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The following commentary was written by Charles Hua, policy analyst at Rewiring America; Ana Sophia Mifsud, a manager within the Rocky Mountain Institute’s (RMI) carbon-free building team; and Robin Lisowski, managing director of policy at Slipstream. See our commentary guidelines for more information.
The Inflation Reduction Act is an unprecedented investment in clean energy and provides a transformative opportunity for Michigan to move toward a healthier, more affordable, and safer future.
By signing this groundbreaking bill into law last year, President Biden directed nearly $400 billion in federal funding for climate initiatives through a mix of tax incentives, grants, and loan guarantees. Depending on household income, Michigan residents can take advantage of tax credits — and soon up to $14,000 in rebates — for making homes less dependent on fossil fuels and more efficient, including technologies like heat pumps and insulation.
But still, states like Michigan have a huge role to play by leveraging these millions in federal funding to invest in clean energy and ensure households are powered by resilient, healthy, and affordable sources of energy.
Michigan has already taken steps toward securing the benefits of clean energy. In 2020, Governor Whitmer committed the state to economy-wide carbon neutrality by 2050. A year later, the state developed the MI Healthy Climate Plan (MHCP) that charts a path to reach a goal halving emissions by 2030. Just last week, Governor Whitmer was one of the 25 members in the bipartisan coalitions of the U.S. Climate Alliance who committed to collectively reach 20 million residential electric heat pump installations by 2030 — potentially quadrupling the number of residential heat pumps currently in operation. The state legislature is currently considering implementing a clean energy standard, which could single-handedly put Michigan over three-quarters of the way to its 2030 climate goals.
Unfortunately, bad faith actors determined to keep homes reliant on inefficient and dirty energy sources would have you believe that Michigan lawmakers are wheeling and dealing behind closed doors to ram through sustainable initiatives without any public debates. But nothing could be further from the truth.
The Department of Environment, Great Lakes, and Energy has been soliciting feedback from the public on implementation priorities for the MHCP, and Governor Whitmer has already signed several bipartisan pieces of climate legislation into law.
The benefits these clean energy initiatives will bring to Michigan households can’t be understated.
This June, Michigan paid the 11th highest rate for energy in the country: 19 cents per kilowatt per hour — well above the national average. This is even more harmful to low-income communities. While the average Michigan household spends 3% of its annual income on energy, low-income households spend upwards of 15%. Furthermore, in the Midwest the cost of fossil fuel expenditures for heating has steadily increased since 2019. We can expect for fuel costs to continue to increase in Michigan. A recent analysis of Michigan’s gas utility, Consumer Energy, which provides gas service to nearly 2 million Michigan households, predicts that gas bills will increase 49% in 2030 compared to 2021. This is partly because the utility plans to spend $11 billion in infrastructure investments in their gas distribution system between now and 2030.
By installing a heat pump, which can both heat and cool a home using electricity, the Department of Energy estimates that many American households can save significantly on operating costs. Households will have one appliance that does the job of both a fossil fuel heating system and a traditional AC unit — and does both jobs better. Heat pumps are more effective at maintaining a comfortable and consistent temperature, even during peak summer or winter days, and are 3 to 5 times more efficient than most fossil fuel heating systems. Households that heat with delivered fuels, like propane, are expected to benefit most.
Induction stoves are also safer than gas options. Induction stoves are also safer than gas options. 12.7% of childhood asthma cases in the US are linked with emissions from gas stoves, and cooking for just one hour can aggravate the condition. In fact, 75% of emissions from a gas stove — including the carcinogen benzene — leak even when the stove itself is off.
Of course, Michigan will have to build out the infrastructure to support carbon neutrality by 2050. But doing so will mean jobs. Since the IRA was signed a year ago, nearly 200,000 clean energy jobs have been created in the Great Lake State to support electric vehicle manufacturing alone. In fact, the state is predicted to see a GDP growth increase of 2.5% above the current baseline growth rates by 2050 as a result of the clean energy jobs and IRA investments.
Clean energy is the future Michigan residents want. More than half of Michiganders supported the IRA when it first came out, and a whopping 71% wanted the state to secure more federal dollars. A poll released in April showed 73% of Michiganders want their government to do more to keep energy bills affordable — and these federal incentives offer a distinct opportunity to do just that.
Federal funding offers the state a huge opportunity to bring in long-term jobs and help households switch to safer, more affordable, and more efficient appliances. It’s the future that all Michiganders deserve.
This article was originally published by Maine Monitor.
Correction: An earlier version of this story misstated the tax relief for heat pumps and other home energy saving projects that is available under the Inflation Reduction Act. One aspect of the IRA incentives is a rebate for heat pumps and other home electrification projects that is still being finalized by the state. The story also misstated a rebate available for small scale home sealing and other do-it-yourself projects. That rebate has expired.
Venus Nappi strolled through a community center in South Portland in early April, chatting with vendors at Maine’s annual Green Home + Energy Show about electric heat pumps, solar power, and the discounts that aim to make these and other technologies affordable. A worker in an oversized plush heat pump costume waved a gloved hand nearby.
Nappi heats her Gorham home with oil, as do 60% of Mainers — more than any other state, as The Maine Monitor reported in the first part of this series. She finds oil to be dirty, inconvenient and expensive. Her oil costs this winter, she said, were “crazy, absolutely right up through the roof.”
Nappi joined a record-breaking crowd at this expo because she’s ready to switch to heat pumps, which can provide heating or cooling at two or three times the efficiency of electric baseboards and with 60% lower carbon emissions than oil, according to Efficiency Maine.
“It’s good to have incentive to try to go somewhere else rather than just the oil,” Nappi said. “Even gas, propane, is actually a little expensive right now, too. The heat pumps are kind of in the middle.”
Government rebates of up to $2,400, with new tax breaks coming soon, help with up-front heat pump installation costs that can range above $10,000. These incentives have helped put Maine more than 80% of the way to its 2019 goal — now a centerpiece of the state climate plan — of installing 100,000 new heat pumps in homes by 2025, and many more in the years after that.
“This is a real highlight of our climate action,” said state Climate Council chair Hannah Pingree. The state aims to have 130,000 homes using one or two heat pumps by 2030 and 115,000 more using “whole-home” heat pump systems, meaning the devices are their primary heating source.
But Maine lags much further behind on a related goal of getting 15,000 heat pumps into low-income homes by 2025, using rebates from MaineHousing. At the end of last year, it had provided just over 5,000 heat pumps to the lowest-income homes.
These homes face particular barriers to maximizing the benefits from this switch — from poor weatherization, to navigating a daunting web of incentives, to fine-tuning a blend of heat sources that can withstand power outages and actually save money instead of driving up bills.
As fossil fuel costs remain high, the pressure is on for advocates and service providers to expand access to heat pumps and other strategies for reducing oil use, especially for people most often left out of the push for climate solutions.
In Maine and beyond, it’s clear that heat pumps are having a major moment — heralded in national headlines as a crucial climate solution that successfully weathered a historic cold snap.
But the technology is not new. It’s long been used in refrigerators and air conditioners.
“The problem was, when you design a heat pump to primarily provide cooling … it is not optimized for making heat,” said Efficiency Maine executive director Michael Stoddard. “So everyone concluded these things are no good in the winter. And then around (the) 2010, ’11, ’12 timeframe, the manufacturers started introducing a new generation of heat pumps that were specially designed to perform in cold climates. … It was like a switch had been flipped.”
Maine has offered rebates for heat pumps ever since this cold climate technology emerged. Even former Gov. Paul LePage, a Republican who frequently opposed renewable energy and questioned climate science, installed them in the governor’s mansion and told The Portland Press Herald in 2014 that they’d been “phenomenal” at replacing oil during a cold snap.
Heat pumps provide warmth in cold weather the same way they keep warmth out of a fridge — by using electricity and refrigerants to capture, condense and pump that heat from somewhere cold to somewhere warmer. Simply put, they squeeze the heat out of the cold air, then distribute it into the home.
The current generation of heat pumps will keep warming your home even if it’s around negative 13 degrees out.
