Rocky Mountain Institute

To keep pace with evolving regulatory expectations and market developments, financial institutions are increasingly turning to corporate transition assessments — evaluations of how a client or investee will be affected by and respond to the energy transition — to gain insights into climate-related risks and opportunities. Yet, despite their importance, transition assessments often fall short of delivering business-relevant intelligence to financial institutions.

This is because today’s assessments often produce superficial snapshots of companies. For financial institutions to make informed decisions about capital allocation, client engagement, and risk management, transition assessments must evolve into tools that provide deep, actionable intelligence. Below we discuss the pitfalls of current assessments and point to how some adjustments — even if implemented for a small subset of priority companies — can deliver big returns.

The shortcomings of current practices 

Two areas offer the greatest potential improvements to the value of corporate transition assessments:

First, the level of analytical detail that assessments provide can be strengthened. Today’s assessments mostly rely on companies’ climate targets, governance structures, and aggregated transition-aligned capital expenditures, but rarely examine the operational realities underlying these figures. Without understanding a company’s assets, transition dependencies, or region-specific constraints, it is hard to see where a company is headed, what stands in their way, and how financial institutions can support companies or mitigate associated risks.

Second, corporate transition assessments results need to be more actionable. Assessments typically result in high-level ratings or summary scores for a company, which can indicate areas of concern but not necessarily inform practical next steps. If a bank risk officer or relationship manager cannot use an assessment to articulate specific transition risks — or opportunities — for a client, for example, its value is diminished.

Transition intelligence as commercial advantage 

To address these limitations, the financial sector must embrace assessments as tools for delivering transition intelligence. A more robust approach to transition assessments involves integrating feasibility and context into the analysis. This includes three key innovations:

1. Transition Footprint Mapping: Mapping a company’s activities and assets to understand where transition exposure and opportunity really lies.
2. Investment Alignment: Evaluating whether a company’s actual investment pipeline (beyond aggregate capital expenditure figures) is consistent with stated targets and sector and regional pathways.
3. Dependency Mapping: Understanding how market factors, technological developments, and national policy frameworks shape what is possible and when for different companies.

Although financial institutions face capacity and data limitations across extensive portfolios, implementing even a handful of these practices for high-priority companies can yield significant benefits. The following contrasting examples of assessments of a major power producer illustrate why depth matters:

Assessment 1: Superficial Snapshot

• The company has a transition assessment score of 3 out of 5
• This reflects an ambitious 1.5°C-aligned target for 2030, but no long-term target
• It also reflects appropriate sustainability governance
• The company has expressed a commitment to build out renewable generation capacity, but lacks capex-based disclosures
• The company discloses emissions annually, but does not include Scope 3 emissions

Assessment 2: Decision-Useful Assessment

• Assessment shows the same disclosures and targets
• Yet, an examination of the company’s projects under construction and announced projects shows a significant gap between the company’s current pipeline and its 2030 target
• The assessment shows the company was primarily relying on the buildout of a new hydropower plant to replace coal assets and meet its target
• The hydropower project failed recently, making it significantly challenging for the company to achieve its transition goals

The second assessment clearly paints a more complex picture. It allows a financial institution to engage the client or investee, meaningfully ask questions about their fallback options for the canceled project, explore financing for alternative low-carbon infrastructure, or flag risk from overexposure to coal in a tightening regulatory landscape. That kind of insight is what creates commercial advantage. It is what allows a relationship manager — who might only get one or two questions on climate with a client per year — to ask the right questions.

A collaborative path forward 

The benefits to more robust corporate transition assessments are significant, but so are the challenges to developing these practices. Many financial institutions already face constraints in building the internal capacity and expertise required for generating transition assessments. Data gaps, especially in emerging markets, further complicate assessments. However, these barriers underscore the importance of investing now in capability-building, peer learning, and cross-sector collaboration.

Emerging frameworks, technological advancements, and AI tools are opening up exciting possibilities to advance assessment practices. What’s needed is a community of practice — financial institutions, regulators, data providers, and civil society working together to turn assessments into a strategic asset — to help financial institutions understand where companies are today, what they aim to achieve, and how capital can be best directed to support credible, effective transition pathways. RMI is working with a community of practice to advance transition assessment practices. In the coming months, we will publish resources and tools including guidance on how to improve transition assessments, selecting and interpreting transition pathways, and incorporating regional context into assessments.

This work — though complex — offers a profound opportunity. Financial institutions are uniquely positioned to enable the global net-zero transition. But to seize this opportunity, transition assessments must move beyond being voluntary or regulatory compliance exercises. They need to deliver value across functions, from risk management to business development, and do so in a way that is scalable and cost-effective.

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Southwestern Pennsylvania may be known as having been the center of the US steel industry, but it now has an opportunity to bolster the regional economy through clean technology manufacturing. The region is well-positioned to leverage its existing strengths — like strong manufacturing and cutting-edge research — to turn around decades of economic development challenges since the decline of steel and the offshoring of manufacturing, while also fostering cleantech clusters that diversify and strengthen the regional economy.  

In the past decade, cleantech costs have fallen by up to 80 percent, while investment has increased nearly tenfold and solar generation has risen twelvefold. Cleantech clusters — a group of interconnected businesses, research institutions, and other relevant organizations in the same or related clean energy industries located in the same region — could help Southwestern Pennsylvania capture this opportunity. As major innovation hubs, cleantech clusters can generate jobs, attract investment, and increase a region’s competitiveness.  

