J1. Green Tech Industry & Utilities

India’s maritime sector is beginning a major shift toward cleaner operations. The Ministry of Ports, Shipping and Waterways (MoPSW) has launched the Harit Sagar Green Port Guidelines, which set a goal for 50 percent of all port equipment and vehicles to be electric by 2030. This goal provides an opportunity to modernize logistics, reduce costs and emissions, and make India’s ports more competitive and cleaner in a changing global market.

RMI’s latest report lays the foundation for large-scale electric truck deployment at ports, improving air quality in port regions, reducing operating costs for fleet operators, and positioning India as a global leader in sustainable port logistics.

Early ZET deployments show promise, but costs remain a hurdle

Today, about 24,000 diesel trucks operate within and around India’s 12 government owned Major Ports. These trucks are essential for moving goods but also add to local air pollution and greenhouse gas emissions. Replacing them with zero-emission trucks (ZETs), such as battery-electric or fuel-cell trucks, is an important step toward meeting the Harit Sagar goals.

Some ports have already begun this journey. Pilot projects at Jawaharlal Nehru Port, Kamarajar Port, and Visakhapatnam Port have tested ZETs across various use cases. Early results indicate that ZETs can match diesel trucks in performance and payload, offering comparable range and operational efficiency. Drivers also report smoother, more comfortable and quieter operations. However, when considering economics, ZETs currently show a 4–20 percent higher total cost of ownership (TCO) compared than diesel trucks (Exhibit 1). This is driven largely by high up-front vehicle costs, elevated electricity tariffs (INR 9.7–16/kWh), and the cost of battery-swapping infrastructure.

Exhibit 1

Total cost of ownership of ZETs vs. diesel trucks for differing ports and use cases

Note: The results are inclusive of PM E-DRIVE E-truck incentives. Daily distance traveled (km) for Jawaharlal Nehru, Kamarajar, and Visakhapatnam ports is 125 km, 120 km, and 150 km, respectively.
Source: RMI Analysis

Despite the TCO gap, major ports are demonstrating a strong intent towards ZET adoption by indicating demand for approximately 800 ZETs to be deployed by 2030. While this represents only about 3 percent of the total truck fleet at ports, it marks a promising start that can build confidence, operational experience, and economies of scale.

The need for a policy framework

To move from small pilots to large-scale deployment, bridge the TCO gap, and align adoption with Harit Sagar targets, there is an urgent need for a dedicated policy framework specifically for ZETs at Major Ports. Such a framework (Exhibit 2), including strategic planning, fiscal and non-fiscal measures, infrastructure development and capacity building, would help align efforts across ports and provide consistent direction to both public and private stakeholders.

Exhibit 2

Policy framework for ZET adoption at ports

Source: Policy Framework for Zero-Emission Truck Adoption at Major Ports in India, RMI, 2025, https://rmi.org/insight/ policy-framework-for-zero-emission-trucks-adoption-at-major-ports-in-india.

It’s critical to prioritize the implementation of these solutions in a phased manner. In the near term (0–1 years), the focus should be on ensuring that each port develops a ZET transition plan to signal its intent to decarbonize logistics and build industry confidence. This can be complemented by aggregating demand across ports through a nodal agency to reduce costs for early adoption.

Additionally, fiscal measures such as up-front incentives can help lower the TCO and spur short-term adoption. These can be accompanied with nonfiscal measures, including the creation of green entry and exit channels for ZETs and the introduction of longer-term logistics service contracts favoring ZET operations. Finally, ports can also explore leveraging state EV tariffs and PM E-Drive charging infrastructure incentives to reduce charging-related costs. Capacity-building and workforce training programs should be prioritized to ensure drivers are equipped to operate ZETs efficiently.

In the medium term (beyond 1 year), more binding measures can be introduced. These may include embedding ZET adoption requirements for terminal operators in new or renewed concession agreements and imposing additional surcharges on the operation of diesel fleets at ports. At the same time, it is important to strengthen upstream infrastructure to accommodate higher charging demand, and to institutionalize continuous documentation, data collection, and monitoring of deployments and key learnings.

Overall, this represents a significant opportunity for India’s major ports to demonstrate leadership in ZET adoption on the global stage. With coordinated action between the public and private sector, and a dedicated policy framework, India can anchor a more sustainable, resilient, and competitive maritime future.

 

 

 

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As the United States grapples with electricity affordability and meeting soaring demand, both red and blue states have begun to embrace advanced transmission technologies (ATTs) as a valuable tool. ATTs, which include grid enhancing technologies (GETs) and advanced conductors, help utilities deliver more electricity through existing infrastructure by routing power more efficiently and safely through existing lines.

