Why RNG Matters in Arizona

RNG projects support methane abatement, clean fuel production, and the recovery of valuable resources from organic waste streams. In Arizona, these benefits are particularly relevant where the waste sector intersects with another resource challenge, water scarcity. Anaerobic digestion (AD) systems that process animal manure and food waste can help conserve water by reusing treated liquid streams and recovering water throughout the process. In a state facing chronic water scarcity, these water conservation benefits strengthen the case for expanding RNG development.

In addition to the environmental benefits, greater RNG production can help stimulate Arizona’s economy. It provides new revenue streams for farmers, landfill operators, and wastewater treatment plant owners, while also creating local jobs in construction and maintenance.

Energy Vision and AzCaNE found that landfill gas and animal manure represent the most commercially available opportunities for Arizona, further detailed below. (Reaching the state’s technical RNG potential would require a massive expansion of feedstocks for thermal gasification, a technology that shows promise but has not been widely deployed at commercial scale.)

Phoenix, Arizona. Image Source: Pexels

Landfills Offer the Largest Near-Term Methane Reduction Pathway

Four resources stand out as primary opportunities available now to expand RNG production and use in Arizona: landfill gas, animal manure, wastewater, and food waste.

In its 2025 Renewable Natural Gas Supply Assessment, the American Gas Foundation (AGF) and ICF identify landfill gas as Arizona’s largest single feedstock in both the Low and High development scenarios. Landfill gas is therefore one of the state’s most important opportunities for near-term methane reduction and renewable energy production. Despite this potential, Arizona currently has only one operational landfill gas-to-energy facility.

For future development, EPA’s Landfill Methane Outreach Program (LMOP) identifies 18 out of the state’s 40 landfills to be candidates for landfill gas adoption, including four that appear to be strong near-term prospects.

Even where conversion to RNG is not feasible, collecting and flaring landfill gas still provides meaningful methane reductions compared to uncontrolled release into the atmosphere. Improving landfill gas collection remains one of the fastest and cost-effective ways to reduce methane emissions. In Energy Vision’s July 2025 report Leading with Landfills, we identified three near-term measures to cut landfill methane:

1. Deploying real-time monitoring and automated tuning to improve existing gas-collection systems.

2. Starting collection earlier in active areas by extending systems within about one year of waste placement.

3. Building gas-collection systems at high-emitting landfills that currently lack them, prioritizing sites with gas flows of at least 700 standard cubic feet per minute (scfm) and treating 250-700 scfm as a stretch tier.

Adoption of these measures at all feasible Arizona landfills could both cut fugitive methane emissions and make the economics of RNG production more appealing.

Dairy Manure Represents Another Major Opportunity for RNG Development

Although you may not think of Arizona for its dairy farming, it ranks 14th nationally in milk production and is home to 122 dairy farms, including 29 large-scale dairies with more than 2,500 cows.

Today, the state has two dairies that generate electricity from biogas and six sites with RNG facilities connected via pipeline. One of those facilities is permitted to co-digest food waste and FOG (fats, oils, and greases) alongside dairy manure. When properly managed, co-digestion presents a unique opportunity to increase methane yield, improve process stability, and strengthen project economics.

EPA’s AgSTAR Market Opportunities report (2018) ranked Arizona’s dairy sector eighth among the ten states with the most energy generating potential from swine and dairy operations. It classified 56 of the state’s dairy operations as technically feasible candidates for AD. Collectively, these could generate 3.5 million MMBtu of RNG and reduce 59,000 metric tons of methane annually, according to AgSTAR (AGF has even greater estimated potentials in its High, Ambitious, and Technical scenarios). Energy Vision and AzCaNE calculated that development of RNG infrastructure, where feasible, at Arizona’s dairies would require an estimated $1.2-1.3 billion in upfront investment. Overall, dairy manure is one of Arizona’s most promising RNG resources.

Wastewater Treatment Plants and Food Waste Provide Secondary Opportunities for RNG

Arizona is home to several wastewater RNG projects, including one of the biggest in the country: the 91st Avenue Waste Water Treatment Plant (WWTP) in Phoenix serves 2.6 million residents and has the capacity to produce raw biogas at the rate of 3,250 scfm.

Energy Vision President Matt Tomich standing in front of the RNG plant owned and operated by Ameresco at the 91st Avenue Waste Water Treatment Plant in Phoenix, AZ during construction in 2018. Image Source: Energy Vision

Three plants in Arizona’s largest metropolitan areas are already producing RNG from wastewater (the 91st Avenue WWTP in Phoenix, the Tres Rios WWTP in Tucson, and the Mesa WWTP in Mesa), yet this feedstock remains a relatively small contributor to the state’s overall RNG potential. While Arizona has 133 publicly owned WWTPs, few are large enough to support economically viable RNG production. Co-digestion with food waste has the potential to raise biogas yields, but the limited number of medium and large size facilities constrains statewide volumes.

Food waste alone represents a relatively minor share of the state’s potential feedstocks, as Arizona lacks a food waste diversion mandate and large-scale organics recycling infrastructure. Before this technically promising resource could contribute much more to Arizona’s RNG portfolio, the policy environment would have to be overhauled and there would need to be large-scale investment in collection systems as well as processing infrastructure.

Policy Landscape and Recommendations

Realizing Arizona’s RNG potential will depend as much on policy and access to out-of-state markets as on feedstock availability. Unlike California, Oregon, Washington, New Mexico and now Hawaii, Arizona does not have a clean fuel standard or requirement for gas utilities to procure RNG. As a result, Arizona-produced RNG will continue to rely primarily on federal incentives such as the Renewable Fuel Standard (RFS) and the 45Z Clean Fuel Production Credit, as well as access to regional clean fuel markets.

To encourage in-state production, Energy Vision and AzCaNE recommend implementing policies that have proven to be effective in other states, adapted as needed to the Arizona context. These options include:

• Rewarding fuels based on verified lifecycle greenhouse gas reductions, with extra value given to those that deliver low or negative GHG emissions (e.g., certain waste-based RNG).

• Enabling “book-and-claim” accounting for pipeline-injected RNG, with meticulous safeguards against double counting.

• Supporting some utility procurement of RNG with clear cost caps and public reporting to protect ratepayers.

Ultimately, landfill gas and animal manure represent Arizona’s most commercially mature RNG opportunities under current policy and market conditions, while wastewater and food waste offer smaller, complementary pathways. Targeted state policies that expand market demand and support investment will help Arizona unlock more of its RNG potential over time.

Check out the full report here for much more on all these topics.

Last year, Energy Vision assessed how Washington could stimulate change in its dairy sector, forging ahead toward the all-important global goal – called for by international climate scientists – of slashing methane emissions 30% by 2030 and toward the State’s own goal of 45% total GHG reduction by 2030.

Following nine months of research, surveying, and analysis, we released our December 2025 report, “Market Challenges and Opportunities for Dairy Anaerobic Digestion (AD) in Washington State,” examining the obstacles and possible solutions.

At present, there are only 5 operational dairy ADs in Washington, down from 9 in 2019, and none have been built in the last 10 years. Energy Vision calculated that another 80 dairies in Washington have herd sizes theoretically large enough to support ADs, and constructing them all would cost about $1.2 billion. Doing so would cut the State’s manure methane emissions by a whopping 75%, meaning a reduction of at least 1.2 million metric tons of CO2 equivalent.

EV Findings – It Comes Down to Economics

Under current state policies and market conditions, dairy farmers and AD developers face very unclear economic returns for what would be major upfront investment, even at the smallest viable scale (of at least several million dollars to build a digester). The going prices for the electricity or renewable natural gas (RNG) that these digesters would produce are generally too low to cover the expenses, even factoring in existing policies, programs and incentives.

However, through strategic grants, loans, and other supportive mechanisms (see below), the State could catalyze significant private capital to reach the full $1.2 billion in capital expenditure rather quickly, and it would be a very cost-effective climate strategy, especially given the urgency to address methane emissions.

Energy Vision engaged dairy farmers, AD developers, regulators, and communities to pinpoint the challenges that have severely limited dairy AD adoption in the State. Based on those findings (including detailed surveys from close to 40 dairy farmers and 10 AD developers), as well as policies that have worked well elsewhere, the report provided 10 recommendations for Washington policymakers to facilitate cutting methane through a buildout of dairy ADs.

We found there’s lots of interest in dairy ADs – 73% of respondents have at some point considered using ADs on their dairy farm, and 71% were interested in learning more about AD adoption. Meanwhile, most developers noted that three incentives would make AD adoption more financeable:

• 80% of the respondents felt a high priority would be guaranteed fixed-price, long-term offtake agreements from the buyers of their biogas or RNG;

• 70% wanted capital cost subsidies, and

• 60% sought better access to low-interest financing or loan guarantees.

Top Three Reasons Farmers Rejected ADs After Consideration

Source: Energy Vision, Market Challenges and Opportunities for Dairy Anaerobic Digestion (AD) in Washington State.

Potential Solutions

Some of the report’s top recommendations are inspired by the success of key policies in California, where building dairy ADs has been among the most cost-effective methane reduction measures among all sectors in the state. California supports dairy digesters through grants that cover 10-25% of a project, which equates to an average cost of $9 per ton of CO2 equivalent abated; by contrast, the average cost of GHG abatement across California’s much larger 2023 Greenhouse Gas Reduction Fund spending overall was $101 per ton. Washington could follow suit by stepping up its grants, subsidizing AD maintenance, providing loans through its new Green Bank, and amending its Clean Fuel Standard program to stabilize prices at higher levels. The State could tap into a small slice of the ~$3 billion it has accrued in its Cap and Invest program to fund these incentives.

There is also enormous potential for Washington to incentivize the diversion of food waste from landfills to dairy ADs, in furtherance of the State’s goal of cutting 75% of the current organic materials being landfilled by 2030. If all 80 candidate dairies were to “co-digest” food waste with manure, they could theoretically accept almost 1.9 million tons of food waste per year – much more than the 1.2 million tons that Washington generates annually.

Food waste that would be prime for co-digestion with manure in ADs. (Photo Source: Taz, Wikimedia Commons)

Prioritizing new data center decarbonization via biogas-to-electricity and/or RNG could also be a promising path forward. This quickly growing industry is poised to change energy markets nationwide, including in Washington. Data centers and dairy ADs may very well be ideal partners, both seeking long-term fixed-price contracts for RNG or biogas-electricity. Data centers could easily soak up the entire dairy AD energy production potential in Washington and still need much more. Their willingness to pay relatively modest premiums for small blends of either RNG or biogas-electricity could provide the market certainty and higher pricing necessary to drive major buildout of Washington’s dairy AD sector by 2030, and the state can play a role in facilitating that.

Meanwhile, by incentivizing the dairies adopting best practices for digestate treatment, the state could address one of the main sources of public concern about ADs: water quality issues. Based on our research and outreach, the most promising path forward to gain community support is building dairy ADs and installing digestate treatment systems.

Lastly, there is a real need for open dialogue to share the facts – backed by credible third-party certifiers – about ADs, add-on digestate treatment systems, and impacts on local communities, including through Community Benefits Agreements. These are legal contracts that define the benefits a developer will provide to local governments or community groups in exchange for their support for a project; they’re tailored to the community’s needs, such as through annual payments, support for public works, etc.

Subsequent Progress in Washington – Greater Recognition and New Funding

Following the release of Energy Vision’s report, Washington has further emphasized the importance of building dairy ADs to help meet the State’s climate goals. Its Comprehensive Climate Action Plan, published in April 2026, acknowledges, “In Washington state, adoption of anaerobic digesters has been slow due to high upfront infrastructure costs, high operation and maintenance costs, smaller on-average dairy size, common manure management practices, and limited development of financing and integration into carbon markets.” It also notes that the State’s “existing [incentive] programs have not yet overcome the initial cost burden to support digesters in the long-term,” and that “Anaerobic digester grants should minimize private match, maximize rewards, and try to help fully fund awarded projects.”

The Action Plan includes two key measures to facilitate a buildout of ADs: “Install more anaerobic digesters” and “Incentivize the conversion of biogas from on-farm anaerobic digesters into clean energy.” The plan also emphasizes the importance of Community Benefits Agreements and greater collaboration with local communities “to improve transparency and reduce negative impacts.”

Positive progress is now underway, with Washington significantly increasing its funding for dairy ADs to encourage their buildout. In April 2026, the Department of Commerce awarded $13.8 million in the form of seven grants to build, repair, or maintain dairy digesters (and two manure lagoon cover-and-flare projects) for the 2025-2027 period.

Dairy is a critical part of Washington’s economy and a largely untapped opportunity to cut methane emissions through ADs. (Photo Source: Karla Salp, Washington Department of Agriculture, Creative Commons)

The State learned its lesson from its previous failed attempt(s) at dairy AD grants; it had authorized $20 million in the 2023-2025 period but the requirement for 50% matching funds from applicants “did not overcome the barriers faced in adding more anaerobic digesters on Washington farms.” Crucially, the latest batch of grants only required 15% matching funds. In an encouraging sign, the funded projects include the construction of new ADs. The awardees were selected in a competitive process based on expected reductions in GHG emissions and untreated effluent (underscoring the importance of digestate treatment).

Additionally, the State Legislature allocated another $10 million for a second round of AD grants, expected later this year, and anticipates another $40 million in dairy AD grants after 2027.

These are all positive developments, and they could be expanded to further align with Energy Vision’s findings. As our report noted, “$200-300 million in state subsidies (which could be spread out over a few years) that are strategically deployed to maximize impact could catalyze significant private capital to reach the full estimated ~$1.2 billion in capex for all feasible dairy ADs in Washington State rather quickly. This would cut manure methane emissions by at least 75%, meaning a reduction of at least 1.2 million metric tons of CO2e or at least 1.25% of Washington’s total greenhouse gas emissions, making it a very cost-effective climate measure. Guardrails would be needed to ensure that taxpayer funds aren’t misspent on non-viable projects. Dairies seeking such subsidies would have to apply with concrete plans proving their economic viability under a reasonable range of prices and conditions (i.e., with some margin to cope with variations in RNG prices.)”

See Energy Vision’s full report here for all of our recommendations.

Trucking is in the midst of what we call the Messy Middle, a transitional phase where multiple energy sources — including fossil and renewable diesel, natural gas, electricity, and hydrogen — coexist because no single solution currently will dominate all duty cycles. The Messy Middle is leading to what we at the North American Council for Freight Efficiency (NACFE) see as a zero-emission future for freight movement.

Last fall, NACFE completed Run on Less – Messy Middle with the goal to bring clarity to long-haul trucking. During the three weeks of the Run, NACFE tracked 14 Class 8 trucks delivering real freight on real routes:

• Four trucks operated on diesel/biodiesel/renewable diesel

• Three operated on compressed natural gas/renewable natural gas

• Five were battery electric trucks

• Two were powered by hydrogen fuel cells

All trucks were outfitted with telematics devices which collected a wealth of data about how the trucks were operating while delivering real freight in real-world operations.

During the Run, we learned that total cost of ownership (TCO) for any powertrain solution must be a bespoke calculation for each fleet. Highly variable factors — such as hyper-local electricity rates, fleet-specific infrastructure strategies, and negotiated vehicle prices — mean that a national average will rarely reflect a specific fleet’s actual balance sheet. We assessed TCO in 2025, 2028, and 2035 based on the following assumptions (see NACFE’s full TCO report for more details).

(Image Source: NACFE.)

NACFE’s analysis of the operational data showed that each powertrain had its strengths and weaknesses.

• Diesel remains the incumbent benchmark across all duty cycles, but its long-term cost advantage is eroding. While fuel costs per mile are projected to drop slightly by 2035, the overall TCO actually rises. This is driven by an expected increase in maintenance costs, insurance premiums, and the rising operational burden of maintaining legacy internal combustion engine vehicles under increasingly stringent emissions regulations. Renewable diesel and blended diesel based on biofuels also are emerging as viable, lower emission alternatives to fossil diesel.

  One thing to note: During the Run, two of the diesel-powered trucks operated at 11.3 miles per gallon (MPG), which is nearly double the national average. MPG certainly is one of the items that factors into TCO, especially in these days of skyrocketing diesel fuel prices.

A diesel-fueled truck operated by Mesilla Valley Transportation. (Photo source: NACFE.)

