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NUCLEAR: The owner of New Jersey’s three nuclear plants says it will seek to extend the plants’ licenses for another 20 years, and says that new federal tax credits will enable the plants to run without state subsidies. (Associated Press, NJ Spotlight)
GRID: Executives from regional grid operators, including ISO-New England and the New York Independent System Operator, say they are “running like crazy” to keep up with rapid changes from decarbonization and electrification. (E&E News)
ELECTRIC VEHICLES:
COAL:
WIND: Officials from eight coastal New Jersey towns urge regulators to reject any attempt by Atlantic Shores Offshore Wind to rebid its project to take advantage of higher renewable energy credit rates. (Asbury Park Press)
UTILITIES: The Massachusetts Attorney General’s office finds that customers of competitive energy suppliers collectively paid $51.8 million more for electricity over a year than they would have paid with basic utility service. (State House News Service)
PIPELINES: Two years after Energy Transfer agreed to provide free water testing for residents impacted by Mariner East II pipeline construction in Pennsylvania, neither the company nor the state has disclosed information about the number of tests done or the results. (Spotlight PA)
EFFICIENCY: A Maine lumber mill will receive a $300,000 Department of Energy grant to install energy-efficient equipment. (WABI)
CLIMATE: New York lawmakers urge passage of a bill that would require the state to incorporate climate change into curriculum standards. (WSKG)
COMMENTARY: Advocates say offshore wind will be critical for meeting climate goals in Delaware, a state that imports most of its power. (Delaware Online)
COAL: Wisconsin utilities are in the process of determining what’s next for the sites of the state’s large coal plants as just a few will still be producing power in the coming years. (Wisconsin Public Radio)
GEOTHERMAL: Minnesota lawmakers introduce legislation to support the development of networked geothermal systems, a technology that is already taking off in the state to reduce buildings’ emissions. (Energy News Network)
POWER PLANTS: Local officials in northern Wisconsin decline to set public hearings for a proposed 625 MW gas plant near Lake Superior, delaying the project that has divided local opponents and labor groups. (Forum News Service)
CLIMATE: A Chicago neighborhood group pushes for more affordable housing development near transit stops, an approach leaders say combats both climate change and gentrification. (Grist)
ELECTRIC VEHICLES:
OHIO: A federal judge denies a request to move former Public Utilities Commission Chairperson Sam Randazzo’s corruption trial to Columbus from Cincinnati, where it is likely to start this summer. (Statehouse News Bureau)
SOLAR: Energy experts broadly expect natural gas to replace most of the solar output, which could top 40 GWh total, lost during Monday’s eclipse. (Utility Dive)
OIL & GAS: Officials believe oil leaking from containers on private property and into a storm drainage system caused a spill into a river in Flint, Michigan. (WJRT)
COMMENTARY:
Ohio ratepayer advocates say proposed state legislation would “rein in utility greed,” reduce shutoffs and prioritize customers in the wake of a historic utility bribery scandal. (Columbus Dispatch)
For years, utilities have grappled with how to handle the ever-growing number of solar and battery systems trying to connect to the lower-voltage grids that deliver power to customers. That’s especially true for midsize projects like, say, a solar array that might adorn the roof of a multiunit apartment complex or a community-solar project that generates power shared by hundreds of dispersed customers.
On the one hand, utilities have eyed such projects warily, fearing that if the solar panels or batteries inject too much power onto local circuits at moments when electricity demand is low, it might cause grid instability or safety problems. As a result, utilities have thrown up barriers that have delayed or halted grid connections.
But as advocates have been pointing out for over a decade, these distributed solar and battery resources can also be enormous assets: By holding back power when the grid doesn’t need it, and then sharing their extra power during periods of high demand, they can help alleviate grid strains and lower the cost of keeping the grid running for everyone.
It’s taken California regulators, utilities and clean-energy advocates nearly four years to hash out these conflicting ideas. But in mid-March, the California Public Utilities Commission approved new interconnection rules that take into account how, with the right structures in place, solar and solar-plus-battery systems can be more help than hazard to California’s overworked grid.
“This will open up opportunities for distributed energy resources to be designed in a way that aligns with grid needs,” said Sky Stanfield, an attorney who works with the Interstate Renewable Energy Council, the nonprofit group that’s been the main proponent of the new rules. “It’s a long time coming to recognize that distributed energy resources are a whole lot more helpful than they’re allowed to be — and that we don’t have to spend as much to upgrade the grid as a result.”
The “Limited Generation Profile option” just approved by the CPUC is a complicated set of regulations that determine how solar and solar-battery systems interact with the lower-voltage grids operated by California’s CPUC-regulated utilities Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric.
Today, those utilities make a simplistic set of assumptions when they consider the potential impacts of a project on the lower-voltage grid systems that carry power from substations to homes and businesses, Stanfield said — basically, that each project is producing its peak output at the time of least electricity demand from customers.
That’s pretty much how all U.S. utilities calculate the risks of new generation connecting to their grids, she noted. But this assumption is likely to yield findings that exaggerate how likely a project is to inject too much power onto local grid circuits.
To eliminate those perceived risks, utilities have demanded that project developers pay for grid upgrades themselves or have prevented the projects from connecting at all. Since those grid upgrades can cost hundreds of thousands to millions of dollars and take years to complete, the result either way tends to stop projects in their tracks.
