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Smaller, regional banks and credit unions are increasingly looking to help homeowners finance solar installations in a sign of growing recognition of the opportunities in clean energy finance.
In the Midwest, Iowa-based Decorah Bank & Trust is among the latest to begin marketing loans for solar and other clean energy projects. The community bank recently relaunched a digital subsidiary called Greenpenny to serve residential and commercial customers in Iowa, Illinois, Missouri, Minnesota and Wisconsin.
It joins longtime Twin Cities clean energy lender the Center for Energy and Environment and a handful of credit unions and other community banks offering products in a space traditionally dominated by larger, national firms.
Clean energy advocates are hopeful the availability of local lenders will increase options for borrowers and provide a greater comfort level for those who might be less inclined to trust online lenders or large national banks.
Jeremy Kalin, a partner with Avisen Legal who helped the Minnesota Credit Union Network create its CU Green solar loan program, said typical residential borrowers are sensitive to “long-term value and trust” when looking for lenders. A personal connection to a bank or credit “makes a difference.”
The process often starts with referrals from solar installers. St. Paul-based All Energy Solar offers Greenpenny and Center for Energy and Environment loans to customers, as well as national lenders. “Historically, we find the national players pushing the envelope here very consistently with innovations and competing with each other to offer a diverse array of financing options that will help each customer to get the most value out of their project,” said Ryan Buege, All Energy Solar’s vice president of sales and marketing. Still, he said, if more banks developed clean energy loans, more consumers would likely become more comfortable installing systems.
Jessica Reis, vice president of communications and marketing for Greenpenny, said the bank creates a transparent loan process with no hidden fees or upfront charges, a contrast with some national lenders who use such fees to lower interest rates. The bank calls every customer who applies and communication continues via phone or email.
Greenpenny relaunched last year after struggling with an earlier rollout during the pandemic. Now the Iowa credit union has been adding staff to manage a growing portfolio. Decorah Bank & Trust CEO and President Ben Grimstad said his father, Larry, had started lending to organizations doing renewable energy projects decades ago because of his environmental interest.
Decorah, home to Luther College, has a strong ecological ethos that allowed the bank to gain experience financing more than 100 local projects, most of them solar. Grimstad wanted to expand the bank beyond Decorah and decided to create a digital offering to leverage the bank’s experience with clean energy.
“We are about a year and a half into it and it’s gone pretty well,” he said.
Greenpenny provides solar loans and a green mortgage product for efficiency, geothermal, battery storage and other carbon-reducing projects. The digital bank serves residential customers as well as small- to medium-sized commercial and industrial projects, but not utility-scale wind or solar farms.
The loans are secured by the value of the equipment, from panels to storage devices. Greenpenny President Jason MacDuff said the bank tries to set up loans that match the amount clients save monthly on their utility bills from a new solar or HVAC system. The loans require no money down.
“These borrowers, by definition, are all homeowners that tend to skew pretty sophisticated and because they’re making a pretty big investment in their home, they tend to have the means to be able to do that,” MacDuff said.
A unique short-term solar loan Greenpenny offers matches the tax credit a customer receives. The customer pays a small interest payment and then pays off the loan when the federal government disperses the 26% tax credit. A second loan covers the remaining 74% of the project’s cost.
The average residential loan size is $40,000, with commercial projects from hundreds of thousands to millions of dollars. He noted that the bank may soon finance as many as seven community solar projects in Minnesota. But plenty of deals fall through because of low reimbursements for energy by utilities or other issues.
When he joined the company in 2021, he was surprised to find so few banks offering clean energy loans. “For us to accomplish the renewable energy transition this country needs, we need more banks to be in the game helping finance these projects,” MacDuff said.
In Minnesota, the largest local option remains the Center for Energy and Environment, which has established partnerships with several cities and neighborhoods and last year financed $22.7 million in projects. Of those, 145 loans totaling $3.5 million were for residential solar, up from 89 loans in 2019. Lending services director Jim Hasnik said the organization had been lending for years for efficiency improvements before it developed a solar loan in 2014.
The loans vary in term and loan-to-value size, with interest rates increasing as the length of loans climbs. Project sizes have grown, and business has been brisk this year as the popularity of solar has grown. The center requires installers to have a builder’s contractor license following a recent string of solar company bankruptcies in the state.
Solar loans remain a niche product. The Minnesota Credit Union Network’s CU Green program launched with two credit unions — Affinity Plus Federal Credit Union and Hiway Credit Union — and has seen no others join the effort. Mara Humphrey, chief advocacy and engagement officer for the network, said some credit unions have begun discussing whether to add solar loans to their portfolios, but she believes many still lack understanding of clean energy projects and will have to see demand grow before creating products for customers.
Affinity Plus had a rocky start before dropping a requirement that homeowners first hire someone to conduct a home appraisal. Members can now apply digitally for loans and receive the money the same day.
Chief Retail Officer Corey Rupp said the new solar loan program did more volume in six months than the home equity-based one did in four years.
“I think homeowners are a little more comfortable with it,” Rupp said. The credit union is now studying loans for electric vehicles, commercial efficiency, and solar projects.
Correction: The $22.7 million CEE lent was for about 1,200 loans.
Indiana solar installers knew their customers would be worse off when new, reduced rates for surplus solar generation took effect on July 1.
But changes being ushered in by utilities go far beyond what the industry had been bracing for, say solar and consumer advocates who are now challenging regulators’ interpretation of a 2017 law that gutted net metering.
All five of Indiana’s investor-owned utilities have won approval to not only slash the rate paid for customers’ surplus solar power, but also change how solar output is calculated in a way that drastically reduces the payments.
Utilities say they are protecting other customers from subsidizing those with solar panels, but advocates say the outcome threatens to put rooftop solar out of reach for all but the wealthiest customers.
“Unfortunately, utilities used the opportunity to completely change the policy, and [state regulators] went along with what utilities wanted,” said Ben Inskeep, program director at Citizens Action Coalition, a consumer and environmental advocacy group based in Indianapolis.
Indiana solar customers until now have been paid for extra solar generation at the end of each billing cycle. The amount of electricity sent back to the grid that month is subtracted from the amount of power the customer used from the grid, and any extra is paid out at a rate lower than the retail rate but robust enough to make solar panels financially viable for many customers.
The arrangement allows a homeowner, for example, to use extra daytime solar generation to offset evening grid power use, but they can’t bank solar credits in the summer to reduce their electric bill during the darker winter months.
A bill (SA309) signed by Gov. Eric Holcomb in 2017 put the state on a path to phasing out net metering by 2047. Meanwhile, it let utilities begin paying solar customers a lower rate when solar penetration reached 1.5% of their summer peak load, or by July 2022.
CenterPoint, previously known as Vectren, was the first utility to reach that benchmark and early last year filed a request to institute the new, lower rate — known as the “excess distribution generation” or EDG rate. CenterPoint also proposed switching from monthly net metering to a new model known as “instantaneous netting,” in which customers pay the full retail rate for all power used from the grid, and all solar power sent back to the grid is paid at the much lower EDG rate. The arrangement turns out so badly for customers that advocates like Inskeep refer to it as “no netting.”
The Indiana Utility Regulatory Commission approved CenterPoint’s full request in April 2021 despite arguments from consumer and solar advocates that the plan oversteps what’s called for in the 2017 law.
“SA309 does not authorize instantaneous netting. It made no mention of changing the netting interval,” Inskeep said.
In March 2021, NIPSCO had submitted testimony seeking an EDG tariff with monthly netting. But NIPSCO withdrew that proposal and sought instantaneous net metering after the commission’s decision on CenterPoint. Utilities AES, Indiana Michigan (I&M) Power, and Duke Energy also sought the same instantaneous netting arrangement. The commission approved all of the proposals — most recently Duke’s on July 6.
The Office of Utility Consumer Counsel, a governmental office set up to advocate for consumers, joined solar advocates in arguing against instantaneous netting, saying it would be inconsistent with SA309.
But the commission has argued, including in its Jan. 26 approval of I&M’s proposal, that the intent of SA309 was to end net metering, and instantaneous netting would basically be a way to do that. The commission acknowledged that customers would save less money through instantaneous netting, but invoked an argument long used by utilities against solar energy: that the savings of customers with solar would be costs shifted onto customers who don’t have solar.
Duke Energy echoed this sentiment in response to Energy News Network questions about the change to instantaneous netting.
“The intent of the legislation is to help ensure that customers who do not own solar generation are not subsidizing those who do,” said Duke spokesperson Angeline Protegere, noting that 2,600 customers in Duke’s Indiana service territory have solar.
“Even though they generate some of their own power, solar customers still rely on electric infrastructure such as power lines, and the new rate reflects the costs of that. It’s important to realize that customers ultimately pay for the credits we give to solar customers.”
