Rocky Mountain Institute

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.

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}}});

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.

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}}});

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.

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}}});

• 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.

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}}});

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.

 

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}}});

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.

Chemicals play a critical, though often overlooked, role in modern society. They provide many of the key building blocks for the construction industry, support agriculture by increasing crop yields, and offer novel materials for a range of products from automobiles to new energy technologies. In fact, chemicals are everywhere, present in 96% of manufactured goods, including 75% of the energy technologies that will be needed to navigate the energy transition.

While chemicals are deeply embedded in modern society, it is equally important to acknowledge the challenges they pose. Among these are the need to reduce reliance on fossil inputs, develop better end-of-life management for chemical products, and lower emissions even as production is projected to grow up to 43% by 2050. More effort is needed across all these fronts, but addressing the 2 billion metric tons — or roughly 5% of global greenhouse gas emissions — from chemical production annually requires particularly urgent action given the long timelines to commercialize new production methods.

Despite these challenges, technologies are emerging to enable low-emissions chemicals production. While many of these technologies show technical promise, few have moved beyond the pilot or early demonstration phase. Scale-up of these technologies is often not held back by technical feasibility so much as by commercial barriers, including uncertainty about demand for low-emissions products and risk-aversion among participants spread across long and complex chemicals value chains.

Clear demand signals from companies that use chemicals in their products and novel mechanisms to bridge chemicals value chains are critical to overcoming these roadblocks and unlocking investment. The Center for Green Market Activation (GMA) and RMI are actively working to establish demand signals by aggregating buyers of low-emissions chemicals and by developing a book and claim system to enable chemical producers to transact directly with downstream companies that have committed to lowering supply chain emissions and are willing to pay a premium to do so.

The Challenge of Decarbonizing Chemicals Production

Scaling low-emission technologies in the chemicals sector is uniquely challenging. Chemical production assets are highly capital-intensive, with investment horizons that span decades. Existing plants, many of which are fully depreciated and can produce at a low marginal cost, leverage processes that have been optimized over many years and produce at enormous scale. The result is constant cost pressure that reinforces the competitiveness of conventional production methods. As a result, even when low-emission alternatives exist, buyers and suppliers alike often default to the legacy status quo.

The diversity of chemical products — and the resulting complexity of value chains required to produce them — results in an additional challenge. Unlike other industries with relatively standardized products, the chemical sector encompasses thousands of molecules, intermediates, and derivatives. This often results in long value chains with multiple layers of intermediaries separating a primary chemicals producer, generally responsible for the majority of emissions, from the better-known companies at the end of the value chain that have made net-zero commitments and are closer to consumer demand. In the middle are specialized producers of intermediate chemicals or products that often operate with thin margins and limited visibility.

In this environment, intermediate producers operating with thin margins have few incentives to source lower-emissions, higher-cost inputs unless they have certainty that their customers are willing to pay an equivalent price premium. The result is an enormous coordination challenge. Multiple parties within a value chain must simultaneously close both procurement and offtake contracts at a material premium to market prices. And all of this needs to occur at a volume that gives the primary chemical producers certainty that customers will pay a premium for most of their output over an extended time horizon. While this may be possible in rare cases where large buyers directly purchase from primary chemical producers, it will be all but impossible in most chemical value chains.

Leveraging Novel Mechanisms to Catalyze Investment

Breaking the deadlock requires both credible demand for low-emissions chemical products and mechanisms to bridge companies across long, complex value chains. GMA and RMI believe that two critical interventions, pursued in tandem, have the potential to address these challenges and unlock investment in low-emissions chemical production: demand aggregation and book and claim.

Demand aggregation is the first necessary intervention. As in many industrial sectors, low-emissions production will come at a price premium, particularly given that novel technologies often operate at small scale and with less historical process optimization than their fossil-intensive counterparts. While new technologies have the potential to decrease costs as they scale, the ability to achieve initial traction in highly price-sensitive markets is often a challenge for these production methods. The presence of buyers willing to purchase at a premium is a critical proof point for projects seeking capital to invest in low-emissions production.

But why is it necessary for multiple buyers to act together in order to provide this proof point? Because chemical assets operate at such a significant scale and because their lifetimes are so long, the purchasing volume required to unlock investment in a new facility can be enormous. By pooling demand, multiple buyers can provide the necessary volume to support an investment decision, thereby decreasing the cost and risk that any individual company would otherwise have to take on.

In cases where physical offtake of low-emission chemicals is constrained, Book and claim systems provide a mechanism to aggregate larger demand volumes through the use of Environmental Attribute Certificates (EACs). Under this chain of custody approach, chemical producers generate an EAC for each unit of low-emission product, such as a ton of ethylene, that reflects the reduced emissions intensity associated with production. This certificate is then sold separately from the physical product, which continues through the value chain as a traditional commodity with a baseline emissions intensity. This separation enables chemical producers to receive revenue from EAC sales to cover the premium associated with low-emission production, providing the financial certainty needed to finance capital-intensive projects. At the same time, buyers gain verifiable, traceable progress toward climate commitments through certificates that are independently verified and tracked through a registry system.

The result is three benefits that can dramatically alter the viability of low-emissions production:

1. Value Chain Bridging: Perhaps the most significant impact of book and claim systems is the ability for interested parties to transact efficiently. By enabling standardized transactions between downstream brands willing to pay for value chain decarbonization and upstream producers that most heavily influence emissions, the challenge of aligning multiple intermediaries around price and volume in complex value chains can be avoided.
2. Geographic Aggregation: Book and claim provides an additional benefit, particularly in the early innings of the net-zero transition when access to low-emissions products remain Creating an EAC distinct from the physical product means that a producer is no longer constrained to finding customers willing to pay a premium for a low-emissions product near its production plant. Instead, they can sell the physical product locally at commodity prices and cover the green premium by selling an EAC to any downstream user of the product, regardless of geography.
3. Product Aggregation: By focusing a book and claim system on high-value chemicals, a third benefit can be realized. A traditional demand aggregation approach would need to find buyers procuring identical products. However, book and claim enables demand aggregation across any product that contains a particular molecule. For example, demand for low-emissions ethylene can be aggregated across apparel companies using polyester for textiles, pharmaceutical companies sourcing polyethylene for syringes, and personal care companies using multiple types of plastic for everyday household goods. By focusing on a common and consistent upstream input, substantially more demand can be aggregated and transacted in a single procurement.

Given the immense challenges associated with decarbonizing chemical production, leveraging novel mechanisms to catalyze investment in low-emissions production will be essential. Combining demand aggregation with book and claim in the form of a buyers alliance for EACs offers a unique opportunity to reduce risk for both buyers and suppliers, while driving real investment decisions.

GMA and RMI’s Low-Emissions Chemicals Initiative

An emerging initiative from GMA and RMI to procure low-emissions high-value chemicals leverages these approaches to tackle emissions in the chemicals sector. Multiple downstream brands that use chemicals in their products have come together to procure environmental attributes for low-emissions ethylene, with plans to expand this approach to other molecules in the future. In the process, they will provide demand certainty for low-emissions projects while simultaneously finding a pathway to address upstream Scope 3 emissions that had previously been out of reach due to complex, multi-tiered value chains.

Prior efforts from GMA and RMI to pool advanced commitments for low-emissions products in heavy industry sectors have demonstrated how aggregated demand can generate confidence for suppliers and investors. Sectoral buyers alliances such as the Sustainable Aviation Buyers Alliance (SABA), managed by Environmental Defense Fund, GMA, and RMI, have shown how standardized frameworks and collective purchasing can accelerate the deployment of next-generation technologies. Launched in 2021, this effort has evolved from one-year advanced commitments to purchase bio-based sustainable aviation fuel (SAF) to a scaled marketplace and targeted 5+ year offtakes at scale for next generation fuels.

Without credible demand signals and effective mechanisms to translate that demand into firm offtake agreements, the transition will stall. GMA and RMI are working to bring these pieces together—aggregating demand and developing mechanisms to more efficiently enable offtake—to ensure that novel pathways to produce low-emission chemicals are developed. Together with active engagement from buyers and support from the broader ecosystem, these actions can provide the demand certainty needed to unlock investment and enable the chemical sector to accelerate its transition to a net-zero future.

If you are interested in learning more about the GMA-RMI low-emissions chemical procurement spotlighted in this article, please reach out to chemicals@rmi.org,

 

The post Harnessing Green Demand to Drive Sustainable Chemicals Production appeared first on RMI.

The post The Geothermal Supply Chain Is America’s to Gain — or Lose appeared first on RMI.

The post What PJM States Can Do to Ensure Affordable, Reliable Electricity During the Data Center Boom appeared first on RMI.

