Rocky Mountain Institute

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As demand for affordable, reliable, clean transportation continues to grow, cities are looking to complement existing transportation offerings with more flexible alternatives. An emerging mobility solution, electric vehicle (EV) carshare, provides flexible, short-term access to clean vehicles. Like any carshare model, an EV carshare program bundles the car’s sale price, insurance, maintenance, and other expenses into subscription or rental pricing. With fuel, insurance, and all costs associated with car ownership rising — owning and maintaining a personal car typically costs about $12,182 per year on average — EV carshare offers an affordable, lower-emissions alternative.

A growing number of cities are deploying this solution to address local mobility, transportation affordability, and air quality challenges. However, there are many considerations that must be included in program design. Equitable mobility objectives must be balanced with financial sustainability. Site locations must be carefully chosen to support key program goals. It is critical that cities identify which community goals to prioritize and how to meet those objectives.

Throughout the past year, RMI worked with three US cities with very different built environments and populations to help identify successful business models to launch (or expand) and maintain EV carshare. In the lead-up, the RMI team surveyed over two dozen existing carshare programs from across the country and directly interviewed eight. Through the interviews and working directly with the cities, the team identified lessons on site selection, insurance, operational challenges, and solutions. This guide is intended to help cities and other local partners learn best practices for EV carshare programs and evaluate the business models that may work well in their unique operating and built environments.

The post Driving Electric: Designing EV Carshare to Expand Access to Affordable, Reliable, Clean Transportation appeared first on RMI.

What is light fuel oil, and why does it matter?

Light fuel oil is a refined petroleum product similar to diesel, and is burned in generators to produce electricity. Island energy systems import this fuel by tanker, burn it locally, and pass the cost directly to governments and consumers. When global oil markets experience shocks like today’s crisis in the Middle East and the Strait of Hormuz, island energy security and costs are directly impacted.

The numbers:

• EIA Global Energy Outlooks 2025 and 2026 have stark differences, In just one year, the 2050 cost projections of light fuel oil-based power rose from $0.29 to $0.45/kWh — a ~33% increase driven by geopolitical disruption in global oil and gas flows.
• For a single 50 MW island power system, that translates to roughly $34 million more in annual fuel costs
• Meanwhile, solar + battery storage projections declined by ~46% to $0.07/kWh in 2050, wind + storage by ~40% to $0.06/kWh, and geothermal is currently at $0.09/kWh.
• The gap between fossil and clean has never been wider or more consequential.

A shared system challenge — and opportunity

The ongoing conflict in the Middle East has constrained a significant share of global oil and gas flows, sending ripple effects through fuel, electricity, and commodity markets worldwide. Clean electricity has transformed from an emerging option into a proven, scalable, and now dramatically cheaper pathway than the imported fuels it replaces.

The energy vulnerability that imported fuels create is not unique to one island. It is a shared system challenge, and the solution is the same everywhere: domestic, diversified, technology-driven clean power that doesn’t arrive by tanker.

Cost-effective solutions including peak demand reduction, virtual power plants, and new approaches to energy storage offer proven ways to grow with less risk and less capital. Those advantages compound over time, delivering both energy security and reduced fiscal pressure.

Why now?

• Fresh data from EIA’s Annual Energy Outlook 2026 vs. 2025 provides a rare apples-to-apples cost projection comparison that makes the fuel shock visible in real numbers.
• RMI has been tracking levelized cost of energy trajectories across more than a dozen island systems in the Pacific, Caribbean, and Indian Ocean.
• Continued reliance on fossil fuels risks deepening fiscal stress, price volatility, and policy trade-offs, while accelerating the clean energy transition provides a more credible path to resilience, affordability, and reduced systemic risk.

A Caribbean transition

 The Caribbean’s energy transition represents a transformational opportunity to break free from dependence on volatile fossil fuel markets and reshape the region’s development trajectory through renewable energy and energy efficiency — reducing costs, strengthening energy security, and building resilience against climate change. To guide this shift, RMI’s A Caribbean Regional Transition Scenario offers seven major categories of transition milestones that span policy frameworks, financial mechanisms, equity considerations, and public participation. Each section is broken down into supporting activities and key stakeholders to serve as a practical implementation roadmap.

The post As Islands Grapple with Spiking Fuel Costs, Renewables Offer a More Secure and Affordable Option appeared first on RMI.

As spring weather arrives, drivers in electric vehicles (EVs) may notice that their cars are going farther between charges. They aren’t imagining things — like all vehicles, EVs operate more efficiently in temperate weather. To help grid planners and regulators better account for these seasonal effects, RMI is releasing a set of new scenarios in our GridUp EV load forecasting tool to showcase how changes in temperature can affect EV charging demand throughout the year.

What factors affect EV efficiency?

A vehicle’s efficiency boils down to two main factors: the friction it needs to overcome to keep moving forward, and the energy it uses to keep the passenger comfortable through air conditioning or heating (often called auxiliary energy use).

Friction reduces vehicle efficiency in three main ways: air resistance, rolling resistance (tires on the road), and drivetrain losses. In the case of air resistance and drivetrain losses, EVs are often more efficient than internal combustion engines, thanks to design decisions that reduce resistance and far fewer moving parts.

All vehicles, including EVs, use more auxiliary energy when the ambient temperature is either colder or hotter than what is comfortable (such as 68°F/20°C). In these conditions drivers use climate control systems to heat or cool the cabin. This is energy intensive, especially on very hot or cold days. While some electric vehicles use heat pumps to improve climate control efficiency, warming a vehicle requires more energy when the ambient temperature drops regardless of the technology used.

EVs also have a third, smaller factor that can impact their charging speed. Low temperatures can affect battery performance for most common battery chemistries, so some vehicles are designed to heat the battery pack to keep it within an optimal temperature range. This impact is typically only noticeable during high-speed charging in very cold weather, when the vehicle needs to warm the battery more to receive the higher power of a fast charge.

Why does EV efficiency matter?

Vehicle efficiency dictates overall energy demand, regardless of the fuel source. The efficiency of the EV fleet — including variations due to temperature — has important implications for the electric grid: all else equal, a less efficient EV fleet will require building more charging and grid infrastructure to meet the greater demand. While there are tools to mitigate the impacts of EV charging on the grid, making good, data-driven investments relies on decision makers at utilities and regulatory agencies being able to anticipate the scale and location of EV charging demand. This led us to develop our EV load forecasting tool GridUp.

This latest update to GridUp, which incorporates EV efficiency variations throughout the year, helps stakeholders such as utility distribution system planners and public utility commission regulatory staff gain more confidence in their ability to make the prudent infrastructure investments needed to serve EV load.

