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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.”
Taking its cues from a successful program in Connecticut, Rhode Island is poised to launch a new initiative to deploy solar and reduce electricity costs in homes owned by low- to moderate-income residents.
The Rhode Island Commerce Corporation recently issued a request for proposals from solar companies interested in partnering on the initiative, called Affordable Solar Access Pathways. The program will offer affordable leases for solar equipment on homes owned by residents with incomes less than or equal to 80% of the area median income. That’s a maximum of $65,460 annually for a family of four, or $44,512 for a two-person household.
“There will be no money down and net savings from day one,” said Vero Bourg-Meyer, project director at the Clean Energy States Alliance, or CESA, which collaborated with the Commerce Corporation to develop the program.
The homes must be located in environmental justice areas, as defined by the state Department of Environmental Management. Those areas are primarily in and around the cities of Providence, Pawtucket, Woonsocket and Newport.
That will enable the program to take advantage of the new environmental justice adders to the Investment Tax Credit passed as part of the Inflation Reduction Act. Those adders will allow solar system owners to qualify for a higher tax credit when homes are located in census tracts designated as environmental focus areas, Bourg-Meyer said.
CESA has been working to persuade states to develop more-inclusive solar programs by promoting Connecticut’s Solar for All program as a model. Under that program, the Connecticut Green Bank paid incentives to a solar company, Posigen, which was then able to offer a reduced price to customers for a 20-year rooftop solar lease.
The program helped drive a 185% increase in solar in low- to moderate-income communities in Connecticut between 2015 and 2018, according to a 2020 white paper.
Third-party ownership of the solar equipment was a critical aspect of that program’s success, Bourg-Meyer said, since lower-income customers are less likely to be able to obtain or afford financing.
Another key aspect was the program’s community-based marketing — “having neighbors speak to other neighbors about it,” she said.
Rhode Island’s program will be administered through the commerce agency’s Renewable Energy Fund, which will provide an initial $1 million in funding, in collaboration with the state Office of Energy Resources.
It’s not clear how many homes that $1 million will cover, as it will depend on how the program’s solar partner designs its program and incentives, said Shauna Beland, administrator of renewable energy programs at the energy office.
“The more creative they get the better,” she said.
There are no funds available to help out homeowners who need roof repairs in order to accommodate solar panels. But it’s possible that the solar installer will work with a roofing contractor and wrap those costs into the lease, something that is fairly common in Rhode Island, said Karen Stewart, manager of the Renewable Energy Fund.
The program should launch this spring.
Hawaii launched a solar program for low- to moderate-income homeowners last year, and Virginia is working on it, Bourg-Meyer said, adding, “it’s something that’s percolating across the country.”
Numerous studies have found widespread inequities in solar adoption across the country. However, a 2020 report from Lawrence Berkeley National Laboratory concluded that those disparities are gradually diminishing, with several states, including Connecticut, even demonstrating income parity between solar adopters and the broader population.
Massachusetts climate advocates say a clean heat standard proposed by state officials could fail to create meaningful progress toward decarbonization if it overvalues alternative fuels and doesn’t prioritize equity.
“The devil is in the details,” said Amy Boyd, vice president of climate and clean energy policy at the nonprofit Acadia Center, one of several environmental groups closely following the developing state policy.
In January 2022, then-Gov. Charlie Baker convened a Clean Heat Commission to develop strategies for decarbonizing the state’s building sector, which accounts for about 40% of its total emissions. Among its final recommendations released in November was the adoption of a clean heat performance standard.
The policy would create a system similar to a renewable portfolio standard but for heat instead of electricity. Heating fuel suppliers would be required to contribute to clean heat projects, likely by buying credits generated from activities such as heat pump installations and weatherization improvements. Over time, the amount of clean heat credits required would increase.
Other strategies recommended by the commission include reforms to state energy efficiency programs, establishing a climate bank to finance heat pump installations and weatherization projects, and scaling up workforce training to ensure there are enough contractors to perform the work.
As Massachusetts pursues its target of going carbon-neutral by 2050, buildings will be a major challenge. As of 2020, more than 80% of the state’s homes were heated primarily by fossil fuels. Switching to electric space and water heating would allow them to be warmed by electricity that includes an ever-increasing proportion of wind, solar, hydro and other renewable power.
