Climate Change

Timeline 2024: 28 sustainability policies, guidelines and targets to track

The business of sustainability continues to evolve rapidly. Here are the most important changes to expect in the coming year.

By:  Elsa Wenzel
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Sophia Davirro/GreenBiz

With COP28 recent in the rearview mirror, 2024 represents a clear and critical inflection point for confronting the climate crisis. New rules in the European Union and in California, the world’s fifth-largest economy, will change how global businesses report risks, purchase energy and manage supply chains. The effects of the Inflation Reduction Act in the U.S. are still emerging: 175 nations are hashing out the first global treaty to end plastic waste.

Below are some defining moments that will drive change in the business of sustainability in the coming year. 

Carbon

Expected U.S. SEC climate-related disclosures in April will require companies to report their GHG emissions.

The U.S. Office of Fossil Energy and Carbon Management, part of the Department of Energy, announces winners in February of its carbon dioxide removal purchase pilot prize and will publish details for corporate sustainability teams’ own carbon removal due-diligence processes.

New guidance from the Science Based Targets initiative on the use of environmental attribute certificates, including carbon credits, in decarbonization goals should come out by summer.

By the end of 2024, companies subject to California’s new Climate Corporate Data Accountability Act (SB253) will need to establish processes for auditing their 2025 emissions ahead of 2026 reporting.

Finance and ESG

A new proposal may emerge in the spring from the U.S. Securities and Exchange Commission (SEC), after it again delayed its climate change disclosure rulemaking.

Changes to the EU’s Sustainable Finance Disclosure Regulation (SFDR) 2.0 are likely following a September 2023 review.

Sometime in 2024, the U.S. Federal Trade Commission’s updated Green Guides are expected to update what “greenwashing” means in business and marketing.

Nature and biodiversity

The EU’s Corporate Sustainability Reporting Directive (CSRD), requiring companies to disclose their risks from environmental and social factors, takes effect Jan. 1.

COP16, the 16th Conference of the Parties to the Convention on Biological Diversity, will take place in Colombia from Oct. 21 to Nov. 1.

Revised or updated National Biodiversity Strategies and Action Plans (NBSAPs), including national targets, are due by COP16. 

By Dec. 30, operators and traders must prove deforestation-free sourcing for targeted commodities in the EU market. That’s the EU Deforestation Regulation (EUDR) compliance deadline.

Food and agriculture

The EU CSRD goes into effect as 2024 begins, influencing supply chain impact disclosure and bringing new evidence of deforestation.

Supply chains risk disruptions if the U.S. Farm Bill continues to stall in Washington in 2024.

Watch for the next steps from the hundreds of nations that signed sustainable food declarations at COP28.

Transport

The U.S. Departments’ of Treasury and Energy rules go into effect, barring vehicles with battery components from a “foreign entity of concern” from consumer tax credits. 

The IRS expands its EV tax benefit by letting consumers choose between claiming a credit on their tax returns or using the credit to lower a car’s purchase price.

The ReFuelEU aviation initiative goes into effect Jan. 1 to advance sustainable aviation fuels (SAF) in the European Union. It also requires aircraft operators and EU airports to work towards emission reductions and to ensure a level playing field for airlines and airports.

In January, the EU extends its cap-and-trade Emissions Trading System (EU ETS) to regulate CO2 from large ships of any flag entering its ports.

The U.S. Department of Energy will release an updated Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) model by March 1.

Circular economy

A hoped-for Global Plastics Treaty in 2024 moves forward with INC-4 meetings expected in April in Ottawa and INC-5 by November in Korea.

California, Maine, Oregon and Colorado are working on enforcement rules and other fine print for their new extended producer responsibility (EPR) packaging laws.

EU battery regulations are gradually being introduced, encouraging a circular economy for batteries.

Energy

At COP28, the U.S. announced new rules to cut methane emissions in oil and gas production, likely to change the energy cost equation. Watch for progress from 150 countries pledging two years ago to cut methane by 30 percent by 2030.

The Biden administration will be giving out $7 billion for its Regional Clean Hydrogen Hubs (H2Hubs).

2024 will be a watershed year for microgrids moment: Interconnection backlogs are creating a new value-add for microgrids, especially as the macrogrid can’t keep up with electricity demand.

Buildings

Watch the 28 countries agreeing at COP28 for “near-zero” buildings by 2030 through the Buildings Breakthrough.

Applications are due and funding will be announced for the EPA’s $27 billion Greenhouse Gas Reduction Fund, backing climate tech and moving money into communities.

Applications for the EPA’s Environmental Product Declaration (EPD) grants are due Jan. 16 from manufacturers.

What’s ‘Greenwashing’ and How Can I Avoid It?

By:  Jacqueline Poh
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Over the last decade, companies and investors have come to pay more attention to environmental concerns, often with a goal of offering “green” products or making “green” investments. But the companion of green is often what’s known as greenwashing. In some countries, regulators are trying to clean up the field, launching investigations and levying fines. They have the backing of some advocates of environmentally minded investing worried that greenwashing’s taint may undermine the field.

1. What is greenwashing?

It’s the use of misleading labels or advertising to create an undeserved image of environmental responsibility. Here are some eamples:

  • In December, the UK’s antitrust regulator began an investigation of Unilever Plc, the maker of Dove soap and Cif cleaner, for allegedly overstating the environmental qualities of certain products.
  • Fashion companies Asos and Boohoo and airlines such as Air France-KLM, and Deutsche Lufthansa AG were told by regulators to discontinue misleading ads that made air travel seem more eco-friendly than it is.
  • In investing, the UK’s Financial Conduct Authority rolled out a framework in November designed to protect retail investors from misleading claims by firms with so-called ESG funds — where investment decisions are shaped by environmental, social or governance factors.
  • In the US, Deutsche Bank AG’s DWS asset management arm agreed in September to pay a total of $25 million to settle Securities and Exchange Commission probes into alleged greenwashing and anti-money laundering lapses. The penalties included $19 million for “materially misleading statements” about how the bank incorporated ESG factors into research and investment recommendations.

2. What’s the incentive for greenwashing?

The ultimate attraction is the favorable image companies project across to clients, investors, shareholders, lenders and even potential employees. But different players have different reasons for exaggeration. When companies fudge on something they’re selling, it’s because they want environmentally minded consumers to be drawn to their products. When they’re borrowing money, they may be chasing a “greenium” — the money they can save by qualifying for the better terms lenders might extend to green or social projects or to ones with ESG goals. Brazil raised $2 billion in the bond market in November 2023 with proceeds earmarked for green and social work, and the debt was priced lower than initial guidance – meaning the Amazon forest nation is paying lower interest rates, compared with a conventional bond. And investment managers might put a greener label than is warranted on a fund to draw in more assets.

3. How big a problem is it?

In 2022, Bloomberg News analyzed more than 100 bonds worth almost $70 billion tied to issuers’ ESG credentials that were sold by global companies to investors in Europe. The analysis found that the majority were tied to climate targets that were weak, irrelevant or even already achieved. Some companies promised to do no more than maintain their existing ESG ratings. And some of the fastest-growing areas of ESG financing involve so-called sustainability-linked loans (SLL) (and similar bonds) in which the connection between environmental labels and environmental goals can be tenuous.

4. How does sustainability-linked debt work?

Sustainability-linked bonds and sustainability-linked loans are signed with commitments from borrowers to achieve certain environmental or social targets, but those goals may be changed in an increasing number of cases. The more flexible agreements even allow issuers to adjust those targets under certain conditions without incurring a penalty. Issuers argue that they have to look for ways to cope with increasingly volatile markets in which key ESG parameters such as energy prices become harder to predict. Then there’s the “sleeping” sustainability-linked debt where financing has an ESG label but with no immediate sustainability targets. Other approaches push responsibility even further out: Bank of China Ltd.’s so-called re-linked bond sold in 2021 is tied to the performance of a pool of sustainability-linked loans made to its clients — that is, not to anything BOC is or isn’t doing in ESG terms, but to the ESG performance of the clients who have taken out those loans.

5. Who’s checking up?

There are dozens of ESG rating and data providers globally, which can provide some assurance that companies and debt issuers are doing their part in sustainability. But private ratings systems can be unreliable and corporate reporting is spotty and hard to compare. All of this greenwashing detective work would be easier if investors and the public had a standardized approach and a robust set of data to compare. Here’s some of what governments and other organizations are doing:

  • Hong Kong, Japan, South Korea, India, Singapore, the UK and EU have issued or proposed rules for ESG score providers, though the rules are only mandatory in the EU and India. The UK Financial Conduct Authority, meanwhile, has unveiled its Sustainability Disclosure Requirement ensuring investment products are accurately labeled or presented.
  • The US SEC is working on getting companies to report on their greenhouse gas emissions and other climate matters.
  • The EU enforced the Corporate Sustainability Reporting Directive in January 2023 which requires companies to disclose risks and opportunities arising from social and environmental issues. For the debt markets, the European Council adopted a green bond standard in October 2023 that specifies where proceeds will be invested and which activities are aligned with the EU taxonomy.
  • Financial bodies, including the International Capital Market Association which oversees the international debt capital markets, and global loan associations have drafted guidelines for ESG debt such as sustainability-linked instruments, green and social financing.

6. Is it just environmental misconduct that’s considered greenwashing?

No. Social and governance aspects have grown to be just as crucial as companies’ environmental efforts, especially since the #MeToo and Black Lives Matter movements began making an impact on consumers’ spending. Many corporations are using their annual sustainability reports to showcase how fair they are in equality employment or what they did to improve employee wellbeing. Given that some of these goals are hard to measure in areas where little data is available, there’s a risk in overstating the results. Of the $1.4 trillion of sustainability-linked debt with disclosed ESG goals, only $352 billion was tied to social objectives, according to BloombergNEF data.

7. How can I avoid investing in greenwashing?

Here are some questions to ask yourself:

  • How ambitious are a company’s goals? Are they integral to its core business, or just superficial commitments? Is the company just promising to do something it would be doing anyway?
  • How specific is the timeframe? Are the goals set annually, or in a way that allows for easy monitoring?
  • Are companies looking at the full “scope” of their emissions, including the carbon released when customers use their products?
  • How much do their plans rely on the kinds of carbon “offsets” that have come under fire for not living up to their promises of environmental benefits?
  • Is there a way to check on companies’ claims, such as in an evaluation by an impartial ESG data- or ratings-provider?
  • Is a company making information about their sustainability goals accessible in a transparent and timely way?