• Compressed natural gas (CNG) remains a stable middle ground, providing a lower TCO than diesel in the 2028 and 2035 timeframes. Because CNG avoids the steep insurance and maintenance escalators projected for diesel in 2035, it serves as a viable near-term hedge against diesel’s rising operational costs, without the intense infrastructure requirements of zero-emission alternatives. However, we project it will eventually be overtaken by the aggressive cost-reduction curve of BEVs by 2035. Renewable natural gas (RNG), based on recovering and repurposing waste methane, can be used seamlessly in CNG engines and is also growing in significance.

• Battery-electric vehicles (BEVs) show the most aggressive TCO improvement of any technology. According to our analysis, BEVs move from being one of the more expensive options in 2025 to becoming the definitive market leader in regional duty cycles by 2035. We project that BEVs will achieve the lowest net TCO in every single duty cycle by 2035, driven by plunging battery costs and superior energy efficiency.

• While hydrogen vehicle and fuel costs are projected to drop significantly over the next decade, hydrogen fuel cell electric vehicles (FCEVs) remain the most expensive powertrain across almost all duty cycles in NACFE’s 2035 modeling. The viability of FCEVs is almost entirely tethered to the delivery price of hydrogen produced by a variety of processes and a lack of scalable infrastructure.

A hydrogen fuel cell truck operated by Pilot. (Photo source: NACFE.)

One key takeaway from the Run was that duty-cycle matters when it comes to selecting a powertrain.

• For long-haul over-the-road, diesel maintained its crown in 2025 and we project it will do so again in 2028, although CNG/RNG offers a compelling near-term hedge for long-haul fleets looking to avoid diesel’s rising costs while using established fueling networks. Looking toward 2035, we forecast that the high fuel consumption of the long-haul cycle will allow BEVs’ cheaper operational costs to finally overcome diesel’s lower upfront CapEx.

• Regional linehaul sees the most dramatic shift. By 2035, BEVs go from being the most expensive option today to the cheapest overall, according to our analysis. The strongest financial case for BEVs in this segment is the combination of high mileage and minimal public charging. As longer-range BEVs enter the market, more linehaul lanes can be completed using only depot-sourced energy, maximizing infrastructure savings while still amortizing the CapEx over high annual miles.

A battery electric truck operated by Nevoya. (Photo source: NACFE.)

• Regional return to base and drayage rack up enough daily miles to generate significant fuel and maintenance savings, but their predictable, return-to-base nature avoids the public charging infrastructure hurdles that keep diesel leading in long-haul over-the-road at least through 2028. By 2035, we forecast that BEVs won’t just achieve parity; they will decisively beat diesel in regional return to base and drayage. Because we project the upfront purchase price of a BEV to drop below diesel by this timeframe, these operational savings will go directly to the bottom line.

• In the low mileage of urban pick-up and delivery, keeping upfront capital costs low is paramount. This allows diesel to remain the undisputed financial leader in the near term, with CNG/RNG serving as a close alternative for fleets looking to avoid diesel’s upcoming forecasted maintenance spikes. Meanwhile, both BEVs and FCEVs are severely penalized in 2025 by this low utilization, often costing more than $4 per mile.

The data analysis revealed some overall themes. The most striking universal trend is that the TCO for diesel goes up over time. While legacy technologies typically see cost reductions, NACFE’s modeling shows the net TCO for diesel rising steadily from 2025 to 2035, which will gradually erode diesel’s incumbent advantage.

CNG/RNG consistently presents itself as a stable middle ground in the near-term timeframes because it avoids the steep maintenance and insurance escalators projected for legacy diesel, and therefore frequently comes in lower than diesel’s TCO in the immediate future. However, as we expect CNG/RNG vehicle and operational costs to remain relatively flat over the next decade, that option will eventually be overtaken by what we anticipate to be an aggressive cost-reduction curve of BEVs by 2035 in most duty cycles. And it is important to remember that CNG/RNG still produces tailpipe emissions, meaning it will not shield fleets from strict zero-emission mandates. That said, RNG can have net negative greenhouse gas emissions on a lifecycle basis, which makes it an especially attractive option within certain clean fuel markets such as California’s Low Carbon Fuel Standard.

A Wegmans truck running on renewable natural gas (RNG). (Photo source: NACFE.)

Across the board in our analysis, BEVs show the steepest improvement trajectory. While BEVs are consistently the most expensive or second-most expensive option in 2025, we forecast that BEVs will achieve the lowest TCO of any powertrain in every single duty cycle by 2035. This drop is driven primarily by shrinking upfront vehicle costs as battery and production costs continue to decline, as well as relatively stable, low electricity and maintenance costs. In some duty cycles, we anticipate that parity will be achieved well before 2035. Incentives and grants will also accelerate the parity timeframe for fleets who take advantage of them, although to be conservative the NACFE report does not include them in the TCO calculations.

Hydrogen fuel cell vehicles are consistently the most expensive powertrain in 2025 and 2028 across all duty cycles, heavily burdened by massive vehicle costs and expensive fuel. While we expect their costs to plummet by 2035, they will still struggle to match the per-mile economics of BEVs or legacy diesel in almost every application.

In order to determine which powertrain option makes sense for their operations, fleet managers must complete their own TCO analysis that is tailored to their fleet-specific routes and costs, keeping in mind that they must look beyond the purchase price of the vehicle but rather at the whole system including fueling/charging, maintenance, and more.

Mike Roeth has worked in the commercial vehicle industry for over 40 years, is the Executive Director of the North American Council for Freight Efficiency (NACFE) and is the trucking lead for RMI. Mike’s specialty is brokering green truck collaborative technologies into the real world at scale. Mike is a Department of Energy Merit Reviewer and past Chairman of the Board for the Truck Manufacturers Association.

The research, analysis and perspectives presented in this guest essay are based solely on the work of the North American Council for Freight Efficiency (NACFE).

In April, Energy Vision released its latest report, The Future of Shipping: Cleaner Fuel Options for the Maritime Sector. Shipping is the backbone of the global economy, with over 100,000 commercial vessels moving 90% of all internationally traded goods. Almost all ships run on fossil fuels, and if the maritime sector were a country, it would rank among the top seven global greenhouse gas (GHG) emitters. But there’s a major, emerging opportunity here to adopt much cleaner fuels, and momentum is growing.

Maritime is one of the hardest sectors to decarbonize, as ships often travel long travel distances, have limited onboard fuel storage and refueling opportunities, and need energy-dense fuels. So almost all ships run on heavy fuel oil (HFO), marine diesel oil (MDO), and marine gas oil (MGO), which are relatively cheap but have high GHG emissions.

This is increasingly urgent to address since the International Maritime Organization (IMO) forecasts that maritime trade could increase 40-115% by 2050 compared to 2020. Furthermore, most of the raw materials and finished goods necessary for the global clean energy transition – from rare earth minerals to wind turbines – will ultimately be transported by ship. Yet the maritime capacity that is necessary to carry out the global clean energy transition has often been overlooked or underestimated; it will have to grow substantially, right as pressure accelerates to decarbonize shipping.

A suite of low-carbon alternatives are now gaining real traction for long-distance shipping, although high costs and limited availability remain major hurdles. These options include:

• Renewable diesel (RD) and biodiesel. These “first generation” drop-in biofuels are already compatible with existing engine infrastructure and can be deployed today.

• Bio-liquefied natural gas (bioLNG or liquefied biomethane, LBM) and biomethanol. These “second generation” fuels require new engines (primarily dual-fuel with diesel) and are increasingly being deployed.

• Green hydrogen, green ammonia, and e-fuels. These “next generation” fuels are made with renewable electricity and captured CO2. Apart from e-diesel, they not only require their own dedicated engines or dual-fuel engines with diesel, but they also face many challenges with cost and scalability.

Regulatory pressure is rising from the European Union and, to a less certain degree, the IMO, to address the slow pace of alternative shipping fuel adoption. Out of about 106,000 commercial ships worldwide, just over 1,300 vessels currently run on alternative fuels such as LNG or methanol. But those totals are rising each year, as are the available volumes of low carbon, bio-based versions of those fuels, such as bioLNG and biomethanol.

Every non-petroleum fuel option involves tradeoffs relative to cost, emissions performance, infrastructure requirements, and scalability.

Low-carbon biofuels, particularly first and second generation options like renewable diesel, biomethanol, and bioLNG, offer the most feasible near-term pathways for significant emissions reductions. While they too face challenges and tradeoffs, they are available, deployable now, and already proven at scale on some of the most demanding trade routes in the world. Next generation fuels like green ammonia are still years and billions of dollars away from being ready at the necessary scale, but they are expected to grow in importance through the 2030s and beyond as policy support, infrastructure, and markets mature.

Notably, the report finds that fuels derived from food waste and livestock manure – including bioLNG, biomethanol, and green ammonia – provide the deepest lifecycle emissions reductions (see chart below), though at higher costs today than fuels derived from other organic feedstocks.

“Well-to-Wake” Lifecycle Greenhouse Gas Emissions (Grams of Carbon Dioxide Equivalent per Megajoule, or gCO2e/MJ) in GREET 2025

Source: Energy Vision chart using data from GREET 2025.

See the full report for more, including the Appendix for in-depth profiles of each fuel.

The Future of Shipping features case studies of encouraging progress in the private sector. Many leading global consumer product companies, including Amazon, Patagonia, and Nestlé, as well as major shippers like Maersk, Hapag-Lloyd, Fortescue, United European Car Carriers, and others are stepping forward, embarking on their own clean fuel programs. Challenges and tradeoffs are prevalent, but so are emerging solutions, including ways to cut problematic “methane slip” from LNG engines.

Auto Energy, one of United European Car Carriers (UECC)’s first dual-fuel LNG “pure car and truck carriers.” It debuted in 2016 featuring a high-pressure, two-stroke main engine, the category of LNG engine that has the lowest rates of methane slip (see the report’s section on Methane Slip from LNG Engines for more). This ship and UECC’s other four multi-fuel LNG car carriers use bioLNG, as will four additional carriers due for delivery in 2028. (Photo credit: Tvabutzku1234/Wikimedia Commons, Creative Commons 1.0)

The financial challenge to alternative fuel adoption may be less daunting than it appears, especially when large, high-profile companies choose to take the lead, such as through the Zero Emission Maritime Buyers Alliance (ZEMBA). And shipowners don’t necessarily have to be on the hook for covering the extra costs. A few additional cents per end consumer product can translate into thousands of tons of avoided emissions.

For example, Energy Vision calculated that the costs of one of the more expensive cleaner fuel options for a trans-Pacific cargo shipment could easily be covered by 12 cents per pair of sneakers (given that a typical container can carry ~2,500 shoeboxes) or less than a quarter of a cent per smartphone (since a typical container can carry hold ~100,000 boxed smartphones).

The EU currently has the most stringent maritime decarbonization regulations in the world, with penalties tightening over time for GHG emissions. The interrelated FuelEU Maritime program and the EU Emissions Trading System are already driving real action in the sector, with orders for alternative-fueled ships rising each year.

Even outside of the EU, some form of binding maritime emissions requirements are likely to come in the future. This may come next in other regional/national jurisdictions and eventually at the global level through the IMO. To its credit, the “IMO 2020” sulfur cap has been the single largest driver of alternative fuel adoption so far, especially for LNG and biofuels, which contain very low or zero sulfur. The IMO provisionally approved a much more ambitious Net-Zero Framework last spring which would have gone into effect in March 2027, with the first GHG fuel intensity reductions required by 2028. In October 2025, though, under intense pressure from the Trump Administration and Saudi Arabia, the IMO Marine Environment Protection Committee voted to delay making a decision on it for 12 months.

The IMO headquarters in London, England. (Photo source: imo.un/ Wikimedia Commons, Creative Commons 2.0)

Nevertheless, fleet owners are now facing a fundamental calculation: bear the escalating costs of non-compliance – and inherent price volatility associated with petroleum-derived fuels – each year or invest now in vessels that will have much lower emissions over their 30-year operational lifespans.

Even in the US, despite the Trump administration eliminating key climate offices and clean energy policies, there may yet be hope for at least biofuel adoption in shipping. Bipartisan bills have been introduced in both chambers of Congress to allow biofuels used in oceangoing vessels to earn credits under the Renewable Fuel Standard, as they already do for on-road transportation and aviation. If enacted, this would almost certainly accelerate US production and usage of bioLNG in particular, as well as RD and biodiesel.

And regardless of how US maritime fuel policy develops, the European market remains a major draw/driver. International shipping associations and US clean maritime fuel producers are advocating for the EU to allow imported alternative maritime fuels to qualify under its strict regulatory system, which would likewise boost production.

While the challenges to decarbonizing the maritime sector are widespread, momentum is growing. As Energy Vision’s report makes clear, there is no silver bullet solution; every non-fossil maritime fuel option has its own particular tradeoffs. Ultimately, accelerating maritime decarbonization will require a portfolio approach grounded in first and second generation biofuels alongside continued investment and innovation in next generation alternatives. With the right combination of policy support, private sector leadership, and innovative financing, a cleaner maritime sector is both technically achievable and economically viable.

Check out the full report here.

Dr. Ilissa Ocko, Sr. Climate Scientist at Spark Climate Solutions, visiting the marsh in Angera, Italy where methane was first discovered 250 years ago, along with scientists measuring methane emissions. (Photo source: Ilissa Ocko.)

I was part of one of the most diverse convenings of methane experts to date, Methane 250. While Volta once stood in this very place asking, “What is this gas?”, our group of scientists, policymakers, and innovators gathered nearby to ask a related, but very different, question: how do we accelerate global efforts to reduce emissions of it?

The Evolving Role of Methane in Our Lives

The journey from initial curiosity to urgent action reflects a story of scientific discovery increasingly intertwined with implications for life on Earth.

When methane was first identified bubbling out of marshes in the 18th century, it was known simply as “inflammable air.” By the 19th century, it had become a utility, used as a core component of town gas to light the streets of cities like London and Baltimore, later taking its name ‘methane’ from its chemical structure. Today, we know it more commonly as the primary component of natural gas, embedded in energy systems around the world.

Not long after, scientists began to uncover another defining feature: methane traps heat. Alongside carbon dioxide, it plays a natural and essential role in keeping our planet warm enough to sustain life. Without these gases, Earth would be frozen and characterized by wild temperature swings.

But about 50 years ago, the narrative shifted: from helpful to harmful. Scientists discovered that methane concentrations were rising rapidly, largely driven by human activities. And methane wasn’t just trapping heat; it was also contributing to the formation of ground-level ozone, a toxic air pollutant that harms human health and crops while also warming the planet as a greenhouse gas.

By around 25 years ago, methane’s role as the second-largest contributor to climate change after carbon dioxide was firmly established. At the same time, a critical insight emerged: because methane is short-lived in the atmosphere, cutting its emissions could slow warming within decades.

Then, about five years ago, the conversation shifted again—this time from understanding to action. Methane moved to the forefront of the global climate agenda, marked by efforts like the Global Methane Pledge (established in 2021), through which 159 countries have now committed to reducing emissions. Since then, momentum has grown: national action plans, new policies at multiple levels of government, and a wave of public-private partnerships targeting emissions from energy, agriculture, and waste.

Today, methane is known as the #1 fastest lever to slow warming (often referred to as an “emergency brake” for climate change), both because of the scale and speed of its mitigation impact, and also the availability of mitigation measures, many that are affordable.

And yet, progress remains uneven. Implementation is still too slow, too fragmented—and targeted methane action receives less than 5% of global climate finance.

Which is why, recently, a diverse group of leaders across science, policy, and innovation came together with a shared goal: to figure out how to accelerate methane action at the scale and speed this moment demands. One outcome of that effort was the Angera Declaration from the Methane 250 conference: a ten-point plan outlining the science and policy priorities needed to turn that promise of hope into reality.

Why Methane Action Matters

Reducing methane emissions is not a substitute for the deep, sustained cuts in carbon dioxide needed to stabilize the climate system, given the scale of its emissions and that they can persist in the atmosphere for centuries. But methane action is an essential complement, because it is possibly the only major lever available today that can rapidly curb the rate of warming at a time when climate impacts are already intensifying and the risk of crossing tipping points is increasing. This is why methane is a core component of climate action, and why there is hope behind the hype.

Here are five reasons why methane deserves the spotlight:

1. Methane mitigation is the fastest lever we have to slow warming now

Lowering near-term warming is important for many reasons, including that it reduces risks from intensifying extreme events (like heatwaves, droughts, floods, and wildfires) and crossing potentially catastrophic climate tipping points.