While environmental advocates have praised most of the plans laid out in the Clean Heat Commission report, they are approaching the clean heat standard with more of a cautious optimism. Most believe the standard is inevitable, but are paying close attention to the details.
“The Clean Heat Standard is unavoidable in some form,” said Larry Chretien, executive director of the Green Energy Consumers Alliance. “We want to make sure that we put disadvantaged folks at the front of the line, and we want to make sure it is legit clean heat.”
In December, the state released its Clean Energy and Climate Plan for 2050, which confirms the current administration’s vision for developing a clean heat standard, setting a target date of implementation by early 2024. Governor-elect Maura Healey is widely viewed as a clean energy champion, but it still remains to be seen how she will develop and build on her predecessor’s work.
Advocates agree that, as the program develops, it will be essential to pay attention to what, precisely, counts as clean heat. Electric heat pumps will be central to any strategy, but it is almost certain that alternative fuels will also be proposed as qualifying for clean heat credits.
Major gas utility National Grid, for example, has declared its intention to replace the fossil natural gas it currently delivers with renewable natural gas and green hydrogen by 2050. Renewable natural gas is derived from natural sources, such as composted animal manure or food waste, and the production process may recapture some greenhouse gases before they are released into the atmosphere.
However, its full lifecycle carbon emissions are highly variable and may or may not be lower than those of conventional natural gas. Further, renewable natural gas is chemically identical to fossil natural gas, so it still releases carbon dioxide when burned, leaks from pipes into the atmosphere, and carries health risks when used indoors.
Also, a recent study commissioned by California regulators found that hydrogen concentrations above 5% in the natural gas system can damage pipes and require appliances to be modified.
National Grid has confirmed its view that renewable natural gas and green hydrogen should be part of a clean heat standard, arguing that electricity alone will not be enough to decarbonize heating systems in a region that experiences as much cold weather as New England.
“As suggested in the recent Clean Heat Commission report, low-carbon fuels provide an opportunity to reduce emissions, which supports our shared decarbonization, climate action and environmental justice goals,” the utility said in a statement.
However, any clean heat credit that is given to these fuels should depend on a rigorous analysis of lifecycle emissions, said Caitlin Peale Sloan, vice president for Massachusetts at the Conservation Law Foundation. Giving too much weight to alternative fuels could slow down the needed transition to electrification, she said.
“The way they count emissions from alternative fuels — that’s going to be the ballgame in many respects,” she said. “The longer you push off the switch to electrification, the more expensive it’s going to be and the harder it’s going to be.”
Advocates also argue that running new fuels through old pipes is mostly a way for utilities to keep their distribution business afloat as the region transitions away from fossil fuels and will only slow the pace of needed carbon reductions.
“That’s going to continue to be a difficult dialogue, because of the gas companies facing the threat of stranded assets,” said Matt Rusteika, director of market transformation at the Building Decarbonization Coalition.
Another major concern is equity. Lower-income residents are more likely to live in some of the state’s oldest and draftiest buildings, while, at the same time, having less money and power to weatherize their homes and upgrade their heating systems.
“Centering equity and engagement — it doesn’t get into a whole lot of detail as to how to do that, but keeping that as a tentpole of all of our decisions going forward is crucial,” said Boyd, of the Acadia Center.
A clean heat standard can generate more revenue to tackle this problem, advocates said, but the state will need to shift some policies and priorities to use the money to the best advantage. Boyd pointed to existing rules in state efficiency programs that won’t provide services to homes that have mold or outdated knob-and-tube wiring systems. The system offers some money to help with these fixes, but the reality is that few property owners go through the full process of making the repairs and pursuing weatherization and electrification.
“So now not only is the tenant stuck with mold that the landlord won’t fix, they don’t get weatherization and still have to breathe in gas fumes,” Boyd said.
To create an equitable system, it would be important to channel money from a clean heat standard into programs to upgrade and repair these homes, she said.
A study by the Regulatory Assistance Project, prepared as part of the development of the 2022 Massachusetts Clean Energy and Climate Plan, suggests other ways a clean heat standard could promote environmental justice. The standard could include a carve-out requiring that an increasing percentage of clean heat credits come from projects serving low- and moderate-income homes, for example. Or the parties required to meet the clean heat standard could receive bonus credits for reaching a certain threshold of credits from projects supporting disadvantaged residents.
