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Heat pumps, induction stoves and other electric devices are increasingly seen as key to a clean energy future. And most new homes have electric service robust enough to handle them.
But older homes were not designed for big electrical loads, and millions will require updates before those new appliances can be safely plugged in.
In states like Minnesota, where old homes with natural gas furnaces and water heaters are common, upgrading electric panels “is going to be huge,” said Eric Fowler, senior policy associate for buildings at Fresh Energy, a clean energy advocacy group that also publishes the Energy News Network. “As we move toward electrification, that bottleneck is going to be the electric panel.”
In Minneapolis alone, the Center for Energy and Environment estimates owners of one- to four-unit buildings could spend between $164 million and $213 million to improve electric service. Pecan Street, a national research organization, found at least 48 million homes nationally may need electric panel upgrades.
And while changing out the electrical panel itself is fairly straightforward, bringing an older home with 60 or 100 amp service to a modern standard of 200 amps may require more extensive utility upgrades that can rack up thousands of dollars in additional costs.
Fowler said electricians modernize the panel of circuit breakers and, if needed, conduct a “service upgrade” to improve the wiring to carry more current between the home and the electric grid. “That upgrade cost can vary wildly, especially if it requires digging underground, potentially under pavement that will need repair,” he said.
One potential solution is a “smart panel” that could help manage the load, eliminating the need for a bigger utility line. While all the electrical devices running simultaneously could overwhelm a 100 amp service, a smart panel would manage those loads to ensure that limit is never reached.
“A smart panel lets you do the first upgrade without the second — you can manage more circuits with the same amount of electricity with slight adjustments in the timing of your electricity use,” Fowler said.
The Minnesota Legislature is considering House and Senate bills offering income-eligible grants to owners of homes and apartments to upgrade their electric panels to a higher amperage or purchase smart panels. The federal Inflation Reduction Act also contains home electrification incentives that could be applied to smart panel investments.
Connexus Energy, the state’s largest member-owned electric cooperative, has been promoting the technology to members. Rob Davis, communications lead for Connexus, said a coalition of businesses and clean energy advocacy groups support the measure and asked legislators to include smart panels.
While smart panels can save money over major utility upgrades, they are still an expensive undertaking. Angie’s List reported the average cost to upgrade an electric panel is $1,230, but that sum increases considerably if the project requires a new panel, additional rewiring and equipment, switches, and so forth. Some upgrades could cost thousands of dollars, especially on older homes.
The SPAN smart panel costs $4,500, not including installation, taxes and shipping. Schneider Electric’s Square D Energy Center Smart Panel lists at $2,999 but for now is only available in California. It also has a smart panel, Pulse, which works in conjunction with other appliances as part of a home energy management system that, if fully installed, will cost around $10,000, according to Wired. Lumin’s smart panel starts at $3,150.
Twin Cities Habitat for Humanity’s Mike Robertson manages Brush With Kindness, which repairs and paints existing homes. He believes the state assistance program would help low-income residents replace aging fuse boxes with devices capable of managing new electric demands.
“Historically, with this kind of technology, the early adopters tend to be rich White people, right?” he said. “If you’re having an equitable approach to decarbonization, then you have to think about disinvested communities, communities of color, where the difference in the utility bill and indoor air quality makes a difference in their lives.”
In Minnesota, Connexus has featured SPAN at a contractor event and its staff is familiar with the product. Principal technology engineer Tom Guttormson explained that power from utilities enters buildings through panels, which redistribute electricity through branch circuits to power lights, home sections and devices.
Panels have a main circuit breaker and smaller breakers. If you connect devices that, in the aggregate, draw too much power from one circuit, then it trips the main breaker, cutting power to the entire building. Building owners can usually switch the circuit back on themselves after turning off an appliance that might be causing the problem.
Common electric panels “are not intelligent devices,” he said. “New smart panels can provide the ability to monitor and control power flowing to various devices, and even let the users see the usage with a mobile device app.”
Smart panels will help consumers take advantage of time-of-use rates by allowing them to turn off home heating and cooling, electric vehicle charging, or appliances during peak demand times, he said. Those with solar could benefit, too, by selling energy during high-demand periods.
For utilities, intelligent panels provide an opportunity to improve load management and could reduce the need for widespread and costly capacity upgrades of transformers and other grid infrastructure, Guttormson said.
“We need to work together to optimize how all this works,” he said. “These conversations are ongoing, but it is all starting. This is all new territory.”
Hannah Bascom, a vice president at SPAN, learned from working at the thermostat company Nest that consumers need time to understand how new home products can improve their lives. As more companies develop smart panels, a product category will emerge and sales should grow, she said.
“The electrical panel is very well positioned to be the central artery in the brain of the home,” she said. “You can understand whole-home energy consumption by circuit by device type, and that is rich data not from the customer experience perspective but from connecting to load management programs in the future.”
A SPAN customer in Lanesboro, a small southeast tourist outpost in Minnesota, said that after just a few months of using one, he’s discovered the data has helped him save money. Joe Deden, the founder of Eagle Bluff Environmental Learning Center, built a new all-electric home with his wife, Mary, that features Tesla solar shingles on a sharply pitched roof, a Tesla Powerwall battery, and all-electric appliances.
Deden wanted a smart panel to direct energy to heating, battery storage, or other devices and to manage loads. Offering an example, he said during a below-zero day the electric backup boiler started operating, consuming three times the energy of his air-source heat pump.
After turning off the boiler, the heat pump maintained a good temperature in the home, using far less energy. He said with the panel he could show his electrician and heating technician “that something was amiss” in the heating system that would require some adjustments. Accessing household appliance data is one of the strengths of smart panels, Deden said.
Being able to easily turn off power to his office or other parts of the home to “save a load” when not needed is another advantage. “The ability to monitor and shed loads remotely is the key,” he said. “Being able to see remotely what’s happening and to be able to control things is, to me, a great peace of mind.”
A lack of inventory from auto manufacturers and a shortage of fast-charging options in rural areas are among the factors slowing progress toward Minnesota’s state government fleet electrification goal.
The Minnesota Department of Administration set a target in 2020 to make 20% of its vehicle fleet electric by 2027, part of an overall strategy to reduce state fleet fossil fuel consumption by 30% by 2027 from a 2017 baseline.
The state would have had to replace more than 400 gas vehicles with electric models per year since 2021 to meet that target, but state officials contacted by the Energy News Network were unable to say exactly how many electric vehicles the state has purchased overall. The Department of Transportation, a leader in electric vehicles among agencies, has 14. The Department of Natural Resources has four.
“We’re moving forward slower than I would like,” said Holly Gustner, fleet and surplus director for the Department of Administration.
The state has more than 15,000 vehicles, with the most progress on electrification in the light-duty category, which represents a third of the vehicles.
In 2021, the state’s light-duty category was dominated by flex-fuel vehicles capable of running on high ethanol blends, accounting for 55%. Hybrids followed at 22% and regular internal combustion engines at 15%. The rest were electric, plug-in hybrid and diesel-run models.
The state’s plug-in electric, hybrid and flex-fuel vehicles contributed to a 17% drop in emissions from light-duty vehicles in 2020 and 2021, according to administration data.
Vehicle cost plays a role when agencies make purchasing decisions, but the total cost of ownership favors electric. While electric vehicles command a higher initial expense, electricity costs less than gas, and the cars require less maintenance, said Marcus Grubbs, director of the Department of Administration’s Office of Enterprise Sustainability. Agencies also like the advantage of having fully charged vehicles available every morning so staff will not have to refuel during the day.
But agency leaders say many state vehicles have no easy electric replacement option yet, and manufacturers of those that do — typically cars, pickups and SUVs in the light-duty category — are often months behind in deliveries.