Top 10 Energy Storage Trends & Innovations in 2024

Published By: Start US Insights
View the original article here

Energy storage is undergoing a rapid transformation wherein research is underway to develop efficient long-lasting solutions. It is a critical component of the manufacturing, service, renewable energy, and portable electronics industries. Currently, the energy storage sector is focusing on improving energy consumption capacities to ensure stable and economic power system operations. Broadly, trends in energy storage solutions can be categorized into three concepts:

  • Moving away from the traditional lithium-ion batteries toward innovative battery chemistries that offer greater stability, density, and shelf life.
  • Developing storage solutions that store intermittent renewable energy efficiently and also scale it up to power large geographical areas.
  • Transitioning from centralized energy storage to a more flexible and portable distributed form of energy storage.

This article was published in August 2022 and updated in September 2023.

Innovation Map outlines the Top 10 Energy Storage Trends & 20 Promising Startups

For this in-depth research on the top global decarbonization trends and startups, we analyzed a sample of 1366 global startups & scaleups. This data-driven research provides innovation intelligence that helps you improve strategic decision-making by giving you an overview of emerging technologies and trends in the energy industry. In the Energy Storage Innovation Map, you get a comprehensive overview of the innovation trends & startups that impact your company.

Top 10 Energy Storage Trends in 2024

  1. Advanced Lithium-Ion Batteries
  2. Lithium Alternatives
  3. Short Term Response Energy Storage Devices
  4. Battery Energy Storage Systems (BESS)
  5. Advanced Thermal Energy Storage (TES)
  6. Enhanced Redox Flow Batteries (RFB)
  7. Distributed Storage Systems
  8. Solid-State Batteries
  9. Hydrogen Storage
  10. Energy Storage as a Service

These insights are derived by working with our Big Data & Artificial Intelligence-powered StartUs Insights Discovery Platform, covering 3 790 000+ startups & scaleups globally. As the world’s largest resource for data on emerging companies, the SaaS platform enables you to identify relevant technologies and industry trends quickly & exhaustively.

Tree Map reveals the Impact of the Top 10 Energy Storage Trends

Based on the Energy Storage Innovation Map, the Tree Map below illustrates the impact of the Top 10 Energy Industry Trends. Companies and research organizations are developing advanced lithium battery chemistries and lithium alternatives. These innovations combat the peak energy demand from the grid. The immediate need to control this energy demand is advancing utility-scale and distributed energy storage solutions.

The electric vehicle (EV) and electronics industry depending on electric grids and on other distributed energy sources require quick charging and, hence, there is a growing demand for short-duration energy storage (SDES) devices. Due to the low recyclability and rechargeability of lithium batteries, alternate forms of batteries such as redox and solid-state are also rising. Additionally, innovative thermal and hydrogen storage technologies reduce the carbon footprint of the energy storage industry. Lastly, industrial energy consumers are leveraging energy storage as a service to incorporate renewable energy and address energy demands.

Global Startup Heat Map covers 1366 Energy Storage Startups & Scaleups

The Global Startup Heat Map below highlights the global distribution of the 1366 exemplary startups & scaleups that we analyzed for this research. Created through the StartUs Insights Discovery Platform, the Heat Map reveals that UK and US see the most startup activity, followed by other Western European countries.

Below, you get to meet 20 out of these 1366 promising startups & scaleups as well as the solutions they develop. These energy storage startups are hand-picked based on criteria such as founding year, location, funding raised, and more. Depending on your specific needs, your top picks might look entirely different.

Top 10 Energy Storage Trends in 2024

1. Advanced Lithium-Ion Batteries

Lithium-ion batteries offer advantages such as portability, fast recharging, low maintenance, and versatility. However, they are extremely flammable, sensitive to high temperatures, require overcharge or complete discharge protection, and suffer from aging. Moreover, there is a huge environmental implication to mining the components for battery manufacturing.

Therefore, startups are modifying lithium-ion batteries to increase their performance and lifetime. To achieve this, lighter and energy-dense materials like li-polymer, li-air, li-titanate, and li-sulfur replace the traditional lithium-cobalt electrodes. In addition, some startups recycle used batteries, advancing the circular economy.

Green Li-ion advances Lithium-ion Battery Recycling

Green Li-ion is a Singaporean startup that recycles lithium-ion batteries to produce battery cathode. The startup’s modular processing plants use co-precipitation hydrometallurgical technology in contrast to the conventional processes that use leaching reagents. This results in purity enhancement while reducing the production time of the rejuvenated cathode. Battery manufacturers utilize this solution for recycling batteries without the need for sorting.

Echion Technologies produces Lithium-ion Anode Material

UK-based startup Echion Technologies produces lithium-ion battery anode material for super fast charging. The startup’s anode material uses a proprietary mixed niobium oxide (XNO) technology which includes designing microcrystals with diffused lithium-ion. This enables fast charging without the need to use nanosized powders. Due to their high energy density, the applications of these anodes range from consumer electronics to the EV industry.

2. Lithium Alternatives

Lithium batteries are not environmentally friendly and it is hard to keep up with the increasing demand for lithium. These limitations are encouraging companies to look for alternative battery materials that power the next generation of battery storage. For instance, zinc-air batteries are a viable alternative to lithium given zinc’s abundant supply, inherent stability, and low toxicity.

Another efficient alternative is sodium-sulfur batteries. These batteries feature longer lifespans, greater charge/discharge cycles, high energy density, and are fabricated of relatively inexpensive materials. Some other promising battery chemistries are aluminum ion batteries, magnesium ion batteries, nickel-zinc batteries, and silicon-based batteries.

Offgrid Energy Labs develops Zinc-based Battery Technology

Indian startup Offgrid Energy Labs develops ZincGel, a proprietary battery technology. It uses a highly conductive zinc electrolyte and carbon-based cathode. The zinc electrolyte is self-healing, temperature-stable, and does not evaporate, thereby warranting a higher life. Moreover, the lack of side reactions and gas evolution ensures high coulombic and roundtrip efficiency. Two-wheeler EV manufacturers leverage this technology as a safe, eco-friendly, non-flammable, and sustainable alternative to the lithium-ion battery.

Altris creates Sodium Battery Cathodes

Altris is a Swedish startup that creates Fennac, a cathode material for use in sodium-ion batteries. The startup produces it using patented low temperature and pressure synthesis technology. It offers a low-cost, sustainable alternative to other electrode materials like alloys and hard carbon, without sacrificing performance. Battery-producing companies use this solution to implement it into their existing production lines and also find use in applications such as photochromic windows.

3. Short Term Response Energy Storage Devices

Devices such as supercapacitors, flywheels, and superconducting magnetic storage have existed for a very long time. Current battery technologies harness their potential in offering high power density for shorter time fractions. Even though they discharge quickly, they improve the quality and reliability of the power grid during transient periods such as after system disturbance, load changes, and line switching.

They also prevent the collapse of power grids due to voltage instability. Further, several startups integrate SDES into fuel cell applications to improve the charge-discharge cycle of electric vehicles. Many cities are also coupling their energy storage systems to SDES and noticed improvements in overall energy storage and charge cycles.

EEXION makes Supercapacitors

Israeli startup EEXION enables energy storage using supercapacitors. The startup’s proprietary product, Energize-N’-Go, is a chemically manipulated cell that uses pure carbon materials to achieve faster charging in comparison to rechargeable batteries. The recyclability and a near-infinite number of charge-discharge cycles make it apt for electric mobility applications.

GODI manufactures Hybrid Capacitors

GODI is an Indian startup that manufactures biowaste-derived hybrid capacitor material. The startup’s capacitor combines activated carbon and graphene which delivers short-term peak power required for fast charging. The extension of the solution from cell to module-level finds applications in automotive, renewable energy, and regenerative braking.

4. Battery Energy Storage Systems

Even though renewable energy technologies are more efficient and economical than ever before, they are highly intermittent in nature. Therefore, they need complementary solutions to fill in the availability gaps. Long-duration energy storage solutions ensure that renewable energy dominates power plant expansion but also overtakes traditional sources of energy.

As more and more clean energy sources are tied to the grid, the electricity infrastructure becomes better suited to tackle the changing demands. The risk of disruption also reduces significantly. Moreover, large-scale renewable energy storage improves the overall resilience of energy systems and accelerates the clean energy transition.

Albion Technologies offers a Smart Battery Energy Storage System

UK-based startup Albion Technologies makes battery energy storage systems (BESS) that serve renewable energy providers, developers, and grid operators. The startup’s product, Smart BESS, is a containerized system that enhances the battery lifetime and delivers over 90% usable energy. The solution is flexible and can be deployed almost anywhere and integrated with other units to meet diverse power and energy requirements.

Smart BESS is equipped with all the essential components, such as batteries, inverter, HVAC, fire protection, and auxiliary systems. It complies with the G99 UK national grid standards and enables the storage of clean energy from renewable sources, thereby reducing CO2 emissions and oil consumption.

Genista Energy designs Lithium-Iron Phosphate Battery Storage

Genista Energy is a UK-based startup that designs a lithium-iron phosphate-based battery energy storage system. It consists of a large container with several battery strings. The startup interconnects several such containers to obtain a scalable system to provide power in remote locations. Genista Energy offers power to industrial and commercial buildings while providing renewable energy management and an alternative to diesel generators.

5. Advanced Thermal Energy Storage

Heat storage, both seasonal and short-term, is an important means for affordably balancing high shares of variable renewable electricity production. The process of thermal energy storage includes providing heat to the storage system for removal and use at a later time. Conventionally, heating companies store hot or cold water in insulated tanks to use when demand increases to manage peaks in district heating and district cooling.

However, the developments in the few years showcase the use of new mediums such as molten salts, eutectic, and phase-changing materials to store heat energy. The most common application for thermal energy storage is in solar thermal systems. This overcomes the challenge of intermittent renewable energy and enables access to stored solar power at night.

HeatVentors offers Phase Changing Material (PCM)-based Thermal Storage

Hungarian startup HeatVentors makes phase-changing material-based thermal energy storage systems. The startup’s product, HeatTank, uses melting and solidification of phase change materials to store thermal energy. The use of these PCMs also saves space, energy, and cost by balancing the efficiency of the cooling and heating system. Companies providing heating, ventilation, and air conditioning (HVAC) systems utilize this solution to improve stability and peak performance management.

Cowa Thermal Solutions produces Capsule-filled Heat Tanks

Cowa Thermal Solutions is a Swiss startup that produces capsule-filled heat tanks for thermal energy storage. The startup’s solution, BOOSTER CAPSULES, utilizes naturally occurring salts as raw materials. The capsule-filled tanks have three times the storage capacity compared to normal water storage tanks without capacity or stability loss. As a result, the heating tank becomes energy-dense and less dependent on the main power. The distributed energy industry leverages this solution in combination with a photovoltaic (PV) system to provide continuous heating.

