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New Hampshire’s electric utilities have come out in favor of continuing the state’s current system for compensating customers who share surplus solar power on the grid.
Eversource, Unitil, and Liberty Utilities surprised clean energy advocates by submitting joint testimony to state regulators last month endorsing the state’s current net metering structure. The program credits customers roughly 75% of the standard electricity rate for any unused solar generation that flows back onto the grid and is used by other customers.
“I am delighted that our utility friends have come over to our way of seeing things,” said Sam Evans-Brown, executive director of Clean Energy New Hampshire.
The utilities’ testimony is part of New Hampshire’s current deliberations over whether the state’s net metering rules should be adjusted. The process in New Hampshire is playing out as many other states are also debating what role net metering should play in the transition to clean energy.
Net metering provides an important source of revenue for solar customers when their generation doesn’t perfectly match their electricity use, but critics contend that it unfairly shifts costs to consumers who don’t generate their own renewable energy.
“I think renewable energy is great,” said Rep. Michael Vose, chair of the state House’s Science, Technology and Energy Committee, who has supported bills that would have cut net metering rates. “If people can afford to buy it and want to buy it, they should go ahead, but I am not in favor of subsidizing renewable energy and shifting costs to people who don’t directly benefit from that renewable energy.”
New Hampshire’s current rules, put in place in response to 2016 legislation, replaced a previous system that gave participants credits equal to the price utilities charge customers for electricity. This same law also required the state to conduct studies on the impact and effectiveness of net metering and make changes to the regulations if the findings warranted.
Previously, the utilities had advocated for much lower rates for net metering customers. Nationally, utilities have often taken the same position as well, arguing that higher net metering rates push costs onto customers who can’t afford to buy solar panels.
At a glance, it’s easy to dismiss: if a homeowner sends 1 kilowatt-hour of power to the grid and receives a credit worth the price of 1 kilowatt-hour, it would seem everything should come out even. But the retail price of electricity includes more than just the cost of the power itself — everything from the salaries for lineworkers who do maintenance to the cost of debt on construction projects to keep the wires and poles safe and reliable.
“The whole system is packaged up and rolled into the price,” Evans-Brown said.
So when a homeowner receives a full retail credit for their power, they are getting paid for more than just the energy they are providing, increasing the cost to run the utility. These costs are then passed on to the utility’s entire consumer base. A lower net metering credit means less of this sort of cost shifting and, some argue, a fairer deal for customers without solar.
The gap between net metering rates and utility costs can be even more pronounced at certain times of day. In the early afternoon on a sunny summer day, demand on the grid is low, meaning the price for power from the grid drops as well. At the same time, solar panels are producing plenty of excess energy. Utilities can end up paying higher rates for this electricity than they would have had they been buying from a power plant, at a time when excess residential solar energy wasn’t even needed to help meet high demand.
“Solar does not make the grid more reliable or resilient, nor does it improve power quality in any way,” Thomas Meissner, chief operating officer of Unitil, testified in 2016.
Supporters of a strong net metering rate, however, argue that net metering creates an array of benefits for utilities that solar generators should be compensated for. The report produced in accordance with the 2016 law notes that solar can reduce capacity payments the utilities must make, reduce the cost of complying with renewable energy standards, and lower the amount of power lost traveling through transmission lines, among other benefits.
Utilities, however, have generally downplayed these benefits. However, in their joint testimony, the utilities go so far as to praise the economics of the system.
“New Hampshire’s net metering policy — which is among the most balanced in New England — has been effective in encouraging the growth of [solar] resources in our state, and there is no evidence that the current compensation level is creating unjust cost shifts,” said Eversource spokesperson William Hinkle, after the testimony was filed.
The state report presents similar findings. It concludes that distributed solar generation should provide increasing value to the grid over the next 12 years. It also found evidence that limited cost shifting would occur, increasing the average residential bill in the range of 1% to 1.5%.
Supporters of net metering say this number is so small that it is an acceptable price to pay for the benefits of increased renewable energy. Vose, however, is concerned about any increased costs for consumers who have not chosen to install solar panels.
“That is one of the problems we’ve tried to ameliorate, to minimize such cost shifting whenever possible,” he said.
Nationally, net metering remains contentious in many states. For example, North Carolina’s public utility authorities have angered environmental groups and many in the solar industry by approving a utility plan to reduce payments to net metering customers. And earlier this year, California cut rates by about 75% for new net metering customers, with utilities pushing for even more cost-cutting concessions.
“They’re hugely disincentivizing rooftop and community solar,” said Patrick Murphy, senior scientist at PSE Healthy Energy, who researches clean energy transitions and energy equity.
Overall, the more a state lowers its net metering credits below the retail price, the more likely utilities are to embrace — or at least accept — the program, Murphy said. In New Hampshire, the reduction from full retail price to 75% has been enough to satisfy utilities.
The New Hampshire net metering docket remains open and the matter is under consideration by the Public Utilities Commission. Vose thinks it very possible that net metering rates will be further lowered. Evans-Brown, however, thinks the utilities’ recent testimony could have a significant influence toward keeping the current system in place.
“This makes it more likely that we will get a favorable outcome,” he said.
Thermo King, headquartered in the Minneapolis suburb of Bloomington, has for decades manufactured diesel-powered refrigeration and heating units for use in semi-trailers, trains, ships and buses. The company’s logo can be seen on ubiquitous “reefer” trailers being pulled along highways across the country.
As Thermo King has begun a massive transition to electrify its product lines, training employees has been a challenge — and a common one facing other companies moving toward electrification.
