A fork in the road for renewable natural gas: Exploring policy developments

As we discussed in our review of the state of the RNG market in 2024, to date, renewable natural gas (RNG) has seen the largest uptake in the on-road transportation market. That growth has been driven by the potential revenue streams from credit generation for compliance markets. These credits are linked to two key programs. The first is the federal Renewable Fuel Standard (RFS). This program requires fuel consumed in the US transportation sector to contain a minimum volume of renewable fuel. And second, the California Low Carbon Fuel Standard (LCFS). This program was designed to decrease greenhouse gas (GHG) emissions, lower carbon intensity (CI) in the transportation sector, and encourage the use of lower CI fuels in the state of California. In addition, state-level clean fuels programs have already been implemented in Oregon and Washington modeled on California’s program. These programs provide other credit generation pathways for RNG projects.

By allowing for a potential, and in some cases significant, revenue stream in addition to outright fuel sales, these programs serve to shift the economics of RNG projects. Stacking the various credits from those compliance markets has generally tended to yield what could be viewed as an “all-in” price for the RNG producer. This price is often much higher than what a long-term voluntary market offtake contract would transact at. The voluntary market offtake price typically ranges closer to USD 20 or USD 25 per million British thermal unit (MMbtu). The calculated “stack” price from projects targeting the compliance markets and the price range for non-transportation voluntary markets are multiple times the current spot price for Henry Hub – the US benchmark for natural gas prices. Recently, the spot price for natural gas has been assessed below USD 2.00/MMbtu, with a March 13 settlement at USD 1.24/MMBtu, a price level not seen since the early 1990s.

That substantial cost difference between RNG and geologic natural gas can be a hurdle for potential RNG buyers outside of compliance markets. While that hurdle remains, it has not stalled the uptake altogether. A company’s own internal cost of carbon (and how that evolves over time) will ultimately drive the dynamics in the voluntary market. In addition, RNG projects, whether targeting the compliance or voluntary markets, may qualify for Inflation Reduction Act (IRA) tax credits.

The following is a brief summary of these programs and credits, as well as upcoming proposed changes that will impact RNG project economics.

The generation of compliance market credits has played a crucial role in the RNG market development to date. Changes to existing programs, and the potential adoption of clean fuels programs in more states are being closely monitored by current and potential market participants as they can have a considerable impact on existing and proposed projects and can influence market appetite in the RNG space. More states have also recently weighed the inclusion of a clean fuels standard including New York, Illinois, Michigan, Massachusetts, and Vermont. In mid-February, New Mexico became the fourth state to pass a clean fuels standard. New Jersey introduced a bill to establish a clean fuels program in late January.

Of particular importance for the RNG space have been the proposed amendments to the California LCFS. Whatever final form the LCFS 2024 rulemaking takes, it will have a potentially significant future impact on other states’ clean fuels programs, given that California has served as a model for those programs.

The treatment of avoided methane emissions in the LCFS will be central to RNG project economics, considering recent public debate around their inclusion. Any significant shift in how these emissions are accounted for would also be considered a potential bellwether for other programs. Avoided methane emissions refer to the capture of methane that would otherwise be released into the atmosphere. The term is typically used to describe the capture of methane from landfills, food waste and agricultural manure through an anerobic digestion process. Generally, the emissions reductions from these processes are based on what the emissions would have been without the controlled storage environment of the digester. In some cases, accounting for avoided methane can help projects gain a negative carbon intensity score and significantly boost credit (and thereby revenue) generation potential.

Oregon has also proposed changes to its Clean Fuels Program, although the January 30 rulemaking workshop suggested that those changes will not be as substantial as those proposed in California. The proposed Oregon rulemaking includes updates to the state’s Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) model to more closely align with California’s model for carbon intensity calculations and third-party verification for electricity reporting. Unlike the LCFS, it does not seek to update its carbon intensity targets, which were last updated in 2022.