Advocates including the Indiana Distributed Generation Alliance and Citizens Action Coalition appealed the commission’s decision on CenterPoint’s proposal and won a favorable ruling in the Indiana Court of Appeals.
But now the matter is before the state Supreme Court, and the appeals court decision is negated until the higher court hears the case, with oral arguments scheduled to start Sept. 15.
“This is a matter of law,” said Laura Arnold, executive director of the Indiana Distributed Generation Alliance. “The commission and CenterPoint have been trying to portray that the General Assembly intended to allow instantaneous netting, but that is just not true.”
Under SA309, the EDG rate paid for energy from solar is equivalent to 125% of the average hourly market rate during that month. Using this calculation, CenterPoint originally proposed to pay their customers 3.1 cents per kilowatt-hour for solar, and NIPSCO proposed 2.6 cents.
Utilities have increased the prices they plan to pay customers for solar as market power prices have risen due to the war in Ukraine, to the 4 to 5 cents per kilowatt-hour range; meanwhile retail prices customers pay for power from the grid have also risen. Duke’s retail rate is 16 cents per kilowatt hour for an average residential customer, Protegere said. (CenterPoint and NIPSCO did not respond to requests for comment.)
Brad Morton, founder and CEO of Morton Solar, told the commission that the switch to instantaneous netting and EDG rates “grossly lengthens the customer investment pay-back period,” with instantaneous netting at the 3.1 cents per kilowatt-hour originally proposed by CenterPoint changing the typical residential solar payback period from the current 7- to-10 years to 21 years.
The 3.1-cent payment rate alone, without instantaneous netting, would result in a typical payback period of 14 years, he testified. When the phaseout of the federal Investment Tax Credit is added to instantaneous netting and the EDG, it would take 25 years for a typical solar system to break even, Morton said.
Morton was the first to install solar in Vectren (now CenterPoint Energy) territory, he told the commission, and among the first to do grid-tied solar in Indiana. His family members had worked in Indiana’s coal mines, and he wants to help transform former coal mine land into solar fields, replacing declining coal mining jobs and revenue with a solar economy in the process.
Last year Morton did $2.5 million worth of solar installations in Vectren’s service area, and $3.1 million in Indiana as a whole. If the instantaneous net metering goes forth, he said he might have to stop doing business in Indiana altogether, and lay off some of his 17 staff members.
“This will be devastating to Indiana’s fledgling solar industry and result in job losses and probable market contraction to an industry that was just beginning to blossom,” he testified.
Customers who have recently installed solar are exempted for a decade, governed by the old terms through 2032. But that just barely covers a typical pay-back period, so right when customers would have hoped to start reaping the savings of solar, the opportunity will stagnate. Customers — like Arnold herself — who installed solar before SA309, can net meter under previous terms until 2047.
Arnold said that if utilities get their way and institute EDG plus instantaneous metering, solar would only make sense for most customers if they have a battery system to use all their energy themselves rather than sending it back to the grid for pennies. But batteries cost thousands of dollars and make the already slim margins on solar unworkable for many customers.
She noted that if “no netting” takes effect, customers would rarely install solar systems that generate more power than they need at any given time, wasting the chance to get more clean power on the grid by installing larger systems.
Arnold added that on top of the gloom facing the solar industry for years to come, there is debilitating uncertainty for customers who’ve signed solar contracts and hoped to install them by the end of the year. Duke Energy and NIPSCO have told customers they could qualify for previous net metering terms if their solar is contracted now and installed by the end of 2022. Protegere confirmed that is Duke’s plan.
But Arnold said solar developers and lenders are worried that the commission might block this arrangement, perhaps if another utility complains.
Arnold said that months ago, advocates had asked the commission to issue an opinion clarifying the deadline, to provide certainty for developers and customers, but the commission has not done so.
Inskeep noted that the changing price of power — and hence the 125% EDG rate people are paid for solar sent back to the grid — means uncertainty for anyone who is considering solar.
“It’s hard to say what your compensation will be in the future — it will change every single year,” said Inskeep, who was principal energy policy analyst at EQ Research, a clean energy consulting firm, at the time the commission decisions were playing out.
“You’re making a 25-year investment, but the value is updated on an annual basis. You have no ability to see if your investment will pay off. Utilities never make large investments for 30-year assets without having certainty for that cost recovery. Now they’re asking residential customers to take that risk — with no ability to understand when their investment will pay off or if it will never pay off.”
Many individuals and households have at least one outdated appliance — a refrigerator, a water heater or a window-mounted air conditioner that they hold onto because of the expense involved with replacing them. Yet the money they save is often more than canceled out by higher utility bills.
Upgrading outdated appliances can help low-income households stay in their homes by reducing their utility bills — and by extension, lowering their overall housing costs. The money saved can be used toward other necessities such as food or transportation to work or school.
However, it can take years for a new appliance to pay for itself through energy savings. Without incentives, it often simply doesn’t make financial sense for a low-income household to upgrade outdated appliances solely to save on energy bills. This is especially true for renters or homeowners who are unsure about how long they will remain in a given location, or who are unsure about whether they can take new appliances with them when they move.
The challenge is in bridging the gap to bring the necessary up-front investment in energy-efficient appliances within reach. That’s where organizations like Elevate and Meadows Eastside Community Resource Organization, also known as MECRO, come in. They coordinate resources such as incentives offered by utilities, grants and low-interest loans, and make them available for low-income households to eliminate this dilemma.
Through its headquarters in Chicago’s West Loop, along with offices in downstate Illinois, Michigan, Missouri, Wisconsin, Oregon and California, Elevate works to help homeowners and owners of multifamily units across the country obtain financing to improve the energy efficiency in their homes and buildings. MECRO is located on the busy 79th Street commercial corridor of Chicago’s Southeast Side and focuses its services on residents in the community. (The name Meadows in the MECRO acronym is in honor of Rufus and Everlena Meadows, the parents of Sharon “Sy” Lewis, founder and executive director of MECRO.)
Through a collaboration with the City of Chicago, ComEd and Elevate, the National Renewable Energy Laboratory utilized its trademarked ResStock tool and place-based data to develop residential energy efficiency strategies for the city’s residential building stock, primarily comprised of bungalows and other single-family homes built before 1942. Through the Chicago Advanced Building Construction project, a series of simulations was executed, which generated up to $49 billion in potential utility bill savings. An especially significant finding was that sizable savings could be achieved through installing heat pumps and other off-the-shelf technologies.
An old refrigerator uses up to three times as much electricity as a newer, energy-efficient model. Energy-certified clothes dryers use 20% less electricity than a standard dryer. Certified clothes washers require between 40% and 50% less energy and 55% less water to operate than conventional washers.
Utilities such as ComEd and Ameren in Illinois provide a number of incentives for ratepayers — such as rebates for trade-ins of old appliances — to facilitate the switch for customers to energy-efficient appliances.
Elevate has a number of funders that provide grants to heavily incentivize or provide upgrades at no cost for homeowners. In addition, in areas where utility incentives aren’t in place, the Community Development Financial Institutions Fund can provide financing, according to Jackie Montesdeoca, director of building electrification for Elevate.
“There are models where we can have a lender include energy efficiency as part of the overall rehab. We do that in the Chicago area, but that’s a model that can be replicated [in other locations]. … The underwriters or the loan officers know that high-efficiency equipment or adding a little more insulation than code requires is going to make that building more resilient [with] lower operating costs, as opposed to a building that didn’t go through those measures in their rehab,” Montesdeoca said.
According to U.S. Census Bureau data cited in a 2020 report by the American Council for an Energy-Efficient Economy, utility costs for poor households averaged 8.1% of their income, versus just 2.3% of income spent by more affluent households on utility bills.
While the lion’s share of these expenditures was for heating and cooling, household appliances accounted for a significant percentage of utility costs as well.
A comprehensive energy efficiency upgrade that includes replacing outdated appliances can translate to savings of 30% or more, according to Montesdeoca.
Yet many eligible households remain unaware of these programs, or have the mistaken belief that they do not qualify, according to Lewis.
“One of the things that I really try to push is that all of these programs are available, [but there is a] lack of information. You would think somebody who lives in Beverly” — a middle-class, racially diverse community on Chicago’s far Southwest Side — “wouldn’t be income-eligible and they wouldn’t be suffering from housing insecurity. They are. It does not matter. There are very affluent neighborhoods where people are suffering. You know, it’s a lot when you’re making a hundred thousand dollars, [but] there are eight people in your house,” Lewis said.
Reducing utility bills by replacing outdated household appliances is a vital tool in enhancing housing affordability through the knock-on effect in freeing up funds that were formerly needed for those bills — funds that can be used for other necessities that enhance overall housing affordability. Even small improvements, such as installing aerators on faucets or converting incandescent lighting to LEDs, can contribute to cumulative money savings, Lewis said.