Energy and economic security can be rapidly reinforced by stopping gas loss. The amount of methane vented and leaked into the air today by the global oil and gas industry is even greater than the total pre-war volume of gas passing through the Strait of Hormuz. When flared gas is added, this overall energy waste is equal to over one-half of worldwide LNG exports.

With energy markets roiling over the loss of 20% of the gas volume traveling through this chokepoint, companies have a responsibility to stop their gas loss on energy security grounds alone. Moreover, given price hikes due to the ongoing conflict, there are immediate economic benefits for selling rather than wasting their gas.

Texas’s oil and gas industry spotlights this massive energy and economic opportunity. Preventing gas venting and flaring in Texas alone could make up the total lost gas volume due to current disruptions in the Persian Gulf. Preventing gas waste and accurately accounting for companies’ self-reported gas loss is not only fair practice, but it also has paybacks for industry and increases resource royalties to the Texas state budget. By keeping gas in the pipe and out of the air, operators can also safeguard people and the planet. As one of the world’s biggest oil and gas producers, Texas serves as a case study to investigate and quantify how companies can step up to bolster energy, economic, and climate security by stopping gas loss.

Reducing system inefficiencies bolsters energy security

There are inefficiencies in oil and gas industry operations that lead to gas waste and methane emissions. The industry acknowledges it. Mitigating product loss, which is paramount when energy supplies are constrained, can be prevented by tighter oversight, better operations, and strategic investments.

Gas loss is becoming increasingly visible due to advances in satellites, sensors, and continuous monitoring. Ongoing measurements are creating alignment around a new priority: turning actionable data into operational decisions that improve reliability, reduce costs, offer payback, and increase production efficiency. The barrier is no longer technology, but workflows — ensuring that actionable insights reach engineers and operators in time to drive change.

Over 10,000 plumes have been spotted in Texas alone over the past several years, amounting to some hundreds of tons of wasted methane gas. A recent gas release spewing over three tons of methane was detected on the eastern edge of the Permian Basin in Texas, as shown below. The two leaks detected by Carbon Mapper at this site, which persisted for two days, wasted as much energy as it takes to dry over 300,000 loads of laundry.

Sample methane plume spotted in Texas by satellites Source: Carbon Mapper Data Portal, Accessed April 14, 2026.

Lowering the volume of gas we waste heightens energy security because more gas makes it to market. Conversely, supply shocks trigger fuel shortages, especially in import-dependent nations. And energy insecurity drives up the price of oil and gas, leading to inflation and economic insecurity.

Preventing gas waste produces revenue streams and boosts economic security

Methane is the main component in gas, and is also co-produced with oil. When it’s allowed to escape into the atmosphere, it’s sheer energy and material waste. When kept in the pipe and sold, it’s a valuable commodity. Moreover, when companies minimize their operational inefficiencies, the gains are transformed into economic benefits for communities in the form of increased revenues, royalties, and jobs.

The industry knows its gas value proposition. When prices are high, gas loss drops. It then rises when prices are low, as plotted for the United States below.

On a global scale, the estimated 81 million metric tons of methane that the oil and gas industry squanders annually through venting and leaking its gas has an estimated economic value today of $20 billion to 50 billion a year, depending on highly variable gas prices. (See endnote for assumptions). In terms of overall financial opportunities, the economic loss of wasted gas is twice as great when also accounting for the additional 150 billion cubic meters (bcm) of gas that is flared worldwide. Given the high volatility of global gas prices, foregone revenue streams, royalties, and resource rents from wasted gas are a material corporate and national concern.

Stopping methane emissions rapidly improves climate security

Methane is over 80 times more powerful at heating Earth over its decade-long lifetime. In other words, every metric ton of methane that is stopped or avoided dramatically lowers damages wrought by droughts, flash floods, excess heat, firestorms, and other climate-driven disasters. The fastest path to reducing methane emissions is improving oil and gas industry operations to prevent gas loss. The companies that succeed in this quest are those that can keep their gas in the pipe.

Improved measurement, models, and methodologies are enabling the shift from data insights to durable action. For example, Carbon Mapper’s data portal identifies large point source methane-emitting events. This focuses operators’ attention on rapidly fixing their super-emitting assets. Separately, NASA’s Black Marble product analyzes nightlights using the VIIRS satellite to make gas flaring data publicly available. And ClimateTRACE quantifies wide-ranging oil and gas industry methane emissions between countries.

Drilling down in Texas

RMI’s study, Drilling Down on Gas Loss, finds that Texas oil and gas operators’ self-reported gas loss is likely 3–4.5 times higher than what is currently self-reported. This results in energy waste and methane emissions that are highly variable across basins, well types, and production volumes, as mapped below.

For example, in February 2026, Carbon Mapper detected a plume in Big Spring, Texas (illustrated above) that emitted 3.4 tons of methane per hour. Coincidentally, this major gas release is in Howard County, Texas, the same county that RMI’s study identified as highly wasteful. Together, bottom-up and top-down analyses can provide real-world validation of gas loss.

Across Texas, the volume of wasted gas identified in this state alone could yield some 15.6 bcm per year of marketable gas. In 2024, before gas prices recently spiked, over $1 billion in Texas’s gas value was forgone, with associated lost tax revenue of nearly $100 million. Today, this amounts to $1.6 billion in forgone gas value at current Henry Hub gas prices.

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}}});

 

Over half of the gas wasted in Texas is attributed to low-volume oil wells that intentionally vent their gas (predominantly methane) directly into the air. This loss is under operators’ control. Moreover, this intentional waste is frequently disguised through under- or false reporting. Nearly one-half of Texas’s company-operated oil leases reported zero gas produced or zero gas loss during at least one month in 2024. Gas leases more accurately reported their product loss.

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}}});

Why industry needs to accurately report and stop gas loss

The sizeable gas loss in Texas alone masks the scale of energy waste from an industry that is largely promoting waste reduction. For example, at CERAWeek 2026 — the largest energy convening in Houston, Texas — numerous companies made clear that the oil and gas industry is ready to treat methane and wasted gas not just as an environmental liability, but as signals of operational inefficiency and lost economic value.

Some operators note that spikes in flaring during production is too common, reinforcing the need for actionable, real-time data to improve operations. Other operators emphasize that methane mitigation is becoming embedded in operational excellence, with reductions made through equipment upgrades. Across international and national oil and gas companies, the message was consistent: better data leads to better operations — reducing downtime, improving process control, and modernizing equipment — which directly translates into lower emissions and economic gains.

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}}});

When companies reduce gas waste, they not only make a difference to their bottom lines. The war in the Middle East highlights a devastating reminder that preventing gas loss is also a matter of energy security. All told, some 112 billion cubic meters of gas passes through the Strait of Hormuz annually. Remarkably, this disrupted trade volume that is upending global energy markets is just a fraction of the 280 billion cubic meters of gas that oil and gas companies discard through venting and flaring every year. We have the policy and market tools to prevent gas loss. If acted on, this will win-win-win, significantly bolstering energy, economic, and environmental security.

Acknowledgment: Thank you to Dwayne Purvis (Purvis Energy Advisors) for his lead on the Texas study, Drilling Down on Gas Loss.

Endnotes: These calculations assume (1) a methane content in gas of 74%–85%; (2) methane density of 0.657 kilograms per cubic meter; (3) a heat conversion of 1038 btu per cubic foot; (4) resource pricing of $3.70 per million British Thermal Units (MMbtu) for pipelined natural gas anchored on Henry Hub; (5) $11.33 per 1000 cubic feet for LNG; (6) 2024 Waha Gas Hub and Henry Hub prices of $0.21 to 2.21/MMbtu, respectively; (7) April’s Henry Hub gas spot price is computed as $2.79 per MMbtu for 2026.

The post Stopping Global Gas Loss in Its Tracks appeared first on RMI.

“It is not that we have a short time to live,” the ancient Roman philosopher Seneca once wrote, “but that we waste a lot of it.” His point — that we often waste things that hold great value — echoes through the centuries.  

As the closure of the Strait of Hormuz forces governments around the world to enact restrictive policies to stabilize their energy supplies and national economies, it’s a critical time to reflect on wasted energy resources.

Before the war, some 20% of the world’s liquefied natural gas (LNG) supplies was shipped through the Strait. But with blockades and damaged infrastructure largely bottling up that supply, it’s a moment to look at where that supply could be made up if a concerted effort is made to stop gas from escaping systemwide.

The answer? Waste. 

The 112 billion cubic meters of gas lost by the Strait’s closure is dwarfed by the scale of gas wasted by venting and flaring worldwide. The good news is that we have the technological and policy tools available to us today to limit waste and increase our energy and economic security. 