Last year, the company contacted the University of Minnesota’s Technological Leadership Institute to co-create and pilot a 12-credit engineering electrification graduate certificate. They believe the program offers the nation’s first graduate-level certificate specifically for electrification.
The collaboration led the state to fund the Minnesota Center for Electrification Opportunity, an initiative announced in July that will train workers in companies moving toward electrification and hybrid systems.
Jodie Greising, director of the Minnesota Job Skills Partnership at the Department of Employment and Economic Development, said that “to ensure Minnesota businesses remain competitive and to help workers retain jobs, it’s imperative that training is available to upskill and reskill workers in occupations such as technicians, electricians, and engineers to help integrate, troubleshoot, and design the systems that leverage these evolving technologies.”
Grant Ovsak, Electrification Center of Excellence leader for Thermo King Americas, helped develop the certificate.
“We’re moving towards a sustainable power source from diesel, which is the same transition as the automotive industry,” he said. “We have a large employee base that needs to be brought along for that journey.”
A division of Trane, Thermo King has more than 200 engineers at its Twin Cities campus who could benefit from the certificate. But Ovsak said he wants employees in many disciplines to take the courses.
“The certificate is not just for engineers,” he said. “We want human resource [managers] to take the courses because we’re hiring in that area, and they need to be able to talk the lingo. Even quality, aftermarket and project management employees can take the courses.”
As companies move toward electrification, all their employees must learn a new technical language that will take time and practice, Ovsak said. The courses will allow students to test batteries in a lab and see the problems, such as thermal runaway, that electrical systems potentially face, Ovsak said.
John Hurst, senior director of the landscape appliance company Toro’s Center for Technology, Research & Innovation, said around 20% to 25% of the company’s sales involve electric products, some of which have been on the market for years. Employees’ training on electrification has been primarily offered in-house or on the job.
In the past, Toro, also headquartered in Bloomington, has worked with higher education providers on training programs that proved hard to sustain, he said. Hurst said that having the university deliver the classes and offer credits should appeal to Toro employees and other companies. The ability to count the courses toward a graduate degree should also attract more ambitious employees.
“What excites me about this is it’s a pathway we can use to continually send people through year after year as we hire or retrain staff,” he said, adding that Toro plans to encourage rather than mandate the training.
Keith Dennis, president of the Beneficial Electrification League, said the confluence of federal, state and industry investments in electrification “merit more deliberate training opportunities. We are seeing some of this around the country, but it is mostly from an increased awareness of sustainability officers and from companies who sell the products themselves.”
The Minnesota Center for Electrification Opportunity is working on a long-term vision to quicken the pace of electrification, a strategy it believes will create employment growth in Minnesota and position its workforce for jobs in a variety of fields, from utilities to renewable energy companies.
The state has few options for retraining employees in companies moving to electrification. Like many states, Minnesota has created clean energy training programs at state schools for students seeking jobs in the solar, wind energy and biofuel industries.
Non-degree and certificate programs exist for electricians and people in construction through unions and clean energy training centers. Electrification courses designed for employees, however, are challenging to find.
The Center for Technological Leadership resides in the university’s College of Science and Engineering. Travis Thul, senior fellow and operations director at the Technological Leadership Institute, said the center’s role has been to work with industry to develop continuing education seminars, short courses, master’s degree programs and other training opportunities.
The electrification certificate will serve as the foundation of an eventual master’s degree, Thul said.
For now, he worries about attracting students to the program in a tight labor market where many employees are comfortable in their jobs and have little incentive to give up their nights to attend classes.
“We’re facing an unbelievable demand from the industry standpoint,” he said. “We need this talent for the United States’ economic competitiveness to be assured, while simultaneously we’re limited on human capital motivated and inspired to come and pursue these topics.”
The certificate courses will be taught by professors of practice who work at the United States Army Corps of Engineers, Toro and Polaris. A full-time tenure track professor at the university assisted in developing the coursework to reflect academic standards, Thul said.
One of those professors of practice is Toro electrical engineer Robb Anderson, who delivered the first introduction to electrification course to around 20 people, including managers, engineers and service departments who worked at Thermo King.
One challenge is keeping up with the fast-evolving field, Anderson said. Another is motivating people with full-time jobs to finish their classwork. By late August, the first cohort had a few procrastinators still filing the final papers, though Anderson felt confident they would make the deadline.
Anderson said the classes feature field trips to different companies at various stages of electrification. Classes visited a University of Minnesota wind turbine research facility, a Wabtec Corporation electric train operation in St. Paul, and Toro’s headquarters.
“Students hear about the challenges companies face, which makes the courses very real,” he said.
Hurst, a 23-year veteran of Toro, believes the certificate helps employees stay up to speed in an industry facing a monumental transformation. “I think for us, it’s an exciting journey,” he said. “I tell people walking in the door that it’s the best time to come right now because we have so much change.”
The Minnesota Center for Electrification Opportunity holds an “Electroposium” Oct. 9 at the university’s McNamara Alumni Center. The event offers training and information sessions on the future of electrification.
This article originally appeared in the Idaho Capital Sun.
Todd Fischer, an electrical engineer, has lived in his North End home since 1988. Built in 1905, the Victorian-style home is a juxtaposition between Boise’s historical architecture and modern energy technology.
On the inside, the home is aligned with wooden columns and a wooden staircase, but on the outside sit 16 solar panels on the south side of his rooftop that generate electricity for his home.
In an interview, Fischer said he installed his solar panels in 2016 and receives monthly credits for providing additional energy to Idaho Power’s grid. In the winter he pays $5.24, and in the summer months he pays $0.24.