“So, with these little aerators people think, oh, that’s just something cute. No, it’s not. It is saving you water. It’s saving you gallons and gallons and gallons of water. Is it impactful? Yes, absolutely. Will it be able to keep more people in their homes? Absolutely. Because this is now an expense that they do not have to pay on their property, that they can invest on their bills, that they can invest in their property,” Lewis said.
Nonetheless, many would-be beneficiaries find it difficult to justify the expense to replace a functional refrigerator or water heater. A lack of awareness about available incentives also contributes to resistance. It’s often necessary to educate people about how the return on investment combined with available incentives and other resources actually helps them save money in the long run, Montesdeoca said.
“Owners need a clear expectation of estimated savings related to their upfront investment. We work to make the process easy for them and break down costs along with identifying the funding gap. For a lot of small multifamily owners … these owners don’t have a lot of cash flow to play around with. So if we aren’t bringing incentives, grant dollars, or some kind of financing as a resource it is hard to otherwise make that project work. The best scenario is that we can connect the owner to the problem and the financial tools that can help get to solutions,” Montesdeoca said.
Many energy efficiency incentives are geared toward single-family homes, but multi-family building owners and renters also struggle with high utility bills. Energy-efficient upgrades for multifamily units are essential in retaining affordable housing, according to Karen Lusson, staff attorney for the National Consumer Law Center, with offices in Boston and Washington D.C.
“The multifamily building market has always been a larger challenge. With the single family, it’s about reaching the homeowner and convincing the homeowner that this makes sense. Ideally, weatherization [and related] services should be provided at zero cost to the homeowner. In terms of the multifamily building owner, there can be variances in terms of the copays. There can be sliding scale copays for the building owner. But if we’re trying to increase the availability of affordable housing, we want to make sure those incentives are large enough, and those copays aren’t so big that they lose interest, or turn down these opportunities to invest in energy efficiency,” Lusson said.
Both ComEd and Ameren provide incentives for energy-efficient appliances for multifamily units as well as for single-family homes — working in Chicago and surrounding communities in collaboration with organizations like Elevate and MECRO.
Marcia Ellis is the owner of a six-unit property in Chicago’s New City community area located on the city’s Southwest Side. The legacy building, which was constructed in 1924, has been in the family since 1984. Ellis received a free energy assessment through Elevate, a loan through Community Investment Corporation and $44,697 in incentives from ComEd and Peoples Gas Energy Efficiency Programs to cover the cost of lighting retrofits, roof and pipe insulation, bathroom and kitchen aerators, LED lighting, a new high-efficiency boiler and other improvements. The return on investment? An estimated $2,380 in estimated annual savings, not to mention happy tenants.
MECRO worked with a senior in the community to improve the energy efficiency of her 100-year-old three-flat. Along with weatherstripping, insulation and replacement doors, the dwelling was fitted out with all-new appliances in each unit, according to Lewis.
“She gets three new air conditioners. … And she’s got a freezer in the basement that you could put a body in. It’s not energy efficient. She got a brand-new freezer. She got a stove and a refrigerator for three units, and a deep freezer. And she had her grandson’s college refrigerator. It’s not energy efficient. So, she got one of those. She got a new furnace and a new water heater. So, every appliance in her house is energy efficient.
“I visit her from time to time. You can tell the difference. You can literally tell the difference,” Lewis said.
And while making the conversion from gas or other carbon-based heating fuels to electric increases overall electric bills, making the switch can make up the difference by eliminating a gas bill altogether, according to Emma Baumgart, senior associate for communications at Elevate.
“With electrification [there] is the added benefit of having no gas bill. And especially in Chicago, People’s Gas has high fixed costs on your bill, where even if you’re not using any gas, you still are paying that monthly charge. And so that’s an added benefit of going fully electric. You still have fixed costs on your electric bill, but it’s just one instead of two. So obviously your electric bill goes up when you are converting to all electric, but by completely removing that fixed cost is another way that electrification can help with affordability,” Baumgart said.
For Lewis, a lifetime resident of Chicago’s Southeast Side, her work with MECRO in enabling residents to remain in their homes represents one way of investing in the well-being and stability of the community she calls home.
“Those things that impact the quality of life, impact how low-income housing exists in our community and how people are able to stay in their places and live comfortably,” Lewis said.
For decades, hydrogen has been touted as the fuel of tomorrow — a day yet to come.
But a $9.5 billion package wrapped into the enormous 2021 federal Infrastructure Investment and Jobs Act could assure the element’s speedier arrival in an eco-friendlier fashion.
A bulk of the funding, $8 billion, would go toward constructing regional clean hydrogen hubs to connect production facilities, terminals and pipelines with users in the transportation and manufacturing sectors. West Virginia is vying for one hub.
The goal is to replace “dirty” hydrogen sourced from natural gas with “green” hydrogen generated by splitting water — H2O — with electrolysis technology.
Ideally, that separation would be powered with renewable energy, a boost for the Biden administration’s targets of a 100% clean electrical grid by 2035 and net-zero carbon emissions by 2050.
Alleyn Harned was a proponent of hydrogen fuel long before he became the executive director of Virginia Clean Cities in 2011. He has been based in Harrisonburg since the organization formed a partnership with James Madison University in 2009.
In 2006, he coordinated a state working group that issued a public report about Virginia’s potential hydrogen economy. He also helped draft Virginia’s initial Energy Plan as the state assistant secretary of commerce and trade under Gov. Tim Kaine, now a U.S. senator.
“Green hydrogen is one of many options we have ahead of us to continue a path to better jobs and energy production in Virginia,” the 41-year-old said. Investing in it is more sensible “than blowing money on imported fuel that has energy security issues.”
Researchers see the promise of hydrogen in harder-to-electrify heavy industries such as steelmaking, and in the transport sector with maritime shipping, trucking and eventually aviation.
One urgent matter is dropping the price per kilogram of green hydrogen from the current $5-plus to $1 by 2031. Producing a kilogram of “dirty” hydrogen from methane is now a bargain at roughly $1.50.
Harned fully backs the quest for green hydrogen, but he isn’t such a purist that he wants to ban all methane as hydrogen feedstock. His instincts tell him that the perfect can’t be the enemy of the good when taming emissions of planet-warming gases.
“We are not going to eliminate every gram of carbon dioxide because that’s not the mission,” he noted. “The mission is to eliminate every net gram of carbon dioxide.
“Hydrogen is one scratch in the sand when we’re trying to move mountains.”
In this interview with the Energy News Network, Harned explains how green hydrogen can benefit Virginia’s economy and environment. His responses were lightly edited for clarity and length.
Q: What is the most significant accomplishment achieved by Virginia Clean Cities under your watch?
A: Our biggest accomplishment is raising awareness that transportation in Virginia is the economic sector with the largest greenhouse gas emissions. That information was withheld for years and it took time for people to understand what it meant.
Q: Green or clean hydrogen is having a moment in the headlines. Is it all hype or does the science back it up?
A: It’s understandable that people might think hydrogen is being overhyped. What’s positive is that we are seeing the federal government now investing in a massive research program with plans to build at least four hydrogen hubs nationwide and expand access to hydrogen fuel.
Keep in mind that hydrogen is emerging as part of a larger menu and would be part of a whole ecosystem of energy.
Energy is everything in our economy and hydrogen is an important upcoming component. But we don’t just snap our fingers and we’re done.
Q: U.S. Rep. Don Beyer, D-Virginia, is a co-sponsor of the Clean Hydrogen Production and Investment Tax Credit Act of 2021 (H.B. 5192). Why is Beyer supporting this and what is the measure’s intent?
A: Congressman Beyer represents an area in Northern Virginia that produces no oil. His family also has a long history operating auto dealerships, which perhaps explains his interest in transportation fuel.
His legislation offers what I would call a measured approach to support innovation in producing green hydrogen. That’s because it offers the highest tax incentives to production methods that reduce lifecycle greenhouse gas emissions most significantly. The top tier is a 95% reduction.
The legislation offers much lower incentives for other production methods that offer less of a lifecycle emissions reduction.
The type of tax credit laid out in H.B. 5192 showcases federal interest in reduced lifecycle greenhouse gases by putting a target on that figure.
Q: Let’s talk about green hydrogen in Virginia. First, are any universities or companies conducting research or using hydrogen of any type?
A: The U.S. Department of Energy spends millions every year on hydrogen research, so there could be projects going on in Virginia that I’m not aware of.
One piece of progress Virginia Clean Cities has made with James Madison University is to use federal funding to conduct the economic research behind what’s called the Hydrogen Fuel Cell Nexus.
Basically, the nexus is a U.S.-based business directory of hydrogen companies and products that buyers, partners, planners and other collaborators can use as a building blocks tool to put an actual project together, big or small.