Heat pumps are less efficient in these colder temperatures, requiring more electricity to make the same heat. With outdoor temperatures in the 40s and 50s, today’s typical cold-climate heat pumps can be roughly 300 or 400% efficient — tripling or quadrupling your energy input.
As temperatures drop into the teens, heat pumps are often about 200% efficient. And in the single digits or low negatives, heat pumps can be closer to the 100% efficiency of an electric baseboard heater. Costs at this level are closer to that of oil heat, which usually has about an 87% efficiency rating.
This means heat pumps often generate the most savings and are most efficient when temperatures are above freezing, or when used to provide air conditioning in the summer — something Mainers will want increasingly as climate change creates new extreme heat risks.
“During the shoulder seasons, you can definitely use a heat pump. When it’s wicked cold out, then you’d probably turn on your backup fuel. That’s not the official line of Efficiency Maine Trust, but a physical and engineering reality,” said energy attorney Dave Littell, a former top Maine environment and utilities regulator whose clients now include Versant Power — which, along with Central Maine Power, now offers seasonal discounts for heat pump users.
This is a relatively common approach among installers, such as ReVision Energy, a New England solar company that also sells heat pumps. They don’t recommend heat pumps as the only heating source for most customers, especially those who live farther north, unless the home can have multiple units, excellent insulation, and potentially a generator or battery in case of a power outage — a costly package overall.
“(Heat pumps) do still put out heat (in sub-zero weather), but less, obviously, and they have a lot more cold to combat in those conditions,” said Dan Weeks, ReVision’s vice president for business development. “Generally … we do recommend having a backup heating source.”
These blends of heating sources are nothing new in Maine — many families combine, say, a wood stove with secondary heat sources that rely on propane, oil or electricity. Experts say heat pumps are a powerful addition in many cases, adding flexibility and convenience.
Heat pumps will add to your electric bills but also reduce another expense that’s eating up a lot of household budgets — heating oil. Instead of spending hundreds to fill your tank just as winter starts to wane (a full 275-gallon tank would run more than $1,000 right now), you might be able to switch entirely to your heat pump in early spring. Vendors say a heat pump will be much more cost-effective than fossil fuels for the vast majority of Maine’s heating season.
One study from Minnesota — which has lower electric rates and more access to gas, but has made a similar push for heat pumps — found the greatest savings from using a heat pump for 87% of the heating season, switching to a propane furnace only below 15 degrees.
Electricity costs also change less frequently than fossil fuel prices. And the advent of large-scale renewable energy projects, like offshore wind, aims to help smooth over rate hikes that are now driven by the regional electric grid’s dependence on natural gas, said Littell of Versant Power. (While Maine has little gas distribution for home heat, New England power plants use a lot of it to make the electricity that’s primarily imported to Maine on transmission lines.)
This will also mean the electricity that fuels your heat pump will be even lower-emissions than it is now. The emissions comparison between heat pumps and oil is based on the current New England electric grid’s carbon footprint, which is set to continue shrinking.
Paige Atkinson, an Island Institute Fellow working on energy resilience in Eastport, pitches heat pumps as a good addition to a home fuel mix. But she said all these cost comparisons can cause anxiety for people unsure about switching. Oil costs, though rising and prone to fluctuations, can be a “devil you know” versus heat pumps, she said.
“Transitioning to an entirely new source of heat creates a lot of ‘what-ifs,’ ” she said. “There’s a lot of uncertainty about how to best use that system — will it meet my needs?”
The best way to guarantee savings from a heat pump is likely to work closely with your contractor about where to install it, and when and how to run each part of your home’s fuel mix.
“Our job is to educate (customers) on proper design, proper sizing, best practices for installation,” said Royal River Heat Pumps owner Scott Libby at the South Portland expo. “I always tell people to use the heat pump as much as possible. … If you are starting to get chilly, that might just be for a couple hours in the morning when the temperature outside is coldest, so maybe use your fossil fuels just to give the system a boost in the morning, for even an hour.”
The condition of your house is another big factor in the heat pump’s performance.
“Weatherization is a great tool. It is not necessary to make a heat pump work … but the heat pump will work better if the house is well weatherized,” said Stoddard with Efficiency Maine. “When you have those super, super cold days, it won’t have to work as much.”
The need, ideally, for updated insulation and air sealing as prerequisites for heat pumps may help explain the slower progress on getting them into low-income homes. (We’ll address heat pumps as a potential benefit for renters later in this series.)
“I think a lot of the homes especially that (qualify for rebates from) MaineHousing … require a lot of upgrades, just sort of basic home improvements, to get to the next step,” said Hannah Pingree of the state Climate Council.
Bob Moody lives in the kind of house Pingree is talking about in Castle Hill, a tiny town just outside Presque Isle. The ramshackle clapboard split-level totals four stories, set into a wooded hillside. Moody grew up down the road, and his family built this place in the 1980s using much older scrap materials from the former Loring Air Force Base in Caribou.
On a snowy day in March, Moody was visited by a small team from Aroostook County Action Program, or ACAP. It included his next-door neighbor, ACAP energy and housing program manager Melissa Runshe. She and her colleagues were there for an energy audit, a precursor to weatherization projects — all paid with public funds through MaineHousing.
“Weatherization is at the very top. If your heat isn’t flying out of your house, it’s going to save you money,” Runshe said. “We have a lot more winter here (in Aroostook County) than in the rest of Maine, so it’s really important to make sure that the houses are energy-efficient — so that they’re not burning as much oil, so that they’re not spending as much money on oil.”
ACAP officials said they don’t push any technology over another when meeting new clients, but instead describe the options and benefits — savings, comfort, a smaller carbon footprint. This all typically happens after someone has called for heating aid or an emergency fuel delivery — or, in Moody’s case, an emergency fix for their heating equipment.
Moody’s health forced him to retire early, and he now lives alone on a low fixed income. He’s gotten energy assistance and upgrades from other state and county programs before, but first called ACAP late last year when his main heat source, a kerosene furnace, suddenly died. ACAP got him a new, more efficient oil furnace, then signed him up for a weatherization audit.
“If it hadn’t been for assistance, I would have been really in trouble,” Moody said as he filled out paperwork at his kitchen table. A sticker on the wall proclaimed Murphy’s Law — anything that can go wrong, will. “Murphy has been settling in very heavily on me,” he laughed.
Moody’s ACAP audit included a blower door test, which depressurizes the house to expose air leaks. They showed up on a thermal imager as cold seeping in through window seams, power outlets, hairline cracks in the walls, and most of all, an uninsulated exterior-facing wooden door that was down the hall from Moody’s new furnace, sucking heat from the rest of the house.
“He has, roughly, a (total of a) one-by-two-foot-square hole that’s wide open in the house,” said energy auditor BJ Estey. “It’s basically like the equivalent of having a window open year-round.”
The inspection showed weatherization could save Moody $1,230 a year on oil. New windows and doors would help even more — but the weatherization program doesn’t offer those, and there’s a 900-person waiting list for ACAP’s program that does. Instead, the staff told Moody to try a federal option for home repair grants and loans, and promised to help him with the forms.
For people who don’t receive MaineHousing-funded upgrades, Efficiency Maine offers healthy rebates for air sealing and insulation performed by contractors. Last winter it also added a small new rebate for do-it-yourself home weatherization, such as plastic wrap for windows, pipe wraps and caulk, which has since expired.
Groups like ACAP also offer free heat pumps for low-income residents using MaineHousing funds. The rebates feed the state’s goal, where progress has been slow.
Moody has one kind of heat pump in his home but it’s not the type that provides hot air — it’s a heat pump-based hot water heater, which he got for free through a rebate from Efficiency Maine. He loves the savings and convenience it’s provided.
But he doesn’t think an air-source heat pump — the kind that can replace an oil furnace — will work for his home, which has many small rooms split up across levels. (Installers often recommend at least one heat pump per floor.) He’s also worried about how a heat pump would affect his electric bills. He knows he couldn’t afford electric baseboard heat, so he’s concerned about the very cold conditions where a heat pump’s efficiency drops down to around that level.
“Sometimes in the middle of the winter, you get so cold that you just might as well have an electric (baseboard) heater,” he said. “And there ain’t no way that I can afford an electric heater — not even one month.”