Our analysis revealed three high-potential cleantech sectors that can reinvigorate manufacturing and strengthen regional economic development in Southwestern Pennsylvania: battery manufacturing, solar component manufacturing, and green buildings. To succeed in cluster development, Southwestern Pennsylvania will need to improve coordination and address workforce gaps. Importantly, cleantech cluster development, like all economic development, should ensure employment and other benefits for communities that have historically been left behind.  

Creating jobs and developing an equitable workforce   

Although Southwestern Pennsylvania has an extensive history of coal mining, steel manufacturing, and fracking, it has in more recent years established itself as an innovation hub in biomedical research, robotics, and even AI. The region’s manufacturing legacy and more recent advanced specialization provide a solid foundation the region can build on to support cleantech cluster development and the economic opportunity it offers.  

Battery manufacturing 

Battery energy storage is key to a flexible, reliable grid — especially batteries that use easily obtainable materials and recycling-friendly designs. Southwestern Pennsylvania is a prime location for a grid battery manufacturing cluster because of its existing battery manufacturing, technological innovation, and workforce skills. Local companies have helped develop and bring to market alternative chemistries and novel approaches for batteries. For instance, Eos Energy Enterprises received a $300 million Department of Energy loan to scale the manufacturing of its long duration zinc-based batteries, and startup SeaLion Energy developed a regeneration technology that extends batteries’ lifespans. Further developing these technologies could offer a more sustainable solution to meeting global battery storage demand, which is projected to be nearly six times today’s capacity by 2030.  

Battery manufacturing has already created jobs in the region, and a fully developed manufacturing and recycling cluster could help attract investments in related sectors like electric vehicles, solar energy, and green buildings. However, the region will still need to develop workforce capacity in specialized roles like semiconductor processing and computer hardware and electronics engineering, and it will need to ensure it has the lab space needed to support development and demonstration of new technologies. 

Solar component manufacturing 

The United States has rapidly deployed renewable energy resources over the past decade — clean energy investments totaled over $70 billion in 2024 alone, resulting in 37 GW of additional clean energy generation capacity that could power over 7 million homes — but the country has been slow to manufacture solar panels domestically. In recent years, US-based companies like First Solar have developed some parts of the solar supply chain, but gaps remain to meet the current and projected demand for solar. And now, with the repeal of manufacturing and solar deployment tax credits, and with looming tariffs, the picture for domestic solar manufacturing is more uncertain than ever. 

However, if you’re going to gamble on domestic solar manufacturing, Southwestern Pennsylvania is a pretty good place to bet on. The region already produces steel and aluminum, setting it up well for component manufacturing, and it has a long history of glass production. Vitro Architectural Glass, North America’s largest glass producer, recently upgraded its facility in Meadville, fewer than 100 miles north of Pittsburgh, to produce flat glass for First Solar. JM Steel has been working with NEXTracker since 2022 to produce trackers for solar arrays. This is all important. Southwestern Pennsylvania is one of a handful of places in the country with this past and current expertise.  

Click image to see larger (opens in new tab).

Further, there is substantial overlap between the workforce skills needed for manufacturing both batteries and solar components, and increasing needed capacity in roles like semiconductor processing and computer hardware and electronics engineering would support both clusters. 

Green buildings and related technologies 

As residential, commercial, and industrial buildings are built and retrofit to be more efficient and healthier, they’ll do more than create construction jobs. The demand for these green buildings creates additional opportunities for economic development, like locally manufacturing advanced building materials.  

There have been substantial recent advances in industrialized and automated production of building components and materials, allowing faster, cheaper, and site-appropriate construction. Modular housing builder Module has a Last Mile Facility in Pittsburgh that includes a construction innovation lab, a workforce training program, and manufacturing space. Southwestern Pennsylvania’s strengths in manufacturing and robotics make it an excellent place to manufacture the materials it needs for its buildings, and state programs can spur additional demand. For example the state’s Reducing Industrial Sector Emissions (RISE PA) program is providing $396 million in grants for industrial facility projects that reduce energy costs and air pollution. 

A cleantech cluster initiative can improve coordination and help win cleantech investments 

With so many advantages, why isn’t Southwestern Pennsylvania already a cleantech powerhouse? When it comes to deciding where to site facilities, businesses think about Ohio or southern states first, and Southwestern Pennsylvania economic development stakeholders haven’t prioritized cleantech business attraction. A cleantech cluster initiative — an initiative to steer and organize the region’s efforts focused on cleantech to support the industry’s growth in the region — can help Southwestern Pennsylvania attract investment. The region has similar initiatives for other sectors, such as the Pittsburgh Robotics Network and the Pittsburgh Life Sciences Alliance, which have helped build the region’s dominance in these fields. The Robotics Network, for example, developed a dense geographic cluster that provides workspace, leverages public and philanthropic financial support, and plays the role of promoter and convener to connect and coordinate firms, investors, suppliers, and talent. Total investment in Pittsburgh’s robotics sector reached $4.3 billion in 2022.  

The initiative could help the region overcome key constraints, like helping economic development stakeholders coordinate to proactively attract cleantech opportunities. It could also facilitate collaboration to identify gaps in the regional economic development and lab-to-market ecosystems and empower organizations in those ecosystems to address those gaps.  

These are uncertain times for cleantech manufacturers, but demand for clean energy isn’t going away. Southwestern Pennsylvania’s strengths in innovation and manufacturing position it well to capture the cleantech opportunity. Economic revitalization is within reach if the region can coordinate and proactively prioritize opportunities to build cleantech clusters.

