You are here
Rocky Mountain Institute
Why Communities Can and Must Consider Electricity Affordability and Risk Together
American electricity customers and their advocates have good cause to be worried. Since 2020, residential electricity prices for urban Americans have risen by 40 percent, and current trends suggest prices will continue to increase. Natural gas, which supplies ~40 percent of America’s electricity, is projected to grow in price in the coming years. Gas turbine shortages and growing obstacles for wind and solar development are limiting new supply. And utilities are upgrading aging infrastructure to better withstand natural disasters, passing costs onto customers.
At the same time, utilities are scrambling to meet ballooning electricity demand. Data center proliferation, along with industrial growth and electrification, could increase annual electricity usage by 32 percent by 2030. This combination of surging demand and constrained supply will further increase prices. And homeowners and renters may suffer the most, as these groups have experienced the largest price increases in recent years compared to commercial and industrial users.
These affordability concerns and rising demand are pressuring legislators, regulators, and utilities to act — and many are turning to traditional approaches. Utilities like the Tennessee Valley Authority are proposing large, new natural gas facilities. Large-scale projects can benefit from economies of scale, but they also create financial and reliability risks that, all too often, end up hurting consumers in the long run. Just as investors balance risk and reward by building portfolios of stocks, we should pursue diverse energy strategies.
Portfolios of small, local investments — such as energy efficiency, batteries, renewable energy, and flexible resources such as virtual power plants — offer an alternative means to meet growing electricity demand without compounding risk. By leveraging these technologies, we can create an energy system that is more diverse, more resilient to financial and operational shocks, more affordable, and cleaner.
Putting all your eggs in one basket is riskyA utility’s typical response to serving new load is to build centralized, fossil-fuel generation, including natural gas turbines. Utilities like these facilities because they are familiar and can be turned on when you need them (i.e., they are “dispatchable”). Further, many utilities are allowed to bill ratepayers more when they invest in new capital assets, which incentivizes them to build centralized generation.
However, building large, homogenous generation fleets places several risks on consumers:
- Overbuilding: When a utility builds a large plant, it is making a big, long-term bet. The utility spends lots of money in the hopes that there will be sufficient future electricity demand to justify the expense. Yet utilities routinely overestimate demand growth, on average by 17 percent. Customers and investors are then left footing the bill for underutilized plants. For example, during the Dot Com bubble, utilities built a fleet of gas plants to meet expected future demand. However, electricity usage fizzled after the bubble burst, leaving customers paying for plants they didn’t need. The same issue can occur for renewables projects. The City of Georgetown, TX, contracted for significant volumes of wind energy, expecting future growth that never arrived. As a result, the city was left with excess electricity that it had to sell at a loss.
- Market shifts: Another challenge with large, long-term bets is that energy markets can change dramatically over decades. For example, when communities in Illinois committed to building a new coal plant at Prairie State Campus in 2007, the project looked like a decent investment. However, by the time the plant was finished, innovations in fracking technology had made natural gas far cheaper. As a result, RMI analysis found that these communities paid at least $390 million extra for their electricity over four years.
- Fuel price risk: Reliance on fossil fuels can expose customers to more volatile prices. Between 2020 and 2023, electricity customers in Florida saw their monthly fuel charge double from ~$20 to $40. Today, natural gas prices are again rising and increasing costs for consumers around the country.
- Shared disruptions: Non-diverse energy systems are also less resilient because they share common points of failure. In 2021, many communities in Texas lost power during Winter Storm Uri when natural gas generators and pipelines across the state froze. Other regions, such as New England, are also vulnerable to polar vortexes due to their reliance on natural gas. In fact, the North American Reliability Corporation (NERC) flagged the United States’s growing usage of natural gas as a national reliability risk.
Many of these risks are becoming more acute as surging electricity demand, increasingly volatile weather, a dynamic policy landscape, growing geopolitical risk (which can impact fuel prices), and rapid technological innovation increase future uncertainty.
Diversification is a powerful risk reduction strategyInvesting in a diverse set of energy solutions can mitigate these risks and create a more financially and operationally resilient system. This diversity can take several forms:
- Diverse types of generation limit common points of failure and fuel price risk: Generating electricity from a variety of types of facilities increases resilience to extreme weather by reducing common points of failure. For example, it was the City of Springfield’s “balanced portfolio” of renewables and traditional resources that allowed it to successfully weather a severe winter storm. A diverse generation fleet also reduces fuel price risk by dampening the impact of market shifts in any one commodity (e.g., increases in natural gas prices).
- Diverse generation locations protect against localized disruptions: Varying the geographic location of generators can limit the risk that all of them will be impacted by a single event (e.g., a wildfire).
- Staggering contract timing protects against buying when prices are high: Just as investors use techniques such as dollar cost averaging to manage market volatility, building an energy system incrementally over time limits the risk of any one transaction losing a lot of money. Further, staggering purchases provides more regular opportunities to adjust over time as electricity needs and market prices fluctuate.
- Diversifying technology size balances economies of scale with nimbleness: Leveraging smaller, fast-to-deploy solutions can limit the risks of overbuilding to meet anticipated demand. Investments in energy efficiency, batteries, demand response, and flexible resources such as virtual power plants have the potential to be deployed in months rather than years. As a result, instead of making bets years in advance, we can deploy these solutions over time as demand evolves. These local solutions can also significantly reduce costs for consumers. For example, in 2024, ComEd provided residents and businesses with $277 million to reduce electricity waste. As a result, customers will save an estimated $3.2 billion, a more than tenfold return. Similarly, virtual power plants (VPPs), which leverage large numbers of devices to reduce demand at critical times, can provide the same services as a new gas plant at 40-60 percent of the cost.
These ideas are not just nice theories — communities are putting them into action. Consider the case of Burlington, Vermont. Over the years, Burlington has:
- Reduced residential electricity usage and peaks: Through a dedicated energy efficiency utility, Burlington has consistently made investments to slash waste and reduce homeowner bills. Since the program’s inception, the City’s investments have reduced annual residential energy use by 59,204 MWh — enough to power over 5500 typical Northeastern homes or a bit less than one-third of Burlington’s households. These waste reduction efforts not only reduce homeowner energy costs but also help minimize the utility’s maximum load on any individual day (particularly when combined with the recently launched flexibility programs). Since the electric grid must be sized to meet a community’s highest demand throughout the year, these efforts provide an elegant means to delay or even avoid costly new infrastructure investments.
- Kept bills low and stable: Burlington generates its power from a variety of sources, including biomass facilities, hydro, wind, solar, and oil. This diversity has protected its customers from price volatility and enabled it to retain lower rates. In contrast, Eversource customers in neighboring New Hampshire have been exposed to fluctuating natural gas prices, and experienced higher, more volatile bills. (See Exhibit 1). Importantly, this analysis assumes comparable electricity usage across households, but in reality, Burlington residential users consume 34 percent less than the average in New England, at least in part due to the city’s long-standing energy efficiency efforts. As a result, a typical Burlington homeowner’s actual bills would likely be even lower than what is represented here.
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
Exhibit 1: Burlington Electric Department’s and Eversource’s average monthly residential bills over time.
We can have a less risky, more reliable systemA more diverse, distributed, resilient energy system is possible — but it won’t happen on its own. While state policy makers and regulators can play a critical role in passing policies and regulations to support this adjustment, local governments and communities can adopt policies that help streamline local installations (e.g., permitting reforms).
We also need to collectively rethink how we evaluate investments. Too often today, individual energy projects are evaluated in isolation, where perceived risks about cost effectiveness can delay or cancel projects. This narrow lens too often causes us to overlook the risks we are already exposed to and undervalue the benefits of diversification. To be fair, there will be times when the cost savings from distributed energy resources may be uncertain or, at the end of the day, not realized. Yet communities that take a holistic lens to their investment decisions will be rewarded with a more financially and operationally resilient system.
In today’s uncertain environment, customers need affordable, reliable electricity — without more risk. Portfolios that leverage distributed, local solutions to complement centralized approaches might be just what they need.
The post Why Communities Can and Must Consider Electricity Affordability and Risk Together appeared first on RMI.
Methane 101: Why it matters, where it comes from, and how to tackle it.
Preventing methane emissions is one of the fastest ways we can slow Earth from overheating right now. Methane isn’t just a damaging waste product. It is also a valuable commodity that is marketed as “natural gas,” which is produced alongside oil. When it leaks into the atmosphere, however, methane massively traps heat and warms our planet at an accelerated rate.
Methane was discovered in Italy 250 years ago due to bubbles arising from marshes. When collected and ignited, methane lit on fire and was initially called “swamp gas.” Although methane (chemical name CH4) has been steadily present in the Earth’s atmosphere at low levels for tens of thousands of years, its volume has increased dramatically since the Industrial Revolution due to increased fossil fuel use, agricultural expansion, and landfill development. In 2025, methane levels were at the highest ever recorded.
This increase in methane accounts for a roughly 0.5°C increase in global temperature, or nearly 30 percent of “forced” or human-made warming to date, which makes tackling methane pollution a pressing climate concern.