Wasted gas is no longer invisible. More satellites, drones, sensors, and other technologies are being used to reconcile differing methane inventories and identify methane super-emitters. Now we must segue from “how to measure” to “how to act.” Getting actionable insights embedded into system design, planning, operations, and emissions management systems is key. So too are policies that limit leakage and actions that amplify methane mitigation through sound financial investments and smart insurance underwriting.

Were Seneca an energy planner today, he might observe that energy supplies are ample, but only if we know how not to waste them. 

 Read more: Stopping Global Gas Loss in Its Tracks

The post The World Wastes More Gas Each Year Than the Strait of Hormuz Supplies appeared first on RMI.

Across the United States, rising energy prices, an ongoing affordability crisis, and compounding reliability and resiliency issues are driving demand for energy solutions that lower monthly bills and keep the lights on for households and small businesses.

Clean energy technologies can meet these needs by lowering energy use and costs. As a result, significant momentum has grown across the clean energy and community development financing ecosystem, mobilizing a range of financial institutions, including:

• Community lenders seeking technical assistance, capitalization funding, and capacity building opportunities to grow clean lending portfolios.
• Green banks seeking new partnerships, product deployments, and opportunities for scale
• Regional banks mapping opportunities to enhance Community Reinvestment Act (CRA) lending while integrating portfolio level investment opportunities for new asset classes.
• Philanthropic organizations seeking catalytic investment opportunities to drive community development objectives.

These organizations and others are building local strategies and piloting a range of clean community financing initiatives. Still, many community clean energy projects face common challenges in achieving scale as they often do not satisfy mainstream capital’s credit box.

Absent the federal funding that aimed to address these challenges, an opportunity has emerged to strengthen regional financing ecosystems that leverage individual organizations’ strengths and improve coordination across regional priorities, barriers, and opportunities. These ecosystems play a significant role in building a more resilient capital base and developing the place-based infrastructure to scale clean energy investment that delivers solutions with outsized economic and community impact.

RMI is exploring what a strong regional financing ecosystem needs in practice and how local circumstances and market realities may shape priorities, opportunities and partnerships. This article outlines eight lessons for strengthening regional clean community financing ecosystems, using Michigan as a case study.

Lessons from Michigan’s Clean Community Financing Ecosystem

RMI, in partnership with the Michigan Climate Investment Hub (the Hub), hosted a roundtable discussion in early 2026 to build a shared understanding of the current realities across Michigan’s clean community financing ecosystem. Discussions focused on priority market opportunities, partnerships, and identifying strategic next steps.

Across four market segments — single-family residential, multi-family residential, small business lending, and MUSH (Municipalities, Universities, Schools and Hospitals) — insights from Michigan demonstrate how other regions can accelerate clean energy opportunities in their communities.

Lesson 1 Institutional density attracts national capital, because capital flows where there is clarity, coordination, and credible partners.

Recommendations to other ecosystems:

• Make your ecosystem legible to external actors, providing clarity on who does what, where capital gaps exist, and how partners can plug in with clear entry points.
• Package opportunities for national intermediaries and investors.

The Michigan clean community financing ecosystem has strong institutional density and alignment, represented by diverse capital sources, actors, products, and offerings targeting emerging opportunities across the state. The ecosystem includes:

• Michigan Saves, the nation’s oldest green bank, which has facilitated over $790 million in energy improvements with a 30:1 private capital leverage ratio. It also hosts a vetted contractor network of over 1,500 partners.
• Two Community Development Financial Institution (CDFI) coalitions — the Michigan CDFI Coalition and the Detroit CDFI Coalition — represent a significant share of Michigan’s more than 44 certified CDFIs. Together, they chair a joint climate committee that drives ambition and provides technical assistance. They use a four pillar strategy to fill local gaps: advocacy, collaboration, sharing and learning, and growth.
• A dedicated Commercial Property Assessed Clean Energy (C-PACE) marketplace, administered through Lean and Green Michigan, that includes 62 local governments representing 85% of Michiganders. Since 2015, it has facilitated 89 projects and mobilized $315 million in private investment.
• Local impact capital providers, like The Kresge Foundation, play a key role in keeping clean energy projects moving forward. They provide catalytic capital, technical assistance, capacity building, market building and strong partnerships across Michigan’s CDFI network.
• Regional banks, such as Fifth Third, are expanding beyond CRA activity and increasing their role in clean community lending in Michigan. They leverage partnerships, intermediaries, and green banks, as well as innovative financing models such as equity equivalent investments and tax equity programs.

Strong coordination across state actors in Michigan has attracted national interest from organizations such as Inclusiv, Justice Climate Fund, and Local Initiatives Support Corporation, which have developed dedicated strategies and state-specific commitments to complement existing coordination efforts. When transparent market signals show how, where, and when national organizations can play a catalytic role in delivering value and creating opportunities, they respond.

Lesson 2 A financing ecosystem works best when coordination is treated as core infrastructure, not as a side activity. Recommendations to other ecosystems:

• Establish a formal coordination body or “hub.”
• Create shared priorities across market segments.
• Move beyond convening to build ongoing working groups that can put ideas into action.

One of Michigan’s strengths is that organizations are organically coordinating through bilateral engagement, as well as organized forums for strengthening collaboration. These forums have recently taken shape in partnership with the Michigan Climate Investment Hub (the Hub), established in 2025 as an anchor institution designed to attract and accelerate climate investments across the state.

“Michigan’s rich ecosystem of climate actors has indicated a clear appetite for increased collaboration and coordination in pursuit of speeding adoption and increasing access to clean energy and climate mitigation/adaptation resources. The Hub is channeling that demand and acting as a trusted convener and connector – working with in-state and national stakeholders to build lending capacity, attract and mobilize capital, and accelerate deployment to meet the goals laid forth in the MI Healthy Climate Plan.”

— Ben Dueweke
Director of the Michigan Climate Investment Hub

Organizations like the Michigan Environmental Council, Michigan Energy Innovative Business Council, and Michigan Energy Michigan Jobs Coalition are also bringing together businesses, utilities, policymakers, and financial institutions to develop policies, rate designs, and collaborative approaches to capitalize on clean energy economic growth and community development opportunities. Stakeholders across the state recognize a need to continue to align around shared priorities across market segments (more in Lesson 4) to put ideas into practice.

Lesson 3 Durable ecosystems are not dependent on any single funding source or administration, but state leadership can accelerate momentum.

Recommendations to other ecosystems:

• Use state or local support where available to build early momentum.
• Build self-sustaining capital flows and market-driven partnerships.
• Design for resilience to policy shifts.

Early state adoption of efficiency and energy waste reduction policies helped build momentum for clean energy in Michigan. That momentum is reinforced by strong state level initiatives, such as the Department of Environment, Great Lakes, and Energy (EGLE) Office of Climate and Energy’s MI Healthy Climate Plan, which provides technical assistance programs, multi-stakeholder coordination efforts, grant and funding challenges, and communications and promotional strategies.

While state-level programmatic support can be subject to administrative uncertainty, the level of interest across Michigan is suggestive of a long-term, systemic transition that is currently underway. This is displayed by EGLE’s Growing Green Lending Challenge, a dedicated blended-capital program designed to accelerate capacity building, foster partnerships, and drive innovation in Michigan’s clean energy lending ecosystem – which received over a dozen partnership proposals and ultimately announced four winners of the challenge.

Additionally, local jurisdictions have been charting a path forward in defining city leadership by integrating climate into long-term strategy planning for affordability, reliability, resilience and economic growth.

The city of Ann Arbor has developed the A2 Zero Carbon Neutrality Plan, a comprehensive climate partnership plan underpinned by commitments to 100% clean and renewable energy by 2030, a reduction in vehicle miles traveled, residential electrification, energy efficiency and resiliency.

Other communities like the city of Holland and Marquette County have partnered with their local utilities and EGLE to pilot the MiHER Program for residential and multifamily home energy efficiency and electrification upgrades in 2024, which has subsequently been rolled out statewide.

These kinds of initiatives provide early momentum for ecosystem actors to coordinate around and build self-sufficiency.

Lesson 4 Segment-specific strategies outperform one-size-fits-all approaches.

• Map gaps by market segment.
• Create segment-specific working groups.
• Design tailored products.

Different markets require distinct financing tools and coordination strategies.

Institutional density is important, but equally so are the products, tools, and solutions at work across the ecosystem. In Michigan, stakeholders are showing up across market segments with products and solutions designed to address specific barriers to accelerating the local clean community lending and investment opportunity. This suite of solutions includes:

• Origination partners focused on addressing affordability and financial access gaps.
• Risk mitigation tools such as loan loss reserves (LLRs), guarantees, and interest rate buy-downs facilitated by concessional capital.
• Bridge financing products offered through local financial institutions and green banks.
• Aggregation and warehousing to free up balance sheet capital for originators, encourage participation, and attract institutional investors.
• Capitalization funding providing a diverse pool of funding sources for local institutions to scale lending activity and capacity.
• Liquidity pathway support to address capital market access barriers through standardization support, balance sheet commitments, and secondary market development.

