydrogen production processes. Hydrogen producers seeking to use different feedstocks or processes not included in 45VH2-GREET must initiate a separate process to obtain an individualized Provisional Emissions Rate (PER). More information on that process is available here.
Past versions of 45VH2-GREET included only one biogas feedstock: landfill gas. The update adds biogas from anaerobic digestion of wastewater sludge and animal manure, as well as from coal mine methane. Importantly, since book-and-claim accounting is not allowed until at least 2027, per the 45V rules, the updated model assumes a direct 1-mile pipeline connection between the feedstock supplier and the hydrogen producer.
45VH2-GREET includes other fixed, "background" assumptions for biogas and coal mine methane feedstocks. Those assumptions address, among other things, the "alternative fates" of the feedstocks if they aren't used to produce hydrogen. The updated instructions give further details regarding how the alternative-fate assumptions apply beyond what the 45V rules included.
Landfill Gas
The model assumes landfill gas is flared if it isn't used to make hydrogen. This flaring counterfactual includes estimates of methane emissions associated with incomplete combustion of landfill gas during flaring and N2O emissions associated with flaring. The result is an avoided emissions assumption of 1.065 g CO2e/MMBtu for landfill gas. (Previous versions of the model included this same figure.) CO2 emissions from reforming landfill gas are treated as "anyways emissions," which would otherwise occur if landfill gas were flared. Those emissions are treated as zero in the model. Also included as background data for landfill gas are emissions associated with upgrading the gas to renewable natural gas (RNG) and leakage of RNG during pipeline transport.
RNG from Anaerobic Digestion of Wastewater Sludge
The model assumes the following counterfactual scenario for wastewater sludge biogas:
- Approximately 55 percent of gas from the digester is used to produce steam to heat the digester.
- Approximately 44 percent of the gas is flared.
- Approximately 1 percent of the gas is lost to leaks.
Those assumptions are meant to reflect practices at large wastewater treatment plants where biogas could be upgraded to RNG instead of flared. As with the landfill gas counterfactual, this counterfactual also includes (1) estimated methane emissions from incomplete combustion during flaring and (2) N2O emissions associated with flaring. It also includes (3) estimates for other non-CO2 emissions that result from combustion (such as CO) and (4) any emissions associated with the disposal of residue.
The avoided emissions value associated with (1), (2), and (3) in the list above is -31.2 gCO2e/MMBtu of wastewater sludge biogas. A specific emissions value for (4) is not given in the instruction manual.
Other background data include emissions associated with digestion to produce biogas, upgrading the biogas to RNG, and leakage of RNG during pipeline transport.
RNG from Animal Manure
45VH2-GREET can also model emissions from hydrogen produced by reforming RNG from animal manure biogas. The instruction manual refers to a separate DOE technical paper addressing the counterfactual emissions value referenced in the 45V rules of -51 gCO2e/MJ of animal manure biogas. According to Treasury and DOE, this value is derived from an analysis of "the national average of all animal waste management practices."
Using assumptions in DOE's technical paper, animal manure biogas is then assumed to be upgraded to RNG. The resulting carbon intensity (which includes avoided emissions and emissions associated with upgrading) is -33.011 gCO2e/MMBtu.
Background data for animal manure biogas include avoided emissions associated with the counterfactual scenario described above, emissions associated with delivering manure to the digester, emissions associated with the digestion of manure to produce biogas, emissions associated with upgrading the biogas to RNG, and leakage of RNG during pipeline transport.
Coal Mine Methane
Coal Mine Methane is the only fugitive methane feedstock identified in the 45V rules that is not treated as identical to fossil natural gas in terms of lifecycle emissions. The rules and instructions identify flaring as the alternative fate for coal mine methane. The counterfactual scenario for coal mine methane includes estimates of methane emissions from incomplete combustion during flaring, N2O emissions associated with flaring, and other non-CO2 emissions that result from combustion. Emissions associated with reforming coal mine methane are assumed to be zero, similar to the "anyways emissions" assumed for landfill gas.
Additional Insights
How lifecycle emissions are modeled for these feedstocks may apply across a range of creditable clean energy sources, not just clean hydrogen. Similar assumptions will apply for biogas used to produce clean fuels under Section 45Z, the IRA's Clean Fuel Production Credit. Other programs could be affected as well. Biogas-derived fuels are credited under the EPA's Renewable Fuel Standard (RFS) program and similar state programs. The RFS program relies on DOE and Argonne National Laboratory for lifecycle emissions modeling, particularly when assessing individual pathway petitions for renewable fuels. Clean heat standards that include RNG are being developed in states like Vermont. Those programs also rely on lifecycle emissions for crediting purposes. DOE's evolving approach to emissions modeling could have ripple effects beyond the IRA and is worth tracking, not just for hydrogen but for a range of other low-carbon technologies.
The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.