What makes methane so dangerous?While carbon dioxide acts like a heat-trapping blanket around our planet, methane acts like an electric blanket with much more warming power. Methane has a lifetime of about a decade before it reacts to form other climate gases. Over a 20-year span, methane is over 80 times more powerful than carbon dioxide at warming the planet. As methane and other greenhouse gases build up at today’s elevated levels, their “blanketing” effect traps far too much heat. The greater the buildup, the greater the risk of life-threatening, property damaging, and costly extreme weather, wildfires, flooding, and other harms.
As well as being a climate concern, methane also causes substantial problems on the ground. Methane contributes to the formation of ground-level ozone, known as smog. Methane is also co-emitted with deadly contaminants and air toxins that kill and sicken people near where it is released. For example, benzene, a known carcinogen, can accompany methane when gas leaks from wells, flares, tanks, pipelines, chemical plants, and furnaces. Deadly hydrogen sulfide can be co-emitted with methane from oil and gas wells. And super-emitting methane sources that are present in very large volumes can explode and cause fires.
What are the main sources of methane?The fossil fuel industry, landfills, livestock, and agriculture are the major human-made sources of methane, making up about 55 percent of current methane pollution. Natural sources, like wetlands, swamps, and thawing permafrost, produce roughly 45 percent. Different places have different shares of methane.
Methane is invisible, usually odorless, and under high pressure. This means it can readily leak in every stage of the oil and gas supply chain. It is easily emitted from landfills when food and other organic waste decompose. Some crops release methane as they grow. And animals, like cattle, expel it as a waste product.
How can we cut emissions?The best place to slash methane is to start where we can make the most immediate impact. Methane from fossil fuels is a prime target because the methane in gas is a valuable commodity that is widely traded. Preventing gas from escaping means that companies can recoup money and prevent exposure to harmful impacts. Stopping leaks, reducing venting, and limiting flaring can quickly cut energy waste and curb methane emissions.
For landfills, a suite of tools is available to stop methane pollution at waste sites. These include reducing food waste, diverting food waste from the waste stream away from the disposal sites to anaerobic digesters or composting facilities, improving landfill cover practices, and enhancing gas capturing efficiency.
Cutting methane from livestock involves changes to waste handling and animal diets. Promising experiments are taking place with novel cattle feeds that reduce overall emissions. And reducing methane emissions from agriculture calls for changes to cultivation practices and other new control methods.
As a backstop, there is also work underway to study methane removal. As this powerful greenhouse gas builds up in the atmosphere, there may be a role to develop methods in the future for its removal in addition to efforts underway to cut methane emissions in each sector.
How can data accelerate action?To tackle leaks and ultimately prevent them before they happen, we need to make invisible methane visible. This requires sensors and checks on the ground to make sure equipment is working as it should, as well as aerial surveys and even satellites to catch leaks as they happen.
Data-to-action efforts involve updated infrastructure, improved monitoring, and tighter regulations to enable faster responses to unexpected events that can reduce methane releases. The greatest opportunities in tackling methane emissions lie in more accurately measuring the emissions and reducing reliance on the industry’s self-reported emissions, which leads to emissions undercounting, as the exhibit below from Texas illustrates.
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
What is being done at the international level to prevent methane pollution?Countries at COP26 in 2021 signed on to the Global Methane Pledge, which calls for a 30 percent reduction in 2020 methane levels by 2030. The 159 country signatories currently represent roughly 50 percent of the total methane emitted today.
Other initiatives involve incentivizing the production of low-methane oil and gas. The European Union’s methane regulations, which came into force in 2024, apply strict measures, including bans on venting and flaring and a low-methane standard that gas importers must meet.
How is RMI involved in tackling methane?RMI works at multiple points to slash and prevent methane pollution. Our initiatives help to quantify and visualize methane to support policy adoption and advance market activation.
RMI’s Oil Climate Index plus Gas (OCI+) is an open-source analytic tool that estimates and compares the life-cycle greenhouse gas emissions intensities, including methane, of a majority of oil and gas resources worldwide from extraction to consumption.
RMI also quantifies methane emissions from oil and gas and waste sectors for ClimateTRACE, a coalition tracking greenhouse gas emissions from every global sector.
Through WasteMAP, a partnership between RMI and Clean Air Task Force, we’ve created an open, online platform that aggregates and maps reported, modeled, and observed waste methane emissions data worldwide.
We are also part of the CarbonMapper coalition, which helps shed light on major emitters. Last year, RMI was part of the launch of the Tanager-1 satellite, which has been hard at work tracking super-emitters and speeding solutions.
MiQ, a voluntary certification standard developed by RMI and SystemIQ that grades gas production on an A–F scale, has certified a volume of 24 billion cubic feet per day of low-methane-leakage gas. In July, we released an analysis showing that, with Pennsylvania acting as the keystone producer, US output of certified low-leakage gas can meet demand from both domestic and international buyers.
RMI has also mapped the vast number of uneconomic and end-of-life wells — marginal wells — across the United States. Future work will focus on pinpointing high-emitting marginal wells and stopping their emissions.
What are the benefits from reducing methane?Methane has a much shorter lifetime in our atmosphere than carbon dioxide. This means that reducing methane now immediately prevents it from warming Earth in the short term. Methane also takes longer to react into dangerous air pollutants, like smog. Any action to prevent or more quickly stop methane leakage protects our health and safety. Rapidly attending to large methane plumes and preventing explosions can prevent risk to people and property.
Driving down methane emissions buys us crucial time to accelerate new technologies and scale the energy transition. Cutting methane means a cooler planet, a healthier environment, and clearer skies — and wasting fewer energy sources.
The post Methane 101: Why it matters, where it comes from, and how to tackle it. appeared first on RMI.
How Fuel Cost-Sharing Can Deliver Savings for Utility Customers
Highlights
- Fuel cost-sharing could have saved North Carolina customers nearly $89 million in cumulative savings between 2020 and 2024.
- Even in high volatility years, a fuel cost-sharing mechanism would not materially threaten utility revenues.
- Expanding cost-sharing to include purchased power and integrating complementary tools — such as fuel management plans, hedging strategies, independent audits, and clean energy investments — can further reduce fuel cost volatility and improve accountability.
The post How Fuel Cost-Sharing Can Deliver Savings for Utility Customers appeared first on RMI.
Case Studies in Cost-Effective Low Embodied Carbon Buildings
The post Case Studies in Cost-Effective Low Embodied Carbon Buildings appeared first on RMI.
Norway’s Wins Go Beyond the Olympic Podium
Norway has won the most medals at the Winter Olympics since the games began in 1924 — 405 total, including 148 gold. On top of its winter sport dominance, Norway has led the way in clean energy and emissions reduction.
Approximately 98% of electricity is from hydro or wind powerNorway has a legacy of hydropower that goes back to the 19th century — the first hydropower plant owned by a municipality came into production in 1891 in the Arctic town of Hammerfest. Today, hydropower supplies almost 90 percent of Norway’s electricity generation. Although hydropower is likely to remain the backbone of the Norwegian power system, support for wind power is growing (currently around 9 percent of electricity generation), and the government aims to have 30,000 MW of offshore wind production by 2040.
Electric vehicles made up 96% of new car sales in 2025Norway has the highest number of electric vehicles per capita in the world. In 2017, the Norwegian Parliament set a goal that all new cars sold by 2025 should be zero-emission (electric or hydrogen). Through a combination of carrots and sticks, Norway has incentivized the purchase of electric vehicles to the point that 96 percent of new cars sold in 2025 were electric (up from 89% in 2024).
The lowest methane emissions intensity of any oil and gas producerAlthough its grid is clean, the country is the fourth largest natural gas exporter in the world, with about 95 percent of Norwegian gas going to the European Union and United Kingdom.
Norway leads the world in ensuring its oil and gas production limits methane, a powerful greenhouse gas with more than 80 times more warming power in the near term. It wastes less gas for each barrel it produces than any other nation. By banning non-emergency flaring in 1971 and imposing a tax on natural gas venting and flaring in 2015, Norway has been able to significantly slash its oil and gas methane emissions.
The International Energy Agency (IEA) finds that global oil and gas methane emissions would drop by over 90 percent if every country matched Norway’s emissions intensity for oil and gas operations.
The rest of the worldCurious about how other countries rank in methane intensity? Check out RMI’s Oil Climate Index Plus Gas (OCI+) tool to see and compare greenhouse gas emission intensities from oil and gas assets. OCI+ also provides guidance and insights for reducing energy waste and life-cycle emissions across the oil and gas supply chain. https://ociplus.rmi.org
The post Norway’s Wins Go Beyond the Olympic Podium appeared first on RMI.
How Electrification Can Shrink the Emissions in Everyday Products
Solar panels, fertilizers, and even your workout gear contain chemicals that are derived from fossil fuels. These chemicals pose a dual fossil fuel challenge — they are made from fossil fuels, but the high-temperature heat used in production is also powered by fossil fuels. This latter step contributes a significant percentage of the greenhouse gas emissions of these products, and rethinking the heating and chemical conversion processes can deliver substantial emissions reductions.
RMI’s Chemistry in Transition report indicates that the solutions to reducing half of current emissions from chemical production exist today. But addressing the remaining emissions will call for innovation, particularly for processes that continue to rely on fossil fuel-based heat and reaction systems.