Q: The Virginia General Assembly addressed passenger vehicles in 2021 by passing the Clean Cars law, which stimulates a transition to electric vehicles. But what about the separate carbon pollution from heavy-duty trucks and other segments of the transportation sector?
A: High-pressure hydrogen fueling infrastructure matters for these vehicles. That starts with fleet-fueling sites, shared fueling sites that can handle large vehicles, and a wide redundancy to the network.
It will take time but we see transit fleets installing their stations and succeeding with hydrogen today.
Consider that a tractor-trailer gets about 4 miles per gallon and emits 25 pounds of carbon dioxide per gallon of diesel. This is an opportunity for a higher density fuel like hydrogen, one that can produce zero tailpipe emissions.
Other mobile sources hydrogen can power are garbage trucks, transit vehicles, refrigerated trucks, as well as forklifts in all types of industries and marine ports with tractors and other vehicles.
Q: In-the-know observers predict that green hydrogen growth will take off in the 2030s. What kind of investments will that require?
A: Renewable hydrogen is produced at scale today and it’s a growing industry. There’s no need to wait until 2030. With energy hubs being built and with lessons learned from advances in California, those markets will only get bigger.
It’s what the whole country needs to thrive economically as we reach the end of our carbon budget. It’s a card that can be stored and played when needed.
Q: Relatedly, this country produces more than 10 million metric tons of non-green hydrogen, mostly from natural gas. That’s roughly 2% of U.S. total emissions. The U.S. Department of Energy estimates that producing an additional 10 million metric tons of green hydrogen would require doubling today’s wind and solar deployment. Is that buildout a pipe dream?
A: We will get this done, not because it’s easy but because we can and we have to so we can have a future. This transition is a critical component of maintaining our economy through the end of the century.
Everybody recognizes that our fossil fuel use will change dramatically in the decades ahead. It will be replaced with lower- and zero- and negative- carbon energies.
Q: On that last point you differ from strict adherents. They claim green hydrogen can only be created when renewable energy is used to generate the electricity that splits water into hydrogen and oxygen. Can you explain your reasoning on methane-sourced hydrogen?
A: I’m neutral on the pathway to decarbonization. It’s a game of inches, not a game of magic beans.
Capturing hydrogen via electrolysis (splitting water molecules) certainly works. But being able to eliminate releases of waste methane from landfills, wastewater treatment plants and agriculture using a process called steam reformation is crucial when you consider that we need to address this area of harmful waste and emissions.
Studies by the Virginia Department of Environmental Quality estimate that annually, our landfill methane is the equivalent of 2.4 million metric tons of carbon dioxide, manure management is half a million metric tons and wastewater is 0.7 million metric tons. It could be a win to grab it, reform it and reuse it.
Q: Environmental organizations such as the Natural Resources Defense Council have pointed out that “hydrogen leakage” has potentially negative climate consequences. Can that be mitigated?
A: Hydrogen safety and leakage is a top-level area of action for regulators and manufacturers. They’re not going out there building anything helter-skelter. Systems will be built with numerous layers of leak prevention.
Yes, it’s likely there will be minimal leaks so reducing that is important. But think about it this way: To get emissions equivalent to the carbon pollution from burning one gallon of gasoline, you would have to leak 2.5 kilograms of hydrogen into the air. It’s unlikely that a fraction of that hydrogen will be released, so it paints a rosy picture for the reduction of emissions.
Q: If green hydrogen isn’t generated directly on-site, how will it be shipped? Is talk about repurposing natural gas pipelines realistic?
A: It’s unlikely existing infrastructure such as large pipelines would be used. Hydrogen can be moved as a liquid or as a gas in a high-pressure cylinder. It’s possible it could be put into newly designed pipelines.
In Virginia, you already see heavy trucks and tanker trucks carrying large amounts on roadways. Also, Roberts Oxygen and other companies use smaller trucks to transport portable canisters for individual projects.
There is flexibility in all of this and distribution will be well-regulated.
As hydrogen is a bottle of energy, it seems like a good idea to distribute production all over Virginia to maximize local access and jobs.
Q: Anything else?
A: With transportation, it’s not easy to transition to hydrogen so it will take a little time. That’s why I’m excited that we’ve arranged a fleet demonstration for rural Virginia of a hydrogen vehicle from Toyota called the Mirai. We will make it available to government and rural fleet users periodically in 2022 and 2023. This totally hydrogen sedan is available in California and is used by federal fleet vehicles in Washington, D.C.
The following commentary was written by Laura Sherman. Sherman is president of the Michigan Energy Innovation Business Council, a trade organization of more than 140 advanced energy companies focused on improving the policy landscape for the advanced energy industry in Michigan. See our commentary guidelines for more information.
Michigan’s recently finalized plan to reach carbon neutrality by 2050 is an ambitious strategy that would remake the state’s economy. Under the plan, transportation would become electrified, and our energy would increasingly come from renewable sources backed by storage, among other bold policies.
While it can be daunting, big change is often good. The shift envisioned by the plan will pay dividends to Michiganders from all walks of life by increasing job growth, boosting income and raising the state’s overall economic output.
The advanced energy sector is one of the fastest-growing parts of Michigan’s economy, as the members of the Michigan Energy Innovation Business Council (Michigan EIBC) have seen firsthand. Michigan EIBC represents approximately 140 companies that work in Michigan in renewable energy project development, advanced mobility, energy storage, energy efficiency, manufacturing of batteries and other components used in clean energy, and more.
The MI Healthy Climate Plan, as unveiled by Governor Whitmer, will build upon this progress. Not only will prioritizing clean energy and transportation lead to savings for consumers, but also, the state’s economy can leverage several elements of the plan to attract businesses and private investment.
Clean energy and transportation are a foundational part of the state’s economy. According to E2’s 2021 Clean Jobs America Report, Michigan’s clean energy employment share of the statewide workforce is higher than the national average and the state ranks 6th in the nation in total clean energy jobs. Michigan also has the second highest number of clean energy jobs when compared to other states in the Midwest. Michigan ranks second in the nation, behind only California, for the number of jobs in the “clean vehicle” sector, including electric, hybrid, and hydrogen fuel cell vehicles. Furthermore, despite an unstable economy for much of the pandemic, the clean energy sector grew at a higher rate than the state’s overall economy.
State and local governments have helped make these jobs possible through policy. One of these policies is the renewable portfolio standard (RPS), passed in 2008, that required that 10% of the state’s energy come from renewable sources by 2015. As of early 2022, the Michigan Public Service Commission’s study on the effects of the RPS found that it had led to a total of 2,828 megawatts of renewable energy deployment in Michigan and over $5.1 billion worth of investment.
The MI Healthy Climate Plan recommends taking the RPS to the next level, increasing it to 50% by 2030.
Another important existing policy is the economic development package (Public Acts 134, 136, and 137 of 2021) and funding for the Michigan Strategic Fund that have invigorated the electric vehicle market in Michigan. The bipartisan deal secured transformational investments from multiple global companies, including Michigan EIBC member company General Motors and LG Energy Solutions, who chose Michigan over other competing locations.
To support additional electric vehicle deployment in Michigan, the MI Healthy Climate Plan recommends deploying infrastructure to support 2 million electric vehicles on Michigan roads by 2030.
We need to implement the policies proposed by the plan so Michigan can fully realize the potential benefits of advanced energy. An October 2021 report published by Greenlinks Analytics analyzed the shifts in employment, income, and Michigan’s economic output related to investments in energy efficiency, solar, demand response, and other renewable energy technologies associated with state climate goals. Using an integrated modeling platform, the report found that investment in clean and renewable energy over the next several decades would lead to the creation of 96,000 jobs, a $2 billion increase in residential household income and an additional $3.9 billion to the state’s GDP.
The recommendations in the MI Healthy Climate Plan can help Michigan capture these economic benefits, but we should not forget that it is just a plan. Michigan lawmakers and officials will need to do the hard work of enacting the planks of the plan. Decarbonizing Michigan’s economy over the next 30 years will be a challenge, but the state’s history of growth and strength in the advanced energy industry shows it is a challenge worth undertaking.
The following commentary was written by Meredith Connolly and Shelley Wenzel. Connolly is the Oregon director for Climate Solutions, a Northwest-based clean energy policy nonprofit. Wenzel is an energy data analyst at Energy Innovation, a nonpartisan climate and energy policy think tank. See our commentary guidelines for more information.
No matter what happens with federal climate progress, state climate action is imperative to cut greenhouse gas (GHG) emissions and help achieve the United States’ commitment to the Paris Agreement. Outside the media spotlight, Oregon has adopted some of the nation’s most significant climate policies, recently finalizing rules to slash emissions from fossil gas and transportation, while targeting 100 percent clean electricity by 2040.