“My power bills are beautiful,” he said, while holding a stack of power bills he has collected since installing the panels.
Fischer’s solar panels are a part of Idaho Power’s “legacy” system, meaning he qualifies for the company’s original credit system for homeowners providing extra energy to the grid. Fischer does not get paid for over generation, but instead he accumulates credits from Idaho Power that compensate for the cost of his energy usage from the grid at another time.
But soon, homeowners who are a part of the “non-legacy” system, meaning they installed solar panels after December 2019, could face changes in the amount of money Idaho Power credits to their account.
Idaho Power is awaiting a decision from the Idaho Public Utilities Commission on a proposal to decrease the amount it credits customers who sell their rooftop solar back to the grid. Fischer, who is compensated under the “legacy” system, would not be affected by the changes if approved by the utilities commission.
But along with local environmental advocates, Fischer argues that Idaho Power’s proposal disincentivizes home owners from installing solar panels.
On Aug. 5, the Idaho Climate Justice League, a youth environmental advocacy group, held a rally outside of the Idaho Power building in downtown Boise addressing concerns about the company’s proposal to reduce its credit rates for solar.
In a letter to Idaho Power CEO Lisa Grow, the youth advocates said the proposal is contradictory to the company’s 100% clean energy goal by 2045.
“We, the youth, demand change,” the justice league letter said. “We are the ones who will face the future consequences of your inaction. As the climate crisis intensifies, and as the date on your commitment to 100% clean energy draws closer, we will not stand idly by.”
But Idaho Power negates the justice league’s claims. In a response letter to the justice league, the company said it is committed to reliability and affordability for all of its customers.
“We support solar and we’re seeking to pay a fair market price for it, whether that’s from a large solar array or a customer’s rooftop,” the Idaho Power letter said. “We are proud to have some of the lowest energy costs in the nation, but we can only maintain that by making sure we’re looking out for the interests of all customers while we invest in our clean energy future.”
Jordan Rodriguez, the spokesperson for Idaho Power, told the Sun that residential solar power brings many benefits to the company, but that its current credit system, established 20 years ago, is outdated.
Rodriguez said Idaho Power supports customer choice, and it acknowledges that residential solar saves the company money on expenses that it would take to generate and distribute that same energy using other sources.
However, the proposal to change its credit system is meant to be more equitable to customers without solar, Rodriguez said – noting that the number of customers with solar generation in the company grid has grown significantly in recent years.
The number of Idaho Power customers with residential solar power has increased from nearly 1,000 in the Idaho Power system in 2016 to more than 13,000 in 2022, according to a company report.
Rodriguez said the rise in Idaho homeowners with solar panels is largely driven by the decrease in costs associated with installing solar.
Solar installation costs have declined by more than 50% over the past decade, so in addition to a decrease in installation costs, the desire to run on clean energy or save money on electric bills is driving solar adoption across the country, according to an article from the Solar Energy Industries Association.
“An average-sized residential system has dropped from a pre-incentive price of $40,000 in 2010 to roughly $25,000 today (2022),” the article said.
“We are looking to change the way we credit customers for energy they generate because the current credit structure is unfair to the 98% of our customers without solar panels,” Rodriguez said. “Customers without rooftop solar currently pay an unfair share of grid maintenance and improvement costs.”
The change would more accurately reflect an on-site generator’s use of the electrical grid, he said.
If approved by the utilities commission, the changes would include:
Idaho Power requested an effective date of Jan. 1, 2024, but the case is ongoing and the timing of the order is at the discretion of the Idaho Public Utilities Commission.
Rodriguez said the outcome of the utilities commission case will not impact the company’s 100% clean energy by 2045 goals, adding that the company has several large-scale solar projects under construction.
“We support solar energy — our proposal is intended to ensure our customers don’t pay more for solar energy from one source than they would from another,” he said. “Looking into the future, Idaho Power expects solar energy will continue to be an important part of our energy mix and clean energy goal.”
In late 2022, Idaho Power began purchasing energy from the Jackpot Solar Project at some of “the lowest prices for solar energy in the nation,” Rodriguez said. The project brings up to 120 megawatts to Idaho, providing energy to roughly 24,000 homes, the Idaho Capital Sun previously reported.
Rodriguez said the company is also working on pairing the solar projects with batteries. The batteries would help store power generated during periods of lower use and deliver the power during peak energy consumption times, which he said are typically during hot summer evenings when the sun has set but energy use remains high.
Rodriguez said misinformation about residential solar plays a role into public discontent with the company’s credit rate proposal.
“Customers are encouraged to get the facts about solar energy before making a financial commitment,” he said. “Any Idaho Power visits to customers’ homes will be preceded by a phone call or other communication. Idaho Power employees will arrive in a company vehicle clearly marked with Idaho Power’s logo.”
Idaho Power is hoping to dispel misinformation and scams related to residential solar power on its website.
Common tactics being reported include solar sales representatives:
While Fischer believes a new credit system at Idaho Power would disincentivize homeowners from installing solar panels, he said his decision to install solar panels was “definitely not a financial” decision—adding that installing them cost him about $17,700.
Additionally, the amount of time it will take to get a return on the investment is so long, assuming that he will be living in the same home until then, he said.
Fischer said he acknowledges that Idaho homeowners already enjoy a low electricity rate because of the state’s rich hydroelectricity production.
As such, he said investing in solar panels is not as “financially viable” as it would be in a state like California, which ties with Maine as the state where electricity prices are increasing the fastest in the country. Both states have seen a rise in electricity prices by 78% in the last decade, according to the Sunpower Solar Energy Report.
So what motivated Fischer to install solar panels? The decision was based on curiosity, he said.