The CPUC’s new policy takes a different tack, one well suited to larger-scale projects that are more likely to trigger grid upgrades. It will allow solar and battery projects to modulate how much power they send to the grid with the help of either solar inverters whose power-control systems can reduce power output from moment to moment or batteries that can soak up excess solar power and inject it back into the grid later.
Limited Generation Profile projects would be able to use these capabilities to alter their grid injections during different periods of the day, based on a set of schedules they can choose from. Those scheduling options are derived from the grid data available in the maps of hosting capacity from Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric. (Here’s a snapshot of PG&E’s hosting-capacity map for a downtown section of the central California city of Bakersfield, with circuit capacity represented in red, orange, yellow and green.)
Most utilities in the U.S. haven’t been ordered by regulators to collect the detailed and accurate local grid data needed to create these kinds of maps, Stanfield noted. In fact, the Interstate Renewable Energy Council has played a key watchdog role in alerting the CPUC to problems with these maps as they’ve been developed over the past decade, as well as in making them more useful for customers and project developers looking for good spots to connect to the grid.
Thanks to those improvements, California’s maps now contain accurate information on the hour-by-hour capacity of individual circuits.
With this data in hand, California’s three largest utilities and clean-energy project developers can finally agree on just how much power solar and battery projects can safely inject onto the grid during different periods of the day and night across each month of the year.
That amount may be close to zero during some stretches — say, on a circuit with many homes with rooftop solar systems during sunny and mild spring daylight hours, when self-generated solar power can exceed customer demand for electricity. Within those hours, Limited Generation Profile projects may export little or no energy at all.
But these “minimum-loading” conditions are relatively rare — and at other moments, that same grid circuit may be hungry for all the power it can get. That’s typically during hot summer and autumn evenings, when the state’s ample solar resources are fading away, yet electricity demand for air conditioning remains high — the same conditions that have caused statewide grid emergencies in recent years.
California’s power grid is struggling to deal with the wide swings between times when it has too much solar and times when all available resources still don’t provide enough electricity. In fact, the CPUC and state policymakers have made significant efforts to address this imbalance via state rooftop solar policy — which has reduced the value of solar delivered to the grid while promoting the value of batteries that can store power for when it’s needed — and with utility-scale power procurement policies, which have put gigawatts of batteries into operation over the past few years to store solar power for those evening hours when demand exceeds supply.
But until now, utility interconnection policy “has not taken into account, or enabled, distributed energy resources to differentiate when they produce power and when they don’t,” Stanfield said. That’s left interconnection policy misaligned with broader state policy imperatives for how best to use solar systems and batteries, she added.
It’s also put interconnection policy at odds with policy efforts to better manage growing distribution-grid costs, Stanfield noted. Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric are facing tens of billions of dollars of additional grid investment in the coming decades to supply the millions of electric vehicles, heat pumps and electric appliances that the state is asking consumers to adopt in order to reduce carbon emissions.
“Grid upgrades are expensive,” Stanfield said, “and we want to avoid them where we don’t need them” — particularly in cases where new solar and battery systems could actually help reduce grid strains.
Even more fundamentally, rules that bar more solar and battery power from reaching the grid based on outdated and inaccurate methods of determining their grid impacts will rob customers at large of the value those projects could provide.
That’s the conclusion reached by Amin Younes, an electric distribution planning and policy engineer with CPUC’s Public Advocates Office, which represents utility customers’ interests. Younes studied the potential for the Limited Generation Profile option to add more clean energy to California’s grids during hours when energy is in short supply.
This graphic from a presentation of his work indicates how widely the capacity of a typical distribution grid circuit can vary from hour to hour. In this case, limiting a solar or battery project to the minimum loading condition — the red line on the chart — would have forced a project to be sized to deliver no more than 1.5 megawatts of power of maximum capacity. But during many more hours of the year, that circuit could accept far more than that — often more than twice that minimum limit, or more than 3 megawatts of power.
According to his analysis, factoring in that extra capacity across the distribution circuits of all three utilities could add up to tens of billions of dollars per year in additional clean energy that could be delivered. And because that power would supply the grid at hours when electricity costs and threats of grid emergencies are the highest, that “could lower costs and increase grid reliability,” he said in an interview.
Finally, implementing the Limited Generation Profile option should allow solar and battery developers to avoid having to pay for grid upgrades and give them a much faster interconnection process, Stanfield said. And, if it works as planned, it could be a useful model for other states to follow.
In a 2021 blog post, the Electric Power Research Institute, a nonprofit power-sector research group involved in a wide variety of utility technology projects, highlighted the need for more flexible interconnection policies across the U.S. to prevent the tens of billions of dollars of forecasted investment in EV charging, distributed solar and battery backup systems from being stalled out by grid constraints.
The conservative, expect-the-worst approach that most utilities take with interconnection processes may be a way to maintain grid reliability, the institute noted. But it can also “lower customer satisfaction and slow progress toward renewable energy targets.”
It’s important to distinguish the problems plaguing this class of clean energy from the similar but distinct issues blocking hundreds of gigawatts of utility-scale wind and solar farms from connecting to transmission grids across the country. The Interstate Renewable Energy Council’s work in California and other states has focused mainly on distribution grid interconnection policies, which cover everything from rooftop solar systems and home battery and EV charging installations to multi-megawatt solar and battery projects.
While these types of interconnection problems can stymie even smaller-scale home rooftop solar systems, the bigger challenges tend to arise with larger-scale installations like community-solar systems that generate power for many different customers (in California, for example, most projects under 1 megawatt in generation capacity aren’t responsible for paying for grid upgrades). In many states, growing grid-upgrade costs and maddeningly slow interconnection timelines have become increasingly significant roadblocks to connecting these mid-sized projects.
