Methane intensity — the amount of methane waste generated when oil and gas are produced, processed, and transported — is a critical consideration in a growing number of applications. Corporate target setting and reporting, financial sector investment guidance, insurance underwriting, and policy implementation all need to factor oil and gas methane intensity into their decision making.

Methane intensity can be calculated in numerous ways, however. Without adherence to rigorous approaches, practicality, and harmonization of methodologies, there is a risk that methane intensity metrics will be meaningless or misapplied, and the data generated will not provide a credible indication of an entity’s methane performance. This article analyzes two leading methodologies for calculating methane intensity and highlights how they work together.

Parsing oil and gas

There is no standard oil or gas. Petroleum resources — and their resulting emissions intensities— are highly variable, defined by their disparate physical and chemical makeups, diverse corporate practices, inconsistent regulatory oversight, dynamic economic prospects, and powerful geopolitical factors.

Oil and gas co-exist underground together and are normally produced together. As such, it’s rare for gas to be extracted alone. Even “dry” gas stores can consist of liquid hydrocarbons that make plastics, liquid petroleum gas for cooking, petrol, and jet fuel. On average, one-half of the petroleum industry’s emissions footprint comes from methane. However, equivalent barrels of oil and gas emit varying amounts of methane that vary by over an order of magnitude, as plotted below. Further differentiation finds that assets that primarily produce gas (leftmost bars) as well as those assets that primarily produce oil along with associated gas (rightmost bars) have a significant share of their emissions intensity from methane waste. As such, future policies must attend to venting, fugitives, and flaring along both the oil and gas supply chain to be effective.

Establishing two different methane metrics

Assessing how much gas ends up in the atmosphere and not in the market is a valuable way to track methane emissions and prevent waste. This metric — the gas loss rate — is calculated as the share of gas emitted compared to gas sold (or gas throughput). When the methane content of the gas is known, this can be expressed as a percentage of methane loss rate.

Knowing the methane content level is important because, while gas composition is often assumed to be about 90 percent methane, the share of methane in gas can vary widely from less than 70 percent to over 90 percent.

Methane content is influenced by the location of a methane release in a system: The closer the discharge is to the wellhead, the lower the methane content because gas contains variable amounts of non-methane hydrocarbons and other impurities when it is extracted. The closer the gas leak is to distribution and end use, the higher the methane content because heavier hydrocarbons and impurities have been removed.

A second essential methane intensity metric — volumetric methane intensity — considers the methane emitted based on combined oil and gas throughout certain system boundaries. The methane intensity is calculated as the mass (kilograms) of methane per barrel oil equivalent (boe oil and gas) throughput.

Taken together, these two metrics provide additional information on material differences between comparative methane waste from oil and gas systems operations. The most methane intensive activity is high on both metrics, and the least methane intensive is low on both.

However, when one metric is high and the other is low, these findings trigger increased analysis to offer a complete picture of methane emissions in this diverse and complex sector.
The graph below plots gas loss rate versus the volumetric methane intensity for nearly three-quarters of the world’s oil and gas assets that are currently modeled through RMI’s Oil Climate Index plus Gas (OCI+). This analysis finds that those resources designated as “gas” (which includes dry, wet, and sour gas) have fundamentally different methane intensity profiles than those resources designated as “oil” (which includes condensates, ultra-light, light, medium, heavy, and extra-heavy oils).

While there is a close relationship between these different intensity metrics for gas assets, there is no relationship between these independent metrics for assets that are primarily oil. Additionally, for predominantly oil assets with little to no gas, a gas loss rate does not return a reasonable value and is not applicable. Therefore, a comprehensive look at oil and gas methane intensities requires the use of both metrics — gas loss rate and volumetric methane intensity — to fairly assess complex petroleum systems worldwide. This is especially critical for successful implementation to cut down on methane waste sector wide.

It is important to note that there are yet other metrics, in addition to methane intensity, that are needed to prevent energy waste. For example, operators should strive to flare less of their gas and keep their flares maintained at high efficiency when they must burn off unwanted gas. These are each evaluated in the OCI+ mitigation scenarios.

Differentiating countries’ methane intensities

Oil and gas producing countries have highly variable average methane intensities. Moreover, the range in methane intensities within a country is also wide ranging. Countries like Norway, for example, have both very low average methane intensity and a small range between their different oil and gas assets. Other countries, like Algeria and Russia, for example, have both high average methane intensities and a large range between their different oil and gas assets, as plotted below.

The economic value of methane policy

Historically, gas was viewed as an unwanted waste byproduct that was extracted along with oil. It was systematically flared and vented to maximize production of liquids. Today, gas is a highly traded global commodity with significant economic value.
The high price of gas in Europe and Asia — roughly five times greater than in the United States — should be sufficient to warrant significant capture to minimize waste and maximize its market return. The International Energy Agency finds that at least 50 percent and as much as two-thirds or more of wasted gas is cost-effective to capture, depending largely on the price of gas.

But energy markets are dynamic, and gas prices vary over time and place. Operators’ vigilance also varies widely. Capital investments can be sluggish. Upsets happen. As a result, progress toward abating methane waste and gas loss has been too slow — but targeted demand-side policy can help unlock the investments and operational changes needed to accelerate reductions and modernize the oil and gas industry.

Next steps for establishing methane intensity metrics

Directives are loud and clear. Whether it’s Oil and Gas Decarbonization Charter (OGDC) targets, methane abatement financial metrics, or EU methane regulations, methane intensity is a critical market and policy benchmark. Insurance companies are already using methane intensity as an underwriting guideline to gauge system safety. And other financial actors like banks and investors are following suit.

There is a growing need for more transparency and harmonization across methane intensity methodologies. This starts with clearcut metrics. Inputs need to be discoverable to be actionable. The two indicators presented — gas loss rate and volumetric methane intensity — are integral across use cases.

Spurring reductions in methane from oil and gas requires a combination of policy push and market pull. These dynamics shine a spotlight on the importance of durably designing and implementing a robust and comprehensive set of metrics that can accurately track the methane intensity of oil and gas through the supply chain.