Process electrification is one of the most promising innovations. By substituting electricity for combustion-based heat, or by using entirely new electrically-driven reaction pathways, we can significantly reduce emissions from chemicals production.
However, many electrification technologies remain in early stages and require further validation, optimization, and scaled demonstration before they are ready for commercial deployment.
RMI’s Applied Innovation Roadmap (AIR) for Chemicals offers a roadmap to bridge those gaps and move toward deployment. It highlights six electrification technologies with meaningful emissions reduction potential. It assesses the technologies’ current readiness, identifies key barriers to scale, and outlines priority research, development, and deployment (RD&D) and funding needs to achieve technical feasibility and economic viability.
Here’s how those processes could transform a selection of essential products, from plastics, to clothes, to fertilizer.
PlasticsMain component: Ranging from PET (drinking containers), to LDPE (garbage bags)
Chemical building blocks: Ethylene, propylene
Emissions reduction possible through electrification of process heat: 15%+
Many household appliances, car parts, and even solar panels call for plastic to keep their construction light and to provide durability. By targeting the heating processes that make these plastics’ building blocks — ethylene and propylene — we can make plastics that contain the same characteristics, but with significantly lower emissions.
Both ethylene and propylene come from a process called steam cracking, where hydrocarbons are super-heated to convert into plastic precursors. The fossil fuel heat for cracking contributes at least 33 percent of emissions from this process, so if we can remove fossil fuels as the heat source, we can dramatically cut emissions.
RMI’s AIR for chemicals outlines a range of ways to electrify or otherwise improve the current steam cracking process. One solution, resistive heating, runs off the same principle as your toaster: heating coils (using renewable energy) to induce the cracking reaction rather than burning fossil fuels. Resistive heating’s compatibility with existing steam cracking equipment also makes it attractive for retrofitting plants, while reducing emissions by around 15 percent compared to fossil-fuel-fired steam cracker furnaces.
Resistive heating for steam cracking
/wp-content/uploads/2026/01/Ex4-resistive-heating-2.mp4Clothing
Main component: Polyester
Chemical building block: Ethylene and paraxylene
Emissions reduction possible through electrification of process heat: 15 –100%, depending on process used
Head to any gym and you’ll immediately see chemically derived clothing all around you. Athletic-wear materials like spandex, nylon, and polyester are all synthetic fibers that come from chemical processes.
Take polyester, for example. Before it can be made into a t-shirt, it begins with a chemical reaction between ethylene glycol and purified terephthalic acid (PTA) at very high temperatures to eventually create a polymer that is extruded and spun to create polyester fiber.
How polyester garments are made from fossil-fuel derived inputs
That second step, the chemical reaction (outlined above), takes an enormous amount of energy that is today achieved by burning fossil fuels, usually natural gas. But as our AIR for chemicals indicates, a host of other options to create that heat are now on the table. From the more traditional resistive heating (like a heating coil on an electric stove) to the less orthodox shockwave reactor (see animation below) to the emerging process of CO2 electrolysis, fossil fuels are no longer the sole route to creating the building blocks of these clothes.
Shockwave heating for steam cracking
/wp-content/uploads/2026/01/Ex9-shockwave-heating-3b.mp4
Main component: Ammonia
Chemical building block: Hydrogen
Emissions reduction possible through electrification of process heat: 40% (if powered by 100% renewable energy)
Fertilizer helps feed the world, but it also carries a heavy emissions footprint: the 1.31 gigatons of CO2e emitted each year from synthetic nitrogen fertilizer is more than the aviation and shipping sectors combined. And while two-thirds of emissions come from fertilizer use in the field, the other one-third comes at the production stage — making it a ripe target for reductions.
Much of fertilizer’s production emissions come from producing hydrogen, the precursor to ammonia. Today, this happens through steam methane reforming (SMR), where methane and water are superheated and react to produce hydrogen and carbon monoxide. Fossil fuels currently power this heating process, but switching to innovations like green hydrogen eliminates the need for SMR altogether, and could cut emissions to near zero.
For existing fossil-fuel-powered sites, options like induction heating could electrify SMR, with the potential to cut direct emissions by 40 percent. Although induction heating is common in other areas, such as in home stoves, its industrial application is still nascent, with commercial projects likely still decades away.
Induction heating for steam methane reforming
Where we go from here
The problem of fossil-based chemical manufacturing has many solutions, but hurdles still remain to scale the technologies needed to make them a reality. Because of the relative novelty of some of these solutions, we are still decades from making them an ordinary part of chemicals production. Moving as quickly as possible to invest in and scale these technologies means we can avoid tons of emissions while creating a resilient and diversified manufacturing base.
RMI’s Applied Innovation Roadmap for Chemicals outlines the gaps in RD&D and, critically, the funding needed to make these solutions part of everyday manufacturing, and provides guidance on where stakeholders across industry, research, policy, and finance can engage for maximum impact.
The post How Electrification Can Shrink the Emissions in Everyday Products appeared first on RMI.
Reactions to Landman Season 2: Risky Business Continues in the Oil Patch
Beyond the over-the-top family drama that keeps us watching, Landman’s second season showcased many unfortunate and harsh realities of the oil and gas industry.
For those yet to watch, Billy Bob Thornton stars as “Tommy,” a veteran landman — a one-man oil and gas field fixer — turned president of M-Tex, a fictional, independent West Texas oil company. As the second season progresses, we witness Tommy tiring of the high stakes, risky oil business he’s worked in for decades. Tommy cynically observes that “greed has dug a million wells.” Scathing aside, at his core, Tommy is a lifelong oil man. And Season 2 ends with Tommy forming CTT Oil Exploration and Cattle, a new “wildcatting” oil and gas venture drilling on a hunch with a handful of lowly-production wells — and branded with his own initials and those of his son, Cooper, and father, Thomas, plus some cows tossed in.
Despite the whimsical name of Tommy’s new company, the gamut of safety, environmental, economic, and geopolitical risks his industry faces is no laughing matter. These risks keep arising because they are ever-present. As a chemical engineer who once worked in the oil and gas industry, here’s a recap with my reactions.
Season 2, Episode 1 opens with a serious oil and gas health hazard. Toxic hydrogen sulfide (H2S) gas leaks at dangerous levels from M-Tex’s oil and gas equipment. A hunting party in the vicinity encounters animal carcasses strewn in a nearby field before perishing themselves. Tommy’s crew, despite wearing mandatory H2S monitors to alert them, cannot retreat fast enough. With H2S entering their bloodstreams, they become violently ill, and one worker loses his eyesight.
Reaction: Oil and gas are chemical concoctions that contain methane and other volatile compounds, including toxins like H2S and carcinogens like benzene. Although oil and gas are advertised as simple, “standard” commodities, they are very complex. Their makeups vary widely, but their compositions are not publicly disclosed. Greater transparency detailing what’s in oil and gas is needed to safeguard people and property.
Scenes from Landman’s second season.Safety risks are a continuing theme in Landman. In episode 4, an oil field truck plows into a parked pickup in distress, resulting in a fireball with no survivors.
Reaction: Road accidents are common in West Texas’ oil patch due to long shifts, high speeds, rural (often unpaved) roads, and big rigs transporting heavy equipment. Studies find that the leading causes of oil and gas deaths, beyond dangerous field conditions, are road fatalities.
An oil field truck crashes in episode 4.Physical risks are confronted in episode 6. One of M-Tex’s offshore rigs is damaged beyond repair in a hurricane, and insurance fraud surfaces. Money is paid out, but no reconstruction takes place.
Reaction: Oil and gas infrastructure is capital intensive and requires insurance (and often re-insurance) to operate. Yet much of the oil and gas industry’s operations — platforms, refineries, LNG terminals, ports, tankers, and pipelines — are in harm’s way in or near waterways and the methane leaking from oil and gas is superheating the planet. The changing climate is increasing the frequency, speed, and severity of superstorms, tornadoes, hurricanes, sea level rise, and flash floods that present physical and financial risks that the industry has not weathered in the past. At least one insurance company, Chubb, has set underwriting guidance that may deny coverage to oil and gas companies with assets that leak too much of the powerful climate accelerant, methane, which is also a main component of oil and gas.
Economic risks are highlighted in episode 6. Tommy and his crew attend an industry fair showcasing conventional and novel technologies. They stop at a booth of a real-world startup, MaCH4 Coldstream Energy — which recovers natural gas liquids instead of burning and wasting them. One of Tommy’s crew laments: “That’s the future without us.”
Reaction: The energy world is in transition. Efforts are accelerating to eliminate energy waste, as evidenced by companies like MaCH4. Markets are reinforcing changes in the energy landscape. For example, the price of renewable energy has been even lower than that of gas and oil recently. And electric vehicles are overtaking gasoline-powered vehicles in new car sales, which is reducing demand for oil and shifting energy markets. There is added economic uncertainty about the future price of gas, given its significant market volatility. Taken together, this is making the future of oil and gas far less certain than it was in the past century.