Numerous studies have shown that ATTs can be deployed quickly to reduce consumer bills and accelerate interconnection of cost-effective generation. For example, RMI’s Getting Connected in PJM analysis showed that GETs deployment in five PJM states could accelerate interconnection of 6.6 gigawatts of new generation, saving PJM customers more than $1 billion annually.

As pilots and small-scale deployments continue to demonstrate the benefits of ATTs, state legislators have collaborated across party lines to encourage ATTs. Over the past year, 10 red and blue states (seven with republican governors and three with democratic governors) have passed laws to accelerate deployment, joining six states that already had laws on the books.

To realize the lawmakers’ intended benefits, utilities and the regulators that these laws empower must leverage their vested authority to actually deploy ATT solutions and reduce electric bills.

Snapshot of state ATT laws

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While the language in state ATT legislation varies, most follow one or more of the following approaches:

1. Planning laws require utilities, public utility commissions (PUCs), and/or grid operators to study the economics and feasibility of ATTs during resource and transmission planning. Some laws require ATT deployment if studies show they are cost-effective; others leave more discretion to utilities and regulators. Some planning laws require that ATTs be included in integrated resource plans (IRPs) or require large transmission owners to submit a separate GETs evaluation.
2. Siting and permitting laws require PUCs to evaluate ATTs during their considerations of proposed grid infrastructure as part of the Certificate of Public Convenience and Necessity (CPCN) process.
3. Cost recovery laws can guarantee that ATT expenditures can be included in rate base for cost recovery. Montana’s advanced conductors law offers a higher rate of return for advanced conductors through “cost-effectiveness” criteria.
4. Study requirements require state agencies to examine the impact of ATTs without connecting the study to a particular planning or siting and permitting process.

For most these approaches, regulators have significant freedom on how they implement the new laws. If regulators thoughtfully leverage the tools these laws provide, they can cost-effectively expand transmission capacity and reduce bills, as the legislators intend.

Implementing ATTs in planning processes

To realize the value of ATTs, utilities and regulators must include them throughout generation and transmission planning. Because planning with ATTs is relatively new, utilities may need to upgrade their processes. Fortunately, Quanta Technology recently released an Advanced Transmission Technologies Planning Guide that suggests best practices for integrating ATTs into planning.

As detailed in Quanta’s planning guide, optimal IRP planning incorporates ATTs into modeling assumptions. Quanta recommends an iterative study process that co-optimizes generation and transmission planning and solves for both system reliability and least-cost procurement. In this way, planners can optimize investments inclusive of both ATT costs and benefits.

While implementing Quanta’s suggestions may require utilities to upgrade their planning process and software, those relatively small planning investments should yield significant customer savings given the fast return on investments common with ATTs. For example, a dynamic line rating pilot in AEP’s service territory cost $0.5 million to install and paid for itself in about a month, with a total estimated savings of $11 million. Utilities may benefit from working with vendors and other technology experts to develop ATT modeling assumptions, while referring to analysis of recent successful deployments.

Implementing ATTs in siting and permitting processes

Most new state CPCN laws require state PUCs to consider the prudency of ATTs when evaluating new transmission lines, with the presumption that, in many cases, ATTs will reduce upgrade costs. As an example, using the same transmission towers and right-of-way, advanced conductors can double transmission flows at less than half the cost of building a new line. Given expected demand increases, these deployments will likely provide a quicker return on investment as they help avoid or defer more costly upgrades.

Where CPCN requirements are legislated, state PUCs should require that utilities include cost-benefit analysis in their applications. If that analysis is insufficient, regulators could require utilities to resubmit or revise the submission. If utilities decide not to use ATTs as part of the project, they should be required to explain why ATTs were not selected and provide adequate evidence to support their claim. Transmission owners may seek to avoid using ATTs, due to misaligned incentives created by cost-of-service regulation, which rewards regulated utilities for capital expenditures. Because ATTs are so cost-efficient, they can often be overlooked by utilities. Accordingly, PUCs should be prepared to apply a rigorous evaluation of any utility explanation for avoiding the deployment of ATTs.

PUCs should also consider providing pathways for ATTs to act as a bridge technology for new construction. GETs, such as dynamic line ratings, advanced power flow controls, and topology optimization, can increase system capacity and minimize outage durations when new lines are being constructed. For instance, a study by topology optimization provider NewGrid found that reconfiguration of power flow could reduce the cost of power from $600/MWh to $25/MWh at a congested point while transmission reinforcements were built.

From policy to performance: states must act swiftly to close the implementation gap

If implemented robustly, ATT laws could cut customer costs, relieve congestion, and improve reliability. States that lead on implementation will create blueprints for others to follow, showing how to quickly and cost-effectively unlock no-regrets investments. Passing state ATT laws is a vital first step. Now it’s time to turn policy into performance and deliver the modern grid that the moment demands.