If major gas and oil buyers in Europe and Asia adopt policies to prevent gas waste — and US states like California, Michigan, and New York, for example, follow suit — entities supplying oil and gas will start to produce commodities with low methane leakage. Together, these actors can cut energy waste, bolster national security, create jobs, protect public safety, and prevent super-heating the planet.

The post Establishing Measures to Achieve Near-Zero Methane Waste from Global Oil and Gas Assets appeared first on RMI.

Why now is different

The passage of the One Big Beautiful Bill Act was a significant moment for nearly every energy technology in the United States, but holds particular promise for carbon management — an emerging industry that creates value from the carbon dioxide produced from industrial activity, either by capturing and reusing it or by storing it. This can take the form of point-source carbon capture from industrial waste streams, direct air capture (DAC), pipelines to transport the carbon dioxide for various end uses, and using geological formations to store the carbon.

One of the critical policies for carbon management is the 45Q carbon oxide sequestration tax credit. Before July 2025, the tax credit was calculated based on the specific features of the project. Under that formulation of the credit, outlined in the Inflation Reduction Act, direct air capture projects qualified for more credit than point-source capture, and projects that stored the captured carbon in permanent storage qualified for more credit than those that sold or used the carbon for further industrial processes. However, the OBBBA modified the credit by raising the value of projects that utilize or sell carbon to equal that of projects that sequester carbon, for both point-source capture facilities and DAC facilities.

Exhibit 1

These changes will have a significant impact on the carbon management industry, closing the cost gap for more types of projects and presenting highly significant financial and job creation opportunities in states that pursue projects and infrastructure supportive of a carbon management economy.

Texas is poised to lead this growing industry

The increased value in 45Q presents a prime opportunity for Texas’s industrial clusters to source carbon at scale and unlock its considerable economic potential. Major industrial activities in Houston, San Antonio, Austin, Dallas-Fort Worth, Corpus Christi, and East Texas represent both sides of the supply and demand equation for carbon management processes, creating the potential for a homegrown industry.

Existing cement, refining, petrochemical, and plastic facilities offer both abundant carbon dioxide streams as well as strong demand for the captured carbon in order to produce urea, synthetic fuels, and other materials. The state offers a large carbon dioxide pool as industry produces over 367 million metric tons (Mt) of CO₂ annually statewide, including power generation. Furthermore, the existing 2,325 miles of CO₂ pipeline infrastructure, accounting for over 40% of the entire CO₂ pipeline infrastructure in the US,  can provide the needed infrastructure support to move the carbon where it is needed.

Beyond capturing and utilizing carbon, Texas’s subsurface geography provides unmatched long-term carbon storage capacity. The Department of Energy has estimated that Texas possesses over 1.6 billion Mt in potential storage capacity — equivalent to 4,000 years of today’s carbon output in the state. Texas offers an extensive carbon storage basin through depleted oil and gas reservoirs, and deep saline aquifer formations, which allow for proven containment with reduced costs and technical risks.

This storage capacity can be monetized. Companies that sequester the carbon dioxide underground are eligible to receive the federal 45Q tax credits, while an additional revenue stream can be created through the sale of carbon credits in voluntary carbon markets. Momentum is also building on the regulatory front: the EPA proposed approval of Texas’s Class VI underground injection well primacy application in June 2025. This represents one of the critical steps that will allow the state to streamline permitting for storage and accelerate carbon management.

Given this profile, over $10 billion in investments in carbon management are already flowing into Texas. Occidental Petroleum is investing $500 million to build the world’s largest DAC project in the Permian Basin, with the potential to capture 500,000 metric tons of carbon dioxide from the atmosphere. ExxonMobil’s acquisition of the 1,300-mile CO₂ Denbury pipeline for $1.9 billion is also a critical infrastructure investment to facilitate carbon transportation in the Gulf. In Baytown, ExxonMobil is developing a $7 billion blue hydrogen facility (hydrogen produced via natural gas with carbon capture), the largest of its type in the world, to fuel its olefins plant and capture over 7 Mt of carbon annually. These projects demonstrate the scale and tangibility of Texas’s carbon management opportunity.

Exhibit 2

Exhibit 3

Texas stands to benefit immensely from the near-term opportunity to capture federal dollars from tax credits and generate economic growth. RMI analysis estimates that by 2050, Texas could see between $12 billion and $94 billion in investments in carbon management, and a cumulative economic benefit of $24 billion to $182 billion. (See Exhibit 4)

But carbon management’s benefits extend beyond the bottom line and reach into the wider Texas economy. Addressing carbon management proactively will retain Texas’s national and global status as an energy leader, with all the economic benefits that it brings. It also provides Texas with a low-risk, high-reward response to commercial opportunities from the global shift toward low-carbon energy.

The scaling of the carbon management industry can also support the creation of new jobs in engineering, construction of pipelines and carbon capture hubs, operations for hydrogen, carbon capture, and storage facilities, and advanced manufacturing for newer technologies like DAC and carbon utilization technologies. The world-class Texas oil and gas workforce is perfectly suited to transition into these new roles.

Depending on the uptake of carbon management in Texas, RMI analysis anticipates a cumulative creation of 21,000 to 211,000 new jobs through 2050 (See Exhibit 4).

Exhibit 4

Preparing for, rather than reacting to, the growing carbon management industry is the smartest way for Texas to seize this opportunity

The energy landscape is changing, new technology is emerging, and new policy frameworks are coming. Texas is a leader in the carbon economy today, and it should act now to ensure that it remains a leader in the new carbon economy of tomorrow.

The incentives through OBBBA will further help the economic case for projects that include carbon management technologies, and with its century of expertise in petroleum engineering and geology, and some of the highest-potential injection sites in the country, Texas has the foundation to define the future of carbon management in the United States. This opportunity is Texas’s to seize, and proactive policymakers and economic development organizations should start to get ready.

The post Capturing the $100 Billion Carbon Management Opportunity in Texas appeared first on RMI.

Updates in 2025 Q3

In the third quarter of 2025, utilities that updated their IRPs increased projected load through 2035 by 2.1 percent and emissions by 5.5 percent.

This continues a few trends that we have highlighted in recent quarterly reviews: projected electricity demand is increasing due to new large loads, and many utilities are finding it difficult to meet capacity needs in the near future. Changes to resource adequacy rules, particularly in the Midcontinent Independent System Operator (MISO) region, continued to have an impact, and phase out of renewable tax credits began to appear as an additional reason that many utilities have recently reduced plans to build wind and solar capacity.