Geopolitical risks are materializing in real time as the finale of Landman Season 2 airs. Tommy shares that M-Tex is a bit player in a global oil and gas industry that is too big to fail. He likens the business to a layer cake of many different interests, and he considers pursuing new opportunities with an international oil company — Chevron (one of the companies operating in Venezuela).
Reaction: Had Landman’s Season 2 script been written now, it’s very likely that the geopolitical situation in Venezuela would have been mentioned. Oil and gas are valuable trade commodities and countries rise and fall on them. When the US invaded Venezuela and jailed its president, at least one motivation was appropriating another country’s resource wealth.
Perhaps the most surprising reality that surfaced during season 2 was in my conversations with everyday Landman viewers. There is widespread public misconception regarding the source of everyday products we depend on to power our computers, heat our homes, form fiber for our clothes, manufacture our medicines, fuel our cars, trucks, and planes, pave our roads, and more. I was asked more than once if the gas piped to our homes is the same gas that comes out of the ground.
Reaction: The oil and gas that are drilled out of the ground are the very same resources that are processed into commodities that we consume every day. While the oil and gas that M-Tex and other companies produce must flow through a long chain of custody involving drillers, producers, processors, shippers, refiners, terminals, traders, public utilities, and retail outlets, the gas and petroleum products we consume start their journey under the ground. Regardless, these equivalent barrels of oil and gas do not have the same impact in terms of their safety, environmental, economic, and geopolitical concerns. The longer the trip from extraction to end uses, the more potential gas has to leak and cause harm to people, property, and the planet.
This is precisely what RMI’s Oil Climate Index plus Gas (OCI+) charts. Nearly three-quarters of global oil and gas supplies are analyzed — including those produced by smaller companies like the fictitious M-Tex in West Texas — to quantify the waste and emissions from equivalent barrels of oil and gas that M-Tex and its competitors produce.
US Oil and Gas Assets’ Methane Intensities are Wide Ranging, Especially in West Texas
Source: https://ociplus.rmi.org/, accessed February 9, 2025.
RMI then uses the OCI+ to generate oil and gas emissions inventories worldwide on the ClimateTRACE portal and to assess mitigation scenarios. It turns out that the energy waste and emissions vary markedly from field to field and country to country. This is valuable information that banks, insurers, companies, and policymakers are using to make smarter investment, underwriting, operational, and regulatory decisions.
Closing Reaction: Differentiating barrels of oil and gas is the key to a well-functioning market. Without knowing a commodity’s attributes — safety, environmental, economic, and geopolitical — inefficiencies, waste, and risks cannot be managed. As the maxim goes, we can manage what we measure. And this is especially true for critical commodities like oil and gas.
The post Reactions to Landman Season 2: Risky Business Continues in the Oil Patch appeared first on RMI.
Fast, Efficient Solutions to Meet Electricity Demand Growth
Data centers, electrification, and manufacturing facilities are driving a surge in US electricity demand. Following years of only needing to maintain electricity levels, utilities and regulators now need to find an additional 270 GW of power in the next decade. This is due to an expected increase of 150 GW of national peak demand and an estimated retiring of 120 GW of existing power generation.
Thankfully, there are cost-effective solutions that can be deployed quickly to strengthen the grid and make up 95 percent of the difference. Below we list five solutions with the percentage of demand each can reduce.
Energy efficiency: The fastest, lowest-cost resource (20 percent)Improving energy efficiency helps make the most of every electron, reducing costs while also improving comfort and resilience in homes and other buildings. Creating energy efficiency programs for new loads and expanding existing programs aligned with system needs can unlock over 50 GW of electricity for the grid.
Energy efficiency has traditionally meant replacing older technologies or appliances with newer versions that perform better with the same amount of energy or less. Looking at energy efficiency from a systems perspective, not just a product-focused approach, it becomes evident that many efficiency opportunities are interconnected across the buildings, transportation, and industry sectors, creating multilayered opportunities for greater efficiency and cost savings.
Virtual power plants: Fast, flexible capacity without new infrastructure (22 percent)Virtual power plant (VPP) programs coordinate distributed energy resources like smart thermostats, home batteries, and electric vehicles to provide grid services. By 2030, 60 GW of VPPs could be deployed.
VPPs are unique in their flexibility, cost-effectiveness, and speed — programs can be created and launched in under six months. VPPs can allow utilities to more efficiently use existing, underutilized grid infrastructure, which often results in a lower cost capacity for incremental demand. They are also highly modular and can be scaled up or down on short notice, making them a useful solution for managing the risk associated with uncertain demand forecasts — meaning no stranded assets.
Advanced transmission technologies: An efficiency upgrade for the grid (30 percent)Advanced transmission technologies (ATTs), including grid enhancing technologies (GETs) and advanced conductors, are essentially an efficiency upgrade for the grid: they can help existing infrastructure transport more electricity, which relieves congestion, lowers customer costs, and improves reliability.
GETs and advanced conductors can unlock over 80 GW of incremental peak capacity by reducing transmission and interconnection constraints. ATTs are also less expensive than new transmission and can be installed in a shorter time than it takes to site, permit, and build new lines. Modernizing the grid with ATTs can help quickly get more out of the existing grid, but ATT uptake has been slow despite successful small-scale deployments in the United States.
Clean repowering: Using existing grid connections to get clean energy on the grid faster and cheaper (5 percent)Clean repowering is an elegant and efficient solution that builds new clean energy resources where grid connections already exist to circumvent the lengthy interconnection queues that have emerged as the primary barrier to launching new energy resources. It can take up to 15 years or more to plan, permit, and build transmission lines in the United States, leaving energy projects languishing in limbo as they wait to connect to the grid.
Although some planned retirements have been delayed, the US Energy Information Administration predicts that coal generating capacity will decline by 13 GW over the next two years.
Building new renewable energy and storage where fossil generation is retiring or alongside exiting fossil plants could speed up the deployment of energy resources while reducing system costs because we don’t have to build as much new infrastructure.
Power Couples: Powering new large loads without straining the grid (19 percent)Powering new large electricity loads with wind, solar, and battery systems built near existing, underutilized generators with approved interconnections — a strategy we call “Power Couples” — can deploy the energy needed for data centers and other consumers without putting additional strain on the grid or raising prices for other ratepayers.
These new clean energy resources are sized to meet the demand of the new load and can send surplus energy to the grid.
As of 2025, there are more than 30 GW of opportunity to deploy Power Couples under $100 per megawatt-hour (MWh), and over 50 GW of opportunity under $200/MWh.
Power couple co-located at site of existing natural gas generator
We can meet demand growth with solutions available nowProven solutions exist to provide utilities and regulators with options to support economic growth in the near term without risking massive investments in infrastructure that could be stranded if the data center, manufacturing, and electrification booms don’t pan out as expected.
These existing technologies can be quickly implemented to get the most out of our energy infrastructure, strengthen our existing grid, and prepare the system for the deployment of future energy generation resources.
The post Fast, Efficient Solutions to Meet Electricity Demand Growth appeared first on RMI.
How We’re Building Lighthouses for the Financial Sector
Some deals take longer than others. At the height of the COVID-19 pandemic in 2020, a gas-fired power plant in Illinois secured $875 million in debt financing just three months after appointing bankers and investors to arrange the loan. In November 2023, an innovative lithium mine in Germany took eight times as long to raise a comparable debt package, despite booming demand for critical minerals and a marquee investor roster.
The difference wasn’t project quality. It was risk perception and the complexity of financing new business models and critical infrastructure.
Markets know how to fund what they’ve seen before: pipelines, data centers, solar farms. But for emerging, low-carbon technologies, such as thermal batteries and sustainable aviation fuel, even shovel-ready projects can stall in years of finance negotiations. Bankers must align dozens of stakeholders (investors, customers, suppliers, insurers, technology providers, construction firms, accountants, regulators, etc.) around key terms and risk-sharing structures before the project developer runs out of money.
These delays make projects that deploy emerging technologies expensive, risky, and often unviable. This is dampening enthusiasm for energy transition investment opportunities at a time when it must be rapidly expanding.
RMI’s Deal Lab breaks this cycle.
By encouraging earlier engagement in the deal cycle from key transaction participants, RMI’s Deal Lab helps shape projects, improve bankability, and accelerate financing readiness. In our Role of Banks report, we outlined the need for a recalibration of expectations on banks’ role in the energy transition, oriented around getting transactions done by playing to the strengths of different actors across the financial ecosystem. RMI’s Deal Lab sets both the new expectation and provides the means to implement climate leadership. It invites financial institutions to demonstrate commitment through the giving of time, capacity, and capital to get lighthouse transactions over the finish line.
RMI calls this new effort “Deal Lab” not to evoke experimentation, but to highlight the often-overlooked role of financial learning in commercializing new technologies. This corrects a key flaw in target-setting to date: the separation of climate ambition from the core services and smart investing strategies that banks provide.
Vulcan Energy Resource’s (Vulcan) lighthouse lithium deal presented a novel underwriting challenge to investors because it featured several innovative elements. On the technical side, the project combined on-site geothermal heat and power generation with lithium refining. Financial innovations included “preferential supplier status” to attract specific equity co-investors.
Nearly two years after formally appointing BNP Paribas as financial advisor, it secured over €1.2 billion in debt commitments, signaling investor confidence once the risks were understood and appropriately shared.