The authors wish to thank RMI’s Aaron Brickman for his contributions to this article.

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Key Insights

• Data center operators are ready to invest in efficient, flexible, and low-cost energy sources that can mitigate stranded asset risks for utilities and keep ratepayer costs in check.
• Data centers use just 2 percent of global electricity today — and may account for approximately 10 percent of projected electricity demand growth between 2024 and 2030.
• Many utilities have a track record of over-forecasting demand, spending billions of dollars building power plants for load that did not materialize.
• We mapped a range of energy solutions for data centers that can temper the risks of over-building and high rate-payer costs.

Before you panic: data centers use just 2 percent of global electricity today

Data centers are large commercial facilities that house servers and other equipment that are used to provide digital services such as email, streaming, real-time navigation, running and developing software, cloud storage, and, increasingly, artificial intelligence (AI) applications for individuals, businesses, and government agencies of all sizes. Data centers require large amounts of electricity to run their equipment while keeping them cool.

Recently, the rapid growth of the AI and traditional cloud forecasts has been causing panic around electricity demand. Media headlines describe the situation as explosive and out of control, causing countries to eventually run out of power.

However, data centers account for just 2 percent of global electricity demand today — and will account for approximately 10 percent of projected electricity demand growth between 2024 and 2030. Globally, data center load growth will be less than other sources of load growth, such as industrial operations, electric vehicles, household appliances, and space cooling.

It’s also worth remembering how power panics in the past have played out. In 1999, Forbes ran an article declaring that half of the electric grid would be powering the digital economy within the next decade. In 2017, the World Economic Forum warned that Bitcoin would consume more power than the entire world by 2020. But neither of these happened. Globally, the share of electricity going to data centers has remained under 2 percent, and cryptocurrency today consumes just 0.5 percent of global electricity.

Exhibit 1

The data center challenge is best understood at the local level

One potential challenge is the tendency for data centers to concentrate in specific regions due to preferences for fast connectivity and cheap power, land, and water. The shift to hyperscale data centers — which can be as large as 1–2 gigawatts (GW), more than 100 times the size of traditional data centers — is likely to further contribute to data center concentration.

Data centers already account for a large percentage of overall electricity load in certain regions. In Virginia, home to the world’s largest data center market, data centers account for about 26 percent of state-wide electricity demand, compared to the US average of about 4 percent. This can pose unique reliability concerns for the local grid: last summer, Northern Virginia narrowly avoided widespread blackouts when 60 data centers simultaneously switched to backup power in response to a grid equipment fault. In Ireland — the second largest data center market in Europe—data centers account for about 21 percent of electricity demand. EirGrid, the Irish utility, has had a de facto moratorium on new data centers since 2022, and Irish policymakers are considering legislation that could require data centers to actively contribute to alleviating grid constraints.

Fortunately, local jurisdictions and utilities have a range of options available to meet and manage load growth. This includes building new generation capacity; deploying grid enhancing technologies; implementing energy efficiency, demand response, or bring-your-own-power (BYOP) requirements; requiring capital commitments; and even placing moratoriums on new data center requests. Data centers have also been proactive — shifting facility construction to new geographic markets, investing in flexibility and energy efficiency research and development, installing their own generation and storage sources, and more.

While there is an uptick in data center demand, it is just one part of the broader electricity load growth puzzle. In the past, utilities have successfully managed greater load growth than what is expected over the next decade. This time, we have an even greater variety of technologies and policies available to make it work as well as an ambitious data center industry willing to make the necessary investments.

A fork in the road: the path well-trodden poses affordability risks

The concern is not whether data centers will cause regions to run out of power, but how utilities and regulators respond to the increased electricity demand, and the impact those decisions will have on ratepayer affordability and net-zero goals.

Historically, utilities have had a track record of over-forecasting: in the United States, utilities over-forecast 10-year demand growth by more than 17 percent​ between 2006 and 2023. Systematic over-forecasting like this means that utilities have spent billions of dollars building power plants for load that did not materialize, leaving regular ratepayers to foot the bill.

Exhibit 2

This risk will become even more salient in the following years given the high uncertainty of data center load growth. The range across forecasts is significant: according to the IEA, global data center electricity consumption could increase by anywhere from 300,000 to 1.3 million GWh in 2035. Moreover, there are significant unknowns around improvements to future hardware and software efficiency, the evolution of AI products and training practices, and the emergence of new business models. Each of these could sway overall data center energy demand. Not all proposed data centers will be fully utilized or get built: some estimate that speculative interconnection requests could be 5 to 10 times more than the actual number of data centers, as data centers “shop around” for the fastest interconnection opportunities and cancel data center projects in oversupply.

Exhibit 3

Meanwhile, there are reports of utilities across the United States starting to build new natural gas plants in preparation for this uncertain data center demand. Our analysis shows that planned gas capacity between 2021 to 2024 stayed relatively flat according to utility integrated resource plans (IRPs) but has jumped about 20 percent — by 52 GW — in the past year. This is bad news for ratepayers: if data center demand is less than expected, ratepayers may still be saddled with paying for the new plant and be exposed to fuel price volatilities.

In some regions, utilities are also turning to coal lifetime extensions, which can also lead to higher electricity rates, since coal plants become more expensive to operate as they age.