But new research shows the state won’t achieve its climate goals without coupling power sector progress with additional policies that get vehicles, buildings, and industry off fossil fuels. In short, the winning climate playbook for all leading states must be “clean the grid and electrify everything.”
In 2020, Governor Kate Brown enacted an Executive Order (EO) to set a statewide goal of cutting greenhouse gas pollution 45 percent by 2035 and 80 percent by 2050. The same EO led to increased transportation electrification, cleaner fuels, and a Climate Protection Program (CPP), which sets emissions caps for transportation fuels and fossil gas.
And last year, Oregon’s legislature passed the fastest 100% clean electricity target in the West, requiring the state’s largest utilities slash emissions from power generation 80 percent by 2030 and 100 percent by 2040.
Even with these successes, Energy Innovation modeling shows the state is off track for reaching its own goals: If all recently adopted policies are rigorously implemented, Oregon would still only cut emissions 60 percent by 2050.
But there’s good news. The modeling also finds that adopting additional policies – especially for transportation and buildings – would not only cut emissions by 75 percent, but would also boost statewide GDP by $4 billion, create 18,000 jobs, and prevent nearly 900 asthma attacks annually in 2050.
Examining statewide GHG sources illuminates why a broader set of policies in Oregon, along with a pathway for how they will be achieved, is needed. As with most of the U.S., transportation has surpassed the power sector as the largest greenhouse gas source, composing 35 percent of all emissions. Meanwhile, homes and buildings consuming power and gas make up the second largest source at 34 percent, followed by industry and agriculture at 10 percent each.
With Oregon’s population expected to hit almost 4.6 million by 2030, these emissions will trend upward unless policies to shift from fossil fuels to clean electrification start right away. Every new gasoline car or truck, every new gas furnace and new gas-heated building or home locks in emissions for decades. Without meaningful progress in these other sectors, the state won’t hit its 2050 climate goals.
The Oregon policy modeling used the Energy Policy Simulator, a tool created in collaboration with Power Oregon and the Green Energy Institute, to evaluate the state’s new 100% clean electricity by 2040 law and the Climate Protection Program, finding they get Oregon much closer but still fall short of the state’s 80 percent reduction by 2050 goal. The open source, peer-reviewed EPS estimates the emissions, jobs, and health impacts of climate and energy policies using federal and state data.
The Oregon EPS research modeled a set of broader climate policies for all sectors that would put the state on track to achieve its goals and align with the U.S. Nationally Determined Contribution (NDC) to the Paris Agreement (i.e., Oregon doing its proportional fair share). The findings show an “NDC Scenario” for Oregon would avoid $4.8 billion in climate and health costs in 2050 (on top of the $4 billion in GDP growth).
Oregon is in a perfect position to adopt additional policies that leverage its clean electricity sector to secure compounding emissions reductions across the economy through efficiency and electrification policies. And state policymakers must ensure the clean energy transition’s health and economic benefits are broadly shared and reach frontline communities hit the hardest by pollution and climate impacts.
First, Oregon should adopt a 100 percent all-electric new vehicles sales standard by 2035, paired with an EV subsidy lasting through 2030, to supercharge transportation electrification. These policies must be accompanied by EV charging investments to plug in rural areas, low-income communities, and trucking corridors.
Second, increased investments in public transportation, as well as safe walking and biking paths, would reduce emissions while improving equity and air quality. An expansion of the state’s Clean Fuels Program could further cut emissions as the state moves toward a zero-emission future. These transportation sector policies achieve nearly one quarter of all the reductions under the NDC Scenario, showing how vital they are to reaching Oregon’s climate goals.
Third, Oregon must phase out fossil fuels for indoor uses. Similar to Washington’s recently passed commercial and large multi-family building heat pump requirement, the NDC Scenario modeling finds the most important policy for cutting greenhouse gas emissions from buildings would be a building code or standard requiring all new buildings or building equipment to be electric by 2030. This policy alone achieves over 10 percent of all the NDC Scenario’s reductions. To be most impactful, this transition must be coupled with strong efficiency standards.
These policies also create other health and economic benefits. Transportation electrification, along with greater reliance on active transportation, cuts health-damaging particulate and NOx emissions. Electric vehicles are also cheaper to own and maintain than gas cars and protect drivers from volatile oil prices. Electric heat pumps for space or water heating are more efficient than their fossil gas burning counterparts, and electric or induction stovetops avoid harmful fumes from gas cooktops that experts say may cause childhood asthma symptoms.
Together, a broader set of policies like those included in the modeling would get Oregon within a couple percentage points of the state’s 2050 emissions reduction goal, while additional land use and climate-smart agricultural practices could make up the difference. Equitable policy design and planning that prioritizes access and affordability for low-income households and communities will ensure the benefits are enjoyed by all residents, not just the wealthy.
While transitioning the power grid to 100 percent clean electricity is a critical step, Oregon’s lesson is that state climate action can still fall short if that isn’t coupled with rapid electrification. Cutting power sector emissions alone will not solve climate change, but it can make a big difference and leverage clean electricity to secure urgently needed emissions reductions in the transportation, buildings and industrial sectors. If we equitably and rapidly electrify as we clean up our grid, more of our cars and homes will be emissions-free, hopefully in time to avoid climate catastrophe.
Prospects are dimming for an offsite solar innovation promoted as a bright and affordable renewable energy option for Virginia apartment dwellers when legislation was greenlighted two years ago.
Now the fate of the new multifamily shared solar program is in the hands of utility regulators.
Solar advocates have pleaded with the State Corporation Commission to reject “program-killing” double-digit monthly fees that Dominion Energy would be allowed to charge solar subscribers.
Dominion has proposed an $87.68 fee, while commission staffers have suggested one as high as $57.26 a month. Figures are based on enrollees with a 1,000-kilowatt subscription.
Charlie Coggeshall, who directs policy and regulatory affairs for the Coalition for Community Solar Access, said Dominion arrived at its fee by lifting a page from its docket related to a similar, but separate, shared solar program for homeowners.
“The utility basically cut and pasted the charges it had proposed on a parallel docket,” Coggeshall said.
In late March testimony to commissioners, Coggeshall’s coalition asked regulators to also dismiss a $16.78 fee option floated by regulators.
Instead, his coalition of solar developers joined the Mid-Atlantic-based Chesapeake Solar & Storage Association in calling for commissioners to approve an interim administrative charge floated by Virginia environmental advocates.
That charge would amount to 1% of the bill credit value per month until Dominion “demonstrates a reasonable administrative charge.” The law calls for enrollees to be credited for their share of electricity the off-site panels generate.
“It is critical that the Commission send a clear message … that Dominion will not be allowed to use the administrative charge as a vehicle to block customer access to the benefits of solar or prevent investment in Virginia’s clean energy transition by non-utility shared solar developers,” attorneys for the two trade groups testified.
Commissioners could reach a ruling this spring.
Multifamily shared solar was just one piece of the wide-reaching Solar Freedom laws spearheaded by state Del. Mark Keam, D-Fairfax, in 2020.
The measure was designed to allow people living in apartments, condominiums and duplexes in Dominion territory the ability to buy solar energy via subscriptions to local arrays instead of having to install panels on their own rooftops. In most cases, shared off-site power facilities are built and owned by third-party entities, not utilities.
Ideally, subscribers earn credits in the form of savings on their monthly electric bills while also helping to pay down the developers’ cost of the array.
Such flexibility is attractive to low-income customers who can’t afford the upfront cost of rooftop panels, those with shaded southern exposure, people subject to homeowner association restrictions, and apartment renters and condominium owners without control of their rooftops.
Keam’s multifamily measure is separate from a different shared solar program, Senate Bill 629, designed mostly for homeowners and shepherded through the General Assembly by state Sen. Scott Surovell, a Democrat who also represents a district near Washington, D.C.
Both were signed into law by former Gov. Ralph Northam, a Democrat.
All along, Surovell’s law was set to launch in Dominion territory next year. Any day now, utility regulators will be announcing how much the utility is allowed to charge subscribers for minimum fees and administrative fees in that program.
Solar advocates challenged those charges at recent commission hearings, claiming they could put the kibosh on the whole program if they’re out of reach for market participants.
Surovell’s measure builds in a component that offers cost breaks to low-income subscribers. For instance, those enrollees are exempt from paying minimum and administrative fees.
Initially, that program is capped at 150 megawatts of solar. However, it can be boosted to 200 MW if it reaches an incentive requiring at least 30% of enrollees to meet pre-established low-income standards.
Keam’s original multifamily program could have been up and running in early 2021 if it hadn’t become mired in legislative and regulatory twists and turns.
For instance, regulators began writing rules based on a final version of the law that allows “the investor-owned utilities to recover reasonable costs of administering the program.” How that phrase is being interpreted is at the heart of the dispute. Dominion assumed it had broad leeway to set administrative charges. Solar advocates accuse Dominion of piling on costs in an effort to hamstring a program that should hardly make a dent in the utility’s budget.