New common themes of IRPs this quarter included delayed retirements and uncertainty in planning. Many utilities are experiencing load growth, but don’t have the ability to bring new resources online quickly or rely on purchases from neighboring utilities — available capacity is limited not just for individual utilities, but for broader regions. Consequently, many utilities have pushed back retirement dates for existing fossil plants, expecting this to be the lowest-cost solution to ensure resource adequacy.

Compounding these issues is significant uncertainty in several areas, including load forecasts, resource costs, market rules, environmental protection agency (EPA) regulation, and federal and state policy. Utilities discussed the difficulty of planning with all these sources of uncertainty and change, reflecting that the industry is undergoing an intense period of change and needs to learn new methods to effectively meet the needs of the future grid.

Below, we share detailed analysis of recent changes in IRPs, their underlying causes, and potential opportunities for improvement.

The current state of IRPs

In our current snapshot of IRPs (Exhibit 1), we continue to see a gap between projected emissions, target emissions, and decarbonization pathways such as the International Energy Agency’s Net Zero Emissions by 2050 Scenario (IEA NZE).

Most decarbonization pathways, including the IEA NZE, find that the electricity sector needs to reach net-zero emissions by 2035. Unfortunately, utility company targets often aim for net-zero emissions by 2050 and often do not comprehensively cover emissions from both owned (Scope 1) and purchased (Scope 3) emissions. If all companies in our coverage meet their targets, they will only reduce emissions by 63 percent by 2035, compared to a 2005 baseline. We also find a gap between these targets and projected emissions based on IRPs, which as of 2025 Q3 we project to be reduced by just 53 percent by 2035, compared to a 2005 baseline.

Exhibit 1

Load

As of the end of 2025 Q3, IRPs across the United States anticipate load will grow 24 percent by 2035 compared to 2023 levels (Exhibit 2). This is an increase from prior projections — 12 percent at the end of 2023, 8 percent in August 2022, and 6 percent in January 2021.

Load growth continues to be driven in the short term primarily by large loads such as data centers. This quarter, every utility with a new IRP increased its load forecast compared to previous expectations. Baseline load forecasts included moderate growth, but utilities also consistently reported wide ranges of uncertainty in their forecasts. Santee Cooper’s IRP (Figure 8) is a highlight example, where a range of uncertainty in potential new large loads from 101 to 1,536 MW accounts for a majority of the difference between high and low load cases.

Load changes from residential customers are relatively smoother and more predictable, and recent IRPs expressed more challenges with forecasting large loads and predicting increases in extreme weather events. Best practices for large load forecasting and planning with climate variability are increasingly critical for effective utility decision-making, as both the quantity and hourly profiles of new load are different from past utility experience.

Exhibit 2

Capacity

Current planned capacity in IRPs across the United States (Exhibit 3) includes 259 GW of wind and solar additions, 103 GW of gas additions, and 74 GW of coal retirements between 2023 and 2035.

This reflects 6 GW of additional wind and solar capacity (+1 GW from 2025 Q2), 53 GW of additional gas capacity (+4 GW from 2025 Q2), and 7 GW (+0 GW from 2025 Q2) of additional coal retirements compared to utility plans at the end of 2023.

Utilities that updated IRPs in 2025 Q3 cited several external factors with influence on their capacity plans:

• This is the first quarter in which we observed impact of the phase out of federal renewable tax credits, leading to higher costs and reduced plans to build wind and solar capacity.
• MISO’s shift to seasonal accreditation had varying impacts on utility plans, generally resulting in shifts toward gas capacity as a safe, familiar solution for meeting capacity needs.
• Compliance with EPA regulation of greenhouse gases often led to gas cofiring as an option with minimal risk if the regulation is rescinded.
• Difficulty interconnecting new resources in MISO, with impacts both locally and regionally, made it difficult to rely on power purchases for capacity needs.
• Renewable portfolio standards in New Mexico helped maintain and accelerate El Paso Electric’s plans to build zero-carbon capacity.
• Frequency of extreme weather events increased capacity needs to maintain reliability.

The most notable combined effect of these influences was delayed retirements of existing fossil plants, often with conversion from solid fuels to gas. This method provided risk mitigation amid uncertainty and changes, but exposes utilities to gas price volatility and misses the opportunity to reduce emissions and customer costs with zero-carbon electricity generation.

One highlight in this quarter’s capacity plans is Cleco Power’s use of MISO’s generator replacement process to add 240 MW using existing interconnection rights at the site of the retired Dolet Hills coal plant. This example could be scaled to many more opportunities of clean repowering.

Exhibit 3

Emissions

Our latest projections (Exhibit 4) from IRPs at the end of 2025 Q3 are that carbon emissions will be 53 percent lower than 2005 levels by 2035. This is a smaller reduction than we projected from IRPs in August 2022, when emissions planned in IRPs showed a 57 percent reduction. And it is nearly back to the level we projected at the beginning of 2021 when the figure was 51 percent.

Projected emissions are lower than today’s emissions because utilities do still have plans to retire coal and build zero-carbon capacity. However, projected emissions have consistently increased since the end of 2024 because of increased electricity demand, insufficient zero-carbon capacity additions to meet all of this demand, and increased use of gas generation to fill the remaining gap.

All utilities that updated their IRPs in 2025 Q3 increased their future projected emissions compared to previous plans.

Exhibit 4

Cumulative metrics

When considering climate alignment of the US electricity sector, or individual utilities, RMI’s Engage & Act platform’s key metric is cumulative emissions through 2035. Cumulative emissions, or the total amount of greenhouse gases put into the atmosphere, directly influences climate change, so this metric gives us clear insight into whether we are on track to meet climate goals. We also find value in metrics of cumulative projected load, to know whether the task of reducing emissions is becoming easier or more difficult for utilities, and cumulative projected emissions intensity, to know if consumers are increasing or decreasing emissions associated with their electricity consumption.

Exhibit 5 shows that across all IRPs in the United States, cumulative projected emissions from 2023 to 2035 are 4.9 percent higher, cumulative projected load is 2.2 percent higher, and cumulative projected emissions intensity is 2.7 percent higher now at the end of 2025 Q3 compared to a year ago at the end of 2024 Q3.