Methane mitigation is uniquely powerful at limiting warming because of both the scale and speed of its impact. Methane is responsible for around 30% of current warming, yet it has a relatively short atmospheric lifetime of about a decade. That combination matters: large impact on current warming, but it can be decreased quickly if emissions are reduced.

This stands in sharp contrast to carbon dioxide, which can persist for centuries, meaning that its impact today is from an accumulation of emissions over time and therefore cannot be reduced as quickly from a change in emissions. However, CO2 reductions are essential to limiting the overall extent of warming, and achieving net zero emissions is essential for stabilizing the climate system.

2. We already have solutions, many affordable, that can avoid considerable warming by midcentury and beyond

Unlike many areas of climate mitigation, methane is not primarily constrained by technology gaps. We already have proven, scalable strategies that could reduce global methane emissions by roughly half.

In the energy sector, for example, leak detection and repair, improved equipment standards, and capture of vented gas can deliver large reductions, often at low or even negative cost because the captured methane is a usable product. In agriculture and waste, a growing set of practices and technologies are also showing promising reduction potential.

If these solutions were rapidly scaled, they could avoid around 0.25°C of warming by midcentury (see figure below), which is a substantial amount in a world that is already approaching 1.5°C of warming above preindustrial levels and is aiming, under the Paris Agreement, to keep warming well below 2°C.

Further, over 80% of available measures are considered low annual cost, with around half at near-zero cost. In many cases, methane reductions are negative-cost: they pay for themselves or generate net savings, particularly in the oil and gas sector where captured methane can be sold as a product rather than lost to the atmosphere. This fundamentally changes the investment case, turning mitigation from a cost center into a value-generating opportunity. Methane captured from manure and landfills can also be used for heat, electricity generation, and/or to produce renewable natural gas (RNG) that can displace fossil fuels. Finally, research has shown that achieving the Global Methane Pledge (30% reduction globally in methane levels by 2030 relative to 2020) could cut climate damages in 2050 by over $1 trillion annually at a cost of just one-sixth of the losses avoided.

3. Near-term action shapes long-term climate outcomes

Methane’s short lifetime doesn’t make it a short-lived problem. On the contrary, ongoing emissions continue to add significant warming for as long as they persist, leading to the exceedance of our temperature targets and increasing major risks like crossing tipping point thresholds.

While a one-time reduction wouldn’t meaningfully lower long-term temperatures, sustained mitigation is essential to limiting peak and long-term warming. In that sense, methane is a lever not just for near-term temperature benefits, but important for achieving longer-term climate goals. The earlier we act, the more benefits we will have. And, early methane action can also help lower risks of longer-term climate consequences that worsen with more overall warming, like the loss of Arctic sea ice.

4. It addresses other growing environmental challenges and underappreciated risks in a warming world

Methane emissions are a major contributor to the formation of tropospheric ozone, which is both a greenhouse gas and a harmful air pollutant that degrades human health and damages crops and forests. Each year, tropospheric ozone is currently estimated to cause around 500,000 premature deaths, up to 26% loss in global crop yields across the globe, and 11% loss in forest productivity. Methane mitigation can therefore help save lives and strengthen food security by improving air quality. In fact, scaling up existing measures could save 180,000 lives and 19 million tonnes of crop losses annually by 2030.

Another challenge is that methane and other emissions can also change as natural systems respond to a warming world, many of them increasing. For example, there is a real risk of increased methane emissions from sources like wetlands and permafrost. This introduces important nonlinear risks but also opportunities. Methane mitigation will keep temperatures lower than they otherwise would be, thereby reducing emissions from natural systems. Addressing methane now reduces exposure to these risks and helps limit the potential for self-reinforcing warming dynamics.

5. It unlocks a broader ecosystem of innovation and finance

Methane mitigation spans a diverse set of sectors (energy, agriculture, and waste) each with distinct technologies, actors, and investment opportunities. This diversity creates a unique space not only for innovation, but also for climate finance grounded in strong economic returns.

At the same time, methane reduction is driving rapid growth in monitoring, measurement, and verification technologies, enabling more precise detection and accountability. These capabilities are opening the door for investors interested in scalable, near-term climate impact, while also creating space for researchers and entrepreneurs to develop new solutions to address harder-to-abate sectors like livestock and rice, as well as climate feedback-related sources like wetlands.

Pulling the Methane Lever ASAP

The importance of methane action is grounded in science, enabled by largely affordable solutions, and increasingly backed by real-world action, as I also saw firsthand in Italy, where farmers are deploying methane-reducing cattle feed and manure strategies.

Photos from farms in Italy in April 2026 that are using feed and manure treatments to reduce emissions of methane and other compounds from livestock. (Photo source: Ilissa Ocko.)

But key barriers still limit methane’s full potential, such as weak or absent policies, inconsistent measurement and reporting, financing gaps, and limited capacity in some regions to deploy solutions; innovations could also expand our solution set. And this is why I recently joined experts across science, policy, and innovation to begin to chart a path forward towards overcoming barriers and accelerating action, with more than 250 scientists signing the Angera Declaration outlining at a high-level what is needed next.

Because methane is worth the attention and mitigation is worth the effort. Every reduction delivers near-immediate benefits for climate and air quality, and when sustained alongside essential CO2 reductions set us on a path to long-term climate safety. I am hopeful that the growing hype around methane action will translate into tremendous progress in driving down emissions.

Dr. Ilissa Ocko is a senior climate scientist focused on super pollutants at Spark Climate Solutions. In the Biden Administration, she served as a Senior Advisor to the U.S. Special Presidential Envoy for Climate at the State Department. Before that, she held the Barbra Streisand Chair of Environmental Studies at the Environmental Defense Fund.

An airplane taxiing on a runway. (Photo Credit: Dovydas Pranka/Pexels, CC Public Domain)

At any given time, there are somewhere between 12,000 and 14,000 airplanes in the sky worldwide on an average day.

Of all forms of transportation, aviation emits the most CO2 per mile, although the sector’s total emissions are less than on-road transportation and maritime shipping. Still, aviation is a hard-to-decarbonize sector (dependent on energy-dense liquid fuels) that accounts for around 2.5% of global CO2 emissions.

Momentum is growing to decarbonize aviation to the greatest extent possible, through a variety of means spanning technology, economics, and policy. The one solution that has received the most attention of late is sustainable aviation fuel (SAF).

What is Sustainable Aviation Fuel (SAF)?
SAF is a drop-in fuel certified to meet all performance and safety standards in existing jet engines while cutting greenhouse gas emissions 50-99% from the fossil baseline. Because SAF emits fewer pollutants than fossil jet fuel during combustion, it also improves air quality and reduces contrail formation (which is another contributor to global warming). The tradeoff (and biggest near-term obstacle) is that SAF costs 2-5 times as much as conventional jet fuel to produce, although economies of scale are expected as output ramps up.

There are multiple pathways to producing SAF, involving different feedstocks and technologies. At present, the four main approaches being pursued are: 1) hydro-processed esters and fatty acids (HEFA); 2) biomass gasification through the Fischer-Tropsch process (G-FT); 3) alcohol-to-jet (AtJ); and 4) power-to-liquids (PtL). The HEFA pathway (involving used cooking oil or oil-yielding plants) is the most common worldwide, while AtJ (often involving ethanol) and PtL (using captured CO2 and hydrogen) are emerging opportunities.

In 2021, United Airlines flew the first passenger flight with one engine using 100% SAF and the other using conventional jet fuel, demonstrating no difference in performance. (Photo Credit: @scottkirby/Instagram, CC 4.0)

One of the more promising avenues for commercial-scale SAF production appears to be through the use of renewable natural gas (RNG) as a building block “feedstock”. This post highlights the emerging but significant potential of the RNG-to-SAF pathway.

What is Renewable Natural Gas (RNG) and How Can It Be Used to Make SAF?
RNG is produced by capturing the methane from decomposing organic waste and upgrading it to pipeline quality specifications. It is virtually identical to fossil natural gas but has much lower lifecycle greenhouse gas (GHG) emissions and doesn’t require extractive drilling or fracking.

Indeed, when derived from manure or food waste, RNG is typically net-carbon-negative on a lifecycle basis, meaning more GHGs are captured during its production (as very potent methane) than are released when it’s combusted (as less potent CO2). About 70% of the US RNG supply is derived from landfill gas, which has higher lifecycle GHG emissions, but still typically less than half that of fossil natural gas.

To sum up the chemistry involved, RNG can be converted via the Fischer-Tropsch (FT) process into SAF and renewable diesel. FT is not without challenges but it is a well-established technology already in commercial operations globally, unlike some emerging SAF pathways (such as AtJ and PtL) using novel techniques and feedstocks. These emerging technologies are expected to play a larger role in the future but they are less proven at commercial scale.

What is the Nationwide RNG-to-SAF Potential?
According to the most ambitious scenario in ICF’s 2025 US RNG Assessment, by 2050 the US could produce nearly 2 billion MMBTU/year of RNG from the existing feasible “waste” feedstocks of livestock manure, food waste, wastewater, and landfill gas. That’s about 15 times as much as total US RNG production in 2024 (~135.5 million MMBTU), according to Energy Vision’s calculations (as detailed in a recent deeper dive Substack post). Historically in the US, most RNG is going to the on-road transportation sector (i.e. trucks and buses); in addition, a small but growing segment is going to some combination of utilities and corporate/industrial customers to partially decarbonize their gas supplies.

SAF will have to compete with these sectors as well as with other emerging pools of demand, perhaps most notably the maritime industry, where the market for bioLNG (liquefied RNG) is nascent but likely to expand significantly in the coming years. Despite competing end use applications for a growing but ultimately finite supply of RNG, we expect to see a larger portion of US RNG production going to new markets above and beyond the on-road transportation sector, including for SAF production.

To put the scale of the RNG-to-SAF opportunity in perspective, if all additional feasible US RNG production (1.85 billion MMBTU) were to be directed to SAF, that would result in production of as much as 8 billion gallons of SAF. That would be a sizable volume, surpassing the 3 billion gallon level that the US SAF Grand Challenge has targeted for 2030 (although almost certainly not in time, given the need to develop so many new RNG projects and SAF production facilities). However, even the maximum feasible SAF production from RNG would still fall far short of the 35 billion gallons consumed annually in the US today.

Realistically, only a portion of additional US RNG production will end up going to SAF, and the extent to which this pathway scales is heavily dependent on policy and markets. Nonetheless, an ambitious but achievable target would be for 10% of all additional feasible RNG production, or 185 million MMBTU to be directed to domestic SAF production. That would result in approximately 800 million gallons of SAF per year, which is considerably more than total US SAF production in 2025 (according to the EPA, approximately 240 million gallons of domestically produced SAF were registered for the Renewable Fuel Standard in 2025).

An airplane refueling at Miami International Airport. (Photo Source: Sunnya343, Wikimedia Commons CC BY-SA 4.0)

With federal support for climate and clean energy measures having now been tremendously scaled back, it’s largely up to the states and private sector to keep driving progress. This is particularly salient for the SAF industry and Washington State, which prides itself on being a climate leader and has a storied history of aviation (Boeing was founded there in 1916 and remains one of the state’s biggest private employers).

Zooming in on Washington State
Washington has quickly become the most SAF-friendly state in the country, due to a number of targeted policies. One is a substantial tax credit that requires SAF to be produced and used in-state. It starts at $1/gallon for production of SAF with a 50% GHG reduction compared to fossil jet fuel and rises proportionally to $2/gallon for production of SAF that achieves a 100% GHG reduction. In order to drive large-scale development of SAF, Washington’s incentive will only come into effect when there are commercial-scale projects with at least 20 million gallons of SAF production in the state. Unlike in some other states, Washington’s SAF tax credit does not have a cumulative monetary cap, further incentivizing large-scale projects there.

Washington also allows SAF pathways under the state’s Clean Fuels Program. This provides an additional revenue stream to SAF producers that is “stackable” with credits that they earn under the federal Renewable Fuel Standard. (See more about the proven effectiveness of Clean Fuel Standards in our earlier Substack post.)

Additionally, the state-funded Cascadia Sustainable Aviation Accelerator debuted in early January 2026, based in Snohomish County. The nonprofit brings together stakeholders representing the entire SAF value chain in an effort to accelerate production and consumption of SAF in the Pacific Northwest (PNW), anticipating major economic benefits for the region. It has set a stretch goal for 1 billion gallons of annual SAF production to be supported by PNW feedstocks by 2035. The Cascadia accelerator launched with $10 million in tax dollars approved by the Washington Legislature, plus another $10 million from an unidentified philanthropic donor.

A portion of Seattle-Tacoma International Airport, the largest airport in Washington State. Photo Credit: formulanone, Wikimedia Commons CC BY-SA 2.0

Washington’s SAF approach is a prime example of effective state-level climate action that could be replicated elsewhere or inspire similar initiatives. For example, Illinois has enacted a $1.50/gallon tax incentive for airlines using SAF with at least a 50% lifecycle GHG reduction; the SAF must be used in-state but it can be sourced from elsewhere, including through book and claim accounting (a widely used practice where the environmental attributes of the fuel are sold separately from the physical molecules, with meticulous tracking and verification).

Energy Vision attended a Decarbonizing Aviation forum in Seattle in late January hosted by the Clean Energy Transition Institute (CETI). Excitement was palpable about both the Cascadia accelerator and several SAF projects (using a range of pathways) in the works in Washington and the PNW more broadly. These include SkyNRG’s RNG-to-SAF project (see Case Study below) at the Port of Walla Walla; Twelve’s power-to-liquid SAF project in Moses Lake, WA; NXTClean Fuels’ HEFA-to-SAF production facility in Clatskanie, OR; and Montana Renewables’ HEFA-to-SAF production facility in Great Falls, MT.

Case Study: SkyNRG’s Project Wigeon

SkyNRG is developing a major RNG-to-SAF project in the Port of Walla Walla’s Wallula Gap Industrial Business Park in Washington State. Called Project Wigeon, it will use mostly landfill RNG and some manure-derived RNG to produce up to 50 million gallons per year of SAF.

In its project description document submitted to state regulators, SkyNRG states, “Unlike other feedstocks used for SAF today, such as waste oils and agricultural crops, RNG does not create competition for land used for food crops and it can be supplied using existing natural gas pipelines in the region.” The company notes it will purchase RNG for the project using book and claim accounting, although it strives to purchase as much locally produced RNG as possible, provided the commercial terms are reasonable.

The 165-acre site also has the potential for an on-site anaerobic digester to produce its own RNG to be used for SAF and RD production. SkyNRG states that local feedstocks for the digester “will likely include feedlot manure, agricultural wastes, and/or industrial wastes from the nearby Tyson Beef Processing facility and Packaging Corporation of America paper mill. As such, the anaerobic digester will not only benefit the Project but will also eliminate the adverse impacts of these largely unregulated waste streams.”

SkyNRG anticipates that construction on Project Wigeon will begin in 2028 and production will commence in 2031. The SAF produced there is expected to reduce lifecycle GHG emissions by approximately 85% or more compared to fossil jet fuel, according to the WA GREET model. SkyNRG expects the vast majority of the SAF produced at Project Wigeon to be delivered by rail to the few major airports in Washington State.

Challenges to Scaling Up RNG-to-SAF
The RNG-to-SAF pathway faces broader challenges applicable to SAF in general as well as its own particular constraints.

For all types of SAF, the main challenge is an intertwined one: high costs and limited availability. These are very expensive projects that take years to materialize, making reliable financing critical to line up early. There was a lot of emphasis at the CETI aviation forum on the need for long-term policy stability and risk-sharing among the various stakeholders involved in order to make these projects actually happen.

The Clean Energy Transition Institute (CETI) hosted a forum, Addressing Aviation’s Climate Impacts, in Seattle on January 29, 2026. (Photo Source: Energy Vision.)

Another insightful takeaway from the CETI forum was why actual SAF production in the US is far below nominal capacity. A Rocky Mountain Institute (RMI) review found that 40% of all announced and operational SAF facilities in the US by 2030 are at high risk of major delays or cancellations for a variety of reasons, including economics, logistics, and policy uncertainty. For example, the One Big Beautiful Bill Act’s reduction of the 45Z Clean Fuel Production tax credit for SAF from a maximum of $1.75/gallon to $1/gallon was a substantial blow to developers, even if the eligibility timeline was extended by two years (to 2029).

