A new bill being considered in Washington State would delay, for at least a couple of years, implementation of proposed rules that constrain crediting of avoided-methane offsets in the state’s Clean Fuel Standard (CFS). These offsets expand the scope of greenhouse gas (GHG) accounting for renewable natural gas (RNG) pathways to include avoided emissions from agricultural waste management and organic waste diverted from landfills. While RNG from waste is a low-GHG resource suitable for producing alternative fuels, such offsets divert CFS support to the agricultural sector and away from transport, the largest source of GHG emissions in Washington State.

That means the constraints on the offsets, which were proposed by the Department of Ecology, are important safeguards. Any delay would endanger the effectiveness of the CFS. Let’s review why.

The ICCT has extensively highlighted issues with unrestricted avoided-methane offset crediting for RNG in clean fuels programs, and California indeed adopted some restrictions in its recent Low Carbon Fuel Standard (LCFS) rulemaking. Washington’s proposed CFS update follows suit and would introduce a 15-year limit on avoided methane crediting for each RNG project. It would also require that participants demonstrate that at least some RNG is physically flowing into Washington; this starts in 2032 for fuel used in vehicles and in 2037 for RNG used for production of other alternative fuels. But there’s also a provision in Senate Bill (SB) 5601 that would override these safeguards, at a minimum through 2026. Its language targets RNG used for producing sustainable aviation fuel (SAF). But the proposed rules are not SAF-specific. Therefore, the safeguards could be jeopardized if SB 5601 is adopted as currently written.

There are two primary reasons for the concern. First, for as long as avoided-methane offsets are in use, a fuels program is not technology neutral because it allows some pathways to benefit from offset accounting but not others. A recent ICCT paper highlighted this issue by demonstrating the excessive policy value of avoided-methane hydrogen pathways under the LCFS compared with a technologically advanced green hydrogen pathway with near-zero in-sector emissions. Under a $75-per-credit scenario, dairy-RNG hydrogen in California could receive $3.30 per kg in credits compared with only $1.40 for green hydrogen. Similar outcomes are expected when comparing RNG-based SAF production with more scalable advanced solutions like e-kerosene, which is already being pioneered in Washington State. If the provision in SB 5601 that overrides safeguards on avoided-methane offsets takes effect, CFS support for innovative transportation technologies like e-kerosene could instead be diverted to pathways that rely on avoided-methane offsets.

Second, avoided-methane offsets can endanger the stability of a fuels program by disrupting the balance between the supply and demand of credits. This happens because offsets can enable deeply negative carbon intensity values that lead to a decoupling of credit generation from the supply of fuel. In other words, credits would be generated not from displacing fossil fuel, but from crediting changes in manure management practices at farms across the country. As shown in the figure, credit generation from dairy digester/animal waste compressed natural gas in the LCFS rapidly outpaced fuel volumes. In the second quarter of 2024, dairy and swine RNG generated 20% of program credits while making up only 3% of the alternative fuel used in California. This oversupply has contributed to a growing credit bank and declining LCFS credit values.

With credit values in the Washington CFS already declining to $22.93 per MT in January 2025, an influx of methane-offset-supported, negative-carbon-intensity RNG pathways would drive the price down further. This could severely damage the CFS’s ability to support in-sector emission reductions. In particular, low credit prices could stymie any CFS support for zero-emission vehicles and charging infrastructure aligned with Washington’s ambitious Clean Vehicles Program. This support is especially critical now that federal support for zero-emission vehicle adoption and charging infrastructure deployment is in question.

Allowing avoided-methane offsets without restrictions is all risk and no reward. It has the perverse effect of providing greater incentives to pathways that have less impact on in-sector emissions. If any language in SB 5601 serves to prevent or delay the implementation of the proposed safeguards, this would be the likely, unfortunate outcome.

A recent report by the North American Council for Freight Efficiency (NACFE) highlighted the role of natural gas as a transport fuel and estimated that the greenhouse gas (GHG) emission savings from a natural gas engine are in the range of 13%–18% compared with diesel fuel. However, NACFE “focused most [its] discussion on the tank-to-wheels effects of the alternate fuels” in comparing a natural gas-powered truck with a diesel truck doing the same route. An analysis of the complete fuel-cycle GHG emissions (i.e., well-to-wheel) would cover emissions associated with all the steps of producing, transporting, and consuming the natural gas and diesel used for those trucks. As I’ll show here, the emission impacts of the upstream natural gas supply chain complicate the climate benefits of using natural gas for trucks.

The primary issue is methane leakage. Natural gas is mostly methane (85%–90% by volume) and its production involves multiple steps during which methane could be released into the atmosphere through leaks and venting. This happens all along the supply chain and these upstream emissions are noteworthy because methane is a potent GHG.