In Minnesota, solar and consumer groups are fighting a utility policy that can assign hundreds of thousands of dollars in grid-upgrade costs to relatively small rooftop solar and community “solar garden” projects. In the community-solar-rich state of Massachusetts, some developers are stuck waiting for years for grid studies to allow projects to move forward.
States including New York, Minnesota and Massachusetts have begun to explore flexible interconnection policies — the more general term for the approach California is taking, according to Stanfield — but only through pilot projects or laborious “non-wires solutions” programs run by utilities. They have yet to embrace a standard way for clean energy developers to work with utilities.
Most other U.S. utilities haven’t been compelled by state law and regulatory mandates to produce the detailed distribution-grid-level data collection and hosting capacity analyses that enable the CPUC’s Limited Generation Profile approach, Stanfield noted. But these kinds of tools are starting to be developed in other states. That’s an important precursor to enable flexible interconnection, she said.
To be fair, utilities have very good reasons to take a conservative, safety-first approach to interconnection. After all, they’re responsible for keeping grids safe and reliable — and distributed energy resources represent potential disruptions to those grids that utilities can’t directly control.
That’s why California’s Limited Generation Profile option won’t go into effect until nine months after certain power-system control technologies are certified by the Underwriters Laboratory standards organization as being able to reliably perform according to schedule. That’s expected to happen sometime within the coming year, Stanfield said.
Utilities have also been concerned that changes on their grids could leave circuits susceptible to dangerous conditions. CPUC’s new policy does allow utilities to curtail a project during emergencies or request a change to the project’s schedule in the highly unlikely circumstance of a “sustained load reduction” on a grid circuit — namely, if a major customer using that circuit closes down and permanently reduces electricity demand.
But under the new rules, utilities are largely required to honor the schedules they’ve agreed to with solar and battery projects, and to take on reasonable costs of grid upgrades to manage them. That’s a vital feature for any successful flexible-interconnection process, Stanfield said, because project developers secure investment for projects based on some level of certainty about how much power they’ll be able to sell over the project’s lifetimes.
Any utility program that injects too much uncertainty into that prospect — by, for example, retaining the right to unilaterally curtail a project’s grid exports without a clear and provable grid problem to justify it — won’t work for developers, she said.
“A flexible interconnection solution, if it’s modeled and can show what the impacts are going to be, might give developers a lot more certainty and more comfort,” said David Gahl, executive director of the Solar and Storage Industries Institute, during a November event held by the Interstate Renewable Energy Council. That nonprofit is leading a flexible-interconnection pilot project in New York state that’s funded by The U.S. Department of Energy’s Interconnection Innovation e-Xchange program.
Utopia Hill, CEO of Reactivate, a joint venture developing community-solar projects for disadvantaged communities, also noted at the November event that the key to future flexible-interconnection processes is increasing their predictability. “If we can’t get financing parties comfortable with that, we can’t get the funding to build the projects,” she said.
It’s still not clear if the CPUC’s Limited Generation Profile rules will meet that need for California solar and battery developers, said Kevin Luo, interconnection policy advisor for the California Solar & Storage Association trade group. One big question is whether the scheduling options approved by the CPUC will actually allow developers to design moneymaking projects.
“That’s one of the reasons why we pushed so hard for customers to be able to pick their own schedules,” he said — an option that the CPUC denied. “Nobody has done the forecasting work necessary to have the confidence in any one schedule.”
Nor are California’s solar policies and market dynamics aligned to support the 1-megawatt-and-up projects that the Limited Generation Profile option would be best suited to, Stanfield said. California lacks effective policies to promote the development of multi-megawatt, distribution-grid-connected community-solar projects or large-scale rooftop solar projects on warehouses or apartment complexes that would be eligible for the new interconnection treatment — although solar and environmental-justice groups are pushing regulators and lawmakers to change that.
Even so, Stanfield said, starting with a schedule-based approach at least begins to align utilities’ grid needs with the imperative to add far more solar and batteries to California’s grid. That way, “you can start to get some of the benefits now — and then we can build on that further.”
The term “clean energy” often brings to mind gleaming solar panels, spinning wind turbines or water surging through a hydroelectric dam.
Few people would imagine dark salt caverns a mile underground, but these geologic formations could play a key role in the development of emissions-free green hydrogen.
Hy Stor Energy wants to use such salt caverns in Mississippi and elsewhere to store hydrogen made by splitting water molecules with electrolysis powered by new renewable energy. The fuel could then be stored in the caverns until electricity demand spikes and then used to generate emissions-free electricity when other renewables can’t meet demand.
Hy Stor Energy is among the companies that supports proposed rules for a potentially lucrative federal tax credit for “green” hydrogen fuel production. These companies provide a counterpoint to power companies and other industry players who are pressuring the government to relax provisions that demand green hydrogen production does not use existing renewable or nuclear power that would otherwise be used on the grid.
Companies, including members of federally funded hydrogen hubs, have argued that under the proposed rules governing the tax credit known as 45V, not enough hydrogen will be produced to meet demand and help develop a zero-emission economy.
But environmental advocates and academics point to studies showing that hydrogen production without stringent rules can actually lead to emissions increases. They, along with some industry sources, are calling on the U.S. Treasury Department to enshrine proposed requirements that hydrogen receiving tax credits meet “three pillars”: The renewable energy used to power electrolysis must be newly added to the grid, known as incrementality or additionality; it must be generated near the hydrogen plant, known as deliverability; and it must be generated around the same time it is used, known as hourly matching.
