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This commentary was submitted by Sneha Ayyagari, a Clean Energy Leadership Institute Fellow and a Program Manager for Clean Energy Initiative at the Greenlining Institute. See our commentary guidelines for more information.
Winter is coming, and having resilient homes is crucial in climate disasters. For instance, Texans were woefully unprepared for Storm Uri which resulted in 246 deaths. While my family shivered under blankets, temperatures in our house stayed safe since we had insulation and a heat pump that kicked into gear when we had short periods of power. It was devastating hearing of families living in poorly insulated homes exposed to hypothermia. Weatherizing buildings and switching to efficient systems like heat pumps can be lifesaving in extreme weather and generally be more comfortable and can save residents money.
However, for more than a third of residents living in rental housing, accessing incentive programs that allow them to make these upgrades in their homes is very difficult. These barriers are especially high for residents in multifamily affordable housing and mobile homes where many people who are most susceptible to heat-related illnesses live.
States and local governments should implement federal funding with renters in mind. The Department of Energy’s Home Energy Rebates (HER) program provides $8.8B in rebate funding for energy efficiency and electrification projects and an additional $200M for states to develop complementary contractor training programs. States can provide their most vulnerable residents health, economic, and environmental benefits by prioritizing low-income renters in their applications for Home Energy Rebate funding.
To ensure the benefits of this program reach tenants, states should:
Renters should not have to fear that their landlords would use building upgrades as a reason to raise rents or displace them (as has happened in construction projects including apartment renovations in Los Angeles). At a minimum, HER guidance states that the owner must agree to rent the dwelling to a low-income tenant and cannot increase rent as a result of energy improvements for two years. Tenants must also have written notice of their rights in a specific and verifiable mechanism. States should go further to specify clear enforcement and penalties. They should ensure that tenants have access to legal services and support in reporting violations without fear of retaliation. Administrators should prohibit rent increases due to HER or at least extend the window of preventing rent increases to at least 10 years following the precedent of other programs.
In addition to building decarbonization programs, states should adopt policies such as rental efficiency standards, rental registries, eviction protections, and rent-stabilization measures to preserve affordability and increase the quality of rental housing. State and local renter protections such as California’s Transformative Communities Draft Program Guidelines and Berkeley’s Existing Buildings Electrification Strategy include a list of tenant protections and anti-displacement resources.
States have many resources from tenant advocates, environmental justice leaders, and policy groups to build from. This letter led by Just Solutions Collective in collaboration with 60 environmental justice, housing, workforce, and environmental organizations has detailed recommendations on reducing barriers for tenants. Strategic Actions for a Just Economy shared recommendations on developing a tenant protection plan to prevent rent burden, limit evictions, minimize disruptions to tenants, and design enforcement and penalty systems. The Greenlining’s Equitable Building Decarbonization Framework shares how to design a community-led approach to implementation. Just Solutions Collective provides recommendations on ensuring access to low income renters, and Green and Healthy Homes Initiative and Building Decarbonization Coalition shares lessons learned from past federal building retrofit programs. Other resources include American Council for an Energy-Efficient Economy’s webinars and Energy Innovation’s report on ways to design effective outreach strategies.
Regional and local community based organizations should be compensated to be part of the program administration team and help with outreach, implementation, and evaluation of the Home Energy program. The HER application also requires that states create Community Benefits Plans that describe anticipated economic and direct benefits especially for disadvantaged communities. As states develop their community benefits plans, they should ensure that benefits to low income tenants are prioritized within the scope of the goals.
Stacking and braiding federal funding with other state, local, and utility housing, energy, and building retrofits programs can maximize benefits to renters while streamlining the effort of property owners applying for multiple programs. Philadelphia’s Built to Last and Washington’s Weatherization and Health are good examples of holistic programs.
Families shouldn’t have to choose between affording rent and having a safe and healthy place to live, especially in the face of climate disasters. States have a historic opportunity to drastically improve the lives of tenants. By collaborating with tenants, state energy offices can create strong applications in 2024 that ensure healthy, affordable, and climate-resilient housing for all.
Northern Indiana Public Service Co. is planning to build a 400-megawatt natural gas-fired power plant that critics say is unnecessary, out of step with clean energy goals, and happening outside the usual planning process.
In September, the utility asked the Indiana Utility Regulatory Commission for a needed certificate of public convenience and necessity to build the $643 million peaker plant on the site of the retiring R.M. Schahfer coal plant in Jasper County in central Indiana.
The utility, known as NIPSCO, says it needs the plant to provide power during times of high demand, since it will be phasing out coal by 2028 and transitioning to renewables.
“Energy from renewable resources does not follow the load,” David Walter, NIPSCO vice president for power delivery, testified before the commission. “In order to have generation available when the load is there but sufficient energy from renewable resources is not, it is critical to have sufficient fast-starting, quick-ramping dispatchable generation,” meaning the natural gas plant.
NIPSCO also says the plant could be converted to run on natural gas blended with hydrogen — a fuel being pushed by the U.S. Department of Energy, including with the recent funding of regional hydrogen hubs.
Groups with intervenor status — including Citizens Action Coalition and the Industrial Group of NIPSCO customers — are in the process of filing testimony about the proposed gas plant, due Dec. 12.
Just Transition Northwest Indiana legislative director Susan Thomas said the organization “is actively opposing this build-out of what will most likely be only an occasional-use facility that either prolongs the use of fossil fuels for another 50 years or will be rendered obsolete due to more stringent climate regulations in the future.”
Currently, NIPSCO’s generation mix is 43% coal, 26% natural gas, 17% solar and 15% wind. In its 2018 integrated resource plan, NIPSCO proposed to close all its coal plants by 2028, and keep running its existing Sugar Creek natural gas plant.
NIPSCO told the commission in recent testimony that by 2028, it expects to get 31% of its capacity from natural gas-fired power, 13% from wind and 55% from solar plus storage.
NIPSCO’s 2021 integrated resource plan called for 300 MW of natural gas. In its September filing, NIPSCO said that the proposal for a 400-megawatt gas plant is based on a recent analysis including “market shifts” since 2021, like rule changes in the MISO wholesale market and passage of the Inflation Reduction Act.
“They’re backsliding off their 2018 commitment,” is how Thomas sees it.
NIPSCO had originally planned to retire two units of the Schahfer coal plant in 2023, but had to extend to 2025 because of delays in getting planned solar online, it told the commission. Two more units at Schahfer are scheduled to close by 2028, and existing gas-fired peaking units at that site are scheduled to close in 2026. NIPSCO’s Michigan City coal plant is scheduled to close by 2026.