6. Enhanced Redox Flow Batteries

Redox flow batteries are used as fuel cells or rechargeable batteries. They consist of two interconnected tanks both containing electrolyte liquids and oppositely charged electrodes, where ions pass from one tank to another via a membrane. Redox flow batteries offer longer lifespans than lithium batteries as the flow of current from one tank to another does not degrade the membrane.

Moreover, due to their flexible system design and easy scalability, they offer great potential for utility-scale integration of renewable energy. Advances in the field focus on developing new redox chemistries that are cost-effective and offer greater energy density.

XL Batteries offers Saltwater-based Flow Batteries

US-based startup XL Batteries offers saltwater-based non-corrosive flow batteries. The startup uses organic molecules from inexpensive, industrial feedstock to store charge in the battery. Since dissolved charge storage molecules flow over electrodes in a separate stack during charging and discharging, independent sizing is possible. The mild salt water-based chemistry also renders the battery inexpensive in comparison to vanadium flow batteries. The utility industry leverages this technology as an alternative to expensive lithium-ion batteries.

StorEn Technologies develops Vanadium Flow Batteries

StorEn Technologies is a US-based startup that develops vanadium flow battery technology. The property of vanadium allows the production of batteries with only one electroactive element as opposed to two, eliminating metal cross-contamination. They overcome the issue of decay and capacity loss in lithium batteries. StorEn Technologies’ batteries are apt for telecom tower batteries that source power from the electrical grid and renewable energy in off-grid locations.

7. Distributed Storage Systems

Energy generation and storage systems traditionally follow a centralized architecture. This increases grid failure risks during high energy demand periods, which may disrupt the energy supply chain. Distributed storage systems, on the other hand, address this challenge by allowing individual facilities to produce energy on-site and retain it for personal needs.

Energy producers are also able to sell the excess energy to the grid. Distributed energy storage solutions such as EVs, microgrids, and virtual power plants (VPPs) avert the expansion of coal, oil, and gas energy generation. Moreover, they enable greater reliance on renewables through the integration of local energy storage solutions like rooftop solar panels and small wind turbines.

​MET3R advances Vehicle-to-Grid (V2G) Management

​Belgian startup MET3R aids V2G management. The startup’s platforms, ZenChargeZenSite, and ZenGrid, utilize artificial intelligence (AI) to optimize fleet charging and reduce grid impact due to the charging site. Moreover, they provide insights on managing loads related to EV charging. Energy distribution companies leverage the startup’s platform to monitor the status of distributed energy assets (DERs) on low-voltage networks.

Karit provides Virtual Power Plants

Australian startup Karit offers virtual power plants. The startup combines a number of distributed energy assets such as generation and storage systems into a VPP. By consolidating the distributed energy assets, energy retailers ensure efficient power supply to customers while moving surplus energy into the market. Energy retailers and multi-site organizations use VPPs to enable predictive energy storage and management.

8. Solid-State Batteries

Conventional liquid electrolytes are highly combustible and have low charge retention and operational inefficiencies in extreme temperatures. To address these challenges, solid-state batteries replace the flammable liquid electrolyte with a solid compound that facilitates ion migration. Startups now use electrolytes like polymers and organic compounds that offer high ionic conductivity.

Additionally, solid electrolytes support the use of high voltage high capacity materials for battery manufacturing. This enables greater energy density, portability, and shelf life. Since solid-state batteries offer a greater power-to-weight ratio, they are also an ideal choice for use in EVs.

Solid State Battery (SSB) Incorporated makes Polymer-based Solid-State Electrolytes

SSB Incorporated is a US-based startup that makes polymer-based solid-state electrolyte material. The startup’s solid electrolyte combines polymer and ionic materials to improve ion mobility. In comparison with conventional liquid electrolytes, this material has high energy density while improving electrochemical and thermal stability. The solid-state separator allows packaging of these electrolytes into lithium batteries and also in larger applications such as vehicles or planes.

Theion offers Solid-State Crystal Sulfur Batteries

Theion is a German startup that devises solid-state crystal sulfur batteries. The startup uses direct crystal imprinting (DCi) to develop wafers from molten sulfur. Its proprietary solid-state polymer electrolyte operates within the voids of these wafers where lithium metal foil acts as an anode.

The advantages of this solution over conventional batteries include long cycle life, fast charging, low cell cost, and safety. Theion’s technology finds use in solutions ranging from smartphones and computer batteries to energy storage in cars and airplanes.

9. Hydrogen Storage

Hydrogen exhibits the highest heating value per mass of all chemical fuels while also being regenerative and environmentally friendly. It is stored physically either as gas or liquid. Storage as a gas typically requires high-pressure tanks whereas liquid storage requires cryogenic temperatures.

To economically store hydrogen, startups are designing innovative processes and storage tanks. In terms of storage types, recent trends indicate a shift towards the adsorption of hydrogen on solid surfaces and through chemical reactions. The applications of hydrogen storage range from use in cars as a clean fuel to portable power supply for buildings.

GRZ Technologies manufactures Solid-state Hydrogen Batteries

Swiss startup GRZ Technologies manufactures solid-state hydrogen storage systems. The startup stores hydrogen in atomic form within a metallic structure. This ensures greater safety while providing high volumetric density and a longer lifetime. The standardized stacks enable desirable storage capacity for obtaining stationary and portable power for the transportation industry.

Hydrogen First designs Composite Hydrogen Pressure Vessels

Hydrogen First is a Polish startup that designs composite overwrapped hydrogen pressure vessels. The flat vessel has an isotensoid shape with reinforcement studs across its thickness to store the compressed hydrogen. Its design facilitates carbon fiber reduction, thereby reducing the weight and cost of hydrogen storage. These flat composite containers find applications in the aerospace and automotive industry for storing hydrogen in gaseous, liquefied, supercritical, or cryogenic forms.

10. Energy Storage as a Service

There are several setup costs associated with the installation of energy storage infrastructure and long-term ownership leads to locked-in capital and stranded assets. Energy storage as a service allows businesses to obtain a reliable power supply at zero asset investment and low implementation costs. It enables facilities to evaluate the value of an energy storage solution.

This approach also offers maximum flexibility when market conditions shift. Further, energy storage as a service aids utilities in congestion management, seasonal peak demand management, and tackling grid infrastructure failures. Moreover, consumers in remote locations with weak or no grid connection benefit from increased grid flexibility and efficiency.

Hybrid Greentech simplifies Energy Storage Management

Danish startup Hybrid Greentech offers HERA, an AI-based energy storage management platform. It combines longer-term optimization models and short-term machine learning models to decide the optimal operation of energy storage assets.

This enables detailed operating expenses (OPEX) modeling in early concept development to ensure the best investment decisions. A variety of industries such as hybrid power plants, micro-grid, and electric mobility companies leverage this technology for advanced energy storage analytics.

Renon India makes Smart Battery Management Systems (BMS)

Renon India is an Indian startup that develops ARK, a smart battery management system. It performs passive balancing of cells by voltage measurement and temperature sensing. This ensures functional safety, efficiency, and performance of the battery packs. These ARK systems are suitable for batteries storing solar energy in commercial and industrial applications.

Discover all Energy Storage Trends, Technologies & Startups

Energy storage companies utilize advances in the sector to increase storage capacity, efficiency, and quality. Long-duration energy storage such as BESS plays a vital role in energy system flexibility. Battery energy management systems and VPPs, on the other hand, impact transmission and distribution grids. Additionally, standardization in storage systems, along with a network of distributed energy sources, will ultimately tackle challenges due to increasing energy demands and energy transition.

The Energy Storage Trends & Startups outlined in this report only scratch the surface of trends that we identified during our data-driven innovation and startup scouting process. Among others, lithium alternatives, hydrogen economy, and supercapacitors will transform the sector as we know it today. Identifying new opportunities and emerging technologies to implement into your business goes a long way in gaining a competitive advantage. Get in touch to easily and exhaustively scout startups, technologies & trends that matter to you!

Green hydrogen: Loaded up and (long-haul) trucking

By Joseph Webster and William Tobin
View the original article here

Long-haul trucking is a highly promising use case for the US hydrogen industry, and California and Texas are two large potential markets for pioneering hydrogen-fueled trucking. Both states have excellent green hydrogen potential and are taking initial steps to become hydrogen trucking hubs. When it comes to decarbonizing heavy-duty transportation, hydrogen is here for the long-haul. 

Cleaning up hydrogen

Today, the vast majority of hydrogen is produced from reforming the methane in coal or natural gas in a process that produces ten times more carbon dioxide than hydrogen by mass. It is principally used for refining heavy sour oil and producing ammonia for fertilizer. 

The most promising pathways to create zero-carbon clean hydrogen at scale are through renewables-produced green hydrogen or nuclear-powered pink hydrogen, both of which use zero-carbon electricity to separate hydrogen and oxygen via electrolysis. There is also blue hydrogen, which comes from natural gas in a process paired with carbon capture. Blue hydrogen’s role in decarbonization, however, is contingent on the mass buildout of carbon transportation and storage infrastructure.

If deployed judiciously, clean hydrogen can have a meaningful impact on lowering emissions in hard-to-electrify sectors, which require a chemical feedstock, long-duration energy storage, or extreme heat.

Long-haul trucking is a viable clean hydrogen offtaker

For most forms of transportation, growing economies of scale have given batteries an edge over hydrogen fuel cells. However, long-haul trucking—which accounts for 7 percent of transportation emissions—may be too high a fence for batteries to climb.

As a vehicle becomes heavier, its battery must expand proportionately in volume to provide the requisite power. Electric freight tractors use battery packs that are significantly heavier than the weight of diesel a truck typically carries, which decreases range and payload capacity while requiring more frequent charging. This is meaningful in the freight industry, where time is precious, and downtime can come at a cost of over $50 per hour before accounting for costs of charging. An electric long-haul truck takes thirty minutes to charge to only 70 percent capacity even with megawatt charging.  In comparison, hydrogen re-fueling can be done quickly. Refueling a hydrogen truck takes ten minutes.

Hydrogen fuel cell trucks are therefore likely to edge out batteries for trips surpassing 180 miles and payloads above 24,000 pounds, according to an industry study.