As an electrical engineer, Fischer said he was “intrigued by solar power,” and wanted to get firsthand experience with it. He said his biggest concern when deciding to install solar panels was finding a reputable installer.
After installing the solar panels, he said there were other costs outside of the installation that he did not initially take into account such cutting down trees, replacing his roof and fixing water damage in his home after the solar panels were incorrectly installed.
“My advice would be to talk to your friends that have solar, find out if they were happy with the quality of work that installer did,” he said. “They can fall off your roof in a windstorm, and they can cause a leak in your roof.”
Despite the lessons he learned along the way, Fischer said he has no regrets after installing his solar panels.
“There’s a lot better investments you could do than solar panels,” he said. “If you wanted to spend that much money to have a lower carbon footprint, I suspect there are better options than solar panels.”
A share of $9.7 billion in funding under the Inflation Reduction Act can help Ohio’s rural electric cooperatives save money while cutting greenhouse gas emissions.
Buckeye Power, which provides generation and transmission services for the group’s 25 rural electric cooperative members, “has more exposure to coal” than any comparable group in the United States, said Neil Waggoner, federal deputy director for energy campaigns for the Sierra Club, so the IRA funding is an especially huge opportunity.
The U.S. Department of Agriculture’s New Empowering Rural America program is accepting notices of intent to apply for up to $970 million in funding for projects to cut greenhouse gas emissions and add renewable energy. Funding can include grants of up to 25% of project costs, as well as low- or no-interest loans.
The notices are due by Sept. 15. Full applications would follow later in the fall.
“We are aware of and actively working on a proposal for the USDA New ERA program but do not have anything to report publicly until the application is complete,” said Caryn Whitney, director of communications for Ohio’s Electric Cooperatives, referring to both the cooperative organization and Buckeye Power. The New ERA program is part of the IRA.
Environmental groups’ analyses suggest the member cooperatives’ 380,000 residential and business customers could see big savings if Buckeye Power replaces some or all of its coal-fired generation with renewables and storage.
Most of Buckeye Power’s current generation mix comes from the 1.8-gigawatt coal-fired Cardinal Power Plant in Brilliant, Ohio. Units 1 and 2 at the Cardinal plant are 56 years old, and Unit 3 is 46 years old. Buckeye Power also has an 18% share in the Ohio Valley Electric Corporation, which owns the two 1950s-era coal plants involved in the state’s ongoing House Bill 6 corruption scandal.
The marginal costs to run almost all existing coal plants in the United States already exceed the levelized all-in costs of new solar or wind generation, Energy Innovation Policy & Technology reported earlier this year.
Also, a report released in August by the Evergreen Collaborative estimated the Cardinal Plant’s costs going forward will be roughly $31.16 per megawatt-hour. Regional wind generation is 18.6% less costly than coal, and local solar is about 11% cheaper, the report said.
In addition to New ERA grants, Buckeye Power could “stack” money from other funding opportunities and tax incentives to further cut costs for switching to clean energy, said Mattea Mrkusic, energy transition policy lead at Evergreen Collaborative. The IRA provides larger credits if projects meet criteria for prevailing wages and domestic materials, for example.
Much of the territory served by members of Ohio’s Electric Cooperatives falls within areas designated under the IRA as “energy communities,” Mrkusic also noted. Those are areas that have had coal closures or disproportionately relied on coal, oil or natural gas. The designation qualifies clean energy projects for even larger tax credits.
“Rural co-ops should really take this money on the table to make power more affordable for lower-income communities,” Mrkusic said. “This is an equity issue.”
A July 2023 analysis prepared for the Sierra Club’s Beyond Coal program reached similar conclusions.
Heavy reliance on an aging coal fleet already means many rural cooperative customers pay more than those of investor-owned utilities, the analysis said. The report used 2020 data from the Energy Information Administration for an example in which residential customers of a co-op in southwestern Ohio paid roughly twice the per kilowatt-hour rate that AES Ohio’s residential customers paid in neighboring areas.
Overall, the Sierra Club report estimated Buckeye Power could save 4% on wholesale power costs by 2032 by switching all its current coal generation, including both the Cardinal and OVEC plants, to a mix of 2,370 MW of solar generation, 1,080 MW of wind power, 1,700 MW of battery storage and just 5 MW of combustion turbines.
Funding under the New ERA program, tax credits and other federal funding opportunities could offset up to 73% of the plan’s estimated costs of $5.66 billion, the analysis said.
A more scaled-back plan to replace just Cardinal Unit 2 would cost about $1.56 billion, the Sierra Club analysis said. Up to four-fifths of that amount could be recouped through federal funding and incentives, the report added. The plan would replace Unit 2 with 300 MW of wind energy, 650 MW of solar generation and 470 MW of battery storage.
Applying for the New ERA funds is a necessary step for getting money, but getting funding won’t be automatic. Buckeye Power should expect competition from other rural electric cooperatives seeking a piece of the New ERA funding pie, the Sierra Club’s Waggoner said.
“The folks at Buckeye need to be thinking proactively,” Waggoner said. “They need to be thinking about what they can do to best show the largest amount of emissions reductions, considering how heavy they are in terms of carbon with their coal exposure.”
Replacing the older coal generation would make a big dent in Ohio’s greenhouse gas emissions, which drive human-caused climate change. Ohio ranks fifth among U.S. states for carbon dioxide emissions, the Energy Information Administration reports.
The Cardinal plant’s three units emitted more than 11 million tons of carbon dioxide in 2022, an increase of more than 365,000 tons compared to the year before, according to data from the U.S. Environmental Protection Agency.