For the RNG-to-SAF pathway in particular, there is a broader feedstock challenge (as is the case for essentially all other biofuels) of how to access the “right mix” at acceptable costs. However, this is surmountable. Landfill RNG is the cheapest, and although it has the highest lifecycle GHG emissions of all RNG feedstocks, there are cost-effective opportunities to significantly cut these emissions (see our recent report Leading with Landfills). Plus, combining landfill RNG with smaller amounts of carbon-negative RNG from manure and/or food waste could result in net-zero SAF without sky-high prices.

Simultaneously, economies of scale could be achieved for RNG production, bringing costs down through fixed, long-term contracts. There will still be a major premium over fossil jet fuel for SAF produced from RNG, but that’s a common theme in the energy transition. With existing state and federal policy – on the books today – this cost premium could be offset to a significant degree. And over time, additional market mechanisms and further technological innovation are expected to lower the SAF premium. Last but certainly not least, companies and consumers are already committed to absorbing some portion of higher prices to fly green.

Meanwhile, floods are swallowing towns. Wildfires are choking entire regions in smoke. Droughts are decimating farms. Glaciers are collapsing into warming seas. They are lived realities. And they are accelerating.

The 2024 hurricane season was the most destructive in U.S. history, with an estimated $500 billion in damage to property, public health, and the broader economy. The first half of 2025 set records for the costliest extreme weather disasters ever recorded in this country, including the catastrophic Texas floods that claimed at least 135 lives, many of them children at summer camps. Across the West, intensifying wildfires are pumping particulate pollution into communities hundreds of miles away, worsening heart and lung disease.

We have seen this before. In 2012, Superstorm Sandy ravaged the Caribbean and the East Coast, killing more than 250 people and causing $68 billion in damage. More than a decade later, some communities are still rebuilding. The warning signs were unmistakable then. They are undeniable now.

Debating causal links between global warming and a given weather event is one thing. This administration’s blatant disregard for the data, the science, and the devasting economic, social and environmental impacts of climate change is something else.

The Trump EPA is dismantling climate safeguards, not because the science is unclear, but because fossil fuel interests prefer it that way. Key beneficiaries are oil and coal executives. The costs are borne by the public: in lost homes, lost livelihoods and lost lives.

But there is a path forward, and it doesn’t lead through Washington. It involves states, municipalities, and forward-thinking industry leaders stepping up.

Cutting methane emissions, one of the most potent greenhouse gases, is among the most immediate and effective climate strategies available. Scientists worldwide have made clear that reducing methane emissions by at least 30 percent by 2030 is essential to avoid triggering more severe, destabilizing climate impacts.

Now more than ever we must double down on proven, cost-effective and climate-smart strategies. By working with city, state and industry partners the progress and momentum we have seen can be sustained and even accelerated. At Energy Vision, our focus is unchanged, but the urgency has intensified to advance and implement practical solutions.

Among the practical solutions we’re working on, capturing methane from landfills, reducing emissions from dairy and agricultural operations, and transforming food waste into renewable energy all show great promise. These are not theoretical ideas. They are scalable, proven solutions that protect public health, strengthen local economies, and reduce climate risk.

We can’t and won’t wait for Washington. An informed and engaged public can get behind climate solutions, and we can take action at the state and local levels. Administrations come and go. The climate consequences of inaction do not.

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Trucks parked just inside New Mexico. (Photo source: maduarte, CC BY-NC-ND 2.0)

After New Mexico passed legislation in 2024 creating the Clean Transportation Fuel Program (CTFP), the final regulations (shaped by extensive public input) were approved in late January 2026. The CTFP will come into effect on April 1st, 2026.

By law, the CTFP must reduce the carbon intensity of transportation fuels used in the state at least 20% by 2030 and at least 30% by 2040, relative to a 2018 baseline. This technology-neutral program mandates stricter emissions reductions each year but lets the market achieve them most efficiently – rather than instating mandatory minimum or maximum production/sales of various fuel options. Producers of cleaner fuels whose carbon intensities are below the state-established threshold for that year earn credits (which correspond to tons of CO2 equivalent avoided). Meanwhile, producers of dirtier fuels whose carbon intensities are above the threshold must either buy credits to offset their emissions or reduce their carbon intensities (which is only possible to a limited degree for fossil fuels).

Traffic on I-40 near Santa Rosa, New Mexico. (Photo Source: Pom’ from France, European Union, CC BY-SA 2.0)

Clean Fuel Standard programs mainly incentivize zero-emission technologies (battery-electric and fuel cell vehicles) and low-carbon biofuels – primarily renewable natural gas (RNG) and renewable diesel (RD) – while disincentivizing fossil fuels. They are a proven strategy to expand the availability of these important low- and zero-carbon non-petroleum fuels and make fleet/fuel transitions more economically competitive. California’s Low Carbon Fuel Standard (LCFS) has been so successful that it has consistently met its annual transportation decarbonization goals several years in advance and has accordingly deepened the targets. Thanks to the LCFS, almost all diesel and natural gas used for transportation in California have been replaced with RD and RNG, respectively. The program also generates approximately $4 billion annually that is used to fund low-carbon investments and public transportation in the state.

The New Mexico program (CTFP) incorporates many key elements of California’s LCFS while also customizing it for its own context. Crucially, the CTFP includes:

• Avoided methane crediting. The Clean Transportation Fuels Program (CTFP) allows avoided methane emissions to be reflected in a fuel’s carbon intensity score. This is particularly important for biofuels—especially renewable natural gas (RNG)—because many of the organic waste feedstocks used to produce these fuels would otherwise decompose and release methane, a highly potent greenhouse gas, directly into the atmosphere. Recognizing these avoided emissions more accurately captures the real climate benefits of diverting organic wastes into controlled fuel production pathways.

• Book and claim accounting and out-of-state eligibility. The CTFP does not require a direct physical pathway for clean fuel from producer to end-consumer. With thorough tracking and verification, the clean fuels can be mixed into the existing distribution system/grid and “claimed” elsewhere, even if the physical molecules or electrons received at the end are not the same. This “book and claim” system is widely used/accepted and key to unlocking greater production and use of cleaner fuels. The CTFP also treats clean fuels produced in-state and out-of-state equally. As a result, clean fuel produced elsewhere in the country can use book and claim accounting to participate in the CTFP, which opens up a far greater potential than in-state production alone.

• Mandatory funds for transportation decarbonization and underserved communities. By law, for utilities participating in the program (such as those selling credits from residential EV charging), 100% of their net revenue from the CTFP must support transportation decarbonization projects, including discounts on EV purchases. At least half of those funds must be directed to assist people living in low-income and underserved communities. The CTFP also enables transit agencies to generate credits, given that more people riding buses and trains means fewer other vehicles on the road and accordingly less pollution.

• Ability to deepen targets. The annual decarbonization targets have already been established through 2030, but the CTFP’s performance will be regularly evaluated and those targets could be deepened if progress is made faster than expected. This was the case in California, which in 2025 officially raised its 2030 target from a 20% reduction to a 30% reduction (among other revisions).

The New Mexico Environment Department expects the CTFP to expand economic development across the state, including creating over 800 jobs. It is also forecasted to deliver $1.65 billion in net benefits by reducing health impacts caused by air pollution as well as infrastructure damage caused by climate change.

The seal of the New Mexico Environment Department. (Image Source: https://www.env.nm.gov)

For clean fuel producers and technology providers this is a welcome development. According to Cory-Ann Wind, currently the director of state regulatory affairs for Clean Fuels Alliance America, a national trade association, “From a market perspective, New Mexico represents an almost 800-million-gallon opportunity for the biomass-based diesel industry. Since it sits along a key corridor for both feedstocks and finished fuels produced in the Gulf Coast and Midwest, New Mexico’s entry into the market not only expands the demand for clean fuels but further strengthens the supply chain.” (Wind previously led implementation of Oregon’s Clean Fuels Program, so she is intimately familiar with the mechanics and benefits.)

New Mexico’s CTFP is a prime example of practical, climate-smart, state-level action to cut greenhouse gas emissions that does not depend on federal support or authorizations whatsoever. Many other states can follow suit with their own Clean Fuel Standards, which are proven to deliver significant results within a few years and at virtually no expense to taxpayers. For state policymakers across the country who want to decarbonize transportation but are concerned about affordability, this is encouraging news.

For many years, the vast majority of U.S. RNG production was absorbed by the on-road vehicle fuel market. That market is now close to saturation. In California, 99% of the natural gas used as vehicle fuel is RNG. Nationwide, the share reached 86% in 2024 and continues to rise. As a result, RNG supply is beginning to exceed demand for transportation fuel.

This may prove temporary. A new heavy-duty natural gas engine from Cummins, the 15-liter X15N, and similar offerings from other major truck/engine manufacturers (e.g. Volvo and Westport’s Cespira JV) open the door for RNG use in long-haul trucking, a segment that previously had few viable clean fuel options. As trucks equipped with these new engines become more common, RNG demand from transportation is expected to grow again. At the same time, ongoing challenges facing zero-emission trucking—high costs, limited availability, and uneven policy support—may further strengthen RNG’s role as a practical alternative.

A heavy-duty tractor-trailer with a Cummins X15N engine filling up with RNG. (Photo credit: Clean Energy.)

While transportation still represents a major opportunity, the most important near-term shift in the RNG market may happen outside the transportation sector. Uses that were once considered niche—particularly gas utility procurement and voluntary purchases by corporations—are central to future demand growth.

A November 2025 report by ICF, commissioned by the RNG Coalition, examined RNG demand across sectors through 2030. It found that while the on-road vehicle market will continue to grow, the largest increases in demand over the next few years are expected to come from gas utilities and voluntary buyers. Other uses, such as aviation, maritime, rail, and hydrogen production, are likely to remain relatively small by 2030, though they hold strong potential beyond that timeframe as the need for high energy density low carbon fuels expands.

ICF estimates that RNG demand from on-road vehicles will grow steadily from just over 100 million MMBTU per year in 2025-26 to 135-160 million MMBTU per year by 2030, driven in part by adoption of the X15N engine. Even under optimistic assumptions, however, transportation demand is projected to be far smaller than demand from utilities. By 2030, utility demand alone is expected to reach nearly 300 million MMBtu per year, with voluntary buyers adding roughly another 100 million MMBtu per year.

If true, this would represent a major shift. Utility and voluntary markets were once a footnote compared to transportation, but they are undoubtedly essential drivers of future RNG demand. While prices in these markets tend to be lower than in transportation, contracts are typically much longer, reflecting utilities’ and corporations’ interest in stable, long-term renewable energy supply and credible emissions reductions.

It is inherently difficult to accurately predict future demand, given the number of variables and market uncertainty. Nonetheless, the ICF assessment offers an evidence-based approach and outlook, even if it proves overly optimistic. Either way, the market is amidst a fundamental shift and the overall direction is clear: by 2030, utilities and voluntary buyers alone could add more than 300 million MMBtu per year of new RNG demand—more than doubling today’s total US RNG production/consumption.

Other demand sources, especially aviation and maritime fuels, are likely to remain modest through 2030. However, they are laying the groundwork for significant growth in the following decade, particularly as shipping and aviation seek proven, cost-effective technology and fuel pathways to meaningfully reduce emissions.

On the supply side, ICF expects RNG production to continue rising, though not as quickly as demand. By 2030, production is projected to increase by roughly 150–240 million MMBtu per year, representing strong growth but still falling short of expected demand.

Today, about 70% of RNG supply comes from landfills, which generally have higher carbon intensity than RNG from manure, food waste, or wastewater. Even so, a stronger market outlook should encourage more landfills to invest in advanced gas capture and upgrading systems. As Energy Vision highlighted in our July 2025 report Leading with Landfills, capturing and selling methane is one of the most cost-effective ways to reduce near-term climate impacts.

It’s important to remember that RNG producers (and investors) need clarity that these new markets will indeed materialize. Some of the most impactful market signals are legally mandated goals for utilities to procure certain percentages of their gas supply as RNG by certain years (such as Oregon requiring that the share of RNG in utilities’ gas rise from 5% in 2024 to 30% by 2045). Growing concerns about affordability and reliability have led many utilities (and states) to reconsider ESG commitments, which could further delay (or derail) efforts to ramp up RNG procurement.

Voluntary commitments by major corporations for using RNG in new markets are also important — especially when backed by early-stage agreements or even seed funding to help such projects get off the ground. This is the case for airlines proactively signing deals to procure SAF, even if deliveries are years out and many hurdles still need to be overcome. It also applies in the shipping industry, where for example, CMA CGM – the operator of the world’s largest LNG-powered fleet – has committed to using 10% bioLNG by 2030.

CMA CGM, operator of the world’s largest LNG-powered fleet, has committed to using 10% bioLNG by 2030. (Photo credit: kees torn/Wikimedia Commons, Creative Commons 2.0)

Additionally, governments can expand successful existing programs to accelerate the growth of new RNG markets. For instance, the federal Renewable Fuel Standard could build on its success in spurring the uptake of biofuels in the on-road vehicle market by also making biofuels eligible to earn credits when used in oceangoing vessels.

Above all else, one thing has become abundantly clear over the past year — demand for natural gas across many sectors of the global economy will persist, likely at least through mid-century. The extent to which those gas supplies (and supply chains) can be decarbonized is now largely a function of political will and corporate leadership as opposed to technological limitations. Despite the near-term market challenges, we expect to see RNG play an important and growing role.

Stay tuned for Energy Vision’s upcoming report on sustainable shipping fuels, including bioLNG and biomethanol.

The 2025 New York State Energy Plan (NYSEP) was formally adopted on December 16^th, in the most encouraging sign yet of the State’s prioritization of technologies and energy/fuel sources that are “affordable, abundant, reliable and clean.” This now includes renewable natural gas (RNG) made from the methane produced by decomposing organic “waste.” While the role envisioned for RNG in the NYSEP is modest and obstacles remain, the State now appears to recognize that it has no viable path to meeting its legally binding greenhouse gas (GHG) emissions reduction targets if it doesn’t make significant changes, including about RNG.

The fact that RNG is being formally included as an option in New York at all is a significant positive step. And not just in the State Energy Plan but also in the “Zero by 40 Technoeconomic Assessment,” prepared by the Electric Power Institute for the New York State Energy Research and Development Authority (NYSERDA) in September 2025. The Technoeconomic Assessment analyzed RNG as part of a set of options for “dispatchable emissions free resources (DEFRs),” which “could provide clean, firm power to the NYS grid to achieve a zero-emissions power sector.” Biofuels – specifically RNG and renewable diesel (RD) – were included among the other DEFR candidates of hydrogen, advanced nuclear, carbon capture and storage on thermal power plants, next-generation geothermal, long-duration energy storage, and virtual power plants, and the assessment concluded that there is a role for all of these sources to play in New York’s energy future.

This is all the more notable because New York’s landmark 2019 climate law, the Climate Leadership and Community Protection Act (CLCPA), enacted a unique greenhouse gas accounting system that has precluded RNG from being considered a “zero-emissions” energy source. More specifically, the CLCPA accounting methodology only measures in-state gross emissions and out-of-state upstream emissions for imported oil and gas. It excludes any avoided emissions from fuel production, any land use change factors, and out-of-state emissions from alternative fuel production and processing.

By contrast, the International Panel on Climate Change (IPCC), the US federal government, California, the EU, and virtually all other developed economies use life cycle analysis (LCA), which counts all emissions and avoided emissions anywhere in the production, processing, transportation, and end-use of all fuels/energy sources. LCA also counts biofuel combustion as carbon neutral, since it is part of the above-ground carbon cycle of plants taking in carbon from the atmosphere and organic matter releasing carbon when it decomposes, rather than bringing up new carbon into the atmosphere from fossil fuels deep underground.

While Energy Vision has long called out the flaws in the CLCPA accounting methodology (see our November 2023 report Putting New York’s Organic Waste to Work and our May 2025 Substack post “Ambition vs Action: New York’s Climate Leadership Gap”), now the State is, too. The State Energy Plan includes detailed analyses of why the CLCPA (or “Climate Act”) accounting distorts the emissions of various fuels, especially biofuels, and why LCA is more accurate. The table below, taken from the State Energy Plan, clearly lays out the shortcomings of Climate Act accounting compared to the widely LCA approach.

The chart below, also from the 2025 State Energy Plan, shows various discrepancies in NY’s accounting methodology, including in-state versus out-of-state emissions. The most important takeaway is that the adoption of lifecycle accounting (the black diamonds in the columns) would reflect all the avoided emissions from RNG production (the green portion of the bars).