Exhibit 4

A better path forward: managing load growth responsibly with fast, low-cost solutions

A more responsible approach to managing load growth focuses on both the supply and demand side of the equation, mitigating ratepayer impact while creating benefits for data centers and utilities. The best solutions will be measures that:

• Reduce the energy data centers use in the first place.
• Enhance flexibility of when and where data centers use energy.
• Deliver energy supply fast, modularly, reliably, and at lower cost.
• Ensure the energy supply is right-sized to confirmed loads rather than speculative ones.

Combined, these solutions will help data centers scale rapidly while keeping costs as low as possible; help policymakers and utility regulators balance their priorities of attracting economic growth, ensuring energy affordability for their constituents, and generating energy abundance for all ratepayers; and help utilities minimize stranded asset risks.

Exhibit 5 shows the range of energy solutions that are being explored today in response to rising data center energy demand.

Exhibit 5

Reduce energy demand in the first place. Energy efficiency provides benefits to all stakeholders involved. For data center operators and customers, it reduces energy consumption, leading to lower energy bills. For utilities, it reduces the burden on the grid, offering an opportunity to avoid, delay, or reduce the need for costly grid infrastructure upgrades, new generators, or deferred retirements. For the private sector and investors, it provides a compelling business and investment opportunity in new and existing technologies and services that help operators avoid costs and reduce waste. Policymakers around the world are already moving to ensure this opportunity, with many jurisdictions implementing energy efficiency requirements for data centers.

There are a wide range of efficiency opportunities that can reduce data center energy usage:

• Cooling: Cooling accounts for about 20 percent of overall data center energy consumption today. New data centers — especially hyperscale data centers — have significantly improved cooling efficiency, averaging about 7 percent, thanks to technologies such as liquid cooling and equalizers. Energy demand for cooling could also be alleviated by siting data centers in cooler regions, or by incorporating solutions that allow servers to be operated at higher temperatures.
• Hardware: The energy efficiency of computers has improved exponentially, doubling about every two years. This is a large reason why the IT sector has historically consumed less energy than expected, and it is a trend that continues to be seen with leading machine learning hardware such as GPUs and TPUs.
• Software: Computing software and underlying (AI and other) algorithms can run far more efficiently than they currently do, using less computing power and thus energy, for the same result. For example, simply grouping tasks and running them together, instead of sequentially — known as batch processing — can reduce energy consumption by as much as 50 percent.
• Product design: The development of fit-for-purpose AI products may significantly lower energy consumption. Many AI services can be fulfilled with small language models that are built to run specific tasks with fewer resources, consuming more than 90 percent less energy than the large language models widely used today.
• Data management: Over 50 percent of data is so-called “dark data” — created and stored but never re-used. Storing this data requires significant energy use. Better data management and governance policies can help reduce dark data and the associated energy consumption.

Singapore is an excellent example of how far energy efficiency can go. Their Green Data Centre Roadmap, released last year, provides grants for the adoption of efficient equipment and supports R&D for state-of-the-art efficiency solutions. The roadmap covers facility retrofits, liquid cooling, hardware upgrades that allow for higher operating temperatures, and high-efficiency servers and software. These solutions, in combination with renewable energy sources, are expected to free up 300 megawatts of capacity in the near term — over 20 percent of Singapore’s overall data center load (1.4 GW) today — with much more to come in the future. Exhibit 6

Enhance flexibility of when and where data centers use energy. Flexibility offers benefits for data centers and utilities alike. Flexible data centers may be able to connect to the grid faster and can potentially be paid for by demand response services. Demand flexibility helps utilities maintain a stable grid and avoid, delay, or reduce the need for costly grid infrastructure upgrades or new generation capacity. In the United States, if new data centers met an annual load curtailment rate of 0.5 percent — just a handful of hours each year — it could make nearly 100 GW of new load available without expanding generation. That’s roughly equivalent to 1,000 hyperscale data centers — double what is in the pipeline today.

There are a variety of approaches to demand flexibility:

• Temporal flexibility (demand response): Data centers have traditionally been considered inflexible loads, but this is changing with the shift toward AI. Certain workloads such as AI training and machine learning are less time-sensitive than traditional data center workloads and can tolerate brief interruptions.
• Generation and storage flexibility: Data centers already install on-site backup generation to stem temporary disruption to electricity supplied by the grid. These are usually emergency-only diesel generators intended to operate no more than a handful of times a year for only a few hours. A move toward more flexible, on-site generation and storage options — in particular, grid-interactive battery storage — can help with peak shaving and also act as spinning reserves.
• Spatial flexibility: Delay-tolerant workloads can be moved, not just in time, but also in space. Currently, this means building some data centers farther away from key markets, where renewable energy is cheap and abundant. In the future, a more advanced approach may look like the carbon-intelligent computing platform being piloted by Google, which can shift delay-tolerant tasks to data centers in other regions in response to forecasted grid stress events or high abundance of renewable energy This requires adequate planning and scheduling and incorporating good data and clear signals of renewable energy availability to ensure that the shifted workload does not affect local grid reliability.

In the United States, the technology needed for data centers to be flexible grid assets could be available in the next 1–2 years. The Data Center Flexible Load Initiative (DC Flex) Initiative aims to deploy five to ten large-scale flexibility hubs by 2027 that demonstrate how data centers can provide demand flexibility and grid services. Meanwhile, Verrus, an Alphabet spinoff, is designing flexible data centers with dynamic workload management and battery storage, aiming to have them operational by 2026 or 2027. In China, the East-to-West Computing Resource Transfer Project promotes the migration of delay-tolerant services from the eastern coastal regions — where the big cities are, and data centers have traditionally been built — to western regions, where wind and solar energy are abundant. One study estimates that this project can reduce emissions from the data center sector by 16–20 percent, while generating economic benefits of about US$53 billion. Exhibit 7

Increase transmission and generation capacity quickly, modularly, reliably, and at lower cost.