At the federal level, while the RFS for compliance years 2023-2025 was just finalized in June 2023, the volumes for compliance year 2026 must be determined at least 14 months ahead of when those volumes will be needed. That suggests some insight into how RNG will be incorporated into the next set rule before the end of this year, however, in practice those deadlines have been extended, including most recently in 2023 ahead of the current set rule.

California’s LCFS program is the oldest such program in the US, having been established in 2009 and implemented in 2011. The LCFS was amended in 2011, re-adopted in 2015, amended in 2018, and is slated to be amended once more in 2024, although now on a less clear timeline given the delay to California Air Resources Board’s (CARB) public hearing on those proposed amendments. The current CI targets that were set in 2018, require a 20% reduction from a 2010 baseline for CI of transportation fuels by 2030, with the CI benchmark remaining constant thereafter. CARB, which administers the program, is responsible for determining which fuels can generate LCFS credits. The LCFS itself is fuel agnostic as long as the CI reduction benchmark is met.

At its outset, the LCFS program was designed so that in early years excess credit generation was anticipated to help market participants meet compliance targets that became more stringent over time. In effect the program was backloaded to allow time for low-carbon fuel development. While that was the original intent, the oversupply of credits versus deficits hit an all-time high in Q3 2023. Indeed, LCFS credit creation has exceeded the modeling and related projections undertaken for the current LCFS benchmarks established in 2018. CARB specifically pointed to renewable diesel, electricity and hydrogen used as vehicle fuels as major drivers of that credit growth. The increased volume of credits has served to lower credit value (see figure 1). LCFS credits are currently trading near USD 66/metric ton on a daily basis. However, they had previously reached a peak of USD 200/metric ton in early 2021, which was near the LCFS market cap of USD 200 (in 2016 dollars).

In late December 2023, CARB released its draft rule covering proposed LCFS revisions. These amendments were proposed in alignment with the increased ambition of CARB’s 2022 Scoping Plan, which acts as a climate roadmap for California. The goal of the plan is to achieve carbon neutrality in the state by 2045. Notably, the 2022 Scoping Plan specifically called out the need for accelerating LCFS CI targets prior to 2030 and additional CI decline after 2030. The final comment period for amendments proposed in December closed on February 20. However, it appears that additional potential changes are still on the table, as CARB indicated what it termed “refinements” to the proposed December amendments were possible. The notice accompanying the March 21 hearing’s delay to an unspecified future date specifically stated that this was to “enable additional discussion and re-evaluation of the carbon intensity benchmarks, including the proposed step-down and auto-acceleration mechanism, as well as more consideration of the proposed sustainability guardrails, among other topics.”

The final form the LCFS rulemaking will take remains uncertain. Nonetheless, we have summarized the high-level program changes, given they would result in a significantly steeper CI reduction compared to the targets in place today. Our focus is particularly on the amendments related to RNG to gauge the potential breadth of any impacts.

[1] The AAM would be triggered when the credit bank to average quarterly deficit ratio exceeds three and credit generation exceeds deficit generation based on the prior year’s reporting.

That change in CI reduction and the AAM, if adopted, would not likely materially shift RNG project economics in the near term, considering the recent proliferation in credit generation and the AAM’s timeline to implementation.

For the purposes of this analysis, outside those broad-based proposed changes to the LCFS impacting credit generation and value across all low-carbon fuel types discussed above, we consider the proposed changes specifically relevant to RNG, including biomethane and avoided emissions. These revisions were hotly contested and discussed in multiple presentations hosted by CARB’s environmental justice advisory council (EJAC) over the summer of 2023. Ultimately, the proposed amendments sought to phase out RNG in transportation by 2040, while striking a balance to avoid stranding assets as in CARB’s view RNG and its non-upgraded form, biogas, have a key role to play in hard-to-abate sectors that are not likely candidates for electrification.