The U.S. EPA’s data set also shows OVEC’s Kyger Creek plant emitted roughly 6 million tons of carbon dioxide last year, and its Clifty Creek plant in Indiana released about 6.5 million tons of carbon dioxide. Collectively, the emissions of those plants are comparable to roughly 5 million passenger cars.
For now, Buckeye Power’s plans appear to call for shutting down roughly one-third of the Cardinal plant’s total generating capacity within the next five years.
American Electric Power sold its ownership interest in Unit 1 to Buckeye Power in August 2022. The website for Cardinal Operating Company, which runs the Cardinal Plant for Buckeye Power, said the purchase “paves the way for Buckeye Power to shut down Unit 3 by the end of 2028.”
New federal rules proposed in May call for additional big cuts in greenhouse gas emissions by 2038, primarily by adding carbon capture and storage.
The Edison Electric Institute and multiple utilities have objected to the rules, claiming carbon capture technology is not commercially proven and power shortages could result if plants must shut down within the rules’ proposed timeline. Buckeye Power likewise opposes the proposed rules.
“It is unknown at this time how much, if any, funding Buckeye Power would receive from the funding opportunities,” said Pat O’Loughlin, president and CEO for Ohio’s Electric Cooperatives and Buckeye Power. “We do know that replacing the energy from existing resources that the proposed rule would likely force to retire prematurely would have costs much greater than the maximum available from these programs.”
For now, work on a proposal under the New ERA program is underway, said Ben Wilson, director of power delivery engineering for Buckeye Power. Buckeye Power also submitted an application under the Bipartisan Infrastructure Law’s $10.5 billion GRIP program. GRIP stands for Grid Resilience and Innovation Partnerships and aims to boost electric grid flexibility and resilience in the face of climate change.
“Under both applications [for GRIP and New ERA], without sharing too much detail, we are aiming to position Buckeye Power to have a reliable, cost-effective power supply that we can confidently count on for many years to come,” Wilson said.
The following commentary was written by David Wooley, director of the Goldman School of Public Policy at the University of California-Berkeley. See our commentary guidelines for more information.
The Gulf Coast’s power grid and economy share a common need: diversity. Diverse electric generation supplies increase power system reliability and resilience in the face of rising demand and extreme weather. Diverse economic activity supports employment, expands the tax base and boost overall prosperity. Offshore wind could help achieve both goals for the Gulf Coast region — if state governments act.
Offshore wind is surging, with over 700 gigawatts in the global development pipeline. European nations plan to install at least 120 gigawatts of offshore wind by 2030 and 300 gigawatts by 2050. China added nearly 20 gigawatts of offshore wind in the last two years alone.
Those rising tides are also lifting American boats. On Aug. 29, the U.S. Bureau of Ocean Energy Management (BOEM) will hold an offshore wind energy lease sale for three areas on the Outer Continental Shelf in the Gulf of Mexico. In July, the nation’s first large-scale offshore wind plant began construction off the northeast coast. Twenty-nine U.S. ports are being refurbished to support offshore wind turbine construction and maintenance. Factories are going up across the U.S. to produce offshore wind energy components.
A new report — 2035 and Beyond: Abundant, Affordable Offshore Wind Can Accelerate Our Clean Electricity Future — shows our coastlines have the world’s highest-quality offshore wind resource. The new report details a pathway for offshore wind to provide up to 25% of total U.S. electricity generation by 2050, while producing large economic benefits and without increasing electricity costs. It could help meet rising electricity demand from electrification of transportation, industry, and buildings — which will triple U.S. electricity demand by 2050.
The U.S. is currently targeting 30 gigawatts of installed offshore wind generation by 2030. Our new research shows that offshore wind technology can be 10 to 15 times larger than that by 2050. Offshore wind along the Eastern seaboard, Gulf of Mexico, Great Lakes, and Pacific Coast can supply more than 1,000 gigawatts of generating capacity with operational characteristics comparable and complementary to existing power plant production (i.e., more than 50% capacity factor). This would create hundreds of thousands of new jobs nationwide and attract billions in investment to revitalize port and manufacturing communities.
The Gulf of Mexico is particularly well-suited for offshore wind deployment. The region could host more than 100 gigawatts of new offshore wind by 2050. With its existing manufacturing, port, and logistics infrastructure, and skilled workforce, the region could become a hub for new offshore wind generation. Many of the requisite offshore wind labor skills, ships, and port facilities can be adapted from existing Gulf offshore oil and gas industries. The Gulf of Mexico hosts most of the U.S. shipyards able to build wind turbine installation vessels. The region is already producing ships, turbine foundations, and steel components for offshore wind farms on the east coast.
New research by Cambridge Econometrics finds that offshore wind could employ 20,000 workers in the Gulf region by 2040 and 60,000 in 2050. Billions of grant and tax-credit dollars are available to repurpose existing infrastructure for jobs and clean energy production. The areas appropriate for offshore wind development in the Gulf are so vast that large amounts of offshore wind generation can be developed without interfering with fisheries, existing offshore infrastructure and sensitive marine ecosystems.
But offshore wind has far wider benefits than just jobs. Wind energy produced offshore can add large amounts of new electric power generation to bolster electric grid reliability — particularly important given Texas’ recent blackouts and near misses. Offshore wind in Gulf waters tends to kick up when solar production drops at sundown, and offshore wind turbines are less affected by extreme cold and heat events than land-based renewable and gas generation.
Several policy changes can achieve this potential. In the near term, the federal government must accelerate the identification and assessment of offshore wind sites, and leasing and permitting in federal waters. But state leadership is also needed to tap the Gulf Coast’s offshore wind potential.