Automakers have been prioritizing states such as California and Massachusetts, which have requirements to make electric vehicles available. Gustner said one factor expected to increase Minnesota’s access to electric vehicles is its adoption of clean car standards, which have helped increase supply in other states as their demand increased. The Minnesota Pollution Control Agency adopted the California-developed standards last year and has been finalizing rules.
“I think once that rulemaking is completed, and we actually sign off as one of the clean car states, I think we’re going to see more cars coming this way,” Gustner said.
Grubbs said the government uses vehicles in such specific ways that finding electric replacements has not been easy. As an example, he pointed to a new electric transit van that “looked great” until he discovered it had no lift for disabled passengers.
“Availability has been the greatest challenge,” said Jed Falgren, state maintenance engineer with the Minnesota Department of Transportation.
His agency may have the biggest obstacles in meeting the state goal because light-duty vehicles are only 13% of its fleet. The rest are medium- and heavy-duty vehicles — including 800 snowplows — which currently have no practical electric replacement models available, he said.
Falgren said the agency has spoken to trucking manufacturers about replacing heavier vehicles with models fueled by hydrogen or compressed natural gas, which pollute less than plows now being used, he said.
New, greener snow plow models have begun to come onto the market, but how well they work remains a question. For example, a recent test in New York City found electric snowplows “basically conked out after four hours,” according to a city official there.
“Our plow trucks have got to run and be available to run 24 hours a day,” Falgren said. “So there’s a lot of technological nuts to crack before we can go widespread on some of those [vehicles].”
The Department of Natural Resources wants to add to its four-vehicle electric fleet and has ordered more. Aaron Cisewski, fleet and materials manager in the DNR’s Operations Services Division, said the agency covers a huge geographical area of Minnesota, with state parks and other offices spread far apart. Employees have expressed concerns about range reduction caused by cold weather and trailer towing, which the agency does a lot of in state parks.
The department has deployed Chevy Bolts in state parks, where they operate in a limited area and are recharged nightly, he said.
Gustner said developing a charging network for state vehicles has been a challenge. Parts of the system are robust, such as around the Capitol complex, where 65 chargers operate. But outstate Minnesota is a different story even as the state continues to add chargers in more rural locations.
Fast chargers are becoming a priority because most state workers will be “topping off” their vehicles rather than needing a full charge, Gustner added. But for now, the charging infrastructure in some areas “does not enable the flexibility [of long-distance travel] right now, or doesn’t exist, or isn’t perceived to exist,” he said.
Minnesota is better poised, despite the weather, to take advantage of transitioning to electric vehicles than some other states. The state government could replace more than half of its light-duty vehicles, a better average than Colorado or North Carolina, according to a National Renewable Energy Laboratory 2022 study of state fleet electrification.
Using 2-year-old data, the study found the driving range of electric vehicles on the market can meet 93% of the state’s light-duty needs. The study projected a $4.7 million savings over the lifetime of vehicles and a reduction of more than 10,000 metric tons of greenhouse gases.
While the new clean car standards are expected to help, Brendan Jordan, vice president of transportation and fuels at the Great Plains Institute, said Minnesota’s state government could have an easier time procuring electric vehicles if the state had additional policies that incentivize their purchase by residents and businesses.
“Other states offer incentives on the medium- and heavy-duty side, which we don’t offer,” he said. “Companies look at what kind of policy environments are in place when they’re deciding where to ship the cars.”
The Minnesota Future Fuels Coalition, which includes the Great Plains Institute and Energy News Network publisher Fresh Energy, has been advocating for the recently introduced Clean Transportation Standard Act that would require the carbon density of fuels to decline to zero by 2040.
There’s also legislation that would “establish a preference” for electric vehicles for the state’s fleet. Other preferred vehicles include hybrids and those that can run on cleaner fuel. The law would solidify a preference already practiced by agencies.
Should either or both bills pass, they would give the state government an extra benefit of removing some obstacles from electric vehicle acquisitions, Jordan said.
Either way, preparations continue for an electric future. With assistance from Xcel Energy and a consultant, MnDOT created a software tool that uses data captured from its vehicle fleet to determine suitable electric replacements, he said. In addition, plans are emerging for training mechanics to work on light-duty electric vehicles.
And the agency must get used to paying more upfront for electric vehicles while understanding the cost of ownership will be less in the long run.
“MnDOT does not mind being on the leading edge of technologies,” Falgren said. “The leading edge is a good spot to be.”
The following commentary was written by Olivia Ashmoore, a policy analyst at Energy Innovation, and Ashna Aggarwal, an associate at RMI. See our commentary guidelines for more information.
Climate leadership in Minnesota, Michigan, and Wisconsin could revitalize the Midwest. And the timing couldn’t be better.
The Inflation Reduction Act (IRA) is the biggest clean energy investment in American history, generating tremendous opportunity for pro-climate state officials to pass bolder policy and take advantage of billions of dollars in new federal investments in clean energy technologies.
Recent Energy Innovation Policy & Technology LLC and RMI modeling using the new state Energy Policy Simulators finds just five policies can effectively cut emissions in any state—even those with quite different greenhouse gas (GHG) emissions sources. The analysis also shows adopting strong climate policies would boost local economies, create jobs, and protect public health. The most impactful policies are: clean electricity standards, zero-emission vehicle standards, clean building equipment standards, industrial efficiency and emissions standards, and standards for methane detection, capture, and destruction.
In Minnesota, Michigan, and Wisconsin, adopting these five policies would help achieve climate targets and boost GDP, though the most impactful policies vary by state. By 2050, Minnesota’s GHG emissions could drop by 50% below 2005 levels, Michigan’s by 85%, and Wisconsin’s by 80%.
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In Minnesota, policymakers committed to climate action took office this January, resulting in passage of a new law requiring 100% carbon-free electricity by 2040. Thanks to recent coal power plant retirements, Minnesota was already on track to meet its GHG reduction goals for 2025. Now, a faster clean energy pace will help the state reach its goals of slashing emissions 80% below 2005 levels by 2050. However, the modeling shows the state will also need to tackle transportation, industry, and agriculture emissions.
Using the new Minnesota Energy Policy Simulator, Energy Innovation and RMI find adopting the top five policies would cut emissions in these sectors to achieve economy-wide reductions of 50% below 2005 levels by 2050 — major progress toward the state’s goal. These five policies would also stimulate Minnesota’s economy, adding more than 30,000 new jobs in 2030, 100,000 new jobs in 2050, and growing GDP 2.4% in 2050.
In 2020, transportation was the largest source of in-state emissions and industrial emissions are projected to rise through 2050. The modeling shows joining other states in following the new Advanced Clean Cars II standard (ACC II), requiring 100% of car and small truck sales to be zero-emission vehicles (ZEV) by 2035, and 100% of heavy-duty truck sales to be zero-emission by 2045, can eliminate the majority of transportation sector emissions by 2050.
Industrial emissions standards or an industrial carbon cap program would require industrial facilities to switch from fossil fuels to electricity, renewable biofuels, and hydrogen. Minnesota is already advancing projects to integrate cleaner fuels — Gov. Tim Walz proposed new funding for biofuel infrastructure in the state’s budget and a Minnesota utility is piloting a new program to use hydrogen fuel. Industrial emissions standards that shift 100% of fossil fuel use to a mix of electricity and hydrogen for low-temperature and medium- to high-temperature heat by 2050 could reduce industry emissions 75% in 2050, accounting for a quarter of the potential reductions of five policy package.
Our modeling did not address the large agricultural sector in the state, which contributes 19% of Minnesota’s emissions. But the state is exploring policies that can offset agricultural emissions. Well-designed land use policies, like wetland restoration or grassland management, can close the gap between the five-policy scenario and the 80% reduction goal.
Minnesota has made major progress. Capitalizing on the IRA by adopting additional policies can cement its leadership, create new clean energy jobs, and ensure the state reaches its 2050 goal.