The US Department of Energy estimates that total cost of ownership for hydrogen fuel cell long-haul vehicles will become affordable by 2030 thanks to new production tax credits for clean hydrogen. Furthermore, the department cites evidence that the long-haul trucking sector is willing to pay a premium for clean hydrogen. This outcome, however, is contingent on a buildout of refueling infrastructure along freight corridors. To boost demand, infrastructure could be built along freight lines that support high volumes of freight, such as near seaports. This can help medium-sized refueling stations reach their breakeven utilization rate. To do so, industry and policymakers must overcome a chicken-and-egg problem. The development of refueling infrastructure is critical to enable hydrogen-powered long-haul trucks, and—conversely—hydrogen refueling stations will rely on long-haul trucking for their income, as hydrogen uptake in transportation is likely to be confined to this sector.

California and Texas: Unlikely hydrogen trucking partners

California and Texas are important players in both green hydrogen and long-haul trucking.

Not only do the two states have the largest populations and economies in the country, but they also have outstanding green hydrogen potential.

Both California and Texas have excellent renewable resources, including solar and wind. The two states have deployed nearly 74 gigawatts of solar and wind capacity with another 36 GW in development.

Texas and California are the nation’s largest and second-largest renewables generators. As more renewable electricity production grows in these states, so will green hydrogen capacity—although there will be tensions between providing renewables for power generation or hydrogen.

Long-haul trucking is a natural use case for green hydrogen in both states. Texas and California are the country’s largest users of diesel for the transportation sector, consuming 633,000 barrels per day in 2021, or about 21 percent of total US diesel demand. Both states rely heavily on trucking to transport cargo from ports along the coast of California and Texas to destinations further inland. Indeed, Los Angeles, Long Beach, and Houston are the country’s first, second, and fifth-largest container ports by volume, respectively.

There is already evidence that Texas and California’s long-haul trucking sectors could see synergies between ports and green hydrogen production. California provides fiscal support for zero-emissions vehicles, plans to end the sale of fossil fuel-powered medium- and heavy-duty trucks by 2036, and continues to develop hydrogen refueling infrastructure. Tellingly, Hyundai Motor will soon operate thirty fuel cell electric trucks in California; Hyundai states this deployment will mark the largest commercial deployment of fuel cell electric trucks in the United States in the super-large vehicle class. In North Texas, Air Products and AES are teaming up to construct the country’s largest green hydrogen facility to service the trucking industry.

The trucking fleet is replaced very rapidly: the average lifespan of a super-large class truck is eight years, while the median truck on the road today is approximately six years old. In comparison, personal vehicles are replaced on average only every ten and a half years. Moreover, unlike the personal vehicle segment, most long-haul trucks are procured by fleet owners who pay very close attention to the total cost of ownership, not just the sticker price. If hydrogen-fuel trucks become more competitive than their diesel counterparts, there could be a relatively rapid adjustment.

Hydrogen: Here for the long-haul

Hydrogen’s technical and economic fundamentals are likely to improve as technology advances and the Inflation Reduction Act incentivizes investments in renewables. Owing to their renewables potential, large ports, and significant diesel demand, California and Texas are primed to lead the trucking market’s transformation. While trucking fleet turnover will take time, hydrogen appears poised to disrupt the US trucking market.

Pieces That Need To Fall Into Place To Make Green Hydrogen Viable

By:  Steven Carlini, VP of Innovation and Data Center
View the original article here


In the zero-carbon economy of the future, electricity will become the dominant energy but green hydrogen (and the fuels derived from it) will have a role to play as well. Making green hydrogen viable and abundant will take collaboration, effort, and investment.

Pieces that need to fall into place to make green hydrogen viable

Hydrogen definitely has a role to play in global decarbonization. In the decarbonized world of the future, electricity will become the dominant energy with a 60-70% share in 2050, biofuels will rise, dependence on fossil-based energy will significantly decrease and hydrogen will increase. I want to focus on green hydrogen – derived from water using electrolysis since it is the most promising. In my estimation, green hydrogen will rise between 3 – 10 times the 90 Mt of hydrogen used today by 2050. The 3X – 10X projection goes from a very conservative 270 Mt (3X) to an aggressive 900 Mt (10X). So why is there such a large gap if green hydrogen is the energy source needed for hard-to-abate applications? Mainly because there are 10 significant “pieces” of the puzzle that must come together to produce green hydrogen at the scale needed.

1) Renewable Generation Electricity Capacity – Green hydrogen must be derived through electrolysis which is highly energy intensive. For hydrogen to be green the process must be electrified using a sustainable source (hydro, wind, or solar). How much? The electricity required by 2050 for decarbonized electrification and green hydrogen production of 900 Mt (10X) is estimated to be 130,000 TWh – around 5X today’s total electrical supply of 27,000 TWh. By 2050 using the 900 Mt (10X) green H2 assumption, 30% of electricity use will be dedicated to producing clean hydrogen and its derivatives, such as e-ammonia and e-methanol.

2) Electrolyzer Capacity – Once there is sufficient renewable generation, the capacity of electrolyzer plants needs to match. According to Bloomberg NEF, today’s global electrolyzer capacity of 300 MW must grow to 3000 GW by 2050 to meet clean hydrogen demands of 900 Mt (10X). IEA estimates that every month from January 2030 onwards, three new hydrogen-based industrial plants must be built.

3) Total Cost of green hydrogen – Green hydrogen is fundamentally tied to the cost of renewable electricity, the cost of clean water, CapEx cost of electrolyzer plants, the efficiency of the electrolyzer plant, and finally the cost of storing and transporting the green hydrogen. Today, green hydrogen can cost around €2.5-€5/kg, making it significantly more expensive than the fossil fuel alternatives. Levelized prices need to fall to €1.5/kg by 2050 and possibly sub-€1/kg, to make it competitive with natural gas. However, there are incentives from governments around the world to bring the price down. In the US part of the Inflation Reduction Act created new provisions for clean hydrogen. Under the law, clean hydrogen plants in 2023 can receive a production tax credit up to $3 per kg of hydrogen, for the first 10 years of operation through 2032.

4) Electrolyzer cost – the total installed costs of a GW scale industrial electrolysis plant is currently around 1400 €/kW for Alkaline electrolyzer technology and 1800 €/kW for PEM electrolyzer technology. These need to drop at least 50% by 2050 for green hydrogen to be cost-competitive. However, CapEx improvement plans cannot be a tradeoff resulting in reduced electrolyzer efficiency or durability.

5) Electrolyzer efficiency – Today’s efficiency hovers around 50%. To meet the cost targets, the consensus in the industry is that efficiency needs to continuously improve and be at 75% by 2050. This is a major engineering challenge, plus there is efficiency degradation every year as well.

6) Water Supply – Fresh or clean water must be used in electrolysis. Ocean or salt water (sometimes called seawater) cannot be used. Clean water can be aggregated from collecting rainwater or from a process called desalination. Desalination using reverse osmosis is another very energy-intensive process that also outputs brine (salt-dense water) as a byproduct.

7) Storage – Ideally, electrolysis plants should be located in areas that have abundant renewable electrical power and fresh water. Consumption in the future will likely be places like marinas for ships/vessels and airports for long-haul planes as well as strategic places in the electrical distribution system at the turbine or areas requiring grid stabilization. This means compression, storage, and transportation will be needed. Hydrogen does not degrade over time and can be stored indefinitely. In a gaseous form, it can be stored in ways: pressurized steel tanks and underground reservoirs or salt caverns (for large capacity). Hydrogen can also be liquefied. This would deliver about 75% higher energy density than gaseous hydrogen (stored at 700 bar), But it would waste the equivalent of 25%-30% of the energy contained in the hydrogen to liquefy.

8) Transportation Grid – Moving gaseous hydrogen from the place where it is derived to the place where it will be used is not a straightforward process. There is no piping infrastructure like there is with oil and natural gas pipelines or distribution grids. Because hydrogen is such a small and potentially combustible element, constructing a pipeline is quite challenging.

9) Demand side efficiencies – Just like miles per gallon affects how much fuel a car uses, all applications using electricity or hydrogen need to be made more efficient. A massive effort is required to modernize the existing stock of inefficient assets (buildings, mobility, industrial facilities, and machines, etc.), for higher efficiency or adapt to fun on hydrogen.

10) Funding – In total, investments could amount to almost $15 trillion between now and 2050 – peaking in the late 2030s at around $800 billion per annum1 for 900 Mt (10X). Of this, about $12.5 trillion (85%) relates to the required increase in electricity generation, with only 15% (peaking at almost $150 billion per annum in the late 2030s) relating to an investment in electrolyzer, production facilities, and transport and storage infrastructure. This investment must be coordinated between private-sector action and national and local governments.

The 10 “pieces” of the puzzle that must come together are significant. As with all puzzles, if a single piece is missing, the puzzle is ruined and the 3X scenario would be more likely than the 10X. We have no choice but to put this puzzle together and in this case, we must have all of the pieces in order to meet decarbonization targets and have green hydrogen play its critical role in the effort to halt global warming.

Navigating The Hurdles Of Green Hydrogen Production

By: Felicity Bradstock
View the original article here

There is great optimism around the future of green hydrogen, with many seeing it as a super-fuel that will replace oil-derived options, as well as be highly competitive with electric battery technology. However, we are far from achieving this ambition yet, mainly due to small-scale production operations and high costs. Many companies around the globe have plans to produce green hydrogen, but some are battling challenges that are slowing down the rollout of the clean fuel. Despite improvements in production processes, thanks to greater investment in the sector in recent years, the production and transportation costs of green hydrogen remain much higher than other fuels, including other types of hydrogen.

Producing grey or blue hydrogen, which is derived from fossil fuels, is viewed as relatively low cost, with many companies already relying on this fuel. Grey hydrogen is produced using natural gas. It undergoes a steam methane reforming (SMR) process, which breaks methane apart using high-pressure steam, which creates separate hydrogen, carbon monoxide, and carbon dioxide molecules. This process produces high levels of carbon dioxide, around 9 to 10 tons of CO2 for every ton of hydrogen. But it is also highly cost-effective, so long as natural gas prices remain stable. In July 2022, the cost of grey hydrogen was around $2 per kilo.

In contrast, green hydrogen production methods are more expensive. Green hydrogen is made using renewable energy sources to power an electrolysis process that separates hydrogen from water, producing just steam as a waste product. It is carbon neutral, making it highly attractive for companies looking to decarbonize. However, by July 2022, it cost around $4 to $5 a kilo, or even more, to produce green hydrogen. And some industry experts believe that the high cost of green hydrogen production isn’t going to fall any time soon. 