Exhibit 5

Exhibit 6 provides an additional view of the direction that IRPs are going, by considering percent change in cumulative projected load and emissions among the set of companies that did update their IRPs each quarter. Utilities that updated IRPs in 2025 Q3 increased load by 2.1 percent, emissions by 5.5 percent, and emissions intensity by 3.3 percent.

In our history of tracking IRPs, load projections have never decreased in a quarter, and 2025 Q3 makes nine consecutive quarters of at least 2.1 percent load growth among utilities with IRP updates. While projected emissions decreased in the early 2020s, 2025 Q3 also marks seven consecutive quarters of at least 3.2 percent increase to projected cumulative emissions among companies with IRP updates.

Exhibit 6

Achieving a climate-aligned future

Electric utilities in the United States face significant, and changing, challenges. They remain focused on providing reliable electricity service to customers while balancing priorities of costs for customers, external requirements of policy and regulations, returns to investors, and climate impact.

Current planning processes struggle to meet these needs. Current utility plans do not reduce emissions fast enough to align with decarbonization targets. Multiple priorities can appear to conflict with each other.

However, some interventions to utility planning have synergistic effects in solving multiple problems simultaneously. Improved forecasting of large loads and planning for climate variability, understanding that reliability and dispatchability are not the same, and updated costs and constraints of available technologies are key. While delayed retirements and more gas additions are the default choice in most current utility plans, there are a range of fast, affordable, flexible alternatives that utilities can use in this period of transition. Improved planning processes, with supporting policy and regulation, would enable utilities to more effectively transition toward a low-cost, zero-carbon future.

Methodology

Historical data in this article comes from the RMI Utility Transition Hub. Projected capacity and total generation (load) is based on data collected manually from IRPs by EQ Research, with RMI corrections, combined with historical data. Generation by technology is calculated with assumed continuation of trends in capacity factor for each company and technology, and is converted to emissions using utility-specific emissions factors by technology.

The post The State of Utility Planning, 2025 Q3 appeared first on RMI.

This is not only a household affordability challenge but also a system-wide one. Utility debt gets collected on the bills of all customers. Essentially, when your neighbor can’t pay for their utility bills, you end up paying it for them. Energy debt also contributes to service instability and deepens cycles of energy poverty. Public utility commissions (PUCs) are charged with ensuring safe and reliable service at just and reasonable rates, and today’s affordability crisis underscores the importance of that responsibility.

Evidence from multiple state programs shows that when commissions adopt affordability policies, they support vulnerable customers, reduce system-wide debt, improve payment behavior, and lower collection costs. Because there are less unpaid utility bills and collection costs that would eventually be recovered on all customer bills, these programs benefit participating customers while also putting downward pressure on the energy bills of all customers.

The promise of arrearage management plans (AMPs)

Arrearage (utility debt) management plans help customers eliminate past-due balances gradually while establishing regular payment habits, which can lead to lasting improvements in bill payment behavior. For participants, these programs create a clear and achievable pathway out of debt, restoring stability and reducing the stress of persistent arrears. A typical AMP might work like this: a customer with $600 of outstanding utility debt makes regular, on-time monthly bill payments, and in return the utility forgives one-twelfth of the arrears (or $50) each month, so that after a year of consistent bill payments the entire balance of debt is eliminated.

At least 10 states currently have active AMP programs. A 2021 evaluation of utility company Pepco’s AMP found that bill coverage rates for participating customers increased by 16 percentage points compared with nonparticipants, reduced average shortfalls by $370, and lowered late charges. Collection actions dropped from 36.7 actions per customer pre-enrollment to just 1.8 afterward — a net reduction of 4.2 compared with nonparticipants. These outcomes reduced customer hardship while also lowering bad debt charges and termination costs.

Percentage-of-income payment plans (PIPPs)

Percentage-of-income payment plans cap bills at a set proportion of household income, ensuring that customers are not charged more than they can reasonably afford and preventing arrears from accumulating. For participating households, this means predictable bills that fit within their monthly budgets, reducing the likelihood of falling behind and facing disconnection.

California’s PIPP pilot demonstrated measurable benefits in its first year: average arrears declined by $131 per household, and the share of participants with no past-due balance grew by 11 percentage points.

Low-income discount rates (LIDRs)

Discount rate programs reduce bills for income-eligible households. While less tailored than PIPPs, they are easier to administer and still provide meaningful relief. For customers, a lower monthly bill creates breathing room to cover other basic expenses while reducing the risk of utility shutoffs.

New York’s Energy Affordability Program has proven highly effective in reducing arrears and lowering the risk of service termination for low-income customers. During the pandemic (2020–June 2022), arrears for EAP participants rose by 50 percent, compared with an 89 percent increase for nonparticipants. According to the Public Utility Law Project, this difference saved the residential customer base an estimated $89 million in arrears relief. Without the program, arrears among participants likely would have grown at the same rate as nonparticipants, requiring an additional $380 million in relief, or $559 million when including carrying costs.

Another example comes from Indiana. A 2007 evaluation of the state’s Universal Service Program found that arrears occurred less often and were lower among those customers on the discount rate. At Citizens Gas, for example, average January arrears were $42 for participants compared with $100 for nonparticipants.

Low-income energy efficiency programs

Energy efficiency programs such as weatherization and appliance replacement lower bills for the lifetime of the efficiency action by reducing energy use. For customers, these investments improve comfort and safety in the home, while also helping to enable more affordable bills over the long term.

An evaluation of Pennsylvania’s Low-Income Usage Reduction Program (LIURP) for the 2021–2022 program year found that average net arrears fell by nearly $99 for PPL participants, $51 for PECO, $39 for Duquesne Light, and $25 statewide. These reductions were accompanied by declines in bad debt write-offs, showing how efficiency investments deliver system-wide benefits in the form of reduced bad debt in addition to the other system-wide and household benefits.

The bottom line: Supporting affordability for all

Programs such as AMPs, PIPPs, discount rates, and efficiency upgrades provide essential support to customers, reduce customers’ utility debt, and protect households from disconnection.