Additionally, while EVs have zero tailpipe emissions, their efficiency still influences upstream power sector emissions. As three-quarters of US electricity still comes from nonrenewable sources, lower EV efficiency means burning additional fossil fuels and therefore greater carbon and local air pollutant emissions (although EVs still have a much smaller carbon footprint than gasoline vehicles).

In numbers: the seasonal temperature effects on EV charging energy demand

To demonstrate how seasonal temperature changes can affect the energy needed to charge EVs, let’s take a closer look at the results from the new, temperature-dependent GridUp scenarios for two cities with very different climates: Phoenix and Minneapolis. We modeled the energy use of millions of trips individually, incorporating trip speed and seasonal snapshots of ambient temperature based on hourly weather data to determine how changes in operating friction and climate control use impacted the amount of energy used by a vehicle.

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Phoenix

In Phoenix, the average daily temperature is 76°F (24°C) year-round. On days like that, GridUp’s forecast for unmanaged EV charging in 2035 shows peak power demand reach 2,525 MW. However, on a hot day in July, the temperature climbs to a sweltering average temperature of 96°F (35°C). Then the peak power for charging rises 14% to 2,871 MW. In other words, hot days result in significantly increased energy and power demand from these vehicles, primarily from air conditioning usage. (Gasoline usage is also higher on these days, as drivers of all car types use more energy to cool down.)

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Minneapolis

In Minneapolis, the average daily temperature is 47°F (8°C) year-round. During these days, GridUp’s forecast for unmanaged EV charging in 2035 shows peak power demand to be 387 MW. However, the temperature can plummet to a frigid 16°F (-9°C) on average in January. The peak power for charging then rises dramatically to 540 MW, 39% above the median day. Cold weather also brings additional energy and power demand for cars as drivers try to stay comfortable and their vehicles must overcome an increase in air resistance.

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Seasonal temperature swings change the shape and size of loads that utilities and regulators must plan for, not just the range of an individual EV. For grid planners, relying on EV load forecasts that only consider average conditions can systematically underestimate energy needs for charging, especially during extreme weather, which already stresses the grid. Understanding seasonal variation in vehicle efficiency is a prerequisite for making prudent, least-cost investments that keep costs down and improve reliability.

Consider an example from Minneapolis: In 2035, EV charging is excpected to draw 5,496 MWh for an average temperature day compared to 7,433 MWh in our cold scenario, and this difference of 1,947 MWh occurs day after day. At the end of a cold month (e.g., January), energy demand from charging exceeds an average scenario by 60,357 MWh. Perhaps more importantly, if even a fraction of this demand lines up with evening hours when winter peaks often occur — almost a certainty given typical unmanaged charging patterns — feeders, transformers, and generation capacity that are adequate in an average scenario may become constrained. Planners should treat seasonal EV efficiency as a key part of preparing for peak conditions in different parts of the year.

Whether the weather is hot or cold, utilities and regulators have a set of options to mitigate the impact of EV charging demand; the key will be to plan ahead using good data and planning tools, and take advantage of such opportunities. For example:

• Utilities can and should lean into managed charging and other load management strategies to shift charging to off-peak hours, reducing the need for infrastructure to be built solely for extreme-weather conditions.
• Utilities, regulators, consumer advocates, and other stakeholders can support these cost-effective options by earnestly incorporating EV load flexibility into planning exercises, prioritizing development of programs to harness this flexibility, and ultimately making participation easy for customers.

The new seasonal scenarios in the GridUp tool are designed to make this actionable: they can be used to stress-test infrastructure planning against extreme conditions, model how much incremental load shows up on extreme days, and, importantly, explore what amount of flexibility can be obtained from EV charging to keep upgrades focused where they are truly needed.

RMI’s GridUp Tool

GridUp forecasts when and where energy and power demand will materialize from vehicle electrification. The tool is uniquely detailed and flexible, allowing users to gain greater insight into how driving behavior will create and shape charging demand.

Explore the Tool

RMI would like to thank FedEx for their generous support of this work.

The post How Weather Changes EV Charging Demand appeared first on RMI.

Richard Kidd has seen what happens when energy runs out.

As an emergency logistics officer with the United Nations, Kidd was responsible for ensuring the flow of food, fuel, and water in some of the world’s most fragile environments. In refugee camps, energy isn’t abstract — it’s life or death.

“The refugee camp is the ultimate energy poverty environment,” he says. “If you run out of diesel to run the generators, you turn off the generators that clean the water, and people start to die of waterborne disease. You turn off the generators that provide power to the medical clinics, and you no longer have cold chains to keep medicines effective. Or you turn off the power that provides the lighting and the security, then you have violence.”

That experience shaped how Kidd understands energy: not only as infrastructure, but also as the foundation for human dignity, safety, and survival.

That perspective influenced his approach to driving efficiencies in last-mile logistics, and led him to RMI.

In the early 2000s, Kidd was invited to participate in an RMI design charrette exploring what a net-zero refugee camp might look like — an ambitious idea that brought together thinkers from across disciplines.

“I was brought into the charrette as the refugee camp guy,” he recalls. “I met Amory and the entire Rocky Mountain team. It was really enriching and exciting.” Richard then went on to collaborate with Amory and RMI on Winning the Oil End Game. He also briefed RMI’s board on energy and environmental security.

What stood out for Kidd during these early collaborations wasn’t just the people, but the way they approached problems.

“Two principles I learned from RMI that cascaded through everything were whole-systems integrated design and the idea of ‘making the problem bigger.’ Because then you have more solutions.”

At first, that idea can sound counterintuitive. But in practice, it means stepping back from a narrow technical question to understand the real need behind it. Instead of asking, “How do I heat my house?” you ask, “How do I keep people warm?” That shift opens up entirely different solutions — like better insulation, smarter building design, or passive heating — that can reduce or even eliminate the need for a furnace altogether.

It’s a way of moving from what RMI cofounder Amory Lovins calls the “hard path” to the “soft path.” The hard path focuses on producing more energy — bigger power plants, more fuel, and more supply. The soft path starts by reducing demand through efficiency and smarter design, often solving the problem before new energy is needed.

By expanding the frame, challenges that once seemed intractable become flexible, and new, often simpler solutions come into view.

Those ideas would stay with Kidd as his career evolved.

Kidd went from the UN to the US government, where he spent over 16 years leading public-sector sustainability projects at the Department of Energy, the Army, and later, the Department of Defense.

Initially, he led the Federal Energy Management Program at the US Department of Energy, helping federal agencies meet their sustainability goals through improved building performance, energy efficiency, and renewable energy deployment.

Later, he brought that same systems-thinking approach to the US Army, where he served as Deputy Assistant Secretary for Energy and Sustainability. There, he helped drive significant reductions in energy use, including cutting petroleum consumption in the Army’s vehicle fleet by more than 40% in just a few years.