One of the least-regrets ways to add capacity to the grid is by adding alternative transmission technologies (ATT). These encompass grid-enhancing technologies (GETs) — such as dynamic line ratings (and advanced power flow controls — and advanced conductors. These technologies can meaningfully increase the capacity, flexibility, and efficiency of existing transmission infrastructure. ATTs can also be deployed significantly faster, sometimes in a matter of months, and at a far lower cost than traditional transmission upgrades.

In terms of new generation capacity, solar and onshore wind, combined with battery storage, is the cheapest and fastest source, with a typical project lead time of less than two years. In comparison, natural gas plants take three to four years — a timeline that is now being set back even further due to turbine shortages. Solar and wind additions to the grid also keep electricity rates low for consumers, whereas natural gas plants can expose consumers to fuel cost spikes.

Data centers typically purchase solar and wind energy through the grid via green tariffs and power purchase agreements. Many already achieve 100 percent renewable energy on an annual basis using these tools. Tariffs are being used by both utilities and data centers to manage investment and electricity rate risks from building new infrastructure, and to pursue energy efficiency, demand response, and investments in a broader portfolio of grid resources (including ATTs and renewable generation and storage).

We are also increasingly seeing data centers built directly next to new or existing generators, an arrangement known as co-location. This can offer benefits to utilities and the grid, including the opportunity to utilize curtailed solar and wind, or in the case of new solar and wind projects, reduced grid stress. Our recent report on “Power Couples” shows that pairing data centers with new renewable energy and battery storage, using an existing generator point of interconnection, could rapidly satisfy over 50 GW of new data center load in the United States, while improving affordability and maintaining grid reliability. When co-locating with existing generators, it is critical to ensure that they continue to meet their historic responsibilities to the grid so it doesn’t increase costs for other ratepayers or affect reliability.

Co-located developments are often financed by the data center operator (as opposed to the utility), which raises their capital costs, but — as evidenced by the rising popularity of the “Bring Your Own Power (BYOP)” approach — this is more than offset by the benefits in terms of speed and long-term cost reductions.

Data centers are also actively exploring nuclear and geothermal options, signing agreements with startups working on small modular reactors (SMRs) and enhanced geothermal. SMRs may lower construction times compared to traditional nuclear, which often face substantial cost and schedule overruns. Some data centers are also looking to nuclear power plant restarts, with targeted timelines of three to four years.

Geothermal energy has historically been limited to certain geographies, but next-generation geothermal can be deployed more broadly across regions. For these technologies to be commercially competitive, they will need to come down significantly in price. In the United States, utilities are working with industrial customers — including data centers — to create “clean transition tariffs” that would allow willing customers to finance advanced clean energy technology projects on the grid.

Some tech majors have indicated a willingness to power their data centers with natural gas and carbon capture. Data shows that carbon capture, use, and storage (CCUS) technologies considerably increase capital and operational costs and may also face challenges becoming an economically competitive option.

Exhibit 8

Data centers can be enthusiastic partners investing in future-ready grid solutions

As competition heats up around AI, data center operators are looking to build as fast as possible to stay ahead of the game. In their quest for speed, they are demonstrating a willingness to be flexible on priorities such as location and cost — reflected in the rise of new data center markets, the BYOP model, support for capital commitments, and investment in emerging energy technologies.

This offers a great opportunity for the future of the electricity system. In places like the United States where aging grid infrastructure is an increasing challenge, the willingness of data centers to invest in fast, flexible, and affordable electricity solutions could be a boon.  It will be up to utilities, regulators, and policymakers to direct this momentum in a way that will balance economic opportunities with other responsibilities such as ratepayer affordability and renewable energy goals. When data centers are seen as a burden on the electricity system, it makes utilities more prone to hasty decisions like overbuilding new natural gas capacity. Instead, they may be better understood as an enthusiastic, capital-rich partner that can help finance desirable, no-regrets upgrades that can help the transition to a cleaner and more affordable electricity system for all.

This analysis was made possible by generous support from Galvanize Climate Solutions. To learn more about how to support RMI’s work, please click here.

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Over the past decade, the Atlantic, Pacific, and Indian Oceans have endured a barrage of tropical cyclones. The 2020 North Atlantic season was the most active on historical record with 30 named storms, 11 of which made landfall in the continental United States. Last summer, in July 2024, the earliest category 5 hurricane to ever form in the North Atlantic, Hurricane Beryl, destroyed homes and infrastructure across Grenada and Saint Vincent and the Grenadines. And solar energy infrastructure didn’t escape the destruction.

Our team investigated three ground-mount solar installations in the path of the deadly hurricane. Our findings, published in Solar Under Storm III, is an update to our first Solar Under Storm report, published after the deadly hurricane season of 2017. Solar Under Storm III takes the learnings from Hurricane Beryl and provides a comprehensive update to Solar Under Storm specifications, best practices, checklists, industry codes, and recommended references based on evolution of the solar industry, advancements in technology, and additional seasons of experience and field investigation.

The growth of solar in hurricane-prone regions

As solar energy becomes central to the energy transition, its role in driving down energy costs, carbon emissions, expanding energy access, and bolstering energy security is unprecedented. With around 2.2 terawatts of solar capacity now installed globally and nearly a billion dollars invested daily in solar initiatives, solar power is reshaping the global energy landscape with extraordinary momentum.