Michigan is laying the foundation for bolder climate action. In her 2023 State of State address, Gov. Gretchen Whitmer pledged to make Michigan “a hub of clean energy production.” It’s already happening — Ford just announced plans to set up an electric vehicle (EV) battery manufacturing facility 100 miles west of Detroit.
Last year, the state released a new climate plan, outlining policies to reduce emissions 52% below 2005 levels by 2030 and reach carbon neutrality by 2050. Previous Michigan EPS analysis by 5Lakes Energy, the Michigan Environmental Council, NRDC, Energy Innovation, and RMI found the state’s climate plan would cut emissions 50% by 2030 — nearly reaching the state’s near-term goal.
Strong implementation of Michigan’s climate plan sets the stage for further climate progress to reach the 2050 net-zero target. The state’s plan includes key components of the five policies, but more ambition is needed. Adopting our five recommended policies would cut Michigan’s emissions 86% relative to 2005 levels by 2050. The five policies would also spur economic development as clean energy infrastructure is built out, creating more than 70,000 jobs in 2030 and 153,000 jobs in 2050, and growing GDP 2.67% by 2050.
An 80% by 2030 and 100% by 2035 clean electricity standard would cut emissions more quickly than the climate plan target of 60% renewables by 2030 — though this is a solid foundation. The clean electricity standard accounts for a whopping 67% of total emissions cuts achieved by the five-policy package in 2030. Michigan could also move to adopt ACC II and set ambitious ZEV standards. Though a strong ZEV standard would only account for 5% of total emissions cuts in 2030, it would grow to 25% in 2050 as more gas vehicles are replaced with EVs.
With new majorities in the Michigan legislature and IRA incentives for clean energy technologies across sectors, the state is well positioned to implement — and go beyond — the policies laid out in the climate plan.
In Wisconsin, Gov. Tony Evers and state offices have made plans to address climate change and move towards carbon-free electricity. In 2020, the Governor’s Task Force on Climate Change produced a detailed report on reducing statewide emissions and now is the time to execute. If adopted in Wisconsin, our top five policies would reduce emissions 80% below 2005 levels by 2050 and add 39,000 new jobs in 2030, add 82,000 jobs in 2050, and grow GDP 2.8% in 2050.
The most impactful policy for Wisconsin is a 100% clean electricity standard by 2035, which accounts for half of the five policies’ emission reductions. The clean electricity standard alone would cut emissions 40% in 2035. This one policy would also be an economic juggernaut, creating 14,000 new, in-state jobs in 2035 and saving residents money by deploying lower-cost clean electricity. A separate Energy Innovation report finds replacing Wisconsin’s aging coal plants with new regional wind energy would yield savings up to $290 million annually compared to running existing coal.
Wisconsin can take advantage of Gov. Evers’ climate leadership to realize new economic opportunities. Among these three Midwestern states, Wisconsin could see the greatest GDP growth by implementing the top five policies — an estimated 2.8% growth in 2050.
As our modeling demonstrates, just five climate policies would build on the progress these states have made to date, solidify Minnesota, Michigan, and Wisconsin’s leadership, and revitalize their economies. Now is the time to act on ambitious plans. The IRA dramatically lowers the cost of clean energy technologies and new climate momentum means these states are positioned to deliver — as demonstrated by Minnesota’s passing of 100% clean energy law.
Sharing best practices and building infrastructure across the region — such as EV charging networks and transmission lines — can amplify the actions of any one state alone. The collective action of these three states could revitalize America’s industrial heartland. It’s now up to Minnesota, Michigan, and Wisconsin to take advantage of this opportunity.
Rhode Island’s top utility regulator says a statewide moratorium on new gas hookups is on the table as the state works to meet its ambitious climate goals.
“That doesn’t mean it happens tomorrow,” said Ronald Gerwatowski, chair of the Rhode Island Public Utilities Commission, during a proceeding Thursday. “But it surely begs us all to ask the question: If not tomorrow, then when?”
Gerwatowski’s comments came as the commission held its first technical conference in its investigation into the future of natural gas.
A wide-ranging discussion followed about the many challenges and conundrums facing the commission in the so-called “Future of Gas” docket. Regulators opened the investigation in response to the passage of the state Act on Climate, which includes a mandate to zero out greenhouse gas emissions by 2050.
Building emissions, including those that result from the use of natural gas, account for about 35% of the state’s total emissions. The commission regulates the gas distribution system, which is operated by Rhode Island Energy.
The purpose of the first proceeding was “to prepare the commission to make big and ambitious decisions,” said commissioner Abigail Anthony.
The breadth of the challenge ahead was laid out by Rhode Island Energy executives, who provided a factual representation of the state’s gas distribution system. The company has more than 273,000 residential, commercial and industrial gas customers served by some 3,200 miles of gas distribution main, said Michele Leone, vice president of gas.
Through the company’s ongoing pipeline replacement program, 60 to 65 miles of gas main are replaced every year, she said. About half of the mains have been replaced with less leak-prone pipes so far.
Whether or not to continue that program is a particularly vexing question for the commission, Gerwatowski said. Replacing leak-prone pipes is both a safety issue and an environmental issue, he said. Right now, those infrastructure investments are factored into the rate base and are depreciated over 40 years, a timeline that is now far too long.
“We could depreciate it more quickly, but that has an impact on rates. So what do we do here?” Gerwatowski said. “Do we stop the program on the assumption we’re going to close the system down,” allowing for some continued methane leaks?
Or, he said, do they allow the program to continue, and then likely face lawsuits over who should be responsible for the stranded costs once the assets are no longer in use?
Ben Butterworth, director of climate, energy and equity analysis at the Acadia Center, said in response that the commission must prioritize safety above all else first, but could perhaps investigate ways to repair pipes rather than replace them. That would reduce costs and the time period over which the utility is spreading those costs.
“That’s why it’s essential to determine a plan as soon as possible for the future vision of the gas system,” Butterworth said. “It might make sense to do it on a case-by-case basis.”
When it comes to transitioning from the use of natural gas, the state will need to find pathways “that ensure safety and reliability, equity, and affordability,” said Dan Aas, director at E3, an energy consulting firm representing Rhode Island Energy.
He recommended a “portfolio-based” approach that might include a combination of air-source heat pumps, hybrid electrification, renewable natural gas, and geothermal.
He noted that in California, Pacific Gas and Electric is experimenting with targeted electrification, in which they target for electrification a small cluster of customers on a segment of the distribution system that is costly to maintain.
But the prospect of converting hundreds of thousands of residential customers to air-source heat pumps poses another daunting question, Gerwatowski said.
“There’s a huge upfront funding cost — where does the funding come from?” he said.
The commission also heard from speakers representing consumer perspectives. Chelsea Siefert, director of planning and development for the Quonset Development Corp., a 3,200-acre business park in North Kingstown with more than 220 companies, urged regulators to consider the impacts of phasing out natural gas on industrial manufacturers.
For example, she said, burning natural gas generates the high temperatures Toray Plastics requires to convert plastic pellets into plastic film. Toray employs about 600 people at its Quonset facility.
And Jennifer Wood, executive director of the Center for Justice, which represents low-income utility consumers, called on the commission to prioritize any electrification efforts in the neighborhoods that have been impacted by fossil-fuel pollution for generations due to redlining and other discriminatory lending practices.
In the city of Providence, those old redlined areas now coincide with areas with the highest poverty rates and incidences of childhood asthma, she said.
“The remedies for meeting the goals of the Act on Climate should be targeted to the neighborhoods that have been the most adversely impacted along the way,” Wood said.
As the next step in the process, the commission will issue an invitation for interested parties to apply to join a stakeholder committee. The committee’s first meeting will likely be next month, said Todd Bianco, chief economic and policy analyst. The overall goal is to have a report with recommendations to the commission by next spring, he said.