Multifamily participants would be on the hook for those administrative fees because the measure doesn’t have a low-income exemption.
Robert J. Trexler, Dominion’s director of regulation, argues that because solar is intermittent, subscribers will continue to rely on the utility’s transmission and distribution systems.
An administrative charge is “a reasonable means to ensure that participating customers pay for the costs of services they will be utilizing,” he said, adding that “it is the only safeguard to minimize cost-shifting to non-participating customers.”
The administrative charge would vary based on subscription level.
However, solar advocates counter that Dominion’s proposed $87.68 fee or the $57.26 option presented by the commission staff make the program inaccessible because those charges are higher than customers’ regular electric bills.
“It is concerning that the utility is trying to use this administrative fee to preemptively charge for cost-shifting for which Dominion presents no evidence,” said Laura Gonzalez, energy policy manager for the Charlottesville-based nonprofit Clean Virginia.
Gonzalez emphasized that all three proposals before the commission should be rejected because regulations defined the fee as the reasonable incremental cost Dominion would incur to administer multifamily shared solar, not costs already incurred that are neither incremental nor related.
Acceptable administrative charges, she said, are new expenditures Dominion would need to make to operate the shared solar or handle billing. Examples include upgrading infrastructure or hiring employees.
She added that Dominion should recognize that enrollees are contributing to the big climate change picture by boosting electric grid resiliency and reducing emissions of heat-trapping gases.
“These programs have lots of benefits,” Gonzalez said. “The commission should rule based on the facts.”
Will Cleveland, a senior attorney with the Southern Environmental Law Center, said Dominion’s “extremely high” monthly charge “would result in an unworkable program.”
He added that the utility is seeking to recover lost revenue from program enrollees under the guise of an administrative fee.
“Dominion undermines both the plain language and spirit of the multifamily statute and rules by recycling its minimum bill proposal from a separate shared solar proceeding and renaming it an ‘administrative charge,’” Cleveland wrote in a March 24 document filed with regulators. “Moreover, Dominion has failed to demonstrate … that any of the costs of its proposed administrative charge are needed, just or reasonable.”
Many of the third-party developers who would build and own the off-site power facilities in Virginia are reluctant to speak on the record about shared solar because they don’t want to rock established relationships with utilities.
Nor, evidently, has there been a hue and cry for multifamily shared solar from trade organizations such as the Virginia Apartment Management Association.
The concept would be more appealing to affordable housing builders if it included carveouts aimed at attracting low- and middle-income residents.
For instance, Sunshine Mathon, executive director of the Charlottesville nonprofit Piedmont Housing Alliance, supports multifamily shared solar in theory but he’s far less intrigued by a program lacking affordability guardrails.
“The bottom line is that we’re going to advocate for something that makes financial sense for our residents,” he said. “They’re already struggling with enough cost challenges around every corner.”
Mathon is no stranger to solar energy. He’s currently overseeing the transformation of a public housing complex built in the late 1970s from an energy sieve into a community of energy-efficient homes. Part of that includes navigating the intricacies of installing rooftop solar panels that won’t empty residents’ wallets.
What should be appealing about solar is allowing customers the peace of mind of locking into fixed, long-term costs.
That predictability is nonexistent in the multifamily solar program wending its way through the regulatory process, he noted.
“I won’t say we would reject it, but I would look at any potential installation with a level of healthy skepticism as to whether it’s a good deal or not,” Mathon said. “I wouldn’t know that until I saw the details.”
A year after idling its first electric buses because of reliability problems, the transit agency serving Minneapolis and St. Paul has put the vehicles back on the road and released a plan to begin electrifying more of its bus fleet.
Metro Transit’s Zero-Emission Bus Transition Plan was submitted to the Legislature in February. It calls for spending a fifth of its bus acquisition budget over the next five years to purchase more than 100 electric models.
The plan comes as Metro Transit works to catch up with agencies in comparable cities and recover from a bumpy pilot program that resulted in the sidelining of eight 60-foot articulated buses for about a year while it addressed mechanical and charging problems. The buses were placed back in service in December.
Since then, “they have been performing very well,” said Nick Thompson, Metro Transit’s deputy general manager for capital programs. The buses were built by Minnesota company New Flyer, which made significant software upgrades.
The agency’s net-zero bus plan details the problems experienced during its pilot program. The electric buses generated a high number of service calls compared to its diesel buses, but those dropped by two-thirds following upgrades and incremental maintenance.
The transit agency reconfigured heating controls and addressed wheel slippage issues. All of the Siemens chargers were replaced in 2021 while still under warranty due to technical problems that included blown fuses and premature transformer failure.
It’s been about two decades since Metro Transit introduced electric-diesel hybrid buses, which now constitute more than 10% of its 900 vehicle bus fleet. The agency started using particulate matter traps in 2007 and introduced diesel exhaust fluid three years later to reduce nitrous oxide emissions. In 2012, Metro Transit added solar to facilities and in 2016 began testing non-revenue electric transit vehicles.
The net-zero emissions report was requested and funded by the Legislature, which allocated $250,000 last year for the study. Other transit agencies highlighted in the report are moving faster on electrification. Toronto plans to add 300 electric vehicles by 2025. Seattle is aiming for 250 by 2028.
Net-zero buses will be effective in reducing particulates and other pollutants in low-income neighborhoods that suffer the highest levels of greenhouse gases and respiratory-related illnesses. But the overall impact may be minimal. The state’s transit and school bus fleet produce just .7% of the state’s greenhouse gas emissions, with Metro Transit constituting .4% of that total. In contrast, passenger vehicles, including light-duty trucks, represent nearly 58% of emissions. Metro Transit believes system improvements will help move people out of cars and onto transit.
Thompson said Metro Transit feels confident about the future of electric buses because the technology continues to improve. Stakeholders who participated in the study universally supported more investment in electric buses. “We did find the interest among riders and stakeholders surprised us, in a good way,” Thompson said.
Metro Transit’s plan focuses on using standard-length, 40-foot electric buses in core neighborhoods. The challenges during the pilot program were in part due to its use of longer, 60-foot articulated buses on a suburban commuter route that only allowed them to partially recharge their batteries after completing routes.
“Our zero-emission bus plan assumes our deployment and expansion of electric buses would be without inline chargers,” Thompson said. “We want to secure buses that can be charged overnight and then operate their routes during the day on that charge.”
Equity was one measure for route selection, as was proximity to five bus garages with chargers. A new garage opening next March near the agency’s headquarters near downtown Minneapolis will be able to accommodate several electric buses serving the core cities.
Riders will not see electric buses on express routes or bus rapid transit corridors with articulated buses, Thompson said. Those routes may have electric buses in the future, but they will not be a priority for now, he said. Two upcoming new lines connecting St. Paul with northern and eastern suburbs will use electric buses.
Still, some advocates want faster adoption of net-zero buses. Sam Rockwell, executive director of the transit advocacy organization Move Minnesota, questioned why the agency did not commit to replacing all buses with electric models or consider trolleybuses operated by overhead electric lines. The agency “shouldn’t be buying diesel buses anymore,” he said.
One big factor is funding. The Legislature has not decided how much money Metro Transit will receive to help pay for the new buses. Gov. Tim Walz has recommended $3.2 million in his proposed state budget, enough to pay for just four electric buses. State Rep. Frank Hornstein, a Minneapolis Democrat, said legislators will propose more money, but the amount has not been determined.
“I think we have a broader challenge of transit funding and making sure we can build for a 21st-century system that gets people where they want to go, when they want to go, and quickly,” Hornstein said.
The plan puts the agency in a position to win federal funding under last year’s bipartisan infrastructure law, which includes $7.5 billion for electric bus expansion to transit agencies with an electrification plan. “We’re ahead of other markets because we’re done and ready,” Thompson said. In addition, he said the agency expects prices will drop, just as diesel hybrid buses did after the agency first began buying them 20 years ago.
Metro Transit has already ordered eight Proterra 40-foot buses using federal grant money. The agency has also applied but has not received approval for federal infrastructure funding to buy electric buses from the bus manufacturer Gillig. The agency plans a general procurement for electric buses later this year, allowing manufacturers to compete against one another for a contract that will last several years.
Metro Transit must also retrofit bus garages with chargers, an expensive proposition. Xcel Energy, the agency’s partner, needs to ensure the electric grid is ready to serve those charging bays. However, national data on electric buses show they get an equivalent of 16.5 miles to a gallon compared to 3.8 miles for a diesel fleet.