The NYSEP calls for LCA to be used wherever possible in addition to the legally required Climate Act framework. It notes, “Both life cycle analysis and Climate Act accounting of GHG emissions from low-carbon alternative fuels should play a role in the design and development of programs and policies. Life cycle analysis should be used in policy development to evaluate and compare GHG emissions reductions associated with different feedstocks, fuels, and end uses and to calculate emissions reductions relative to a business-as-usual scenario. The Climate Act accounting framework should be used when calculating emissions impacts that relate to measuring progress toward Climate Act goals.”

The nearest-term goals under the CLCPA are two-fold for 2030: cut GHG emissions 40% from 1990 levels and source 70% of electricity used in the State from renewables. However, New York acknowledges that it is way off course. The State Energy Plan notes that the core planning scenarios only hit the 40% GHG reduction threshold in 2037-2038. And it is struggling to come up with enough clean sources of electricity to meet the 70% renewables threshold by 2030, especially given that demand is growing rapidly from data centers and the AI boom. Indeed, the base case forecasts a 24% rise in annual electricity demand and a 21% increase in peak demand by 2040 relative to 2025. And the CLCPA targets deepen considerably beyond that: 100% renewable electricity by 2040 and at least an 85% reduction in GHG levels by 2050, with offsets bringing the economy to net zero emissions. Yet the State Energy Plan cautions, “Due to external factors including supply chain disruptions, inflation, recent cuts to federal clean energy tax credits and incentives, and other changes in energy and tariff policy from the federal administration, there is considerable uncertainty in the timeline for progress toward emissions reductions.”

However, there is a workable policy solution at hand: change New York’s accounting methodology to life cycle analysis, the international gold standard. The State’s Annual GHG Inventory already calculates emissions based on LCA as a reference point, alongside the mandatory Climate Act accounting. Based on the latest GHG Inventory, the State Energy Plan notes that if the methodology were changed to LCA, its “Current Policies” scenario would almost reach the 2030 goal of 40% GHG reduction and the “Additional Action” scenario would attain a 41% reduction by 2030 (see charts below). In other words, the current carbon accounting methodology being used by NY distorts the significant progress already made in the State while also limiting the suite of technology/fuel/energy options available to NY to achieve its legally mandated clean energy goals.

Changing over to LCA accounting would greatly help NYS meet its climate targets, with the side benefit of facilitating in-state RNG production and use. It’s not yet clear if/how the State plans to reconcile this issue, but the first step to recovery is recognition of the problem. So we are optimistic that these recent findings – detailed in the NYSEP – signal a level of willingness to address the problem, perhaps even in 2026.

But even with the current Climate Act accounting methodology in place, the State Energy Plan’s Additional Action scenario is still counting on RNG to play a relatively small but important role. This scenario entails incremental policies supporting the deployment of 24 million MMBTU/year of RNG in 2040 (or 3.4% of the energy delivered by the gas distribution system in 2040), to be used at peaking plants to generate electricity. See chart below for the breakdown by end-use sector:

This would be a significant increase from the Current Policies scenario of zero RNG deployment. And if NYS were really serious about reaching net zero GHG emissions as soon as possible, RNG would play a much larger role, rising to 109 million MMBTU/year or 33% of the of the energy delivered by the significantly downsized gas distribution system in 2040 (see table below from the State Energy Plan).

The chart below (also from the State Energy Plan) shows the relative shares of low-carbon biofuels by scenario, where RNG has the greatest feasible potential to scale up.

How do these figures compare to New York’s in-state RNG production potential?

Based on Energy Vision’s ongoing research, New York State is currently producing close to 4 million MMBTU of RNG per year, although almost all is going to end-users out of state where it commands higher prices. According to a 2022 study by consultancy ICF that was funded by the New York State Energy Research and Development Authority (NYSERDA), with existing technologies the State could ambitiously yet feasibly produce up to 44.4 million MMBTU/year of RNG using landfill, wastewater, animal manure, and food waste sources. This is the “Optimistic Growth” scenario featured in the study, involving feedstock utilization rates of 50-75%.

• Energy Vision’s Putting New York’s Organic Waste to Work report calculated that reaching the 44.4 million MMBTU/year level would require building about 300 anaerobic digesters to turn organic waste into RNG and fertilizer. This would cut total NYS methane emissions by 15% at an estimated cost of $3.4 billion, primarily as private investment if policies and incentives improve, and would create roughly 8,000 jobs.

The ICF study calculated that New York’s maximum technical RNG potential is nearly double the Optimistic Growth total, at 83.9 million MMBTU/year. (These figures exclude potential RNG sources that are not commercially viable today, specifically thermal gasification of agricultural residues, energy crops, forestry residues, and municipal solid waste, although the ICF study did calculate their potential in various scenarios as well.)

So the 24 million MMBTU envisioned in the State Energy Plan’s Additional Action scenario would be around six times greater than current RNG production but still well below New York’s achievable potential. This level can be reached, and it appears the State is laying considerable groundwork for it by inclusion in these official scenarios.

In the power sector, relative to other dispatchable emissions free resources (DEFRs), RNG has many advantages, including in commercial readiness, cost, and reliability and scalability of supply.

For example, citing the Zero by 40 Technoeconomic Assessment, the State Energy Plan notes that “hydrogen carries significant deployment barriers, including challenges related to the buildout of infrastructure, renewables, plant upgrades, and electrolyzers. RNG carries advantages as a drop-in replacement to conventional fuels.” The Technoeconomic Assessment includes a sensitivity analysis where RNG replaced green hydrogen as the “zero-carbon firm resource”; this resulted in cost savings to the State of $2.9 billion in net present value through 2040, with additional savings expected beyond then, and avoided technical challenges. The State Energy Plan notes these were driven by “Lowering fuel costs, as RNG is estimated at approximately 2.5 times less expensive than green hydrogen; Avoiding converting the combustion resource fleet for hydrogen compatibility; [and] Avoiding some technical challenges of H2 [hydrogen] including buildout of infrastructure, renewables, and electrolyzers.”

So how does NYS propose facilitating the necessary RNG production? Several other passages from the State Energy Plan reveal a considerable push for changes, albeit with some caveats, and we provide our perspective after each one.

• “To catalyze low-carbon alternative fuels markets to meet future demand, policy, regulatory, and market interventions—such as mandates, market-based mechanisms, and incentives—will likely be needed.”

  This is an acknowledgement that the status quo is insufficient to drive the necessary growth but that it is within the State’s power to change these structural conditions.

• “To meet State policy goals, a limited amount of alternative fuels will need to be produced, transported, and used in the broader energy system. To minimize costs and other impacts, existing infrastructure should be leveraged for the transport and storage of pure or blended alternative fuels wherever it is safe and technologically and economically feasible. In cases where existing systems are incompatible or insufficient, limited new, fuel-specific infrastructure may be needed to connect supply with areas of demand.”

  This is an acknowledgement that RNG will need to be blended into the existing gas pipeline grid, and that new pipelines may be needed to connect sources of RNG such as large dairy farm clusters to the grid.

• “To maximize production and leverage economies of scale, future RNG production facilities may be sited where they can collect feedstock from multiple sources, such as clusters of farms or food waste producers, in an efficient and cost-effective manner and be located near existing pipeline infrastructure to minimize the need for new construction.”

  This is a pragmatic recognition of how RNG production can most effectively scale up in NYS and may indicate what the State would be willing to incentivize down the line.

• “Regardless of the specific future pathway for New York’s energy system, continued investment to maintain and modernize existing infrastructure, replace aging equipment, and purchase fuels to meet energy needs will be necessary.”

  This is an affirmation that the natural gas grid will remain a key component of New York’s energy matrix, even as the State is expected to decommission older natural gas plants over time and ideally see RNG displace fossil natural gas as much as possible.

• “New York State should take a targeted approach to alternative fuel use—prioritizing in-state, waste-based feedstocks when possible—to maximize GHG emissions reductions and other benefits of reducing waste disposal in landfills, affordability, and economic development opportunities... To meet the demand projected in the Pathways Analysis, regional and non-waste feedstocks and fuel production will also be necessary.”

  This shows an understandable preference for prioritizing in-state, waste-based feedstocks over out-of-state and/or non-waste feedstocks (the potential for energy crops being used to produce biofuels), but it acknowledges that both of those will be necessary to meet rising demand for biofuels. This doesn’t apply as much to RNG as the other biofuels considered (like renewable diesel and sustainable aviation fuel or SAF), given that there is sufficient in-state potential for RNG and energy crops are not among the commercially ready feedstocks for RNG at present (since they would require thermal gasification). But it perhaps opens the door to out-of-state RNG procurement if in-state production proves insufficient.

While these passages underscore how NYS is warming up to RNG in the power sector, it’s still not a wholehearted endorsement. “Electrification should remain the State’s primary decarbonization solution,” the State Energy Plan declares. Another passage notes, “It is important to recognize that many alternative fuels, such as hydrogen, SAF, renewable diesel, and RNG, can be produced from the same limited pool of feedstocks. As such, infrastructure and policy decisions should prioritize fuels with the greatest long-term strategic value, which are expected to play a role in decarbonizing hard-to-electrify sectors. For example, one possibility is that wastewater treatment facilities could be designed to lower methane generation and instead optimize conditions for producing liquid fuel or hydrogen rather than RNG. Ultimately, infrastructure should reflect a long-term holistic, system-wide vision rather than focus on single fuels.” Lastly, the State Energy Plan also pushes for improving the operational efficiency of RNG production. It states, “Anaerobic digestion and RNG production should focus on energy efficiency, leak detection and repair, right-sizing digester and gas production operations, and using clean energy in production processes to further reduce GHG emissions.”

The bottom line: New York State appears more receptive than ever to RNG, at least in the power sector. Even under the current constraints, NYS has now laid out a detailed justification for procuring six times more RNG than current in-state production for use in peaking plants. And if the State changes over to LCA accounting to help meet its climate targets, it would dramatically accelerate in-state RNG production and use.

International scientists concluded in 2021 that cutting emissions of methane, an extremely potent greenhouse gas, is the top near-term global priority to avoid the catastrophic impacts of runaway climate change. This gave rise to the Global Methane Pledge that year, in which 159 countries have now committed to cutting global methane emissions at least 30% from 2020 levels by 2030 (“30x30”).

The signatories of the Global Methane Pledge are highlighted in blue. Source: Global Methane Pledge.

But progress has been slow toward that goal for several reasons. Major methane emitters like China, India, and Russia have refused to join. The Trump Administration has retreated from not only the Methane Pledge but from essentially all of the US’s climate commitments. And other countries have asked why they should have to pay when others aren’t doing their share. The result is that global methane emissions have actually gone up since 2021.

With just over four years left until 2030, a major acceleration in methane reduction is required. To achieve that, there’s a real need for credible data showing that cutting methane makes economic sense – both at the individual country/state/local levels and for private sector actors.

A new article in the peer-reviewed journal Science lays out a compelling worldwide economic case for reaching 30x30. “Global methane action pays for itself at least six times over,” by Thomas Stoerk et al, uses the latest, most advanced climate models to calculate the costs and benefits associated with achieving the Global Methane Pledge target and continuing to reduce methane emissions beyond 2030.

Summarizing its findings, the Science study states, “Achieving the Global Methane Pledge results in more than $1 trillion in annual avoided market damages by 2050. Benefits are greater in lower-income countries because of their higher vulnerability to climate change. Methane action also reduces climate risk, including the likelihood and severity of extreme damage outcomes (climate tail risk). It lowers the intensity of several key tipping points: For example, by 2050, the likelihood of Amazon rainforest dieback drops by 8% and Indian monsoon disruption by 13%. Even using conservative assumptions about costs, the benefit-cost ratio of methane action is at least three—rising to more than six when health co-benefits are included.”

The study also notes that some methane mitigation would more than pay for itself directly, thanks to greater energy recovery and other gains. Lastly, it calculates the global “social cost” of methane – meaning what the cost of future damages would be from one metric ton of methane emitted now. The study finds the global average social cost of methane to be $7,381 per ton, which is much higher than estimates in previous studies since it includes the impacts of climate tipping points like melting of the Antarctic and Greenlandic ice sheets. If abatement efforts and damages are measured within domestic borders only, rather than globally, the highest social costs of methane are in the US, EU, India, and China – underscoring that methane action is in their economic self-interest regardless of any broader collective action.

While the global need to cut methane for the sake of the climate is clear, and the economic rationale for countries to do so is now more robust than ever, the missing link is the development of markets and carbon accounting protocols to drive implementation. Regardless of any social cost, if methane abatement projects are not economically viable or there isn’t clear enough guidance around how corporate/voluntary buyers can account for upstream avoided methane emissions, then they won’t get built. At least not without major subsidies, which are often politically controversial.

Fortunately, Energy Vision’s research has found viable drivers for change at hand, including:

• Various state and federal programs in the US and EU are in place driving the construction of anaerobic digesters (ADs) to capture the methane from decomposing organic waste. In Energy Vision’s 2024 report Meeting the Methane Challenge, we calculated that building about 4,700 ADs to process food waste and animal manure would cut total US methane emissions by 13.6% (from the 2020 level). The captured methane from ADs can be used to generate electricity or refined to produce low- or negative-carbon renewable natural gas (RNG). Also known as biomethane, RNG can replace more polluting diesel fuel in heavy-duty transportation and power industries that cannot feasibly be electrified. Meanwhile, the leftover biosolids in the ADs can be used as saleable fertilizer. However, the rapid buildout of this infrastructure (particularly in the US) requires that the markets for RNG must also expand, as demand remains constrained by high costs, lack of clarity for RNG in carbon accounting frameworks outside of the transportation sector (see below), and other factors.

• There is tremendous potential to cost-effectively cut upstream methane emissions from the oil and gas sector. In our report Meeting the Methane Challenge, Energy Vision found that plugging low-producing (“stripper”) oil and gas wells would cut total US methane emissions by 10.7% (from the 2020 level). But there’s perhaps a more feasible subset to target: plugging just the leakiest 5% of those (around 35,000 stripper wells) would cut total US methane emissions by 5.4%. Meanwhile, in the EU, major efforts are now underway (see: EU Methane Regulation) to require fossil fuel importers to first track and then reduce the “carbon intensity” of fuels (especially natural gas and petroleum products) they intend to import to Europe.

• Energy Vision found one strategy that is extremely cost effective in its own right but needs to be better recognized: adopting advanced landfill technology to capture more methane emissions. In Energy Vision’s 2025 report Leading with Landfills, we calculated that implementing proven technology and techniques at approximately 900 candidate landfills in the US would cut total US methane by 8% (from the 2020 level). And were all the captured landfill gas upgraded to RNG, that would expand the current nationwide supply by an impressive 70%. California’s Air Resources Board (CARB) recently approved a new pathway verifying a net-negative carbon intensity for the Yolo County landfill gas-to-electricity project as a result of implementing this kind of advanced landfill tech. If expanded to other markets, this would create a major economic incentive to optimize landfill operations toward minimizing fugitive methane emissions (see our Substack post on that here).

These technological solutions can be accelerated by policy solutions, especially those that directly improve project economics. Well-designed subsidies are always helpful, but even just expanding eligibility and providing much-needed guidance within existing carbon accounting protocols could make a huge difference. Notably, some major companies that have looked into procuring RNG decided against it because they found they wouldn’t have been able to claim the emissions reductions under the default carbon accounting framework, the Greenhouse Gas (GHG) Protocol.

The GHG Protocol is the most widely used framework for greenhouse gas accounting in the world, associated with the World Resources Institute and World Business Council for Sustainable Development. 97% of S&P 500 companies that reported to the Climate Disclosure Project in 2023 used the GHG Protocol; hundreds of cities across the globe have committed to using it; and the Protocol is used in developing some national GHG emissions reduction programs as well. Unfortunately, however, the GHG Protocol thus far has not been clear on allowing renewable gases like biogas and RNG to count toward emissions reduction targets. But a revision is upcoming.

On November 5^th, the Let Green Gas Count Coalition of companies and industry associations (mostly led by EU entities) released a letter asking for the GHG Protocol revision to boost investor confidence by explicitly recognizing market-based tools that incentivize decarbonization, including via renewable gases. These include certification schemes, such as guarantees of origin or proof of sustainability certificates, and emissions-trading schemes. While the revision process currently has a deadline of 2028, the letter signatories urge it to be fast-tracked and for the GHG Protocol to issue an interim statement assuring that it will recognize robust market-based instruments.