Down the road in Castle Hill, Melissa Runshe’s newer-construction house came with three heat pumps, a boiler that can use wood pellets or oil, and a propane fireplace. “I think (heat pumps) are wonderful,” for heating when temperatures are above about 20 and for summer cooling, she said. “They definitely offset the cost of my oil.”
While not every house is heat pump-ready, it may be even more important to get folks like Moody connected with this energy safety net in the first place. This will continue to decrease his oil dependence, offering escalating upgrades as his home changes and funding sources shift.
“In the social services world, there’s this idea of ‘no wrong doors,’ and we need to adopt that for home energy as well,” said Maine Conservation Voters policy director Kathleen Meil, the co-chair of state Climate Council’s buildings group. “There’s no distilling and simplifying how people live in their homes. You experience your house and your home’s heating situation not as a data point, but as your daily life.”
For people like Meil, there are multiple goals working in tandem — help Mainers reduce their reliance on planet-warming fuels like heating oil, while helping them lower household energy costs, and live with more comfort and convenience. This is what climate advocates mean when they say the crisis is “intersectional” — it’s interwoven with health, race, poverty and more.
Juggling these issues can mean making more incremental progress toward emissions goals — but that’s far better than nothing in scientific terms, said Ivan Fernandez, a professor in the University of Maine’s Climate Change Institute.
“Everything we do, every increment we do, counts,” Fernandez said. “I think we need to do this transition in a relatively quick way, recognizing that it will be imperfect, and spending a good part of our focus on realistic, data-driven, science-driven tracking of where we are at, so we’re not telling ourselves fables that aren’t substantiated by the science.”
Officials say Maine used this kind of science in building detailed goals for things like heat pump adoption, adding them up toward a path to the two biggest targets that are inked in state statute — reducing emissions 45% over 1990 levels by 2030 and 80% by 2050.
“Ultimately the atmosphere will determine how successful we are. It’s already telling us that we have not been very successful in many ways,” said Fernandez. “But … I think we’re embracing the reality of that a lot better.”
Setting these goals carefully and pushing hard to meet them does not guarantee equity — and there are still holes in the state’s approach, according to people working on spreading the benefits of the energy transition to those who might not be able to access it without help.
The Community Resilience Partnership, or CRP, is the state’s signature grant program for town-level climate action. Each project starts with a local survey to determine residents’ priorities out of a 72-item list that includes everything from flood protection to energy efficiency.
State officials say the CRP was designed primarily to build up towns’ capacity to respond to climate change. But advocates say they’ve had to work around a crucial gap in the program: It won’t buy equipment directly for individuals, which is often what people say they want the most.
“There are communities who really do have the need to fund heat pumps beyond what Efficiency Maine is providing,” said Sharon Klein, an energy consultant and University of Maine professor who works with Maine tribes on their CRP projects. “Because there’s still that last piece of it where money still needs to be put up, and some people don’t have that money.”
For people whose income is not quite low enough to qualify for a totally free heat pump through MaineHousing, Efficiency Maine’s rebates will cover $2,000 for a first unit and $400 for a second. People at any income level can get $400 to $1,200 for one or two units. This might cover some or all of the cost of a typical single heat pump — but total installation costs can range from around $4,000 to above $10,000, depending on the complexity of the system.
Starting this tax year, the Inflation Reduction Act will offer new tax credits of 30% for heat pumps, up to $2,000 per year. The IRA will also provide additional rebates to cover heat pumps and other home electrification projects, but the details of those rebates are still being finalized. The IRA allows states to, in theory, offer as much as 100% of project costs up to $8,000 for low-income families, or 50% of costs for moderate-income families — but state officials are still deciding how exactly this limited pot of money will be used and who will be eligible. The rebates will not be universal or unlimited, said Stoddard with Efficiency Maine, but should benefit several thousand homes.
Dan Weeks of ReVision Energy said increasing availability of low- or no-interest loans is another priority for those who want to see more people switch from oil to efficient electric heat. The IRA will help Maine expand its Green Bank in the next year or so to “start offering financing to particularly low-income folks and folks with poor credit,” Weeks said.
But tax credits and cheap loans are still deferred ways of helping people lower their oil costs and cover those remaining heat pump costs. Downeast CRP coordinator Tanya Rucosky, who works on community resilience for Washington County’s Sunrise County Economic Council, said many families simply can’t afford to make the switch.
“Folks need just a little bit of seed money,” she said. Without more support, “it locks out the people that potentially need it the most.”
Atkinson, the Island Institute Fellow, said Eastport found a creative way to offer direct funding within the constraints of its CRP grant. People who participate in the city’s peer-to-peer energy coaching program, Weatherize Eastport, can get another $2,000 toward heat pump installation.
“They’re agreeing to become almost ambassadors for this program. One of the steps to do that is to volunteer some time,” Atkinson said. “The city is compensating these residents for their time involved in this partnership, rather than saying, we will just give you funds for X, Y and Z.”
Solutions like this are key to ensuring these tools for moving off oil can grow equitably, said Rucosky — helping more people to join the transition and spread the gospel of its benefits.
“Especially for Mainers — they’re so salty and smart. They’re like, ‘What’s the catch?’ So I don’t think there’s any getting around the labor of it,” Rucosky said. “The more people have successful experiences doing this, the more I don’t have to be the one saying it …and it can be like, Bob down the road. And so it builds — but it takes a long time to build that, where everybody knows this is how you get this done. That’s going to be years in the making.”
This article is co-published by the Energy News Network and Planet Detroit with support from the Race and Justice Reporting Initiative at the Damon J. Keith Center for Civil Rights at Wayne State University.
It’s that time of the year for reflection, whether personally or, in James Gignac’s case, on the progress Midwest states have made in pursuing clean energy goals.
Gignac is the Senior Midwest Analyst for the Climate & Energy program at the Union of Concerned Scientists. He shared with Planet Detroit some additional thoughts from his recent post about milestones reached by Michigan and its neighbors.
Q: Consumers Energy has a proposed plan that will come up for approval before the Michigan Public Service Commission in 2022. That plan includes burning natural gas. How can the MPSC hold utilities accountable for those proposed actions?
A: The utilities in Michigan, including Consumers Energy, are obligated to display ways to provide the lowest cost, cleanest and reliable energy for their consumers in the state using an Integrated Resource Plan.
While Consumers Energy has some really good features in their pending plan, including phasing out all of the coal plants by 2025 and making large investments in solar, there’s also the question of the role of methane gas, which is sometimes called natural gas.
The question is, what is the role of gas in their future resource plan? What Consumers Energy is trying to do is begin to map out how it will achieve the carbon reduction goals that it as a company has established.
While they’re not proposing to build new gas plants, they’re proposing to acquire existing gas plants. And what we and other advocates are concerned about is the transition away from coal and towards clean energy. Investing in gas resources is risky for customers because those gas plants could very quickly become uneconomic or unneeded.
And so while it’s good that the company is not wanting to build a new gas plant – which most utilities are moving away from, it’s still concerning from an economic perspective and because they still produce carbon emissions and other pollutants.
One of the facilities in particular concerns environmental justice advocates. Testimony submitted by our stakeholder coalition and others, highlights the environmental justice concerns of existing natural gas plants.
Q: What other items should we watch out for in Michigan in 2022 you’d like to highlight?
A: In 2021, especially in Michigan, we saw the increasing interest in demand from communities and customers to have greater control and greater amounts of locally-owned clean energy resources. We’re beginning to move away from the traditional model of utilities providing electricity to customers from faraway power plants.
DTE Energy will be filing an Integrated Resource Plan in the Fall of 2022, which is a year earlier than planned. The upside of that is that we will have a chance to look at DTE’s newest proposals a year earlier than expected. That’s important because we need to be moving quickly, and we need to urge utilities to continue taking rapid steps in a clean energy transition.
So looking ahead to 2022, the DTE Integrated Resource Plan and the important opportunity to review those current plans.
I’m also looking forward to seeing a strong action plan from the Council on Climate Solutions. Last year, Governor Whitmer’s executive order, the Council on Climate Solutions, has been working to develop an action plan to reach the state’s carbon reduction goals. We’ll see that quickly in 2022 as a draft will be released in mid-January, and the Council will then finalize that in February and March.