Vermont’s only natural gas company is exploring possible sites for its first fossil-fuel-free, networked geothermal project, a heating and cooling technology that could be a natural fit for a company already skilled at designing and constructing piping systems.
“It’s a near-perfect overlay of our current business model,” said Richard Donnelly, director of energy innovation at Vermont Gas Systems, which currently serves about 55,000 customers.
Legislation pending before the House Committee on Environment and Energy could help speed such geothermal innovation. The bill, still awaiting a number, directs the state Public Utility Commission to adopt rules for permitting thermal energy networks — underground loops of liquid-filled pipes that are heated or cooled by the earth and connected to multiple buildings.
It would authorize any entity, not just existing utilities, to operate geothermal networks as regulated utilities, enabling them to recover their costs through the rates paid by customers.
“An electric cooperative, a homeowners’ association, a municipality, a large fuel dealer — they could become utilities so they could access the capital needed and recover their costs over time,” said Debbie New, a community organizer who helped draft and is promoting the legislation.
Emissions from heating and cooling buildings represent about 34% of Vermont’s carbon dioxide emissions. The state must find ways to reduce those emissions in order to meet its climate goals, and geothermal could be a key part of the solution, advocates say.
A geothermal system — or ground-source heat pump — consists of an underground piping network and a connected heat pump inside the building. Powered by electricity, the pump moves heat from the pipes to warm the building in cold weather. In hot weather, it reverses the process and draws heat from the building into the ground.
The pipes are placed at a depth where the earth’s temperature is relatively constant, around 50 degrees in Vermont.
The systems have no visual impact because they are underground. The pumps are significantly more efficient than other forms of heating and cooling, “and if the electricity being used is renewable, you can envision a really, truly decarbonized future,” said Jake Marin, senior emerging technology and services manager at Efficiency Vermont.
The downside, however, is cost.
“Without question, geothermal is one of the most, if not the most, expensive options out there,” Marin said. “The big question mark is, can we do this at scale? The networked geothermal is an interesting take on this. If that cost can be sucked up into a utility model and amortized over time with the end users paying an access fee to spread that out, the speculation is that that may be a good answer for helping to scale geothermal.”
Donnelly said Vermont Gas has been trying to develop a business model around geothermal for the past two years, “primarily because it’s a unique way for the company to use its core functions and decarbonize.”
The company is currently considering the feasibility of installing its first networked system at a multifamily housing construction project that includes some affordable units. They are largely focused on new construction projects as possible testing grounds because it is easier to put in a system where the ground hasn’t been developed yet, Donnelly said.
Vermont Gas previously submitted a proposal to develop a geothermal project at one of the buildings at Rutland Regional Medical Center, a hospital in central Vermont. But that idea was rejected by regulators last year, largely because Rutland is out of the utility’s service territory.
That rejection “is one example of a need for clear statutory guidance to direct development of these types of decarbonized projects in the future,” said Dylan Giambatista, director of public affairs for Vermont Gas.
Another bill identified by legislative leaders as a major priority this session would also help advance geothermal. Senate Bill 5, the Affordable Heat Act, would require importers of fossil heating fuels to compensate for that pollution by delivering or paying for cleaner heating options. It designates geothermal as one of the technologies that would generate the necessary clean heat credits.
Utilities in New York and Massachusetts are also exploring geothermal technology. Legislation adopted last year in New York directs the state’s seven largest gas and electric utilities to develop at least one and as many as five pilot thermal energy network projects.
And in Massachusetts, Eversource has broken ground on a networked geothermal system in a neighborhood in Framingham. The system will serve around 40 homes, as well as part of a school, a firehouse, and a few businesses, said Audrey Schulman, co-founder and co-executive director of the Home Energy Efficiency Team, known as HEET, a Cambridge-based nonprofit that has been promoting the networked concept.
The Framingham installation should be active by this fall. A research team assembled by HEET is studying every aspect of the system along the way, and will make the data available in a public data bank, Schulman said.
The organization’s outreach efforts with gas utilities around the country have so far yielded a coalition of about a dozen of them, including Vermont Gas, that are actively discussing or installing networked geothermal, she said.
“We believe the fastest way forward for building electrification is for us to work with gas utilities,” she said. “They will otherwise have no business plan going forward.”
The future business plan for Vermont Gas does not envision a complete transition to geothermal, however. The company’s long-term decarbonization objectives also call for renewable natural gas, green hydrogen, and carbon capture technology for industrial users.
The networked geothermal bill previously included a provision calling for a prohibition on the extension of natural gas transmission lines into new service territories. But Vermont Gas did not support that provision — “as we seek to decarbonize, flexibility is going to be very important,” Giambatista said.
So sponsors made the geothermal provision a standalone bill, uniting the gas utility and climate advocates behind it.
Illinois business leaders and researchers are hoping to leverage hundreds of millions of federal dollars to develop a thriving “hydrogen economy.”
The vision involves using the state’s plentiful nuclear power and renewable energy to separate hydrogen from water, and then using the resulting fuel to power industrial processes and heavy-duty vehicles.
The Midwest Alliance for Clean Hydrogen, or MachH2, is among more than 30 contenders seeking funding from a $7 billion U.S. Department of Energy program to jumpstart six to 10 regional hydrogen hubs across the country. Each will be aimed at producing and distributing pure hydrogen that is thus far in short supply.
The coalition behind the Illinois bid includes universities, utilities, economic development agencies, manufacturers, Argonne National Laboratory, and power producers like Constellation Energy and Invenergy, which has launched its own pilot program producing hydrogen in Illinois.
Jon Horek, director of hydrogen project development for Invenergy, said the federal funding can hopefully help solve the “chicken-and-egg problem” of developing hydrogen “demand and supply at the same time — production and consumption at the same time.”
Hydrogen is the most abundant element in the universe, and some see it as key to a clean energy transition, capable of replacing fossil fuels in vehicles and industry. But just getting pure hydrogen to users and fueling stations is a challenge; hydrogen occurs only in tiny quantities naturally in its purified form.
Currently, most hydrogen used industrially is purified or produced on-site, and hydrogen fueling stations for transportation are not common. But backers of the hub hope to change that, with hydrogen producers and hydrogen pipelines connecting entities stretching from northern Wisconsin south through Illinois, Missouri and Kentucky, and east to Ohio and Michigan.
MachH2 was one of 33 proposals to receive official encouragement to move forward from the Department of Energy, out of 79 applications submitted. A final proposal is due in April. The program was created by the Infrastructure Investment Act.
Jay Walsh, vice president for economic development and innovation for the University of Illinois system, said the Midwest and Illinois especially are ideal locations for a hydrogen hub, given the robust transportation and manufacturing infrastructure and academic resources.
“There’s distribution infrastructure — we’re located at the crossroads of the U.S.,” Walsh said. “Transportation is an important sector to decarbonize, and we’re good at transportation: water, rail, air, and of course trucking. We have all of those components, and add on top of that the talent and ability to create the talent — the workforce development.”
Currently most of the hydrogen used in fuel cells or industry is created by splitting hydrogen in methane (CH4) away from the carbon, usually using steam — which creates carbon dioxide as a byproduct — or energy-intensive pyrolysis, which creates pure carbon.
A cleaner way to produce hydrogen is from water, with a process known as electrolysis. But that also takes electricity, which often means greenhouse gas emissions. Though the gas is clear, hydrogen is described with a rainbow of colors depending on its source and sustainability. Hydrogen obtained from water with renewable energy is often referred to as “green hydrogen,” and hydrogen obtained thanks to nuclear energy is known as “pink hydrogen.”