“Without the right rules in place, you’re going to see companies try to make as much hydrogen as possible, since the 45V tax credit is so lucrative,” said Dan Esposito, manager of the electricity program for the consulting firm Energy Innovation: Policy & Technology.
That, in turn, would place additional demand on the existing grid, much of which would be supported by coal and natural gas.
“Not only are you making [greenhouse gas emissions] worse, you’re making it more difficult to clean up our electric system,” Esposito said. “The climate community is saying if we set weak rules it will be a disaster, this will not be clean hydrogen, it will just be a huge greenwashing campaign.”
Hy Stor Energy is among the hydrogen companies and renewable energy developers that have sent letters supporting the rules as proposed. A March 1 letter to Treasury and White House officials from companies including Hy Stor Energy says:
“Clear section 45V guidance that upholds the three pillars is necessary to guard against harmful climate impacts and significant emissions increases that might be driven by increases in fossil fuel-based generation to sustain electrolysis when renewable generation sources are not available. Weak section 45V rules would permit this perverse result, thus imposing significant climate and market risk that would undermine the achievement of U.S. climate goals, further the perception of political risk in U.S. climate regulation, and upset the hard-won momentum currently driving investment in the sector.”
That letter was also signed by renewable energy developers CWP Global and ACCIONA, ACCIONA affiliate Nordex Green Hydrogen, major hydrogen producers Air Products and Synergetic, geothermal energy provider Fervo Energy and others.
The action followed a Feb. 26 letter from seven federally funded hydrogen hubs to the Treasury Department arguing against the three pillars. That letter touts the job creation potential of the hubs, but adds:
“Unfortunately, these investments and jobs will not fully materialize unless Treasury’s guidance, in its current form, is significantly revised, as many of the projects generating these investments and supporting jobs will no longer be economically viable.”
Esposito noted that when the hubs were created by the 2021 Bipartisan Infrastructure Law, the Inflation Reduction Act, including the 45V tax credits, had not yet passed; it was signed by President Joe Biden nine months later. In other words, the federal government expected the hubs to be able to succeed even without tax credits, Esposito argues.
“The public evidence suggests the hubs can do this the right way from the start,” he said. “They’re supposed to be centers of innovation, the whole point is they are research and development, so we shouldn’t give them the easiest path forward.”
Hy Stor Energy CCO Claire Behar said that the company controls 10 salt domes in Mississippi and has necessary permits from the state oil and gas regulatory body to move forward with their hydrogen production and storage project.
“We like to think our location at scale can really serve as a strategic hydrogen reserve, with years worth of hydrogen storage,” Behar said.
Power generation companies, “green steel” mills, and other hydrogen-hungry industries could be co-located near Hy Stor Energy. The company says these industries would basically be powered by renewables built specifically for this purpose, fueled by hydrogen that is created by renewables then stored for when it’s needed.
“It is really about having that large-scale storage that is dispatchable, we’re able to deliver a 24/7 product,” said Behar. “Those end users understand that the zero-carbon solution will have to be hydrogen. We’re focused on both the industry already existing in our region — maritime, large industrial — and also attracting new greenfield customers.”
Behar said requiring new renewable generation is crucial to define hydrogen production as clean.
“We can’t be cannibalizing current demand by using those renewables” already on the grid, Behar said. “We need a strong 45V rule that will protect against harmful climate impacts. If we have weak or blurred rules, it can really carry significant climate and emissions risks that will undermine both the achievement of climate goals and industry credibility.”
Start-up company Q Hydrogen argues that green hydrogen can be produced in ways that use much less energy and water than typical electrolysis. Q Hydrogen CEO Whitaker Irvin Jr. said his company never pushed for tax credits, and he thinks Q Hydrogen can produce hydrogen at a profit without such supports.
But since tax credits are reality, he wants stringent rules making sure that only truly green hydrogen production is eligible.
“The economic incentive is so astoundingly large, that if it does exist people can be creative and make [the three pillars] work,” Irvin said.
Irvin explained that technology pioneered by his father to develop a more efficient heat pump can actually make hydrogen with low energy and water requirements, by using streams of air with wide temperature differential to create a chemical reaction.
The company’s flagship facility is in the New Hampshire town of Groveton, drawing water from the Ammonoosuc River and electricity from a nearby hydroelectric plant, as well as backup power from the grid.
The hydrogen produced can in turn create clean energy that can be sold to industrial users and deployed when needed, Irvin said. This could relieve demand on the grid from existing industries during peak demand times, and help attract new industries to a town that has struggled economically since a paper mill closed in 2007. Irvin said he ultimately hopes the hydrogen-powered plant on the former paper mill site can sell power into New England’s grid.
He said Q Hydrogen would qualify for tax credits under the proposed IRS rules, since they use relatively little energy and since New England’s grid operator already employs technology that makes it possible to log when and where renewable energy is consumed and produced, helping to meet the hourly matching and deliverability pillars of the rules. This capability, along with ample water resources, are the reasons Irvin chose New England for the company’s first commercial-scale plant.
The company has a pilot operation in Park City, Utah, running since 2016, that can produce 10,000-50,000 kgs of hydrogen per day. Plants are also planned in Sweden and Germany, he said.
In December 2022, Q Hydrogen wrote a letter to the Treasury Department in response to its request for input on the tax credits. The letter urges the department to require additionality and stringent accounting for emissions impacts, in awarding tax credits.