We’re hopeful that the document will be a strong plan for Michigan and include immediate and near-term steps that can be taken and lay out a long-term action plan for additional policies that can be put in place.
We also will have a Consumers Energy decision on its Integrated Resource Plan. So we’re hopeful that the Public Service Commission will approve the company’s plans to retire its coal plants and pursue its solar expansion. And ideally, either postpone or not approve all of the existing gas plants for acquisitions. So if there’s an opportunity to evaluate those further or ask the company to do some additional analysis to ensure cleaner energy options could be pursued instead of those gas plants.
And in Michigan’s legislature, I think it’s important to continue focusing on and discussing clean energy legislative proposals and to build the demand for taking action at the legislative level.
Q: There was a recent major win for Illinois – anything you want to share about it?
A: The Climate and Equitable Jobs Act (CEJA) was based on building upon and expanding previous legislation, so in 2017, Illinois passed the Future Energy Jobs Act. What advocates started doing immediately after that legislation passed was starting to think about the next set of policies that can be passed in Illinois, while identifying things that needed to be improved or changed from the 2017 legislation.
CEJA was the product of many conversations and discussions amongst a broad set of stakeholders, which led to its passing in 2021.
Centering the needs of lower-income communities and making sure that clean energy investments and benefits are shared amongst all Illinois communities is a key to making them a leading national leader in the equitable pursuit of clean energy and climate action.
Q: What else should Michigan consider in 2022 related to clean energy advocacy and policymaking?
A: I would say that crafting clean energy policies centering people and lower-income, traditionally disadvantaged communities. Doing that is important, but it’s also popular. People want to see equity being a key part of clean energy and climate responses.
So I think our work in 2021 really highlighted that and we have an increasing amount of good examples to draw from, whether it’s Illinois’ efforts or programs in other states that can be applied in Michigan and elsewhere.
Q: What’s next for UCS?
A: We’re looking to follow up on our Let Communities Choose Report in partnership with Soulardarity. In Highland Park, we’re working on analyzing a microgrid for the Parker Village neighborhood in Highland Park. So that would be an additional piece showing the potential for local clean energy.
We partner with many other groups doing great work in Michigan and at the state level, advocating the Council on Climate Solutions and the Michigan Public Service Commission.
Refunds for unlawful utility charges are a top priority for Maureen Willis, the veteran litigator who became Ohio’s new consumers’ counsel this month.
The Office of the Ohio Consumers’ Counsel is a state-funded agency that represents ratepayer interests in gas and electric utility cases, including matters relating to House Bill 6, the 2019 law at the heart of Ohio’s nuclear and coal bailout scandal. The office also works for legislative reform to promote competition, eliminate subsidies and protect energy affordability for vulnerable groups.
The Energy News Network spoke with Willis about her agenda as Ohio’s official advocate for residential ratepayers.
“If consumers are charged and there’s a decision by the court or even a federal agency that the charges were unlawful or unreasonable, we think they should get the refund all the way back to when they paid it,” Willis said.
Instead, a majority on the Ohio Supreme Court has held that a 1957 case against “retroactive rulemaking” forbids refunds of charges, called riders. That’s the case even if the court holds the charges are otherwise unlawful or unreasonable and even if the riders were not part of a full ratemaking case.
So, even though the Ohio consumers’ counsel has helped consumers avoid $433 million in charges since 2009, they’re still out $1.5 billion in refunds. That makes the wins something of a “hollow victory, because you’re not getting that money back,” Willis said. “But we will continue to fight.”
“We want to advocate for consumers to get energy at the least cost,” Willis said, noting the agency generally considers itself agnostic on the source of electricity. Nonetheless, “renewables are becoming more and more economic, and that certainly is something that we take into account in the mix,” Willis said.
A 2023 report by Energy Innovation Policy & Technology found that 99% of U.S. coal plants are more costly to keep running than replacing them with new solar, wind or energy storage.
Yet HB 6 and regulatory rulings before it require Ohio ratepayers to subsidize costs for two 1950s-era coal plants. OCC continues to contest those charges.
“To the extent that there are subsidies built into the rate and those subsidies are attached to monopoly rates, it creates a problem” by undermining the market, Willis said. “In Ohio, we do rely on the competitive market to bring consumers lower prices and greater innovation.”
“From our perspective, energy efficiency is a good thing,” Willis said, noting that it can help reduce people’s utility bills. Ten years ago, Ohio law required utilities to meet an energy efficiency standard. Back then, OCC was among parties pushing regulators to require FirstEnergy to bid that energy efficiency into a capacity market auction, which lowered costs to consumers. But in 2019, HB 6 gutted Ohio’s energy efficiency standard.
Now, though, consumers can get energy efficiency products and services from competitive suppliers, Willis said. So, “we would say that the utility really has no business to be in the energy efficiency business anymore.” OCC also objects to “shared savings,” which it views as extra profits for utilities.
A bipartisan bill to let utilities run voluntary energy efficiency programs is pending in the General Assembly. Supporters say utility-run programs can make savings simpler for consumers and can produce benefits for all ratepayers by reducing system-wide demand.
OCC has “always battled” electric security plans, or ESPs, Willis said. “We believe they are crony capitalism.”
A traditional ratemaking case requires utilities to show all their projected costs and revenues, based upon actual data from a representative test year. ESP cases don’t require that detailed scrutiny. They allow utilities to raise rates for isolated issues, without presenting those charges in the context of all of a company’s financial activities. And utilities can reject any change regulators might try to make to a plan — effectively giving them unequal, outsized bargaining power, Willis said.
Along those lines, OCC supports Senate Bill 143, which would get rid of ESPs and strengthen corporate separation between utilities and their affiliates.
OCC opposes Senate Bill 102, which would require periodic rate cases but still allow multiple riders. And the bill would let utilities use projections instead of actual data from test years in full ratemaking cases. Challengers also would have fewer opportunities to conduct pre-hearing discovery from utilities and others.
Discovery procedures are “truth-finding tools,” Willis explained. “To the extent you put limits on those, you’re saying, ‘We don’t really want you to get to the truth; you’re just going to have to accept what the utility has filed.’”
“It’s really an unfair situation where we’re stayed when it comes to protecting consumers,” Willis said. “But when it comes to charging consumers rate increases, there’s no stay on those.”
A Sept. 22 filing by OCC asked the PUCO to lift the stay in the four HB 6-linked cases. An Oct. 2 filing by FirstEnergy opposed ending the stay but did not address the argument that it’s unfair to continue the stay while the company has a separate case seeking more money from ratepayers.
OCC filed a complaint with federal regulators last month, asking them to review utilities’ “supplemental” transmission projects. As things stand, neither the Federal Energy Regulatory Commission nor the grid operator PJM reviews charges for those projects before utilities ask state regulators to let them pass along the costs to ratepayers. Nor does the PUCO scrutinize the charges, Willis said.
Since 2017, Ohio utilities have added more than $6 billion for “supplemental” projects to their local transmission plans in Ohio, according to the complaint. By filing its complaint, OCC hopes “that someone starts looking at these projects for need, cost-effectiveness and prudence,” Willis said.
OCC is also concerned about the pending transfer of the Energy Harbor (formerly FirstEnergy Services) nuclear plants to Vistra for one of that company’s subsidiaries to run. “We want to make sure that the competitive market is protected,” Willis said.
While the grid needs to be updated, Willis doesn’t want it done through “gold-plating.” Generally speaking, that involves adding pricey equipment that’s not really necessary. The added spending increases the base on which a utility earns a return on investment.
Instead, Willis wants regulators to scrutinize any grid modernization plan carefully: “Is it really needed? And who is benefitting? Is it really to the benefit of residential consumers?” she asks.
“Payment assistance is something we’re always going to be looking at,” along with the prices charged to low-income customers, disconnection data and more, Willis said. “Part of our advocacy must certainly be to protect the at-risk consumers.”
This story was originally published by Grist.
This coverage is made possible through a partnership with Grist and Interlochen Public Radio in Northern Michigan.