While there is strong shared commitment and optimism across the ecosystem in Michigan, organizations naturally focus on different market segments, barriers, and community-specific solutions aligned with their missions. This diversity can make broad discussions on clean community financing less effective for aligning around clear, market-specific priorities. While large forums are valuable for building momentum and awareness, more targeted, segment-specific working groups are often needed to drive practical collaboration and scalable solutions.

For example, the roundtable facilitated by RMI and the Hub surfaced small businesses as a market segment of shared interest across actors, representing a sizable investment opportunity and impact potential for clean energy lending. However, there remains a need for affordable financing products that can align timelines and project sizes with lender expectations and tenures, paired with technical assistance to help build clean technologies into capital expenditure plans. And even within the small business market, not all solutions look the same.

Lesson 5 Technical assistance is as important as capital to avoid under-deployment.

Recommendations to other ecosystems:

• Embed technical assistance into every program and fund as core infrastructure.
  • For lenders: provide underwriting and product design support.
  • For borrowers: offer project planning resources and pre-development resources.
  • For contractors: support technology adoption incentives and capacity.

Without technical support, capital alone will not deploy effectively.

In addition to financial products and services, a number of organizations are actively working to enhance technical assistance programs and coordination efforts across the ecosystem to help build capacity, coordinate priorities, and deploy fit-for-purpose solutions.

Lesson 6 Financing models must be designed around local economics and constraints.

Recommendations to other ecosystems:

• Start with market diagnostics on how energy markets, policy, workforce, and cultural aspects are impacting clean lending opportunity in the state.

Energy prices, workforce, and policy shape what financing models will succeed.

Michigan has some of the nation’s lowest gas prices, and highest electricity rates, presenting a challenge for incremental clean energy lending and associated electrification projects. These dynamics reduce the affordability of many residential clean energy technologies, as shown in RMI’s Green Upgrade Calculator and Market Readiness Map. These challenges are compounded by a limited supply of specialized workers, such as high-efficiency HVAC installers, compared to surrounding states.

While bundling certain technologies presents an economically viable pathway for lifetime savings, it also introduces higher upfront capital demand, financing costs, and misaligned loan tenures and payback periods. This creates additional barriers for many communities with limited access to affordable financing.

Lesson 7 Treat well-coordinated, strategically deployed concessionary capital as strategic infrastructure, and target risk absorption to create markets.

Recommendations to other ecosystems:

• Focus limited resources on portfolio-level de-risking.
• Create a state or regional strategy to deploy concessionary capital.
• Use concessionary capital to develop proof points, strengthen local capacity, and unlock private capital participation.

Targeted risk absorption can unlock private capital and build markets.

Local institutions directly addressing affordability (i.e. community lenders and green banks) need sufficient balance sheet capacity and flexibility. Loan loss reserves and guarantees can help create capacity and build a track record of performance that lowers risk, while simultaneously building portfolios of attractive assets. Still, the availability of concessionary capital is a limiting factor in scalability. Many places face a difficult reality in competing with peers for limited concessionary capital sources.

Our roundtable surfaced interest from participants in aligning around shared priorities and opportunities to coordinate the best use of this capital to create opportunity for all stakeholders and move beyond bespoke use cases to regional strategies and portfolio level approaches.

Lesson 8 Financing alone won’t drive adoption of clean energy — project pipelines are shaped upstream.

Recommendations to other ecosystems:

• Invest in architecture, engineering, and construction (AEC) training and incentives, developer engagement, and contractor education programs to ensure clean energy benefits are designed into solutions.
• Reduce point-of-entry friction by creating more resources and capacity for project pre-development.

Project pipelines are shaped before financing enters the picture.

Understanding true sources of demand is critical in channeling efforts, building strategy, and engaging stakeholders where most effective. While much of the emphasis over the past few decades has been on the need for consumers to drive demand and capital allocators to provide workable financing solutions, in many sectors the real drivers of demand are more nuanced.

Stakeholders of the Michigan clean community financing ecosystem recognized that for a sector like multi-family residential, there is a clear lack of programmatic development across the AEC industry to integrate clean energy solutions into designs, specifications, and manufacturer relations. Absent investor requests, many designers, developers, and contractors are likely to default to business-as-usual where they have existing manufacturing and supply chain relationships. Roundtable participants pointed towards a role for subnational financing ecosystems to help catalyze coordination with AEC industry leaders, noting Passive House Pennsylvania as one model leading the way that could benefit Michigan.

Conclusion

There is more work to be done in Michigan, but the state is one of the leaders in building a collaborative and innovative ecosystem to support clean energy deployment and community development. As such, there is a lot to learn from their experience. Stakeholders across the policy and finance landscape in other states should take these lessons and apply them in their own contexts with the goal of developing resilient financing ecosystems that empower their communities to deploy clean and cost-saving technologies.

 

 

 

The post What Michigan’s Clean Community Financing Ecosystem can teach other US regions appeared first on RMI.

The post Tracking the Growth of Wind and Solar in Rural America appeared first on RMI.

The post The Heat Is On: Decarbonizing Industrial Heat in India and Southeast Asia appeared first on RMI.

Key Takeaways

• Reporting on electricity outages due to supply-side shortfalls is scarce and unreliable.
• Although most grid investments are targeted to increasing generation, customers experience more outages due to failures on the distribution system and extreme weather.
• Renewable resource deployment has not worsened reliability outcomes.
• RMI’s Reliability Dashboard can help inform system planning practices so that grid investments truly reduce customer outages.

Electric grid reliability has been a major topic of public policy and discourse over the past year. If we want to improve grid reliability, and do so in an affordable way, grid planners need to take steps to ensure that the investments they’re making will actually reduce the types of outages their customers experience.

To that end, we decided to take a close look at the numbers to see if the data backs current strategies to enhance reliability. RMI developed a new dashboard, leveraging data reported annually to the Energy Information Administration, to showcase the differences in electric reliability across utilities in the United States.

Recent public policy discourse has focused on the impact of load growth on grid reliability, particularly from data centers, and some policies go as far as trying to prescribe certain types of generators in the name of meeting reliability needs. However, available historic data does not show that load growth or supply-demand imbalances have driven customer outages. Over the past decade, extreme weather and failures on the distribution system — the lower-voltage wires connecting homes and businesses to the bulk electric grid — have been the primary causes of customer outages nationwide.

This reality is already all too familiar to customers, with outages caused by these “major events” reaching a decadal high in 2024. Yet public policy is currently focused on rising energy demand, which does not address distribution system needs and extreme weather risks.

To ensure grid investments are informed by reliability data, utilities and regulators must improve how they track reliability events and incorporate these insights into planning so that the right investments are being made to keep the lights on for all customers.

Planning for a reliable grid

Most regions in the United States plan for grid reliability using a one-day-in-ten-year loss-of-load expectation, a standard that functions as a benchmark that indicates whether further investment in generation is necessary to ensure sufficient ability to meet future demand (“resource adequacy”). While investments can reduce customer outages when they address the specific weaknesses causing outages, this only holds if planning decisions are aligned with the actual sources of interruption. Many outages originate on distribution systems, such as from tree contact or severe weather, where additional generation supply provides little benefit.

Although the grid is only planned to meet the aforementioned resource adequacy standard at the bulk power system level, grid reliability is best understood as an umbrella concept that depends on three distinct components: resource adequacy, stability (or operational reliability), and resilience, across both the high-voltage bulk power system and the lower-voltage distribution system.

Different reliability investments affect these components in different ways and come with very different costs, ranging from low-cost operational and maintenance measures to capital intensive infrastructure investments. Ideally, planners would sequence investments by prioritizing lower-cost actions first and ensure that higher-cost measures are tightly targeted to pesistent, demonstrated sources of unreliability.

This approach would help ensure that spending produces measurable improvements in customer reliability metrics rather than defaulting to an overreliance on resource adequacy alone. However, current data collection practices obscure which component(s) failed during an outage, making it difficult to align investments with the true drivers of customer interruptions.

Quantifying grid reliability

Utilities track two key metrics when looking at the historical reliability of their system: outage durations and outage frequencies, with the threshold for an “outage” being a loss of power for five minutes or longer.

Outage duration is tracked using the System Average Interruption Duration Index (SAIDI). This metric tracks how long the average customer was without power over the course of each year. Outage frequency is tracked using the System Average Interruption Frequency Index (SAIFI). This metric tracks how many times the average customer lost power over the course of each year.