Though the proposed details are yet to be rolled out, it will be vital for any clean heat standard to be coupled with complementary programs and incentives to make a decisive move away from fossil fuels, advocates agreed.
“The clean heat standard alone is not a silver bullet,” Boyd said. “It still needs to be combined with a clear plan for pruning the gas system.”
When the Crawford coal plant in Chicago’s Little Village neighborhood closed in 2012, residents hailed it as a victory for public health and environmental justice. But now a Target warehouse sits in place of the coal plant, with a constant stream of diesel trucks posing a new health threat and source of greenhouse gas emissions.
The neighborhood is just one example, local leaders and statewide advocates say, of why Illinois should adopt rules and programs moving toward electrification of medium- and heavy-duty trucks — starting with the Advanced Clean Trucks rule pioneered by California and now on the books in seven coastal states.
“Because of past decisions going back 170 years, we are without a doubt the freight and rail hub of North America — these freight facilities aren’t going anywhere,” said José Acosta, senior transportation policy analyst for the Little Village Environmental Justice Organization. LVEJO led the fight to close the city’s two coal plants and fought against the construction of the warehouse on the coal plant site.
“If that’s the case, how do we mitigate all the impacts of it?” Acosta added. “The most pressing impact is the air pollution impact, the threat of PM2.5” — fine particulate matter — “nitrogen oxide and other things that have an impact on community health. That’s why it’s so important to electrify fleets.”
LVEJO is among the coalition of environmental, community and labor groups called NET-Z demanding the state adopt the Advanced Clean Trucks rule, or ACT. The rule would mandate that electric or hydrogen fuel cell vehicles make up an increasing percentage of heavy- and medium-duty trucks sold in the state. With different benchmarks for different types of vehicles, the rule would mean almost all new trucks and delivery vans would be zero-emissions by 2040. Given fleet turnover, experts estimate this means almost all trucks on the roads would be zero-emissions by 2050.
The coalition is also calling for the adoption of the Heavy-Duty Omnibus Rule, which would mandate stricter nitrogen oxide emissions controls on new fossil fuel trucks. Meanwhile, a bill introduced in the state legislature would ask the Illinois Environmental Protection Agency to offer $200,000 vouchers for the purchase of class 7 or 8 large trucks, provided a diesel truck is scrapped in return.
“It is not like all the trucks sold have to be electric” immediately under the Advanced Clean Trucks rule, noted Illinois clean energy advocate J.C. Kibbey of the Natural Resources Defense Council. “It’s a very gradual ramp,” and the omnibus emissions reduction rule could be “the peanut butter to the ACT’s jelly,” reducing emissions from fossil fuel trucks as the transition to zero emissions plays out.
In May, the Respiratory Health Association published a study showing that Illinois ranks fifth of all states in the number of deaths per capita attributed to diesel pollution. And 12 Illinois counties, most of them in the Chicago area, are among the top 9% of counties nationwide for exposure to fine particulate matter from diesel.
“People are getting sick and dying from what they’re breathing from the tailpipes,” said Brian Urbaszewski, environmental health programs director for the Respiratory Health Association. “And global warming is happening — when you look at who gets hurt most or first by those increasing extreme weather events, it’s going to disproportionately hit those lower-income vulnerable communities.”
Cleaning up trucks is also an environmental justice issue for workers in warehouses and other sites with heavy truck traffic. Warehouse Workers for Justice, an organization that has long fought for better conditions for workers in Chicago-area warehouses, is a leader of the NET-Z coalition.
So far coastal states — California, Washington, Oregon, New York, New Jersey, Massachusetts and North Carolina — have adopted the Advanced Clean Trucks rule, and 10 other states have signed memoranda of understanding agreeing to similar provisions. Illinois could be the first Midwest state to adopt the measure.
A study commissioned by the Natural Resources Defense Council and Union of Concerned Scientists found that medium- and heavy-duty vehicles make up only 7% of the vehicles on the road in Illinois, but account for more than a third of their greenhouse gas emissions and about two-thirds of nitrogen oxide and fine particulate matter (PM2.5) emissions.