Doing so could unlock a wave of additional investment in methane-abatement solutions like building ADs and advanced landfill tech systems that would produce RNG. This would be key in allowing hard-to-decarbonize industries to verifiably cut their net emissions without any legal ambiguity, which in turn will help governments around the world in meeting their national climate goals.

A heavy industrial plant of the type that could more feasibly run on RNG if carbon accounting frameworks were clearer about crediting avoided methane emissions from the production of renewable gases. Photo source: Llywelyn2000, CC BY-SA 4.0/Wikimedia Commons.

As scientific consensus grows that mitigating methane is the strongest near-term lever available to slow warming, and evidence mounts that strategies for doing so are increasingly cost-effective to achieve, there is nevertheless a major disconnect with the actual pace of progress. This is due in part to a lack of clarity and guidance around carbon accounting protocols. Concerns about double counting and greenwashing among major corporates and heavy industry are warranted. But as our ability to better monitor and measure methane emissions improves – almost daily – around the globe, creating or expanding user-friendly frameworks tied to voluntary and compliance-based GHG reduction markets is key to accelerating the necessary investments and infrastructure.

In the US, the challenge of creating markets for RNG (also known as biomethane) from organic waste has become very acute. Over the past five years alone, US RNG production capacity has grown three-fold. But this has outpaced growth in demand within the traditional markets – most notably, the on-road transportation sector. Despite this rapid growth in production, RNG represents just 0.4% of total US natural gas demand. Numerous “difficult to decarbonize” segments of the economy remain heavily reliant on fossil natural gas, and many are actively pursuing, or at least exploring, opportunities to displace meaningful quantities of fossil gas with RNG, including the maritime sector, steel/glass/cement/asphalt producers, data centers, and many more. But the combined lack of guidance around how to account for these emissions reductions – often Scope 3 – and lack of market mechanisms that exist for potential “voluntary” buyers is inhibiting the ability of investors and developers to build more methane capture projects.

Energy Vision and many others are working to overcome this challenge, but to stay on track to meet the global 30x30 methane reduction goal will require fast action. As COP30 begins in Brazil, scaling up methane abatement should be among the highest priorities. The technology exists, significant sources of capital are available, and major corporate and industrial players are eager to do their part. The time is now to deploy methane capture solutions at scale.

One of many old diesel trucks in Greece. (Photo source: hans-johnson/Flickr, CC BY-ND 2.0)

This is concerning from an air pollutant and public health perspective, since, as a general rule, the older the engine, the worse its emissions of toxic air pollutants. Diesel exhaust is carcinogenic and includes nitrogen oxides (NOx, a respiratory irritant and smog precursor), fine particulate matter (PM2.5), and other harmful components. Cleaner engine technology has advanced a long way since 2000, but these old, ubiquitous diesel trucks are still spewing pollutants in Greece, Italy, and many other European countries (see table below). The effects are disproportionately felt in urban areas with lots of truck traffic and warehouses, and in communities near major highways.

Top 10 European Countries with the Oldest Trucks and the EU Average Age of Trucks

Source: Energy Vision table drawn from European Automobile Manufacturers’ Association (ACEA), Vehicles on European Roads, January 2025.

Energy Vision explored these issues in the U.S. context in our March 2025 report, A Path to a Healthier America: Ditching Old Diesel Trucks. Our general conclusions hold for Europe, too, although we focused on the heaviest trucks while ACEA includes a wider range, and engine and fuel emissions standards are different in the U.S. and Europe.

When ACEA refers to trucks, it specifies these are medium and heavy commercial vehicles over 3.5 metric tonnes (over ~7,700 pounds); in the US vehicle classification system would be from the upper end of Class 2 through Class 8. This is a broader pool than just the Class 7 and 8 vehicles (over 26,000 pounds) that we analyzed in Ditching Old Diesel Trucks. And the engine and fuel standards in Europe vary from those in the U.S., so emissions are not identical even for similar vehicles. Nonetheless, just as Energy Vision found that in the U.S., pre-2013 heavy-duty diesel trucks emitted by far the most toxic air pollutants, we know that the oldest trucks in Europe are likewise the most polluting.

As the table above shows, the problem is most severe in Greece, but it is dire in many other European countries as well, and the average age of trucks across the entire EU is 14.1 years old. Together, just the top three countries – Greece, Italy, and Czechia – have over 1 million old diesel trucks whose average model years are from 2000-2005. And those are averages, meaning there are plenty of even worse emitters from the 1990s still on the road.

In Ditching Old Diesel Trucks, we looked at three cleaner options to replace the oldest 20% of Class 7 and 8 diesel trucks in 31 highly populated counties across the U.S., totaling 130,000 vehicles. We found new models running on renewable diesel (RD) would deliver substantial avoided health costs relative to the baseline with no marginal vehicle purchasing premium. We found new models running on renewable natural gas (RNG, also known as biomethane) would result in even more avoided health costs with a modest vehicle premium. And we found that new electric trucks would deliver the most health benefits but would not be feasible at that scale anytime soon because of very high purchasing premiums, limited availability of trucks and necessary charging infrastructure, and performance issues.

Given the wider range of trucks considered in ACEA’s report, all three cleaner fuel options are available in at least some applications in Europe:

• For example, medium- and heavy-duty trucks in Europe can easily run on renewable diesel with no modifications needed; European production and consumption of RD are rising, aided by EU legislation including biofuels in the transportation decarbonization roadmap to 2040.

• Meanwhile, as of the end of Q2 2025, there were more than 45,000 medium- and heavy-duty trucks running on natural gas in Europe (33,989 compressed natural gas and 11,294 liquefied natural gas), up from 25,000 in 2020, according to the European Commission. Major truck manufacturers like Iveco, Scania, and Volvo offer 9-liter and 13-liter engine models that can run on compressed or liquefied natural gas, including for long-haul tractor trailers. (The new Cummins 15-liter compressed natural gas engine is not yet available in Europe.) These engines can seamlessly run on RNG/biomethane rather than fossil natural gas, and that trend is growing as an immediately achievable sustainability measure for fleets.

• Lastly, medium-duty trucks can feasibly be electric in many cases, especially with various incentives from EU member states. The feasibility is more challenging with heavy-duty trucks, as electric models are still far more expensive than their diesel counterparts, but deployments across the continent are gradually ticking up regardless. As of the end of Q2 2025, there were 19,886 medium- and heavy-duty battery electric vehicles in Europe, up from 2,462 in 2020.

EU policy on heavy-duty vehicle emissions is almost entirely focused on cutting the average emissions of new trucks deeper over time. In 2024, European lawmakers passed legislation that vehicle manufacturers will have to cut the average carbon emissions of new trucks by 45% in 2030, 65% in 2035, and 90% in 2040 (expanding from the 15% target for 2025). This is commendable but does not directly address the scourge of old diesel trucks that are still extremely prevalent on the roads today. To avoid the most public health costs, the oldest trucks need to be replaced with newer, cleaner models as soon as possible – not continued to be driven until the last possible mile.

If the replacements can feasibly be zero tailpipe emission models, great. But if electric is not a viable option for fleets, then there should be more incentive programs for them to replace their old diesel trucks with new, much less-polluting RNG/biomethane trucks (or RD trucks). Whether in Europe or the U.S., truck fleets will select the vehicle and fuel combinations that work best for them, and the economics have to pencil out. It is the role of policymakers to create sticks and carrots to shift fleet managers’ mentality from “change nothing for as long as possible until we’re compelled to go fully electric” to “what feasible, cleaner options can we take now, proactively, to cut emissions?” New RNG/biomethane and RD trucks deserve serious consideration for immediately and cost-effectively cutting air pollutants and greenhouse gases, even as heavy-duty electric trucks become more widely available.

We are particularly focused on ways to cut methane emissions, which is the strongest lever available to slow climate change in the coming decades. Since our founding in 2007, much of our research has been on how methane from organic waste can be captured and used to create renewable energy, simultaneously cutting the need for fossil fuels – a major double win. We regularly produce cutting-edge reports (all available for free at energy-vision.org), present to policymakers, industry and investors and publicize our findings through various channels (including this Substack!).

Energy Vision launched this Substack page in February 2025 as a go-to resource for insights on innovative solutions, policies, changemakers, and opportunities across some of the most challenging sectors to decarbonize: heavy-duty transportation, agriculture, landfills, our food supply, wastewater, shipping, etc. And we have a lot more coming up!

But none of our work would be possible without the support of our members and allies. In that spirit, we invite you all to join us on Thursday, October 16^th in New York City for our Annual Leadership Awards Celebration!

Tickets Available Here!

Our reception offers a unique opportunity to engage with key stakeholders working to advance and deploy climate smart solutions essential for a green economy – all while enjoying delicious food and drinks at fantastic venue committed to sustainability in the City.

Highlighting the evening will be the presentation of our 2025 Energy Vision Leadership Awards, recognizing trailblazers who are accelerating commercial solutions to capture methane and transform it from a climate liability into a clean fuel solution. The awardees are:

· Divert, Inc., a U.S. company actively implementing software, hardware, and physical infrastructure to prevent food from being wasted. Through partnerships with major food retailers and wholesalers, Divert has donated 14 million meals to the food insecure and processed 3.3 billion pounds of unsold, non-donatable food that would otherwise have been landfilled. To further expand its footprint and impact, Divert is now building out a portfolio of commercial-scale anaerobic digestion facilities to transform inedible food (“food waste”) into renewable energy and soil amendments.

· Cummins and FedEx, for their respective commitments to advancing renewable natural gas (RNG) as a vehicle fuel for the heaviest duty (Class 8) trucks on US roadways. Cummins’ new X15N compressed natural gas engine offers the first viable alternative to diesel without sacrificing performance, while providing major environmental and public health advantages when using RNG. FedEx Freight, one of the largest national logistics providers, made an early commitment to deploy new trucks equipped with X15N engines and run them on RNG.

· EnviTec Biogas AG, a German-based global leader in the design, construction, and operation of anaerobic digesters processing a wide range of industrial, agricultural, and municipal organic waste streams. Since its founding in 2001, EnviTec has built more than 800 systems worldwide and owns/operates 88 facilities in Europe. EnviTec’s Güstrow, Germany facility is among the most advanced in the world in extracting maximum value from organic “waste” streams – enough renewable energy (biogas) to power the entire site; liquefied RNG dispensed through its refueling stations to fuel heavy-duty trucks; and beverage-grade biogenic CO2 plus soil nutrients reused in local agricultural operations.

· Durwood Zaelke, founder and president of the Institute for Governance and Sustainable Development (IGSD), is being recognized for his decades of leadership in raising international awareness of the need to rapidly mitigate methane and other short-lived climate pollutants. Fun fact: Zaelke also weighed in for our press release last year for Meeting the Methane Challenge, saying, “Energy Vision’s report will be a very useful publication. Methane is the blowtorch that is pushing the climate from global warming to global boiling. We need to turn this blowtorch off immediately to have the best chance to keep the planet safe.”

Together, we can transform waste into opportunity and vision into action. We hope to see you at the Awards Celebration on October 16^th! Tickets are available here.

If you can’t make it this year, we hope you’ll consider making a tax-deductible donation to Energy Vision to sustain our work in the coming year. https://energy-vision.org/donate/

Thank you!
-The EV Team

Part of a landfill gas collection system using advanced monitoring and optimization technology, which includes both hardware and software. Photo Source: LoCI Controls.

Landfill gas energy projects have historically had relatively high lifecycle greenhouse gas emissions compared to other low-carbon fuels. This reflects the fact that most of the landfills with energy projects are required to install landfill gas collection and control systems (GCCS) anyways, and that such systems are often limited in coverage and inefficient if not properly maintained.

But a new frontier – with a compelling business case – is opening for landfills going above and beyond federal and state regulatory requirements by using advanced technology to capture additional landfill gas. This methane-rich gas would have otherwise escaped into the atmosphere and exacerbated climate change, given that methane is a far more potent greenhouse gas than carbon dioxide. International scientists concluded in 2021 that global methane emissions must be cut at least 30% by 2030 (a goal known as 30x30) to avoid catastrophic runaway climate change, and 159 countries have pledged to do their part.

Earlier this month, the California Air Resources Board (CARB) approved the first-ever negative carbon intensity (CI) pathway for a landfill gas to electricity project in the Low Carbon Fuel Standard (LCFS, the state’s clean transportation fuels program). The lower the CI score, the more valuable the fuel is in the LCFS (arguably also true for other markets like voluntary corporate procurement). This new pathway, at the Yolo County Central Landfill in California, achieved a CI of -101 grams of CO2 equivalent per megajoule (g CO2e/MJ), thanks to its use of advanced landfill tech from LoCI Controls to capture emissions well beyond the regulatory requirements and use them to generate power for electric vehicles. Typically, landfill electricity projects report positive CI scores of 40-50 g CO2e/MJ, so this new pathway is a steep decrease in terms of lifecycle emissions. The quantified environmental benefits were confirmed by CARB with peer-reviewed public methodology from American Carbon Registry (ACR); this certification under the LCFS was validated by independent verifier TÜV SÜD America.

As Energy Vision’s July 2025 report Leading with Landfills noted, there is tremendous potential for landfills to cut their methane emissions and earn new revenue by adopting advanced landfill tech. These include real-time monitoring and automated wellhead tuning systems; installing gas capture systems early on at working faces in time to capture methane (especially from decomposing food waste) that otherwise would escape into the atmosphere before conventional GCCS are installed; and building GCCS at high-emitting, high-flow landfills that are below the relatively lax legal threshold requiring such installation.

To underscore the scale of this opportunity, if all three of these options were implemented at ALL feasible municipal solid waste (MSW) landfills in the US, or some 900 sites, MSW sector methane emissions could be cut in half (reducing total US methane by ~7.2%). This would be incredibly cost effective as a climate measure, at an estimated $8.35 per ton of CO2 equivalent abated – far less than many other options. And this additional captured methane could be used beneficially, to generate electricity or be upgraded to renewable natural gas (RNG), quickly recouping the modest extra costs and then adding to landfills’ bottom lines.

Thanks to this new negative CI pathway, the business case for adopting advanced landfill tech is becoming even more compelling. Now that CARB has set the precedent by greenlighting a negative CI landfill gas to electricity pathway, it seems likely that the first pathway for negative CI landfill gas to RNG used as transportation fuel will be approved at some point, too. It would likewise be based on independent verification of avoided methane emissions above and beyond what’s required by law.

While all CI scores are project-specific, factoring in a host of inputs, we would expect landfill gas to RNG at sites going above and beyond regulatory requirements with advanced landfill tech to achieve negative CI scores in the same ballpark as Yolo County Central Landfill. The economics are appealing even with landfill gas to RNG projects having CI scores in the 40s; if they could achieve -100 CI scores, it would provide a major new impetus to adopt advanced landfill tech.

Thus far, the only RNG feedstock to achieve deeply negative CI scores in the LCFS is animal manure, which averaged -299 in Q3 2024. RNG from food waste also achieves negative CI scores, averaging -25 in Q3 2024. If a subset of new landfill RNG projects (the portion of their production above and beyond regulatory requirements) can attain CI scores of around -100 (or possibly deeper if they really optimize all aspects), then hundreds more sites may adopt advanced landfill tech. For reference, under California’s LCFS program, the difference – in terms of credit value – between a +40 CI and a -100 CI is considerable: approximately $2.10/mmbtu vs. $8.40/mmbtu in incremental value, based on current market conditions.

Landfills, representing roughly a quarter of all operational RNG facilities, already account for about 70% of total US RNG supply. And as Leading with Landfills noted, if all 900 candidate sites were to adopt the feasible advanced landfill tech options and upgrade their newly captured gas to RNG (as market conditions favor), that would bring on another 93 million MMBTU per year – a roughly 70% increase from the current total national supply (around 135 million MMBTU in 2024). If most of that additional supply could be certified carbon negative, the ripple effects would be huge, whether the RNG is used in transportation markets like the LCFS (and where the 45Z Clean Fuel Production Credit created under the IRA may offer a new pathway for additional value) or in other sectors such as heavy industries, utility-scale heating, or maritime fuel (although to date there is not as clear a mechanism to appropriately monetize carbon-negative RNG used outside of the transportation market).

Diverting food waste and organics from landfills is still a key priority (even under the current federal administration, which recently announced a new “Feed it Onward” initiative that maintains a joint goal by US EPA and USDA to cut food waste 50% by 2030). Nearer term, prioritizing advanced landfill tech can enable arguably the single largest cut in US methane amongst all economically feasible and politically realistic options today, keeping 30x30 within reach. Above all else, it’s now abundantly clear the landfill sector has a critically important role to play in advancing the low-carbon future.