Joshua Houdek, senior program manager for land use and transportation at the Sierra Club, said he had been hopeful that problems in the initial electric bus pilot would not dissuade the agency from further investment. “The Metro Transit struggled with the first buses but got them working and back on the road again,” he said. “The experience taught the agency that, for now, the best buses that work for the system will be shorter buses running on tight urban routes that serve a lot of riders. This is efficient and equitable.”
Alireza Khani, an associate professor at the University of Minnesota’s Department of Civil, Environmental, and Geo-Engineering, recently helped author a study of bus electrification in the Twin Cities. The results showed the five most beneficial routes roughly matched Metro Transit’s approach. The routes had among the highest ridership and traveled through diverse, low-income communities. “I think it makes sense to prioritize those neighborhoods and buses that run in those neighborhoods,” Khani said.
Thompson said much still needs to be learned as electric buses move into the system. For example, the agency wants to continue to understand how bitterly cold weather impacts performance. In borrowing a practice from Duluth, the state’s first transit agency to have electric buses, Metro Transit will use natural gas heaters to avoid draining the batteries to heat buses, he said.
Mechanics must also be trained to work on electric buses, which has been a good problem to have, he said. “We have a workforce that actually just wants to work on the vehicles and we see [electric buses] as a way to attract workforce,” he said.
Thompson said net-zero buses are reshaping how Metro Transit powers the region’s bus transportation system and with that challenge will inevitably come hiccups that will lead to more operational changes. “This still is a technology in its infancy and is evolving very quickly,” he said.
Connecticut environmental officials are pushing for legislation that would grant condo owners and renters the right to install their own car chargers, part of a broader effort to dramatically expand the state’s electric vehicle charging infrastructure.
The so-called right-to-charge legislation would prevent condominium and homeowners’ associations, as well as landlords, from prohibiting or “unreasonably” restricting residents who have a designated parking space from installing charging equipment.
Individual residents would be responsible for paying all of the costs associated with the purchase and installation of a charger, which can easily exceed $1,000. But a new state incentive program launched in January could help defray the expense.
Homeowners can receive rebates of up to $500 for a Level 2 charger, as well as up to $500 for any electrical upgrades that might be needed. Various incentives are available for multi-unit rentals, either through the landlord or tenants. Participants can also receive additional credits for charging their vehicles in off-peak hours under demand response programs administered by Eversource and United Illuminating.
A right-to-charge law will help ensure that “the opportunities available to single-family home dwellers to own electric vehicles and participate in demand response programs are also available to those who live in multi-unit dwellings,” about 11% of Connecticut residents, said state Department of Energy and Environmental Protection Commissioner Katie Dykes in testimony submitted to the legislature’s Energy and Technology Committee.
At least eight states have similar laws in place: New York, New Jersey, California, Hawaii, Virginia, Oregon, Maryland and Florida.
But at a recent public hearing on the Connecticut bill, organizations representing condominium associations and landlords opposed the measure, saying it is a “one size fits all” approach to housing developments that vary widely in size, layout, infrastructure and parking availability.
Andrea Dunn, a condominium association lawyer from North Haven, said installing individual chargers “may be impossible” in some communities due to challenges such as a lack of an electrical source close to parking areas, thereby requiring the digging up of land, sidewalks and other common elements.
“Even if the unit owner is paying for it, it affects other members of the community,” she said.
Karl Kuegler, Jr., director of community association management for Imagineers LLC, which manages about 200 common interest communities in Connecticut, said many of the standalone garages with multiple bays commonly found at these complexes “have barely enough electricity to supply the lighting and a couple of utility outlets within the building.”
Condominium lawyers had similar concerns when right-to-charge legislation came before New Jersey lawmakers in 2020, but they were able to amend the language to address those issues, said Matthew Earle, an attorney who chairs the legislative action committee for the state chapter of the Community Association Institute.
For example, “one big concern was that older complexes may not have the electrical infrastructure sufficient to handle more than a couple of chargers,” he said.
So the law includes a provision that says if charger installations are going to require infrastructure improvements to provide a sufficient supply of electricity, the association can assess that cost to the charger owners in a pro rata way.
Since its passage, Earle says he has not heard any reports of negative impacts. At the same time, he also hasn’t seen many car charger applications within the communities he works with. Instead, the trend is toward associations installing communal car chargers.
“They are taking advantage of a state program that will provide up to $30,000 to install one — it’s very popular right now,” Earle said. “It seems like a better way of doing it.”
In such cases, buildings partner with a third-party vendor that provides the software that regulates the station and charges vehicle owners for plugging in, he said.
Connecticut’s charger incentive program offers up to $20,000 for charging equipment installed at a multi-unit development, and up to $40,000 in underserved communities.
But communal chargers run by third-party vendors may not be the most equitable solution in buildings that house people of lower means, said Marc Geller, a co-founder of Plug In America, a national nonprofit advocacy group for electric vehicle drivers.
“The real problem with a third party doing it is that folks in multifamily housing end up paying more for electricity to charge their car than folks in a single-family home,” he said. “Solving this problem for multi-family homes is a major equity concern, and there is not just one solution.”
Right-to-charge laws “go some way to give folks the possibility of installing charging, but it can be quite expensive to do it,” he said.
Where possible, he said, he believes the best approach is to connect a parking space to an individual unit’s meter, so that the resident can simply charge on a regular 120-volt circuit. It’s slower than a Level 2 charger, but it allows the resident to charge at utility rates and without a lot of additional expense, he said.
Gannon Long, director of policy and public affairs at Operation Fuel, which provides energy assistance to low-income households in Connecticut, said she hasn’t heard that the right to charge is of any concern to the financially burdened residents of environmental justice communities.
“People aren’t worried about their right to charge — they’re worried about electricity and heating costs,” she said. “And most electric vehicles are way too expensive for most people to afford.”
Right-to-charge language is also included in Senate Bill 4, a comprehensive package that includes a host of measures to drive electric vehicle adoption, including expanding the state electric vehicle rebate program, and setting goals to electrify all school buses and state-owned vehicles. A public hearing is scheduled for Friday.
Shipbuilders in the port city of Brownsville, Texas, are nearing the halfway mark on shaping 14,000 tons of steel into a vessel designed to ensure the country’s gamble on offshore wind is less dicey.
Meanwhile, 1,676 miles east in Virginia, executives with Richmond-based Dominion Energy who ordered the ship have their fingers crossed.
They are hopeful home-state regulators will greenlight a request by their subsidiary, Dominion Energy Virginia, to deploy the $500 million colossus to “plant” the country’s hugest — and Virginia’s first — full-scale commercial offshore wind farm beginning in summer 2025.
Dominion has dubbed its hulk Charybdis, after the daunting sea monster of Greek mythology. Eventually, the brawny, 472-foot-long vessel will be equipped with sturdy “legs” that stabilize it on the seafloor and a main crane capable of toting 2,200 tons — the equivalent of 4,400 grand pianos.
The looming challenge of efficiently securing 176 mega-turbines to the ocean floor off the coast of Virginia Beach is what prompted the parent company to dip its corporate toe into ship construction.
After enduring a convoluted but ultimately successful process to install its precursor two-turbine pilot project in 2020, Dominion decision-makers are confident that investing in the nation’s first specialized installation vessel is wise — and potentially lucrative.
“The pilot helped educate us,” said Charlotte McAfee, director of construction projects at Dominion who has guided progress on Charybdis since early October. “It showed us that this commercial project is really best managed with a vessel with a U.S. flag.”
Even if the State Corporation Commission nixes the utility’s proposal for Charybdis to install what’s known as the Coastal Virginia Offshore Wind (CVOW) project, Dominion doesn’t expect the giant expensive ship to sit idle.
In fact, it is already chartered to handle turbine installation duties for two separate offshore wind projects in the Northeast slated to be completed before Dominion’s 2,640-megawatt farm.
As well, Dominion figures Charybdis can continue to be a workhorse as the Biden administration has set a goal of reaching 30 gigawatts of wind power by 2030 along the Atlantic and Gulf coasts and in Pacific waters.
“Dominion has really been pioneering on this front,” McAfee said. “I’m proud to be part of it.
“We’ll find good uses for the vessel whether we’re permitted to use it for CVOW or not. The market is ready for the whole United States and this is the best way to install renewable energy.”
One monumental hurdle to harvesting the ample wind along U.S. coastlines is the lack of homegrown industries that craft the foundations, blades, nacelles (which house the generating parts) and other distinctive components fitted together to create the sophisticated turbines. Now, they withstand lengthy and expensive journeys from Europe, where the industry has matured.
Another key obstacle is the obscure Merchant Marine Act of 1920. Known as the Jones Act, it shields domestic shipbuilding enterprises by restricting water transportation of cargo between U.S. ports to American-built and -owned vessels crewed by U.S. citizens.
Charybdis represents Dominion’s commitment to advancing American offshore wind out of its longtime infancy.