Michigan isn’t known for sunny weather. Yet in recent years, it’s seen a strong push for solar energy — including in Traverse City, the largest community in northern Michigan. Along the M-72 highway, rows of huge solar panels gleam in the sun, covering about 30 acres of grassy field.
In the shade underneath the panels are sheep.
This is called “solar grazing,” where livestock are placed on solar installations to keep vegetation in check. Sheep have grazed at the site for the past three summers, eating grass and depositing droppings along the rows of panels.
Bart Hautala, operations manager for Heritage Sustainable Energy, said hosting some 30 sheep is a win-win: Sheep eat the grass, and that prevents foliage from shading the panels.
“It’s a multiuse land now,” he said. “It’s environmentally friendly. We’re helping out a farmer. He’s got more space to put more sheep.”
But across the state and the country, similar collaborations between farmers and companies have faced roadblocks.
Solar power is central to the nation’s transition to renewable energy, including in Michigan, which is aiming for carbon neutrality by 2050. Reaching that goal will require a lot of land, and some solar companies, researchers, and farmers are trying to use land for both agriculture and renewable energy — a practice called agrivoltaics. But local opposition has hampered those efforts, and solar advocates say Michigan is a prime example of how townships can slow renewable energy development.
This debate is playing out around the country, as people grapple with what a transition to clean energy actually means. A May 2023 report by the Sabin Center for Climate Change Law at Columbia University found that across 35 states, there are 228 local restrictions strong enough to stop projects. That opposition has grown steadily, up 35% from the year before. And local restraints severely restrict renewable development, according to a 2022 report from the National Renewable Energy Laboratory.
Michigan exemplifies the tension between solar and local concerns. Since townships decide where renewable energy projects are located, residents have a lot of say and many have placed moratoriums on solar and wind. The Sabin Center found that as of last May, 26 local Michigan governments had delayed or blocked utility-scale developments, the most of any state in the study. It didn’t compare restrictions to the number of existing projects, but 118 wind and solar projects are already operating or under development, according to the state. As more are proposed, much of the focus is on the relationship between solar and farmland.
“Michigan has the most restrictive measures when it comes to siting solar on agricultural land,” said Matthew Eisenson, who authored the May report. “There’s a lot of apples to oranges, but I think Michigan just has the most activity on this issue of anywhere.”
Debates over renewable energy have roiled communities in the state. A group called Michigan Citizens for the Protection of Farmland petitioned to block utility-scale solar on agricultural land last spring, though they withdrew it. In some places, residents have recalled officials who approved projects they didn’t agree with.
Milan Township, in southeast Michigan, held a recall election last spring after residents voiced concerns about an ordinance that would have allowed large solar projects on agricultural land. Stephanie Kozar was elected township clerk during that recall. She’s spent her whole life in Milan, and said it was a rough time for the community.
“There have been rifts between friends, between relatives, between acquaintances, because it is such a hot topic, and there are so many strong opinions and emotions about it,” she said.
The township’s original ordinance allowing solar on agricultural land had passed during the height of the pandemic, which Kozar said raised issues of transparency. Since then, she said, more people have started attending meetings and gotten involved in local politics.
“We’re just trying to make the township a place where people want to come, want to live, and keep it in the agricultural spirit,” she said. “It’s about what the majority of our township wants. And that’s our biggest goal, is making sure that their voices are heard.”
Local opposition to renewable projects can often be nuanced, rooted in a wide array of reasons. Those include concerns about a project’s impact on the environment and economy, and extend to governmental failures to consult Indigenous tribes, according to a 2021 study by Science Direct. Some rural communities worry that losing farmland to solar could fundamentally change their culture.
“I think this is a hot-button in most townships, one way or the other,” said Bob Schafer, the supervisor of central Michigan’s Keene Township, who took on the job after his predecessor was narrowly voted out during another recall election held last spring.
Schafer stressed that people there have a variety of opinions on renewable energy — many people support it, and some oppose “mega projects” but not smaller installations.
“All the landowners have some say,” he said, “both those that are trying to obtain a project and those that may be surrounded by a project. We’re trying to find a balance.”
But that balance is hard to strike, and some Michigan lawmakers are trying to streamline the path to renewables. With a slim Democratic majority, Michigan’s legislature is tackling a heap of ambitious climate legislation this fall.
Abraham Aiyash, a Democrat from Hamtramck, is the house majority floor leader and one of the sponsors of a climate package. He and other lawmakers want the state to have the power to approve utility-scale projects, which he said is necessary to reach their climate goals.
“There is no other way,” he said. “If we are not setting a rapid pace for investing in solar and wind we will not meet the energy centers that we are going to be setting.”
Still, Michigan has a deep history of local decision-making, and for some, the idea of transferring power to the state is unacceptable. Judy Allen, the director of government relations for the Michigan Townships Association, said doing so would create a one-size-fits-all approach.
“It’s not a cookie-cutter situation, and that’s why we think it’s incredibly important that you have that local voice and that local process in terms of location and permitting,” she said — even when it means farmers can’t do what they want with their lands. Read Next
As utility-scale renewables expand, some Midwest farmers are pushing back
Michigan isn’t the only state debating who should approve renewable projects. Ohio’s legislature gave authority to counties to block them in 2021, and local opposition has stymied what’s projected to be some of the biggest renewable energy growth in the country — based on large projects planned on farmland and funded by Fortune 500 companies like Amazon, Google, and Facebook.
Despite those roadblocks, project development hasn’t stopped, and Ohio utilities are on track to meet their renewable requirements, said Matt Schilling, the director of public affairs for the Public Utilities Commission of Ohio and the Ohio Power Siting Board.
“We are continuing to see more development projects come into the power siting board,” he said. “I think time will tell, but the work is still going on.”
States like Minnesota, Illinois, and Wisconsin have seen local challenges as well. But unlike Michigan, those states have the authority to approve large renewable projects — even if local opinions differ.
In Michigan, township control is a big problem for companies, governments, and individuals trying to develop renewable energy, said Scott Laeser, a senior advisor for the Rural Climate Partnership and a farmer in southwest Wisconsin.
“If the opposition were to continue to advance, I think there would be some legitimate concerns about whether we can meet the renewable energy goals that states like Michigan, and quite frankly, the nation have,” he said.
According to Laeser, who has been involved in renewable energy planning for years, outside interests have also gotten involved in local debates, often spreading misinformation. “Some of the opposition is being funded by fossil fuel energy interests who don’t want renewable energy to succeed,” Laeser said. “So there’s a lot of complex dynamics that are mixed up in all of this.”
One way to turn down the temperature may be through projects that use land for both agriculture and energy production.
Proponents see solar grazing and other farm collaborations as an answer to the debate around land use in Michigan. Some studies back that up; a Springer survey in Houghton, Michigan, and Lubbock, Texas, found that most respondents were more likely to support solar projects if they incorporated agriculture. In practice, however, that can be difficult.
Samantha Craig has worked as a shepherd for about six years, first with her husband, and now their children. The family is based in Van Buren County in southwest Michigan, where they manage Craig Farms Katahdins — and a flock of over 200 sheep.
The pandemic and inflation have made the past few years tough, Craig said, and solar could be a path toward a steady income and long-term viability for farmers, as solar operators pay them to lease land or graze down grass.
Craig is excited about the prospect of sheep as vegetation managers. The farm’s website has a section called “lambscaping,” and the family has partnered with United Agrivoltaics, which works to help solar providers and farmers set up solar grazing. Still, Craig hasn’t been able to get her sheep on any solar farms yet. The logistics can be challenging; sheep need water, routine care, and shelter — things many existing solar sites aren’t built to accommodate — and it can cost a lot.
Local ordinances, zoning, and bureaucracy can also mean a lot of red tape. Craig had hoped to get her sheep onto a nearby solar farm, but she hasn’t gotten far with the local government.
“It was just definitely disappointing not to have the sheep out there this summer,” she said. “We were really hoping that that would come to fruition.”
Increasing tensions around renewables complicate potential partnerships. Craig’s neighboring township voted against solar on agricultural land in August and is now being sued by the solar company. To the east, Milan Township, which held the spring recall election, only wants solar erected in industrial areas, which township clerk Stephanie Kozar said excludes collaborations between large-scale solar and farming.