Citizens Action Coalition program director Ben Inskeep noted that NIPSCO has another integrated resource plan due next fall. He said that process would be the appropriate place to explore and explain the need for new gas peaker capacity, offering more chances for public scrutiny and input.
“We’ve had great dialogue with them in the [integrated resource planning] stakeholder process in the past; they’ve been receptive to feedback,” Inskeep said. “One of the sad parts about this proceeding is it’s a step backwards in the process with them; it kind of breaks trust when you have an understanding about how things will operate and you’ve been successful, and then they’ve gone outside the process to come up with a different answer.”
Walter told the commission that NIPSCO could not wait to launch the gas plant request during the 2024 integrated resource planning process, since that would delay plant construction “until late 2027 at the earliest,” while the company said it needs the capacity by 2026.
Advocates say that rather than constructing a natural gas plant to fill gaps in renewable generation, NIPSCO could buy power from the MISO wholesale market, while also reducing energy needs through demand response and energy efficiency programs.
Inskeep said the math behind the gas plant proposal is especially tricky given that it depends on both wholesale power prices in the future, and natural gas prices, for NIPSCO to supply its own plant. Natural gas prices have been particularly volatile over time, severely impacted by things like the fracking boom and the Ukraine-Russia war.
“They’re saying that additional capacity will give them the ability to basically buy less electricity from the MISO wholesale power market, an insurance mechanism so they’re not buying wholesale energy during the few hours of the year when the solar and wind they are building might not be operating,” Inskeep said. “Whether this resource meets the cost-benefit analysis is unclear to me. Is it really going to make the gas plant worth it, even if you don’t take into consideration the climate change and local pollution impacts?”
Opponents are also worried that NIPSCO is for the first time proposing to construct the plant itself, hiring individual contractors rather than hiring one firm to oversee the entire process.
“They’ve never built a plant on their own, but now they’re going to freelance this,” Thomas said. “Where will there be transparency in this process? The potential for cost overruns is rampant.”
Under Indiana law, a company can bill ratepayers for a “construction work in progress,” long before it is “used and useful,” the usual standard for recouping cost and a profit from ratepayers.
Kevin Blissmer, regulatory manager for NIPSCO’s parent company, testified to the commission that this arrangement actually saves ratepayers money, since they are paying costs upfront rather than later, including costs the company took on to finance its investment. Blissmer said billing ratepayers while construction is ongoing would mean a difference of $149 million in financing savings over the project’s life.
But the Citizens Action Coalition website describes the group’s concerns with construction work in progress, saying it “converts consumers into involuntary investors, placing the burden of up front financing costs onto them. The costs end up on their bills sooner, before they ever receive electricity from the plant in question, and there is little recourse should the costs skyrocket or the project be abandoned.”
In July, NIPSCO announced its first two Indiana solar farms are operating: a 265-megawatt solar farm in Jasper County, not far from the Schahfer coal plant, and a 200-megawatt array in White County. In April, NIPSCO signed a power purchase agreement with a 198-megawatt wind farm in Jasper County.
In its September filing, NIPSCO said the gas plant meets the state 21st Century Energy Policy Development Task Force’s recommended five pillars, helping to ensure reliability and resiliency, stability, affordability, and environmental sustainability.
But Inskeep called building the gas plant on the retiring coal plant site a “missed opportunity,” since it precludes the chance to put wind and solar on the site and utilize the existing grid interconnections, without having to go through the otherwise lengthy process to interconnect new solar and wind to MISO’s grid.
Clean energy advocates have also asked NIPSCO to focus on reducing peak demand rather than building more generation.
“Solutions are there and available,” Thomas said. “We’re not even giving those solutions a fair chance. They should have considered energy storage, demand response or purchase from the MISO market before they did this.”
This commentary was submitted by Holly Caggiano, Ph.D., assistant professor in the School of Community and Regional Planning at the University of British Columbia, and Sara Constantino, Ph.D., assistant professor in the Psychology Department and the School of Public Policy and Urban Affairs at Northeastern University. See our commentary guidelines for more information.
After paying our monthly utility bills, most of us take for granted the complex network of infrastructure and institutions that keep the lights on. This is changing. The average monthly electricity bill for residential customers nationally increased 13% from 2021 to 2022, rising from $121 to $137 a month, while climate change and aging and mismanaged electrical infrastructure have contributed to a string of disastrous wildfires. Confronted with rising costs of living and the urgent need to protect the environment, people across the country are taking a serious look at how their utilities are owned and operated.
Electric utilities, which can act as generators, distributors and/or service providers, play a key role in the transition from fossil fuels to renewable energy. For decades, a small number of for-profit, investor-owned utilities (IOUs) have powered most of the country. On November 7th, Maine challenged this model with Ballot Question 3, The Pine Tree Power initiative, proposing a transformation of the state’s two largest IOUs into a non-profit, democratically-managed public utility.
Before the vote, the Washington Post dubbed Maine the “epicenter” of the nation’s growing anger with electric utilities. Customer approval ratings of Central Maine Power (CMP) and Versant–the state’s two largest IOUs, owned by parent companies in Spain and Canada–are among the lowest in the country, but Maine is just one of an increasing number of states where people are raising concerns. Groups across the country have called for public takeover of IOUs, claiming investors prioritize profit over system maintenance, disregard consumer safety, and delay climate action.
While many IOUs have embraced climate action on paper, their actions say otherwise. One recent study found that electric utilities have pushed climate delay, doubt, and denial over multiple decades, promoting messaging explicitly designed to absolve inaction. Reporting also reveals widespread corruption and attempts to halt regulation to encourage clean energy and reduce ratepayer costs. Climate activism group 350.org labeled CMP one of the biggest anti-climate lobbyists in Maine.
IOUs have also been implicated in destructive and deadly wildfires. Hawaiian Electric Company recently acknowledged responsibility for the Maui wildfires—they failed to shut off power despite high winds and dry conditions. California’s PG&E narrowly avoided a trial on manslaughter charges for their role in the 2020 Zogg fire that killed four. IOUs know that the public is worried by their questionable safety records, responding with expensive PR campaigns. These tactics come from an old playbook. In The Big Myth, Erik M. Conway and Naomi Oreskes describe 1920s propaganda campaigns to push privatization that ushered in higher rates for homeowners and bigger profits for corporations. A century later, we’re back to questioning this model.