The NRDC-UCS study used modeling to estimate that the least aggressive of three possible scenarios — the adoption of California’s Advanced Clean Trucks rule — would result in “up to 310 fewer premature deaths and 347 fewer hospital visits from breathing polluted air.” The study also found massive fuel savings to vehicle fleets and savings to electric customers, since the increased electricity sales for vehicle charging could help utilities lower residential rates. “Under the ACT scenario, by 2050 annual cost savings for Illinois fleets are estimated to be $1.2 billion, and annual bill savings for electric utility customers in the state could reach an estimated $62 million,” the study found.
Modeling also looked at the adoption of the emissions-reducing omnibus rule along with the ACT rule, and at a most-aggressive scenario that would see almost all new trucks being zero-emissions by 2040. Those scenarios yielded greater health and economic benefits than the ACT rule alone.
The study noted that there are currently more than 615,000 medium- and heavy-duty vehicles on the road in Illinois, ranging from heavy-duty pickups and vans to semi-trailers. The rules would cover only new vehicles, and only vehicles sold by manufacturers in Illinois, not those purchased out of state.
Kibbey explained that the ACT rule would be enforced through a system of credits: “The standard is implemented as a percentage of total truck sales per manufacturer in the state. They can buy, trade, and store credits. In addition to the manufacturers’ ability to price and market trucks in ways that increase sales, the crediting system allows for a lot of compliance flexibility. If a manufacturer doesn’t fulfill its credit deficit in a given year, they incur a financial penalty based on the class of vehicle, and the deficit rolls over to the next year. If they don’t address the deficit, they will continue to incur penalties.”
The NRDC-UCS study notes that a higher proportion of components for zero-emissions vehicles are manufactured out of the country and must be imported. The net macroeconomic benefits of a national transition to zero-emissions vehicles, therefore, depend on the extent to which the U.S. ramps up manufacturing of such components. This sector holds potential especially for states with a rich industrial history and infrastructure like Illinois, advocates say.
“This is such an opportunity for us, this is not a hair shirt,” Kibbey said. “This is an opportunity not only to add jobs in the clean transportation sector … but to be the best state in the country to drive and manufacture an electric vehicle. If we want to build them here, let’s create a market for them here.”
Last year the electric truck manufacturer Rivian opened a factory in Normal, Illinois, in a shuttered Mitsubishi factory. Rivian’s R1T electric truck produced in Normal was voted the state’s “coolest” product made in Illinois in a contest hosted by the governor’s office this year. As Capitol News Illinois wrote, the R1T is the “first electric truck in production that features four motors, eight driving modes and up to 400 miles of range on a single charge, combining off-road capabilities with the driving style of a sports car.”
The Canadian electric bus and truck manufacturer Lion Electric also has a factory in Joliet, the Chicago-area city that is also home to one of the nation’s largest warehousing hubs. This fall, the company produced its first electric school bus in the Joliet factory.
Buses would be covered by mandates in the Advanced Clean Truck rule. Meanwhile, funding from the Inflation Reduction Act and various other incentives exist for electric buses, including funds from the Volkswagen lawsuit settlement that Illinois has earmarked for electric school buses.
“We’re making [electric trucks] in Illinois,” Urbaszewski said. “The problem is we’re not providing the environment to make sure they stay here and drive on Illinois roads, providing the pollution reduction and health benefits.”
The electrification of transportation in Illinois is especially appropriate given that the state’s energy law passed last year mandates the electricity generation sector phase out fossil fuels by 2045, meaning electric vehicles would be charged with clean power.
“We’re not just going to be moving emissions around to a natural gas or coal plant that will make electricity to run an electric truck — we’re reducing in a real sense,” Urbaszewski said. “Pushing electric vehicles makes sense because it gives you added benefits to what we’re doing in the power sector.”
Illinois’ investor-owned utilities ComEd and Ameren are launching beneficial electrification plans mandated by the state’s 2021 Climate and Equitable Jobs Act, investing hundreds of millions in electric vehicle incentives and charging infrastructure. And the Inflation Reduction Act provides tax credits of up to $40,000 for commercial electric vehicle purchases and up to $100,000 for electric vehicle charging infrastructure.
The NRDC-UCS report noted that the Advanced Clean Trucks rule could mean that total electricity demand in the state increases by 1.3 million megawatt-hours in 2030 and 12.7 million MWh by 2050, an estimated total of 1.3% and 12.9% of Illinois’ electric load in those years. (The study notes that “current annual electricity sales to residential and commercial customers in Illinois total 74.2 million MWh and are projected to grow to 83.8 million MWh in 2050.”)