Importantly, these same programs also deliver system-wide benefits. They lower uncollectible balances, reduce costly collection actions, and strengthen overall affordability for all ratepayers. RMI analysis suggests that nearly half of the costs of these programs can be offset by reductions in utility debt alone.

The bottom line is clear: affordability programs protect the most vulnerable customers and reduce costs for all ratepayers. By advancing these policies, commissions can protect customers while ensuring a more stable and affordable energy system for all.

The post How Low-Income Customer Programs Lower Energy Costs for Everyone appeared first on RMI.

In recent years, those efforts led some fleets to focus on saving fuel costs by improving their efficiency. As a result, some fleets have surpassed the nation’s long-standing fleet average of 6 miles per gallon (mpg); some now exceed 9 mpg, or are even approaching 10 mpg. With so many fleets chasing higher efficiency for so long, the average fuel economy for the US fleet has crept up to nearly 7 mpg. These improvements have avoided the combustion of some 40 billion gallons of fuel in the process.

More efficient diesel rigs are just part of the story, though. Other solutions have emerged, many related to the source of energy used to propel trucks and move the goods. The industry is exploring a growing mix of alternatives, including bio- and renewable diesel, compressed and renewable natural gas, battery electric, and hydrogen are all potential sources for fueling medium- and heavy-duty trucks.

These technologies are being showcased in NACFE’s Run on Less – Messy Middle, a real-world demonstration intended to bring clarity to reducing the carbon emissions from long-haul trucking. Although long-haul trucking — which we define as around 500 miles per day, with a growing segment traveling 300 miles out and back for a total of 600 miles per day — makes up only about 9 percent of the entire trucking market, it produces 48 percent of the industry’s emissions.

“Messy Middle” refers to the time until we see a zero-emissions goods movement. In the Messy Middle, fleets are reckoning with a range of powertrain solutions from which to choose, even in the long-haul segment of trucking. The 13 fleets participating in Run on Less — Messy Middle are making investments in alternative-fueled vehicles and are committed to moving trucking into a zero-emissions future. Although more solutions are good, they make decisions more challenging going forward.

Cleaner and greener goods movement

We are seeing early piloting of these alternative fuel sources and real production-level adoption of alternative-fueled vehicles. Each fuel option offers its own results in reducing a variety of pollutants such as nitrous oxides and sooty black particulate matter, along with carbon, all of which are harmful to our health and/or the climate. All of the alternative-fueled options improve sustainability and lead to cleaner and greener goods movement. The options all have vastly different benefits and challenges, too. Some are better for moving goods just around cities, on shorter distance runs, others are ideal for for longer hauls. Some are available today with infrastructure in place to support refueling, while some are more nascent in their development but are catching up quickly.

This brings us to what is really going on with all of these powertrain solutions for fleets. Does the focus of the current administration and other developments bring all this work on the cleaner movement of goods to a stop? It does not. Have companies reversed their commitment to their sustainability goals? They have not. Some continue to invest in these innovations, in part to chase further efficiency gains, and in part to respond to customers’ persistent requests to develop cleaner delivery and supply chain options.

The Run on Less – Messy Middle fleets

The fleets that participated in Run on Less — Messy Middle are making investments in alternative-fueled vehicles and are committed to moving trucking into a zero-emissions future. Below, they explain why they are making this change.

“It’s ingrained in our culture to continuously improve, and we just want to do good,” says Matthew Copot, vice president of fleet management for Saia, a fleet that is deploying Tesla semis to haul freight. Saia is a less-than-truckload trucking company with 7,000 tractors and 30,000 trailers.

“One of our core values is do the right thing. And I think learning how to use alternative fuels personally is the right thing. I think everything we’re doing here is doing the right thing,” says Ryan Madura, senior project manager, Saia.

Brad Bayne, VP of strategic initiatives at Duncan Trucking — a sibling company to 4Gen Logistics, a family-owned business that operates in port drayage — says, “We have customers that have clean emission efforts and things they’re trying to do to reduce their carbon footprint. With EVs we’re probably in the same range of what our diesel fleet would be as far as the actual fuel costs go.” 4Gen has 83 trucks in the fleet, of which 64 are battery electric Volvo VNRs.

The trucking carrier Nevoya is so committed to moving goods in a more sustainable manner that it is the only 100 percent electric fleet operating anywhere in the United States. Nevoya CCO John Verdon sees this time as a “once-in-a-generation opportunity to engage the shipping community on a mode of transportation shift.” Nevoya currently runs 20 Freightliner eCascadias predominantly out of Southern California in a mixture of over-the-road and drayage operations, but also has established a presence in the Northern California and Texas markets.

Arizona-based JoyRide Logistics has 250+ trucks, 850 trailers, and 250 drivers covering multiple states. Adis Danan, president of JoyRide Logistics, says, “I believe it is very important for us to do something about trucking’s impact on the earth. There’s no better way than just running the trucks on battery electric. We’re probably going to have between 500 and 700 trucks. And we’re hoping they’re all going to be electric vehicles.” Today JoyRide operates Windrose electric trucks.

And the other solutions, such as bio and renewable diesel as well as renewable natural gas and hydrogen fuel cell, being showcased in the Run all produce less emissions than traditional normal diesel. Companies such as Albert Transportation, Frito-Lay, Kleysen, Mesilla Valley, Penske, Pilot, Schneider, and UPS are showcasing their decarbonizing efforts with these technologies.

This is just a sampling of the fleets that are making a real commitment to decarbonize the long-haul segment of trucking. And they are bold pioneers willing to share the experiences for the entire industry to learn and advance.

Read more about Run on Less – Messy Middle, which ran through September, to see for yourself how these trucks — which are outfitted with Geotab telematics devices — ran real routes delivering real freight while reducing harmful emissions.

The post Cleaning Up Long-Haul Trucking appeared first on RMI.

Generic industry averages and simple emission factors have historically dominated oil and gas decision-making, obscuring very real differences in emissions. With increasing observations and computational power, that is changing. RMI’s interactive OCI+ tool reveals the differences in life-cycle emissions that are large enough to matter. OCI+ also highlights the potential for significant emissions reductions and energy waste prevention if action is taken.