Both of these metrics can be combined to determine a utility’s outage restoration, also known as the Customer Average Interruption Duration Index (CAIDI). CAIDI tracks the average time it took electric providers to restore power to customers each year, or put differently, how long the average customer was without power when there was an outage.

From our new Reliability Dashboard on the Utility Transition Hub, we can see that over the past decade, US electricity customers experienced, on average, about six hours without power annually. However, variation from state-to-state and utility-to-utility can be significant, so be sure to check out our full dashboard to explore reliability in your state or utility.

Three key takeaways from historical reliability data

When we look at reliability data and drivers of outages for customers over the past decade, we see three key trends:

1. Reporting on outages due to supply-side shortfalls is scarce and unreliable. Only about half of utilities report this metric, and each utility’s definition of “loss of supply” can vary. Utilities that do report this show that loss of supply was a minor contributor to customer outages over the past decade.

Inconsistent definitions mean that some outages classified as supply-related may actually occur on distribution systems. As a result, it is impossible to parse whether reported supply-side outages are due to power plant outages, transmission versus distribution failures, fuel supply issues, or any other factors. This reduces planners’ ability to ensure that future investments are actually addressing the most critical system needs.

For utilities that track those occurrences, loss of supply was a minor contributor to system outages. From 2014 to 2024, 57% of respondents separated outages that were due to loss of supply, and in the past five years, those outages represented less than 10% of the duration of outages the average customer experienced. In other words, for over 90% of the time that customers were experiencing outages, their utilities did not attribute these outages to supply-side shortfalls, and instead attributed them to distribution system failures.

2. Although planned investments achieve modeled targets, in reality, customer outages can exceed those targets due to failures on the distribution system and extreme weather.

The one-day-in-ten-year (which can be translated to 2.4 hours per year) planning standard is typically used to propose new supply-side resources (power plants, transmission, etc.) until modeling results meet that bulk system resource adequacy target. However, when we retroactively evaluate the average duration of customer outages over the past 10-year period, we see that many customers do not experience that standard — especially when incorporating major events.

This indicates that although utilities may be meeting their supply-side standard in planning, other types of vulnerabilities not accounted for — particularly on the distribution system — are driving customer outages beyond planning standards.

Utilities in more than half of states do not conduct comprehensive integrated system planning that includes the distribution system. As a result, while utilities plan to have enough power plants to limit bulk system outages to an acceptable resource adequacy standard, the same is not applied to the distribution system, leading to worse outcomes for customers.

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}}});

3. In contrast to what some policies suggest, renewable resource deployment has not worsened reliability outcomes.

When we pull in data from the amount of deployed renewable resources in each state over the years, and connect it with this measured reliability data, we don’t see evidence that renewable resources reduce reliability. In fact, states exposed to extreme weather and heavy forests have longer customer outages on average. Overall, clean energy deployments have supported grid reliability through day-to-day operations and numerous extreme storms.

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}}});

What regulators and grid planners can do to make informed decisions about reliability and encourage affordable investment

The same focus that has been placed on potential outages of the future needs to be placed on the experienced outages of today to ensure customers aren’t overpaying for grid investments that don’t meet their needs. To ensure data-driven decision-making that produces an affordable, reliable grid, regulators and grid planners can pursue the following:

• • Use RMI’s new Reliability Dashboard to learn more about your state’s reliability, inform system planning practices, and improve the way that reliability data is tracked and reported so that grid investments truly reduce customer outages.
    • With the rapidly evolving needs of consumers today (and entirely new classes of consumers, like datacenters), data tracking must be updated to better assess and address reliability. For example, outages from supply-side shortfalls should be clearly distinguished from transmission or distribution issues. In 2025, the Hawaiian Electricity Reliability Administrator in filing F-338153 recommended this be addressed with a generator-specific outage metric, as well as the use of segment-specific derivatives of SAIDI and SAIFI that differentiate between transmission and distribution. These metrics are already in use by other utilities internationally, such as those in Canada, Sri Lanka, and some African countries.
    • Regulators can initiate compliance dockets for more detailed data, such as Michigan Public Service Commission’s docket U-21122, which requires utilities to report information about their worst-performing circuits and zip codes with the worst and best outage rates, and outline their plans to improve reliability.

• • Deploy available technologies that address the specific reliability issues localities face today, keeping in mind the evolving grid. 
    • Solutions to load growth are often framed around large, capital-intensive investments on the bulk power system, like new power plants, which can be expensive and may do little to reduce customer outages. In contrast, commonly overlooked and lower-cost solutions such as energy efficiency, virtual power plants, and advanced transmission technologies can both help accommodate load growth and meaningfully improve customer reliability, particularly where outages are driven by the distribution system and extreme weather. These lower-cost solutions are often overlooked due to the prevailing cost-of-service utility regulation model, which biases utility investment toward high capital cost investments. Regulators can investigate performance-based regulation practices that would help counter this bias and restructure utility incentives to ensure affordable approaches are leveraged.
    • Regulators can require their utility to perform integrated distribution system planning aligned with best practices that considers investments at all levels of the grid.
  • Intentionally plan for resilience to major events via improved forecasting and infrastructure.
    • Improve forecasting and extreme weather considerations to better plan for the system to be resilient to future excursions beyond normal conditions.
    • Build resilient inter-regional transmission in coordination with neighboring regions to access resources and support across the United States during wide-area storms.
    • Leverage battery energy storage systems (both transmission-connected and distributed in virtual power plants) to directly reduce outages, and also reduce costs via temporal electricity price arbitrage.

As utilities ask consumers to pay more for their investments amid soaring bills, data-backed and informed decisions matter now more than ever. Improving data collection practices to become more standardized and reflect different levels of the grid is necessary to capture the complexities of grid needs to a sufficient level of detail. RMI’s new Reliability Dashboard can help regulators and planners interact with and learn from existing data, and identify smart improvements that serve all customers’ needs.

RMI’s Gaby Tosado and Jon Rea were both critical collaborators in developing the new Reliability Dashboard on the Utility Transition Hub.

The post Reliability Explored: What a Decade of Data Tells Us About US Grid Reliability appeared first on RMI.

Energy affordability has become a dominant concern across the country. After over a decade of household electricity bills growing with or slower than inflation, average residential electricity bills have outpaced inflation in 41 states over the past two years.[1] These rising costs increasingly strain household budgets, driving ongoing efforts to improve energy affordability around the country. And these energy affordability dynamics extend beyond households, to businesses of all sizes.

Governors are in a unique position to promote energy affordability because of their role at the intersection of state decision makers and their ability to affect change through a variety of tools like executive orders, legislative agendas, and regulatory directives. And they’ve been leveraging this unique position. Over the past three years, governors in 37 states have taken action on energy affordability. In the second half of 2025 alone, governors in 26 different states took an affordability-related action.

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}}});

We compiled data on governor-led actions between January 2023 and January 2026 and analyzed them across several dimensions to understand how governors are choosing to address this complex issue and to identify examples that others might replicate. While this article is primarily focused on efforts to promote residential affordability, many policy solutions can have impacts that extend to commercial and industrial customers. As states continue to wrestle with this challenge, we find that governors taking effective actions are using two approaches that respond to the gravity of this moment and address longstanding, systemic affordability issues:

1. Deliver holistic reforms: Governors are enacting a suite of policies that together safeguard vulnerable households, control the growth in system costs, distribute costs appropriately to different customers (including between residential, commercial, and industrial customers), and give all customers more control over their bills.
2. Balance the timing of impact: These actions are providing both near-term relief to ensure customers realize benefits quickly and long-term system reforms while considering how long the impacts of different policies are likely to persist.

Looking ahead, governors can drive holistic affordability packages through a coordinated set of actions that safeguard vulnerable households, control system costs, distribute costs efficiently, and improve customer agency, delivering on both near-term relief and long-term system reforms. Below, we draw on our research to share key insights and recommendations for how governors can effectively work with other state decision makers to improve energy affordability through this framework.

Governors sit at the intersection of key decision makers

Governors can play an important role in promoting energy affordability through executive action, legislative proposals, regulatory directives, and convening industry and state leaders. Critically, governors can work with a variety of other actors, or they can act independently to promote energy affordability. Because of their unique position relative to other decision makers, governors can affect a diverse set of actions — from standing up state energy efficiency programs to coordinating with wholesale market operators — to address energy costs. The table below shows how different actors can influence energy affordability and provides real-world examples of governors effectively working with each actor.

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}}});

States need holistic reforms to address their affordability challenges

Energy affordability is a complex problem, so we need holistic solutions. A diverse set of factors like aging infrastructure, electricity load growth, and extreme weather are driving energy costs, and there’s no one-size-fits-all approach to address these challenges. Fortunately, policymakers have many tools at their disposal to promote energy affordability, but it’s critical to deploy them in an effective way. In our Electricity Affordability Toolkit, we identify affordability policies across four key focus areas: safeguards for vulnerable customers, cost control, cost distribution, and customer agency.