“We don’t need [the tax credit] to be financially viable, but the industry does,” Irvin said. “That boost will allow for innovation, technological deployments, mass use at scale. I compare it to the early solar and wind days when subsidies were involved. I see this as the beginning of hydrogen becoming a real player in the market.”
The 45V rules as drafted require hourly matching documentation for renewable energy by 2028, showing that the renewable energy used to power hydrogen production was generated within the same hour.
Currently, energy attribute certificates, or EACS — similar to renewable energy credits — are based on annual matching, denoting how much clean power a user theoretically buys and uses in a year.
But if that power is mostly generated by solar in the summer, for example, the user is actually still relying on fossil fuel generation in the winter. Hourly matching can help ensure that renewable energy is literally powering an operation, but critics have said the software and other technology isn’t available to document hourly matching on a large scale any time soon.
Toby Ferenczi is co-founder and CEO of Granular Energy, a software company that provides hourly matching certification to utilities around the world. He says such documentation is entirely feasible and will drive construction of more renewable energy, including for powering green hydrogen.
“How do you as a consumer choose one type of electricity over another?” asked Ferenczi. “Whether you are a homeowner trying to buy clean energy for your home, or a tech company trying to buy clean energy for your data center, or a green hydrogen developer trying to buy green energy for your electrolyzer, it’s the same question.”
Hourly matching does not prevent green hydrogen producers from diverting renewable energy from the grid and causing other customers to rely on fossil fuels. But affixing time stamps to renewable energy credits and mandating hourly matching for tax credits will create market value for renewable energy used in real time, Ferenczi argues, driving the construction of more renewables and energy storage. Batteries or other storage technologies can store renewable energy that would also qualify for hourly matching when dispatched.
“Eventually tradable instruments can be priced according to supply and demand, with revenue streams for things like energy storage and flexibility, as well as more renewable energy,” Ferenczi said. “If you’re a green hydrogen producer, you could either sign lots of individual contracts with individual wind farms or solar farms, or just sign up for a product from your local utility or energy supplier” that can provide clean energy with hourly-matched credentials.
Even hydrogen producers that have exclusive power purchase agreements, or PPAs, with new renewable developments or on-site renewables will still need energy from the grid when the wind isn’t blowing or sun isn’t shining, he argues. So hourly matching will help them ensure all their power is truly green. He thinks hourly matching is a potentially better way to create more renewable energy than PPAs with new renewable developments.
“Additionality is first of all very difficult to prove. Even if you’re the one that signed a PPA, how do you know that someone else wouldn’t have signed that same PPA?” he asked. “Is it the person who signed the PPA who gets to claim the benefit, as opposed to the person who put up the equity or debt for the project or took the risk of developing the site at the very beginning? It’s very difficult to claim additionality and then assign the rights to those claims to any one individual.”
Time-stamped EACs are kept in a registry operated by regional transmission organizations. While technology upgrades will be needed to handle hourly matching nationwide, Ferenczi said PJM and other transmission organizations — including New England’s — already have similar capability.
Ferenczi said it is crucial that tax credit rules retain strong requirements to ensure “clean” hydrogen production doesn’t actually increase emissions, and called on regulators to make sure the proposed rules “aren’t watered down.”
“They’re absolutely essential to preventing what could be a catastrophe in terms of carbon emissions, that pushes up the cost of electricity for everyone,” said Ferenczi, who previously founded an international NGO called Energy Tag focused on time-stamped EACs. “If we build a fleet of gas turbines to meet this increased demand [for electricity to make hydrogen] because you don’t have an hourly matching requirement, you’re going to have a perverse side effect which is the opposite of what you intended.”
Editor’s note: This article has been updated to correct Claire Behar’s title.
The Biden administration’s lucrative incentives for hydrogen are slated to only go to “green” producers who use newly built clean energy sources to make the fuel — and some hydrogen producers aren’t happy about it.
Clean hydrogen has the potential to be a low- or zero-emission alternative to fossil fuels, and could clean up energy-intensive industries like steelmaking and heavy-duty transportation. But it’s not economical to produce just yet.
That’s why the Inflation Reduction Act established the 45V tax credit to help incentivize hydrogen that’s produced with clean energy under these three conditions:
Many companies, including federally backed hydrogen hubs, have pushed back against the rules, saying they will make their projects economically unviable.
But they’re not the only voice out there, Kari Lydersen reports for the Energy News Network. Companies like Hy Stor Energy and Q Hydrogen say they’re committed to producing clean hydrogen, and want the Treasury to only reward fuel that’s produced from new clean energy sources.
Without these parameters, producing hydrogen could actually end up driving up emissions, environmental advocates and academics say. That’s why Hy Stor Energy wants to build new renewable energy, use it to produce hydrogen, and then store it in a network of underground salt caverns for use when renewables can’t meet power demand. Q Hydrogen meanwhile draws its electricity from a nearby hydroelectric plant, and aims to sell its clean fuel to industrial users that otherwise would rely on fossil fuels.
Read more about these hydrogen innovators at the Energy News Network.