In Vulcan’s case, BNP showed what bank leadership looks like: being in the room when market-making happens. The investors who show up early are the ones who will learn first, and the ones the market will trust as these opportunities scale. That’s the role (and opportunity) of banks and finance.
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
For the investment banks (like BNP in the example above) that usually do much of the stakeholder coordination behind the scenes, time is money. Every minute bankers spend learning the ins-and-outs of a new technology or market is a minute not spent on a simpler deal that could be generating structuring fees sooner.
Still, some institutions see these early, complex transactions as where long-term value begins.
“Lighthouse transactions require sustained commitment from institutions willing to engage early, stay close to the deal, share learnings, and build new norms among counterparties,” said Nabil Bennouna, Principal on RMI’s Climate Finance team. “RMI’s Deal Lab helps ease the burden on any individual dealmaker as they navigate the complexity of financing the scale-up of new technologies.”
RMI will accelerate bankers’ and investors’ learning process by applying lessons from years of successful and continued first-of-a-kind (FOAK) project advisory work. Doing so will lower transaction costs by reducing the time spent on diligence and negotiations. From August 2022 to December 2024, RMI’s 100-person Industries program advised 18 large projects (50 percent reached final investment decision compared with 20 percent globally) and conducted three critical functions that banks normally play when there is sufficient commercial incentive to do so:
- Clarifying upside opportunities and downside risk management through consensus-driven financial modeling and technoeconomic due diligence.
- Developing new deal terms to manage nascent market risks and align a deal’s risk-return profiles with investors’ appetites.
- Kickstarting norms and translating key metrics between developers and the varied types of investors in complex capital stacks and across new commercial agreements.
RMI’s dedicated support helped cut through the noise of competing priorities to ensure that attention and resources stayed focused on these lighthouse projects. RMI’s Deal Lab will play three roles until the market can take over:
- Upskill developers and professionalize investor relations: Help developers move from expensive equity to cheaper commercial debt by translating their project value propositions into terms that align with later-stage investors’ norms and expectations.
- Innovate deal structures: Create new templates to align different capital providers’ (equity, credit, insurance) risk-return profiles through multilateral syndicate working sessions that simulate real deal conditions.
- Build an investment engine: Make a stronger case for targeted concessional capital interventions in high impact projects and crowd-in private capital by participating in the development of new investment vehicles.
When learnings from Deal Lab are made public, other advisors and investors can replicate the lighthouse transactions at speed and scale. RMI will share learnings from these deal labs via:
- Investor roadshows that identify and brief potential project funders
- Publicly accessible data rooms that give funders information (e.g., technology performance assumptions, project finance models, energy transition scenarios, comparable legal contracts, etc.) to efficiently diligence similar deals
Roadshows will widen the project’s prospective pool of funders while public data rooms will deepen it. Together, they should help shorten financing timelines because capital markets have already been prepared to diligence and fund innovative deals in that sector. This should mitigate some first-mover risk that can prevent pioneering dealmakers from entering the market.
From 2020 to 2025, the sustainable finance community mainly focused on standards and disclosures. The next five years must see a shift towards transaction-level support, and ultimately, increased deal flow.
The wind and solar industries took around 20 years (and many expensive iterations) to attract cheap, plentiful capital. We don’t have time for this maturation to happen organically in other critical sectors. Lighthouses shine a pathway for others, but someone must first build the lighthouse. RMI’s Deal Lab will enable lighthouse transactions by aligning key counterparties around technical assumptions, contract design, risk management mechanisms, and monetizing new sources of value much earlier and faster than would happen without constructive intervention.
If you are a financial institution, funder, law firm, insurer or project developer interested in learning more or partnering, reach out to RMI’s Deal Lab lead Nabil Bennouna at nbennouna@rmi.org.
The post How We’re Building Lighthouses for the Financial Sector appeared first on RMI.
Powering India’s Electric Trucks with Clean and Affordable Electricity
India’s zero-emission trucking (ZET) market is on the brink of accelerated growth, reaching approximately 1,000 electric truck sales by the end of 2025. However, the supporting infrastructure has not kept pace: only about 5 percent of chargers in India can meet the power needs of zero-emission trucks, and high charging costs remain one of the most significant barriers to scaling the electric trucking market in India today. RMI analysis shows that electricity costs alone can account for 30–50 percent of an electric truck’s total cost of ownership (TCO) over 7 years.
As a result of high electricity prices, electric trucks remain 14–22 percent more expensive than diesel trucks without additional subsidies. Fleets and charging point operators (CPOs) are therefore actively exploring strategies to reduce charging costs. Among these, the use of renewables has emerged as a promising pathway, with the potential to both provide affordable charging and ensure that electric truck deployment delivers real climate and air quality benefits.
Today, only a small number of electric truck charging stations use renewables as part of their electricity supply mix. However, CPOs in India have begun to announce plans to deploy charging stations fully powered by renewables at scale, signaling market demand and growing readiness. This article breaks down the cost structure of charging, and explores how renewable-powered charging can reshape the charging economics.
The post Powering India’s Electric Trucks with Clean and Affordable Electricity appeared first on RMI.
5 Things We Learned from Analyzing More than 200 Utility Incentives
Over the past decade, public utility commissions (PUCs) have increasingly used performance incentive mechanisms (PIMs) to address emerging priorities like affordability, cost control, equity, decarbonization, electrification, interconnection, demand flexibility, and resilience. PIMs are regulatory tools that tie a portion of utility earnings to specific measurable targets. As their use grows, it is important to understand trends, compare performance across jurisdictions, and evaluate whether these mechanisms are working as intended.
RMI’s PIMs Database now contains data on more than 200 PIMs, enough data to extract insights and trends on the application of PIMs for emergent topics across the United States.
PIMs Database Snapshot
Here, we highlight five “PIMsights” we’ve gleaned from analyzing the growing body of data in the PIMs Database.
1: Carrots dominate — and utilities are successfully avoiding sticksPIMs in the database fall into one of three designs: upside-only (the utility can earn a reward), downside-only (the utility can incur a penalty), or symmetrical (the utility can earn either a reward or incur a penalty). This table shows active PIMs with available performance data each year.
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
In the database, downside-only PIMs are rare; of the 221 PIMs collated, there are only two, both of which relate to reliability. Symmetrical PIMs are slightly more common. There are no examples in the database of a utility incurring a PIM penalty between 2020 and 2023.
Upside-only PIMs are the lion’s share. Utilities earned a reward for roughly half of the upside-only PIMs each year from 2021 to 2023. Utilities earned rewards against symmetrical PIMs at a much lower rate — only one per year from 2021 to 2023 and none in 2020.
Takeaway: This suggests that regulators prefer to reserve penalty-only mechanisms for core regulatory objectives like reliability, if at all, and upside-only incentives for emergent priorities. (The skew also reflects the PIMs Database’s focus on emergent objectives.) However, even when penalties are possible, utilities are generally successful at avoiding them, suggesting that downside-only designs may be an underutilized, potentially powerful tool to motivate improved performance. Further, downside-only PIMs can motivate performance improvements without adding reward payouts that can put upward pressure on bills.
2: Return on equity (ROE) and shared savings incentive structures lead in popularity and dollars awardedIn the PIMs Database, we categorize PIMs as having one of four incentive designs, as shown in the graphic below:
The tables below summarize how frequently each structure shows up in the database and how rewards were achieved from 2020 to 2023.
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
ROE basis points and shared savings incentive structures produce the highest average rewards. In 2023, utilities earned $92 million in PIM rewards, of which $58M (63 percent) was the result of 12 ROE-based PIMs and $27.6M (30 percent) was earned based on seven shared net benefits PIMs. Six fixed amount PIMs and five percentage adder PIMs accounted for the remainder.
Takeaway: ROE basis point PIMs are often associated with the largest awards because they scale with the rate base. That scale can send a strong signal, but it also raises a practical question: Are such large rewards necessary to motivate better performance? For commissions using ROE-based incentives, cost-benefit analysis can help confirm that ratepayer benefits exceed the cost of rewards and that incentive levels are right-sized. In contrast, shared net benefits PIMs provide a “built-in” way to ensure ratepayers benefit more than they pay for the level of achieved performance improvement.
3: Percentage adders are rare, but often achievedThough ROE basis points and shared net benefits are the most common incentive structures and yield higher rewards for utilities, percentage adders have the most consistent achievement rates.
In 2023, less than half of utilities with ROE-based PIMs were successful in earning a reward, while shared net benefits PIMs were just above 50 percent. Utilities under fixed amount-based PIMs had the lowest achievement rate (27 percent). In contrast, 100 percent of PIMs with percentage adder incentive structures were achieved in 2023.
Why might utilities achieve performance targets under adder-based PIMs more consistently? Used for climate-forward efficiency, demand flex, and electrification, many percentage adder-based PIMs are tied to program delivery targets (e.g., demand response enrollment and peak reduction) rather than broad system outcomes. Utilities are accustomed to managing, measuring, and reporting these metrics through established processes. Another possibility is that the program performance target may tend to be set closer to expected (or planned) delivery levels rather than “exemplary” performance. If so, higher achievement rates could reflect target calibration as much as the incentive structure itself.