The proposal stated that RNG projects breaking ground in 2030 or later would be eligible for the avoided methane and biomethane combustion credit pathways. However, the eligibility period for RNG for transportation usage will be available only through 2040, while that for renewable hydrogen production will be available through 2045. Depending on in-service date, the exclusion of the avoided methane pathway credit could have potentially expired before the end of a biodigester’s useful life, which is 15 to 20 years for well-maintained medium-scale assets.

The proposed amendments also included a deliverability demonstration requirement for projects breaking ground in 2030 or later, which entailed making sure that a project has a pipeline connection that delivers into California and that it flows toward California more than 50% of the year. This applies to each pipeline segment along which the RNG molecule flows. Compliance would begin January 1, 2041, for pathways including CNG vehicles and 2046 for biomethane used as an input to hydrogen. Given California only has limited points of natural gas entry into the state via long-haul pipelines and its near-total dependence on out-of-state produced natural gas, the final legs of a theoretical RNG molecule’s journey into the state are likely to meet that “flowing toward California” requirement. However, the requirement could still prove complicated for projects in remote regions with few (if any) interconnection options.

The updated LCFS proposal also specifically includes CARB’s view that biomethane – before it is upgraded to RNG – has a key role in “decarbonizing California’s energy use in the long term.” Specifically, it outlines why some support for biomethane/RNG must remain in the interim, even if ultimately that role is outside of the transportation sector:

Additionally, the 2022 Scoping Plan sees biomethane as a pathway for low carbon buildings and industry by either blending it directly into pipelines or using it as a feedstock for renewable hydrogen blended in pipeline.

Given that California serves as a model for other state’s established or potential clean fuels program standards, the treatment of biomethane/RNG as a bio-intermediate is a critical aspect that requires monitoring moving forward.

[2] RNG generally falls under the RFS cellulosic biofuel pathway. Under the RFS program, when certified cellulosic biofuels are produced, they are assigned a D3 RIN credit, which can then be traded. Some RNG projects may qualify for a D5 RIN if the feedstock is biogas from waste digesters.

The Set Rule also allows RNG to receive credits for use as a bio-intermediate for non-RNG-fuels, including renewable diesel and hydrogen. As such, it expands the role of biomethane outside the RNG pathway.

The updated RFS did not include eRINs (a RIN produced when biogas generates renewable electricity used to charge light-duty battery electric vehicles or plug-in hybrid electric vehicles). However, the inclusion of an eRIN benefitting biogas/RNG as a biogas-to-electricity pathway in the next RFS update cannot be ruled out given the lengthy discussion on its proposed inclusion leading up to the finalized 2023-2025 standard. The timing of the release of the proposed new set rule will also weigh on the potential for the reintroduction of the eRIN, given a potential change in administration after November 2024 to one less favorable to electric vehicles. While RVOs must be determined at least 14 months prior to the year they are required – meaning that 2026 volumes must be set in 2024 – these have been subject to delay.

The current Set Rule for 2023 no longer includes cellulosic waiver credits[3] (CWCs) as a compliance alternative instead of production. The absence of CWCs can ultimately act as a price support for D3 RINs prices. CWCs had previously allowed for some level of price certainty for compliance. The credit value was based on an annual formula calculated by the EPA, which was based on wholesale gasoline prices. In effect, the ability to purchase the CWCs also acted as a price ceiling for D3 RINs, given its formulaic price-setting mechanism. For years when there are no CWCs to backfill production, the absence can technically act as a support for D3 RIN prices. Market participants who previously met obligations through waivers will now be required to fulfill obligations through RIN purchases instead.

In its response to comments on the set rule, EPA has stated that it believes it retains the authority to waive those cellulosic volume mandates and reinstate the CWCs in the future. If buyers who were forced to come into the market for production in 2023 were then allowed to purchase a CWC to fulfill that obligation in later years, this could lead to the softening of D3 RINs prices once more.