Private utilities in Maine spent millions lobbying against the ballot initiative and the governor was vocally opposed. We ran a survey with the Climate and Community Project to learn more about how Mainers were feeling in the lead up to the vote. We found that Mainers are overwhelmingly concerned about keeping the lights on, with 88% of respondents very or somewhat worried about current and future energy costs. And despite the lobbying efforts of the private utilities, most respondents believe that their utilities should be locally owned and operated (55%) and not-for-profit (66%).
While these sentiments weren’t reflected in the election results, the reasons are nuanced. Our data suggests that many Mainers weren’t rejecting public-ownership itself, but were looking for a more fully realized plan, citing ambiguities about how the takeover would be financed, if costs would be passed to consumers, and if it would hold up in court—67% of our respondents thought it was somewhat or very likely that Pine Tree would face legal and regulatory challenges.
Despite investor-owned utilities pouring money into campaigns to oppose public power, there is growing momentum to reconsider how our power systems are owned and operated. One recent success is New York’s Build Public Renewables Act, which passed into law in May. After four years of organizing by Public Power NY, a coalition of more than twenty community organizations, the law authorizes the New York Power Authority to build renewable energy projects that help meet the state’s climate goals and include strong labor standards. Municipalization of utilities is also a hot topic in Western states, with ongoing organizing in California and Texas.
Some supporters of the Pine Tree Power campaign hoped that a win would fuel more initiatives across the country. In our poll, 41% of respondents thought it was somewhat or very likely that if passed, Pine Tree Power would spark a larger cross-state movement towards public ownership of energy resources. Despite Mainers choosing to stick with their current model for now, the ballot initiative brought national attention to the issue and has encouraged many to question the status quo. Rather than signaling the end of the road for public power in Maine, this vote could be the beginning of a sustained conversation about transforming our utilities. The research, organizing and discussions that went into the Pine Tree campaign provide a foundation for future efforts to improve the service, safety and sustainability of our energy infrastructure—and start to shift the energy narrative about what is possible, and desirable.
In Maine, we saw how the movement for public power united people across demographic and party lines. Rural or urban, Democrat or Republican, we all deserve access to clean, affordable, and reliable electricity. Climate change is forcing us to reconsider how we produce energy but it doesn’t need to stop there. This is an opportunity to reimagine who owns energy infrastructure and whose interests it serves.
This article originally appeared on Planet Detroit.
After Mayor Mike Duggan announced nine finalists in his campaign to recruit Detroit neighborhoods to host solar panel arrays at a Wednesday press conference, community members and activists are divided over whether the plan will help or unfairly burden their communities.
“I thought it was time the city of Detroit stepped up and took action on climate change,” Duggan said. “Too much of the climate change discussion in this country, as far as I’m concerned, is empty performance.”
Under the program, owner-occupied households in selected communities would be eligible to receive $10,000 to $25,000 in energy-efficient upgrades, such as new windows, roofs, energy-efficient appliances, or battery back-up for power outages.
Detroit would own the land for the solar arrays and contract with private solar developers to build and operate them. Details for how the city would be credited for the power are not yet determined, Duggan said.
Of the nine, he said six will be selected to assemble 250 acres of vacant and underutilized land to offset the electricity used to power city operations. Duggan said the project will cost the city about $8 million a year, or roughly what Detroit now pays DTE Energy to power the city’s 127 public buildings, plus $1-2 million per year more to provide community benefits. He said he plans to bring a funding proposal to city council by spring.
The finalist neighborhoods include Gratiot/Findlay, Greenfield Park/I-75 McNichols, Grixdale, Houston Whittier/Hayes, I-96/Plymouth (O’Shea), Mount Olivet, State Fair, Trinity Pickford and Van Dyke/Lynch.
Duggan emphasized that the city would place solar arrays only in areas “where we are wanted,” noting that the city would buy out residents in owner-occupied homes with a minimum offer of $90,000 and would pay moving costs and 18 months’ rent for tenants. He previously said the city sought “stretches where they don’t have more than one or two occupied homes.”
But several proposals contain a number of residences, especially rentals.
For example, the footprint of the 21-acre Mt Olivet project contains 16 renter-occupied and seven owner-occupied homes. Duggan said the fenced-in solar panel arrays would contribute to neighborhood stability and prevent illegal dumping in vacant and abandoned areas of the city.
But Duggan spokesperson John Roach said the city could also use eminent domain to assemble land for the arrays, and the mayor said the city may condemn vacant properties owned by speculators. The finalist neighborhoods have until Jan. 31 to provide documentation that residents in owner-occupied homes are willing to move.
Measha Parker has lived in Gratiot-Findlay for 18 years. She’s president of her block and said she hoped the fenced-in panels on 24 acres would help fight illegal dumping and drive out illegal drugs in the area.
She’d also like to see the former Wilkins Elementary School building, which has sat vacant for years, demolished as part of the plan. But she is concerned about vandalism and hopes the solar arrays will have surveillance cameras.
“It’ll bring safety over there,” she said. “Once they put the solar panels up…. It’ll help with the blight and help the whole area survive.”
But several residents and sustainability advocates Planet Detroit talked to question the emphasis on large solar arrays that won’t provide energy directly to residents. Others voiced concern that the projects could attract even more blight.
Birch Kemp, a lifelong Detroiter and president of the nonprofit tree-planting organization Arboretum Detroit, said he supports installing solar panels on top of buildings but worries that fenced-in solar fields will only add to blight problems and hurt property values.
Kemp said city officials approached him and others living in and around the Poletown East area about a possible array around Perrien Park, a former Detroit Public Schools site, but neighborhood organizations unanimously rejected it.
“It’s not going to increase anybody’s property value. It’s not going to make it look more beautiful. And it’s not going to increase your access to green space,” he said. “It’s going to be like a little prison for solar panels.”
A recent study found solar installations in California, Connecticut, New Jersey, Minnesota, and Massachusetts reduced property values by 1.5% within half a mile, and outcomes varied by state.
Kemp added that the solar fields would tie up land the city could use for open space and green infrastructure to sequester stormwater and prevent basement flooding. He also worries that trees would need to be cut down to reduce shade on the panels.
Experts consider tree cover important for reducing heat and managing stormwater. And while solar power is considered critical for dealing with the climate crisis, solar fields can create a localized increase in temperature.
This may pose a special problem in Detroit, where the heat island effect, or the capacity of impervious surfaces to absorb and re-emit heat, already increases temperatures by 8 degrees or more.
Jon Kent, a Riverbend resident and co-founder of Sanctuary Farms, also supports solar, but said communities hosting the arrays should benefit more than what he sees in the current proposal.
“They’re doing this within neighborhoods that are really poor and really disengaged,” he said, adding that these areas would be getting a one-time pay-out while the city would continue to benefit.