Takeaway: It’s not clear why utilities are more successful at achieving targets under percentage adder-based PIMs. While this approach may be appealing for its close tie to observable program delivery, there may be an opportunity to increase target ambition to motivate better performance.
4: Equity-focused PIMs are growing in frequency, and utilities are generally achieving their targetsEquity is the fifth most common emergent topic for PIMs in the database, and also one of the fastest-growing emergent topics in the database (21 equity-focused PIMs have been created since 2021). Other fast-growing topics include demand flexibility and climate-forward efficiency. Equity PIMs are also frequently co-labeled with the topics of reliability (3 PIMs) and affordability (12 PIMs).
Six jurisdictions (CO, NY, NJ, MA, IL, and DC) account for all the equity-focused PIMs we are aware of. These PIMs look different in each jurisdiction, using different metrics. Of these PIMs for which there is performance data, 100 percent were achieved or consistently achieved to date.
Takeaway: Equity is a significant and growing area of regulatory focus. This growth likely reflects a broader policy shift in these states toward explicitly requiring commissions and utilities to consider equity in planning and program design — often alongside affordability and goals to reduce low-income customer energy burden. Given the early trends in utility success rate with achieving equity-focused PIM targets, there may be an opportunity for regulators to either (a) consider strengthening the targets of equity-focused PIMs before renewing them, or (b) consider where the application of symmetrical or downside incentives is warranted.
5: Short-term PIMs dominate, with no-end-date options for fuel cost-sharing PIMs.The majority of PIMs (84 percent) within the database are designed to sunset after two to three years. Only 4 percent of PIMs have planned implementation lives of five years or more, and even fewer (3 percent) are established for a single year. The breakdown is shown in the chart below.
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
This pattern suggests commissions often treat emergent PIMs as time-bound experiments rather than permanent features. This allows for testing a metric and observing utilities’ performance before deciding whether to continue, redesign, or retire the PIM. That is a healthy approach for newer policy priorities where measurement, baselines, and understanding of the utility’s ability to influence outcomes are still evolving.
However, not all PIMs are short-term experiments. Some have no end dates. Of those in the database, two-thirds are fuel cost risk sharing mechanisms. These mechanisms are more likely to be open-ended because consistency creates regulatory certainty and supports longer-term planning (e.g., informing procurement and hedging practices), which in turn shapes near-term fuel cost outcomes. The remaining no-end-date PIMs are associated with non-wires alternatives and distributed energy resource-related priorities — areas where commissions may similarly value long-lasting incentives and regulatory certainty. Given their open-ended nature, regulators should evaluate these PIMs on a recurring basis and make the findings transparent, so designs remain fit-for-purpose and performance expectations stay appropriately calibrated over time.
Takeaway: PIM duration should be topic specific. Short terms can support learning and redesign for emergent outcomes, and are best paired with a clear ex post evaluation. That said, shorter-duration PIMs may not provide sufficient time for the fruits of utility actions or process changes to be measured.
What these insights say about the landscape of emergent PIMs in the United StatesIn recent years, utilities have consistently met PIM targets, earned incentives, and avoided penalties when they are at stake. This can be due to two reasons: targets may be set at readily achievable levels, and/or emergent PIMs may be motivating real performance improvements. Both can be true at the same time, and it is hard to determine which factor is at play in the aggregate.
However, these two explanations can be easier to disentangle at the individual PIM level. Regulators can conduct recurring, transparent, and comprehensive evaluations of a PIM to uncover whether it was effective and why. Such reviews can provide the basis for testing more ambitious targets, adjusting incentive design, and ensuring that rewards are not overused where penalty-based incentives could provide sufficient motivation without increasing costs to ratepayers.
With more data available, regulators can now compare PIMs across jurisdictions and designs, continuing to improve PIMs in service of policy goals — everything the PIMs Database was built to support.
The post 5 Things We Learned from Analyzing More than 200 Utility Incentives appeared first on RMI.
Hydrogen trucking for India: economics, opportunities, and way forward
The post Hydrogen trucking for India: economics, opportunities, and way forward appeared first on RMI.
New Ways to Power Data Centers and Other Large Energy Users
Note: In this insight brief, “tariffs” refer to electricity rate tariffs that govern utility services, not trade-related import/export tariffs.
Large energy users such as data centers and other advanced manufacturing facilities are driving demand for electricity. This demand is outpacing the rate at which existing resource planning, procurement, and market processes can identify and integrate new generation in the United States. This mismatch is raising concerns for public utility commissions and grid operators as they consider how to connect large loads without comprising system reliability, affordability of electricity bills, and state decarbonization policies.
To address this, states are turning to large load tariffs to bring large energy users onto the grid in a transparent, standardized way. These tariffs are focused on establishing (1) rates that account for large loads’ potential grid impacts, and (2) measures that reduce the risk of cost increases to other ratepayers, primarily by focusing on the risk of overbuilding due to load that doesn’t materialize. We will refer to this kind of tariff as a “baseline” large load tariff.
Although valuable for transparency and risk mitigation, a “baseline” large load tariff typically doesn’t contain provisions that speed up getting more energy online or that enable customer choice. To realize these additional benefits, a baseline tariff can be complemented by a Bring-Your-Own (BYO) tariff, which defines differentiated rates if large energy users pay for new power resources themselves, allowing new resources to be added quickly and dynamically. These BYO taffirfs can be a separate tariff or be implemented as a voluntary element of a baseline tariff. Eligible resource types can be restricted to clean energy under a subtype of BYO tariffs, Clean Transition Tariffs. Stakeholders should evaluate eligibility rules to determine which resources can participate in BYO tariffs and consider how BYO tariffs can align or conflict with policy goals on decarbonization and affordability.
Procurement under BYO programs can be arranged in a variety of ways
The post New Ways to Power Data Centers and Other Large Energy Users appeared first on RMI.
Tired of Gasoline Prices? Here’s a Surprising Way to Save Money
Despite federal EV tax credits ending last year, most car buyers who purchase an EV will save money in the long-run. It’s their high up-front cost that’s the problem — right?
Here’s what no one seems to be talking about — used EVs are the same price or cheaper than their gas-powered equivalents. And in the United States, most people buy used cars, not new ones — 3 out of every 4 cars sold are pre-owned.
For the budget-minded, choosing a 2022–2024 pre-owned EV from the ten most common electric models in the United States offers a sticker price on average 10 percent less than a comparable used gas car. For the most popular luxury EVs, such as the Tesla Model S and Ford Mustang Mach-E, used options tend to sell for around the same range as an entry-level to mid-range used luxury gas car.
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
A car buyer can begin saving money immediately by choosing a used EV instead of a gas-powered vehicle with the same sticker price. And those savings only multiply with lower maintenance and fuel costs from going electric.
The average American spends more money on gasoline than on electricity and natural gas combined. Drivers who charge daily at home can normally cut their annual fuel expenses $800–$1,000 compared to gassing up at the pump.
If we want to talk about energy burdens and affordability, we have to talk about cars. This single change — switching to an EV — can cut a driver’s operating costs 40–65 percent depending on how they charge.
Big Takeaways- Low-cost used EVs cost 10 percent less on average than their gas equivalents, and mid-range EVs tend to be similarly priced. In August 2025, the difference in sale price between a used EV and a used gas car fell to just $897 across all price ranges – economy to luxury.
- Fuel and maintenance are where EV drivers keep saving. Electricity in general boasts a cheaper cost per mile and more stable and predictable prices than gas, while maintenance costs stay low thanks to fewer moving parts and less wear.
- Lease returns and trade-ins will only continue to boost the supply of affordable EVs. With almost 75 percent of US EV transactions in 2025 leases, over 1 million EVs are projected to enter the used market over the next 3 years as leases expire.
Batteries are proving to last 10–20 years longer than first expected and most EVs on the road today are operating with their original battery.
Real-world driving has proven EV batteries last up to 40 percent more than predicted in early lab tests. Typical stop-and-go traffic and on-road conditions are less harsh than constant lab cycles, potentially extending the battery’s usable life 300,000 miles or more — more durable than gas engines.
A standard American gas car tends to have a useful life of about 12 years or 150,000–200,000 miles before repairs begin to exceed its resale value.
EV battery replacements are expensive. How long a car battery will last will depend in part on when your EV was manufactured. But many battery replacements are covered by warranty, even for used EVs. Federal law requires a minimum 8-year or 100,000-mile coverage for EV batteries. Some states and manufacturers have extended this to 10 years or 150,000 miles. Most warranties will replace a battery that drops below 70 percent capacity before the eight-year mark. Used or refurbished batteries are also a growing option, which can keep costs down when a replacement is necessary.
Before making a purchase, check the battery age and consider how much you’ll be able to save until you need to make a replacement.
ChargingThe convenience and cost of charging an electric vehicle are important factors to consider. While public vehicle chargers are becoming more available, most EV drivers charge at home — often overnight when electricity demand is at its lowest, which could help them save on their electricity bills.