But that new demand would be met with clean energy and by charging vehicles at night when demand is otherwise low, advocates say.
“As long as you have the rate structures in place, the infrastructure in place, it shouldn’t put much strain on the grid,” Kibbey said. “Since the grid isn’t used that efficiently, we build it bigger than we need for most of the time. In Illinois at night, we have a bunch of nuclear energy, a bunch of wind energy” that’s not needed. “If you are charging [electric vehicles] off-peak, it not only avoids creating problems with the grid, but we end up using the grid more efficiently.”
Despite continuing a lawsuit over the state’s clean car standards, the Minnesota Automobile Dealers Association recently hired an electric vehicle program director.
The organization believes it is the first dealer association in the country to add a staff member assigned explicitly to electric vehicle issues. Its vice president of public affairs, Amber Backhaus, said the position developed over the past two years as demands by dealers for expertise and information on electric vehicles grew.
Backhaus said the dealer association does not agree with “supply side mandates,” but does not see that as contradictory to preparing for the market shift that is already well underway.
“Electric vehicles are the wave of the future and our dealers are excited to sell them, but there are a lot of things they need to do to prepare to be able to sell them,” she said. “We get a lot of questions from dealers and we thought it would make sense to bring somebody in-house who could put together those resources and answer their frequently asked questions.”
The association selected Steve Nesbit, a former executive who oversaw electric vehicles and renewable energy programs at an electric cooperative and worked at an auto dealership. Nesbit said he sees his role as helping dealers “support the sale of electric vehicles and keep their business model operating.”
Nesbit worked for Wright-Hennepin Cooperative Electric Association for 12 years, focusing on renewable energy and community solar for part of his time there. Before taking the association job, he worked for an energy technology company and an auto dealer.
The association has been a long-term member of Drive Electric Minnesota, an initiative of the Great Plains Institute. M. Moaz Uddin, a policy specialist at the institute, said the addition of Nesbit will help “bridge the gaps between dealerships and utilities” and make for a smoother transition to vehicle electrification.
While electric vehicles will play a crucial role in decarbonizing transportation, they will not be the only solution. Minnesota needs to continue efforts to create low-carbon fuels and communities where residents can walk or use transit, bicycles and other transportation modes instead of cars, Uddin said.
Nesbit starts his role as the association continues fighting the state’s clean cars standards in a case heard in November at the Minnesota Court of Appeals. Last year, Minnesota adopted the clean cars standards developed by the California Air Resources Board, a move requiring dealers to make more electric vehicles available starting in 2024. The Minnesota Pollution Control Agency oversees the new rule.
Auto dealers and Republicans have criticized the Walz administration’s embrace of the California model. The federal government only permits California to have its own auto emission regulations. However, it allows other states to follow the Golden State’s rules or those of the U.S. Environmental Protection Agency.
More than a dozen states have embraced the tougher rules, but California’s decision to ban the sale of internal combustion engine vehicles in 2035 has left several states, including Minnesota, debating whether to return to the federal standard. Backhaus expects the appeals court to release a decision early next year, which comes after the association lost an earlier challenge in federal court last year.
Fresh Energy, which publishes the Energy News Network, is one of six organizations that have signed on to a brief of amici curiae in support of the tougher standards. Fresh Energy policy staff do not have access to the Energy News Network’s editorial process.
Both Backhaus and Nesbit say the lawsuit does not diminish the association’s embrace of electric vehicles nor its desire to help members overcome challenges. Dealers may not like the speed of the transition, Nesbit said, but they understand the need to educate sales and service staff on the new technology.
They must learn how to speak to consumers about the strengths and weaknesses of electric vehicles in weather conditions in Minnesota, such as brutally cold winters that can diminish battery charges quickly, he said.
Backhaus said automobile manufacturers have begun requiring dealers to have chargers onsite and new equipment in repair shops. Dealers will need new lifts — because electric vehicles weigh more than internal combustion vehicles — and a retraining program for their mechanics. Ford recently announced new requirements could cost individual dealerships $1.2 million in upgrades, she said.
Minnesota dealers work with 65 different investor-owned, cooperative and municipal-owned utilities, Backhaus said. Some utilities, especially those owned by municipalities, have little experience with electric vehicles or chargers. Auto sellers will need onsite chargers, as will their clients.