“Enabling fuel savings required looking at more than just vehicle efficiency. It required examining rule sets and patterns of use,” Kidd says. “In the federal government, the higher the individual’s rank, the larger the vehicle. We changed this and allotted vehicles based on use-cases, matching form to function.”

While with the Army, Kidd implemented what was then the federal government’s comprehensive High Performance Sustainability Design Guide — a set of standards designed to ensure federal facilities are energy-efficient, environmentally friendly, and cost-effective — resulting in the largest portfolio of LEED-certified buildings in the nation. He also led efforts that resulted in the largest pipeline of energy savings performance contracts in the federal government and the deployment of over 700 megawatts of renewable energy systems.

Kidd then served as the deputy assistant secretary of defense for environmental and energy resilience, where he and his team guided policies associated with a $13 billion energy bill and authored the Department of Defense’s climate adaptation and mitigation plans.

Today, Kidd continues to apply that systems-thinking approach as a strategic advisor on energy innovation, decarbonization, and climate resilience. He works with a wide range of clients — from consulting firms and investors to utilities, research institutions, and emerging technology companies — helping them identify solutions that are both commercially viable and socially beneficial.

And he traces this kind of impact back, in part, to the way RMI shaped his thinking.

It’s why he believes the organization’s influence can’t be measured by projects alone.

“RMI’s impact goes far beyond what shows up in an annual report,” he says. “It’s in the people they’ve influenced — people who’ve had some interaction with RMI and then are inspired and go do other things.”

Over time, that ripple effect adds up.

“I would suspect RMI’s cumulative impact… is much higher than the sum of all their annual reports.”

Today, Kidd continues to support RMI as a Solutions Council donor — part of a deliberate giving strategy focused on both humanitarian and environmental work. He sees his contributions not just as charitable, but also as a way to sustain the ideas and insights that have shaped his own work, and a way to help others do the same.

“Every little bit counts,” he says. “This is a collective problem that we collectively have created as a society, and we collectively have to address it.”

For those considering their first gift, his message is simple:

“Everyone has an opportunity to be part of the solution… and if you really want to make a difference, RMI is one of the best places to do it.”

The post From Energy Scarcity to Systems Change: Why Richard Kidd Gives to RMI appeared first on RMI.

As electricity demand in the United States continues to grow — from data centers, electric vehicles, and other large loads — utilities are struggling to keep up. Instead of building more traditional power plants, utilities can meet that demand in a cleaner and cheaper way by also turning to virtual power plants (VPPs).

VPPs are aggregations of distributed energy resources such as batteries, electric vehicles, smart thermostats, and other connected devices that can provide utility-scale and utility-grade services. Designing VPP Programs to meet utilities’ needs, however, requires planning. Just as traditional grid resources are weighed in utilities’ plans, VPPs should also be considered, modeled, and included in the utility planning process.

Today, existing and proposed VPPs are approaching and exceeding the scale of traditional power plants. In 2024, the average combustion gas turbine in the United States was 180 megawatts (MW). Meanwhile, several VPP programs across the country have met or exceeded this capacity:

• In Massachusetts, National Grid launched ConnectedSolutions in 2016, which has grown to 227 MW and includes residential thermostats, residential batteries, and commercial and industrial demand response. Beyond Massachusetts, ConnectedSolutions’ region-wide, open-access VPP shaved 375 MW of demand from the New England grid during a multi-day heat wave in June 2024.
• In California, the Emergency Load Reduction Program (ELRP) and Demand Side Grid Support (DSGS) programs were launched in 2021 and 2022 respectively, to shore up near-term reliability quickly in response to rolling blackouts. The ELRP reached nearly 800 MW as of 2023 and DSGS has reached 1,145 MW as of October 2025 with a majority of the program’s capacity — 768 MW — stemming from the market-aware storage pilot program.

• In Texas, NRG and Renew Home announced a partnership to develop a 1 gigawatt (GW) VPP by 2035 driven by smart thermostat usage; as of 2025 NRG has reached 150 MW. Meanwhile, CPS Energy started its VPP pilot over 10 years ago, which has grown to over 250 MW in size as of 2024 with 175,000 customers.

Recent policy and momentum in other states will drive further development of VPPs at this scale. In the past year, the Virginia legislature directed Dominion Energy to develop a VPP pilot program for 450 MW, New Jersey’s governor issued an executive order for the New Jersey Board of Public Utilities to develop a VPP program within six months, and the Colorado legislature directed Xcel Energy to create its first virtual power plant program, which has developed into a 125 MW proposal that was recently approved by state regulators.

Meanwhile, utilities have also directly taken actions to scale VPPs. For example, Xcel Energy in Minnesota plans to procure up to 200 MW of distributed storage, and Georgia Power recently agreed to procure up to 100 MW of new distributed solar and storage.

At these scales, VPPs can provide significant support to utilities in matching supply with demand and maintaining the reliability of the grid. Fortunately, many existing VPPs have already proven their value in both standard and emergency conditions.

During Winter Storm Elliot in 2022, providers across the region provided support by leveraging customer-sited distributed energy resources. CPower, for example, reported providing 50 GWh of energy. And during the 2025 summer heat dome that swept across the eastern United States, numerous VPP aggregators helped manage customer demand across the region to maintain a reliable grid.

For example, on June 24th — one of the region’s highest demand days — Sunrun leveraged more than 340 MW of customer-sited batteries to support the evening net peak, and EnergyHub shed 900 MW of peak load and shifted 3.5 GWh of energy to non-peak periods. And over the course of the, Uplight managed 350 MW of flexible load, all of which supported grid operators in keeping the lights on amid record heat.

Additionally, a test event on July 29 of California Independent System Operator’s (CAISO’s) Demand Side Grid Support program provided more than 500 MW of demand relief during the afternoon in which net load — demand minus renewables — is highest. The chart below shows the impact of the CAISO VPP test. By simultaneously discharging behind-the-meter energy storage from across the state, VPPs flattened net peak demand between 7:30 and 9:30 p.m.

Exhibit 1

CAISO event day system net load, with and without VPP dispatch

Similar applications of VPPs are starting to emerge on the distribution system, enabling cost savings and making these resources even more attractive to customers and utilities. For example, as part of its 2024 Grid Modernization plan, National Grid found that at least two of its feeder expansion projects could feasibly and cost-effectively be deferred for five years each by leveraging virtual power plant programs, creating near-term savings for customers while benefitting the grid. And Pacific Gas & Electric recently incorporated two battery projects onto its grid that are able to support local distribution overloads, avoid feeder and transformer upgrades, and can participate in the wholesale energy market and support the larger electrical grid.