“Illinois has a larger percentage of its electricity from nuclear than any other state,” Walsh said. “We also expect to be using solar and wind power” to produce pure hydrogen, with renewables increasingly being installed in Illinois, mandated by 2021 legislation to totally decarbonize the electricity sector.
“What distinguishes this hub is all the power producers in it are carbon-free power producers,” said Horek, noting that other hub proposals would produce hydrogen powered by fossil fuels. “For every sector that’s decarbonizing, there’s probably some technology folks may think about” that could utilize hydrogen. “The point of the hub is to continue those conversations and build that uptake.”
Bioenergy company Marquis sees hydrogen as essential to decarbonizing aviation and shipping. The element is crucial for creating sustainable aviation biofuel from corn, woody waste or other biomass, explained Jennifer Aurandt-Pilgrim, Marquis’ director of innovation and market development.
“We take the hydrogen and ethanol and run it over a catalyst, that connects the hydrogen with the ethanol to make a long-chain hydrocarbon,” said Aurandt-Pilgrim. “We’re turning biofuels into alkanes — jet fuel. That is really driven by using that hydrogen to make those long-chain hydrocarbons.”
The company also plans to create “renewable” biodiesel at a sprawling new industrial site from which the fuel can be shipped around the world via railroads or the Illinois River, which leads to the Mississippi River and the Gulf of Mexico. A Department of Energy-funded hydrogen hub could help production scale and lower costs.
Marquis’ corn ethanol plant produces about 400 million gallons of ethanol per year, 1 million tons of high-protein animal feed, and about 1.2 million tons of biogenic carbon dioxide emissions. But some of that carbon dioxide, along with other carbon oxides near the Marquis industrial site, could be turned into more ethanol in a “fermentation” process pioneered in part by Argonne. Marquis is planning to partner with LanzaTech, another member of the MachH2 coalition, to use this process at their site.
“You increase the same kernel of corn’s yield by 50% with no more land use, because we’re bringing hydrogen in,” said LanzaTech vice president of government programs John Holladay.
Aurandt-Pilgrim said it will take time to scale the carbon dioxide-to-ethanol process up. In the meantime, Marquis is planning to sequester carbon dioxide from its ethanol production under the site of the 3,500-acre Marquis Industrial Complex. It also plans to sequester carbon dioxide at its facility in Wisconsin.
The Mt. Simon sandstone formation in Illinois is considered ideal for carbon sequestration, but the concept has had a rocky history in the state. Ambitious carbon sequestration plans at the Prairie State and FutureGen coal plants never materialized, and an ongoing proposal by the company Navigator to build a carbon dioxide pipeline and sequestration site in Illinois faces massive community opposition.
Aurandt-Pilgrim said that Marquis is in the process of obtaining needed permits from the EPA for sequestration, and since it is not piping the carbon dioxide offsite, the company doesn’t expect local opposition. The ability to sequester carbon is not essential to the sustainable aviation fuels plant and other hydrogen hub-related projects moving forward, she said.
Meanwhile, Holladay sees another way hydrogen can cut carbon emissions in local and global industries. LanzaTech makes technology to capture industrial carbon emissions — carbon monoxide and carbon dioxide — which makes the carbon available for everyday manufacturing uses.
“In other words, carbon dioxide is being transformed into essential materials made today from petroleum and natural gas,” Holladay said. “Hydrogen allows us to capture even more industrial carbon emissions, which will help our local industries be better stewards and more competitive in global markets. For example, our partners are making dresses, running shoes, bottles, and cleaning products that started as carbon emissions from steel production.”
Hydrogen-powered vehicles are not the central purpose of the federally funded hubs, but the production and distribution of pure hydrogen would enable fueling stations for vehicles, backers said.
A hydrogen fuel cell can power cars, trucks or other vehicles by basically separating the negatively charged electrons and positively charged protons in hydrogen to create an electrical current, with the only emissions being water vapor. The fuel cell essentially powers an electric vehicle that never needs to be plugged in, as long as the hydrogen fuel tank can be replenished.
That can be a big “if” given that little hydrogen fueling infrastructure exists today, and it’s hard to grasp an advantage over electric cars or buses, with the recent proliferation of electric charging stations. Total sales of hydrogen fuel cell vehicles number in the low thousands, almost half worldwide being in California, as of a 2017 study.
In 2016, Michigan Public Radio explored then-Energy Secretary Steven Chu’s statement that “four miracles” would be needed to make hydrogen fuel cell cars viable: cheaper fuel cells, cleanly produced hydrogen, lighter hydrogen storage tanks on vehicles, and, crucially, a hydrogen distribution network. “If you need four miracles, that’s unlikely. Saints only need three miracles,” Chu told MIT Technology Review.
Jamie Fox, a Chile-based principal analyst at Interact Analysis which has focused on the sector, said he doubts hydrogen fuel cell cars will ever catch on. “It’s too expensive, and it’s too late to catch up with battery electric,” he said.
But heavy vehicles that have trouble holding enough electricity in a battery could be prime candidates. A major goal of the proposed hub is helping to power industries and transport modes that are “not easily electrified,” as Walsh said, including aviation and heavy manufacturing.
Fox noted that early-stage hydrogen-fueled trains already exist in Germany, Japan and the United Kingdom, and they “might make sense somewhere where you can’t have an overhead line [for electricity] due to the terrain.” He noted that battery performance suffers in cold temperatures, perhaps opening another opportunity for hydrogen fuel cells that fare better comparatively.
Meanwhile, hydrogen can also be burned in an internal combustion engine similar to a gasoline or diesel engine, and conventional internal combustion engines can be converted to burn hydrogen. This reaction produces no carbon dioxide or public health-harming particulate matter, though it can produce nitrogen oxide. Hydrogen internal combustion engines have not been deployed widely, though some sports cars have used the technology and engine manufacturers like Cummins are increasingly considering it as a way to cut carbon emissions.
Interact Analysis reported that its research “shows that mass production of hydrogen ICE [internal combustion engine] vehicles is set to take off within the next 5 years. Currently, the TCO [total cost of ownership] is unfavorable compared to traditional ICE vehicles, but shipments will reach 58,000 by 2030” internationally.
Jim Nebergall, general manager of hydrogen engine business at Cummins, wrote that hydrogen internal combustion engines could be ideal for long-haul trucking and “harsh conditions,” while hydrogen fuel cells make more sense for lighter vehicles. He acknowledged that it’s “a running joke in the industry that hydrogen cars are always 10 years away,” but he wrote that interest in hydrogen internal combustion engines could drive the availability of hydrogen, boosting fuel cells’ prospects:
“As these commercial applications become mainstream, hydrogen fueling networks will appear to serve them. Conceivably, these limited networks could then be used by personal hydrogen cars. Hydrogen engines are just around the corner, so hydrogen cars may have a shot at revival within less than ten years after all.”
Meanwhile hydrogen gas stored under high pressure is explosive, a liability that may make its use less popular, especially for vehicles. But proponents are unfazed.
“There are safety issues with every energy source,” Walsh said, citing lithium-ion batteries that can catch on fire. “These can be handled correctly.”
Scientists and engineers can likely find new ways to pursue Chu’s “four miracles” and make hydrogen production more sustainable and less costly, and more available for everyday people. For example, Chinese researchers in 2021 announced that nanoporous cubic silicon carbide could be used to harness sunlight directly to make hydrogen gas from water.
Researchers at Pacific Northwest National Laboratory with partners recently announced their process to make pure hydrogen from methane without carbon dioxide emissions, using a catalyst to produce solid pure carbon and “blue hydrogen,” or hydrogen from natural gas with zero carbon emissions. Marquis is also planning to explore blue hydrogen production in the future, Aurandt-Pilgrim said.
“A lot of energy sources have had to go through a phase where there was an initial investment before that energy source became reasonable to use,” Walsh said. “We’ve had many decades of effort on producing batteries — lithium-ion battery work has been going on for literally decades. There is an imperative here; the imperative is we really need to have cleaner sources of energy.”