Offshore wind is crucial if the investor-owned utility’s portfolio is expected to achieve 100% carbon-free electricity generation by 2045, as required by the 2020 Virginia Clean Economy Act. The utility is also intent on reaching net-zero carbon dioxide and methane emissions goals by 2050.
The Coastal Virginia Offshore Wind project, scheduled to go online in 2026, will power the equivalent of 660,000 homes.
Karl Humberson, a marine engineer hired by Dominion in 2011, oversaw progress on Charybdis before McAfee inherited those duties. He is responsible for the installation and construction of the wind farm.
Four years ago, the company tasked Humberson with exploring potential turbine installation solutions. In May 2020, Dominion announced it was leading a consortium to build a Jones Act-compliant vessel. By autumn, the company had contracted with the global firm KeppelAmFELS to build Charybdis in Texas.
Humberson is aware insiders and outsiders are curious why an energy company took the initial plunge on a vessel that might not even ply Virginia’s coast.
“Let’s take a couple of steps back and look at CVOW,” Humberson said. “The idea is that this is something necessary and aligns with Dominion’s renewable energy and sustainability goals.”
Investing in a “purposeful vessel,” he said, is a boon for all U.S. players intent on advancing wind.
“If you want to be successful, you want to have the right tools,” Humberson said. “What we’re saying is to expand the industry, here’s the only right way we know to do it right now.”
Assembling and installing the pilot — a pair of 6-megawatt turbines in federal waters adjacent to the larger wind farm — was a logistical headache due to lack of a Jones Act-compliant ship.
First, the components manufactured in Europe made a transatlantic journey on a cargo ship, the Bigroll Beaufort, which docked in Halifax, Nova Scotia.
There, the foundations were offloaded onto an installation vessel, the Vole-au-vent, and transported to the construction site off the coast of Virginia. Then, that same vessel completed a second trip from Canada with the turbine components on board.
“This time, we’ll have 176 turbines, not two, so coming down from Canada would not make a lot of sense,” Humberson said.
Without Charybdis in the picture, an alternative method is to put the components on a barge and transfer them to an onsite European vessel that could serve as the installation base.
“Using a barge and tugboat means double-handling everything,” Humberson said, emphasizing that turbine blades are fragile. “If you need to move this equipment, you want to do it once and you want to get it right.”
One of Charybdis’s benefits is providing an extremely stable work platform whether seas are calm or choppy, he said.
The height and weight of components are serious considerations. For instance, blades for the pilot project measure 253 feet. The monopile foundations are 220 feet long and weigh 1,000 tons apiece.
Those measurements are diminutive when compared to the heavy lifts in store with the commercial project. For instance, the turbines — the largest available — have a capacity up to 14.7 MW. Just one of those turbines has more generating capacity than the entire pilot project.
A blade alone measures 354 feet — longer than a football field. And just the visible part of each turbine is skyscraper height, stretching a soaring 800 feet from the top of the ocean to the tip of a blade pointed straight up.
David McFarland, Dominion’s director of investor relations, knows $500 million is a whopping price tag for anything, never mind a unique Jones Act-compliant ship.
“What Dominion Energy is doing is showing confidence in the offshore wind industry” and opportunities for it to thrive domestically, McFarland said.
The question he fields most often: Who is footing that bill?
It’s not ratepayers — at least not directly. Instead, the ship is being built for the mammoth parent company that owns multiple subsidiaries nationwide, including Dominion Energy Virginia.
The majority of capital for funding Charybdis is being borrowed from third parties and banks, McFarland explained, adding that “making payments to banks is a shareholder expense, not something passed on to a utility customer.”
Leasing out Charybdis to other coastal wind projects allows the parent company to reap a return — somewhat indirectly — on that $500 million investment.
For instance, Dominion Energy Virginia has folded the cost of leasing — not building — Charybdis into its request before state utility regulators seeking the go-ahead for the entire $9.8 billion wind farm project.
“That lease is included in the cost of [the wind farm’s] construction,” McFarland said. “It’s spent on behalf of customers and is expected to be recovered from customers. Dominion Energy Virginia is looking to recoup that money.”
He is convinced Charybdis is a boon for the company’s utility customers.
“They’re better off with this vessel, because otherwise the cost [of turbine installation] would be higher,” McFarland said. “You do want the best solution for customers.”
Charybdis is on track to be completed on schedule by December 2023, McAfee said.
Thus far, Ørsted and its joint venture partner Eversource, are the first to book Charybdis for its Revolution and Sunrise wind projects. Their construction and operations plans are undergoing environmental review now.
Revolution is a 704-megawatt project designed to serve customers in Connecticut and Rhode Island, while Sunrise will provide electricity to New Yorkers. Both are expected to be operating by 2025.
Ørsted, a global leader in the wind industry, has also partnered with Dominion on both of its wind projects.
Dominion said it was unable to provide figures for the daily rental fee required because those numbers are “competitively sensitive.”
Willett Kempton, a professor at the University of Delaware who is a nationally renowned expert on offshore wind power, said wind developers negotiate those fees with Dominion.
Kempton said in an interview that he had heard from industry sources that those daily rates could be as high as $500,000, but didn’t know how accurate that number will turn out to be.
The daily fee for using a non-U.S.-made installation vessel is likely close to $250,000, he said.
While $500 million is a hefty sum to invest in a vessel with Charybdis’ capabilities, Kempton said somebody had to go first seeing as “this is the only way the industry knows how to do installations.” One such installation ship likely won’t be enough if the U.S. wind industry booms as expected, he added.
Companies without access to Charybdis or a similar vessel will likely resort to a feeder barge system as a stopgap solution to keep their wind projects on schedule, he said.
The Department of the Interior’s Bureau of Ocean Energy Management has approved construction and operations plans for two other offshore projects: 800-megawatt Vineyard Wind in Massachusetts and 130-megawatt Southfork Wind in New York.
By 2025, the agency has vowed to advance new lease sales and complete review of at least 16 construction and operations plans, which represent more than 19 GW of renewable energy.
Charybdis will be based in Hampton Roads and staffed with U.S. crews. It’s one enormous piece of Virginia’s attempt to transform its existing regional advantages — a robust maritime workforce and a port in Norfolk with deep water and no height restrictions — into a supply chain hub.
“The supply chain is in Europe,” Humberson said. “There’s a lot of talk about building it up in this country, but it’s not here yet.”
As evidence, he pointed to Germany, Denmark, Finland and Italy as sources for turbine components and affiliated infrastructure. Most of it is destined for a 72-acre site at the Portsmouth Marine Terminal. That space will serve as a staging and pre-assembly area, courtesy of a 10-year lease with the Virginia Port Authority.
The terminal also will house a blade-finishing factory operated by Siemens Gamesa Renewable Energy, the company contracted to deliver the 176 CVOW turbines. That work entails sanding and adding protective coatings to the prebuilt blades.
Beginning in 2024, while Charybdis is readying for the two wind projects in the Northeast, Dominion plans to begin driving turbine foundation monopiles into the ocean bed at the 112,800-acre CVOW lease area. The site begins 27 miles offshore and extends 15 more miles out into the Atlantic.
The largest of those 176 steel monopiles, manufactured in Germany by EEW Special Pipe Constructions, is 268 feet long and weighs 1,755 tons. Into 2025, a separate company will transport, position and secure those foundations without the aid of Charybdis.
To protect the North American right whale, the window for that underwater chore is between May 1 and Oct. 31, per National Oceanic and Atmospheric Administration regulations.
When Dominion’s McAfee graduated from law school at Washington & Lee University in 2004, she figured pumps and suits would dominate her career wardrobe.
That changed after the young attorney was hired by the utility a decade ago. Eventually, she began amassing steel-toed boots as she pivoted to electric transmission and distribution projects.
Those boots are again serving her well for her regularly scheduled trips from Richmond to the Brownsville shipyard to monitor Charybdis’ progress.
“It’s not like I’m inspecting the welds, but I’m getting a sense of what I need to be coordinating at the shipyard,” she said. “In-person visits keep the communications open and candid.”
Devotees of Homer’s ancient and epic poem “The Odyssey” know that the mega-ship’s ferocious namesake lurked in a narrow passage between the island of Sicily and the toe of Italy’s boot. The monster was reputed to swallow the sea three times daily, causing a whirlpool that thwarted the protagonist as he sailed home from the Trojan War.
Part of McAfee’s job is ensuring that this version of Charybdis doesn’t wreak any such havoc before it’s ocean-bound.
So far, so good, despite two challenges. One was covering for her lack of maritime experience by burrowing into volumes about shipping. And the other was navigating an immense undertaking in the thick of a pandemic.“As far as the construction goes, Charybdis is a teenager now,” she said. “It’s just an honor to be involved. Once we’re finished, it will be ready to self-propel to Hampton Roads.”
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