Despite the growth in VPPs, utility plans aren’t keeping up

To ensure power delivered to customers is both affordable and reliable, many utilities develop regular long-term plans for their electricity generation and distribution systems —called integrated resource plans (IRPs) and distribution system plans (DSPs), respectively. Utilities that develop these plans do so to ensure that they can deliver power to customers under a range of future scenarios at lowest cost to customers. In these plans, the costs and benefits of various investment options are weighed against each other in order to select the least-cost options to meet all of the utilities’ energy needs while maintaining a reliable grid.

VPPs have increasingly been appearing in state-level regulatory filings, including IRPs, DSPs, and other regulatory dockets (Exhibit 2), reflecting an uptick in utility adoption and increasing interest in these technologies from utilities, regulators, and additional stakeholders. As of 2023, there were already more than 500 VPP programs in operation, serving 30 to 60 GW of peak demand.

Exhibit 2

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However, despite the increasing prevalence of VPPs in utility plans and regulatory filings, these mentions do not indicate that utilities are fully accounting for the value that VPPs are providing to their systems (Exhibit 3).

Exhibit 3

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RMI reviewed a nationally representative sample of IRPs and DSPs and found that utilities do not account for VPPs in the same way in their respective plans, if they account for them at all (Exhibit 4).

Exhibit 4

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We found that there are significant benefits that VPPs can provide to utilities and customers, but two shortfalls in planning often prevent the expansion of VPPs in resource plans.

First, VPPs are often not evaluated as a selectable resource for expansion, unlike other utility generating options. Traditional assets used in bulk system and distribution system modeling include associated capital and operating costs, reliability contributions, assumed operating profiles, and other relevant inputs, including operating limitations, reasonable build rates and times, location-specific cost-benefit analyses when appropriate, and others.

By including detailed representations of traditional resource options, models can select the resources best suited and lowest cost to meet future energy and infrastructure needs. However, VPPs often do not get the same modeling treatment, and instead are given fixed rates of expansion that do not account for the economic expansion of VPPs on the grid.

Additionally, VPPs can have restrictive parameters based on current VPP programs or existing grid needs that don’t evolve over time or reflect actual grid performance. This can prevent VPPs from being viewed as long-term perennial assets that can support grid needs into the future. As such, the ability of VPPs to expand and offset new generation in models is limited compared to their real-world potential.

A second shortfall we see in planning is the exclusion of the many benefits and value streams that VPPs provide. VPPs provide benefits to both the bulk power system and distribution system and can include benefits beyond reducing demand during peak periods.

However, many of the benefits that VPPs provide are lacking in cost-benefit analyses and in operating parameters used in modeling, which can under-estimate their economic value and usefulness, especially when comparing them to other generating assets. For example, when VPPs aren’t being modeled as options to support grid stability or mitigate distribution system upgrades, utilities may be led to build redundant generating assets or substations to meet these needs at customers’ expense. Without capturing the full value-stream of VPPs, their ability to economically offset new generation and investment options is stymied and can lead to inefficient grid expansion.

Despite inconsistencies, many utilities are working to address the VPP modeling gap.

To ensure that utility plans enable VPPs to deliver on their potential and reduce costs, they must be meaningfully included in utility plans, with detailed capacity values, reliability attributes, cost assumptions, and benefit streams. In other words, they need to be evaluated on an even playing field against conventional resources.

In distribution plans, VPPs should be considered to avoid or defer distribution system upgrades or otherwise reduce system costs by providing locational services. While utility plans as a whole may not be modeling VPPs in a consistent way that shows their full effect on the grid, we have seen some best practices emerge in utility plans that address typical VPP modeling shortfalls that are worth highlighting.

Best practices: Portland General Electric

Portland General Electric (PGE) does robust modeling of the components that comprise a VPP — distributed energy resources, flexible load, and batteries — to inform both its distribution planning and integrated resource planning. In integrated resource planning, PGE takes a novel approach to integrating its VPP components to ensure that the VPPs that are cost-effective today are properly accounted for, and VPPs that may be more cost-effective in the future — especially compared to other supply-side options — have the chance to be selected to serve future energy and reliability needs.

Through robust technical and locationally granular modeling in the distribution plan, the utility finds the VPP assets that provide benefits that exceed costs today and leverages them to modify and offset its future demand. Afterwards, the utility treats the remaining VPP assets — those that can realistically be deployed but may provide more value in the future — as options that can be selected to meet future demand alongside other supply-side assets.

Importantly, the utility develops an Effective Load Carrying Capacity (ELCC) — a metric used to value a resource’s contribution to the grid during periods of grid stress — for distributed resources, along with operating characteristics and costs of the VPP resources.

By approaching its modeling this way, PGE can identify the opportunities to expand VPP resources that currently provide more benefits to customers than costs, while continuing to evaluate whether additional expansion of or modification to VPP programs could provide customer benefits in the future

Best practices: Green Mountain Power

Green Mountain Power (GMP) in Vermont has also been a leader in quantifying emerging value streams on both the bulk power and distribution systems, which has led to expanding VPP programs.

In its planning, GMP accounted for numerous value streams of VPPs. As a result. it proposed expanding its distributed solar and flexible load programs — including on EV charging and commercial and industrial load management — to capture new regional benefits and defer spending on new transmission and generating capacity.

The benefits that GMP highlights for VPPs, which factor into its expansion plan, include lowering capacity and transmission peaks, which reduce RTO demand charges and transmission expansion costs; providing frequency regulation to the region; resilience benefits during extreme weather events; deferred distribution system upgrades; reduced load; and improved stability on local distribution systems.

Planners and decision makers can support VPP growth through modeling improvements

As virtual power plants continue to become grid assets that rival the scale and characteristics of traditional power plants and grid infrastructure, utilities need to weigh them on equal footing with their conventional counterparts. To do this, utilities and regulators can consider the following modeling improvements:

• Develop resource attributes of VPPs so that they can be evaluated like traditional investment options. The characteristics of virtual power plants and the costs and benefits of VPP programs must be part of the utility planning process so that utilities are able to evaluate VPPs against other traditional investment options. Regulators and utilities can work to ensure that key characteristics of VPPs — namely reliability contributions, costs and benefits, and operational profiles — are properly incorporated into planning.

• Allow opportunities for growth of VPPs in models. Once VPPs are able to be compared to traditional investment options, utility models need to be allowed to select VPPs as a feasible future resource option when they are cost-effective rather than solely treating them as a pre-determined resource or adjustment to load forecast. As early as 2007, the Public Utilities Commission of Oregon required electric and gas utilities in their resource planning to “evaluate demand response resources, including voluntary rate programs, on par with other options for meeting energy, capacity, and transmission needs (for electric utilities) or gas supply and transportation needs (for natural gas utilities).

• Evaluate VPP benefits on both distribution and bulk power systems. VPPs have the benefit of being able to provide benefits across the grid, while traditional investment options often benefit either the bulk power system or the distribution system. Utilities need to account for the integrated costs and benefits of VPPs in planning through integrated system planning that looks at both the larger bulk power system and the distribution system together. In the absence of integrated system planning, proxy values or estimates can be incorporated into existing plans to ensure that full benefit streams are being accounted for.