“Hopefully, we can also educate utilities serving our dealers, so this is a smooth transition,” Backhaus said.
Tom Leonard, incoming chair of the association and president of Fury Motors in the Twin Cities, has become a big fan of electric vehicles and of the association adding a staff expert devoted to training, education and advocacy. The lawsuit, he conceded, may have led Minnesotans to believe dealers don’t want to sell electric vehicles.
“That’s a massive misperception that has been maybe played more in the media than in the car dealership world,” he said. “Car dealers are very pro-electric vehicles, zero-emission vehicles. We don’t want to be behind what’s coming at us.”
Leonard said he will have to upgrade his dealership, which sells Chrysler, Jeep and Dodge vehicles. The association has been working with manufacturers about how infrastructure charging investments work in Minnesota, for example by pointing out that state funding requires the public to have access to the equipment. Many dealerships must start installing chargers and new equipment early next year to meet 2023 car company deadlines, he said.
Backhaus said auto manufacturers have not yet created programs to help dealers pay for upgrades. The association plans to look for funding for members through federal and state sources. The Inflation Reduction Act offers a 30% tax credit from charger installations, but some of the other initiatives come with “a lot of red tape,” she said.
The association plans to continue advocating for legislation in Minnesota to offer incentives for electric vehicle purchases and develop a program to help dealers pay for upgrades. Rep. Zack Stephenson, a Minneapolis Democrat, has sponsored legislation that offers rebates for buyers and assists in helping dealers pay for programs certifying employees to sell electric vehicles.
In the next few years, Backhaus would like to see dealers have the educational background, infrastructure and services in place to sell EVs.
“We want them to be able to talk to their consumers about how [electric vehicles] work and that they’re not a scary, unknown thing,” she said.
By now, solar trailblazer Tony Smith figured he would be on the verge of linking at least 100 low-income households in Virginia’s Shenandoah Valley with affordable power from the sun.
Secure Solar Futures, the Staunton-based company he leads, had selected an ideal 10-acre, south-facing site in Augusta County for the 1.2-megawatt project. It carried a $2 million price tag and was set to go online after July 2023, per Virginia’s recent community solar law.
County officials heartily embraced Smith’s plan and praised his vision to preserve the region’s agricultural traditions by grazing sheep among the arrays.
And, in the spirit of a true community solar venture, the developer had partnered with an energy-centric nonprofit in nearby Charlottesville to identify potential customers.
“People want to feel a connection to where their energy is produced,” Smith said about seeking local customers. “That’s part of our game plan.”
What could possibly derail such a well-intentioned plan?
As it turns out, plenty.
But the major obstacle emerged when Smith broached Dominion Energy in August 2021 about interconnecting the project to the distribution grid.
Dominion rejected the proposal. In the ensuing back-and-forth, Secure Futures discovered that Plan B would mean footing an extra $1 million bill to install a type of fiber optic wire known as dark fiber between the array and the substation to meet Dominion’s standards.
“Suddenly, the project would cost $3 million,” Smith said. “That made it too expensive. To make it appealing to low-income customers, the price has to be less expensive than the rate they’re already paying to Dominion.”
For distributed energy, Dominion frames dark fiber as a reliability and safety necessity. In tandem, the utility insisted that Smith’s proposed array be able to go offline within one-sixth of a second of a power outage being detected.
That surprise blink-of-an-eye demand has stalled Smith’s array — but not his resolve.
“We were shocked to get this news from Dominion, because no other utility has these requirements,” he said, noting a two-second shutoff is the industry standard. “But we’re still trying to make this project happen.”
Dominion spokesperson Jeremy Slayton didn’t comment on this specific case.
Generally, he said, the utility administers regulations laid out in Chapter 314 of the Virginia code that governs the interconnection of small electric generators in a “consistent and equitable manner” for all customers that “desire to operate generation in parallel with the Company’s distribution grid.”
He added that Dominion performs site-specific, customized interconnection studies to identify modifications needed to ensure the safety, reliability, and operability of the grid.
In May, the State Corporation Commission opened a docket to comprehensively explore interconnection issues related to distributed energy resources.
“Dominion … looks forward to continuing to participate in this docket as it evolves,” Slayton said.
For Smith’s project to come to fruition, Virginia’s solar industry will likely have to convince utility regulators that developers in Dominion territory, especially small ones, not be saddled with installing expensive dark fiber when other — and cheaper — existing technology can meet the same safety and reliability standards.