Green hydrogen is viewed by many international agencies, such as the International Energy Agency (IEA) and the International Renewable Energy Agency (IRENA), as a solution to decarbonize ‘hard-to-abate’ sectors. As more governments and private companies around the globe pump funding into green hydrogen operations, there are high hopes that the production cost of green hydrogen to fall substantially, to as low as $0.5 per kilo. However, others believe it will be difficult to drive the cost to lower than $3 per kilo. 

IRENA published two studies to drive green hydrogen production worldwide: Green Hydrogen: A Guide to Policy Making in November 2020, and Green Hydrogen Cost Reduction: Scaling up Electrolysers to Meet the 1.5°C climate goal in December 2020. These studies were aimed at encouraging governments and private companies to scale up production, aimed at driving down costs. However, the price of green hydrogen production so far remains elevated, at around 2 to 3 times the cost of grey hydrogen production, when gas prices are stable. 

Nevertheless, progress has been seen thanks to greater funding into research and development, with the price of electrolysers falling by around 60 percent since 2010. According to IRENA, they could decrease by a further 40 percent in the short term and by as much as 80 percent in the long term. This cost reduction prediction relies on greater innovation in electrolysis technology to improve its performance, as well as scaling up manufacturing capacity, standardization, and growing economies of scale.

Another challenge to consider is the cost of transportation. Murray Douglas, the head of hydrogen research at Wood Mackenzie, stated that “Hydrogen is pretty expensive to move… “It’s more difficult to move than natural gas … technically, engineering wise … it’s just harder.” And Douglas is not the only one concerned about this. The U.S. Department of Energy (DoE) has reported challenges with green hydrogen including “reducing cost, increasing energy efficiency, maintaining hydrogen purity, and minimizing hydrogen leakage.” The DoE believes greater research is required to “analyze the trade-offs between the hydrogen production options and the hydrogen delivery options when considered together as a system.” 

Companies worldwide are now considering the best locations for their green hydrogen production facilities. While there is great potential for the development of plants in Australia, North Africa, and the Middle East, these could be very far from their principal markets. Douglas highlighted the need for a dedicated pipeline, constructed between the producer and end-user if moving green hydrogen by pipe. Alternatively, green hydrogen could be transported as ammonia with nitrogen, which could be shipped and sold to consumers such as fertiliser producers. Otherwise, users would have to crack the ammonia back into nitrogen, which would increase costs and result in energy losses. 

For green hydrogen to be as successful as everyone hopes, it will require significant investment to overcome these challenges. Jorgo Chatzimarkakis, the CEO of the industry association Hydrogen Europe, suggests the need for a certification system, to guarantee that any green hydrogen production was powered by renewable sources. Further, a well-researched delivery strategy needs to be developed to ensure that production facilities are adequately linked with green hydrogen markets. This has been seen in projects such as Cepsa’s green hydrogen corridor between southern and northern Europe. 

While transportation costs are high, companies already understand how to move green hydrogen as they have been doing it the same way with natural gas for decades. But some are deterred by high costs. Therefore, the industry must drive down production costs to alleviate some of the pressure on transportation. Although the green hydrogen industry continues to face several major challenges, preventing a wide-scale deployment of the clean fuel, greater investment in the sector over the coming decades will likely fix many of these problems and allow for the deployment of global, large-scale green hydrogen production.

How sodium could change the game for batteries

Cheaper batteries might be on the horizon.

By: Casey Crownhart
View the original article here

Buckle up, because this week, we’re talking about batteries. 

Over the past couple of months, I’ve been noticing a lot of announcements about a new type of battery, one that could majorly shake things up if all the promises I’m hearing turn out to be true.

The new challenger? Sodium-ion batteries, which swap sodium for the lithium that powers most EVs and devices like cell phones and laptops today. 

Sodium-ion batteries could squeeze their way into some corners of the battery market as soon as the end of this year, and they could be huge in cutting costs for EVs. I wrote a story about all the recent announcements, and you should give it a read if you’re curious about what companies are jumping in on this trend and what their plans are. But for the newsletter this week, let’s dig a little bit deeper into the chemistry and consider what the details could mean for the future of EV batteries.

Top dog

One of the reasons that lithium dominates batteries today is absolutely, maddeningly simple: it’s small. 

I mean that in the most literal, atomic sense. Lithium is the third-lightest element, heavier than only hydrogen and helium. When it comes down to it, it’s hard to beat the lightest metal in existence if you’re trying to make compact, lightweight batteries.

And cutting weight and size is the goal for making everything from iPhones to EVs: a lightweight, powerful battery means your phone can be smaller and your car can drive farther. So one of the primary ways we’ve measured progress for batteries is energy density—how much energy a battery can pack into a given size. 

When you look at that chemical reality, it’s almost no wonder that lithium-ion batteries have exploded in popularity since their commercial debut in the 1990s. There are obviously other factors too, like lithium-ion’s ability to reach high voltages in order to deliver a lot of power, but the benefit of being lightweight and portable is hard to overstate. 

Lithium-ion batteries have also benefited from being the incumbent. There are countless researchers scouring the world for new materials and new ways to build lithium-ion cells, and plenty of companies making them in greater numbers—all of which adds up to greater efficiencies. As a result, costs have come down basically every year for decades (with the notable exception of 2022). 

And at the same time, energy density is ticking up, a trend I’m personally grateful for because I often forget to charge my phone for days at a time, and it typically works out much better when that happens now than it did a few years ago. 

Branching out

But just because lithium-ion dominates the battery world today doesn’t mean it’ll squash the competition forever. 

I’ve written about the growing number of options in the battery industry before, mostly in the context of stationary storage on the electrical grid. This is especially important in the transition to intermittent renewable energy sources like wind and solar. 

While backup systems tend to use lithium-ion batteries today since they’re what’s available, many companies are working to build batteries that could eventually be even cheaper and more robust. In other words, many researchers and companies want to design batteries specifically for stationary storage.  

New batteries could be made with abundant materials like iron or plastic, for example, and they might use water instead of organic solvents to shuttle charge around, addressing lingering concerns about the safety of large-scale lithium-ion battery installations. 

But compared to stationary storage, there are fewer candidates that could work in EV batteries, because of the steep demands we have for our vehicles. Today, most of the competition in the commercial market is between the different flavors of lithium-ion batteries, with some lower-cost versions that don’t contain cobalt and nickel gaining ground in the last couple of years. 

That could change soon too, though, because just below lithium on the periodic table, a challenger lurks: sodium. Sodium is similar to lithium in some ways, and cells made with the material can reach similar voltages to lithium-ion cells (meaning the chemical reactions that power the battery will be nearly as powerful). 

And crucially, sodium-based batteries have recently been cramming more energy into a smaller package. In 2022, the energy density of sodium-ion batteries was right around where some lower-end lithium-ion batteries were a decade ago—when early commercial EVs like the Tesla Roadster had already hit the road. 

Projections from BNEF suggest that sodium-ion batteries could reach pack densities of nearly 150 watt-hours per kilogram by 2025. And some battery giants and automakers in China think the technology is already good enough for prime time. For more on those announcements and when we might see the first sodium-battery-powered cars on the road, check out my story on the technology. 

Related reading

Here’s how sodium batteries could get their start in EVs.

I wrote about the potential for this sort of progress in a story from January about what we might see for batteries this year.

Sodium could be competing with low-cost lithium-ion batteries—these lithium iron phosphate batteries figure into a growing fraction of EV sales.

Take a tour of some other non-lithium-based batteries:

  • Iron-based batteries could be a cheap way to store energy on the grid and assuage concerns about safety. 
  • What about using plastic instead?
  • Some companies want to go beyond batteries entirely to store energy.  

Another thing

A startup says it’ll be ready to turn on the world’s first fusion power plant in five years. Yes, you read that right: five years. 

Helion Energy, a fusion startup backed by OpenAI’s Sam Altman, announced that it’s lined up an agreement to sell electricity to Microsoft. The company says its first plant will come online in 2028 and will reach full capacity (50 megawatts of output) within a year after that. 

As you might remember, the energy world reached a huge milestone in December when a fusion reaction generated more energy than what was put in to start it. But for a lot of reasons, that symbolic moment doesn’t necessarily mean cheap fusion power is within our grasp. And some experts are pretty skeptical about Helion’s announcement. Read more about the details in this story from my colleague James Temple. 

Keeping up with climate

Need a few extra miles of range on your EV? Might as well slap some solar panels on the roof. But don’t expect too much of a boost. (Bloomberg) 

For the first time in my entire life, I seem to be experiencing seasonal allergies. And climate change might have something to do with it. (The Atlantic)

Companies might be overselling the potential for so-called “renewable natural gas.” While it can cut emissions relative to fossil sources, critics worry that putting too much stock in methane made from cow manure or food scraps will slow efforts to ditch fossil fuels. (Canary Media)

→ I wrote earlier this year about how the process to make and capture methane from food scraps works. (MIT Technology Review)

Aubrey Plaza is hilarious and a gift to this world, but some people aren’t so happy about a recent ad she did for the dairy industry that takes aim at plant-based milks. (Vox)

India might stop adding new coal power plants to the pipeline. While this wouldn’t stop all current construction, it could be a major boost to the country’s emissions cuts. (Reuters)

A lot of the work to improve battery performance has been basically focused on one half of the device: the cathode. But some companies are working hard to improve the often-overlooked anodes by using silicon. (IEEE Spectrum)

→ Silicon anodes from startup Sila made their debut in fitness trackers nearly two years ago. The next stop? EVs. (MIT Technology Review)

Support for nuclear power in the US just reached its highest level in over a decade, according to a new Gallup poll. (Grist) 

Electric vehicles made up 80% of Norway’s new car sales last year. The country provides a picture of the potential future for electrified transport’s benefits (cleaner air!) and challenges (long charging lines). (New York Times)

Why it’s so hard to build new electrical transmission lines in the U.S.

By: Catherine Clifford
View the original article here

Service technicians work to install the foundation for a transmission tower at the CenterPoint Energy power plant on June 10, 2022 in Houston, Texas.
Brandon Bell | Getty Images News | Getty Images

Building new transmission lines in the United States is like herding cats. Unless that process can be fundamentally improved, the nation will have a hard time meeting its climate goals.

The transmission system in the U.S. is old, doesn’t go where an energy grid powered by clean energy sources needs to go, and isn’t being built fast enough to meet projected demand increases.

Building new transmission lines in the U.S. takes so long — if they are built at all — that electrical transmission has become a roadblock for deploying clean energy.

“Right now, over 1,000 gigawatts worth of potential clean energy projects are waiting for approval — about the current size of the entire U.S. grid — and the primary reason for the bottleneck is the lack of transmission,” Bill Gates wrote in a recent blog post about transmission lines.