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Renewable energy smart building materials company ClearVue Technologies Limited has announced the expansion of its ClearVue-Helios Building Integrated Photovoltaic (BIPV) solutions to include modular, fully integrated carparks, carports and canopy structures, with a payback time of four years or less.

Italy is set for rapid renewable energy growth, but with that comes an increasing exposure to grid infrastructure limitations for renewables investors, according to the latest report from global analytics provider Aurora Energy Research.

Sumitomo SHI FW (SFW) has been selected to supply a biomass-fuelled circulating fluidised bed (CFB) boiler plant for Mondi SCP’s EcoPower project at its integrated pulp and paper mill in Ružomberok, Slovakia.

Battery production is the biggest stain on the image of electric vehicles (EVs) as being sustainable. EV batteries rely on virgin, finite resources extracted through ecologically destructive processes in places where child labor is rampant. Although they can reenter circulation when they retire, recycling EV batteries prematurely flushes their residual value down the drain.

Dallas, Texas-based Janta Power has announced a successful seed funding round of $ 5.5 million. This infusion of capital marks a critical milestone as the company accelerates its mission to transform solar energy deployment, especially in space-constrained or infrastructure-intensive settings.

A new storm-resistant ocean energy structure has been installed off the coast of Gran Canaria, marking a breakthrough in developing renewable systems capable of operating through hurricanes. Developed under the EU’s Horizon Europe–funded PLOTEC project, the prototype represents the next step in harnessing Ocean Thermal Energy Conversion to deliver round-the-clock clean power to island nations most exposed to climate risks.

As EU leaders are gathering today (Thursday 23rd October) to discuss competitiveness and climate goals during the European Council, Eurelectric is stressing that electrification is what will allow Europe to reach those targets and is making detailed recommendations to show the way forward.

At the 2025 Energy Vision Leadership Awards in New York, EnviTec Biogas AG was honored for its global leadership in advancing the clean energy transition. Since 2008, the award from the U.S. nonprofit Energy Vision recognizes leading figures and companies for advancing the circular economy, resource efficiency, and the smart use of organic waste, including food and agricultural waste, landfill gas, municipal waste, and other groundbreaking developments.

Turboden S.p.A., a Mitsubishi Heavy Industries Group company, announced successful commissioning of North America’s first waste heat to power project in steam-assisted gravity drainage (SAGD) facility. The facility is operated by Strathcona Resources Ltd. in Cold Lake, Alberta, Canada. The recovered heat is converted into carbon-free electricity, enabling the facility to offset up to approximately 80% of its current grid electricity consumption.

Stargate Hydrogen and OX2 have announced the signing of an agreement to jointly accelerate the commercial deployment of large-scale renewable hydrogen production in the Nordic region. 

The race is on to curb methane emissions and prevent energy waste through oil and gas supply chains. Readily quantifiable and comparable methane intensity metrics are sought after to meet this goal. Adopting such robust metrics will permit market actors and policymakers to assess companies, countries, and assets and comprehensively differentiate oil and gas methane intensities worldwide.

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

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

Parsing oil and gas

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

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

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Establishing two different methane metrics

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

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

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

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

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

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

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

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

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Differentiating countries’ methane intensities

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

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The economic value of methane policy

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

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

Next steps for establishing methane intensity metrics

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

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

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

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

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

Texas has long been a byword for energy leadership, whether that’s in its more-than-century-old oil industry or its position as the number one state in the nation for solar and wind capacity. Another accolade could soon be in reach for the Lone Star state: carbon management pioneer. By utilizing its world-class workforce, pipeline expertise, and unbeatable geological assets, Texas can be the global leader in the new multi-billion-dollar economy of storing and utilizing carbon — creating jobs, revenue, and cementing its status as a first-mover state.

Why now is different

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

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

Exhibit 1
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These changes will have a significant impact on the carbon management industry, closing the cost gap for more types of projects and presenting highly significant financial and job creation opportunities in states that pursue projects and infrastructure supportive of a carbon management economy.

Texas is poised to lead this growing industry

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

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

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

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

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

Exhibit 2

Exhibit 3

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

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

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

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

Exhibit 4

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

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

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

 

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

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 2025 Q3

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

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

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

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

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 or email engageandact@rmi.org.

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

The current state of IRPs

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

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

Exhibit 1

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Load

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

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

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

Exhibit 2

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Capacity

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

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

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

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

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

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

Exhibit 3

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Emissions

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

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

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

Exhibit 4

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Cumulative metrics

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

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

Exhibit 5

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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 2025 Q3 increased load by 2.1 percent, emissions by 5.5 percent, and emissions intensity by 3.3 percent.