Upstream methane emissions can be substantial and they’re not easy to estimate. For example, using ground-based measurements validated by aircraft observations, researchers have estimated that methane emissions from the oil and natural gas (O&NG) industry are much higher than previously estimated by the U.S. Environmental Protection Agency (EPA). Methane emission estimates reported in EPA’s national GHG inventory are based on adding up the emissions from individual components of natural gas production equipment. Although this kind of bottom-up methodology provides detailed data from routine equipment behavior, it does not detect super-emitters, which can be unpredictable and can emit unusually large amounts of methane (one example is malfunctioning equipment). Alternate measurement approaches such as remote sensing of methane emissions via satellites or aerial surveys can help cover vast areas and detect these super-emitters, but such top-down emission estimates can also overestimate emissions. For instance, this technique might not be able to differentiate between O&NG sites and other sources of methane, such as landfills or dairy farms.

It’s also important to differentiate between emissions from combined O&NG production and emissions from producing just natural gas. For sites that produce both fuels, part of the methane emissions should be attributed to the oil produced alongside natural gas on an energy-weighted basis. The left column in Figure 1 illustrates the range of methane losses from O&NG production normalized by natural gas production using data from recent literature. These losses are calculated by dividing methane emissions by the amount of methane produced. The data from both bottom-up (e.g., EPA) and hybrid methodologies (i.e., a mix of bottom-up data and satellite or aerial surveys) were used for these estimates. The methane loss estimates in the right column in Figure 1 illustrate the emissions allocated solely to natural gas production, so they are allocation-adjusted loss rates. When the O&NG sector is considered, the methane loss rate ranges between 0.4% and 9.6%, with a mean of 3.4%. When losses are allocation adjusted, it ranges between 0.4% and 4.8%, with 1.8% as the mean.

Note: Methane emissions from O&NG production are from Alvarez et al. (2018), EPA (2024), and Sherwin et al. (2024). Methane emissions allocated to NG production are from Omara (2018) and Sherwin et al. (2024). 

To understand the climate impacts of upstream methane losses, let’s explore the fuel cycle GHG emissions of natural gas-powered heavy-duty trucks. Figure 2 illustrates the differences in well-to-wheel GHG emissions for 40-tonne trucks that run on compressed natural gas (CNG), normalized per mile, for each fuel option analyzed. We used the mean methane loss rate for natural gas production (1.8%) as well as the minimum (0.4%) and maximum (4.8%) loss rates from Figure 1 to provide the range of emissions estimates indicated by the error bar. The fuel economy of a heavy truck running on natural gas of 6.5 miles per diesel gallon equivalent was taken from the NACFE report. To compare our analysis with diesel-powered trucks, we used the U.S. national average for the carbon intensity of diesel fuel from the U.S. Renewable Fuel Standard, 91.9 g CO₂e/MJ. Non-CO₂ tailpipe emissions (methane and nitrous oxide) from GREET 2023 were included as equivalent amounts of CO₂ in the combustion emissions for diesel and natural gas-powered trucks. The system boundary for natural gas includes extraction, processing, transport, fuel refining and distribution, and methane leakage for all steps. As illustrated in Figure 2, with the mean methane emissions rate of 1.8%, our estimates are a 6% GHG emission savings from CNG trucks compared with diesel ones. However, the same estimate shows that if there is a methane leakage rate greater than 2.5%, that would make CNG trucks worse than diesel ones from a climate perspective.

Note: Fossil CNG results are estimated using GREET 2023 and assumptions therein for CNG production and combustion in dedicated CNG-fueled vehicles using a 100-year global warming potential for greenhouse gases. 

Thus, even with optimistic assumptions for upstream methane leakage, we estimate that CNG trucks only offer mild GHG reductions, if any, compared with petroleum diesel. This means that the estimated GHG savings for switching to natural gas trucks are marginal at best. However, there is also a long-term problem: Purchasing natural gas trucks may create technology lock-in. The CNG trucks purchased today and in the next several years could be on the road well into the 2030s, when zero-emission vehicles that provide much larger emission benefits could be more widely available. Battery electric trucks using grid-average electricity already generate deeper GHG savings than CNG trucks in many regions, and these GHG savings will grow over time as the grid decarbonizes. Adopting CNG could mean foregoing substantial GHG savings in the future from zero-emission vehicles.

Sustainable aviation fuels (SAFs) are essential for aviation decarbonization but make up less than 1% of United States jet fuel consumption. Coupled with federal tax incentives, U.S. states have adopted their own policies to incentivize SAF consumption. And while U.S. state policies can contribute to further SAF adoption, getting the details right can ensure that SAF policies achieve intended benefits.

This webinar will review existing and proposed statewide SAF policies with an emphasis on the risks and opportunities presented by different types of alternative fuels. ICCT experts will discuss their assessment of domestic supply potential for different SAFs, the risk of policy-driven shuffling of fuels between states and sectors, and recommendations for how state SAF policies can best contribute to long-term aviation decarbonization.

After the presentation, there will be a Q&A on the role of SAF and SAF policies in reducing U.S. transportation greenhouse gas emissions.

Prepare for the discussion by exploring our latest publication, SAF policy scorecard: Evaluating state-level sustainable aviation fuel policies in the United States, and reading the fact sheet here.