The stakes are high.

Herding cats with competing interests

Building new transmission lines requires countless stakeholders to come together and hash out a compromise about where a line will run and who will pay for it.

There are 3,150 utility companies in the country, the U.S. Energy Information Administration told CNBC, and for transmission lines to be constructed, each of the affected utilities, their respective regulators, and the landowners who will host a line have to agree where the line will go and how to pay for it, according to their own respective rules.

Aubrey Johnson, a vice president of system planning for the Midcontinent Independent System Operator (MISO), one of seven regional planning agencies in the U.S., compared his work to making a patchwork quilt from pieces of cloth.

“We are patching and connecting all these different pieces, all of these different utilities, all of these different load-serving entities, and really trying to look at what works best for the greatest good and trying to figure out how to resolve the most issues for the most amount of people,” Johnson told CNBC.

What’s more, the parties at the negotiating table can have competing interests. For example, an environmental group is likely to disagree with stakeholders who advocate for more power generation from a fossil-fuel-based source. And a transmission-first or transmission-only company involved is going to benefit more than a company whose main business is power generation, potentially putting the parties at odds with each other.

The system really flounders when a line would span a long distance, running across multiple states.

States “look at each other and say: ‘Well, you pay for it. No, you pay for it.’ So, that’s kind of where we get stuck most of the time,”  Rob Gramlich, the founder of transmission policy group Grid Strategies, told CNBC.

“The industry grew up as hundreds of utilities serving small geographic areas,” Gramlich told CNBC. “The regulatory structure was not set up for lines that cross 10 or more utility service territories. It’s like we have municipal governments trying to fund an interstate highway.”

This type of headache and bureaucratic consternation often prevent utilities or other energy organizations from even proposing new lines.

“More often than not, there’s just not anybody proposing the line. And nobody planned it. Because energy companies know that there’s not a functioning way really to recover the costs,” Gramlich told CNBC.

Electrical transmission towers during a heatwave in Vallejo, California, US, on Sunday, Sept. 4, 2022. Blisteringly hot temperatures and a rash of wildfires are posing a twin threat to California’s power grid as a heat wave smothering the region peaks in the days ahead.
Photographer: David Paul Morris/Bloomberg via Getty Images

Who benefits, who pays?

Energy companies that build new transmission lines need to get a return on their investment, explains James McCalley, an electrical engineering professor at Iowa State University. “They have got to get paid for what they just did, in some way, otherwise it doesn’t make sense for them to do it.”

Ultimately, an energy organization — a utility, cooperative, or transmission-only company — will pass the cost of a new transmission line on to the electricity customers who benefit.

“One principle that has been imposed on most of the cost allocation mechanisms for transmission has been, to the extent that we can identify beneficiaries, beneficiaries pay,” McCalley said. “Someone that benefits from a more frequent transmission line will pay more than someone who benefits less from a transmission line.”

But the mechanisms for recovering those costs varies regionally and on the relative size of the transmission line.

Regional transmission organizations, like MISO, can oversee the process in certain cases but often get bogged down in internal debates. “They have oddly shaped footprints and they have trouble reaching decisions internally over who should pay and who benefits,” said Gramlich.

The longer the line, the more problematic the planning becomes. “Sometimes its three, five, 10 or more utility territories that are crossed by needed long-distance high-capacity lines. We don’t have a well-functioning system to determine who benefits and assign costs,” Gramlich told CNBC. (Here is a map showing the region-by-region planning entities.)

Johnson from MISO says there’s been some incremental improvement in getting new lines approved. Currently, the regional organization has approved a $10.3 billion plan to build 18 new transmission projects. Those projects should take seven to nine years instead of the 10 to 12 that is historically required, Johnson told CNBC.

“Everybody’s becoming more cognizant of permitting and the impact of permitting and how to do that and more efficiently,” he said.

There’s also been some incremental federal action on transmission lines. There was about $5 billion for transmission-line construction in the IRA, but that’s not nearly enough, said Gramlich, who called that sum “kind of peanuts.”

The U.S. Department of Energy has a “Building a Better Grid” initiative that was included in President Joe Biden’s Bipartisan Infrastructure Law and is intended to promote collaboration and investment in the nation’s grid.

In April, the Federal Energy Regulatory Commission issued a notice of proposed new rule, named RM21-17, which aims to address transmission-planning and cost-allocation problems. The rule, if it gets passed, is “potentially very strong,” Gramlich told CNBC, because it would force every transmission-owning utility to engage in regional planning. That is if there aren’t too many loopholes that utilities could use to undermine the spirit of the rule.

What success looks like

Gramlich does point to a couple of transmission success stories: The Ten West Link, a new 500-kilovolt high-voltage transmission line that will connect Southern California with solar-rich central Arizona, and the $10.3 billion Long Range Transmission Planning project that involves 18 projects running throughout the MISO Midwestern region.

“Those are, unfortunately, more the exception than the rule, but they are good examples of what we need to do everywhere,” Gramlich told CNBC.

This map shows the 18 transmission projects that make up the $10.3 billion Long Range Transmission Planning project approved by MISO.
Map courtesy MISO

In Minnesota, the nonprofit electricity cooperative Great River Energy is charged with making sure 1.3 million people have reliable access to energy now and in the future, according to vice president and chief transmission officer Priti Patel.

“We know that there’s an energy transition happening in Minnesota,” Patel told CNBC. In the last five years, two of the region’s largest coal plants have been sold or retired and the region is getting more of its energy from wind than ever before, Patel said.

Great River Energy serves some of the poorest counties in the state, so keeping energy costs low is a primary objective.

“For our members, their north star is reliability and affordability,” Patel told CNBC.

An representative of the Northland Reliability Project, which Minnesota Power and Great River Energy are working together to build, is speaking with community members at an open house about the project and why it is important.
transmission lines, energy grid, clean energy

Great River Energy and Minnesota Power are in the early stages of building a 150-mile, 345 kilovolt transmission line from northern to central Minnesota. It’s called the Northland Reliability Project and will cost an estimated $970 million.

It’s one of the segments of the $10.3 billion investment that MISO approved in July, all of which are slated to be in service before 2030. Getting to that plan involved more than 200 meetings, according to MISO.

The benefit of the project is expected to yield at least 2.6 and as much as 3.8 times the project costs, or a delivered value between $23 billion and $52 billion. Those benefits are calculated over a 20-to-40-year time period and take into account a number of construction inputs including avoided capital cost allocations, fuel savings, decarbonization and risk reduction.

The cost will eventually be borne by energy users living in the MISO Midwest subregion based on usage utility’s retail rate arrangement with their respective state regulator. MISO estimates that consumers in its footprint will pay an average of just over $2 per megawatt hour of energy delivered for 20 years.

But there is still a long process ahead. Once a project is approved by the regional planning authority — in this case MISO — and the two endpoints for the transmission project are decided, then Great River Energy and Minnesota Power are responsible for obtaining all of the land use permits necessary to build the line.

“MISO is not going to be able to know for certain what Minnesota communities are going to want or not want,” Patel told CNBC. “And that gives the electric cooperative the opportunity to have some flexibility in the route between those two endpoints.”

For Great River Energy and Minnesota Power, a critical component of engaging with the local community is hosting open houses where members of the public who live along the proposed route meet with project leaders to ask questions.

For this project, the utilities specifically planned the route of the transmission to run along a previously existing corridors as much as possible to minimize landowner disputes. But it’s always a delicate subject.

A map of the Northland Reliability Project, which is one of 18 regional transmission projects approved by MISO, the regional regulation agency. It’s estimated to cost $970 million.
Map courtesy Great River Energy

“Going through communities with transmission, landowner property is something that is very sensitive,” Patel told CNBC. “We want to make sure we understand what the challenges may be, and that we have direct one-on-one communications so that we can avert any problems in the future.”

At times, landowners give an absolute “no.” In others, money talks: the Great River Energy cooperative can pay a landowner whose property the line is going through a one-time “easement payment,” which will vary based on the land involved.

“A lot of times, we’re able to successfully — at least in the past — successfully get through landowner property,” Patel said. And that’s due to the work of the Great River Energy employees in the permitting, siting and land rights department.

“We have individuals that are very familiar with our service territory, with our communities, with local governmental units, and state governmental units and agencies and work collaboratively to solve problems when we have to site our infrastructure.”

Engaging with all members of the community is a necessary part of any successful transmission line build-out, Patel and Johnson stressed.

At the end of January, MISO held a three-hour workshop to kick off the planning for its next tranche of transmission investments.

“There were 377 people in the workshop for the better part of three hours,” MISO’s Johnson told CNBC. Environmental groups, industry groups, and government representatives from all levels showed up and MISO energy planners worked to try to balance competing demands.

And it’s our challenge to hear all of their voices, and to ultimately try to figure out how to make it all come together,” Johnson said.

Wind and solar power generators wait in yearslong lines to put clean electricity on the grid, then face huge interconnection fees they can’t afford

By: Catherine Clifford
View the original article here

Heavy electrical transmission lines at the powerful Ivanpah Solar Electric Generating System, located in California’s Mojave Desert at the base of Clark Mountain and just south of this stateline community on Interstate 15, are viewed on July 15, 2022 near Primm, Nevada. The Ivanpah system consists of three solar thermal power plants and 173,500 heliostats (mirrors) on 3,500 acres and features a gross capacity of 392 megawatts (MW).
George Rose | Getty Images News | Getty Images

Wind and solar power generators wait in yearslong bureaucratic lines to connect to the power grid, only to be faced with fees they can’t afford, forcing them to scramble for more money or pull out of projects completely.

This application process, called the interconnection queue, is delaying the distribution of clean power and hampering the U.S. in reaching its climate goals.

The interconnection queue backlog is a symptom of a larger climate problem for the United States: There are not enough transmission lines to support the transition from a fossil fuel-based electric system to a decarbonized energy grid.

Surprise fee increases

The Oceti Sakowin Power Authority, a nonprofit governmental entity owned by seven Sioux Indian tribes, is working to build 570 megawatts of wind power generation to sell to customers in South Dakota.

“Economic development through renewable energy speaks to the very heart of Lakota culture and values – being responsible stewards of Grandmother Earth, Unci Maka,” Jonathan E. Canis, general counsel for the Oceti Sakowin Power Authority, told CNBC. “Together our tribes occupy almost 20% of the land area of South Dakota. And the experts who have been measuring our wind resources literally describe them as ‘screamin.’.”

To connect wind power generation to the electric grid and make money from the sale of that power, the Oceti Sakowin Power Authority — like every electricity generator in the U.S. — has to submit an application called an interconnection request to whichever organization is overseeing the coordination of the electric grid in that region. Sometimes it’s a regional transmission planning authority, other times a utility.