Utility plans today are underestimating the potential of VPPs as a cost-effective grid resource, creating a risk that utilities will overbuild their grid to meet needs that VPPs are already filling. Until VPPs are properly modeled in utility plans, they may not reach their full potential across the country.

The post Grid-Scale Virtual Power Plants are Here. Have Utilities Noticed? appeared first on RMI.

Recent discourse about CDR demand emphasizes uncertainty and scarcity. These concerns are real, but so are the demand signals already taking shape. If we support these signals now, they can create multiple paths forward for scaled CDR demand.

This brief spotlights three important demand trends already gaining traction: (1) credit purchasing, (2) demand for differentiated products, and (3) demand for products and services for which CDR is a by-product or co-product. For each trend, we share case studies that illustrate existing successes and how demand can be further scaled.

The post Not Just Voluntary Credits: Three CDR Demand Trends to Support and Scale appeared first on RMI.

Financial institutions are under growing pressure to assess whether companies are truly prepared for the energy transition — but today’s tools fall short. Most transition assessments rely on global 1.5°C benchmarks that measure ambition but reveal little about whether a strategy is feasible in a given region or market.

What we learned from mapping Southeast Asia’s power pathways

A critical component of a decision-useful transition assessment is a multi-pathway approach that makes use of region- and sector-specific pathways wherever possible. This enables an assessment to go beyond just evaluating ambition against a global benchmark, and evaluates ambition based on regional context and constraints, determines alignment to different policy and market conditions, and infers the associated transition risks and opportunities of different strategies in the region.

A commonly cited challenge in adopting a multi-pathway approach is the lack of relevant and credible transition pathways, particularly in regions where pathway coverage is limited or fragmented. To address this challenge, RMI is developing the Transition Pathways Repository. The goal of this tool is to make the broad array of existing transition pathways readily accessible and interpretable. The repository is currently being piloted for the Southeast Asia power sector, with expansion to new sectors and regions planned this year.

Exploring the Southeast Asia power pathway landscape has taught us useful lessons about scenario data availability, remaining gaps in the scenario landscape, and the challenges to deploying a multi-pathway approach. This article describes four of those lessons:

1. The power pathway landscape in emerging markets is richer than expected.
2. Pathway developers output consistent and granular data points for most power sector indicators.
3. Access to underlying pathway data is still limited.
4. By focusing on generation, transition pathways can miss other dependencies

These lessons are useful both to FIs adopting a broader range of transition pathways, and to the pathway developers creating them. With more alignment between these actors, adoption of transition pathways can scale to equip FIs with the information needed to support their clients through the energy transition.

1. The power pathway landscape in emerging markets is richer than expected

Backward-looking metrics based on global benchmarks can inadvertently penalize jurisdictions with high emissions. This is particularly the case for emerging markets with a strong development mandate and young fossil fuel assets. However, these regions need more access to transition capital to deliver clean energy development goals, not less. One way to address this is with region-specific benchmarks that account for local realities. However, a commonly cited challenge by FIs is the perceived lack of ambitious and credible region-specific pathways in emerging markets, including Southeast Asia.

RMI’s systematic review of the pathways available in Southeast Asia revealed a much richer landscape of options than initially expected. There are almost 60 pathways currently available on the Repository from 17 different publications and 11 different institutions. This suite of pathways provides global, regional, and country-level pathways over a range of policy and climate outcomes from business-as-usual to net-zero and 1.5°C. This diversity and granularity gives FIs the tools they need to understand the potential operating environments that companies will need to navigate, and helps them assess companies’ plans and ambition in context.

Gaps do remain in the Southeast Asia power pathway universe; not every combination of regional granularity and policy or market assumptions is available on the repository. But those that are available can be more easily identified, compared, and applied by FIs than ever.

Takeaway:
Financial institutions should continue to expand their transition assessment processes to integrate more region-specific pathways, with the knowledge that the pathway landscape is improving and tools like the Transition Pathways Repository and UNEP-FI’s Climate Pathways Navigator are making them easier to find.

2. Pathway developers output consistent and granular data points for most power sector indicators

Transition assessment methodologies show a high degree of convergence around a core set of power-sector indicators, including absolute emissions, installed capacity mix, generation mix, and emissions intensity. Among the pathways included in the Transition Pathways Repository, 54 out of 56 provide capacity projections by technology, and 55 out of 56 include generation by technology. This consistency enables technology trends to be compared and benchmarked in a consistent way across different regions and assumption sets, ensuring transition assessments are repeatable and scalable.

This set of indicators further enables an understanding of not only how emissions might evolve, but also the underlying technology shifts that will drive changes in emissions. This means transition assessments can move beyond benchmarking emissions intensity and assess which technologies companies would need to deploy at what rate in order to align with different scenarios. Identifying these key transition technologies and their deployment timeframes informs richer engagement with clients.

Finally, the available technology granularity enables analysis of the dependencies of the transition. If a pathway shows that emissions reductions are driven by carbon capture and storage (CCS), CCS infrastructure needs to be deployed alongside power generation infrastructure. Likewise, if emissions reductions are driven by increasing renewables, grid storage and stability infrastructure will be needed alongside renewables deployment. Additionally, pathway users can then make their own judgements about the viability of these dependencies achieving the necessary scale to facilitate the rate of transition modeled in a pathway.

Takeaway:
Financial institutions should expand their transition assessment processes beyond a focus on emissions. Metrics focused on technology deployment can provide a more tangible indicator of how clients are aligning with the energy transition and what kinds of investments are in the pipeline.

3. Access to underlying pathway data is still limited

Despite the core metrics above being modeled in most of the available transition pathways, the underlying data for these results is often confined to high-level reports and not readily available publicly. These reports provide the core drivers of change underlying the pathway narrative, describing the modeling approach and charting the key output results described in lesson 2. However, they often do not provide the actual pathway dataset that financial institutions need to put these pathways to use in transition plan quantitative assessments.

In developing the Transition Pathways Repository pilot, we reviewed 17 publications and engaged with 9 pathway providers to obtain the underlying data. In 2 cases, this data was made available to us so that it could be accessible for download in the Repository.

In many cases, the data is neither confidential nor behind a paywall; it is simply not being made available in a usable format. This adds an additional layer of effort and friction for FIs, preventing the use of additional pathways in transition assessments. For pathway developers, it likewise reduces the uptake of their analysis. Greater standardization and transparency in pathway outputs would benefit both pathway developers by increasing uptake, and FIs by lowering barriers to their use.