Meanwhile, he said the technology already exists to create a hydrogen-based energy economy in the Midwest, and MachH2’s hub would focus on tapping such existing knowledge and scaling up for economic benefit in the nearer term.
“This hub is not for fundamental research — the university research is in moving the technologies forward and then evaluating the technologies as they get deployed, making sure we have what we need,” Walsh said. “There is a transformation that’s going to be happening here. It’s probably less impactful immediately to most people in society because of the sectors we’re working in at first. But this will be happening and there will be job opportunities.”
This article was originally published on Jan. 31 by THE CITY. Sign up here to get the latest stories from THE CITY delivered to you each morning.
Public housing residents who traded their gas stoves for electric induction ones saw improved air quality compared with their neighbors, according to the new results of a pilot program across 20 apartments at a complex in The Bronx.
Run by the nonprofit WE ACT for Environmental Justice, in partnership with the New York City Housing Authority, the Association for Energy Efficiency, Columbia University Mailman School of Public Health and Berkeley Air Monitoring, the experiment involved switching out gas stoves for induction units in 10 apartments at 1417 Watson Avenue, as THE CITY reported last February.
After a 10-month run, the air quality in those households was compared to 10 apartments still using gas stoves.
The households with electric ovens showed a 35% decrease in daily concentrations of the pollutant nitrogen dioxide and a nearly 43% difference in daily concentrations of carbon monoxide, according to the study results released Tuesday.
The findings come on the heels of a national frenzy over possible federal regulations of gas stoves.
Shavon Marino, 34, received an induction stove at the start of the experiment and although she had to learn how to control the heat without knobs, she quickly grew to appreciate the oven. Marino said she was particularly impressed with how fast it cooked her food and the ease of cleaning the flat stovetop.
And as the mom of a 7-year-old, she didn’t take the air quality improvements for granted, either.
“It cooks better and just for the safety of my daughter, that’s why I like the stove,” Marino said. “As she gets older, I think this stove would be a great teaching tool for my daughter.”
Traditional indoor gas stoves burn methane, a planet-warming greenhouse gas more potent at trapping heat than carbon dioxide. But beyond the larger climate concerns, gas stoves can pose immediate health risks to people in a household.
Previous research has shown that the pollutants released when turning on a gas stove are associated with causing or worsening respiratory illnesses.
An alarming December 2022 study estimated that 18.8% of childhood asthma cases in New York might be prevented if households didn’t have gas stoves.
A Bloomberg News report following that study indicated that the head of the U.S. Consumer Product Safety Commission was considering banning gas stoves across the country — but the agency later said that they were only looking into slight regulation.
In the Bronx, in addition to continuous air monitoring, researchers measured pollutants while preparing a “standardized” meal of steamed broccoli, spaghetti with tomato sauce and chocolate chip cookies. They made the meal three times each in six households — two with gas stoves and two with induction.
The researchers found that, while cooking using a gas stove, nitrogen dioxide concentrations were nearly three times as much when using an induction stove. In fact, measurements of nitrogen dioxide concentrations in the kitchens with gas stoves reached levels above what the U.S. Environmental Protection Agency considers “unhealthy for sensitive groups.”
During the cooking tests, “an induction cooking household’s pollution didn’t change at all,” said Michael Johnson, technical director at the Berkeley Air Monitoring Group. “It’s another data point we’re seeing that reinforces this narrative that cooking with gas increases levels of NO2 [nitrogen dioxide] and other pollutants in your home to levels that are often unhealthy.”
Beyond stoves, other sources of pollutants like nearby gas boilers and cars also affected the levels of pollutants in the apartments studied, researchers said.
Misbath Daouda, a PhD candidate at Columbia University Mailman School of Public Health who worked on the study, noted the health benefits of overhauling an entire building’s worth of fossil fuel-powered appliances.
“The transition would need to not only focus on gas stoves as a single appliance, but look at other systems that need to be replaced or improved in those homes to improve air quality and also meet carbon emission reduction goals — and that would include heating systems,” Daouda said.
A full-building transition would greatly decrease the risk of fires and accidents from people using their gas stoves to heat their homes in the winter, she added. Newer electric stoves with batteries would still be usable if the power failed.
NYCHA is preparing to install heat pumps in all apartments in the 96-unit Bronx, as well as a new electrified hot water system.
“The collaboration with WE ACT has helped NYCHA steer its decarbonization commitments, recognizing the clear air quality benefits of electrified cooking,” said NYCHA spokesperson Nekoro Gomes. “We continue to strive for wider implementation of this technology and we are thrilled to see the residents of 1471 Watson enjoying their new induction stoves.”
Switching to electric appliances can raise some concerns about expensive utility bills. The researchers estimated that operating an induction stove would cost about $6 more per month on electricity bills. But households that only pay for cooking gas would see their gas bills zero out, allowing for a monthly cost saving of about $11, the study found.
“Everyone deserves to live in a healthy home, regardless of your income, and regardless of the kind of housing that you live in,” said Sonal Jessel, WE ACT’s director of policy. “It’s ultimately really important that we’re finding pathways to ensure that as we are transitioning, it’s affordable and attainable for all populations.”
Now that the pilot program is complete, residents in the 10 control apartments can have induction stoves installed.
“They were impatient to get them,” Daouda said with a laugh. And no one who received an induction stove as part of the program asked for their old gas stove back.
THE CITY is an independent, nonprofit news organization dedicated to hard-hitting reporting that serves the people of New York.
As Maine comes close to finalizing its roadmap for the development of offshore wind, a coalition of labor and environmental groups is asking the state to strengthen its commitment to supporting union jobs in the burgeoning industry.
A group of 12 environmental and labor organizations has sent a letter to the Maine Offshore Wind Roadmap Advisory Committee asking that the final plan, expected by early February, incorporate explicit language recommending the use of project labor agreements and labor peace agreements as the offshore wind sector develops in Maine. Many of the same advocates are supporting a bill, announced by Democratic state Sen. Mark Lawrence last month, that would require union labor agreements on offshore wind projects.
“Organized labor needs to be a crucial part of this investment,” said Kelt Wilska, energy justice manager for Maine Conservation Voters. “And we need to make sure working families, both coastal and inland, benefit from this.”
As states from New England down to North Carolina work on their own plans for implementing offshore wind projects, Maine is expected to be a major player in the growing industry. With strong, consistent winds, the Gulf of Maine is widely considered to be one of the most promising areas for offshore wind development.
Maine convened its Offshore Wind Roadmap Advisory Committee in July 2021 with the mission of creating an economic development plan for the fast-emerging industry. The panel — which includes 25 members representing state and municipal governments, private business, community and environmental nonprofits, and organized labor — released its draft plan in early December.
The document outlines strategies for investing in infrastructure and workforce development; reducing costs and increasing resilience through renewable power; advancing Maine-based innovation; and protecting and supporting the seafood industry, coastal communities and the ocean ecosystem. Labor and environmental groups have praised much of the plan, particularly its focus on comprehensive planning, workforce and supply chain investment, and environmental monitoring and mitigation.
The draft roadmap, however, mentions unions and organized labor just three times, and not with any detail — an omission that some find problematic. It is essential that offshore wind jobs offer fair wages and benefits, as well as industry training and plans for worker safety, said Francis Eanes, executive director of the Maine Labor Climate Council, one of the groups that signed on to the letter to the roadmap committee.
“All those things are most effectively accomplished when workers can come together with each other in the form of a union,” he said. “It’s not rocket science here.”
Specifically, the letter’s signatories would like to see the roadmap call for the use of project labor agreements and labor peace agreements. Project labor agreements are pre-hire collective bargaining agreements that set the terms and conditions for the temporary employment of workers on a given construction project. A labor peace agreement is an arrangement in which an employer agrees to remain neutral should its permanent workers choose to form or join a union.