There are two main ways to get a vehicle plugged in at home. Plugging a vehicle into a basic home outlet (Level 1 charging) is one option to consider. This method is even possible in many multifamily homes like duplexes, fourplexes, or low-rise townhouses or condos, with the help of an extension cord. Since this method relies on existing plugs (and a charging cord that was likely included with the purchase of the vehicle), it is the cheapest option to adopt. It will take longer to charge, but most people can just charge overnight.
Level 2 chargers are another option. Faster than Level 1 chargers, these chargers can be installed in a garage or at a parking spot. Level 2 chargers typically cost between $1,200 and $3,000, including materials and installation, but many electric utilities offer incentives that can cover some or all of this cost. 84 percent of the United States is covered by a program that offers EV charger rebates or incentives, according to Briteswitch, which also provides info on local programs.
Roughly 60 percent of Americans now live within two miles of a public charger. 3,300 public fast-charging stations came online in 2025 — meaning in just one year, the number of public fast-chargers grew by 30 percent. This comes despite a rocky rollout for the National Electric Vehicle Infrastructure (NEVI) program. So far, states have tapped only about 2 percent of the $7.5 billion available for DC fast-charging, and now that a federal court has overthrown the suspension of NEVI, projects are again coming back online. By 2030, a fast charger should be available every 50 miles along any major highway.
Electricity pricesElectricity bills are rising across the country due to higher demand, and many advocacy groups, policymakers, regulators, and utilities are working to address electricity affordability and stabilize rising costs. Even as these prices rise, driving and charging an electric vehicle is still going to be cheaper than a gas-powered car over the course of the next decade. Even if electricity prices doubled, an EV would still be less expensive to operate, given the additional maintenance savings.
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
As decision-makers implement solutions to reduce electricity prices, the concerns about the cost to charge will likely dissipate. In fact, one proposed method is to lower rates for electric vehicles, which typically can be charged at off-peak hours to avoid the highest demand hours on the grid.
InsuranceEVs are usually more expensive to insure than gas cars, but not always. This can be due to more EVs being luxury cars, repair markets still getting up to scale, and some car components being more expensive. As the repair market grows, costs for repairs — and therefore insurance — may come down.
Used EVs offer reliefThe biggest barrier is simply this: not enough people know they could be saving a lot of money by going electric. The next time they buy a used car, they can start saving money right away.
That money is then available for groceries, education, medical needs, and more. One out of three families currently have to pass on these essentials now due to large energy bills. This relief offers breathing room and security.
RMI is exploring many ways to make energy cost less. Learn more about how we can cut energy bills in half.
The post Tired of Gasoline Prices? Here’s a Surprising Way to Save Money appeared first on RMI.
Winter Storm Fern Highlights the Need for More Resilient Transmission
Winter Storm Fern swept across the United States this past week dumping snow and ice and wreaking havoc from Arizona to Washington, D.C. In addition to the tragic loss of life, almost 1 million people lost power, some of whom are still without power, creating difficult and dangerous living conditions, and costing families, utilities, and states a lot of money. During a particularly strained hour on the afternoon of January 25th, prices in one zone topped $1,800 per megawatt-hour — an order of magnitude higher than average prices during the weeks before the storm. Unfortunately, extreme weather events are becoming more common (and more extreme).
How can we better prepare for the next big storm? In a few ways. Strengthening electricity infrastructure and enabling more interconnected transmission infrastructure could have helped reduce both outages and costs. And, on the customer side, improving the efficiency of housing can relieve both grid and cost stress. Updating homes to just a 2009 building code can keep them above 40 degrees Fahrenheit for nearly two days in sub-zero temperatures.
Below, we dive into how our grid can evolve to make the next “Fern” less impactful.
What RMI is doing
RMI provides utilities and regulators with the tools they need to make smart investment decisions on both large- and small-scale solutions, from transmission lines and utility-scale renewables to efficiency and distributed energy resources. Our resources include The State Regulator’s Role in Transmission, a handbook for US state regulators on how to advance proactive transmission buildout to reduce costs for ratepayers; our Transmission Resource Library, a downloadable spreadsheet with a list of all major reports on transmission going back to 2004; and a webinar that brought utilities, grid operators, and regulators together to discuss how to deploy advanced transmission technologies to boost capacity, improve flexibility, and speed new energy integration.
Sharing electricity across regionsThe US grid is made up of geographically distinct transmission planning regions that share power with each other when necessary. For example, if there is low energy availability or high-priced electricity in one region, it can be supplemented with lower-priced available energy from a neighboring region.
During Fern, neighboring regions supported each other wherever possible. When one area had excess electricity, it sent power to other regions facing shortages — but only up to a point.
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
Power sharing is limited by contractual and infrastructure constraints. Transmission lines, like water pipes, restrict how much electricity can move between regions. So even if one area has surplus power, insufficient transmission capacity often keeps it from reaching places in need.
Research shows that just increasing the efficiency with which we utilize existing lines can save hundreds of millions of dollars per year. Beyond that, more interregional transmission planning and buildout is necessary to increase system-wide reliability while meeting needs more cost-effectively.
Transmission constraints drive huge price differencesWhen transmission is constrained and regions cannot share power, electricity prices can vary drastically, even within the same grid.
For example, MISO, the transmission organization that covers parts of 15 states in the Midwest and South, is made up of three different regions: north, central, and south. In the beginning of Fern, cold temperatures and low wind speeds in the northern states made wind power production plummet and constrained gas availability. Meanwhile, their southern MISO counterparts and neighbors in SPP were flush with higher wind generation than expected and a less constrained gas system. As a result, MISO north customers were left paying much higher prices (2 to 15 times as much at times) than their neighbors.
More transmission capacity between these regions could have allowed lower-cost power to serve more customers, providing relief for ratepayers. Similarly, in PJM, which primarily covers states in the Mid-Atlantic region, the limits on transmission availability meant that some customers were paying much higher prices than others. And in Texas, on January 25, average electricity prices between the northern and southern parts of the state differed by more than $700 per megawatt-hour in the real-time market.
window.addEventListener("message",function(a){if(void 0!==a.data["datawrapper-height"]){var e=document.querySelectorAll("iframe");for(var t in a.data["datawrapper-height"])for(var r,i=0;r=e[i];i++)if(r.contentWindow===a.source){var d=a.data["datawrapper-height"][t]+"px";r.style.height=d}}});
More interregional and intraregional transmission availability could have helped keep prices down for customers. To increase the ability to share power across regions, we need to increase transmission capability on existing lines and plan and build new interregional lines to enable more power sharing.
Strengthening electricity infrastructureThe ice that Fern brought damaged and downed some power lines as well. Initial damage assessments show over 470 miles of affected transmission lines, leaving hundreds of thousands of people without power. This was especially damaging in southern states, where the cold temperatures pushed the electricity infrastructure past its limits.
Hardening transmission and distribution infrastructure, for example by using advanced conductors with anti-icing coatings and real-time monitoring sensors, not only protects lines from extreme cold but also boosts grid capacity overall. These upgrades help reroute power and ensure reliable power delivery during increasingly severe and prolonged storms, reducing the need for repeated fixes (as experienced by crews working through ongoing hazards to restore power in Middle Tennessee Electric territory). Finally, strategic undergrounding, though more costly up-front, can further safeguard lines from extreme weather and limit recurring repair expenditures on the same infrastructure.
A grid that works better — in calm and crisisWinter Storm Fern made one thing clear: the power system we rely on every day is being pushed beyond the conditions it was designed to handle. As extreme weather becomes more frequent, more intense, and more geographically widespread, the costs of outages — in lost power, lost lives, and lost economic activity — will only grow.
A more resilient grid requires both stronger transmission and smarter planning. Regulators play a central role in making this possible by supporting both planned and new transmission expansion and upgrades that deliver broad reliability and cost benefits, including projects that improve interregional power sharing. Legislators can also encourage grid modernization technologies that increase capacity on existing lines as well as threat awareness and responsiveness. And it’s important to take a long-term view of costs, recognizing that investments that reduce outages and price spikes can save customers and utilities money over time.
Likewise, improving home energy efficiency can reduce overall demand on the grid, lower customer bills, and help homes maintain safe indoor temperatures for longer during outages.
Inaction has a cost. Investing now in stronger, more interconnected, and more resilient transmission can help ensure the power system works not just on clear days — but when communities need it most.
The post Winter Storm Fern Highlights the Need for More Resilient Transmission appeared first on RMI.
Financing Community Clean Energy Projects in 2026
2025 marked a structural shift in clean energy and community development finance. Federal programs had been providing or promising flexible capital to make clean energy projects less risky for lenders and investors. Many of those programs are now gone. While that has upended workplans and made financing harder, it has not reduced demand nor commitment for clean energy in communities.
Against this backdrop, RMI convened 70 practitioners in late 2025 from green banks, community lenders, regional and commercial banks, and impact investors to surface the most pressing challenges and priorities for 2026. The message was clear: organizations are moving forward, even in tougher terrain. Participants remain motivated and are actively seeking solutions to ensure communities have access to resilient sources of capital for clean energy projects when federal dollars aren’t available.