Takeaway:
Pathway developers should make their underlying pathway data available in an easy-to-use format so that FIs can plug into their existing systems with minimal friction. 4. By focusing on generation, transition pathways can miss other dependencies

Almost all the available transition pathways in the pilot focus solely on power capacity and generation. Assumptions or modeling related to grid infrastructure, demand flexibility, interconnection, and investment needs are frequently simplified, lack granularity, or are absent. Accounting for and including all these factors into power system models would add significant complexity. However, those additional parameters are important as they help illustrate how the electricity sector, as a whole, needs to evolve in order to achieve its most ambitious goals. For FIs, this can reveal whether new power investments depend on network upgrades that may not yet be planned or financed.

For example, different technology choices will change the requirements for transmission and distribution improvements based on location of power generation relative to demand centers. Likewise, different technology mixes will require different levels of investment in demand flexibility and energy storage to account for intermittent renewables.

Takeaway:
Pathway developers should expand their analyses to consider the broader impacts and dependencies of a given capacity and generation mix. This will increase the value of pathways by giving users greater insight on their feasibility and showing the investments needed to make a pathway a reality. Next steps for the Transition Pathway Repository

These lessons reinforced some of the barriers identified by FIs to implement multi-pathway analyses in their transition assessments. However, we also found that there is a rich and diverse landscape of pathways already available, and the Transition Pathways Repository can help remove the barriers to their use by centralizing pathway data in a standardized and easy-to-use format. Looking ahead, the repository will continue to evolve and expand. Planned developments in 2026 include:

• Expanding to the steel and aviation sectors with global coverage.
• Expanding power sector coverage to new regions outside Southeast Asia.
• Improving usability and navigation to make it easier to identify the right pathway for a given use case.

The repository will remain a living resource that can improve through collaboration. We welcome the opportunity to work with financial institutions to gather feedback on usability and ensure the tool effectively supports real-world decision-making. We also invite pathway developers to help strengthen the repository by flagging pathways we may have missed, and by providing more transparent, standardized outputs that enable broader and more consistent uptake.

To learn more, contact Tom White at tomwhite@rmi.org.

The authors would like to thank Jacob Kastl, Nicky Halterman, and Hannah Barton who performed the analysis on these pathways to inform the insights here. 

The post Improving Energy Transition Assessments with Regional Pathways appeared first on RMI.

Between now and 2030, the increase in electricity demand for air conditioning systems alone will exceed that for data centers, one of the fastest-growing energy uses globally. By 2050, cooling electricity demand is expected to match the combined annual electricity consumption of the United States, China, India, Germany, and Japan today. Yet, cooling hasn’t made it to the top of energy transition conversations and receives far less attention than is needed.

This year is proving to be yet another hot and humid one. But this comes as no surprise, as it joins the warmest decade in recorded history. Just last month, several regions in South Asia and the Southwest United States already experienced pre-summer heatwaves, with temperatures exceeding historical averages by several degrees.

Now more than ever, tackling extreme heat is about more than just comfort. It’s also about productivity, survivability, and safely being able to operate outdoors and live inside our homes and other essential buildings and facilities such as data centers, factories, hospitals, and schools.

The scale of the cooling challenge

In 2022, cooling equipment consumed an estimated 5,000 terawatt-hours (TWh) of electricity globally — about the same as the entire electricity consumption of the United States today. By 2050, this demand is projected to triple to 18,000 TWh.

Cooling also carries a significant emissions impact due to the use of electricity (still generated from fossil fuel-based power plants in most regions) and refrigerants that leak into the environment during servicing or at the end of life. It already accounts for 7% of global greenhouse gas emissions — roughly equal to the cement sector — and could rise to 15% by 2050. As increasing cooling drives energy and peak power demand and need for refrigerants , it will create more emissions and warming, feeding a dangerous cycle.

An integrated approach to solving the cooling challenge

No one technology can solve this unprecedented cooling challenge. An integrated approach is foundational to ensure that people can better respond and adapt to extreme heat events as well as adopt sustainable cooling solutions that reduce planet warming emissions.

RMI and our partners around the world have prioritized three core pillars to tackle the rising heat stress issue and enhance thermal comfort for people: build resilience, enhance comfort, reduce emissions.

• Build Resilience — Build urban heat resilience through heat mitigation strategies, including nature-based solutions such as urban greening and reflective materials.
• Enhance comfort — Enhance affordable thermal comfort through passive design strategies and other low-cost, scalable solutions that reduce cooling needs and make cooling accessible to more people.
• Reduce emissions — Reduce energy use and emissions through super-efficient technologies, improved system design, and better refrigerant management, while scaling next-gen, innovative solutions that lower life-cycle costs and emissions.

When key actors across policy, technology and market align around this framework, it helps create the conditions needed to scale the right solutions that benefit the people and the planet.

Putting the approach into action

Build Resilience — Mitigating urban heat at the source

Reducing cooling demand effectively begins with understanding where heat poses the greatest risk. In many cities, responses are still guided by temperature thresholds rather than real-world impacts on people, infrastructure, and livelihoods.

But cities also need tools that help identify priority hotspots and target interventions to help prepare communities and infrastructure in advance, reducing exposure and managing cooling demand during the hottest periods when grids may otherwise fail. To address this, India’s National Disaster Management Authority developed the Heat Impact Assessment (HIA) Framework and a digital dashboard, empowering cities to identify priority hotspots and target interventions where they can deliver the greatest benefit.

Additionally, urban areas are often hotter than surrounding regions due to the urban heat island effect, where buildings and infrastructure trap heat. Expanding tree cover, improving ventilation, deploying heat-rejecting surfaces, and using thermally efficient materials can help reduce the impact of heat.

At scale, these solutions offer broader system-level benefits by reducing heat buildup across urban areas, lowering neighborhood temperatures, and helping mitigate the urban heat island effect.

Insights from work in communities highlight how combining building-level interventions like cool roofs with neighborhood-scale strategies — and including heat-sensitive urban design — can reduce heat exposure more effectively than stand-alone solutions. Layering interventions like cool corridors across neighborhoods using nature-based solutions, building materials, and urban form is critical to delivering sustained cooling at scale. Together, these approaches are key to improving heat resilience while easing grid stress during extreme heat days.

Enhance comfort — Reducing cooling needs affordably

Enhancing thermal comfort for people begins with helping people stay cool without relying on mechanical cooling systems. One key solution is to use materials that not only reflect sunlight but also actively shed heat. Pilots in Chennai, India, have demonstrated how “cool” roofs and surfaces can significantly reduce indoor temperatures, improving comfort — especially for those without access to air conditioning.

RMI’s climate tech accelerator, Third Derivative, is advancing passive daytime radiative cooling (PDRC) technologies, including specialized paints, films, and membranes. Unlike conventional cool roofs that primarily reflect solar radiation, PDRC materials are engineered to both reflect sunlight and emit heat as mid-infrared radiation that passes through the atmosphere into space. This dual mechanism enables them to cool surfaces below ambient temperatures, with the potential to lower indoor temperatures by up to 18°F (10°C) on hot days — without using electricity.