• Safeguards ensure that households facing the most severe forms of energy insecurity have access to energy and can afford their bills. Safeguards can be embedded into cost control, cost distribution, or customer agency policies by targeting vulnerable communities in policy design. State example: In Maryland, Governor Moore issued an executive order creating the Maryland Energy Advisory Council and directing them to identify recommendations to strengthen the state’s energy assistance programs. The Council will identify potential changes to these programs to improve affordability, bill stability, and energy access for vulnerable households.
• Cost control policies manage the overall size of the pie. They help ensure that utilities prioritize efficient investments and deliver energy in a cost-effective manner. State example: In New York, Governor Hochul’s Ratepayer Protection Plan includes a suite of cost control policies like modernizing rate case procedures to allow regulators to better evaluate rate utility proposals, requiring utilities to submit budget-constrained proposals in rate cases, and investigating utility bills to ensure prudent utility spending.
• Cost distribution policies help distribute costs to different groups (e.g., customer classes, income groups, utilities, private industry, etc.) in a way that promotes affordability for all. State example: In Alaska, Governor Dunleavy championed legislation to create the Alaska Energy Independence Fund, a green bank intended to leverage public financing to support sustainable energy investments and energy upgrades for households and businesses.
• Customer agency policies improve customers’ ability to control and manage their energy bills. State example: In Colorado, Governor Polis launched the Colorado Energy Savings Navigator, an easy-to-use online platform for households to identify their eligibility for over 18 energy assistance programs and 600 utility, state, and federal incentives for energy tech upgrades.

We identified the primary focus area of each governor-led action in our research, and you can see the results in the chart below. Across the country, we found that governors addressed each of these types of policies, but cost control policies are the most popular. Governors in 33 states took cost control actions while only 16 governors enacted policies promoting customer agency. One reason for the popularity of cost control actions is that they target the perverse incentives created by the traditional utility regulatory structure, which create high spending and contribute to growing costs for everyone.

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}}});

However, it’s critical for governors to advance balanced packages that address each of these focus areas and provide holistic relief. For example, focusing on cost control actions can manage upstream spending but does little to improve energy affordability for vulnerable populations or give households and businesses more options for managing their energy bills and vice versa. We found that most governors prioritized actions in at least two areas, but governors in 14 of 37 states only acted in a single area. Governors in 9 states targeted every category to deliver holistic relief. For example, New Jersey Governor Mikie Sherrill’s executive orders include each category:

• Safeguards – directs the Board of Public Utilities (BPU) to identify opportunities to increase investment in low-income energy efficiency programs.
• Cost control – directs the BPU to complete a study on modernizing the utility business model through tools like performance-based regulation, multi-year rate plans, and review of supplemental transmission projects.
• Cost distribution – directs the BPU to review components of the societal benefits charge on ratepayer bills without compromising funding for energy assistance programs.
• Customer agency – directs the BPU to create a virtual power plant program administered by electric distribution utilities.

Give customers near-term relief and champion long-term system reforms

In addition to prioritizing holistic actions, states are balancing the need to provide near-term relief and address long-term system challenges. Governors face a tough but achievable task. It’s not possible to solve the problems driving energy costs overnight, but households are feeling the crunch right now.

As mentioned above, electricity bills are growing quickly in many states, and even before recent growth, one in three households reported sacrificing necessities like food or medicine just to pay their energy bills. As a result, governors are tasked with providing the near-term relief needed by so many while also promoting the reforms necessary to provide long-term affordability. As governors wrestle with this challenge and design affordability packages, they can consider the timing and persistence of relief provided by different affordability policies.

Near-term policies like bill rebates, energy efficiency programs, and disconnection protections can be implemented within 1–2 years (or even quicker, if expanding adoption of an existing program or rate) and start benefitting customers. Long-term policies like utility regulation and rate reform (e.g., performance-based regulation, fuel cost sharing, etc.) and siting and permitting reform can take a few years (or longer) to implement and deliver savings to all ratepayers. The chart below shows the most common governor-led affordability policies we found in our research by impact time horizon.

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}}});

Overall, we found that governors balanced near- and long-term actions, as long-term actions account for about 65% of all actions while near-term actions account for 35%. Governors focusing on near-term actions often did so by bolstering discount rates or energy assistance programs and issuing one-time bill credits. Common long-term actions included those focused on reforming utility business models, deploying new energy resources, and improved transmission planning. Some notable examples of governors balancing near- and long-term priorities include:

• In Connecticut, Governor Lamont played a key role in passing legislation that includes a suite of energy affordability provisions. Near-term policies include public financing of energy assistance programs and a requirement for utilities to consider grid-enhancing technologies when evaluating transmission projects, among others. Long-term reforms include leveraging ratepayer-backed securitization for recovery of storm-related costs. The legislation is estimated to immediately save households approximately $100 per year off their electricity bills and deliver even greater savings to business customers while paving the way for long-term cost reductions.
• In Virginia, Governor Spanberger’s Affordable Virginia Agenda includes six bills to provide near- and long-term energy affordability. Near-term policies include expanding low-income energy efficiency programs and enabling balcony solar. Long-term reforms include optimizing grid planning and expanding energy storage capacity to reduce the need for costly generation during periods of peak demand.

In addition to pursuing both near- and long-term actions, it is important for governors to consider how the affordability benefits of actions persist over time. Affordability policies will have different impact time horizons, and their benefits will also vary in size and persistence based on policy design. For example, some near-term actions may only provide temporary relief while other actions can be implemented quickly and provide more sustained relief. Here are a few examples of different policies and how their affordability benefits can vary over time:

• Bill rebates can be implemented in the near term and be structured to provide one-time relief or more persistent relief if tied to a recurring revenue source like a cap-and-invest program.
• Ratepayer public advocates can be stood up in the near-term and provide long-lasting affordability benefits through intervention in rate cases and other regulatory proceedings.
• Virtual power plants can be implemented in the near- to medium-term and their benefits can grow over time as they become more advanced and are integrated into distribution system planning.
• Utility business model reforms like performance-based regulation will take years to implement and start delivering savings to ratepayers, but they provide highly persistent benefits by shaping utility spending for years to come.

Governors can apply these concepts as they seek to balance the dual objectives of providing immediate relief to households and businesses while also delivering long-term system reforms. It is critical to address near- and long-term affordability challenges, but the exact mix of near- and long-term policies will vary based on a state’s specific needs. For example, states with surging bills might initially prioritize providing immediate relief through bill rebates and safeguards like disconnection protections and low-income discount rates. States facing high load growth in the next 10 years might initially focus more on long-term policies like siting and permitting reform and ratepayer protections from large loads.

Governors have the tools they need to promote holistic, long-term energy affordability

Energy bills are rising quickly across the country while the energy system is strained by factors like high natural gas prices, extreme weather, and load growth. Fortunately, governors have many tools at their disposal to promote energy affordability, and they can have an outsized impact due to their unique position relative to legislatures, state agencies, utility regulators, and grid operators. Looking ahead, governors can promote near- and long-term affordability through a coordinated set of actions to safeguard vulnerable customers, control system costs, distribute costs efficiently, and improve customer agency.

[1] Based on state average electricity bills in July of each year calculated from Form EIA-861M data. Consumer Price Index for all urban consumers comes from the Bureau of Labor Statistics.

The post The Governor Affordability Agenda appeared first on RMI.

Clean steel production will require an enormous amount of clean energy. Producing green hydrogen, operating high-temperature gas heaters, and powering electric arc furnaces will dramatically increase electricity demand at primary steel mills in the United States, and demand could reach gigawatt scale for individual commercial facilities. Therefore, every unit of energy (electrical, heat, or chemical) avoided or reused reduces the scale and cost while accelerating the speed of the renewable buildout required to support commercial-scale near-zero steel production. Improving energy efficiency is sometimes viewed as primarily a strategy for making incremental improvements to legacy infrastructure, but it will also be foundational to making new, deeply decarbonized pathways competitive and viable.

Finding hidden efficiencies

For more than a century, industrial manufacturers have understood the value of efficiency. Steel, cement, and chemical producers have long sought to recycle waste heat, byproduct gases, and residual materials, though not primarily for climate reasons, but because doing so lowers costs and improves competitiveness. Industrial recycling has often been, at its core, an energy strategy. Facilities routinely investigate opportunities to capture value from solid, liquid, and gaseous streams through onsite reuse or external sales.

Yet one major waste stream has largely eluded this efficiency-driven approach: carbon dioxide (CO₂) rich flue gas. In conventional ironmaking, carbon monoxide (CO) and hydrogen (H₂), derived from coal or natural gas, reduce iron ore (FeOₓ) into metallic iron (Fe), producing CO₂ and water in the process. These gases are typically vented to the atmosphere, representing not only a major source of emissions but also lost molecular value and embedded energy.