Since 2004, solar has been the fastest-growing energy source globally, maintaining an average annual growth rate of 25 percent. The industry took nearly 70 years to reach 1 terawatt capacity, but only two more years to add the next terawatt, underscoring its incredible rapid ascent. Solar’s affordability and flexibility — ranging from tiny off-grid systems to enormous utility-scale installations — make it foundational for both decentralized and centralized solutions, as traditional energy systems are challenged technically and economically.

Yet, solar must be resilient to the climate threats it helps mitigate. Hundreds of gigawatts of solar installations are installed in the annual path of tropical cyclones, from Florida to the Philippines, highlighting an increasing vulnerability as the global solar market grows.

Our first Solar Under Storm report brought to light the reality of ground-mounted solar projects in hurricane-prone regions. This was followed by Solar Under Storm II, which focused exclusively on roof mounted PV systems, and then Solar Under Storm for Policymakers, a report sponsored by the United Nations, dedicated the non-technical audience that shoulders the responsibility for minimum standards and best practices for solar installations.

Solar Under Storm III is the next step forward to providing technical guidance to enhance solar system durability against Category 5 hurricanes, typhoons, and cyclones.

This updated report offers practical, field-tested strategies for manufacturing, design, installation, and operations necessary to protect investments and sustain energy access after major storms. Solar’s dual role in mitigation and adaptation makes resilience imperative. By embedding resilience into every solar deployment, the industry can safeguard the promise of solar energy, securing the future for island and coastal communities and economies that rely on its cheap, clean and sustainable power for decades.

Union Island, St Vincent and the Grenadines, after Hurricane Beryl, July 2024 Resilient and reliable power for decades

The Solar Under Storm report series is designed to provide a free resource of the best practices in resilience for solar installations for designers, installers, suppliers, developers and policymakers. Our hope is that by sharing best practices and through continued collaboration, we can increase the reliability and survival rates of PV systems in hurricanes and ensure the resilience and reliability of power for local grids, homes, businesses, and critical facilities for decades to come. 

Download the report

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Coal’s role in the power sector has been declining for years:  the aging coal fleet is increasingly unreliable and expensive to operate — creating billions of dollars in losses for ratepayers annually — and lower cost sources of power have grown exponentially to take its place.

From an operations and planning perspective, transitioning away from coal requires proactive action to minimize the risk of disruptions that could stem from turning these legacy generators off overnight. Notably, utilities, states, and regional grid operators all do thorough analyses today to ensure that planned retirements will not negatively impact the grid and will provide cost benefits for customers. As such, forcing retiring coal to support grid reliability is incredibly costly and burdensome for customers, with minimal reliability benefit.

For coal plants without imminent retirement dates, one way that utilities can make a smooth transition away from coal — in a way that benefits ratepayers and communities and avoids reliability cliffs — includes pairing economic dispatch and clean repowering. In other words, utilities can operate coal less often and more flexibly, and by doing so make room for low-cost replacement power to quickly support the grid.

By pairing economic dispatch (operating power plants only when they are needed and profitable) and clean repowering processes (connecting new clean energy resources to the grid using an existing power plant’s interconnection point), utilities can avoid unnecessarily relying on uneconomic generators and instead begin reinvesting in communities to support long-term economic resilience.

Our roadmap for smoothly transitioning away from coal in this way includes the following steps:

1. Operate coal plants economically and more flexibly.
2. Utilize spare capacity enabled by economic dispatch to bring new resources online quickly.
3. Retire remaining coal assets and take additional steps to ensure a just transition for coal communities.

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Step 1: Operate coal plants economically and more flexibly

First, utilities can operate coal plants more economically and flexibly today. There are fewer and fewer times of the year in which coal plants can provide energy at lower cost than other existing energy sources. And yet many utilities still turn coal plants on and leave them running for weeks and even months at a time when cheaper resources are available — a known driver of the affordability crisis facing customers today.

Instead, utilities can operate their coal plants only when needed by pursuing economic dispatch and additional operational efficiencies. Economic dispatch can be pursued overnight; all utilities have to do is be responsive to market prices and turn off their coal plants when economics dictate it. In fact, merchant coal plants, whose owners do not have ratepayers, almost exclusively operate this way.

Additional changes in unit dispatch that can increase flexibility and reduce uneconomic operations include:

• Putting units on standby instead of running at their minimums, which provides additional ramping capabilities (both up and down);
• Negotiating fuel and power contract obligations so utilities are not purchasing more coal than needed or operating more than is economic; and
• Pursuing other engineering optimizations that can lower minimum operating levels, minimum run times, and/or increase plant-level ramp rates (both up and down), and can support reliability and lower losses incurred while operating the plant.

For example, Southwestern Public Service Company, a utility operating in New Mexico and Texas, pursued numerous operational efficiencies at its coal plants (including renegotiating coal contracts, modifying plant testing parameters, and additional engineering optimizations) that reduced minimum operating levels by 23–32 percent and lowered how long its coal plants need to run before turning off. Minnesota Power, a Minnesota-based utility, was also able to reduce the operating minimum at one of its coal-fired units at Boswell Energy Center by 57 percent.