Dominion evidently insists that dark fiber should be the heart and lungs of grid equipment known as Direct Transfer Trip, or DTT.
The Chesapeake Solar & Storage Association, or CHESSA, challenged Dominion’s dark fiber assertion in testimony submitted to Virginia utility regulators this summer.
“This [DTT] requirement is an unnecessary and arcane approach to addressing anti-islanding, given the fact that certified inverters already perform this function,” said GreeneHurlocker attorneys representing CHESSA.
With DTT costs averaging $2 million to $3 million — and reaching as high as $7 million, CHESSA and Coalition for Community Solar Access have withdrawn multiple projects in Virginia.
CHESSA noted that states with high levels of distributed energy penetration have “long moved away from requiring DTT and instead use inverter-based solutions.”
Virginia solar developers agree that it’s unfair for the first project in the queue at a substation to bear the financial brunt of an entire substation upgrade that essentially becomes a grid modernization project. CHESSA also noted that some states are exploring the idea of cost-sharing among distributed energy projects.
Cliona Robb, an energy attorney for 22 years, is frustrated that Smith’s project is being stymied by Dominion’s dark fiber rationale when she says the utility is clearly an outlier on that front. In August, she filed comments with the commission on behalf of Secure Futures.
“The message is that you can get solar, as long as it’s utility solar. Otherwise, you’re out of luck,” said Robb, of Richmond-based Thompson McMullan. “It’s outrageous to me that a utility can unilaterally adopt a practice that’s not consistent with industry standards.”
In her comments to regulators, she outlined several changes that would help smaller solar developers complete projects without bankrupting themselves.
For instance, Robb urged commissioners to adopt a rule eliminating the need for dark fiber for interconnections under 5 MW. In Virginia, Level 2 interconnections generally apply to projects between 500 kW and 2 MW, while Level 3 projects can be up to 20 MW.
As well, she advised that expenses for those smaller projects be limited to the cost of inverters and reclosers and not costs related to upgrades to a utility’s substations or other pieces of its distribution system. As well, she said, inverters or cellular communications should be the standard in lieu of dark fiber.
Robb pointed to a case study published by the Institute of Electrical and Electronics Engineers (IEEE) concluding that DTT cellular communications provided an efficient and cost-effective approach for utility communications with distributed generation systems.
The study looked at three installed DTT systems — one in Central Virginia Electric Cooperative territory and two in Dominion’s service area. It compared copper telephone lines to cellular communications. The latter was considered because the authors noted that fiber installation is not always feasible because it can be cost-prohibitive.
The Institute of Electrical and Electronics Engineers is the professional body that sets scores of standards, including one that covers inverters and minimum distributed energy performance requirements. Secure Futures and other developers maintain that Dominion’s strict interpretation of that standard is squeezing their projects.
Even if Secure Futures did splurge on fiber optic cable for its Augusta County project, Smith noted that it would be using only two of the 24 total “strands.”
“So, the other 22 fibers would be dedicated to some other purpose not involving our project,” Smith said. “With that, Dominion is putting the cost of infrastructure development on the backs of solar developers.”
Slayton, the Dominion spokesperson, said the inverter performance criteria is not related to the dark fiber requirement. He noted that the inverter specifics had been among the utility’s protection requirements since September 2016.
Utilities, installers, environmental advocates and others in the solar community flooded regulators’ inboxes after the May request for comments.
Two of the eight questions commissioners asked participants to address small solar generators. In addition to dark fiber, solar advocates weighed in on a number of interconnection concerns, including lengthy timeliness, excessive studies, lack of transparency and dispute resolution.
The state General Assembly recognized the benefits of distributed energy by passing both the Virginia Clean Economy Act and a shared solar statute in 2020.
Those and other clean energy laws prompted regulators to update interconnection rules from more than a decade ago. However, advocates had complained that those tweaks weren’t adequate enough to match the rising volume of interconnection applications.
“While the changes made to the rules provided modest improvements to the process, the distribution interconnection process continues to be antiquated and ill-prepared for the 21st century grid,” CHESSA wrote. “The existing procedures [are] not sufficient to enable the amount of renewable energy additions required by the Commonwealth’s transformational energy goals.”