Spotlight on the oil and gas industry’s responsibility

The oil and gas industry is responsible for significant energy consumption and waste — even before petroleum products are consumed. These wide-ranging differences can be quantified. The inherent differences in resource types (defined by their chemical and physical properties) and how they are processed to make fuels and other commodities drive their energy input and emissions intensity.

For example, heavy oils require enhanced recovery methods like steam flooding; wet gas resources are more prone to methane leaks; and light oils tend to release gas from storage tanks. However, there is a huge range in industry responsibility emissions within each asset class, as plotted below. The current OCI+ launch explores this phenomenon along a few key themes, dissecting the supply chain by responsible actor, analyzing the role super-emitting events play, investigating what drives emissions, and proposing mitigation measures to cut energy waste.

Gas going global

Gas used to be a largely unwanted byproduct of liquids production. Today, it is becoming a highly traded global commodity that is shipped around the globe as liquefied natural gas (LNG). But the longer oil and gas supply chains become, the more energy required for transport, and the greater the risk of gas leakage throughout the system. Efforts are currently underway to measure and mitigate wasted energy that has economic implications. For example, MiQ, an NGO that openly and independently certifies oil and gas emissions, is measuring methane losses through its Supply Chain Protocol so operators and investors can durably reduce their emissions footprints and energy waste.

The surge in announcements of new LNG projects and financing highlights this upward trend in global gas trade. To understand this shift, it is useful to trace the life cycle of gas shown in the graphic below.

Gas’s journey starts at the well head, where it is commonly extracted with assorted hydrocarbons (such as oil) and non-hydrocarbons (water and CO₂). Gas is separated from liquids, water and heavier hydrocarbons are removed, and other impurities are shed. From there, processed gas (which is mostly comprised of methane) may enter pipelines for domestic use, or in the case of LNG, be sent to liquefaction plants. At these plants the gas is further treated and cooled with several stages of refrigeration to sub-zero temperatures. The gas is then loaded onto specialized insulated carriers and transported overseas, where it is either transferred, stored, or re-gasified for injection into a local pipeline system. This process allows natural gas to flow freely, like oil, connecting to consumer and producer natural gas markets.

Differentiating LNG emissions

LNG, like all gas, has wide-ranging industry emissions, which vary by a nearly two-fold difference for equivalent volumes. Moreover, the remaining responsibility falls on different supply chain segments, as shown below. Emissions from natural gas production and transport average 72 percent of industry responsibility emissions and go up to 85 percent for high-emitting assets. Operating practices (like venting gas), complex infrastructure (with numerous equipment leaks), or contaminants in the gas (like native CO₂) can drive these differences.

LNG plants may implement strategies to prevent leaks, but the risk of higher natural gas leakage increases with reduced corporate governance and oversight. Transportation of LNG is also an important factor. With the increasingly arbitraged nature of the LNG trade, shipping distances can be much longer than simple point A-to-point B routes, amplifying the risk of transportation emissions with increased shipping distances by more than two-fold. While LNG operators are looking at strategies to reduce these leaks, including electrification or combined cycle power generation, these measures alone have limited impact unless emissions from both oil and gas production and LNG transportation are addressed. OCI+ highlights the uncertainties of these dynamics and illustrates how different factors differentiate LNG emissions.

Super-emission events highlight the non-routine

With the launch of Carbon Mapper’s Tanager-1 satellite in August 2024, this OCI+ relaunch incorporates satellite-observed super-emissions for the first time. Satellite observations enable a combination of modeled methane estimates with additional detected measurements.

The OCI+ map tab charts estimated “routine” methane plus any additional “non routine” super-emitting observations, underscoring the variability across assets and regions. Tanager-1 can detect emissions above 70 kg/hour, which is often above small fugitive leaks during routine operation. Satellite detection data can show non-routine gas losses from equipment failures (such as a blown thief hatch), maintenance activities (such as facility blowdowns), and operational decisions (such as purposeful venting due to price or offtake sensitivities). Super-emitting events can release more methane in a few hours than routine activities might over weeks or months. The large number of satellite observations shows the additional impact of super-emission events; with just partial global coverage, super-emitters increased oil and gas methane intensity from those observations by over 20 percent in 2024.

Scenarios for emissions reduction

There are numerous avenues for mitigating oil and gas industry emissions and preventing energy loss. The OCI+ scenario tab models strategies that can help companies, investors, and others that set net-zero targets for their oil and gas industry Scope 1 and 2 emissions. Different resources respond to different mitigation approaches for the production, processing, transport, and end-use segments. The scenarios tab, for example, shows potential ways to prevent venting, flaring, and fugitive loss of valuable gas commodities. Other scenarios explore using renewable electricity instead of diesel to run motors, using solar energy for generating steam, reinjecting carbon from acid gas, and replacing hydrogen made from gas with green hydrogen from water. These changes can reduce emissions intensities by about one-third, while also mitigating wasted energy. The full list of scenarios can be explored on the OCI+ website. And the aggregated benefit of absolute emissions reductions is showcased on Climate TRACE.

By showcasing the benefits of emission reduction strategies, OCI+ underscores the critical role of targeted, resource-specific strategies in cutting oil and gas emissions and making the impact of emission reduction implementation more transparent for decision makers.

The case for action

OCI+ was built to differentiate equivalent barrels of oil and gas so that industry, policymakers, investors, and researchers can target waste and reduce emissions. The visibility offered by OCI+ showcases which assets (by resource type and location) are leading on effective management, and which are falling behind. Accounting for waste and emissions by supply chain strengthens accountability and lowers financial, safety, and reputational risks.

As more data becomes available, RMI will continue to update OCI+. This will further rightsize the opportunity for reducing gas loss and mitigating methane. Yet, too much data remains hidden or biased toward US operations, leaving large gaps in the picture. OCI+ was designed to drive transparency, moving from invisible to securable energy delivery.

The OCI+ models and results are open and accessible. RMI invites you to explore results, compare scenarios, and dig deeper into methodologies. The project is also collaborative — if you have expertise, feedback, or underlying data, your contributions are welcome. The future of oil and gas will be shaped not by what remains hidden, but by what is made visible.

This article was informed by the contributions of Sasha Bylsma, Marissa DeLang, Kevin Gauthier, Shannon Hughes, Amanda Sessler, Jake Stagner, Adrienne Tezca, and RMI’s entire Oil and Gas Solutions Initiative team.