[3] Per the EPA, “For any calendar year for which the projected volume of cellulosic biofuel production is less than the applicable volume of cellulosic biofuel set forth in Clean Air Act (CAA)…, EPA must reduce the required volume of cellulosic biofuel for that year to the projected volume, and must provide obligated parties the opportunity to purchase cellulosic waiver credits.”

Whether the owner of an RNG project plans to earn credits in compliance markets or sell into the voluntary market, the IRA can potentially measurably shift the economics of that project. The IRA both extended existing credits that previously supported growth in wind and solar to include biogas, and created new technology neutral credits that take hold starting at the onset of 2025.

The investment tax credit (ITC) under section 48 now extends to “qualified biogas property” for facilities that begin construction before the start of 2025. As such, projects looking to qualify for this credit are facing a fast-approaching deadline. They may still need to secure final permitting and equipment ahead of qualifying as beginning construction, either through the start of significant physical construction or through the 5% safe harbor. The safe harbor entails spending 5% of the total cost of the facility as a definition of construction start, though, in practice, incurring more costs than that threshold could provide cushion in the case of potential project cost overrun. The ITC could make a project eligible for a 6% to 50% tax credit, depending on whether it meets conditions for prevailing wage and apprenticeship, domestic content, or energy community.

For the 48 ITC, which may prove most relevant for RNG projects, the November 17, 2023 guidance suggested that upgrading equipment to render biogas into a pipeline-quality fuel would be excluded from receiving the credit. That interpretation appeared inconsistent with the specific language that includes “cleaning and conditioning” as part of the qualified property. Numerous comments were received to that effect during the public comment period for the issued guidance. On February 16, 2024 the Treasury Department corrected the definition of “qualified biogas property” in the section 48 guidance. It now includes “gas upgrading equipment necessary to concentrate the gas into the appropriate mixture for injection into a pipeline through removal of other gases such as carbon dioxide, nitrogen, or hydrogen” as part of energy property, provided that it is an “integral part of an energy property.” Given that upgrading equipment can represent a significant capital investment for a project, and the large role that injection into pipeline plays for the LCFS, the cost of these components would be critical in the full biogas to RNG supply chain. There remains a requirement that a taxpayer must own a “fractional interest” along the full “unit of energy property,” which for RNG is an extensive chain extending from the biodigester to cleaning and upgrading equipment. Further clarification on this fractional interest point is likely, as there have also been numerous public comments on this matter.

For facilities placed into service on or after January 1, 2025, the ITC will be replaced by a technology-neutral clean energy ITC (48E) applicable to zero-emissions facilities. The traditional production tax credit (PTC), Section 45Y, currently applies to biogas used to generate electricity and is worth up to USc 1.25 per kilowatt hour. It will be replaced by a new credit focused on clean energy for zero-emissions electricity production. However, guidance detailing the qualifications for those technology neutral credits is still outstanding, although it is expected to be released in Q2 2024. That guidance will be crucial to understanding how projects will be eligible for zero-emissions status. The qualification process will be based on life-cycle analysis, with an annually published list outlining emissions by technology type. It will also be crucial to understand what system of monitoring, reporting and verification will need to be in place to substantiate qualification.

Beginning in 2025, the 45Z clean fuels production credit could be claimed, although it is currently set to expire in 2027. The calculation for the clean fuels PTC is based on the emissions reduction factor for the fuel. That credit can be stacked with the ITC.

While compliance markets can account for a substantial revenue stream, the recent and proposed changes outlined above can often be seen as adding uncertainty and regulatory risk across the project life cycle, making long-term revenue more difficult to substantiate. That can make traditional financing, if necessary, harder to obtain.

In the case of the IRA, there are incentive structures in place to help support RNG development. The recent definitional change to include upgrading equipment is a positive step. Given that upgrading equipment is a substantial portion of project cost. However, the lack of guidance on technology-neutral ITCs and PTCs may give some project developers cause for pause or, where possible, spur projects to pass the safe harbor threshold by beginning construction before the close of 2024.