An old, extremely polluting heavy-duty diesel truck spewing harmful emissions on the interstate. (Photo Source: Michael Lerner, Energy Vision)

Newer diesel trucks from model year 2013 onwards are far cleaner, in many cases already meeting tighter upcoming standards for nitrogen oxide (NOx) emissions. (Photo Source: CARLOSCRUZ ARTEGRAFIA, Pexels.com)

A May 2025 study published by a team of researchers from University of California, Riverside (UCR) shows outsized emissions reduction effects of replacing older heavy-duty diesel engines with new diesel or natural gas models, regardless of EV adoption. The study, “The impacts of improving heavy-duty internal combustion engine technology on reducing NOx emissions inventories going into the future,” is California-specific in terms of projected fleet composition and toxic nitrogen oxides (NOx) emissions through 2050, but the implications are valid nationwide.

The UCR study can be considered a forward-looking complement to Energy Vision’s March 2025 report, A Path to a Healthier America: Ditching Old Diesel Trucks, which analyzed the reductions in NOx and fine particulate matter (PM2.5) emissions of replacing old (pre-2013) heavy-duty diesel trucks with cleaner options now, and what the resultant public health impacts would be.

Cutting NOx emissions is critical because these compounds are harmful to both human health and the environment. NOx compounds are respiratory irritants; acute exposure can aggravate asthma and other respiratory illnesses. Communities that live in close proximity to major roadways are chronically exposed to higher levels of NOx, with accordingly higher instances of asthma, respiratory infections, and premature death. NOx emissions also contribute to the formation of acid rain as well as ground-level ozone, a toxic air pollutant that is the main component of smog. Ground-level ozone is not only very harmful to human health, it has also been shown to significantly reduce crop yields. All of these issues are particularly important in California, which has long struggled with smog and where heavy-duty trucks are the largest source of NOx emissions. California has accordingly adopted tighter NOx standards for trucks than the rest of the country.

The UCR study analyzed in-use NOx emissions data from 63 heavy-duty vehicles of a variety of applications, model years, and fuel types (diesel, natural gas, liquefied petroleum gas, and hybrid diesel). It found that diesel engines manufactured after 2020 and natural gas engines certified to the voluntary 0.02 grams per brake horsepower-hour (g/bhp-h) emissions standards that California established in 2013 also already meet the more stringent 2027 and 2035 EPA in-use NOx standards, even though the future standards don’t apply to these older engines. Of note, for example, the study found that natural gas engines manufactured in 2016 or 2018 are already meeting the 2027 and 2035 NOx standards.

Under the Trump Administration, there is considerable uncertainty over the fate of the 2027 and 2035 EPA in-use NOx standards, which had been approved in 2022, but are now prime targets for revocation, along with other major EPA rulemakings such as the endangerment finding (see Energy Vision’s earlier Substack post on that). Any attempts at revoking the upcoming low NOx standards will almost certainly be met with lawsuits, but the end results remain to be seen. However, since the UCR study assumes the 2027 and 2035 EPA in-use NOx standards will remain in place, this Substack post will analyze it on those terms.

The UCR study used the California Air Resources Board (CARB)’s latest emissions factor model, EMFAC2021, to model the estimated statewide heavy-duty vehicle fleet composition and NOx emissions through 2050. However, it noted that EMFAC2021 does “not reflect the more recent adoption of more stringent NOx emission standards beginning with the 2027 and 2035 model years.” Based on their findings of the measured NOx emissions of the 63 heavy-duty vehicles as well as the findings of other studies, the authors ran a modified scenario through 2050 using considerably lower NOx projections for heavy-duty vehicles certified to meet the 2027 standard. The results are depicted in the chart below.

Total NOx Emissions from Heavy-Duty Vehicles According to 2027 and 2035 Certification NOx Emission Rates

Source: Troy Hurren, Thomas D. Durbin, Kent C. Johnson, Georgios Karavalakis, “The impacts of improving heavy-duty internal combustion engine technology on reducing NOx emissions inventories going into the future,” Science of The Total Environment, Volume 986, 2025, 179781, ISSN 0048-9697, https://doi.org/10.1016/j.scitotenv.2025.179781.(https://www.sciencedirect.com/science/article/pii/S0048969725014226). Posted here with author permission.

In the chart above, purple represents emissions from pre-2010 heavy-duty vehicles, blue represents emissions from heavy-duty vehicles certified to the 2010 EPA NOx standard, and yellow represents emissions from heavy-duty vehicles certified to the even tighter 2027 EPA standard (including EVs, which don’t emit any NOx).

So what does all this mean?

Based on the UCR study’s revised projections, 95% of the NOx emissions reductions between 2025 and 2045 for heavy-duty vehicles would come from replacing older vehicles with 2027-certified low NOx vehicles running on diesel or compressed natural gas. Those internal combustion engines being replaced include both the relatively small but extremely high polluting pre-2010 subset and the more numerous but less polluting 2010-2026 subset. The replacement of those vehicles and the implementation of much more stringent NOx emissions requirements in 2027 will account for nearly all the emissions reductions. The study notes, “To the extent that vehicle technologies could transition to completely zero emissions after 2027, this would only provide an additional 5.1 % reduction in emissions.”

Given the ongoing efforts at the federal level to eliminate funding and support for electric vehicles, including Congress revoking EPA waivers for three key California clean truck policies, the study authors also ran a demonstrative scenario in which no heavy-duty EVs were to be introduced after 2025. But even then, with additional 2027 certified heavy-duty diesel or natural gas vehicles instead of EVs, there would only be a very slight increase in NOx emissions, as represented by the grey hatched lines in the chart just above the yellow portion.

Overall, if ultralow NOx diesel technology engines are adopted as projected, the study found that California’s NOx emissions from the heavy-duty vehicle sector could decrease 90-91.9% by 2050, depending on the deployment of EVs. The study alludes that this will also improve local and regional air quality, including in environmental justice areas.

These results fit right in with the findings of Ditching Old Diesel Trucks, particularly that:

• Heavy-duty diesel vehicles from pre-2013 model years emit the most toxic air pollutants, including NOx and PM2.5.

• New heavy-duty vehicles (represented by model years 2023 and 2024) running on either diesel or compressed natural gas emit 70% or 94% less NOx than the pre-2013 diesel baseline, respectively. New diesel engines also emit 33% less PM2.5 than the pre-2013 diesel baseline, while new compressed natural gas trucks emit 43% less PM2.5 than the baseline.

• Replacing older heavy-duty diesel vehicles with newer models running on renewable diesel or renewable natural gas (RNG) is feasible now and would make a major difference in local air quality, avoided public health costs, and lifecycle greenhouse gas emissions.

The UCR study notes that ultralow NOx natural gas engines have been available for nearly a decade, are far more economical than electric propulsion powertrains, and can cut lifecycle GHG emissions through the use of RNG. Ditching Old Diesel Trucks analyzes these issues extensively, concluding that new heavy-duty models running on RNG are the overall best, most cost-effective, and feasible choice to replace old, heavily polluting diesel trucks (see our Substack summary of the report here).

Likewise, both studies emphasize the opportunity to cut emissions immediately based on existing diesel and natural gas engine technology, without waiting many years for heavy-duty electric engines to become a feasible option at scale. The UCR study notes, “even if the transition to fully zero-emissions HDVs [heavy-duty vehicles] occurs more gradually, newer technology [including] conventional diesel and alternative fuel vehicles can still provide substantial and meaningful emissions reductions in the intermediate term, and in the near term as battery electric technology continues to develop.” For its part, Ditching Old Diesel Trucks notes, “Given the extremely limited availability and high prices of heavy-duty EVs, if fleets and policymakers opt to change nothing until they can go fully electric, that means essentially locking in years of continued use of heavily polluting diesel fuel by older vehicles in the meantime. That option de facto exposes people to negative health outcomes that could be mitigated by more rapid replacement of old diesel trucks.”

The bottom line: tremendous NOx emissions reductions can be achieved right away by replacing older diesel trucks with newer internal combustion models, regardless of how EV adoption eventually progresses.

(Photo source: Luis Alfredo Romero, CC BY-SA 4.0 via Wikimedia Commons)

But here’s the catch: the global shipping industry moves over 80% of the world’s trade. It also burns some of the dirtiest fuel on the planet. Right now, shipping is responsible for nearly 3% of global greenhouse gas emissions. If considered a country, the international shipping sector would rank among the top 5 global emitters. If we don’t take corrective action, those emissions are poised to rise drastically as shipping volumes increase. The good news? We have the tools to change course, and some companies are already taking the initiative.

Maritime Shipping at a Glance

The global merchant fleet includes over 106,000 commercial vessels, thousands of which move across oceans every single day. Each one of these vessels burns millions of gallons of fuel every year, mainly consisting of heavy fuel oil, a high-carbon byproduct of petroleum refining. A single large container ship can burn 80,000 gallons a day. That’s the same amount of fuel used by 6,500 passenger cars in an average week.

(Photo source: “Houston Fuel Oil Terminal, Houston Ship Channel” by Roy Luck, CC BY 2.0 via Flickr)

Since many ships travel between countries, there’s no single climate decarbonization rulebook for the industry. This makes shipping one of the hardest sectors to decarbonize – and if it keeps running on fossil fuels, shipping will become one of the largest global sources of GHG emissions within this century.

This isn’t just about greenhouse gases though; it’s a public health issue too. A recent global study of 5,000 ports found that port cities face significantly worse air pollution, with the biggest culprits being ship exhaust fumes packed with sulfur dioxide, nitrogen oxides, and fine particulate matter that damage the lungs and heart. In some Mediterranean cities, ships contribute up to 60% of local air pollution near the waterfront. Residents living near busy ports often face higher rates of asthma, heart disease, and other pollution-related health problems. Cleaning up shipping doesn’t just protect the climate, it protects communities.

The industry doesn’t have time to wait for a miracle fuel or for major policy/regulatory changes to lead the way – but those aren’t necessary preconditions anyway, because solutions exist right now. Several low-carbon fuels are already available, and shipping companies are starting to deploy them.

Fuel Options

Not all cleaner fuels are created equal. Some are ready now, while others are still too expensive or remain hard to scale. And electrification of long-distance ships is not feasible given the total lack of charging stations as well as the massive power load and gargantuan batteries that would be required. So here’s a quick breakdown of fuel options that work today and which are on the horizon:

Working Today (Biofuels)

• BioLNG: Liquefied renewable natural gas (RNG) produced from organic waste feedstocks such as manure, food waste, wastewater, and landfill gas. This option has the greatest lifecycle GHG emissions reductions. CMA-CGM Group has just made a major commitment to sourcing more bioLNG (see below).

• Biodiesel & Renewable Diesel (RD): Ideally made from waste oils and fats, as well as commodity food crops (primarily soy). These can work with existing ship engines and infrastructure. Companies like Royal Caribbean and Maersk have already run successful voyages on biodiesel and RD.

• Biomethanol: Produced primarily from agricultural and forestry waste. Maersk and a few other major shippers are starting to use and order biomethanol-fueled vessels to cut emissions now.

Coming Soon (But Not Yet Commercial Options)

• Green Ammonia & Hydrogen: These are close to or net-zero options, but they’re expensive, hard to store, and require new engines and infrastructure adjustments.

• E-fuels (like e-methanol): Made from renewable electricity and captured CO2. These are promising but still pricey and limited in supply.

The key point? Biofuels offer the biggest emissions cuts right now without needing to rebuild the world’s shipping fleet from scratch. This safe, cost-effective option could make a sizable dent in petroleum dependence while achieving deep emission reductions as other technologies continue to scale.

But Who Pays?

Here’s the tough part: clean shipping fuels generally cost more to produce and lack the same kind of logistics infrastructure developed over the past century-plus for petroleum-based fuels; sometimes they cost even twice as much or more than fossil fuels. This is drastically slowing down adoption as ship owners are not eager to pay a green premium for lower carbon fuels. So the question becomes: who is in the best position to pay the premium, and how much can those incremental costs come down over time as non-petroleum alternatives scale up?

Let’s say a cleaner fuel adds $250 to the bottom line per container (called a TEU; twenty-foot equivalent unit), based on recent calculations by Energy Vision on the cost premium for BioLNG. While the total cost premium equates to millions of dollars per year per ship, that incremental cost comes out to just 10 cents more per pair of shoes, assuming each container holds 2,500 shoeboxes. For a major brand, that’s pennies or a fraction of a percentage point on a $100 product for major emission cuts implementable now.

Some companies are already stepping up to take the lead in their decarbonization efforts:

• Nestlé now ships all its ocean freight through Maersk’s ECO Delivery program using certified biofuels.

• Amazon, Patagonia, and Tchibo are pooling their demand through the Zero Emission Maritime Buyers Alliance (ZEMBA) to prepay for clean fuels like biomethane (also known as renewable natural gas or RNG) and e-methanol.

• Just this week, CMA-CGM Group (the 3^rd largest container shipping company in the world) and Vanguard Renewables (a US-based developer of anaerobic digester projects) announced a new strategic partnership in which CMA CGM will make a minority investment in Vanguard and get more direct access to RNG as a means to decarbonize existing and future liquefied natural gas (LNG)-powered vessels.

(Photo source: Maersk Line, CC BY-SA 2.0 via Wikimedia Commons)

Policy Is Catching Up

Creative business models only go so far without policy support. Fortunately, momentum is building. In 2024, shipping was added to the EU Emissions Trading System (EU ETS). That means ships now pay for their CO2 pollution in European waters, up to $100 or more per ton. In October 2025, the International Maritime Organization (IMO) will vote on a global carbon pricing mechanism that could reshape incentives across the industry. While the U.S. Department of Energy launched a decarbonization plan in December 2024 for clean shipping fuels like RNG and methanol, its fate is uncertain. The Trump administration has revoked funding for at least one project to use captured industrial CO2 to create e-methanol for shipping. California, however, is testing its own maritime fuel standards, which could have an outsized impact given the state’s key location for international shipping routes.

What You Can Do

The ships that transport our goods can also move us toward a cleaner future. You don’t have to run a cargo fleet to care about this. Almost every purchase we make and every package that lands at our door, is carried by the global shipping network. We can support brands that use low emission shipping and policies that advance the use of cleaner fuels. We can also push for transparency around shipping emissions from major corporations.

Cleaner shipping is here. It just needs more hands on deck.

Energy Vision is finalizing a new white paper on the maritime sector. This post pulls from some of those key findings. Stay tuned for more on this topic.

Energy Vision’s latest report, Leading with Landfills, shows that landfills can play a much larger and important role in achieving significant methane reductions by adopting proven, commercially available technology – and that there’s a compelling business case for doing so. According to the international scientific community, cutting methane NOW – a very potent greenhouse – is the strongest tool available to slow warming in the coming decades. Cutting global methane emissions 30% by 2030 (30x30) remains a critically important target and priority in the race to stave off the most severe impacts of a warming planet.

Key Findings

Landfills are the third-largest source of U.S. methane emissions, more than half of which comes from decomposing food waste. Many landfill gas capture systems are inefficient, with large gaps in coverage: they typically don’t include “working faces”, where decomposing food waste releases methane in the first few years – before gas capture systems are installed. And some high-emitting landfills have no gas capture systems at all due to the nature of regulation(s).

We focused on the top three most impactful strategies for capturing more landfill methane and putting it to beneficial use, which is a far better environmental outcome than allowing it to escape into the atmosphere and warm the planet:

1. “Real-time tech” – improve the efficiency of existing landfill gas collection systems through the use of hardware and software that enables real-time monitoring and automated wellhead tuning technology.

2. “Early action” – install gas collection systems much earlier at landfill working faces (in time to capture the methane-rich biogas from decomposing food waste).

3. “New gas capture systems” – build gas collection systems at high-emitting landfills that lack them and which are not required to install them under current lax regulations.

Horizontal gas collectors deployed at a landfill working face as exemplified in the “early action” option. Photo Source: LoCI Controls

Energy Vision refers to these three options as “advanced landfill tech.” We found that if the nearly 900 feasible candidate landfills adopted advanced landfill tech, that would halve total emissions from municipal solid waste (MSW) landfills and cut total U.S. methane emissions by 7.2% (49.4 million metric tons of CO2 equivalent) relative to the 2023 level. And it would be extremely cost-effective. With estimated capex of just $1.3 billion and opex of $250 million annually, and based on the advanced landfill tech equipment having an 8-year lifespan, the cost comes out to approximately $8.35 per metric ton of CO2 equivalent (MT CO2e) abated – far lower than many other GHG reduction strategies (see chart below).