Kent said he’d like to see the city take more time with the process, doing additional community outreach and building in a more extensive community benefits process that could include allowing communities to renegotiate the terms for hosting arrays in the future.
The expedited time frame may be driven by pressure to secure federal support through the Inflation Reduction Act before this program ends in 2033. A city of Detroit spokesperson confirmed that the city is seeking federal credits to offset municipal operations’ energy use under the IRA. However, they added that the short timeline is because “the mayor feels the climate crisis is an urgent matter.”
Roach defended the current plan, saying the city worked with 15 renewable energy groups to develop the proposal and that eight groups, including Walker-Miller Energy Services, EcoWorks and the GreenDoor Initiative, have been working with neighborhoods to help them develop community benefit requests.
“This is a remarkable partnership between renewable energy advocates and neighborhood groups to design better neighborhoods that will help fight climate change,” he said.
Roach also pushed back on the idea that solar could hurt property values. “Those who best know the property values in a neighborhood are those who actually live there, which is why they will be the ones choosing the sites,” he said.
Jackson Koeppel, a Highland Park-based energy democracy practitioner and former executive director of the nonprofit Soulardarity, questioned the strategy of jumping immediately to large-scale solar arrays before embracing more targeted strategies.
“This approach to just build out as much solar on vacant land as possible to meet that need isn’t the right order of operations,” he said. Koeppel argues that on-site and rooftop solar and battery storage is the most cost-effective approach for city operations because it would generate “behind the meter” power that would allow the city to avoid the full cost of energy it would otherwise have to purchase.
Instead, the mayor’s proposal would have a third-party solar developer generate the power and likely sell it to DTE, which could then credit the city on its bills. The city’s request for information from solar developers did include inquiries about behind-the-meter projects at municipal facilities.
North Rosedale resident Amanda Paige said the city could incorporate solar energy into the urban landscape in other ways, like installing rooftop solar panels in neighborhoods or putting panels on top of structures like parking garages and bus shelters.
She worries especially about those living in some of Detroit’s most disinvested neighborhoods who may be underwater on their mortgages and struggling to build generational wealth.
“They’re not attractive,” Paige said of solar panels. “It’s not going to do anything for your long-term property values if you’re across the street from a big solar farm.”
Maine is drafting plans for its share of nearly $9 billion in home energy and efficiency rebate funding from the Inflation Reduction Act, with a straw proposal due out by the end of the year for input from contractors and other professionals who will be on the front lines of promoting new and expanded incentives to the public.
The landmark 2022 climate legislation known as the IRA included two programs focused on household rebates for weatherization, electrification and more, aiming to reduce energy use, costs and emissions for low-income families in particular.
Maine and other states are crafting applications to the U.S. Department of Energy that detail how they hope to use the funding on new and expanded incentives. States will have to balance offering larger rebates with ensuring more availability, while navigating overlaps with existing programs and considering new goals.
The IRA programs at issue include $4.3 billion across all states for “energy-saving retrofits” and another $4.5 billion across states and tribes for efficient electric appliances and equipment.
“It’s an unprecedented amount of money to be going to this particular thing of helping people make their homes more modern, cleaner, healthier and cheaper to operate,” said Kristin Eberhard, the senior director of state and local policy with the electrification advocacy group Rewiring America.
Maine, for its part, can get about $36 million from each program — and, under each, must direct a minimum of about $11.5 million to low-income households and another $2.8 million or more to low-income people who live in multifamily housing.
“It’s really transformative,” Eberhard said. “It’s going to have a much bigger impact than anything we’ve seen up to date on those harder-to-reach households.”
Maine energy officials say these groups are already a priority for growing the impact of existing rebates, and will be top of mind in their IRA plans.
“We’re trying to figure out where the gaps are and how we could deploy these funds to fill some of those gaps,” said Efficiency Maine Executive Director Michael Stoddard, whose quasi-governmental agency oversees state energy incentives.
Through rebates, loans, aggressive marketing and coordination throughout the supply chain, Maine has emerged as a national leader in deploying electric heat pumps, which provide high-efficiency space heating, cooling and water heating.
Buildings are an entrenched source of planet-warming carbon emissions in Maine, where a greater share of households rely on home heating oil than any other state. That dependence declined from 70% to 56% in 2022, the state reported on Nov. 9.
Maine has already met the initial 2025 heat pump target in its climate action plan, but lags behind on its goal for getting the technology into lower-income homes.
The state already offers hundreds of dollars off heat pumps for people of any income. Lower-income families can get $2,000 off their first unit. For those who qualify for government assistance, both equipment and installation may be free.
This 100% coverage is essential for the lowest-income families, Eberhard said — those who “can’t put up anything.” But Maine’s existing program “only has so much funding,” she said. “It can only reach so many households.”
“So some of that is where these rebates are going to come in and … give an infusion where they will be able to reach a lot more low-income households,” Eberhard said. “They know how to do it now. It’s just the money to do it.”
Efficiency Maine, working with MaineHousing and the Governor’s Energy Office — the federal designee for receiving this IRA money — is contemplating new income tiers to help make higher rebate amounts more accessible, according to Stoddard.
People with the lowest income might qualify for the highest rebates — $8,000 or 100% of project costs for heat pumps, under IRA rules. And the state might split the moderate-income category, which will receive lower rebates, into two tiers, offering more flexibility for people at different income levels than under current programs.
People in multifamily buildings are able to qualify alone or collectively, based on their income or the share of tenants in the building in each bracket. The IRA also includes rules that would allow renters to request rebates for their apartments.
Stoddard expects IRA funding will be especially useful for moderate-income households to move toward “whole-home” heat pump systems, which are a key part of Maine’s long-term electrification goals.
But just as important, he said, is what Maine doesn’t plan to do with its IRA funds.
“What these IRA rebate programs enable us to do is expand and extend the number of customers that we can serve — but it’s not likely that it’s going to dramatically change the amount of incentive on any individual project,” Stoddard said. “That may be true in other states … where they’ve had no programs until this money came along, but that’s not the case in Maine.”
Several kinds of heat pump hot water heaters, for example, are basically free under current incentives, so Stoddard doesn’t expect to emphasize those for IRA funding.
Likewise, he doesn’t expect Maine’s single-family home insulation rebates will change. He said the IRA’s rules for modeling energy savings for these rebates could be onerous or too costly for individual customers.
Instead, Stoddard expects Maine to focus this pool of money again on multifamily buildings, where the IRA’s requirements may be easier to accommodate in bulk.