Robust union participation is the best way to make sure the economic benefits of the offshore wind industry are shared with working families, supporters argue. And, they say, project labor and labor peace agreements are the best way to ensure union labor is used in the construction, operation, maintenance, and supply of offshore wind. But the current roadmap language doesn’t reflect this urgency, said Jason Shedlock, regional organizer with the Laborers’ International Union and president of the Maine State Building and Construction Trades Council.
Representatives from the state’s energy office declined to comment as the roadmap development process is still ongoing. However, documents distributed to participants in a January 18 meeting of the committee noted that, “This is an all hands on deck moment — labor will be key, as will other actors — we don’t want to send signals of people being excluded.” The materials also indicated that the committee would possibly add to the roadmap a description of project labor agreements as an example of the kind of arrangement the state is looking for, but without going so far as to recommend or mandate these agreements.
“There is more wiggle room than we’d like,” Shedlock said.
The roadmap is already informing offshore wind legislation: Lawrence’s bill was heavily influenced by the recommendations in the draft document. The bill goes further than the roadmap on labor as it requires project labor agreements, but has a long way to go to become law. Advocates want the roadmap to call for similarly strong measures.
Using non-union contractors would prevent Maine residents from taking full advantage of the opportunities provided by offshore wind, Shedlock said. To meet the needs of such large projects, smaller, non-union companies would inevitably need to bring in temporary, out-of-state workers — workers who would then head home, contributing little to Maine’s long-term economic development, he said. Unions, on the other hand, have the resources and structures in place to recruit and train a substantial in-state workforce, he said.
“These are the partnerships we have in place,” Shedlock said. “This is the capacity that we bring.”
Formal union agreements have emerged as a significant feature of offshore wind projects. In Massachusetts, in 2021, the Vineyard Wind project signed a project labor agreement committing to use exclusively union labor. In May 2022, major offshore wind developer Ørsted announced an agreement to use American union labor to build all of its U.S. wind projects.
It would be a mistake for Maine not to follow this precedent, especially given the pressing nature of the climate crisis, Shedlock said.
“For Maine to think that they can do it differently than everyone else is only going to waste time,” he said.
Though these commitments have been widely hailed, not everyone is sure they are good for equity and diversity. When Vineyard Wind announced its project labor agreement, for example, some workforce diversity advocates declared the commitment would work against the goals of nurturing diversity and inclusion in the industry. Organized labor has a history of racial exclusion, they noted, and the majority of small construction businesses owned by people of color are non-union and would therefore be shut out of opportunities.
Labor advocates in Maine acknowledge this history, but say they are working hard to build opportunities for a diverse range of Mainers. The Maine Labor Climate Council has partnered with the Maine AFL-CIO to create a pre-apprenticeship program that will actively seek out participants from underrepresented groups. The program will help recruit and prepare potential workers for taking on an apprenticeship in the trades by teaching them soft skills and familiarizing them with unions. To help potential students overcome barriers to participation, stipends will be available to help pay for child care or transportation.
“It’s a model that is a really successful approach for bringing people currently and historically underrepresented into the union apprenticeship programs that we know lead to high-quality, stable careers,” Eanes said.
Advocates will now have to wait to see what language is included in the final version of the roadmap. Regardless of what emerges, however, they are committed to pushing the state to commit to organized labor in the long run.
“We really have one opportunity to get this right,” Shedlock said. “If we don’t employ local labor with good, family-sustaining jobs, that’s an unforced error right from the beginning.”
A Minnesota gas utility says it is successfully blending “green” hydrogen into its natural gas pipeline system in one of the first such tests in the country.
Since last summer, CenterPoint Energy customers near downtown Minneapolis have been burning a bit of hydrogen alongside the usual mix of methane gas in their stoves and furnaces.
The utility completed a $2.5 million hydrogen production pilot facility last year and began injecting the carbon-free fuel into its system in small amounts in June. Hydrogen accounts for no more than 5% of the overall blend at any time.
“The good news is that this facility has integrated well with our distribution system,” CenterPoint spokesperson Ross Corson said of the facility’s first months of operation.
The pilot project is a chance for the utility to iron out operational challenges. It’s already made several adjustments, including changes to a water circulation system and the way in which it removes moisture before injecting the gas into its pipelines.
But even a technical success for the project is unlikely to resolve broader questions in Minnesota and beyond about the role of hydrogen in a clean energy economy. Some experts and climate advocates have argued that blending hydrogen into the natural gas system is an inefficient and expensive climate solution compared to switching to electric appliances, and that hydrogen should be reserved for industrial uses and other difficult-to-decarbonize sectors.
Most hydrogen today is produced from a chemical process involving fossil fuels that releases significant carbon emissions. “Green” hydrogen is produced by using electricity to split water molecules into hydrogen and oxygen. If done with renewable electricity it can be a zero-emission fuel source.
“The color wheel of hydrogen is complex and a little bit overwhelming, but green hydrogen, as long as it’s generated using renewable electricity, is the gold standard,” said Joe Dammel, buildings program manager for the St. Paul clean energy advocacy group Fresh Energy, which publishes the Energy News Network.
CenterPoint’s small plant sits on the site of a former coal gasification plant that began operating when CenterPoint was called the Minneapolis Gas Light Company. The company chose the site due to its central location in its pipeline system and the availability of space. The grounds now host the green hydrogen center and a parking lot for workers taking courses across the street at a CenterPoint training center.
John Heer, the utility’s director of gas storage and supply planning, oversees the facility. Making green hydrogen is not a huge technical feat and involves electrolysis, Heer said.
City water is purified before being piped into a 1-megawatt electrolyzer that processes two gallons a minute. The facility disperses oxygen through fans outside the plant. “We’re learning by doing,” Heer said. “We need to know how it works before we can scale it in a larger facility.”
The facility gets electricity from Xcel Energy’s grid and offsets its electricity use with wind energy renewable credits, also purchased from Xcel. Critics have disputed whether hydrogen facilities that use renewable energy indirectly through offsets should qualify as “green.”
Part of the pilot is determining how hydrogen changes the characteristics of natural gas in pipelines. Hydrogen is less dense than methane and only carries about one-third as much energy per cubic foot. The molecules are the smallest in the universe and can exacerbate pipeline cracks and cause embrittlement, increasing leakage and explosion risks above certain concentrations, according to the National Renewable Energy Laboratory.
In July, a California Public Utilities Commission study found that 5% blends of hydrogen and natural gas are safe but going above that amount could require modifications to stoves and water heaters. Moreover, since green hydrogen carries less energy content, more of it would be required to replace natural gas, the report said.
Even if produced from fully renewable sources, hydrogen is unlikely to replace natural gas for various reasons, Dammel said. The manufacturing process absorbs more energy than it produces, with roughly a 30% to 35% loss. Larger green hydrogen plants will need to compete for clean electricity at a time when demand for wind and solar power has skyrocketed.
“We think that just adding hydrogen to the distribution system to substitute for fossil gas has economic and technical limitations,” Dammel said. “It’s not going to be a 100% substitute for every molecule of fossil gas that’s right now in the system.”
To replace all the nation’s natural gas consumption with green hydrogen would be an enormous undertaking, demanding hundreds of billions of dollars in investment in renewable energy, electrolysis technology, pipeline infrastructure and storage.
Critics also say green hydrogen production requires much water, a potential problem in more arid regions than Minnesota. Yet one study and market data suggest that its manufacture consumes far less water than plants using coal, nuclear, natural gas, biomass or solar.
For now, clean energy advocates believe the best application for green hydrogen will be heavy-duty industrial applications where using electricity cannot cost-effectively replace natural gas, Dammel said.