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Step 2 (if needed): Utilize spare capacity enabled by economic dispatch to bring new resources online quickly

Utilities that operate their coal plants less often and with more flexibility can open up substantial headroom (additional capacity the grid can handle without needing to install new equipment) on the transmission system for new low-cost energy resources. In 2023 and 2024, US coal plants had an average capacity factor near 40 percent — meaning that the average coal plant was not utilizing 60 percent of the transmission capacity allocated to it. Further economic operations would undoubtedly increase this available headroom.

Fortunately, the process known as surplus interconnection allows utilities to leverage extra transmission headroom and existing infrastructure to quickly connect new energy resources to the grid. Nationwide, the surplus interconnection opportunity is large, and by taking advantage of this opportunity, utilities can get cost-effective clean energy resources connected to the grid quickly — often in less than a year. These resources can directly displace the energy output and reliability services that coal plants have historically provided and rapidly decrease customer bills. Having replacement resources already online can make the decision to fully decommission a coal plant even easier.

Because the surplus interconnection process requires replacement resources to connect to the grid near the existing coal plant, it has the potential to support energy communities with local jobs, revenue, and economic diversification and resilience. Utilities will need to renew or transfer interconnection agreements for generators added via surplus interconnection when the entirety of the coal plant they are linked to retires, but with proactive planning and ongoing interconnection queue reforms, this need not become a major hurdle.

Utilities and regulators may also find that coal plants are no longer economic to operate at all, especially compared to building new clean energy resources, suggesting that utilities should move toward full decommissioning and replacement of the plant rather than the interim step of surplus interconnection. This is the case for most coal plants today. Fortunately, many regions also have a generator replacement process that can provide the same reliability, affordability, and energy community benefits as surplus interconnection service.

Step 3: Retire remaining coal assets and take additional steps to ensure a just transition for coal communities.

At this point, the transition to economic dispatch and additions of surplus energy resources to the grid have created immediate cost savings for customers, minimized the risk of reliability cliffs upon coal retirement, and supported coal communities early in the transition away from coal. What’s left now for utilities is to retire their remaining coal assets and continue remediation efforts that ensure near-term stability and long-term community benefits well after closure of coal plants.

Action Plan

Utilities can pursue this path away from coal today, and regulators can ensure utilities are doing so to benefit customers. To enable this transition away from coal, regulators can:

• Investigate and require economic dispatch at coal plants. Regulators can investigate how utilities are currently operating their coal plants and ensure that utilities are not over-relying on coal at customers’ expense. Regulators in Minnesota have continued to investigate the impact of uneconomic coal dispatch on customers, and regulators in Michigan and Louisiana have recently taken action to ensure customers are not overburdened by uneconomic coal operations.
• Require utilities to evaluate surplus interconnection potential at their coal plants and share surplus opportunities with developers. Today, surplus interconnection service is available for nearly all utilities across the United States, and yet few evaluate the potential for surplus interconnection opportunities in resource planning and procurement. Evaluating surplus interconnection opportunities in resource planning and sharing opportunities in competitive resource solicitations can enable new power to get online quickly, minimize costs for customers, and enable continued investment in coal communities. The same opportunity exists for many other thermal power plants today, most of which have significant unused headroom that can be filled by new resources using surplus interconnection service.
• Ensure utilities are proactively planning to transfer or apply for new interconnection agreements as legacy plants retire and surplus resources remain. Eliminating this bottleneck can provide certainty that the process outlined above will function as planned.

Relying on coal for reliability is an unnecessary and costly solution for customers. With proper planning and utilizing procedures available today, utilities can enable a smoother transition away from coal, maintain a reliable and affordable grid for customers, and reinvest in energy communities — wins across the board.

The post Reality Check: Reinvesting at Coal Plant Sites with Clean Energy Upgrades Supports both Reliability and Affordability appeared first on RMI.

This article is one of a series in our review of all integrated resource plans (IRPs) for electric utilities across the United States. We provide analysis of expected load, planned capacity, modeled generation and emissions, and comparison to targets and decarbonization scenarios to evaluate progress toward a zero-carbon energy future. IRPs do not provide a fully accurate prediction of the future, but we focus on them because they reflect the direction that utilities are currently striving for and a set of proposed actions to get there.

Updates in Q2 2025

In the second quarter of 2025, utilities that updated their IRPs increased projected load through 2035 by 2.0 percent and emissions by 4.5 percent.

Changing policy, regulation, and market rules, as well as interconnection queues, limitations to capital deployment, and claims of reliability concerns create a difficult environment for utilities to meet load growth with wind and solar generation. Instead, utilities continue to increase plans to build new gas capacity, and in some cases, also delay retirement of existing fossil capacity.

This quarter’s updates represent a reminder that the sector is not completely homogenous. Regional differences, and even intraregional differences, were apparent and reflect the importance of company-specific evaluation to enrich the sector-wide story. In subsequent sections, we share detailed analysis of recent changes, their underlying causes, and potential directions of opportunity for improvement.

The current state of IRPs

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

Most decarbonization pathways, including the IEA NZE, find that the electricity sector needs to reach net-zero emissions by 2035. Unfortunately, utility company targets often aim for net-zero emissions by 2050 and often do not comprehensively cover emissions from both owned (Scope 1) and purchased (Scope 3) emissions. If all companies in our coverage meet their targets, they will only reduce their emissions 64 percent by 2035, compared to a 2005 baseline. We also find a gap between these targets and projected emissions based on IRPs, which as of Q2 2025 we project to be reduced by just 53 percent by 2035, compared to a 2005 baseline.