Passive design strategies, including PDRC, cool roof coatings, efficient building envelopes, solar shading, and proper ventilation, reduce the need for active cooling solutions, improving comfort and making cooling more affordable and accessible for all.

Reduce Emissions — Advancing efficiency and accelerating innovation

Today’s air conditioners (ACs) need to be re-designed to fully optimize the refrigeration cycle and deliver better comfort and energy performance using high-efficiency components. The Global Cooling Efficiency Accelerator, supported by RMI and partners, conducted extensive prototype field testing in Palava City, India, where super-efficient AC prototypes maintained consistent comfort (below 27°C/80.6°F and 60% relative humidity) even in extreme conditions, while cutting peak power demand by up to 50%. Additionally, they used 60% less energy than today’s common models and delivered better dehumidification, reducing the need for overcooling the indoor spaces, which means dramatically lower total cost of ownership for consumers. This is particularly important as many households buy their first AC to seek respite from high wet-bulb temperatures that are reaching critical human survivability thresholds.

However, scaling these improvements requires more than better technology. Updated testing and performance standards are needed to enable fair comparison and clear differentiation of efficient technologies. At the same time, aligned procurement specifications and strong demand signals from like-minded buyers give manufacturers the confidence that the market is ready — helping drive a fundamental shift in how technologies are produced and purchased.

RMI and partners are actively working across both the demand and supply sides to help shape the market for products that ease the tension between people’s comfort, grid reliability, and emissions.

As ACs get widely adopted globally, addressing refrigerant emissions is as critical as improving energy efficiency. Transitioning to low-GWP and natural refrigerants, as well as improved life-cycle refrigerant management — including leak reduction, recovery, and reclamation — is essential to prevent significant climate impacts from cooling systems.

And as we improve today’s AC technology to become super-efficient, there is an opportunity to go even further. Innovation across the cooling sector is essential to unlocking the full range of solutions needed to address this challenge. For example,  desiccant-based systems and hybrid solutions using membrane technologies can separately and independently manage dehumidification from cooling, enabling more efficient operation in humid climates.  Solid-state technologies, which use an applied field or pressure instead of refrigerants, can offer improved efficiency and comfort, quieter operation, lower energy costs, and reduced emissions.

RMI’s Third Derivative program is actively sourcing and supporting these emerging cooling innovations, working with eight startups globally that are developing innovative active cooling technologies, from optimized system design to highly efficient humidity management with liquid desiccants and refrigerant-free solid-state cooling.

The path forward

In the coming years, we will continue to deepen our engagement with key stakeholders to support them in implementing national and sub-national policies and to adopt low-cost scalable passive design strategies and solutions that reduce cooling demand at the source.

We will also continue working to accelerate the development and scale of super-efficient cooling technologies, advance refrigerant management efforts, and unlock next-generation innovations. We aim to deepen our understanding of the rapidly evolving cooling technology landscape to identify the most relevant and impactful opportunities for intervention. We will work closely with policymakers, manufacturers, buyers, and startups to pilot solutions, strengthen performance standards, and build the market confidence needed to drive widespread adoption.

Taking a holistic, whole-systems approach — build resilience, enhance comfort, and reduce emissions — can deliver significant impact, on both the building level and across the entire cooling sector. This could translate into electricity savings of up to 8,500 TWh by 2050 — more than the current annual consumption of the United States and the European Union combined — while reducing peak demand and avoiding the need for thousands of new power plants. And improving AC efficiency levels by over 50% means people can cool their homes when they need to without stressing the grid, driving up electricity bills, or adding to emissions.

In a warming world where heat stress is rising and rapid urbanization and increasing incomes will drive significant growth in cooling demand, accelerating these efforts is critical. By working collaboratively, we can ensure cooling needs are met for all without accelerating the warming of our planet.

We would like to thank Ankit Kalanki, Tarun Garg, and Tess Healy for their contributions to this article.

The post Tackling the World’s Surging Cooling Demand appeared first on RMI.

Rapid load growth is putting tremendous pressure on PJM, the regional transmission organization covering 13 states and Washington, D.C., to deliver  necessary power while maintaining affordability and reliability. This demand surge has collided with a constrained transmission grid and a slow generator interconnection process (which PJM is making efforts to address).

Fortunately, PJM can quickly add cost-saving new generation by improving the path for “energy-only” resources to connect to the grid. Recent conversations surrounding fast, flexible load interconnection highlight a broader principle: whether connecting load or generation, faster connection can be offered in exchange for modest operational curtailment, and the interconnection process can be streamlined accordingly.

While capacity price spikes and the need for “firm capacity” have dominated headlines and PJM-led interventions to date, the reality is that energy prices remain the largest share of electricity bills. Energy market prices were up 50% in 2025 compared to 2024, driven by factors such as higher gas prices and higher demand, which results in the dispatch of less efficient, higher-cost generators.

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To meet load growth and deliver downward pressure on energy costs, PJM needs not just additional capacity, but also more low-cost energy generation on its system. Energy-only resources (those that seek energy resource interconnection service, or ERIS) are well positioned to support PJM’s needs and reduce costs, but they must have a path to come online quickly and at a scale.

Encouragingly, new Aurora Energy Research analysis shows ERIS resources are financially viable in PJM, would reduce customer bills, and even contribute to reliability.

What are ERIS resources?

ERIS is not a new concept. FERC Order 2003 (released in 2003) required transmission providers to offer two levels of interconnection service: the more comprehensive Network Resource Interconnection Service (NRIS), and Energy Resource Interconnection Service (ERIS). The latter was intended to facilitate faster, more competitive access to the transmission system.

FERC defines ERIS as a basic interconnection option that does not guarantee “firm” deliverability in all situations, including during peak load or times of grid congestion. ERIS generators are curtailed when there is insufficient transmission space, and do not qualify as capacity resources. In exchange for assuming curtailment risk and “as available” service, ERIS developers were not intended to have to pay (or wait for) larger transmission network upgrades during interconnection. ERIS was supposed to enable developers to trade firm transmission service for speed, where the value proposition made sense.

Interest in ERIS has been limited to date, due to implementation of ERIS study procedures that do not meaningfully differentiate these projects from those seeking NRIS, or capacity status. There is little upside to developers in forgoing capacity revenues and pursuing ERIS if the interconnection study timeline and costs are not significantly reduced. Additionally, grid operators and utilities have tended to prefer firm capacity resources and disfavor ERIS projects. ERIS resource uptake in PJM is particularly low.