“We feel solar panels, even with crops or animals of some sort, it’s still a very industrial-looking project,” she said. “And so we feel like the industrial zoned area is probably the most appropriate place for it.”
Despite many hurdles, some still think partnering solar and agriculture will play an important role in debates around land use. Charles Gould is an educator at Michigan State University Extension. He started working at the intersection of farming and renewable energy about a decade ago, when farmers began asking him for advice on solar company lease agreements.
Since then, he’s delved into the dynamics of local governance, farming, and solar power. Gould said many farmers have come to see solar lease agreements as a sort of retirement package, and some consequently bristle at local efforts to restrict solar development, seeing them as a threat to their chances at financial stability.
“It evolved to, ‘This is a takings issue,’” he said. Farmers were asking, “How does a township have the right to tell me how to use my land?”
Of course, farmers are far from united on the issue. Some don’t like the idea of using their land for renewables. Gould agrees that areas like brownfields and right-of-ways should be considered for solar projects before farmland. But he said the many benefits of solar–agriculture collaborations mean it’s imperative to work with local governments and those who have concerns about the impacts of solar on their communities, something echoed in a federal study on successful collaborations.
As Michigan pursues its renewable energy goals, companies will continue to approach communities with these plans, according to the extension service. To help local governments tackle solar planning and zoning, Gould and others created a guide that includes templates for solar-specific ordinances and steps on how to plan for various situations.
The goal of this work is to help communities, solar companies and farmers hash out plans before the panels go up.
“Really, if we want to be successful at this, we need to back up and think ahead of time before that solar project is on board,” Gould said. “Bring all the partners together, have them all sit down and figure out what that’s going to look like.”
This article originally appeared in Grist at https://grist.org/agriculture/in-michigan-not-so-sunny-prospects-for-solar-farms/.
As the growth of Xcel Energy’s demand response programs in Minnesota lags a state target, some stakeholders say it’s time to expand the use of third-party companies to enroll customers.
Demand response refers to a broad range of voluntary programs in which utility customers agree to reduce energy use during periods of peak demand. The best-known programs involve smart thermostats or other technology that remotely switch off customers’ air conditioners in short increments when the electric grid is under stress.
The programs are expected to play a bigger role as the country transitions to more variable, renewable generation such as wind and solar power. Having the ability to shift customers’ energy use into hours when those sources are providing lots of clean and inexpensive electricity could help lower costs, reduce fossil fuels use, and improve reliability.
In Minnesota, Xcel Energy operates one of the country’s largest demand response programs. A 2019 analysis by the Brattle Group ranked its portfolio eighth in the country as a percentage of peak demand. More than half of that capacity comes from its “interruptible tariff” program, in which commercial and industrial customers are offered bill savings in return for committing to curtail electricity use if called upon by the utility. The next largest source is its residential air conditioning Saver’s Switch program, which has enrolled more than 60% of homeowners with air conditioning.
As of 2017, the company had 850 megawatts of demand response capability in its Minnesota territory, about 10% of its system peak demand. That year, Xcel and state utility regulators agreed to a target of growing demand response enrollment by 50% over six years — an increase of 425 megawatts by 2023.
Earlier this year, Xcel reported slow progress toward that target, saying it had added just 117 megawatts in the previous half-decade. The company said the COVID-19 pandemic made it harder to recruit new participants and caused some of those in Xcel’s programs to go out of business.
The company also expressed confidence that program growth would be robust in 2023 and that it would achieve the target. The company continues to install smart meters, allowing more market demand response programs such as time-of-use rates that encourage customers to shift energy consumption. Other demand response programs involve customer-owned batteries, electric vehicles, building control systems and grid-connected appliances.
“We are very close to meeting the target this year, incentivizing growth through creative marketing, sign-on bonuses and a variety of new demand response offerings that give our customers choices to best fit their needs,” Xcel said.
Meanwhile, some clean energy and industry groups say Xcel’s apparent struggles to meet the demand response target shows there is a need for competition in the space.
In August, the Minnesota Public Utilities Commission heard debate over whether to allow the use of demand response aggregators — third-party companies that sign up customers for programs and then sell the capacity into wholesale markets. Xcel and other utilities argued against permitting retail aggregators because of unease over how they would impact the grid.
The commission voted 3-2 to table the topic.
Commissioner Joseph Sullivan said utilities will need more resources than just solar, wind and battery storage to maintain a resilient grid as fossil fuel plants close. Demand response is a flexible resource that can be an alternative to a gas power plant, he said. Sullivan said he has been surprised by how little Xcel uses demand response. Xcel tested but did not use demand response once last summer, he said.
“I think there is a tremendous opportunity for Xcel to be doing more,” Sullivan said.
Xcel has told the commission that exercising demand response programs too often increases the risk of participants dropping out.
Frank Lacey, a founder and former chair of Advanced Energy Management Alliance, which represents demand response companies, said Xcel and other utilities don’t embrace demand response because building new generation is more profitable, offering a guaranteed rate of return. “Utilities have an inherent conflict in growing demand response,” Lacey said.
But the programs save consumers money, with programs sometimes paying six times their cost. They offer a way for utilities to balance loads when solar and wind production fluctuate and fossil fuel plants no longer exist to fill in the gaps. Lacey said he hopes Minnesota looks again at the aggregator issue.
“What’s the expression about shutting the barn door after the horse escapes?” he said. “If you wait until you need it, you won’t recognize you need it until you need it, and it’s too late at that point.”
Wisconsin has ambitious climate plans, but the Republican-controlled legislature has refused to pass funding to carry them out.
That’s why Wisconsin city and state leaders are especially glad for a nearly $5 billion federal initiative meant to help states and municipalities advance climate action plans.
The Climate Pollution Reduction Grant program, created by the Inflation Reduction Act, has already provided a $3 million planning grant to Wisconsin’s Office of Sustainability and Clean Energy, as well as smaller grants to the Southeastern Wisconsin Regional Planning Commission and four tribal governments within the state’s borders.
“This is a really awesome kickstart to emissions reductions in the state,” said Maria Redmond, director of the Wisconsin Office of Sustainability and Clean Energy.
“The challenge in Wisconsin is we haven’t been able to get a lot of resources [for climate programs] because the legislature hasn’t allocated them. The last three budget cycles, the governor proposed significant funding for climate action, including for this office. None of that has been approved. Through this grant, we can get a lot more done.”
The program this year awarded $250 million in non-competitive grants to states, tribes and major metropolitan areas for climate action planning. The entities that received the planning grants can then apply for implementation grants totaling $4.3 billion to carry out their climate action plans.
The implementation grant application deadline is April 1, 2024. In a guidance document released in September, the U.S. Environmental Protection Agency said it anticipates awarding 30 to 115 such grants ranging between $2 million and $500 million.
Redmond said the state has “already been doing a lot of work on decarbonization,” including in keeping with Gov. Tony Evers’ 2020 action plan, and “this gives us the resources to really ramp up this work locally,” including by “identifying pathways to reduce emissions, renewable deployment, optimizing energy efficiency, innovating in transportation, and improving our building stock,” and also potentially looking at agriculture, forestry and carbon sequestration.
Wisconsin lawmakers have pushed legislation that limits municipalities’ ability to pursue climate goals, like a ban on local zero-emissions mandates and a bill that would prevent local governments from operating pay electric vehicle charging stations. They’ve also thus far declined to pass a bill enabling community solar, and rebuffed advocates’ requests for legal clarity on third-party-owned solar.
Justin Backal Balik is the state program director for Evergreen Action, which was among organizations offering the administration input on designing the federal program. He said the grants are “tailor-made for a state like Wisconsin at this particular moment in time, when you have the leadership of Gov. Evers that has articulated a clean energy plan to achieve 100% decarbonization in the electricity sector, and also looking at the industrial sector and clean transportation goals.”
“One of the reasons Evergreen advocated for the [Climate Pollution Reduction Grant] was that it is specifically designed to focus on sectoral transformations and unmet funding needs — Wisconsin has a lot,” Backal Balik continued. “The policy vision is there, and particularly with the capacity Wisconsin has with the $3 million planning grant, there are a number of directions they could go in. This is a generational opportunity that’s not going to come around again, an opportunity to meet a good chunk of the unmet funding needs that have popped up as a result of the Republican intransigence in the legislature.”