These rebates come from the efficiency portion of IRA, and will vary depending on how much energy the user will save — hence the need for modeling. But weatherization isn’t the only allowable path to achieving those savings, Stoddard said, meaning that multifamily buildings could also use this money for heat pumps.
State applications for this IRA funding have to include consumer education and outreach plans and other strategies, including a “market transformation plan” on how the use of this money will help lead to ongoing home energy investments.
Eberhard said Maine has already set a standard for this kind of transformation with its approach to heat pumps — working “upstream” with suppliers, distributors, contractors and retailers to make savings and resources as accessible as possible.
“If we had that in every state in the country, where you walked into Lowe’s [and heat pumps were front and center], and your contractor knew how to do it, and your distributor could take care of the rebate — that’s a real game-changer,” she said.
There’s no hard deadline for states to apply for the IRA rebate funds, and the money is available through the fall of 2031. But Dan Burgess, who heads the Maine Governor’s Energy Office, said efforts like those that Maine has already established should make its IRA rollout easier.
“I think we’re in a good place to put these funds to good use and to hopefully be one of the early states moving forward with a rebate program,” he said.
Steel doesn’t have a great set of climate credentials.
The iron and steel manufacturing industries have a huge emissions impact, accounting for 7% of carbon dioxide emissions in 2020, according to the U.S. Energy Information Administration. Producing iron and turning it into steel also takes tons of heat and power, making the industry a hard candidate to convert from fossil fuels to electric power.
But one major steel producer has found success in cleaning up its process. Ohio-based Cleveland-Cliffs cut emissions last year by almost a third from 2017 levels at a few dozen of its U.S. facilities, winning it federal recognition, Kathiann M. Kowalski reports.
Much of that progress stems from Cleveland-Cliffs’ opening of a “direct reduction” plant in Toledo. Its steel is made with pelletized iron ore, which already has many impurities removed, reducing the power needed to turn the pellets into hot briquetted iron. From there, the hot briquettes can head into an electric furnace, where they can be turned into steel with a lower emissions impact.
Energy efficiency upgrades also made a difference, and the incorporation of hydrogen power could take the company’s emissions cuts even further.
After all, while climate advocates and steel company representatives know there’s more work to be done, Cleveland-Cliffs’ success proves that cleaning up steel is definitely doable.
Read more from the Energy News Network.
🌎 Climate predictions: The White House has released its National Climate Assessment, which predicts how climate change will likely impact each region of the U.S. — and how many states are leading on action to stop it. (Grist)
🗳️ Vote of climate confidence: Analysts say the 2023 election shows that a strategy by some Republicans to attack climate policy was “dead, flat wrong,” as Democrats made gains even in states where clean energy was a prominent issue. (E&E News)
🏭 A carbon capture milestone: The nation’s first direct air carbon capture facility is beginning operations in Tracy, California, where it’ll use limestone to capture carbon from the air and store it. (E&E News)
💸 Throwing away “free money:” Five large states have collected more than half of a federal climate grant program’s funding, while several smaller states still haven’t accessed “free money” for climate-related projects they’ve been offered. (E&E News)
☢️ Nuclear disaster? After a proposed small modular nuclear power plant was canceled over cost concerns, industry observers are questioning whether next-generation nuclear reactors will ever take off. (Deseret News, E&E News)
🔎 Search party: Startups pilot software that can help utilities and grid operators identify rare openings to connect new renewables to the grid. (Canary Media)
🚦 Driving emissions cuts: An environmental group found that California ranks first in the nation for transportation projects that address inequality while tackling climate change. (Bloomberg)
🔥 Does gas still make sense? Clean energy advocates say Wisconsin regulators should withdraw their prior approval for a 625 MW natural gas power plant, citing the availability of new grid storage and federal clean energy incentives. (Energy News Network)
🧱 Brick by carbon brick: A Bill Gates-backed startup company says it can effectively capture and store carbon by making bricks out of wood chips and plant pieces, which it can then bury deep underground. (Washington Post)
A group of utilities that once went big on building transmission is now going small to open bottlenecks and move more wind power from western Minnesota and the Dakotas.
Grid North Partners, which includes 10 investor- and consumer-owned utilities, will spend roughly $130 million for 19 transmission upgrades to improve access to wind energy and reduce grid congestion.
Many of its members, including Xcel Energy, Minnesota Power and Great River Energy, are also involved in much larger transmission projects through the Midcontinent Independent System Operator, or MISO, which manages the grid in the central portion of the country.
The utility partnership came together in 2004 to begin planning additional transmission lines to tap wind generation in the state’s western regions and the Dakotas. The CapX2020 initiative, as it came to be called, developed the largest transmission project in the Upper Midwest in more than 40 years.
Between 2010 and 2017, CapX2020 spent $2 billion on five projects that created more than 800 miles of new transmission lines. The initiative interconnected 3,600 megawatts of wind energy, enough to power 1.5 million homes annually.
The planning for CapX2020 took place before MISO began extensively planning regional transmission lines. MISO eventually incorporated CapX2020 into a portfolio of projects that decade, a precursor to a current batch of projects announced this year known as “Tranche 1,” two of which involve Great River Energy.
Beth Soholt, executive director of the Clean Grid Alliance, said the Grid North projects serve a different purpose. Rather than add a huge volume of new capacity, the projects will create “a bridge until we get the new large transmission lines in place” and create enough capacity to allow utilities to continue adding solar and wind.
Utilities involved seek to “use the existing grid we have better,” she said. “You’ve got a spectrum of smaller things you could do quickly, that are not going to solve your whole problem, but they’re going to help and they’re going to be quick.”
Unlike bigger projects, which will take years, Grid North Partners said the upgrades will be completed over the next three years and be finished by the end of 2026. The partnership of the state’s major utilities and cooperatives includes Xcel, Great River Energy, Minnesota Power, Otter Tail Power, Dairyland Power Cooperative, Missouri River Energy Services, Rochester Public Utilities, Southern Minnesota Municipal Power Agency, Central Municipal Power Agency and WPPI Energy.
Matthew Ellis, Great River Energy’s manager of transmission strategy and development, said big transmission projects take eight to 10 years to build. The generation and transmission cooperative is involved in six Grid North Partners projects in collaboration with other members.
“The goal of this effort was to identify what can be done incrementally to mitigate congestion within the next two to three years,” he said.
Congestion blocks the transmission of clean energy generation and has caused the growing problem of wind curtailment in western Minnesota. The projects will allow “cost generation, like wind and solar, to have better access to the transmission grid,” he said. “The transmission grid is all interconnected. What these projects directly do is allow better access for clean energy resources.”