From flue gas to value

Unlike scrap steel or waste heat, flue gas emissions have historically been viewed as unavoidable and unusable. Flue gas streams are often diluted and contaminated with particulate matter, water vapor, and other impurities. CO₂ itself is chemically stable and does not readily participate in further reactions without significant energy input. For these reasons, it has long been treated as waste rather than as a resource that could be recaptured and reused, but that is starting to change.

Researchers at the Hydrogen and Electrochemical Research for Decarbonization, or HERD Lab, at the University of Wisconsin-Madison are developing a system designed to recycle steelmaking flue gas. Using solid-oxide electrolyzers (SOE), the team converts streams of CO₂ and water (traditional flue gases) back into carbon monoxide and hydrogen (recycled top gases in Exhibit 1). These regenerated molecules can then be reintroduced into the iron reduction process, creating a near-closed-loop system that minimizes waste and maximizes energy productivity.

In addition to the HERD lab the project team is comprised of several others, including industry partners Cleveland-Cliffs (Cliffs), FuelCell Energy (FCE), and Electric Power Research Institute (EPRI), and partners in research and academia, i.e., Laboratorio Energia Ambiente Piacenza (LEAP), University of California, Irvine (UCI), Politecnico di Milano (PoliMi), and University of Wisconsin-Madison (UWM). Cliffs works as the Toledo iron plant operator and system integrator, while FCE is the SOE manufacturer and balance of plant integrator. LEAP and PoliMi are responsible for system design, flexible operation and carbon utilization, while UCI is responsible for developing SOE system control strategies. EPRI focuses on techno-economic analysis and life-cycle analysis of the full-scale system.

Electrolyzers are not new, but what distinguishes SOE systems is their ability to operate efficiently at the high temperatures common in steel production. SOEs can leverage industrial heat and pressure conditions to improve the thermodynamic efficiency of hydrogen production. When integrated into a direct reduced iron facility, this approach can dramatically reduce overall fossil fuel consumption and decrease typical electrical energy demand for electrolysis by leveraging available heat energy.

In practical terms, that means fewer installed renewable megawatts are required to produce a ton of near-zero steel. By reducing total energy intensity and recycling key molecules within the process, technologies like this can shrink the renewable energy burden associated with deep decarbonization and make the transition more achievable in the near term.

Exhibit 1: Integrated SOE-DRI configuration

We recently sat down with Dr. Luca Mastropasqua, who leads the HERD Lab research team, and RMI steel expert Nick Yavorsky to discuss how this technology works, what it could mean for steelmakers and regional economic development, and what comes next. The conversation has been edited and condensed for clarity.

RMI: Dr. Mastropasqua, what excited you the most about the potential for this technology?

Dr. Mastropasqua: This technology is one of the few able to reduce ironmaking emissions by more than 94% compared to typical natural gas DRI systems (~500 kgCO₂/tDRI vs ~30 kgCO₂/tDRI) and 98.5% compared to coal-based blast furnace basic oxygen furnace production. At the same time, this technology will minimize the use of total energy inputs (either fossil or renewable sources). This technology shows energy savings of approximately 40% against traditional natural gas DRI (11 GJ/tDRI vs 8 GJ/tDRI) and 10% compared to other hydrogen DRI systems (9 GJ/t DRI vs 8 GJ/t DRI).

One of the most synergistic aspects of this technology is that we are not only doing thermal integration, in the form of waste heat recovery, but also chemical integration. We are recovering chemical content and upgrading it to a more valuable stream, rich in hydrogen, that can be repurposed to displace additional natural gas.

RMI: How does your research and technology demonstration advance from where it is today?

Dr. Mastropasqua: The SOE technology must be demonstrated at the megawatt scale in real industrial sites before commercial-scale systems can be deployed. This is key to developing the necessary manufacturing capacity to cut manufacturing costs. We need to build gigafactories in the same way we did for Li-ion batteries. This will allow us to convince the steel industry (as well as many other industrial sectors) that SOE systems can be utilized for behind-the-meter, on-site hydrogen and syngas generation at the scale required by current plants (i.e., 100s MW of equivalent hydrogen, and GW-scale electrical capacity).

I expect that, if the main US manufacturers of SOE systems continue with their capacity build-up, we should be able to get to full commercial scale in the next 5-8 years.

RMI: Globally, we expect DRI production to increase in the coming decades. Can you explain how greenfield deployment of your technology has different implications than retrofits at existing assets?

Dr. Mastropasqua: The main difference between brownfield and greenfield deployment for this application is connected to the primary energy source of choice, i.e., fluctuating energy source like solar or wind versus firmed resource like fossil fuels, grid, geothermal, or nuclear. Since ironmaking plants want to operate at steady state close to their nominal design point for 8,000 hours a year, coupling with an intermittent resource requires large buffer systems: hydrogen storage, syngas storage, or thermal storage. On the other hand, existing brownfield systems could install an SOE plant to upgrade their reducing stream without the need for large-scale storage facilities, if their primary electricity source comes from the grid. However, this solution does not guarantee the same degree of decarbonization, given that most of the US electric grids don’t have a sufficiently low carbon intensity yet. As far as the shaft furnace technology is concerned, they have already been demonstrated to be able to operate with pure hydrogen.

RMI: How does your proposed technological solution compare to carbon capture and storage (CCS) or other forms of retrofitted decarbonization technologies at steel mills?

Dr. Mastropasqua: Some CCS technologies have a breakeven cost of carbon that is competitive with current cap and trade systems in EU. In the United States, the 45Q tax credits provide a real incentive to install CCS systems for enhanced oil recovery or permanent storage. However, most CCS systems (post-combustion, pre-combustion, or oxyfuel) have a specific primary energy consumption per unit of CO₂ avoided (SPECCA index) that varies between 2-4 MJ/kgCO₂. This means that plant owners must consume between an additional 2-4 MJ of primary energy relative to their usual consumption to capture every kg of CO₂. This translates into additional energy supply costs. With an SOE, the SPECCA index would be negative! We would be able to avoid the emission of CO2 and reduce the primary energy consumption at the same time.

CCS technologies certainly have a role in decarbonizing heavy industries, and we have worked on electrochemical carbon capture and storage technologies applied to the steel sector that show SPECCA values close to zero, i.e., do not introduce any energy penalty compared to a non-CCS system. One should also consider the availability of CO₂ storage sites, which can become a limiting factor, considering the amount of CO₂ that the steel sector alone cumulatively emits.

RMI: Nick, how does this type of facility upgrade impact the workforce onsite for DRI facilities? What kind of impact could it have on the long-term steel workforce in the US?

Nick Yavorsky (RMI): As highlighted by Dr. Mastropasqua, the energy efficiency implications for an integrated SOE system at primary steel production sites are immense, but its potential to provide regional economic value for those who choose to implement is also considerable. As a retrofit system, this technology could introduce anywhere from 100 to 400 additional full-time employees, depending on integration and automation. This does not include the several hundred construction workers required to implement the retrofit system or the thousands of workers needed to construct, operate, and maintain the hundreds of megawatts of upstream renewable energy resources needed to supply the SOEs with clean power.

In addition to the regional workforce growth potential, these types of systems will help US steelmakers produce more valuable products. Potentially accessing a higher price via a market premium while responding to high demand globally, production of near-zero DRI or crude steel products would support the continued operation of US assets for decades to come, with ample opportunity for expansion and continued reinvestment.

Greenfield sites offer the best opportunity to realize the market potential for this technology. Although it can be applied at existing facilities, new plants can likely achieve the greatest energy demand reduction as key systems can be designed intentionally from the start. As indicated by Dr. Mastropasqua’s1 energy and emissions reductions estimates, sites where thermal and chemical integration are paired with energy storage capacity and flexible operation schemes are positioned to become the most attractive for producers looking to maximize profits and compete against other global near-zero emissions approaches.

Fundamentally, deploying energy, cost, and climate-efficient systems like this one can help to revitalize the dwindling US primary steel production base and the economic prosperity it brings.

RMI: Are there any other groups exploring similar technology pathways?

Nick Yavorsky (RMI): Yes, in addition to the research being conducted at the HERD lab, the team at Helix Carbon is also exploring the reuse potential of steel production off-gases as a means of reducing energy demand onsite. That’s good news, because energy efficiency innovations that increase the cost competitiveness of clean industrial solutions are greatly needed, and the more arrows in the technological quiver, the better.

With both groups producing promising modeling results backed by extensive lab testing, the hunt for commercial partnerships and deployment opportunities is on. Incumbent steel manufacturers in the US and abroad will soon be clamoring to incorporate these types of systems to reduce operating costs and help clean up their production.