The biggest hydrogen markets currently are petroleum refiners, fertilizer companies, food processors and metals treatment firms. Hydrogen’s advocates, however, believe that in addition to manufacturing it can revolutionize the transportation sector.
Hydrogen is expected to get a boost in 2023 from the federal government. The Infrastructure Investment and Jobs Act, signed in 2021, includes $9.5 billion in incentives for clean hydrogen. The Department of Energy’s Hydrogen Shot program has set a goal of reducing the cost of 1 kilogram of hydrogen to $1 in one decade.
In September, the Energy Department released a 112-page clean hydrogen roadmap that calls for funding regional hydrogen hubs, support for manufacturing plants, and research into reducing the cost of electrolysis.
The Inflation Reduction Act includes a tax credit for green hydrogen that will soon provide up to $3 a kilogram credit for producers. The U.S. Treasury Department is expected to decide soon what criteria need to be met, with some environmental groups lobbying for on-site renewable generation to be a requirement.
“It costs more to produce hydrogen than to use natural gas today, so $3 a kilogram is kind of a big deal,” said Heer, the utility spokesperson. CenterPoint also wants to build a larger, second hydrogen plant but the timing on that has yet to be determined. The pilot is expected to avoid 1,200 tons of carbon emissions annually.
Virginia’s participation in an East Coast greenhouse gas emissions pact is pivotal to curbing the climate impact of its thriving data center industry.
Globally, northern Virginia has become one of the largest data center hubs over the last decade-plus. Offering generous tax incentives has attracted tech giants eager to construct massive server farms with proximity to crucial digital infrastructure. An estimated 70% of the world’s internet traffic moves through the suburbs of Washington, D.C., daily.
That burgeoning has propelled a surge in electricity use. In 2020, the sector consumed close to 12,000 gigawatt-hours in Dominion Energy’s territory — roughly one-sixth of the investor-owned utility’s total retail sales that same year.
And yet, the state’s carbon emissions from power plants have fallen 12% annually during the last two years.
William Shobe, an environmental policy professor at the University of Virginia, is among those crediting the 11-state Regional Greenhouse Gas Initiative. Known as RGGI, the initiative is a voluntary carbon cap-and-invest venture designed to tamp down heat-trapping gases emitted by the utility sector. Virginia’s downward emissions trend will halt without that cap in place, Shobe said.
Even as electricity-hungry data centers multiply across the state, RGGI’s binding carbon cap keeps emissions in check. Basically, the amount of fossil fuels a utility is allowed to burn shrinks each year as the cap is lowered.
It’s a crucial dynamic to understand, Shobe said, as Republican Gov. Glenn Youngkin has vowed to extract Virginia from the market-based climate initiative.
“As a planetary citizen, I’m happy with that [cap],” said Shobe, who directs the Energy Transition Initiative at the University of Virginia’s Weldon Cooper Center for Public Service. “If the state relaxes RGGI, then data centers have climate consequences that we need to worry about.”
He’s hopeful that legislators won’t follow Youngkin’s lead on RGGI during the session that opened last Wednesday. Republicans control the House of Delegates while Democrats have a majority in the Senate.
Shobe also argues that continuing to build data centers in Virginia can be a net positive for climate change — assuming data centers will be built somewhere and the state stays committed to the regional greenhouse gas program. That construction trend shows no signs of abating in Virginia for at least the next 10 years.
“As long as we are a member of RGGI, then we should encourage data centers here rather than Ohio, Indiana or someplace else without a cap on carbon dioxide emissions,” Shobe said.
Shobe played a significant role in designing the mechanisms behind RGGI, which debuted in 2009. In a nutshell, each member state limits emissions from fossil fuel power plants, issues carbon dioxide allowances and sets up participation in auctions for those allowances.
In 2020, Virginia became the first Southern state to join RGGI, after ample back-and-forth bickering. Advocates have hailed the program for its climate benefits and the upward of $450 million the allowance auction has so far yielded for statewide flood resiliency projects, energy efficiency upgrades, and home repairs for low-income residents statewide.
Youngkin has been itching to extract Virginia from RGGI since he took office a year ago. In early December, the state’s Air Pollution Control Board voted 4-1 to accelerate that exit.
Attorneys with environmental organizations maintain that the Youngkin administration lacks the authority to leave the compact. That decision, RGGI proponents say, is in the hands of the General Assembly. A legislative effort to derail RGGI failed last year.
The air board’s initial vote to leave RGGI will trigger a 60-day comment period this winter. Shobe and his colleagues are prepared to weigh in with insights that the board will review before voting again on the proposal.
Shobe published an electricity use forecast in April 2021 predicting that data centers will be the driving force behind a 38% increase in electricity sales between 2020 and 2035. That equals an average increase in electricity use of around 44,000 gigawatt-hours per year.
“Whether we think this is a good thing or not, data centers are growing very fast,” Shobe said. “Unfortunately, they use a lot of energy. How we provide that energy is what will make a difference.”
Shobe noted that residential electricity sales are close to flatlining due to slower population growth and improved energy efficiency. Likewise, commercial and industrial demand have fallen for several years.
For the most part, large technology companies have pledged to power their facilities with renewable energy. However, it’s unclear whether or how they are following through on those commitments.
Thus far, Virginia’s solar expansion is on pace with a legislative mandate to decarbonize the grid by 2050, Shobe said. But the state can’t afford a solar stumble if it’s going to feed the needs of voracious data centers.
Some in the environmental community doubt that server farms will be able to live up to their vows to harness 100% of their energy from clean sources. Rooftop solar can’t cover those needs because the average solar array on a data center would only offset about 2.2% of its annual electricity consumption, according to calculations by solar developers.
That means operators resort to power purchase agreements, which allow them to go solar even if the utility-scale arrays they invest in are located miles away or in other states and might not be generating when data centers are consuming power.
Some are leery of those pacts. But Shobe defends the agreements as “perfectly fine ways” to contain greenhouse gases.
“If a data center has a solar farm built somewhere else to cover emissions, why wouldn’t you want to credit them for that?” he said, adding that his university does just that with two off-campus arrays. “From the point of view of resolving global warming, it doesn’t matter where it is built.
“As long as it’s on the same planet, it has the same effect on emissions.”
Shobe suggested that in the big picture, a third-party monitoring organization — along the lines of a Good Housekeeping seal of approval — should be tasked with holding data centers accountable for clean energy pledges.
“Enforcement is a tricky problem,” he said. “What it boils down to is, are people holding true to their promises?”
Boosting in-state solar capacity is far preferable to importing electricity because that might be sourced from states without a carbon emissions cap, Shobe said.
“The question is how fast we can add renewable energy,” especially over the next five or six years, he said. “We are going to have to be more aggressive and do it faster if we are going to be a center for data center construction.”
In the meantime, the air board’s vote and the start of Virginia’s new, two-month legislative session has ushered in fresh fears that the state’s progress could be stymied. Shobe said he and other RGGI champions will meet with lawmakers to tout the climate value of sticking with the cap-and-invest program.
Withdrawing from RGGI would halt the flow of auction allowances. Instead, in mid-December, Youngkin proposed replacing that with $200 million in taxpayer dollars dedicated to a Resilient Virginia Revolving Fund.
That shift away from the RGGI model signals a lack of commitment to tackling climate change, Shobe said, because it removes not only environmental certainty but also the incentive for utilities to pivot from high- to low-emitting generation.
In Virginia, he emphasized, the original reason for joining RGGI was about having a cost-effective tool for reducing emissions. Producing revenue was an afterthought.
“If what the governor is hoping is that we will give up on achieving carbon dioxide reductions, that’s another matter,” Shobe said. “If we’re serious about reducing carbon emissions, we need to be thinking ahead and asking ourselves what our energy portfolio is going to look like.”
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