Grid North Partners conducted the research to determine the location of transmission bottlenecks. Ellis said the experience is a bit like looking at traffic maps and where congestion occurs at different times and places. Electricity from wind and solar generators slows at sites in different parts of the state, he said.
Fixing one part of the grid to reduce congestion sometimes means just adding to another location. “One of the advantages of Grid North Partners is that, by having different utilities partnering up, we can mitigate those downstream impacts,” Ellis said. “We can get a lot more bang for our buck and much more synergy.”
Ellis said the transmission upgrades mainly focus on replacing old equipment, not on adding lines or new transmission towers. Instead, newer technology allowing them to operate more efficiently will be installed. Grid North Partners said in a news release the project will pay for itself.
Upfront costs will be paid for by the utilities that will benefit from them. In some projects, several utilities will split costs; in others, the line and work will be owned by one of the partners, Ellis said. The transmission lines affected by the projects span in length from half a mile to 67 miles.
Xcel Energy said in a statement that congestion in western Minnesota caused by wind projects has pushed the existing grid beyond what it can support and forced the utility to use peaking plants to supplement the energy supply at peak demand times. Congestion “limits our efforts to keep costs low for customers,” Xcel said.
Xcel will partner or be the sole sponsor on 10 Grid North projects, more than any other utility. Two of the largest Xcel projects add second circuits to the existing CapX2020 transmission lines between eastern South Dakota and Lyon County, Minnesota, and between Scott and Dakota counties. After regulatory approval, the western line will be completed by 2024, with the Scott-Dakota project slated for 2025. Xcel has partners on both projects.
“We estimate hundreds of millions of dollars in benefits to customers following the completion of the project due to reduced congestion costs and increased ability to access renewable energy in the region,” Xcel said.
Otter Tail Power’s seven Grid North projects involve upgrading substations, adding circuits and replacing electricity poles, said communications director Stephanie Hoff. No new facilities will be added by the utility.
Hoff said Otter Tail has partnered with other regional utilities on two projects in the long-range MISO plan. Although the Grid North Partners initiative does not directly impact Otter Tail’s generation assets, including renewables, the investment will help the grid function more effectively, she said.
“New and upgraded transmission helps move electricity from where it’s generated to where it’s used,” Hoff said. “When the transmission system can’t move electricity from the most economic energy generators, market prices rise and energy generators may need to be curtailed, resulting in higher electricity costs for customers.”
Grid North Partners’ budget is tiny compared to projects announced by MISO and Xcel. MISO will spend $10.3 billion on its first tranche of transmission projects, with more than $2 billion dedicated to corridors entirely or partially in Minnesota. Xcel Minnesota Energy Connection, linking wind farms in the southwest to a plant in Becker, will cost $1 billion.
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Illinois is the home of the world’s first nuclear reactor, and has since made a business of splitting atoms. Today, nuclear power is the source of more than 50% of the state’s energy, and legislators just decided Illinois needs more of it.
With bipartisan support, Illinois lawmakers last week eliminated the state’s nearly 36-year-long ban on construction of new nuclear reactors, opening the door for the development of emission-free nuclear power that proponents say will accelerate the state’s transition to clean energy.
The plan, however, will exclude the large scale nuclear reactors that make up the entirety of Illinois’ nuclear fleet in favor of smaller, untested nuclear reactors – which could take years to build.
The new legislation will limit the kind of nuclear reactors that can be built within the state to small modular reactors (SMRs) with an electrical output of only up to 300 megawatts. For comparison, the Byron Power Station, a large-scale light water reactor in northern Illinois, can generate up to 2,347 megawatts – enough to power more than 1.7 million homes.
The idea is the smaller reactors will be produced at factory scale, which will lower costs over time and bring them online faster than previous generations of reactors. Currently, there are no SMRs in operation or even production anywhere in the U.S.
As coal burning plants go offline in southern Illinois to meet a 2045 statewide climate goal to offramp the state from fossil fuels, State Sen. Sue Rezin, the lead co-sponsor of the bill, said SMRs could be a boon. And even a lifeline to the region, which has faced energy issues with affordability and reliability.
“You have a very highly skilled workforce that used to work at the coal plants that can now build out the new nuclear plants and work at the new nuclear plants,” Rezin said. “It’s a win-win.”
She adds that the state’s major agricultural and technology forward industries could capitalize on the emission free energy to decarbonize.
Abe Scarr, the director of the Illinois Public Interest Group, a non-profit watchdog group, opposed the legislation.
“I wouldn’t be confident that based on this, anybody’s going to be building SMRs in Illinois,” Scarr said. “It’s still a speculative technology. The largest company in the United States that was moving towards building one just announced that it was scrapping the project because it had gotten way too expensive.”
The NuScale Power Corporation announced last week that its venture, a first of its kind SMR project in the country, fell apart after 10-years of work and more than a $1 billion pledge from the Biden administration due to issues with financing.
Even so, the U.S. Department of Energy is counting on more nuclear power. In a report released this year, officials estimate that to successfully hit net-zero emissions by 2050, the country will need to add an additional 200 gigawatts of reliable generating capacity. To hit that target, the agency is looking at nuclear power such as SMRs.
But the American public soured on nuclear after the 1979 partial meltdown of the Three Mile Island power plant in Pennsylvania, and nuclear development nationwide all but halted. Only a handful of reactors have come online since.
States started banning new construction of nuclear reactors until the federal government could identify a permanent solution for the nuclear waste piling up across the country. In total, 16 states enacted some level of nuclear ban. Illinois put its own in place in 1987. A masterplan for the country’s nuclear waste never materialized.
Illinois is done waiting. Gov. JB Pritzker has vowed to sign the new bill, and soon Illinois will join Wisconsin, Kentucky, Montana and West Virginia in rolling back nuclear bans.
Mark Nelson, founder of the Chicago-based energy consultancy group Radiant Energy, said the state is making a mistake by banking on SMRs.
“It’s going to be a really rough and exceptionally difficult energy transition if we don’t do it based on nuclear energy, which we have proven to work in upstate Illinois,” Nelson said.
He said the exclusion of large-scale reactors is a mistake because “the only proven nuclear plants in the world are cut out of this bill. And the only ones we’re allowed to build are the ones that are expensive and going bankrupt.”
The law would take effect in 2026, and according to Rezin, could take anywhere from six years to a decade to obtain the permits necessary to build a new reactor in the state.
Ohio-based Cleveland-Cliffs’ success in beating its goal to cut greenhouse gas emissions from its U.S. iron and steel operations won recognition from the Department of Energy last month.
The progress is part of a broader industry trend to cut pollution that drives human-caused climate change. Yet advocates say there’s lots of room for further cuts.