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But record-setting turnout defied any low expectations. With nearly 1,000 events and over 100,000 attendees, the scale and substance of the sprawling event told another story. While the shift to clean energy may be facing headwinds in the United States, growth is enduring globally and at home, driven by rising demand for power and the cost advantages of deploying solar, wind, batteries, and other renewable energy solutions.

By many accounts, this CWNYC was the most global to date. With COP30, this year’s UN climate conference, slated to begin in November in Belém, Brazil, many attendees framed this CWNYC as an easier-to-attend alternative. And while Washington has again withdrawn from the global negotiation, other leaders are emerging: “There’s a sense of enthusiasm around other countries — India, Brazil, Mexico, China, and others — moving into a leadership position ahead of COP,” said Jon Creyts, RMI’s chief executive.

On the ground in New York, private sector priorities on energy, data centers, and competitiveness displaced past years’ focus on policy- and subsidy-led decarbonization as the key forces driving clean energy. Among RMI-ers , many conversations centered on the work needed to remove market barriers, such as better accounting standards (to assess and track company emissions), as well as technical steps to lower emissions from shipping, aviation, and other industries.

Even so, as companies continue to push ahead, many are doing so with less fanfare than in the past. “This year saw more closed-door events, an opportunity to have honest and real conversations about progress and barriers,” added Thomas Koch Blank, RMI managing director focused on industrial decarbonization.

“I am more confident than ever that the transition has reached escape velocity and is unstoppable even in the face of political volatility,” Koch Blank said. “It simply makes too much long-term economic sense for politics to topple.”

Between threading their way through Manhattan’s grid-locked streets during CWNYC, RMI-ers shared these snapshots.

The grid is the biggest investment opportunity being overlooked here in the U.S. We have pumped trillions into the grid over the years, and today it only operates at 40% capacity. To meet the load growth we are facing now and in the future, it’s about upgrading energy efficiency, supporting demand side resources, and delivering more incentives for innovation.

Jon Creyts: Most of the world is moving quickly to clean energy

Chief Executive Officer

At a CWNYC flagship session, Creyts emphasized the profitable opportunities clean energy offers at home, and overseas: “All of us on the panel were optimistic about the future, with 80% of the world still moving fast on the energy transition, plus strong subnational and corporate leadership here in the U.S.”

Energy efficiency was eerily absent from most discussions. The most cost-effective energy to supply is the energy not consumed. Efficiency upgrades can deliver disproportionate benefits by reducing or delaying capital expenditure, debottlenecking infrastructure, and enabling growth of electrified, high-value-added sectors.

Thomas Koch Blank: A missing focus on efficiency

Managing Director, Climate-Aligned Industries

Not far from the busy meeting venues at CWNYC, Koch Blank notes, the Empire State Building offers a towering example of the potential returns from investing in efficiency.

Starting in 2009, RMI had the privilege to work with the Empire State Realty Trust to design and implement a deep retrofit that optimized energy performance across the entire building — for example, by remanufacturing windows on site to let in light, but reflect heat — leading to more than a 50% reduction of both energy consumption and carbon emissions.

Learn more about RMI’s work on the Empire State Building here:

While it’s true some companies are pulling back on climate pledges, the bigger story is that many more are staying the course — some quietly doubling down on sustainability.

Ben Bartle: How to advance US clean energy competitiveness

Principal, Catalytic Finance

The reversal of federal support for clean energy manufacturing puts the United States at risk of falling behind in the race to build solar, batteries, and related technologies at home, Bartle notes. But the United States won’t beat big state-backed rivals in China at their own game.

Absent efforts to mobilize domestic output, the United States could face a $152 billion annual deficit in new energy technology by 2035, while China would be earning $340 billion in exports, according to a new RMI report co-authored by Bartle with  Sarah Ladislaw (below) and others. 

But America can stay in the race if it activates a range of competitive strengths:

• Balance US energy security with real competitiveness and resilient supply chains.
• Benchmark the right technologies and partners with hard data, and set disciplined, sector-by-sector priorities, moving beyond ad-hoc deals.
• Build execution muscle such as master energy agreements and empowered deal coordinators, and modernize and derisk trade finance (such as export-import banking) to mobilize US private capital and tech innovation focused on supply-chain resilience and energy security.

[Companies] want to have a share in producing clean energy technologies, selling them to the world. [They can profit from] the single largest capital formation in the history of the world.

Sarah Ladislaw: For businesses, unprecedented opportunity

Managing Director, US Program

In conversation with Axel Threlfall of Reuters and Drew Bond of C3 Solutions, Ladislaw spotlighted the economic urgency of the clean energy transition and the private sector’s pivotal potential to profit from it.

Clean energy, she emphasized, is not only a climate solution. It’s also increasingly the best pathway to transform and upgrade the global economy. For a deeper dive into the US role in the global clean energy race, explore RMI’s new energy statecraft playbook.

RMI has a history of working with ambitious companies to accelerate the adoption of low-emissions products, from the Sustainable Aviation Buyers Alliance (SABA)’s work on scaling the market for sustainable aviation fuel to the Sustainable Steel Buyers Platform’s ambitious plans for green steel.

Bryan Fischer: To scale clean cement, steel, concentrate demand

Managing Director, Industrial Decarbonization

At CWNYC, Fisher celebrated the launch of RMI’s latest demand initiative, Sustainable Concrete Buyers Alliance, a collaboration between RMI and the Center for Green Market Activation (GMA). SCoBA aggregates demand for low-carbon cement and concrete, the production of which accounts for around 8 percent of global carbon emissions every year.

For a comprehensive look at how smart procurement can reduce carbon pollution, check out RMI’s work on catalytic procurement.

There’s so much data exchange that’s happening in the carbon markets across the different stakeholders. We want to be able to make that data exchange happen as effectively and as efficiently as possible.

Bonnie Lei: To lift carbon markets, improve data transparency

Principal, Climate Intelligence

At CWNYC, Bonnie helped launch the Carbon Data Open Protocol. CDOP is tackling a well-known challenge in voluntary carbon markets. In climate finance, every extra step to re-format, re-check, or re-request project data adds cost and slows execution. By creating a shared, open framework for carbon credit data, data can flow more smoothly, saving time, cutting risk, and helping more dollars reach clean energy and climate solutions that matter.