— Kathryn Krawczyk
🛑 Coal exports on hold: The bridge collapse in Baltimore is blocking access to the U.S.’s second-largest port for coal exports and will likely disrupt the industry for at least six weeks. (E&E News)
♿ Are EVs really for everyone? Electric vehicle chargers are often inaccessible for people with disabilities, a growing problem as officials forecast millions more electric vehicles on roads in the coming years. (Mother Jones)
🚛 Rolling toward zero-emission trucks: The U.S. EPA announces a new rule that aims to get more zero-emission heavy- and medium-duty trucks on the road by 2032, earning praise from environmental groups but concern from truck and engine manufacturers. (New York Times, NPR)
🏥 Efficiency saves lives: Appliance energy efficiency standards reduced emissions and prevented as many as 4,400 pollution-related deaths in 2017, researchers find, making a case for even stronger requirements. (Utility Dive)
⛵ Offshore wins: Over the past week, four developers bid to build offshore wind projects off the Connecticut, Massachusetts, and Rhode Island coasts, and the federal Interior Department approved three large offshore wind farms. (CT Mirror, E&E News, Associated Press)
🏭 Passing on gas: As economic growth drives new electricity demand, utilities look to natural gas as a quick fix, but customers and clean energy advocates say the strategy lacks ambition and ignores the giant pool of federal money currently available for cleaner alternatives. (Grist/WABE)
🌱 Greenhouse effect: Indoor farming offers producers steady growing conditions amid increasingly unpredictable weather, but their energy consumption represents a potential threat that could worsen climate change. (Washington Post)
👀 Eyes on state climate policy: A new searchable database aims to reveal how lobbying is derailing climate policy in 17 state legislatures. (Inside Climate News)
🗑️ Trash’s emissions impact: Landfills release an average of three times more methane than they report to federal regulators, a study of 1,200 landfills across the country finds. (New York Times)
This article originally appeared on Planet Detroit
While being a stay-at-home mom, Deana Neely had an idea. She began researching federal contracts and saw that Black women-owned businesses could win contracts and subcontract to other firms.
She also noticed that properties were being purchased all over Detroit. She felt that Black Detroiters needed a bigger stake in the contract work being performed amid the city’s development boom.
So Neely studied to get her electrical contractor’s license and founded Detroit Voltage, a Detroit-based Black-owned company that provides electrical contracting services for residential, commercial and government projects.
“It took me months. But after I got that first contract, my phone literally never stopped ringing,” Neely said. “Within my first six months of operating, we generated over six figures in revenue [and] became like the go-to electrical contractor in the city.”
Initially, Neely said she was not forthcoming about being a Black woman-owned business.
“It is very much so a white male-dominated industry, and I didn’t want anyone to know that I owned the company. And so everything about it looked like a white male owned it,” Neely said.
But, when she participated in a Google small business accelerator, the leaders of Google’s program encouraged her to bring her face to the forefront, a move that paid dividends later.
The U.S. construction industry remains largely white and male-dominated. Only 10.6% of construction managers in the U.S. are women, and only 4.8% are Black, according to the U.S. Bureau of Labor Statistics as of January 2024.
Despite the sector’s homogeneity, Neely is inspiring other people of color to enter the skilled trades with a focus on sustainability.
Today, Detroit Voltage is installing electric vehicle charging stations for DTE Energy in Detroit. And she’s also helping others enter the field.
In the Spring of 2022, Elevate, a national nonprofit based in Chicago, tapped Neely to help shape the Detroit Clean Energy Contractor Accelerator Program. The program trains contractors from underrepresented backgrounds to bring their businesses into the clean energy economy. The following year, Neely participated in the program’s first Detroit cohort.
“What we’re trying to do is build up a network of contractors that are located in Detroit,,” said Tim Skrotzki, Associate Director of partnerships at Elevate. “We want these contractors to look like and be from the community we’re working in. With Detroit being predominantly Black, 78%, we want contractors to reflect that.” Editor’s note: Skrotzki is an Advisory Council member for Planet Detroit
Beyond training workers in the space, the nonprofit seeks to get general contractors to understand clean energy technologies so that they can oversee such projects, he added.
Neely said the clean energy accelerator program has helped build a connected local ecosystem for contractors like her.
“It also opened our eyes to partnering to get the work done. So if we didn’t have the capacity to do it directly, we can work within the group to make it happen,” she said.
Detroit Voltage was contracted to install EV charging stations across the city on behalf of DTE Energy. Neely said that the two began working together last April, and Detroit Voltage had installed about 100 EV charging stations on behalf of DTE. Neely first connected with the utility giant through its Bright Ideas for Neighborhoods Business pitch competition, during which small local businesses compete for a cash prize. Neely won $5,000 at the competition.
Detroit Voltage was installing EV chargers prior to participating in Elevate’s accelerator, but the program introduced Neely to other possible services beyond EVs. For example, Neely said she plans to implement battery backup preventative maintenance sometime in the near future, such as inspections, testing, and upkeep of battery backup systems.
“We have a very positive working relationship with Detroit Voltage. They are a DTE-certified electrician who takes part in our Home EV Charger Installation program,” Ryan R. Lowry, spokesperson for DTE told Planet Detroit.
Before launching Detroit Voltage in April 2016, Neely spent more than a decade working for the Detroit Buildings, Safety Engineering, and Environmental Department. There, she met her now ex-husband and went on to have two children.
Similarly, Neely said she has tried to spread the word to young people in youth and professional organizations about opportunities in the industry.
“Everywhere you go there’s construction happening, ” Neely said. “Once you have this skill, you can go anywhere in the world and thrive with just the skill alone.”
Minnesota is home to a growing number of networked geothermal systems — essentially massive ground-source heat pumps providing low-emissions heating and cooling to a group of buildings.