RMI: What are some of the remaining challenges with continuing and scaling your work?

Dr. Mastropasqua: There are still quite a few research and development questions that must be addressed to increase the lifetime of these systems, especially when expected to operate with “dirty” feedstocks typical of the ironmaking sector.

Some exciting research avenues show that we can tailor the operation of the SOE system to match specific compositional targets for integration in DRI systems. This will make these electrolysis systems a drop-in replacement for the conventional steam reformers generally used for syngas production.

Public funding and support are key to demonstrating continued interest in US manufacturing industries that need to scale up capacity. Similarly, investment in R&D at universities is needed to support overcoming longer-term material degradation challenges, as well as educating future workers on electrochemical technologies.

Finally, an ecosystem of industry, national labs, philanthropies, and academia working in collaboration to demonstrate these technologies at industrial scale can further accelerate impact.

The big idea

Efficiency improvements have long been leveraged at industrial sites. Now, it is time for the next generation. Technologies like this point to a pathway where energy savings and emissions reductions go hand in hand, reducing overall energy use, making the scale of the challenge easier to solve, and ultimately unlocking a faster, more competitive future for iron and steelmaking over the next century.

The post Maximizing the Efficiency of Clean Steel Production and Achieving Cost Competitiveness appeared first on RMI.

The United States government has entered a new era of financing critical minerals projects, deploying tools that go far beyond the grants, loans, and tax incentives that have dominated US industrial policy for decades. Over the past year, the federal government has ramped up its investment strategy with a series of equity stakes in private critical mineral projects and companies.

These investments underscore the importance of critical minerals to the US economy and national security and demonstrate the lengths to which the US government is willing to go to diversify supply chains. Critical minerals are key inputs to defense, energy, and AI technologies. If the US wants to meet rising electricity demand  while creating more secure energy supply chains, it needs a more reliable supply of critical minerals.

Diversifying critical mineral supply chains will require investment, and government equity is emerging as a favorite tool of the Trump administration to de-risk and stabilize the sector. US critical mineral production is costlier than China’s, and new projects require high up-front capital costs and long lead times. While up-front investment from the federal government can help push projects forward, their long-term success will ultimately depend on market stability and sustained product demand. So far, critical minerals projects that have received equity investments have experienced jumps in their stock prices and additional private sector investment.

Yet, while equity deals can shore up or kick-start projects, it is yet to be seen whether they can create the market signal required for a sustainable operating environment. To build a durable US critical mineral industry, federal supply-side investment, like equity, must be paired with demand-side support to create a sustained market.

In the meantime, developing a Congressionally authorized program that follows the critical mineral equity investment framework proposed in this article can strengthen deals and create a suite of coordinated investments that help stabilize the critical minerals market.

Why is the critical mineral industry attracting government investment?

Critical minerals are significant inputs to a broad array of technologies in different industries, including semiconductors, permanent magnets, electric motors, transmission, batteries, solar photovoltaic cells, wind turbines, and advanced industrial equipment. Key minerals to the energy transition include copper, gallium, nickel, rare earth elements, graphite, lithium, and cobalt. These minerals are used in everything from chips to cooling systems in data centers to actuators and alloys in specialized defense equipment.

The critical mineral market is concentrated in a few countries, creating the potential for supply disruption, with China dominating the critical mineral mining and refining market. The US Geological Survey found that the US relies on China for 24 mineral commodities, and China is the leading producing nation for 30 critical minerals globally. China controls the global production of approximately 77% of natural graphite, 70% of rare earth elements, and 98% of gallium.

Market concentration in China has created complex trade dynamics and market uncertainty. In 2023, China announced export controls including permit requirements for exports of gallium and germanium and a ban on rare earth extraction and separation technologies. In the spring of 2025, the US announced import tariffs on China, and China announced export controls on seven heavy rare earth elements. US investment in critical minerals would reduce dependence on China by creating a new steady supply.

Government critical mineral equity deals

The US government has historically invested in critical mineral companies to spur domestic industry, promote innovation, and stockpile key national security inputs. These investments have mainly been grants and loans managed by the Department of Energy, Department of Commerce, Department of Defense, and the US International Development Finance Corporation.

Tax credits have also been used to incentivize domestic production of critical minerals and battery components, such as the Advanced Manufacturing Production Tax Credit (45X), the Qualifying Advanced Energy Project Credit (48C), and the now phased out complementary New Clean Vehicle Credit, which required domestic critical mineral and battery inputs to increase domestic demand.

In 2025, we saw a series of announcements from the US government providing up-front capital to acquire equity stakes in critical mineral mine projects. While equity investments are not new for the US government, the quantity of equity-based investments in the critical mineral sector is, with 7 projects being announced over the past year.

These critical minerals deals have taken stakes in companies or specific projects, such as through a special purpose vehicle, a legal entity created for one specific project separate from a parent company. The deals have included equity stakes, preferred stock, warrants for future stock purchases, and in some cases minority positions on boards, price floors, and offtake agreements.

Historically, federal equity investments have been used relatively sparingly and often in response to specific economic or strategic circumstances. However, US government equity stakes in private companies have crossed sectors and administrations. In 2008, the US Department of the Treasury purchased preferred stocks in several banking and automotive companies through the Troubled Asset Relief Program to stabilize the US financial system. In 2025, the US government made equity investments in sectors beyond critical minerals, such as Intel and Nippon Steel.

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 trends do we see in critical mineral deals passed so far?

• Many of the projects are already in development or actively under construction.
• The majority of projects are funded by the Department of Defense.
• Many of the projects are financed by more than one federal agency.
• The US government is restructuring existing funding from previously awarded grants and loans into these new deals.
• Deals have been announced alongside already committed private investment. Three deals had subsequent offtake agreements or investments with private companies.
• The majority of projects are for facilities based in the United States. The exception is the Alcoa Sojitz Gallium Recovery Project to build a gallium refinery in Western Australia. This project was a joint investment with Australia and Japan.

The MP Materials deal stands apart because the equity investment is complemented by a guaranteed price floor and an offtake commitment. For 10 years the US government will purchase at $110 per kilogram the rare earth elements product neodymium-praseodymium or price match if purchased by another company for a lower price. The deal also included a 10-year commitment to purchase 100% of the magnets produced at a proposed facility. This sets a powerful demand safeguard to ensure the increased output has a market that can keep the company afloat.

At the time of the deal, China had implemented a tariff of 125% on US imports, including rare earth concentrates from the Mountain Pass mine. Rare earth materials are critically important to defense, and the US government stepped in to ensure the facilities were kept online.

The deals that have succeeded MP materials have not included offtake agreements or price floors. In February this year, the White House launched a new US Strategic Critical Minerals Reserve, Project Vault, to store critical minerals for civilian industries at facilities across the United States, backed by the Export-Import Bank of the United States (EXIM).

A framework to finance the future

As a key input to energy, the US government should bolster investments in critical mineral supply chains to increase domestic capacity and diversify global supply. Equity investments are one financing mechanism that with careful design could help stabilize the critical minerals market.

A congressionally authorized program that provides equity investments in critical minerals projects would codify some of the benefits of government stakes with the purpose of strategically building a portfolio of investments that support long-term market stability. A congressional program would set safeguards to protect market stability and taxpayer funds. Whether establishing a new program or consolidating deals into an existing one, a centralized federal program could sharpen the government’s understanding of the long-term impacts of equity investments while allowing it to build out expertise to better support potential board representation and eventual exit strategies. The program could be cross-sector, covering projects to support acute energy and infrastructure supply chain risks or targeted at critical mineral projects.

With more dedicated resources to evaluate projects, the program could consider the following project framework to maximize market-wide impact and strengthen critical mineral supply chains.

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}}});

So far, deals have been financed by the Departments of Commerce, Defense, and Energy. A new program could either sit in one of these existing departments or in a new, more targeted organization.

Going beyond equity deals

Equity deals demonstrate the US government’s willingness to intervene more directly in critical mineral supply chains. They can catalyze investment, accelerate projects, and stabilize strategically important facilities.

To secure the production of minerals essential to energy, defense, and digital infrastructure, the United States should pair capital with predictability and build a coherent, transparent, and strategic program capable of steering investment where it has the greatest impact.

While equity deals provide strong up-front capital, equity alone is not enough. Without demand-side policies that guarantee buyers, stabilize prices, or provide incentives for domestic sourcing, even well-capitalized projects may fail to thrive.

The New Energy Industrial Strategy Center

The NEIS Center is a thought partner, funder, and community builder that helps create advanced energy systems that support competitive economies and power the industries of the future.

The post Securing Energy Supply Chains: One Critical Mineral Deal at a Time? appeared first on RMI.