This photo shows the rangeland on the Cheyenne River Reservation with the Missouri River in the distance. The Oceti Sakowin Power Authority wants to build two wind power projects and the Ta’teh Topah project, planned to be 450 megawatts, is the larger of two wind projects. The transmission tie-line for the Ta’teh Topah project will cross the rangeland and the river to interconnect with a Basin Electric transmission line east of the Missouri River.
Photo courtesy Oceti Sakowin Power Authority.

In late 2017, the Oceti Sakowin Power Authority paid a $2.5 million deposit to secure a place in line for its application to be reviewed by the Southwest Power Pool, a regional grid operator.

Five years later, in 2022, the Southwest Power Pool came back and told it that the fee to connect to the grid would actually be $48 million. That’s because connecting all that new power to the grid would require major updates to the transmission infrastructure.

The Oceti Sakowin Power Authority had 15 business days to come up with the extra $45.5 million.

“Needless to say, we couldn’t do it and had to drop out,” Canis told CNBC.

Now, the Oceti Sakowin Power Authority is reevaluating the size and composition of the project and plans to reenter the interconnection queue by the end of the year. That could mean another yearslong wait in line.

These burdens are typical.

In 2020, Pine Gate Renewables had a solar project located in the Piedmont region of North Carolina that it expected to cost $5 million to connect to the electric grid. The local utility in charge of overseeing the interconnection process told Pine Gate it would be more than $30 million. Pine Gate had to terminate the project because it couldn’t afford the new fees, its vice president of regulatory affairs, Brett White, told CNBC.

“We view, as a company, the interconnection problem as the biggest impediment to the industry right now and the costs associated with interconnection are the biggest reason that a project dies on the vine,” White said. “It’s the biggest wild card you have going into the project development cycle.”

There are efforts underway to improve the efficiency of the process, but they’re fundamentally putting a Band-Aid on top of an even deeper problem in the United States: There isn’t enough transmission infrastructure to support the energy transition from fossil fuel sources of energy to clean sources of energy.

“You could make the process for the queue as efficient and pristine as possible and it still could not be all that effective because at some point you’re going to run out of transmission headroom,” Wood Mackenzie analyst Ryan Sweezey told CNBC.

This photo shows the Western Area Power Administration’s substation in Martin South Dakota on the Pine Ridge Reservation where the 120 megawatt Pass Creek project, the smaller of the two wind power projects Oceti Sakowin Power Authority is trying to stand up, will interconnect if the project can move forward.
Photo courtesy Oceti Sakowin Power Authority.

Waiting in line

The entire electric grid in the U.S. has installed capacity of 1,250 gigawatts. There are currently 2,020 gigawatts of capacity in the interconnection queue lines around the country, according to a report published Thursday by the Lawrence Berkeley National Laboratory. That includes 1,350 gigawatts of power capacity, mostly clean, looking to be constructed and connected to the grid. The rest, 670 gigawatts, is for storage.

In 2022, the active energy capacity in interconnection queues in the U.S. is about 2,020 gigawatts and exceeds the installed capacity of entire U.S. power plant fleet, which is about 1,250 gigawatts, according to the report on interconnection queues out of Lawrence Berkeley National Laboratory published Thursday.
Chart courtesy Joseph Rand at Lawrence Berkeley National Laboratory.

Berkeley Lab pulls interconnection queue data from all of the regional planning territories in the United States and from between 35 and 40 utilities that are not covered by areas with regional planning authorities. The data covers between 85% and 90% of the electricity load in the United States, Joseph Rand, an energy policy researcher and the lead author of the study, told CNBC.

The interconnection process starts with a request to connect to the grid, which officially enters the power generator in the interconnection queue. The next step is a series of studies — the feasibility, system and facilities studies — where the grid operator determines what equipment or upgrades will be necessary to get the new power generation on the grid and what it will cost.

If all the parties can agree, then the power generator and grid operator reach an interconnection agreement, which establishes the grid improvements the power generator will pay for.

The total power capacity that comes out from a fossil fuel-burning power plant is often much greater than the capacity from renewable plants. That means it can take multiple wind or solar power generation plants — and, therefore, interconnection requests — to get the same units of energy online.

A single natural gas plant could be 1,200 megawatts, Sweezey told CNBC. “That’s one request — 1,200 megawatts,” Sweezey said. “Whereas usually if you’re going to get that same amount of capacity with renewables, that’s going to be six, seven, eight, nine, 10 different projects. So that’s 10 different requests in the queue.”

On average, it took a new power generation project 35 months to go from the interconnection request being filed with a grid operator to an interconnection agreement being reached in 2022, according to Berkeley Lab.

The amount of electricity generation in queues by region by type of power, according to the report on interconnection queues out of Lawrence Berkeley National Laboratory published Thursday.
Chart courtesy Joseph Rand at Lawrence Berkeley National Laboratory.

How did this process become such a problem?

The U.S. energy grid is a patchwork system of many regional utility companies. Some provide transmission services and some don’t.

In an effort to promote competition, the Federal Energy Regulatory Commission issued an order in 1996 saying transmission service has to be provided to power generators on a nondiscriminatory basis. This allowed all kinds of power generators, including those that do not own transmission infrastructure, to compete. In 2003, it issued another order that standardized the interconnection process for energy generators.

Both orders “attempted to make the services one needs nondiscriminatory and fair to all users, for their respective service,” according to Rob Gramlich, founder of transmission market intelligence firm Grid Strategies.

This is a simplified visualization of the interconnection queue study process.
Chart courtesy the Government Accountability Office and Lawrence Berkeley National Laboratory.

That process worked well enough when the power generation industry was building large, centrally located energy plants that burned fossil fuels. But the process started to show signs of strain around 2008 when renewable energy started to come online in places where there was not sufficient transmission, Gramlich told CNBC. In April 2008, MISO, one of the regional operators, said it would take 42 years, until 2050, for it to get through its interconnection queue.

Reforms in 2008 and 2012 helped a little bit, Gramlich told CNBC. “But I think everybody’s realizing now that that original process is fundamentally unsuited to the new generation mix.”

The interconnection process is especially bad at estimating battery storage, said White. That’s because transmission planning is always defaulting to the worst-case scenario, but batteries will draw energy from the grid when the demand is low and energy prices are low, and then use that stored power when the grid is at or near capacity. Using worst-case-scenario planning for battery storage fundamentally misses the point of a battery.

“The upgrades that are going to be triggered on the system are going to be very, very extensive and very, very expensive. And so they hand you a bill that reflects that,” White told CNBC.

But that kind of system upgrade “in our mind is totally disassociated from the economics of the asset, and not really looking at the benefit that the project is going to provide to the system,” White said.

Texas makes it easier

The rates of interconnection applications that actually reach commercial completion vary significantly, but none are higher than 38% in the New England region, according to Berkeley Lab. The Texas grid operator, Electric Reliability Council of Texas, or ERCOT, has a completion rate of 31% and is the only other region with a completion rate of over 30%.

On the low end, the California Independent System Operator region has an 13% completion rate and the New York Independent System Operator region is at 15%.

This chart shows the share of projects that requested interconnection from 2000 to 2017 that have reached a commercial operation date.
Chart courtesy Joseph Rand at Lawrence Berkeley National Laboratory.

The low percentage of interconnection requests that actually get built is partly because of the high cost to connect.

In the MISO region, for instance, interconnection costs were generally less than $100 per kilowatt-hour from 2008 to 2016, but have risen to a few hundred dollars per kWh for wind and solar, with spikes as high as $1,000 per kWh in some parts of the region, Gramlich told CNBC.

Adding even small amounts of energy to the grid requires infrastructure improvements because it’s nearly at capacity. Pushing those costs onto the builders of individual renewable projects generally makes them economically unsustainable.

“Those projects ended up withdrawing from the queue or terminating, because they don’t pencil anymore,” White told CNBC.

Some of the completion rates are artificially low because developers don’t actually expect to complete them all, but instead shop the same project around to various regional grid operators to get the best deal — what’s called “speculative queuing,” Sweezey told CNBC. It’s not expensive to get into queues, so developers submit applications to get information about which location will require the least expensive upgrades.

For grid operators, having power generators stuff their queues is overwhelming an already taxed system.

“Projects that have come through the process are not being built and becoming operational,” Jeffrey Shields, a PJM Interconnection spokesperson, told CNBC. “There are about 38,000 MW of renewable projects that have no further PJM requirements but are not being built because of siting, supply chain, or other issues facing the industry that are not related to PJM’s interconnection process.”

The long application timelines and expensive upgrades have made Texas a desirable place to build renewable energy projects because the state has its own interconnection application process.

“There is Texas, and then there’s the rest of the country with respects to interconnection,” White of Pine Gate told CNBC. Texas doesn’t require the same level of network upgrades to get power generation connected to the grid so getting a project online in Texas is faster and lower cost than the rest of the country, White said.

“You can put a project in the PJM queue tomorrow and it may not get constructed and built until 2030, whereas if you do the same with the Texas project, right now, it’s probably online in two to three years. So it’s just a much, much shorter timeline to commercial operation for a project in Texas,” White told CNBC.

But Texas also has a unique risk because ERCOT can decide to limit the amount of power that a generator can sell to the market if a particular electric corridor gets overly congested.

“It’s a bit of a double-edged sword,” White told CNBC. But with infrastructure deals, “time kills deals, time kills projects,” White said, so energy developers may prefer to take the risk and get the deal done.

Huge clouds and transmission towers are seen from Highway 5 in Kern County of California, United States on April 2, 2023.
Anadolu Agency | Anadolu Agency | Getty Images

How does this situation get fixed?

In June 2022, FERC issued a proposal on interconnection reforms to address queue backlogs and has since received a slew of public comments.

“We understand that 80 to 85 percent of the projects that are waiting in the queue ultimately are not being built. I think FERC has an opportunity here to make sure that we unlock that bottleneck and that we do all that we can to move those projects forward,” FERC Chairman Willie Phillips said on March 16, according to a statement provided by a FERC spokesperson.

The proposed rule change would offer incremental improvements, like providing information to developers so they can make more informed siting decisions without flooding the queue with speculative requests, and imposing more strict mandates on the regional grid operators to complete studies in a given time period, Rand of Berkeley Lab told CNBC.

“I do think what FERC is proposing has the potential to improve this situation,” Rand told CNBC. But fundamentally, these iterative changes won’t be a silver bullet.