Now, state legislators have introduced bills that aim to support further adoption of the technology, which advocates say is a key tool for cutting emissions in the building sector, especially in cold-weather states.
The legislation builds on what’s already happening in the state. Thermal energy networks have been installed in Rochester’s city hall and will be extended to a library and civic center to create a system serving more than one million square feet. Carleton College built a networked geothermal system and The Heights, a development on St. Paul’s East Side where more than 1,000 people will live and another 1,000 will work, will be heated and cooled by a networked thermal system.
“There’s a lot of excitement building around networked geothermal,” said Luke Gaalswyk, president and CEO of St. Paul-based Ever-Green Energy, a utility system operator and advisor with an expertise in district energy.
The state’s two major gas utilities, Xcel Energy and CenterPoint Energy, included networked geothermal pilots in plans submitted under the Natural Gas Innovation Act to the Public Utilities Commission. At least one legislative initiative calls for devoting 15% of the Innovation Act budget to networked geothermal. The federal government has several initiatives underway, too.
Joe Dammel, managing director for buildings at policy nonprofit Fresh Energy, said the state’s goal of becoming net zero by 2050 means shifting away from natural gas for heating.
“We think that there’s tremendous potential from network geothermal,” he said. “The studies being considered and the number of bills at the Legislature right now are only going to help us understand the technical and economic potential of geothermal.”
Fresh Energy also publishes the Energy News Network.
The proposed laws encourage geothermal in a variety of ways. One (HF 4759/SF 4849) offers planning grants to cities, counties and planning agencies to examine the feasibility of geothermal systems. A second (HF 4689/SF 4686) creates rebates related to geothermal. A third (HF 4688/SF 4687) requires the Public Utilities Commission to set up a workgroup. A fourth (HF 4423 / SF 4760) builds a framework for thermal energy network pilots and instructs the Commerce Department to study the potential for geothermal networks in Minnesota.
State Rep. Larry Kraft, a co-author on several of the bills, said buildings in Minnesota represent around 40% of carbon emissions and more than 60% in his suburban community of St. Louis Park. He believes municipalities that receive grants for geothermal and build systems will demonstrate, by example, the technology’s ability to decarbonize heating.
Kraft said ground-source systems, while expensive, are more efficient at heating than air source heat pumps. New developments may be easier to build with geothermal energy, or when streets are being reconstructed, neighborhoods could be retrofitted for it.
He imagines utilities that distribute natural gas will move to operating geothermal networks someday.
“How we decarbonize heating is going to be a big challenge for us here in a cold climate, but geothermal has great potential,” Kraft said.
Geothermal of any sort, however, remains expensive because the most common application, ground-source systems, requires drilling hundreds of boreholes and installing significant amounts of piping. There aren’t many contractors who can do this job, and financing institutions have little familiarity with it. Utilities may remain skittish because it threatens the natural gas business model.
Advocates believe more adoption will drop costs, create a robust contractor pool and enable more financing. Minnesota’s new Climate Innovation Finance Authority appears poised to be a potential financing source, having just provided $4.7 million for planning a networked geothermal for The Heights development in St. Paul.
Networked geothermal systems serve several buildings or homes with centralized heat or cooling using the same principle as district energy systems. A central heating and cooling source — typically borefields or aquifers — to serve many buildings while employing economies of scale to decrease costs through shared infrastructure.
Trade unions view networked geothermal as increasing employment opportunities for pipefitters and other contractors. Gas utilities could potentially transition toward geothermal as fossil fuel demand diminishes, Dammel said.
Clean energy advocates meanwhile like geothermal’s efficiency and ability to operate on electricity for heating instead of natural gas or propane. Lawmakers see thermal systems as providing a path to meeting the state’s goal of being net zero by 2050, Kraft added.
The Inflation Reduction Act incentivizes thermal networks by offering tax credits and direct reimbursements to government agencies and nonprofits.
“The [IRA] is contributing to an explosion in interest and adoption of geothermal,” said Ryan Dougherty, president of the Geothermal Exchange Organization.
Schools and other nonprofits can now receive 30% to 50% of the installed cost of a geothermal system, Doughtery said. The surge in commercial and institutional installations has grown so significantly that the industry has begun to face a labor shortage.
For the electric grid, networked thermal systems could bring relief because they use substantially less electricity than competitive solutions. Ground source heat pumps operate more efficiently than air source heat pumps, which now outsell fossil gas furnaces. And although ground source heat pumps use electricity, they consume less energy than heating alternatives, Gaalswyk said.
Such systems could even tap sources such as waste heat from wastewater facilities or data centers to warm buildings, he said. Another benefit is the ability to shift heat on a sunny day from a south-facing building, for example, to a north-facing one needing it.
Audrey Schulman, co-founder and co-executive director of the nonprofit climate solutions incubator HEET, said utilities with networked geothermal can begin heating water a week before an expected cold snap to avoid stressing the system — for instance, taking advantage of excess electricity from wind farms.
“There’s a lot of different options available,” Schulman said.
Massachusetts has required utilities to direct a growing percentage of funding allotted for replacing natural gas piping to networked geothermal, Schulman said. The fastest way to move away from natural gas and toward geothermal, she argues, will be by maintaining the financial health of natural gas utilities.
Utilities would socialize the cost of the capital expenditures to networked geothermal and then potentially pay it off by charging customers for the operations and maintenance, depending on the size of their homes or businesses.
“No one’s quite figured out how the charges will be structured,” she said.