Dominion submitted 15 pages of comments. Two of those pages addressed regulators’ query about how commissioners could facilitate its approach to the Institute of Electrical and Electronics Engineers standard on inverters and distributed energy.
Dominion stated that it believes any use of distributed energy “ride-through or voltage regulation functionalities should be at the Company’s discretion and evaluated based on system needs on a case-by-case basis.”
The utility told commissioners that the regulations centering on the standard don’t need to be revised.
“Specifically,” commission staffers summarized, “Dominion commented that anti-islanding functions of [distributed energy resources] inverter-based resources alone do not replace the multiple functions and layered protection that DTT provides to the electric power system.”
On Sept. 19, commission staff released a 57-page action plan, of sorts, after reviewing input. They concluded that some concerns could be addressed immediately, others would be more time-consuming and still others would likely require a separate docket.
“The requirement for usage of dark fiber-optic cable for DTT implementation was one of the most pressing issues commented on by the parties,” commission staffers said.
Solar developers echoed Secure Futures’ concerns about dark fiber. However, they also pointed out that the fiber can cost more than $250,000 per mile to install. The total price tag is a blow to project planners because utilities don’t deliver those cost estimates until the “facilities study phase,” the final study phase of a long and involved process.
Smith said he is disappointed that working groups will likely be handling the issues delaying his Augusta County project — dark fiber and the excessive cost of interconnection — in a far-off timeline.
“We have a need for speed,” he said. “But we’re looking at four to six years until anything is settled.
“In the meantime, while Rome burns, solar investment will bypass Virginia. Social policy and interconnection barriers are hindering the promise of solar.”
Robb, his attorney in this case, said commissioners need to be aware of the damage they are inflicting by pushing immediate concerns off to slow-moving work groups instead of acting themselves.
“Not advancing community solar is harming the public interest,” she said.
Smith, who founded Secure Futures in 2004, is no clean energy rookie. The entrepreneur has been immersed in solar since 1978 when he created his first job in the industry with the Philadelphia Solar Energy Association.
Thus far, his Staunton company has developed more than 11 MW of arrays in Virginia, West Virginia and the Carolinas.
Five years ago, the business became a certified B Corporation to reflect its commitment to solving social and environmental problems. It prides itself on innovations in financing, public policy and energy education that extend the reach and affordability of solar power.
For instance, that spirit is reflected in an endeavor Smith’s company is undertaking in the state’s seven historic coalfield counties, at the behest of the Solar Workgroup of Southwest Virginia.
A public-private partnership launched in September 2020, appropriately named Securing Solar for Southwest Virginia, is in the midst of installing 12 MW of solar arrays at five commercial buildings, five multifamily housing units and 10 schools. The optimistic completion date is next year.
Relatedly, Smith viewed the Augusta County project as an innovation to connect underserved Virginians with community solar, a new concept in Dominion territory.
He praised the utility for setting up a program but lamented how interconnection challenges are “killing it on the implementation side.”
Dominion’s program, set to debut next year, sprang from state legislation passed in 2020. Initially, total capacity will be capped at 150 MW. Both solar and environmental justice advocates had lauded the law for requiring that at least 30% of the enrolled customers qualify as low-income. If that bar was met, the program could grow by another 50 MW.
In addition, no single community solar project could be larger than 5 MW. The idea was to incrementally stimulate a series of small-scale distributed generation projects, roughly 1 MW apiece.
This summer, regulators set off an uproar among solar advocates by allowing Dominion to charge a $55 monthly minimum fee to enrollees. The legislation had included a measure allowing commissioners to set a monthly fee that let Dominion account for costs of implementing shared solar and for use of the grid infrastructure.
Low-income subscribers, however, are exempt from that minimum fee. Aiding that poorer audience is why Secure Futures sought out a local collaborator in Augusta County.
Now, that affiliation also might be unraveling.
Due to delays, it’s not clear where the partnership with the Charlottesville-based Local Energy Alliance Program now stands. Leaders of the nonprofit didn’t return requests for comment. Since 2010, LEAP has offered home and commercial energy upgrades, as well as solar services.
Even though Smith has “come to the sad conclusion that we’re not going to get any help on the regulatory level,” he is forging ahead.
After withdrawing the project in April, Secure Futures is now in the midst of resizing it and preparing a new interconnection application.
“We’ll see what happens,” Smith said. “We’re not holding our breath.”
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