Louisiana has shown its neighbors how to get started. Its 2022 Climate Action plan set a target of 5 gigawatts of installed offshore wind capacity by 2035, prioritized planning for transmission and workforce needs, established an interagency working group to address permitting, and enacted legislation to secure state tax revenues from offshore wind developed in state waters. Ports there have responded to the policy signals by making changes to accommodate offshore wind development and ships are being built in the state’s shipyards. Plans are in place to establish an offshore wind technology research, training, and technology demonstration center, but even all this isn’t enough to establish the state as an offshore wind hub.
A recent roundtable event organized by C2ES recommended, among other things, that the state take three steps. First, map out the unique roles each of Louisiana’s ports could play in the offshore wind industry. Second, open public utility commission dockets to consider how to interconnect and provide transmission support for new offshore wind projects. Third, undertake initiatives to prepare its workforce for offshore wind development.
Meanwhile, Texas stands in stark contrast, turning a blind eye to offshore wind energy, despite being desperately short of electricity during extreme winter and summer weather. The ultimate result may be that Louisiana’s ports and industries become the region’s offshore wind port and manufacturing hub for project development in waters off the Texas coast.
Texas’ policymakers could take a better approach by actively coordinating infrastructure and supply chain development with Louisiana, and pushing together for federal dollars to de-risk port and vessel construction through revenue guarantees for port and ship owners.
Punishing heat waves gripped the Gulf this summer, straining the electric grid to its limits. It’s a harbinger of things to come. Offshore wind can supply large new power supplies and help make electric power systems more reliable. The Gulf Coast states could be global leaders in this new industry, building a stronger economy and more resilient grid along the way.
The company seeking to build one of the nation’s largest carbon sequestration projects in Indiana was trying to avoid a “PR disaster” by locating in a rural farming area, a company executive said at a community meeting recently.
But that decision has not preempted controversy over both the project itself and the company’s larger strategy.
Local opposition is quickly snowballing in the small towns around Terre Haute as the EPA considers whether to approve injection well permits crucial for a federal loan guarantee.
Wabash Valley Resources says it wants to build a fertilizer plant that will bring jobs to rural Indiana. It aims to use petroleum coke or other feedstocks to create hydrogen and then anhydrous ammonia while sequestering carbon dioxide emissions 4,500 feet below ground in Vigo and Vermilion counties, about 12 miles from the plant.
Residents feel the company and the federal government are making them “guinea pigs,” as several said, in a project aimed at taking advantage of lucrative federal grants and tax incentives.
The company has been seeking to capture and sequester carbon since 2016, when it bought the former Duke Energy coal gasification plant that it plans to retrofit.
The EPA on July 7 issued a draft permit for the two Class VI carbon injection wells. Residents said they were given only days notice by mail about the lone EPA public meeting on the issue, which was held August 10.
Many local farmers had never heard about the concept, and were outraged that the company did little outreach and the government gave them little notice about their chance to weigh in. A 35-day public comment period on the draft permit — shorter than typical 60-day periods — was scheduled to close Aug. 11. The deadline was extended to Aug. 21 at advocates’ behest.
“We understand that once landowners learned it was going in their backyard, there was a short ramp to learn about carbon storage,” Wabash Valley spokesperson Greg Zoeller said. “Admittedly, we could have done better initial outreach to the landowners. We hoped the EPA information session would ease most of their concerns.”
Since that was clearly not the case, the company held its own meeting Aug. 16 in the small town of Universal, where residents pelted the officials with questions and accusations.
Wabash Valley Vice President of Operations Rory Chambers was asked why the carbon couldn’t be sequestered at the gasification plant site.
He responded that injecting carbon there — under a river and closer to Terre Haute — would be a “PR disaster.”
“Admittedly a little self-servedly I said, ‘Well if I put it in my plant site, this plume will clip the north side of Terre Haute and I end up with 3,000 angry people,” Chambers said.
By sequestering the carbon around Universal, “If there are a few mad people, here I can talk to individuals…and calm them down,” Chambers said. “My god, if there’s 3,000, I’ll never be able to convince them.”
As outrage erupted in the room, Chambers continued:
“It’s not because you’re rubes, I don’t think you’re rubes,” he said, adding that he himself does not have a college education.
Wabash Valley founder Nalin Gupta, meanwhile, explained to the crowd that he previously worked in finance in New York, on a team deploying over $85 billion in energy finance.
“If someone said, ‘Here, take two billion dollars and do something that would destroy people’s properties and water,’ would I do it?” Gupta asked the crowd in an ill-fated attempt to reassure them about the company’s motivations.
“Yes!” someone yelled out. “Nobody in this room wants it!”
Susan Strole-Kos told Chambers at the meeting that she has spent many hours looking at data and studies about carbon sequestration, and fears the underground carbon plume could harm the farm that’s been in her family for 200 years.
“I have been given the job to be the steward of my land, and you are trying to take that from me,” she said tearfully. “It may be legal because you have worked politicians, you have the law in your favor, but it is immoral, and I don’t know how you guys can live with that.”
Strole-Kos said her family was approached by the company last year and invited to what they described as a meeting of local farmers about a fertilizer plant.
She thought it could be a good idea. But when she arrived, she found no other residents, just Chambers and two other company representatives who pressured her to “sign a piece of paper” in exchange for a few hundred dollars, as she told Energy News Network.
“I said, ‘No we are not fools here,’ it did not end well,” she said. “Maybe they thought we were just simpletons out in this area.”