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Yet today, with interconnection serving as a primary bottleneck to new generation supply and affordability pressures mounting, there is good reason to re-examine ERIS resources and the potential value add they could bring to customers and the grid. RMI commissioned an analysis and report conducted by Aurora Energy Research to explore ERIS resources’ viability in PJM. Aurora’s analysis indicates that the value add could be notable: consumers could realize nearly $11 billion in savings over the next decade, from deploying just 10 GW of energy-only resources in PJM.

Highlights from Aurora’s “Viability and Benefits of ERIS in PJM” analysis

• Analysis scope and set-up: In order to realize the opportunity for expanded use of the ERIS interconnection pathway in PJM, it is important to assess the financial viability of energy-only service for project developers and financiers, as well as to understand the potential benefits that a reformed study process might yield. Aurora’s recently published report undertook this analysis by adding hypothetical “ERIS resources” to four load zones in PJM with a 2028 commercial operation date. The ERIS resources analyzed were wind and solar generators, given the greater likelihood of these resource types electing ERIS service due to their lower capacity accreditation values and thus lesser reliance on capacity revenues.
• ERIS financial viability assessment: First, Aurora assessed the expected internal rate of return (IRR) for these resources across the four zones (American Electric Power, Commonwealth Edison, Dominion, and Pennsylvania Power and Light) and a range of scenarios, to account for uncertainty in future price projections and load growth. An energy generator’s expected IRR, or hurdle rate, is a key metric for project finance: investors require a certain IRR to ensure their investment will return a profit. Based on Aurora’s industry expertise, they used a 9% hurdle rate as the benchmark for a project’s financial viability.For the initial assessment, they assumed no interconnection costs beyond the point of interconnection, which would represent an ideal ERIS interconnection pathway. Aurora found that ERIS resources are financially viable in all four zones and across nearly all scenarios (with the exception of the Low scenario, which reflects low energy prices and low load growth). Central Scenario results revealed IRRs of 9%–10.2% for solar, and 9.2%–13.6% for wind. Wind resources are particularly profitable because the timing of their power output aligns well with higher-priced energy hours in the zones where they were studied.

  Unfortunately, other challenges limit development of onshore wind, even more than solar resources. This shows that ERIS resources can be profitable, even without capacity revenues, in an appropriately scoped ERIS study process.

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• System benefits of ERIS resources: ERIS resources’ value-add does not just accrue to project developers and investors. These projects could yield system benefits as well, contributing to both grid reliability and affordability. In PJM, peak system risk moments typically occur in the winter, when winter storms drive up power demand and thermal generator forced outage rates. Those thermal generator outages may free up grid headroom for energy-only resource deliverability, and wind resources in particular have relatively high output during peak winter load days. As Aurora’s analysis found, onshore wind resources in PJM had an average 39% capacity factor on peak winter load days over the past decade. During Winter Storm Elliott, PJM’s onshore wind fleet saw higher generator availability rates (the share of capacity not in outage) than both coal and gas resources.

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Finally, ERIS resources can help lower energy prices. If — in a scenario where PJM reformed and sped up its ERIS study pathway — 5 GW each of ERIS-accelerated wind and solar resources were added to PJM by 2028, PJM ratepayers could save almost $11 billion over the next decade.

 

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Necessary interconnection process reforms to catalyze ERIS uptake

Across the country, most ERIS interconnection processes remain intertwined with NRIS resources, negating the potential time savings and cost benefits of ERIS. PJM and other grid operators should update their ERIS study pathways to ensure the following:

1. ERIS resources should be studied in a separate and parallel track from resources seeking NRIS. Study timelines should be short and clearly defined, and should leverage the most advanced modeling software available. We would also expect a separate study process for ERIS to support speedier and more streamlined study of NRIS clusters, as this would reduce cluster sizes and thus the potential for dropouts and re-studies.
2. Network upgrade costs and timelines should be minimal. The scope of the study should be limited to ensuring a reliable connection to the point of interconnection, as is the process in ERCOT. ERIS resources should not trigger deeper network upgrades due to network deliverability studies. An appropriate study for ERIS resources must include realistic dispatch assumptions that reflect how ERIS resources would be treated in the market and operationally. For example, if they will be subject to operator curtailment during times of grid congestion, that should be reflected in the study models. The interconnection study could be scoped to inform the operator of typical curtailment expectation, but network upgrades beyond the point of interconnection are unnecessary, as any broader system impacts could be managed by curtailment or redispatch.
3. Transmission system needs should be addressed in existing transmission planning processes. If grid congestion results in high curtailment of ERIS resources, that should be considered in transmission planning processes, like PJM’s Regional Transmission Expansion Plan (RTEP). That is where reliability and economic drivers of new transmission needs are assessed, and where consideration of any future transmission enhancements that might deliver system-wide benefits — such as reduced curtailment and greater ability for low-cost resources to serve load — should occur.

Additionally, grid operators should undertake a full evaluation of the reliability contributions of these resources, and the ways in which they may need to adapt market rules or operations to unlock the full capabilities of ERIS resources. Importantly, if these resources contribute non-zero capacity value, as Aurora’s analysis suggests they might, the region’s resource adequacy planning paradigm might need to be adapted to accredit the resources accordingly. And if operational practices impede system operators’ real or perceived ability to perform redispatch, opportunities to enhance those should be explored at the system-wide level.

Grid operators can look to ERCOT for effective tools and processes to manage these types of resources, where their “connect and manage” approach to interconnection has enabled rapid entry of new resources onto the grid while maintaining reliability. The influx of solar resources paired with battery storage has effectively eliminated ERCOT’s evening resource adequacy concerns in the summer.

ERIS resources are more than “energy-only” — they are fast-to-deploy, low-cost resources that can be important contributors to a balanced generation mix. Reforming their interconnection process to match their speedy development potential could unlock significant benefits for grid operators seeking near-term new generation resources to meet growing load.

The post A Fast-Path to Affordability: Understanding the Benefits of Energy-Only Resources in PJM appeared first on RMI.

Demand for key grid hardware has soared since 2019, due to large load growth, integration of new energy generation resources, and investment to modernize the aging grid. This demand is driving up equipment lead times and prices. In fact, if you need a large power transformer, you may have to wait up to four years. The stakes are high for American businesses and consumers: the grid supply chain crunch is already impacting utility bills, threatening reliability, and stalling critical projects, from power plants and data centers to new housing construction.

While recent investment announcements in domestic grid component manufacturing will help ease shortages in the coming years, these developments on their own are not enough to secure America’s grid supply chain. Policymakers can leverage a range of proven industrial policy tools to boost the capacity, coordination, and competitiveness of US grid component manufacturing. Addressing the gridlock is an opportunity to reinvigorate domestic manufacturing, strengthen US energy security, improve energy affordability, and propel economic growth.

The post Solving the Gridlock: America’s Electric Supply Chain Opportunity appeared first on RMI.