Redmond said the $3 million planning grant has allowed her office to hire a full-time community engagement facilitator and another full-time staffer, basically doubling the staff. The planning grant is also used for carrying out analysis, modeling, community outreach and status reports over a four-year period.
Environmental justice is a focus of the funding, and a key metric in the scoring system for implementation grants. Redmond said this dovetails with Wisconsin’s focus on equity and inclusion.
“Understanding lived experience is one of the things we’re most excited about” augmenting with the planning grant dollars, she said. “This gives us the ability to go out to communities instead of having them come to us. It’s also about supporting organizations working in communities, making sure we are not expecting them to volunteer their time.”
That could include honorariums for people to attend community meetings.
“We’re asking people to step away from their lives, maybe in the evening when they need child care, or to step away from their jobs,” she said.
Redmond said the state is also planning to work with Illinois and Minnesota to “make sure we are in alignment with state plans, and not working against each other” — especially since Wisconsin metropolitan areas overlap with those states.
Allison Carlson, executive director of the Wisconsin Local Government Climate Coalition, said staff capacity is a common need for local governments on the climate front, and she’s glad the planning grants can be used to hire staff.
“A lot of local governments have one person dedicated to climate action, probably being shared with other departments like recycling; they have a lot of other things on their plate,” she said. “We need to be making sure we’re building capacity in local governments and in communities to sustain efforts over time.”
Backal Balik noted the planning grants are meant to help governments make sense of all the incentives and opportunities on the table.
“EPA is really encouraging states and other jurisdictions to use the CPRG process to step back and look at their federal funding deployment strategy as a whole,” he said. “You have Solar for All here, and direct pay here, so many different pieces. The planning process is asking states to think about how all these funding streams can be accessed together. The parts are pretty consequential in their own right, but you have the opportunity to really scale up the impact of what all the federal investments can achieve.”
States or metro areas that received planning grants can serve as coordinating entities to collaborate with other government bodies to seek grants. Redmond said her office is eager to work with Wisconsin municipalities and agencies on meeting their climate goals, and will hold nine regional meetings for that purpose.
The Wisconsin Local Government Climate Coalition is also focused on helping municipalities participate in the CPRG program.
“Many member communities have their own climate action or clean energy plans in place. They’ve done data analysis, engaging with their communities to understand what the needs are — a lot of them are already making strides,” she said. “One of the big barriers is: where are the dollars to actually do these things? The competitive CPRG grants and other IRA funds are allowing communities to put their plans into action.”
She added that “a lot of the climate action plans were already in place or in process, not necessarily prompted by the CPRG process.”
“But what the CPRG process does is create opportunity to align the needs of local communities with the state and other stakeholders, so we can leverage even more IRA dollars and become more organized together.”
Kelly Hilyard is the sustainability coordinator for the city of Middleton, not far from Madison. She said the office has been stymied by legislative inaction around electric vehicles. They had applied for federal funding for electric vehicles under the Carbon Reduction Program, a program separate from CPRG under the U.S. Department of Transportation. But the county had to switch its proposal to seek funding for LED lights instead because of constraints placed on the program by the legislature.
Hilyard said the city “scrambled” to put together a proposal to transition their street lights to LEDs, which was necessary “low-hanging fruit,” but they still hope to seek federal funds for electric vehicles.
Since being part of a seven-city collaboration on an energy plan in 2020, Middleton has been “ticking things off” on a list of priorities like increased building efficiency and putting solar on city buildings. They are working on a battery storage project at the police station, where a planned microgrid had to be scaled back because of the pandemic.
Hilyard said the city has not been very focused on the CPRG thus far, but is looking for multiple sources of federal and other funding for its goals, and for the advance study and planning needed to bring goals to fruition.
“It’s chicken or the egg — what information do you need to get the grant to do the work, and how do you get the grant to get the information?” she said. “You have to work it from both ends constantly.”
A top priority is energy efficiency for the city’s affordable but often aging and inefficient housing units. A separate federal grant is helping the city take inventory of its housing stock.
“Once you stack all those incentives, decarbonizing entire neighborhoods becomes possible,” she said. “You can do major projects, and reduce the energy burden for people most affected by climate change and high energy bills.”
La Crosse environmental planner Lewis Kuhlman is hopeful that federal programs like the CPRG could help the city acquire more electric city buses or other electric vehicles, as well as creating an electric bike share program.
The city’s sustainability efforts have largely been through a partnership with the company Johnson Controls, which has provided the city with solar, energy efficiency and other energy investments, with a performance contract guaranteeing savings. The partnership helped the city access solar despite the state’s failure to clarify the legality of third-party-owned solar, which has made it more difficult for municipalities to finance solar energy.
“Huge grant opportunities like this are going to take collaboration, because communities the size of LaCrosse don’t really have the staff to implement or prepare for a grant like this,” Kuhlman said. “There are so many different types of projects that can get funding; we need to keep an eye on what we have in our plan — and how can that fit into what’s available for funding? And do state regulations allow it?”
The implementation grants are meant to help states and municipalities meet their climate goals; reduce hazardous air pollutants, especially in disadvantaged communities; complement other funding sources for greenhouse gas reductions; and create programs that are replicable and scalable. The agency is encouraging collaborative proposals that cross local and state lines. Points in the competitive grant scoring process are awarded based on criteria including the funding need, the extent of emissions reductions, benefits to low-income and disadvantaged communities, and community outreach.
Redmond noted that doing extensive engagement, figuring out what different stakeholders need and want, and meeting the application deadline all in six months will be a challenge.
“One of the things that keeps me awake at night is the timeline,” she said. “We need to have a thoughtful and meaningful process” in a tight time frame, “but we’ll make it happen.”
Milwaukee’s Climate and Equity Plan calls for making the city carbon-neutral by 2050, and creating green jobs that drive racial and economic equity. The city proposes to do this through projects including clean energy, a green jobs accelerator, and transportation electrification.
Erick Shambarger, Milwaukee director of environmental sustainability, said they hope CPRG funding will help the city implement its long-standing ambitious climate goals. He said other municipalities in the metropolitan area that received the grant have taken inspiration from Milwaukee in crafting climate action plans of their own.
“It took several years for us to get our climate plan together, and we don’t have that kind of time relative to getting everything in place for these implementation grants,” Shambarger said. “We don’t want to start from scratch. We want to share lessons we’ve learned; we don’t want to reinvent the wheel on planning processes.”
He said a key focus of the planning grant is a greenhouse gas emissions inventory, which has never been done for the region as a whole. He said that the metro group still hasn’t decided where to focus their CPRG-related plans.
“It could be everything from a major transportation project to a focus on buildings,” he said. “It could go in a lot of different directions. We’ve been doing pilot projects, but this will really be important to take it to the next level.”
Marco Marquez is the Wisconsin state director for the organization Action for the Climate Emergency, which mobilizes youth. He said IRA programs could provide federal funding for multiple climate-related initiatives that young people are passionate about and that affect them directly — like electric school buses and energy efficiency and updated HVAC systems in aging school buildings. He said young people are especially frustrated by the inertia of the Wisconsin state legislature on such issues.
“It’s unfortunate that we see a lot of effort from elected officials trying to dictate how each municipality can run and what they’re able to seek in terms of funding,” he said.
The funding available under the IRA and the potential for entities to apply for it without going through the state legislature holds much promise, he added. While his organization has not been specifically focused on CPRG, he sees it as symbolic of larger trends and opportunities.
“This is an amazing opportunity for young people to rewrite and rethink how our society should operate,” Marquez said. “And climate is the justice issue.”
Four states — Florida, Iowa, Kentucky and South Dakota — declined to participate in the CPRG program. Metropolitan areas in those states that received planning grants can still participate. In Iowa, the Des Moines, Cedar Rapids and Iowa City areas received planning grants and can apply directly for CPRG implementation funds.
Backal Balik said advocates hope the CPRG dollars can not only help work around inaction from the legislature in Wisconsin and other states, but actually change a state’s direction on climate as people see the benefits of the funding play out.