Advanced Landfill Tech Has Lower Annual Cost Per Metric Ton of CO2 Equivalent Abated Than Other Notable Climate Strategies

Source: Energy Vision, Leading with Landfills (more details on chart sources available in report).

Including the “stretch goal” of installing gas capture systems at another roughly 140 landfills that aren’t as economically attractive under current market conditions would deepen the cuts to 59% of MSW landfill emissions and 8.6% of total US methane (59.2 MT CO2e). The estimated cost would be just $9.58 per MT of CO2e abated – still incredibly cost-effective relative to other greenhouse gas reduction options.

Energy Vision also calculated that if all food waste were ultimately diverted from landfills, implementing the real-time tech option and new gas capture systems options would still cut 4.1% from total U.S. methane in 2023. This underscores that these advanced landfill tech options are worth implementing even as efforts to redistribute and divert food waste gradually gain momentum. There is no conflict between these priorities; both should be pursued.

There are also many secondary methane mitigation measures worth pursuing at landfills, including incorporating remote/aerial monitoring of leaks, adopting best practices in cover, and decreasing the spacing between wellheads. In addition, there is almost entirely untapped potential at some industrial landfills, which face no regulatory requirements to install GCCS yet collectively emit almost one fifth of the emissions that MSW landfills do.

The report notes that the international goal of cutting methane emissions at least 30% by 2030 (“30x30”) to avoid runaway climate change is still within reach, with advanced landfill tech playing an important role (alongside a buildout of anaerobic digesters, plugging leaky oil and gas wells, and various other measures). Options to accelerate implementation of advanced landfill tech include tighter regulations; direct subsidies; and expanding incentives for beneficial use of gas – to produce renewable natural gas (RNG) or generate electricity – at landfills implementing best practices for gas capture.

“As this important Energy Vision study makes clear, improving landfill gas collection is one of the most cost-effective opportunities to slow near-term warming, while boosting domestic energy production, improving air quality, and protecting public health.”

Tom Frankiewicz, Principal, RMI Climate-Aligned Industries Program

The business case for adopting advanced landfill tech is very compelling. If virtually all the additional captured gas is converted to RNG and sold as fuel, as the current market incentives strongly favor, then landfills adopting this tech could produce 93 million MMBTU of RNG each year. That would be a roughly 70% increase from the current total national supply (around 135 million MMBTU as of end-2024). Operators producing RNG could recoup their initial investment within one year of advanced landfill tech equipment coming online; afterwards, this additional RNG would cumulatively generate gross revenue of $1.86 billion per year. (The calculations in the report are based on the direct costs of all the advanced landfill tech feasible today and the additional revenue from the incremental gas capture; they exclude capex or opex associated with RNG plant installation.)

The bottom line: adopting advanced landfill tech to address a large source of current U.S. methane emissions would be a major, quick win at a very low cost relative to many other climate solutions.

Photo Source: American Gas Foundation, Renewable Natural Gas Supply Assessment 2025

The AGF report, prepared by consultancy ICF, updates the previous assessment from 2019 with improved data and more potential production pathways of RNG, among other revisions. There is a tremendous amount of information in the report, and we are not attempting to summarize all the findings here. Rather, this Substack post focuses on one key component: the total RNG potential from their most ambitious scenario for utilizing the existing feasible feedstocks of livestock manure, food waste, wastewater, and landfill gas. We also briefly touch on the rest of that scenario based on technology that’s still under commercial development, as well as overall projected costs.

The report analyzes three scenarios of RNG production: Low, High, and Ambitious. The Ambitious scenario assumes very high utilization rates of the four existing feedstocks listed above via anaerobic digestion (AD):

• 75% of technically available manure would be used for RNG production.

• 70% of the food waste available (at a biomass price of $500/dry ton) would be diverted to anaerobic digestion for RNG production.

• 95% of eligible landfill gas projects would produce RNG (assuming landfills with more than 1 million tons of waste in place).

• 95% of wastewater plants with a capacity of at least 3.5 million gallons per day would produce RNG.

While this is not the absolute maximum feasible RNG potential from AD feedstocks, we consider it to be ambitious yet defensible, especially as it’s thoroughly calculated with the most recent available data.

According to the calculations in the Ambitious scenario, the total RNG potential by 2050 of these four AD feedstocks is 1,998.3 tBtu/year (or nearly 2 billion MMBTU/year). That’s about 15 times as much as total US RNG production in 2024 (~135.5 million MMBTU). Using the standard conversion factor of 1 MMBTU = 7.2 Diesel Gallon Equivalents (DGEs), if all that RNG were used as transportation fuel, it would amount to approximately 14.4 billion DGEs.

And as Energy Vision noted in our March 2025 report, A Path to a Healthier America: Ditching Old Diesel Trucks, “Of the 61.3 billion gallons of diesel consumed in the U.S. in 2022, 46.5 billion gallons (76%) were in transportation, and the overwhelming majority of that (almost 93%) was used by medium- and heavy-duty vehicles.”

So, based on the calculations above, the 14.4 billion DGEs could displace 31% of the 46.5 billion gallons of diesel currently used in the US transportation sector. In other words, maximum feasible RNG production from existing feedstocks could displace almost a third of all on-road diesel consumed in the US. That’s a big deal, and it is slightly higher than our past calculations that maximum feasible RNG production could displace about a quarter of all on-road diesel. Alternatively, the nearly 2 billion MMBTU/year of RNG that could be made from existing AD feedstocks would be close to 12% of existing US natural gas demand (roughly 17 billion MMBTU/year, averaged from 2015-2024).

The RNG Supply Assessment 2025 report also includes projections for RNG production from two pathways that are still under commercial development: thermal gasification, and, to a far lesser extent, methanated hydrogen. ICF does not project thermal gasification (of energy crops, ag residues, forest residues, and municipal solid waste) to make a significant difference until 2035, but from 2040 onwards in all scenarios they project it to grow to more than double the total of RNG from the four AD feedstocks noted above (manure, food waste, wastewater, and landfill gas).

For reference, in the Ambitious scenario, the four AD feedstocks produce 1,998.3 tBtu/year of RNG, and the thermal gasification feedstocks produce 2.5 times as much: 5,062.6 tBtu/year, making the projected grand total 7,060.9 tBtu/year, or 7 billion MMBTU (see chart below). (This assumes utilization rates of thermal gasification feedstocks at 25-70% of the available biomass at higher prices.)

Source: American Gas Foundation, Renewable Natural Gas Supply Assessment 2025

We take such lofty claims for commercially unproven technology with a large grain of salt. However, for argument’s sake, if that 7,060.9 tBtu/year were all to be converted to RNG, it would amount to about 50.8 billion DGEs – more than enough to displace all 46.5 billion gallons of diesel currently used in the transportation sector.

On a final note, aside from the feasible potential, cost is the critical consideration in terms of whether or not this RNG will actually be produced. The chart below shows the RNG supply cost curves for the report’s Low, High, and Ambitious scenarios (factoring in all pathways, including AD and thermal gasification). In all scenarios, the majority of the RNG production potential could be achieved at relatively modest costs per MMBTU. The report notes, “ICF estimates that 75% of the RNG production potential in the Low Scenario and High Scenario could be produced at an average cost less than $20/MMBtu and at a weighted average cost of $23/MMBtu in the Ambitious Emissions Reduction Scenario.” These are encouraging projections.

Source: American Gas Foundation, Renewable Natural Gas Supply Assessment 2025

The bottom line: current RNG production could feasibly increase many times over at a reasonable cost. We will dig into the market demand side of the equation, which is equally important, in future posts. For now, check out the full AGF report for more on projected emissions reductions, technological developments, and analyses of other factors.

As seen in the figure below, renewables play a central role in Brazil’s energy security strategy. Renewable sources made up approximately 50% of Brazil’s total energy/fuel supply in 2023, 32.9% of which was from biofuels and waste, 11.8% was from hydro, and 5.6% was from solar, wind, and other renewables. For reference, in the United States in 2023, about 19.3% of total energy was supplied by renewables, and biofuels made up just 5.25%.

Source: International Energy Agency. License: CC BY 4.0

Brazil’s Fuel of the Future Program, or “Programa Combustível do Futuro”, was implemented in October 2024 with the primary objective to decarbonize the transportation and energy sectors through low-carbon and low-emission fuels. The program will increase renewable energy/fuel production and consumption, including through specific incentives for biofuel production, facilitated through the National Program for Decarbonization of Natural Gas Producers and Importers and Biomethane Incentives. This initiative encourages the production and use of domestic biofuels, the manufacture and use of biomethane-powered vehicles, and helps to foster Brazilian infrastructure development.

Renewable natural gas (RNG), also called “biomethane,” is made from organic materials such as food scraps and agricultural wastes, capturing the methane that would otherwise leak into the atmosphere and utilizing it to create energy. In a double win, RNG also displaces traditional fossil fuels. On a lifecycle basis, RNG can be even better than carbon-neutral, capturing more greenhouse gases (GHGs) in its production than it emits when combusted.

The Fuel of the Future Program incentivizes the use of RNG through emissions reduction goals for the transportation sector. Set by the National Energy Policy Council (CNPE), the first objective is a 1% reduction by 2026, with an eventual target of 10% by 2036. To achieve this, Brazil has developed a market-based program in which credits (Certificates of Guarantee of Origin of Biomethane; CGOBs) are granted to RNG producers and traded between downstream users to meet emissions reduction targets. CGOBs are validated by Brazil’s National Petroleum Agency (ANP) to ensure all emissions are legitimate, traceable, and accounted for in time to meet their 2036 goal.

The RenovaBio program, which launched in 2020 and helped to lay the foundation for Fuel of the Future, has a similar concept: it establishes national decarbonization targets and issues credits for each ton of carbon dioxide equivalent avoided. Decarbonization credits are issued by biofuel producers and exporters based on their emissions reduction efforts. In turn, these credits are purchased by fuel distributors looking to offset their own emissions and meet decarbonization quotas. Together with Fuel of the Future, these programs create a system that targets both fossil natural gas and RNG producers to ensure significant reductions in emissions.

Aside from the transportation sector, the main end users of RNG in Brazil are industrial and corporate customers. The Brazilian steel company Ternium, for instance, is partnering with biomethane producer Gás Verde to use landfill-derived RNG in their production process. Long-term contracts like this one, between RNG producers, the transportation sector, and industrial customers, are key connections to further decarbonization efforts.

Despite these positive developments and recent progress, the Brazilian RNG industry is still young with 6 ANP-certified biomethane plants with the capacity to produce and sell around 5.37 million MMBtu/year of biomethane. With 10 additional biomethane plants scheduled to finish construction this year, Brazil’s capacity for RNG production will increase to approximately 15.46 million MMBtu/year in the next two years, almost triple the original production capacity. As high prices are already deterring potential customers from purchasing RNG, a broader customer base is needed to support this new market. Securing more long-term contracts and gathering additional corporate fleets to make the switch to RNG will be crucial to support this expansion of RNG production.

While there is still a long way to go in terms of emissions reductions and scaling up RNG, more policies like RenovaBio and Fuel of the Future will be necessary to support the transition to clean energy strategies. Even with 50% of its energy supply coming from renewables and its commitment of net-zero emissions by 2050, Brazil is still the highest-emitting country in Latin America. Nonetheless, these developments set an important precedent. Brazil has the chance, later this year, to lead the global discussion on biofuel production and emissions reductions in the transportation sector.

COP30, the annual United Nations Climate Change Conference, will be held this November in Belém, Brazil, and we are expecting biofuels to be a major topic of discussion. Back in 2023, the countries closed Dubai’s COP28, making a historic call to “transition away from fossil fuels” and, for the first time, formally recognizing that coal, oil, and gas are detrimental to our planet’s ecosystem. Early indications show Brazil will push for a COP30 commitment to increase sustainable fuel production by a certain percentage by 2035, alongside other pledges toward decarbonization in the transportation sector, such as targets for finances, innovation, and energy security. Goals to triple renewables, double energy efficiency, and increase development of and access to climate technology are also on the table. Additionally, Brazil will push for the harmonization of carbon markets and carbon accounting systems to hold polluters accountable for their role in the transition away from fossil fuels. This fall, following Brazil’s lead in biofuel production and usage to displace fossil fuels will be one of the strongest levers we have to accelerate actionable, climate-smart strategies and technologies.

This GHG Inventory is probably the last one to be published for the remainder of the Trump administration, so it’s worth gleaning the most recent key takeaways before the screen goes temporarily dark. The headline figure is that U.S. net GHG emissions decreased by 3.3% from 2022 to 2023 (see chart below), largely due to a decrease in coal consumption for electricity generation.

Chart Source: US EPA, 2025 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2023

Energy Vision is particularly focused on cost-effective ways to cut emissions of methane, an extremely potent GHG. International scientists concluded in 2021 that the world must cut methane emissions 30% by 2030 (a goal known as “30x30”) from 2020 levels to forestall runaway climate change. According to the latest GHG Inventory, U.S. methane emissions decreased by 2% from 2022 to 2023, but the picture is more nuanced.

Overall, U.S. methane emissions declined by 10.1 million metric tons of carbon dioxide equivalent (MMT CO2e).

• The largest source of methane emissions, enteric fermentation (i.e., cow belches) dropped by 2.8%, or 5.5 MMT CO2e, driven by a recent decrease in beef cattle populations.

Photo source: US Department of Agriculture

• Emissions from the second-largest source, natural gas systems, decreased by 6% or 10.4 MMT CO2e, as part of a longer-term drop in methane emissions from natural gas distribution, transmission, storage, and processing.

These are both positive developments.

However, all the other sources of methane emissions rose by small margins from 2022 to 2023. Ranked from largest to smallest sources, these included:

• Landfills (up 0.7% or 0.8 MMT CO2e);

Chart Source: US EPA, 2025 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2023

• Manure management (up 0.6% or 0.4 MMT CO2e);

Chart Source: US EPA, 2025 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2023

• Coal mining (up 4.1% or 1.8 MMT CO2e);

• Petroleum systems (up 4.7% or 1.7 MMT CO2e);

• Wastewater treatment (up 1% or 0.2 MMT CO2e);

• Rice cultivation (up 3.9% or 0.7 MMT CO2e); and

• Stationary combustion (up 1.1% or 0.1 MMT CO2e).

• The handful of remaining smaller sources of methane emissions were unchanged from 2022.

These increases are small, and some may only be slight annual fluctuations rather than sustained new upward trends. But regardless, they are troubling. To reach 30x30, these categories need to be trending downward, not plateauing or increasing.

Overall, based on the 2020 methane level (730.9 MMT CO2e), the 2023 methane level was 6% lower (686.7 MMT CO2e). In other words, methane still needs to be cut by 24 percentage points, or another 175.4 MMT CO2e over the next five years. This is a very tall order that only grows harder over time, since many cost-effective options take some time (months to years) to implement, including design, permitting, securing financing, and actual construction.

Perhaps not so surprisingly, the U.S. is currently not on track for reaching 30x30. Bold action is needed, yet it will only happen if the solutions are economically viable. Energy Vision’s May 2024 report, Meeting the Methane Challenge, crunched the numbers and provided the first concrete roadmap for how the U.S. could feasibly reach 30x30, via options using proven, existing technology. These options included a mass buildout of anaerobic digesters to process food waste and manure, capturing the methane-rich biogas emitted as they decompose and upgrading it to renewable natural gas (RNG) or combusting it to generate electricity. We also examined methane mitigation options in the oil and gas sector such as plugging leaky wells and upgrading equipment.

Energy Vision’s next report will analyze the potential of installing advanced landfill technology at all feasible sites in the U.S. Sneak peek: there is huge nationwide potential in this arena and it is extremely cost-effective. These options, using proven technology and techniques, are also implementable soon, in time to make real progress toward 30x30. Stay tuned for the new report, which should be released in the next month!

The bottom line is that the U.S. needs to make significant progress in cutting methane from multiple sectors, and there are multiple proven, cost-effective options that should all be pursued simultaneously. Despite the void at the federal level, city, state, regional and corporate efforts can sustain and even accelerate progress.

With no new EPA GHG Inventories coming for at least the next few years, we may not know how much overall progress we’re making toward 30x30. But that’s no excuse for inaction. We know the problem and we are pinpointing a growing suite of solutions that can cost-effectively move the needle and keep the 30x30 goal within reach.