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

Exhibit 6

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Achieving a climate-aligned future

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

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

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

 

Methodology

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

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

The latest data is out, and it doesn’t look good. Households across America are falling behind on their utility bills. According to a recent analysis from NEADA, household utility debt has risen from $17.5 billion at the end of 2023 to $23 billion as of June 30, 2025, an increase of 31 percent. As a result, 21 million households — roughly one in six — are behind on their utility bills, and shutoffs are projected to climb from 3.5 million in 2024 to as many as 4 million this year.

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

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

RMI’s role

RMI supports PUCs and consumer advocates in designing and implementing smart policies that lower system-wide costs and protect the most vulnerable customers. These programs reduce customer energy burdens and debts while reducing system-wide costs. Learn more at our Regulatory Resources Dashboard.

The promise of arrearage management plans (AMPs)

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

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

Percentage-of-income payment plans (PIPPs)

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

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

Low-income discount rates (LIDRs)

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

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

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

Low-income energy efficiency programs

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

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

The bottom line: Supporting affordability for all

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

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

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

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

Headline News:

• “A Quiet Floating Solar Revolution Is Bubbling Up In US Waters” • Floating solar arrays require specialized racks and mooring systems. As demand rises, economies of scale kick in, helping to reduce costs. Ease of installation is a notable feature typical of floating solar systems. They don’t require land to be cleared and leveled. [CleanTechnica]

US floating solar array (Courtesy of Third Pillar Solar)

• “Gas And High Coal Penetration Are The Drivers Of Costly, Volatile Power Prices” • Analysis of price data in Australia’s National Electricity Market shows a strong link between the share of gas and coal generation and wholesale electricity prices. When gas-fired generation exceeds 6% or coal meets over 55% of demand, prices rise significantly. [Renew Economy]
• “Green Energy Market To Reach $2.4 Trillion By 2032” • A report from Allied Market Research, “Green Energy Market,” says the global market, valued at $1.0 trillion in 2022, is projected to reach $2.4 trillion by 2032. The global move toward reducing greenhouse gas emissions and enhancing energy security has propelled the demand for green energy. [Newstrail]
• “Chilean Salmon Farmer Signs Up For Floating Solar Power Supply” • Trusal, Chilean fish farmer, is to be receive electricity generated by on-site floating solar power after signing a 15-year supply deal with Alotta, a company based in Norwey. Alotta said aquaculture companies can use solar power without the need for upfront investments. [Fishfarming expert]
• “Harris County Sues Trump EPA To Restore $400 Million In Texas Solar Energy Funding” • Harris County Attorney Christian Menefee filed a lawsuit after the Trump administration cancelled over $400 million in solar energy grants for organizations based in Texas. The grants were expected to save participants annual amounts estimated to be $1,740. [Yahoo]

For more news, please visit geoharvey – Daily News about Energy and Climate Change.

Headline News:

• “‘Tipping Point’ Threshold Reached For World’s Coral Reefs” • The latest Global Tipping Points Report suggests the world’s coral reefs are at risk of mass dieback. Over 80% of the world’s coral reefs were bleached by heat in the past two years. Countries worldwide will meet at COP30 in November to discuss reducing greenhouse gas emissions. [ABC]

Coral (Francesco Ungaro, Unsplash, cropped)

• “The West’s Power Grid Could Be Stitched Together, If Red And Blue States Buy In” • A regional energy market in the West would meet the demands of eleven states, bolstering utilities’ power plants with surplus energy from across the region. With the passage of a landmark new law in California, that market is finally on its way to becoming a reality. [Stateline]
• “India’s Renewable Energy Capacity Surges In H1 FY25 With 25-GW Addition” • India’s renewable energy sector continues to gain momentum, achieving a capacity addition of approximately 25 GW in the first half of FY25, the current fiscal year. This move was primarily driven by the solar power segment, which added around 21.7 GW. [Power Technology]
• “NextEnergy Capital Powers Up 60-MW Hatherden Project” • NextEnergy Capital has energised its latest UK solar farm, the 60-MW Hatherden project, on behalf of its own NextEnergy UK I fund. The milestone takes the fund’s total operational capacity to 380 MW, more than doubling the size of its portfolio over the past twelve months. [reNews]
• “California Oil Workers Face An Uncertain Future In Its Energy Transition” • Thousands of workers could lose jobs in coming years as California tries to reduce its reliance on fossil fuels. But maybe not. Energy company Valero said earlier this year it would close a refinery in the Bay Area, and now Democrats are considering how to keep it open. [ABC News]

For more news, please visit geoharvey – Daily News about Energy and Climate Change.

OBM is fundamentally changing how power suppliers approach risk management for large-load customers.

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