“The energy transition is here. But our updating and expansion of our electric transmission system so far has not even remotely kept pace with that velocity, rate of change we are seeing on the generator-supply side,” said Rand.

There’s also a shortage of the kinds of electrical and transmission engineers required to process all of these applications, Sweezey and White told CNBC. “There’s just not enough people and so we have to think about what is the smartest way to maximize that expertise. And that means getting those engineers out of some of the rote manual data entry and into the actual analysis,” White told CNBC.

Another option is building new sources of clean energy that can be constructed closer to where demand is needed, like small nuclear reactors, Sweezey told CNBC. “I just don’t think people have come to that realization yet.”

Building sufficient transmission to support the energy transition is not necessarily a technical challenge as much as it is a political one.

“The type of coordination and planning that’s required for this kind of large-scale transmission — this involves maybe multiple utilities, multiple grid operators, multiple states, cities, counties, everything, even the feds are all involved — and that is antithetical to the U.S. as structured as a decentralized nation,” Sweezey told CNBC.

But the stakes are high.

“Even with all of the work, with all this great stuff that’s in the IRA and all of the wind that is in the sails of decarbonization in the renewable industry, if you can’t address transmission and infrastructure, then those goals aren’t going to be met,” White told CNBC.

“It really is the bottleneck that’s preventing that from happening.”

The Inflation Reduction Act upends hydrogen economics with opportunities, pitfalls

Regulators and policymakers must resist the temptation to overcommit to hydrogen for end uses where electrification will ultimately win out.

By: Dan Esposito and Hadley Tallackson
View the original article here

This opinion piece is part of a series from Energy Innovation’s policy experts on advancing an affordable, resilient and clean energy system. It was written ​​​​by Dan Esposito, senior policy analyst in Energy Innovation’s Electricity Program, and Hadley Tallackson, a policy analyst in the Electrification Program at Energy Innovation.

The Inflation Reduction Act has upended hydrogen economics, making “green” hydrogen — electrolyzed from renewable electricity and water — suddenly cost-competitive with its natural gas-derived counterpart.

On the supply side, electrolyzers can help utilities integrate renewables into the grid, speeding the clean electricity transition. On the demand side, electrolysis can cost-effectively decarbonize hydrogen production.

But the new hydrogen economics mean regulators and policymakers must be even more careful to avoid directing the fuel to counterproductive applications like heating buildings.

“Gray” hydrogen, which uses the highly-polluting steam methane reformation, or SMR, process, has long been the cheapest production method, trading around $1.50-2.00 per kilogram in the United States. In comparison, electrolyzed hydrogen costs about $4-8/kg without subsidies. The Inflation Reduction Act’s $3/kg incentive for zero-carbon hydrogen makes green hydrogen cheaper than gray, potentially spurring an electrolyzer boom.

To facilitate utilities connecting newly-cheap electrolyzers to the grid, regulators should set tariffs reflecting their flexibility value, empowering more bullish utility wind and solar resource procurement.

However, cheap hydrogen should not encourage its use in applications better served by direct electrification like buildings or transportation. Regulators should remain wary of gas utility proposals to blend hydrogen into pipelines, as they would achieve few emissions reductions before facing costly dead-ends while increasing threats to public safety. State policymakers should also use caution before directing public funds toward hydrogen light-duty refueling stations, as electric vehicles have substantial cost and performance advantages that risk stranding hydrogen vehicle infrastructure.

Instead, industrial consumers should use green hydrogen to decarbonize their gray hydrogen consumption for a cheaper, cleaner product.

The IRA’s clean hydrogen production tax credits

The Inflation Reduction Act offers a 10-year production tax credit for “clean hydrogen” production facilities. Incentives begin at $0.60/kg for hydrogen produced in a manner that captures slightly more than half of SMR process carbon emissions, assuming workforce development and wage requirements are met. The PTC’s value rises to $1.00/kg with higher carbon capture rates before jumping to $3.00/kg for hydrogen produced with nearly no emissions.

The carbon capture rate estimates assume an emissions rate of 9.00 kg CO2e / kg H2 from producing gray hydrogen.
Permission granted by Energy Innovation Policy and Technology.

However, the IRA’s “clean hydrogen” definition includes upstream emissions, including methane leakage from natural gas pipelines. Since methane is a much more potent greenhouse gas than carbon dioxide, even small leaks significantly increase the carbon capture rate needed to qualify for different PTC tiers.

This suggests “blue” hydrogen produced from pairing SMR and carbon capture and sequestration technology won’t qualify for the highest PTC value. Even hydrogen produced via pyrolysis — which uses natural gas but has no process emissions — may be knocked into lower tiers with enough methane leakage.

Green hydrogen therefore has a $3/kg subsidy advantage over gray and at least a $2/kg advantage over blue. These subsidies will be lower in practice, as the 10-year PTC will be spread over the facilities’ 15-or-more year lifetimes, but they still shift the hydrogen economics paradigm.

The opportunity: Cleaning today’s gray hydrogen while boosting renewable integration

The Inflation Reduction Act makes clean hydrogen production very cheap, but hydrogen faces costs for transportation, storage and conversion to other compounds. The U.S. also lacks hydrogen-compatible pipelines, storage caverns, refueling stations, and equipment like consumer appliances.

The first best use for clean hydrogen is circumventing these mid- and downstream cost and infrastructure challenges. Namely, clean hydrogen can plug-and-play to replace today’s gray hydrogen production.

For example, ammonia facilities and oil refineries use 90% of U.S. annual hydrogen production. Electrolyzers sited nearby can opportunistically produce clean hydrogen to reduce facilities’ fuel costs and emissions.

The gray hydrogen replacement market is huge — 90% of 2021 U.S. utility-scale wind and solar electricity would be required to produce it all via electrolysis. Green hydrogen also has a 25% to 50% greater GHG emissions reduction impact when replacing gray hydrogen than natural gas.

Non-hydro renewables includes wind, solar, biomass, and geothermal. Data excludes distributed generation.
Permission granted by Energy Innovation Policy and Technology.

This process can speed renewable energy deployment. Grid-connected electrolyzers can draw from renewables when electricity is cheap, helping finance them for power that would otherwise fetch low prices or be curtailed. When electricity prices rise, electrolyzers can ramp down, allowing the renewables to meet demand and keeping hydrogen production cheap.

The combination is a win-win: grid-connected, price-responsive electrolyzers help clean the industrial sector and power grid without committing to extensive new hydrogen-ready infrastructure and appliances. As U.S. renewables deployment accelerates, the demand for complementary green hydrogen may grow apace, including feeding an enormous clean ammonia export market.

The risk: Misallocating public funds for myopic projects

The Inflation Reduction Act’s clean hydrogen PTC is a massive incentive and can make many potential hydrogen end-uses look attractive. However, these propositions are often a mirage.

Clean hydrogen tax credits will reduce electrolyzer capital costs, helping unsubsidized green hydrogen production costs converge toward the cost of renewable electricity. However, since renewable electricity will always be an input to electrolysis, unsubsidized green hydrogen will never be cheaper than direct use of renewable electricity, even though the $3/kg credit is large enough to temporarily distort the market in hydrogen’s favor. By contrast, renewable energy subsidies are helping unsubsidized wind and solar become cheaper than fossil fuel power plants, as these resources’ costs are independent of each other.

Rightmost chart assumes green hydrogen is used for electricity production ($/MWh), but metaphor extends to any use-case where electricity and hydrogen can compete on the same time-scale.
Permission granted by Energy Innovation Policy and Technology.

Despite these dynamics, suddenly cheap hydrogen will amplify the fuel’s hype, inviting proposals for investing in hydrogen infrastructure and compatible end-use equipment. Such actions risk wasting time and money on research or infrastructure that will be underutilized or stranded once Inflation Reduction Act subsidies expire.

For example, gas utility plans to blend hydrogen with natural gas may be cost-effective with the subsidies, but they heighten safety and public health risks and aren’t long-term decarbonization strategies. By comparison, electric appliances like heat pumps and induction stoves use clean electricity approximately four times more efficiently than green hydrogen equivalents.

Other proposals may entail committing public funds to sprawling new infrastructure networks including pipelines and refueling stations to support hydrogen-powered fuel cell vehicles. Yet electric light-duty vehicles hold clear, insurmountable advantages that may be veiled by heavily subsidized hydrogen.

Hydrogen infrastructure proposals will sometimes be worthwhile. For example, geologic caverns for seasonal electricity storage can help clean the last 10% to 20% of the power grid, using green hydrogen to generate electricity when renewables and batteries are unavailable. Hydrogen can also be used as a feedstock or fuel for high-heat industrial processes. But in these cases, hydrogen’s advantage comes from filling a niche that direct electrification cannot, making its inefficiencies irrelevant.

Setting up for success

The IRA’s clean hydrogen tax credits can accelerate a reliable clean electricity transition while beginning to decarbonize industry — if applied judiciously.

Supporting a clean power grid will require incentivizing developers to connect electrolyzers to the grid rather than build standalone projects with co-located renewables, as only the former will allow utilities to benefit from electrolyzers’ flexible demand.

The U.S. Treasury should issue guidance clarifying how electrolytic hydrogen’s carbon intensity will be measured. Its framework should explicitly permit electrolyzers to connect to the grid, using collocated renewables, power purchase agreements, or potentially renewable energy credits to confirm they’re powered by renewables.

Regulators should direct electric utilities to set electrolyzer-specific tariffs, as current industrial tariffs may be mismatched with the flexibility value electrolyzers provide. They should also ease interconnection constraints and build more transmission, both of which can connect co-located renewables and electrolyzer projects to the grid. More grid-connected electrolyzers should then give regulators greater confidence to fast-track utilities’ renewable deployment schedules.

Industry consumers should explore contracts that allow clean hydrogen to replace some or all of their gray hydrogen, reducing costs and providing a cleaner product that may fetch higher prices from climate-conscious purchasers.

However, regulators and policymakers should steel their resolve against temptations to overcommit to hydrogen for end-uses where electrification will ultimately win out.

Research and development should focus on ways clean hydrogen can decarbonize hard-to-electrify sectors like aviation and shipping and boost long-duration electricity storage, rather than focusing on blending hydrogen into natural gas pipelines, using hydrogen for low-heat industrial processes, or designing hydrogen-capable consumer appliances. Limited state funds for commercialization should support electric infrastructure like electric vehicle charging stations and heat pumps, letting private companies take the risk for ventures like hydrogen refueling stations.

Together, these strategies can ensure the Inflation Reduction Act clean hydrogen tax credits maximize their value in reducing GHG emissions without inadvertently leading states and utilities down futile paths.