In voluntary carbon markets, RMI is pushing for consistent standards for data related to carbon projects and credits.  More transparency can help buyers, project developers, and registries access reliable, verifiable, and science-backed information throughout the life cycle of a carbon credit.

Learn more about RMI’s work in carbon markets.

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Energy waste is everywhere, largely invisible, and shockingly valuable. Taken together, these losses across the world’s energy supply systems add up to $4.5 trillion every year — or nearly 5 percent of global GDP. Converting delivered energy into useful services – such as hot showers and cold beer — wastes at least 80 percent of what’s left.

In many cases, affordable — indeed, often profitable — solutions are available to cut the waste, improve efficiency, and save money. That’s why prioritizing energy efficiency is an essential part of the solution to ease the transition to clean energy. Because renewables waste less energy generating and transmitting energy, wind and solar power can double or even triple the efficiency of electricity production. And pairing clean energy supplies with conventionally improved end-uses —  such as variable-speed electric motors or electric heat pumps — can then double efficiency again.

But the biggest breakthrough, often overlooked, comes from rethinking how we design and operate buildings, vehicles, and factories — melding a series of design solutions to deliver compounding benefits. Few people have championed this whole-system approach more than RMI cofounder Amory Lovins, who recently explained at Stanford University’s Energy Seminar how the transition to clean energy can become far faster, cheaper, and easier by applying “integrative design.”

While most analyses focus on the technologies of energy supply and of isolated energy-using parts, Amory explains that rethinking how we design buildings, vehicles, and factories as whole systems can boost energy productivity by as much as fivefold, measured from delivered energy (such as electricity or gasoline) to final service (such as torque, flow, or mobility). Here are select excerpts of his talk, adapted for length. Scroll to the bottom to view the full presentation via video.

Improving comfort and saving money in buildings

“Optimizing buildings, vehicles, and factories as whole systems, not as piles of isolated parts, could often make very big energy savings cost less than small or no savings, turning diminishing returns into increasing returns,” says Amory. Such enhanced efficiency magnifies returns before a single solar panel or wind turbine is added, yet it’s seldom taught, practiced, rewarded, or expected. “Renewables get all the headlines because they’re visible,” Amory explains. “But energy is invisible, and the energy you don’t use is almost unimaginable.”

For example, improving a building’s insulation and windows may eliminate the need for a heating and cooling system altogether, turning what seems like an extra up-front cost into long-term net savings.

In Amory’s own home in Snowmass, Colorado, where temperatures can drop below -5°F (-20°C) — he observed –47°F (–44°C) in the 1980s — and winter days can be continuously cloudy for as long as 39 days, passive solar design, superinsulation, and advanced windows cut energy use so effectively that he doesn’t need conventional heating at all. “Eliminating the heating system subtracted more capital cost than efficiency added,” says Amory. After also saving about 99% of water-heating energy, 90% of electricity, and half the water, “all the savings combined paid back in 10 months. Today, that would probably be less than zero.”

The same principle scales up to commercial buildings. For example, RMI’s retrofit design of the Empire State Building initially cut energy use by 38 percent, later by 51 percent, with a three-year payback, largely because smaller mechanical systems offset much of the cost of efficiency upgrades. From Stanford’s Carnegie building to RMI’s Innovation Center in Basalt, Colorado, and across numerous other projects worldwide, passive design combined with efficient existing technologies has consistently delivered deep energy savings and superior comfort, along with excellent economics — even with lower upfront costs, which further shorten payback periods.

Designing small changes with big impacts in industry

And these results aren’t limited to buildings. In industry, which uses half the world’s energy and electricity, rethinking design choices like pumps, fans, motors, and pipes could yield 40–90 percent savings, with lower capital costs. In his remarks to Stanford University’s Energy Seminar, Amory notes that most engineers focus on making these devices more efficient but forget to improve efficiency in how they’re connected — namely, pipes and ducts. He described how small design decisions, like using fatter, shorter, straighter pipes, can reduce friction losses so dramatically that pump sizes — and therefore energy use — drop by up to 90 percent. “It’s not a technology, it’s a design method,” says Amory. “And few people yet think of design as a path to speed and scale.”

Improving efficiency in cars, data centers, and more

This same logic applies to electric cars, cement, data centers, and aviation. For example, BMW started making its i3 electric vehicles with lightweight, durable carbon fiber. The costlier but lighter-weight material needed fewer batteries to move less weight, and recharged faster with less electricity and infrastructure. For BMW, just the avoided batteries and simplified auto assembly repaid the carbon extra upfront cost of using carbon, quadrupling efficiency, and leading the German automaker to profitably sell a quarter-million of the compact EVs in 2013–22. Applying this same logic to AI data centers, Amory argues that improvements to AI hardware, software, and system architecture could increase energy efficiency, greatly reducing power demand and capital cost. Better structural design could profitably save half the world’s cement and steel. And so on across all of industry.

Thinking in whole systems

In every sector and nearly every use, integrative design offers a powerful yet radically underused pathway to dramatically reduce energy, water, and material use across the entire economy, often at lower cost and faster payback. The reason it remains rare, Amory points out, is not a lack of technology but a failure of education and practice.

“Observing buildings, vehicles, factories in over 70 countries in 50 years, I see the same design errors repeated everywhere, because they’re widespread in our textbooks and our classrooms,” he says. “If the people who shape our built environment — engineers, architects, sheet-metal workers, pipefitters, mechanical contractors — were trained to think in whole systems, not just parts, we could unlock efficiency gains on a scale most still consider unimaginable.”

It’s a problem we can solve today. And the solution starts with spreading integrative design literacy. As Amory puts it, we should aim to “make integrative design as common as grass… then the revolutions in renewables, electrification, decentralization, even digitization and democratization can get faster, cheaper, and easier.” Making that shift won’t just reduce emissions; it will reshape the very foundation of how we provide and use energy.

This article is based on a lecture Amory Lovins gave for Stanford’s Energy Seminar on June 2, 2025. You can visit the event webpage or watch the recording of his lecture here.

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