Across conversations, one familiar but unresolved challenge rose to the top: many community clean energy projects can work on paper, but they don’t fit mainstream capital’s “credit box” — the criteria banks and investors use to decide what they will fund, including cash flow predictability, counterparty credit, and deal size and structure. This misalignment is most acute for smaller deal sizes, in new markets, or with unfamiliar or credit-constrained counterparties.
Federal programs were designed to help bridge these gaps by providing flexible capital that could absorb risk and fragmentation. With that support receding, the work ahead requires sharper execution: clearer roles, stronger coordination, and financing approaches that help projects fit within the credit box without relying on perpetual subsidy.
The convening brought to light four priorities for 2026:
- Fix affordability gap: Strengthen concessional balance sheets for institutions that can absorb cash flow risk and provide products that improve project economics for low-income and underserved customers.
- Address risk perception gap: Map and standardize credit enhancements to build investor confidence and move from bespoke risk mitigation to scalable structures.
- Close market access gap: Identify asset classes ready for standardization and aggregation, and support warehousing to connect small or fragmented assets to secondary markets.
- Resolve ecosystem capacity constraints: Invest in subnational financing ecosystems that can turn localized solutions into investable markets by diagnosing constraints, enabling institutional specialization, and strengthening coordination across the finance stack.
Most climate finance work, at its core, is about moving assets into the credit box. Trying to convince lenders and investors to abandon their risk-return requirements is a dead end; the work is in identifying and addressing the specific frictions that keep otherwise viable projects from being financed.
In practice, clean energy assets tend to fall outside the credit box for one or more of three reasons.
The first is an affordability gap. This is a failure of economic viability where projects don’t generate sufficient or stable cash flows at price points end users can afford, failing the credit box’s cash-flow and repayment assumptions. Even when technologies are cost-effective at a system level, the revenue model breaks at the household, small business, or community level, particularly in low-income or underserved markets. This is fundamentally a cash-flow problem, not a technology or performance risk issue.
The second is a risk perception gap, where assets may cash flow on paper, but investors are uncomfortable with real or perceived risks — including performance uncertainty, counterparty credit quality, or regulatory and policy exposure — and they demand protections accordingly. Unfamiliar risks are frequently overweighted, keeping otherwise viable projects sidelined because investors aren’t confident that assets will perform as advertised.
The third is a market access gap, where assets can’t reach investors who want to buy them. Even when projects perform well individually, they may be too small, bespoke, or scattered to meet investors’ size and standardization needs. Because each deal is different, lenders and investors must spend significant time and money to review, structure, monitor, and service them, and those costs can outweigh the returns. This is made worse by inconsistent deal flow, limited performance track records, and too few actors positioned to hold projects on their balance sheets long enough to enable bundling them, building scale, and bringing them to larger, more liquid secondary markets.
The priorities for 2026 that surfaced in our convening flow from these gaps.
Priorities for 2026 to Align Projects with Investor Requirements Fix affordability gap: address the economicsWhen affordability is the binding constraint, the solution needs to improve what customers can actually pay, not shift risk around the capital stack. Tools like guarantees protect lenders after default, but they don’t reduce the likelihood of default.
Affordability tools improve project economics. On-bill mechanisms make repayment easier and more reliable by tying payments to utility bills and expected savings. Interest rate buydowns lower monthly payments, improving borrower cash flow. Lease structures can lower upfront costs or shift performance and maintenance risk away from customers. Technology bundling can also lower costs in certain instances, such as when pairing efficient heat pump upgrades with rooftop solar results in more affordable electricity.
2026 priority: Strengthen concessional balance sheets for institutions that directly address affordability, such as green banks and community lenders, so they can continue serving customers with affordable, accessible financing. Address risk perception gap: reallocate or clarify riskEven when cash flows are adequate, investors may hesitate if they don’t trust the counterparty or don’t fully understand performance risks. This is where credit enhancement tools are most effective. Guarantees can protect against downside outcomes, especially for newer or unfamiliar asset types. Insurance can transfer specific, well-defined risks. Loan loss reserves can absorb expected losses when defaults are possible but limited.
Standardization helps here, too. Consistent underwriting, contracts, and performance data help make unfamiliar risks clearer, more comparable, and easier to price.
Today, credit enhancement tools are often highly customized and designed deal-by-deal. While helpful in specific cases, this fragmentation makes it harder to attract larger pools of capital.
2026 priority: Map and standardize existing credit enhancements to move from deal-by-deal risk support toward structures that enable scale and attract larger pools of capital. Close market access gap: build liquidity pathwaysEven well-performing assets can’t scale if they can’t reach liquidity. Moving capital at scale requires a sequence of steps: first, standardizing rules, contracts, and data where appropriate; then, aggregating assets through warehousing or pooling; and finally, accessing secondary markets.
Intermediaries play a critical role in this process. Bond banks and other centralizing entities or capital markets-facing intermediaries can turn small or fragmented projects into investable portfolios or securities. They lower the cost of capital by pooling assets and making it easier to sell or refinance assets once they reach scale.
Credit enhancements may be required at the point of sale to meet investor requirements. But the constraints show up earlier — in how assets are originated, standardized, aggregated, and held. Credit enhancements can’t substitute for those steps.
2026 priority: Identify which asset classes are ready for standardization and aggregation and clarify which institutions can warehouse and centralize assets to connect them to secondary markets. Resolve ecosystem capacity constraints: strengthen subnational financing ecosystemsEcosystem and institutional capacity constraints determine whether the solutions to the three gaps described above can be developed and applied effectively.
Subnational financing ecosystems could be a powerful forum for coordinating the problem-solving and action needed in the years ahead. With federal pullback — and because conditions vary widely by place — these ecosystems are where solutions to the three gaps must ultimately be executed.
In practice, however, subnational financing ecosystems are themselves constrained because many places lack institutional capacity, functional coverage, and coordination to deploy solutions effectively.
This shows up today in a few ways. In many places, institutions are too small or undercapitalized to operate at scale; key entities that should play critical ecosystem functions are missing or underleveraged; and coordination remains weak — both among local actors and between local markets and the secondary capital markets they depend on.
Subnational financing ecosystems can become engines for action across the other three priorities outlined above, but only if underlying capacity constraints are addressed through investment in three essential priorities.
- Diagnosis and learning: identifying which constraints are binding for specific assets and communities, testing solutions, and building a place-based track record over time.
- Role clarity and coordination: enabling institutions to focus on what they do best and what the market needs — whether customer-facing origination and affordability, credit enhancement, or warehousing, aggregation, and capital markets access — rather than duplicating every function everywhere and competing for the same limited pools of concessional capital. Scaling the right interventions depends on clear, differentiated roles, sufficient institutional capacity, and effective coordination mechanisms.
- Capital translation: connecting local lending activity to national and institutional capital markets by converting fragmented assets into standardized, investable portfolios and turning local proof points into models that can scale.
To overcome longstanding challenges in affordability, risk perception, and market access, the next phase of community clean energy finance must focus on moving assets into mainstream capital’s credit box at scale without subsidy. That means building subnational systems that can do this work and endure as federal support ebbs and flows.
In practice, this comes down to building financing systems that make projects affordable for customers, reducing perceived risk for investors, and creating clear pathways to scale. Rather than relying on one-off tools, the emphasis shifts to how these elements work together consistently across markets.
Delivering on these priorities will require capital sources better suited to long-term market building — and, critically, will create the conditions for more of that capital to participate. Local deposits can anchor community lenders and green banks focused on affordability and origination. Centralizing entities can manage complexity and timing mismatches, aggregate assets and demand, and connect local lending activity to secondary markets and pooled issuance platforms. Institutional investors and bond buyers can then provide the liquidity needed to recycle capital and scale what works.
Progress in addressing binding constraints across affordability, risk, market access, and subnational capacity is connected and reinforcing. The result is a financing system that can support community clean energy investment at scale across regions and regardless of the availability of federal support.
The post Financing Community Clean Energy Projects in 2026 appeared first on RMI.
The Fine Print I:
Disclaimer: The views expressed on this site are not the official position of the IWW (or even the IWW’s EUC) unless otherwise indicated and do not necessarily represent the views of anyone but the author’s, nor should it be assumed that any of these authors automatically support the IWW or endorse any of its positions.
Further: the inclusion of a link on our site (other than the link to the main IWW site) does not imply endorsement by or an alliance with the IWW. These sites have been chosen by our members due to their perceived relevance to the IWW EUC and are included here for informational purposes only. If you have any suggestions or comments on any of the links included (or not included) above, please contact us.
The Fine Print II:
Fair Use Notice: The material on this site is provided for educational and informational purposes. It may contain copyrighted material the use of which has not always been specifically authorized by the copyright owner. It is being made available in an effort to advance the understanding of scientific, environmental, economic, social justice and human rights issues etc.
It is believed that this constitutes a 'fair use' of any such copyrighted material as provided for in section 107 of the US Copyright Law. In accordance with Title 17 U.S.C. Section 107, the material on this site is distributed without profit to those who have an interest in using the included information for research and educational purposes. If you wish to use copyrighted material from this site for purposes of your own that go beyond 'fair use', you must obtain permission from the copyright owner. The information on this site does not constitute legal or technical advice.
This site is not the official webpage of the Industrial Workers of the World.