Hundreds of residents turned out for a second meeting with company officials on Aug. 22, at an elementary school near the injection well site. Strole-Kos’s daughter Whitney Boyce, a high school teacher, worries about danger to students.
“We have our natural disaster drills, tornado drills, earthquake drills, we recently added active shooter training; now how do we prepare for a carbon dioxide leak?” she said. “We have to notify students and parents when people come in to spray for bugs. So I find it mindboggling we don’t have to notify parents when something like this is coming in.”
The federal Inflation Reduction Act expanded the 45Q tax credit to $85 per ton of sequestered carbon dioxide. Provisions of the Bipartisan Infrastructure Law could also aid Wabash Valley’s plans.
The U.S. Department of Energy meanwhile is funding the development of hydrogen as a clean fuel, and there are various tax credits available for hydrogen production that the company could potentially tap. Wabash Valley Resources currently has a $33 million federal grant for hydrogen technology demonstration.
During the Aug. 16 meeting, Gupta touted the federal government’s support.
“The Trump administration reached out to me and said restart this plant, we don’t want ammonia from Ukraine and China,” Gupta said. “$20 million was given to us in 2019 by the Trump administration, it was followed by [support from] the Biden administration.”
Zoeller told Energy News Network that “this is not a local project, this is really the first of what I see as a change away from smokestack industry.”
But as multiple carbon dioxide pipelines and sequestration sites have been proposed in the Midwest, residents have raised fears of safety, environmental and economic consequences should carbon escape, as it did in a 2020 disaster in Sartartia, Mississippi. In Illinois, for example, residents and local governments are stridently opposed to the company Navigator’s plans for a carbon dioxide pipeline and sequestration of emissions from ethanol plants.
Near Terre Haute, residents are especially concerned since the area is a seismically active zone, and there is an abandoned coal mine underground.
During the contentious Aug. 16 meeting, Gupta repeatedly noted that there are 145,000 active and defunct carbon injection sites nationwide — mostly in Texas and California. Such sites have long been used for enhanced oil recovery, where carbon is injected into the ground to force hard-to-extract oil out of diminishing reservoirs.
Though common, critics consider enhanced oil recovery to be under-regulated and under-studied, posing a potential risk to drinking water. And they fear large-scale, permanent sequestration of carbon dioxide raises different and little-understood issues.
Doug Martin is town board president of Universal and lives less than two miles from the proposed injection site. He says the company never reached out to the town nor the local fire department.
“How can you say you have an emergency plan when Universal has never been contacted?” said Martin, an author and former creative writing professor at Indiana State University.
“I don’t want to walk out and see people passed out in their yards with permanent brain damage. It’s right by our park too, where kids play. My guess is when they start shooting that much into the ground, it’s going to go under all the houses.”
Under state law, Wabash Valley does not need permission from landowners to sequester carbon below their land. A state law passed last year mandates that permission is needed from 70% of landowners, but that law specifically exempts the “pilot project” developed by Wabash Valley.
In April, the legislature passed a law setting the price the company will pay surface landowners if carbon migrates below their land. Indiana state legislators have sought to pass a law insulating Wabash Valley Resources from liability, unless landowners can prove actual harm from carbon dioxide migration.
Meanwhile a 2019 state law declared carbon sequestration in the public good and allowed the use of eminent domain for siting the pipeline from the plant. During the community meeting, Wabash Valley officials said they would use eminent domain as a last resort, if they cannot obtain permission from landowners on the pipeline route.
Wabash Valley has said the plant will open in 2026, but Kerwin Olson, the executive director of environmental group Citizens Action Coalition, predicted the process will take much longer, as the company still needs “a jigsaw puzzle” of various federal and state permits to construct the pipeline and open the plant.
He said that in the meantime, the public is bearing unfair financial risks, in the form of federal grants and subsidized loans, not to mention tax credits and potential damage down the road.
“To me what this is really all about at the moment is them getting their money, where the public is assuming all the risks on the financial side of things,” Olson said.
“It’s potentially a Solyndra 2.0,” he continued, referring to the solar company that failed after receiving high-profile federal subsidies under the Obama administration.
In comments filed with the EPA, the Citizens Action Coalition argued that producing and transporting the petcoke, coal, corn stover or biomass feedstock for Wabash Valley’s plant would create more carbon emissions than they plan to sequester.
The coalition proposed in its EPA comments that a fertilizer plant could more efficiently and cleanly operate using the electrolysis method powered by renewable energy, rather than “the Rube Goldberg-machine approach replete with multiple sources of various toxic air emissions, acid gas generation, slag, carbon emissions, and risks to private property and public health.”
Citizens Action Coalition organizer Bryce Gustafson said it appears the increasing number of concerned local residents are “in it for the long haul.”
“They haven’t lost hope,” he said. “A lot of people were under the impression EPA was going to rubber stamp this, but now they’re understanding there are ways they can keep the fight going. When people come together and stand up for their rights, for their communities, it makes me proud to be a Hoosier.”
Reprinted from E&E News with permission from POLITICO, LLC. Copyright 2023. E&E News provides essential news for energy and environment professionals.
For years, Delaware has been on the sidelines as the emerging offshore wind industry flocked to neighboring states, but a new law could transform the industry in the state — if it’s not too late.
Delaware’s Democratic-led Legislature recently ordered a study of the state’s offshore wind potential to be reported back by the end of the year. The move, which was signed by Gov. John Carney (D) this month, adds momentum for the state to set its first target for offshore wind, a goal of many lawmakers and environmental groups.