Cliffs slashed greenhouse gas emissions for almost four dozen U.S. facilities by nearly one-third from a 2017 baseline as of the end of last year. As a result, the Department of Energy named the company a 2023 Goal Achiever in the agency’s Better Climate Challenge.
The steel industry was responsible for about 7% of global carbon dioxide emissions as of 2020, the U.S. Energy Information Administration reported last year. That’s roughly one-sixth of all worldwide emissions from generating power, according to a Canary Media analysis of the International Energy Agency data. The iron and steel industry led the industrial sector, with the cement industry coming in second.
The achievement and ongoing decarbonization efforts by Cliffs and other companies stand out because the steel industry has been seen as a hard-to-decarbonize sector, due to its need for high heat and continuous operations, as well as process reactions that emit more carbon dioxide.
At the same time, the energy transition and growth of renewable energy will likely increase demand for steel, and global demand for low-carbon steel should grow as well, according to a McKinsey & Company analysis released earlier this year. Companies in the steel industry also see a need to curb emissions in order to limit the worst impacts of climate change.
“We do know that we play a role in global warming,” said Traci Forrester, executive vice president for environmental and sustainability matters at Cliffs.
Added incentives come from the prospect of possible government regulation of carbon emissions in order to address climate change, as noted in the company’s 2022 annual report to shareholders, released this past April.
Customer demands also play a role. “At U.S. Steel, it’s not just about reducing our own carbon footprint,” said Arista Joyner, who manages financial and sustainability communications for that company. “We must adapt to the changing needs of our customers and their sustainability goals too.”
The traditional method of making steel mixes iron ore in a blast furnace with a high-carbon form of coal, called coke. The carbon combines with oxygen in the ore to form carbon dioxide. The iron melts. Other leftover waste takes the form of slag.
The iron — called “pig iron” at this stage — is then sent to a second furnace that blows in oxygen to make steel from the iron and some other elements. That also releases greenhouse gas emissions.
Together, the two steps account for nearly three-fourths of the U.S. iron and steel industry’s carbon dioxide emissions, according to RMI, a nonprofit whose work focuses on decarbonization.
Much of Cliffs’ progress on emissions is thanks to the 2020 opening of its “direct reduction” plant in Toledo. The facility starts with pelletized iron ore, which comes primarily from Minnesota, where a preliminary baking process has already removed some impurities.
Direct reduction removes oxygen from the ore with reformed methane, which is basically a combination of carbon monoxide and hydrogen. Both the hydrogen atoms and the carbon monoxide molecules can combine chemically with the oxygen. So, direct reduction is a lower-carbon way to process the ore pellets. The plant’s output is hot briquetted iron.
The Toledo plant has not eliminated the company’s use of blast furnaces. But hot briquetted iron can reduce the amount of coke needed if its next stop is a blast furnace, Forrester said. Transporting the briquettes while they’re hot also cuts down on fuel needs there or for the oxygen process furnace.
Hot briquetted iron can also go into an electric arc furnace. The steel industry mainly uses those furnaces now to recycle scrap steel.
“The beauty of steel is that it’s infinitely recyclable,” said Rich Freuhauf. The senior vice president and chief strategy and sustainability officer for U.S. Steel spoke at a Reuters Industry Transition conference in September.
Recycling eliminates the need to repeat the carbon dioxide-releasing steps of refining iron ore. And, as the name implies, electric arc furnaces run on electricity. So they could use nuclear power or renewable energy with battery storage instead of fossil fuels.
But recycled steel from electric arc furnaces won’t necessarily satisfy all the forecast demands for steel. Nor does it yet meet the requirements for some higher-grade or specialty types of steel. Those include higher-strength steel and high-ductility steel, which can be formed into different shapes, such as the exposed panels on automobiles.
“That’s really our niche in servicing the automotive market, in addition to many other markets,” Forrester said. Some carbon content can also help achieve different properties in steel.
Cliffs’ emissions cuts also reflect energy efficiency improvements throughout its facilities, Forrester said. And there’s room for more emissions reductions.
Cliffs is part of the Midwest Alliance for Clean Hydrogen. Assuming acceptable agreements can be negotiated with the agency, the coalition stands to get up to $1 billion in hydrogen hub funding, the Department of Energy announced last month.
The hub could help supply Cliffs’ Indiana Harbor and Burns Harbor plants. Hydrogen would likely be blended with natural gas at first, Forrester said. Then, if all goes well, hydrogen could substitute for more or potentially all of the fossil fuel.
Cliffs also was part of the Great Lakes Clean Hydrogen Hub Coalition, which proposed making so-called “pink hydrogen” with excess electricity at the Davis-Besse nuclear plant in Ohio. Although DOE did not pick the project for a regional hydrogen hub award, the Energy Harbor plant has been working on hydrogen production for several years. Spokesperson Todd Morgano said the project “is scheduled to be operational by spring of 2024.”
The steel industry has also been buying more renewable energy. Last December, for example, Cliffs agreed to a 15-year power purchase agreement with EDP Renewables for 180 megawatts of power from a wind farm in Indiana near the Ohio border. State laws passed in 2014 and 2021 make it extremely difficult to site new commercial wind farms in Ohio.
Carbon capture utilization and storage, or CCUS, could also curb the steel industry’s emissions, although its feasibility hasn’t been proven yet.
“While carbon capture technologies exist and are widely adopted in the oil and gas realm and some other industries, carbon capture has never been done with blast furnace gas,” Forrester said. Cliffs has multiple facilities near areas with suitable geologic formations for storing the waste carbon dioxide, she noted.
Other research is exploring whether carbon might be further cut or eliminated from the ore-processing stages. In June, the Department of Energy announced nearly $32 million in funding for projects to decarbonize iron and steel.
One of the 10 projects that won funding, led by Cleveland’s Case Western Reserve University, would use an electric current with molten salt to strip oxygen from iron ore. Case Western is also among the partners for the Center for Steel Electrification by Electrosynthesis, headed by Argonne National Laboratory in Lemont, Illinois.
“From our standpoint, Cleveland-Cliffs has been a good actor to date,” said Nick Yavorsky, an RMI industry analyst who co-authored a September report on opportunities for making near-zero-emissions steel in the Great Lakes region. But, he added, “now we have to look at the big stuff.”
While hydrogen could potentially power all of a direct reduction plant, there are limits on how much could be blended with coal at a blast furnace, he said. Further big cuts would likely call for retiring coal-burning blast furnaces and replacing them with more direct reduction plants. Yavorsky said he also thinks most specialty steel products could be made in electric arc furnaces run on renewables or nuclear power with hot briquetted iron.