“As in Wisconsin, the program is purposely designed to achieve emissions reductions in states where they wouldn’t otherwise occur,” he said. “It’s not just moving money around, but incentivizing the next round of leadership. We had administrations willing to act but with constraints outside of their control. This is a moment in time where they can get a huge chunk of resources to move forward their climate vision.”
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.”
Secure Solar Futures president Tony Smith barely paused to celebrate last week’s David vs. Goliath victory for small-scale commercial projects.
The bustling but tiny solar operation he founded just couldn’t spare the time for a party.
Still, he’s jubilant utility regulators put the kibosh on Dominion Energy’s attempt to saddle rooftop installations with astronomical grid interconnection fees that was stifling the industry’s gains across an expansive swath of Virginia.
“We were joyful,” Smith said about the injunction the State Corporation Commission (SCC) delivered on Aug. 30. “Then, upon saying ‘Wow!’ for 15 minutes, we got back to work.”
After all, his Staunton-based company needed to redirect its attention to advancing two stalled rooftop installations in Prince William County. The threat of unexpected expenses from Dominion meant projects at Freedom High School and Potomac Shores Middle School — roughly 1 megawatt apiece — had been in limbo for eight-plus months.
Secure Solar Futures was far from alone.
Companies across Dominion’s service territory were also reassessing projects they had paused after the investor-owned utility rolled out new and expensive interconnection parameters last December for non-residential, net-metered solar projects.
Dominion’s surprise rules — announced more than two years after a major Virginia law bolstered solar — could have boosted the price tag of each school project by at least $1 million, Smith estimated.
“This hits Virginia right in the groin,” Smith said. “It wasn’t isolated and it created havoc.”
Regulators had not vetted the new requirements, which spelled out how solar companies would be on the hook to pay to upgrade substations, cables and other hardware, as well as cover the cost of a series of studies to guarantee the new projects met safety and reliability requirements.
Also, solar array recipients would be required to pay a monthly fee to Dominion to cover maintenance. Not only that, but the utility wanted solar customers to sign what it called a “small generator interconnection agreement” so it was clear they would be the ones held liable if their array caused a grid failure.
“We heard war stories from other solar companies who were throwing up their hands and saying they would have to back out of Dominion territory because it was a deal-stopper,” Smith said.
Handfuls of complaints weren’t confined to Northern Virginia, where the two Prince William County schools are. For instance, a solar array on a grocery store in the Hampton Roads region was put on hold. And near Richmond, Henrico County officials slowed plans for a 686-kilowatt array at the James River Juvenile Detention Center.
Those setbacks prompted Smith and others to reinvigorate the Virginia Distributed Solar Alliance. A decade ago, the group — spearheaded by Secure Solar Futures — had successfully strategized a legislative path forward for solar power purchase agreements. It’s a mix of solar installers, and advocacy organizations such as the Sierra Club of Virginia and Solar United Neighbors of Virginia.
“One of the virtues of being a network of players joined by a set of shared values and aspirations is that we could be extremely nimble,” Smith said. “We didn’t have to go through hierarchies.”
This time around, the alliance needed to convince regulators to order Dominion to back down on costly interconnection demands.
“We realized what Dominion was doing was unprecedented and harmful,” Smith said. “And it was illegal.”
The alliance, with Smith at the helm, started its conversation with Dominion via an April letter to CEO Bob Blue. It laid out roughly a dozen projects close to 1 MW in size that would be deep-sixed due to the time and money consumed by the parameters.
Within a week, Blue responded, telling the alliance that Dominion wasn’t budging, saying that the safety of customers and employees, and the reliability of the grid were paramount.
Eventually, alliance members concluded that utility regulators needed to hear their case. On June 1, they filed their first-ever petition with the SCC, calling on guidance from Cliona Robb, an energy attorney for 23 years.
Robb, a partner at Richmond-based Thompson McMullan, serves as legal counsel for the alliance.
The alliance’s June petition stated that Dominion’s interconnection parameters were illegal because they were never approved by regulators. It asked commissioners to rule on net metering projects between 250 kW and 1 MW.
“We narrowly cast our petition because these are the kinds of projects that have always been net-metered without any issues around safety and reliability,” Smith said.
Briefly, net metering is a billing mechanism that credits solar energy system owners for the electricity they add to the grid.
For years, net-metering models, which use power purchase agreements, have appealed to universities, public schools, hospitals, churches, municipalities and small commercial ventures because they are low-risk. They lock in an affordable kilowatt-hour price of electricity, the installer covers upfront costs and maintains the arrays for their 25- to 30-year lifespan, and the recipients can achieve sustainability goals.
Those entities can least afford to finance, much less build and operate solar, Smith said, adding that school arrays are often incorporated into hands-on lessons about renewable energy for students.
He noted that no net metering projects in Dominion’s service area exceed 1 MW, even though the Clean Economy Act of 2020 bumped that cap up to 3 MW for the state’s two investor-owned utilities. In Appalachian Power territory, just one net metered project is bigger than 1 MW, at roughly 1.5 MW, according to state records.
Smith and the alliance were encouraged in late July when SCC hearing examiner Mary Beth Adams recommended that Dominion’s interconnection rules be suspended until the commission resolved the interconnection-related issues raised in two other separate cases.
Adams referred to a section of Virginia code focusing on interconnection, stating that Dominion is bound to provide power distribution service that is “just, reasonable, and not unduly discriminatory to suppliers of electric energy, including distributed generation.”
She also said that Dominion lacks the authority to require net-metering customers to execute a small generator interconnection agreement.
Decisions by hearing examiners are non-binding. However, within a month, commissioners concurred with Adams’ conclusions in a five-page order. The injunction prevents Dominion from forcing solar companies and their customers to comply with the interconnection parameters and small generator interconnection agreements.
They noted that the suspensions are effective until commissioners have investigated and completed rulemaking on two separate cases dealing with interconnection issues.
Commissioners also made it clear that they have “neither disregarded, nor taken lightly, Dominion’s claims regarding safety and reliability.”
“Dominion should continue to take the actions necessary to maintain the immediate safety and reliability of its system,” the commissioners wrote. “This may include, but need not be limited to, seeking specific authority from this Commission in one or more formal proceedings.”
Utility spokesperson Jeremy Slayton stuck to that two-word mantra when asked to comment on the commission’s injunction.
“Our filings and interconnection requirements are designed to ensure the same safety and reliability standard regardless of who builds the project,” Slayton said. “We believe this to be critical to maintaining a reliable energy grid.”
Alliance members maintain that neither safety nor reliability is being compromised with current commercial solar net metering. They claim the unnecessary parameters add at least 40% to project costs.
For instance, one rule required the use of an advanced form of cabling, also called dark fiber, which costs $150,000 to $250,000 per mile. Another piece of hardware, a distributed generation relay panel, runs $250,000.
In addition, solar companies said they would have to spend between $200,000 and $1.2 million per project on engineering and construction costs to be sure all the pieces were operating efficiently.
Smith and Robb are no strangers to tangles with Dominion. They bumped into similar interconnection issues two years ago when trying to site a 1.2-megawatt community solar project for low-income residents on 10 acres in Augusta County. Issues with that project still have not been resolved, Smith said.
He’s relieved the commission’s ruling puts the pair of Prince William school projects back on sound economic footing.
“The biggest unknown was not knowing how long all of this would take,” Smith said about the timeline of the Dominion challenge. “We had already put in a lot of money upfront with the engineering and ordering the panels.”
As it stands now, he’s relieved both installations will go online — but in 2024 rather than later this year.
The solar trailblazer is also reassured that the commission’s ruling will quash other utilities’ pursuit of add-on interconnection fees.
“Our fear was, if we lost, Appalachian Power and co-ops in Virginia would take a cue from Dominion and impose similar restrictions,” he said. “Dominion may have underestimated our willingness and capacity to take this to the mat with them”
Indeed. That relentlessness prompted the trailblazing solar developer to draw upon the sentiments of noted author and cultural anthropologist Margaret Mead.
“‘Never doubt that a small group of thoughtful committed individuals can change the world,’” Smith said, reciting Mead’s notable words from memory. “In fact, it’s the only thing that ever has.”
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.”
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