Dammel said natural gas utilities have a long history of innovation and changing their business models. Initially, they provided natural gas for streetlighting before transitioning to a delivery service for natural gas.
“We certainly see that gas utilities could play a significant role in providing heat to customers and maintaining that longstanding customer relationship gas utilities have with their customers,” Dammel said.
Dammel and Schulman say regulators, utilities and others will face inevitable challenges in moving thermal systems into the mainstream. One is getting utilities onboard. Schulman said one Massachusetts utility, Eversource, fully embraces networked geothermal as the future, while others have taken a wait-and-see approach.
Dammel said utilities and clients must learn through pilots the upfront costs of the systems and how they could save money over time. Helping state residents and lawmakers understand the potential for networked geothermal and how it could benefit communities will be another task, he said.
Developing a geothermal workforce remains critical to growth. Minnesota has existing tradespeople capable of building geothermal systems, but the potential to create a much bigger workforce remains, Dammel said.
“There’s a huge opportunity,” he said, not only for installers but for companies developing new geothermal technology, financing, design and other aspects of the business.
Schulman agrees. Contractors drilling boreholes for geothermal in Massachusetts have become “overtaxed” with all the projects underway. The adoption speed will increase once regulators, utilities, and customers see the advantages.
“I can’t imagine any reason a customer would not want lower heating and cooling bills,” she said.
Legislative committees have heard several of the geothermal bills. Minnesota’s legislative session ends May 20.
GEOTHERMAL: Texas is emerging as a hotspot for geothermal energy exploration, with scores of former oil industry workers and executives seeking to use their knowledge of geology, drilling, and extraction to tap into a new energy source. (Texas Tribune)
OFFSHORE WIND:
OIL & GAS:
PIPELINES: A Virginia couple who have fought the Mountain Valley Pipeline for a decade talk about the grief, fear, and anger of having to live next to the project for the last six years. (West Virginia Public Broadcasting)
POLITICS: A bill awaiting signature from Florida Gov. Ron DeSantis would ban offshore wind energy, relax natural gas pipeline rules, and eliminate most mentions of climate change from existing state laws. (Grist)
GRID: Texas’ grid operator says it underestimated how fast San Antonio would grow, leaving the region with transmission issues that “could lead to cascading outages” and put the statewide grid at risk. (San Antonio Express-News)
SOLAR:
OVERSIGHT: A bill awaiting signature by Georgia Gov. Brian Kemp would extend the length of state utility regulators’ six-year terms by another two years. (Union Recorder)
TRANSPORTATION: Drivers of fuel-efficient and electric vehicles in Virginia say they are being penalized with higher vehicle registration fees. (WAVY)
INDUSTRY:
COMMENTARY: In a “reality check” on small nuclear reactors, a Virginia editor says the best site for one is likely at an existing nuclear power plant, but that it’s up to utilities and regulators — not the governor — to decide. (Cardinal News)
GEOTHERMAL: Geothermal power could help plug solar and wind power’s intermittency gaps, but experts say first scientists and developers need to unlock next-generation technologies that make it easier and cheaper to harness the earth’s heat. (Canary Media)
ALSO: Texas is emerging as a hotspot for geothermal energy exploration, with scores of former oil industry workers and executives seeking to use their knowledge of geology, drilling, and extraction to tap into a new energy source. (Texas Tribune)
CLEAN ENERGY:
CLIMATE:
OIL & GAS:
ELECTRIC VEHICLES:
STORAGE: The U.S. added 4,235 MW of new energy storage capacity in the last quarter of 2023, more than doubling additions in the previous quarter. (Utility Dive)
OFFSHORE WIND: New London, Connecticut, residents welcome federal incentives for offshore wind facilities, saying the first wave of wind workers are already boosting local businesses. (WTNH)
GRID: Grid operators want federal regulators to reject the North American Electric Reliability Corp.’s proposed cold weather reliability standards for power plants, saying they will only lead to more costly reliability issues in the future. (Utility Dive)
OFFSHORE WIND: The Biden administration approves the 924 MW Sunrise wind project, slated to be built off Long Island, marking the administration’s seventh major wind project approval. (Associated Press)
ALSO:
UTILITIES: A New York state audit finds PSEG Long Island is inadequately managing the Long Island Power Authority, and that its deficient renewable energy and efficiency programs jeopardize its ability to meet state clean energy goals. (Newsday)
ELECTRIC VEHICLES: New Jersey’s governor signs into law a new $250 annual registration fee for electric vehicles to patch a projected downturn in gas tax revenues. (New Jersey Monitor)
GRID:
STORAGE: Maine is on track to meet its goal of installing 300 MW of energy storage capacity by 2025, according to a report from state regulators. (Utility Dive)
COAL: The bridge collapse in Baltimore is blocking access to the U.S.’s second-largest port for coal exports and will likely disrupt the industry for at least six weeks. (E&E News)
SOLAR: A New York state senator introduces a bill that would increase the tax credit for homeowners to install rooftop solar to $10,000. (Spectrum News)
CLIMATE: Massachusetts’ climate chief discusses the state’s progress on installing heat pumps, and how rising temperatures are already affecting farming and other industries. (Berkshire Eagle)
LITHIUM: A Maine scientist argues a proposed rule change is adequate to allow lithium mining in the state, but environmental and health groups argue more safety considerations are needed. (Maine Morning Star)
HYDROPOWER: A western New York board game maker is awarded low-cost hydropower to support a $6.5 million expansion. (Buffalo News)
COMMENTARY:
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