Ohio policymakers could support investments to achieve those shifts, including through existing programs for JobsOhio, said Lachlan Carey, an RMI policy analyst and economist who also worked on the September report. Supporting green steel could increase the state’s steel industry employment, while also enhancing Ohio’s ability to attract other manufacturing jobs where companies want access to clean energy, he said.
U.S. Steel has already committed to net-zero greenhouse gas emissions by 2050, Freuhauf said. Cliffs has so far shied away from that.
“We take a very practical approach to reducing greenhouse gases and the statements and promises that we make,” Forrester said, adding that while the company has aspirations, it focuses on what it knows it can achieve. “We take action on what we can today,” she said.
Maine is considering new kinds of electric rates to encourage more widespread home adoption of electric vehicle chargers and heat pumps while easing the strain these technologies add to the power grid.
Central Maine Power, the larger of the state’s two investor-owned utilities, is working with regulators and advocacy groups on designs for time-of-use rates, which charge customers more for electricity use at times of day when demand on the grid is at its peak.
But these rates are only one piece of the puzzle, stakeholders say. They anticipate more planning work to come on complementary technologies that will make it easier for customers to change their energy use.
Time-of-use and related tools to limit and shift electricity demand are currently most common among larger commercial and industrial customers, according to the U.S. Department of Energy. But as home electrification accelerates, some utilities have begun trying out similar programs for residential ratepayers.
Central Maine Power is currently piloting seasonal heating and electrification-focused rates, and the smaller Maine utility, Versant Power, has its own time-of-use programs for heat pumps and electric vehicle charging already in place.
The Maine Public Utilities Commission is working to expand time-of-use rates on multiple fronts, including in one proceeding that was required as part of the June settlement in Central Maine Power’s latest rate case. The utility, which is owned by Connecticut-based Avangrid, is due to file a proposal on the issue Dec. 1.
“I personally believe that there’s a great opportunity here for all of our policy goals to be advanced,” said deputy Maine public advocate Drew Landry, whose office acts as an ombudsperson for residential utility customers. “But if we do it wrong, there’s a chance that we could undermine all of them.”
Transportation and buildings are Maine’s top sources of planet-warming greenhouse gas emissions. This underlies the state climate plan’s ambitious goals for expanding the use of electric vehicles and heat pumps, which use electricity for high-efficiency water and space heating as well as air conditioning.
Maine relies more than any other state on home heating oil but has made strong progress on switching to heat pumps, already meeting its initial target of installing 100,000 new units by 2025. The large, rural state is also hoping to accelerate its so-far slow progress on electric vehicle adoption.
The utilities commission’s goals for its ongoing time-of-use work with Central Maine Power and other stakeholders are to “incentivize customers to shift usage away from the summer peak,” encourage wintertime use of heat pumps and other efficient systems, and complement state rebate and discount programs for this kind of technology.
In its upcoming proposal, the utility must consider at least four alternative rate designs specific to electric vehicles and heat pumps and consider a rebate program for customers who successfully reduce their electricity usage at peak times. The utility is also asked to propose a “customer education and communication plan” on these initiatives, and will have to draft data-gathering plans to aid in future, similar rate design processes.
Rates in this particular proceeding would fit under the distribution charge on customers’ bills. A separate ongoing docket looks at tying similar rates to the supply charge, which is a larger part of ratepayers’ costs.
Landry, the deputy public advocate, said more use of heat pumps and electric vehicles is sure to drive up New England’s peak demand, which typically falls between 5 and 9 p.m. in summer and, increasingly, winter.
Absent large-scale energy storage, Landry said, this increased demand could exceed available renewable power supplies, potentially adding to emissions. New England’s grid remains largely reliant on natural gas and, in recent years’ cold snaps, has tended to burn oil and coal as its backup fuels.
Widespread electrification will require significant and costly investment in transmission and distribution infrastructure, stakeholders say, no matter how rates are designed.
But they see time-of-use as a way to moderate that impact. These rates, Landry said, send a price signal that encourages electricity use at “off-peak” times when it will be easier and cheaper on the grid — nudging people, for example, to wait to charge their cars until near bedtime as opposed to right after work.
The solution is less straightforward for heat pumps, but Landry said pre-heating with a smart thermostat or using an electric thermal storage system could help limit the need for intensive heating during peak hours.
Landry and others agreed that helping customers access technology to manage their electricity use — and making it extremely simple to navigate related rate changes — will be vital to success.
“There needs to be careful consideration and effective implementation of consumer protections to make sure that it doesn’t create financial hardships for customers who are either low-income and/or have high energy burdens, in this time of high electricity prices,” said Phelps Turner, a senior attorney with the Conservation Law Foundation, which is an intervenor in the distribution-focused utilities commission proceeding.
Landry said he feels customers need “an action they can take in response to the price signal.” Otherwise, the rates “may simply penalize customers for using electricity when they have limited options,” he said, or “may be perceived as being burdensome,” creating a potential backlash.
Efficiency Maine, the quasi-governmental agency that runs energy rebate programs for the state, already offers a “load management” incentive of $50 upfront plus $50 a year for electric vehicle drivers who give the agency permission and electronic access to set their cars to charge automatically overnight by default.
“Study after study shows that the cost of our transition, very broadly — like the amount of generation, transmission, distribution that we need to fully electrify our economy — is dramatically lower the more load control you have associated with it,” said Ian Burnes, the agency’s director of strategic initiatives. He referenced a recently published draft study from ISO-New England, the regional grid manager, showing that transmission costs to accommodate increased load rise sharply with higher peak demand.
This means programs like Maine’s existing electric vehicle incentive will be important pairings to any future time-of-use rates, he said. “What we’re trying to build off of is to have devices that can respond to prices,” he said, “so the customer just has to say, ‘I’m just going to set this up once,’ and then the device does the work for them.”
With Central Maine Power’s initial time-of-use plans still in progress, there are open questions remaining around whether participation should be “opt-in,” and whether and how these rates might apply only to people who use relevant technologies or to all ratepayers.
Either way, customer education will be key, said the Conservation Law Foundation’s Turner — either ensuring that ratepayers understand the benefits of signing up if the rates are voluntary, or offering easy steps they can take to avoid penalties and achieve cost savings if the rates are automatically applied.
Burnes said he also hopes that more data-gathering by the utilities and agencies like his will help assess the “fairness” of current and future electrification-focused rates.
Smart meters will be one tool to achieve this, he said, with a goal of determining whether new rates only make power cheaper for some more than for others, or whether they create savings across the system.
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