Exhibit 1

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Load

As of the end of Q2 2025, IRPs across the United States anticipate load to grow 24 percent by 2035 compared to 2023 levels (Exhibit 2). This is up from prior projections — 12 percent at the end of 2023, 8 percent in August 2022, and 6 percent in January 2021.

Load growth continues to be driven in the short term primarily by industrial loads such as data centers, but also comes from increasing adoption of electric vehicles and beneficial electrification. Load changes in Q2 2025 varied widely by utility, ranging from Indiana-Michigan Power Co.’s projection that load will more than double from 2023 to 2030 with data centers becoming 60 percent of total load, to PacifiCorp’s 12.3 percent reduction in projected peak load. PacificCorp’s reduction is due to removing large loads from its forecast because these customers are now expected to provide and pay for their necessary resources and transmission outside of the traditional planning process.

Exhibit 2

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Capacity

Current planned capacity in IRPs across the United States (Exhibit 3) includes 258 GW of wind and solar additions, 102 GW of gas additions, and 75 GW of coal retirements between 2023 and 2035.

This reflects 4 GW of additional wind and solar capacity, 52 GW of additional gas capacity, and 3 GW of additional coal retirements since the end of 2023.

With these recent changes, utility resource plans now include 52 GW more gas capacity than wind and solar capacity in 2035. This is a stark contrast to our Q2 2024 IRP review, in which planned wind and solar capacity in 2035 nearly exceeded planned gas capacity.

Capacity needs continue to increase because of load growth, and utilities that updated IRPs in Q2 2025 also cited higher reserve margins required by the Southwest Power Pool as well as a desire to keep resources online to improve reliability during extreme weather events as reasons for delayed retirements and more fossil additions. It is clear that in aggregate, utilities are focusing on additional gas capacity to meet these needs.

Exhibit 3

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Emissions

Our latest projections (Exhibit 4) are that emissions planned in IRPs at the end of Q2 2025 will be 53 percent lower than 2005 levels by 2035. This is a smaller reduction than we projected from IRPs at the end of 2023, when emissions planned in IRPs showed a 60 percent reduction, and the end of 2024 when the figure was 56 percent.

Projected emissions by 2035 remain lower than they were at the beginning of 2021 because of increased overall plans to build zero-carbon capacity. However, projected emissions are higher now than at the end of 2023 and 2024 because of increased electricity demand, insufficient zero-carbon capacity additions (in many cases, delays or reductions to plans) to meet all of this demand, and increased use of gas generation to fill the remaining gap.

Exhibit 4

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Cumulative metrics

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

Exhibit 5 shows that across all IRPs in the United States, cumulative projected emissions from 2023 to 2035 are 4.5 percent higher, cumulative projected load is 2.0 percent higher, and cumulative projected emissions intensity is 2.4 percent higher now at the end of Q2 2025 compared to a year ago at the end of Q2 2024.

Exhibit 5

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Exhibit 6 provides an additional view of the direction that IRPs are going, by considering percent change in cumulative projected load and emissions among the set of companies that did update their IRPs each quarter. Utilities that updated IRPs in Q2 2025 increased load by 2.4 percent, emissions by 4.1 percent, and emissions intensity by 1.6 percent.

In our history of tracking IRPs, load projections have never decreased in a quarter, and Q2 2025 makes eight consecutive quarters of at least 2.4 percent load growth among utilities with IRP updates. While emissions decreased in the early 2020s, Q2 2025 also marks six consecutive quarters of at least 2.7 percent increase to projected cumulative emissions among companies with IRP updates.

Exhibit 6

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Achieving a climate-aligned future

Our review of IRP updates in Q2 2025 continued many of the themes we’ve discussed in previous quarterly updates. Similar to last quarter, we observed regional and intraregional differences in load growth, particularly from data centers. Utilities need to expand capacity to meet new load, with additional pressures from increasing reserve margin requirements in certain regions. While delayed retirements and more gas additions seem to be the default choice in most plans, there are a range of fast, affordable, flexible alternatives that can meet this moment, especially considering the gas turbine supply crunch.

Emerging topics this quarter included recurring utility comments on gas fuel price volatility risk, as well as impacts of climate change on utility planning: wildfire mitigation creating a limit on investment, variable hydroelectric resources, and keeping plants online due to increasingly frequent extreme weather events. We are also tracking advancements in how utilities effectively connect large loads: Georgia has approved a tariff framework and other states such as Missouri are at various stages of implementation. These new tariffs will continue to develop, making the process of connecting new large load customers more streamlined and limiting impact on existing customers.

It is important to note that all IRPs in our dataset were completed under currently available policies. Recent federal policy changes, including tax credit and domestic content policy, are likely to affect implementation of these plans and may create new barriers to zero-carbon capacity additions.

While the United States electricity sector faces many challenges, progress remains possible. Utilities should continue prioritizing cost to customers, earnings for investors, and reliable electricity service, while simultaneously increasing their focus on the growing risk that the sector is not on track to meet climate goals. Utilities need to fully take advantage of relevant incentives, utilize novel approaches — such as Power Couples — to meet large loads, take advantage of opportunities for clean repowering, and improve their forecasting and modeling methods to plan more comprehensively.

RMI’s Engage & Act Platform: Data and Insights for Real Climate Impact

RMI’s Engage & Act Platform provides data and insights for real climate impact. To learn how you can access and use this targeted resource to uncover recent trends and clean energy growth opportunities — and accelerate the pace of electric utility carbon emissions reductions — please visit the Engage & Act website.

 Methodology

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

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