“We’re alone among our neighbors of not really having wind targets,” said state Sen. Stephanie Hansen (D), who has spearheaded the state’s reassessments of offshore wind to meet its climate targets as chair of the state Senate Environment and Energy Committee. “Delaware, as of now, I think, is really firing on all cylinders to move into the next phase of energy planning and implementation.”
If the study leads to a state offshore wind goal, it would bring Delaware in line with neighboring states and give it an opportunity to compete for industry jobs and businesses emerging along the East Coast. Power grid operator PJM Interconnection LLC is assisting with the study in looking at transmission impacts. But concerns about the cost of offshore wind still linger from a 2018 analysis that effectively tabled wind ambitions in the state for years.
Meanwhile, a movement against offshore wind along coastal communities has begun to capture the sentiment of Delaware towns and some lawmakers.
“I think it is harmful,” said state Sen. Bryant Richardson (R), the only senator to vote against Hansen’s study. He opposes the offshore wind industry due to its potential costs and what he says are negative impacts to the ocean environment and views from the shore.
“It’s an eyesore,” he said of the industry.
Delaware is juggling its offshore wind future as the industry reaches a turning point in the U.S.
Thousands of turbines are expected to go up in the northeast Atlantic in the coming years, spurred by state commitments and subsidies from Maine to Virginia. That comes alongside millions of dollars of promised state and private investments to beef up aging ports, build manufacturing and steel fabrication facilities, and make job programs to create a workforce capable of building and maintaining the new industry.
The wave of new proposals is partly thanks to the Biden administration’s commitment to raise enough wind farms in the ocean to power 10 million homes by 2030. The White House on Tuesday approved the nation’s fourth commercial-scale offshore wind farm off the coast of Rhode Island and has said it remains “on track” to reach 16 offshore wind environmental reviews by 2025.
The administration also announced last month potential new lease areas in the central Atlantic, including a swath of ocean about 30 miles off the coast of Delaware Bay. If developed, that area would add to two planned offshore wind farms that sit off the Delaware coast in federal waters.
Delaware’s grid may not reap the power of those two offshore wind projects, which are helping Maryland meet its offshore wind target. But experts say the new offshore wind areas could offer electricity to help Delaware reach its renewable portfolio standard of 40 percent renewable power by 2035.
Chelsea Jean-Michel, a wind analyst at BloombergNEF, said local opposition and limited space has made it difficult for the state to grow its renewable sector onshore, making offshore more attractive.
“Offshore wind projects can help decarbonize Delaware’s energy system by providing bulk renewable energy capacity in one go,” she said in an email.
For years, Delaware has flirted with the idea of offshore wind to help it decarbonize. It was poised to be the first U.S. state with an offshore wind farm when the proposed Bluewater Wind offshore wind project secured a long-term contract more than a decade ago with the state’s utility. The proposal later fell apart, largely because of cost concerns and investment uncertainty amid the recession.
Offshore wind got a second look largely thanks to Carney, who in 2017 ordered a study of the industry’s potential role in reaching state clean energy goals.
That analysis found that the cost of offshore wind energy would be high, prompting many lawmakers to shy away from supporting turbines off the coast.
One reason why offshore wind is getting another look in the state now is that costs have fallen significantly as projects have advanced in the U.S.
An updated report from Delaware’s Special Initiative on Offshore Wind (SIOW) last year found the cost of a Delaware offshore wind project — if it was large enough to capture economies of scale — would cost the same as existing sources of electricity in the state like natural gas and solar. That would be the case without state subsidies or tax breaks, researchers said. The study considered federal incentives that were expanded in the Inflation Reduction Act giving developers a 30 percent tax credit for offshore wind.
“There’s enough time, plenty enough time, for Delaware to do one project, maybe two, and still get advantage of that tax credit,” said Willett Kempton, a professor at the University of Delaware’s School of Marine Science and Policy and a leader of SIOW.
Kempton’s report also weighed how fossil fuels negatively impact human health and the environment, driving up the overall cost of using those sources for power. When those factors were considered, offshore wind became cheaper than existing sources like natural gas in the study’s models.
Hansen said Delaware hired analysts to interpret the report. When executive action did not occur, she said she wrote the legislation that passed earlier this year tasking the governor’s office and state regulators to review and report back to the Legislature on offshore wind’s potential.
“We need to hear from the administration on this, is this a direction that we ought to go?” she said. “I can tell you that there is the legislative will to move this forward. But we also aren’t experts.”
Carney’s office declined to comment for this story.
Hansen said that Delaware’s tardiness on offshore wind could lead it to lose out on benefits from the industry, such as jobs and manufacturing.
Jean-Michel, with BloombergNEF, noted wind developers have forged relationships with nearby state lawmakers that give those states an advantage.
“Given that it’s entering the market later and it is likely to be a smaller market, Delaware may not benefit as much economically through offshore wind in terms of green growth or jobs, or it may have to pay a significant premium for offshore wind projects if it wants to stimulate that local manufacturing sector,” she said.
However, Kempton, with the University of Delaware, said he would warn lawmakers, if they proceed with a procurement target in Delaware, against tying offshore wind projects to local investment.
Other states have encouraged offshore wind developers to bundle economic development plans into their wind proposals, leading to manufacturing projects planned in states like New York and Maryland.
But those investments mean the price of electricity for those projects is higher, Kempton said, noting that wind developers may not be the most effective planners for associated supply-chain businesses. They also may not have long-term commitments for jobs in mind onshore.
Offshore wind supporters are hoping when the Delaware Legislature meets again in January, lawmakers will have offshore wind on their minds.
Hansen said she couldn’t disclose some of the conversations happening now on offshore wind but that Delaware leaders could make progress even before the session convenes.
But as the state weighs a greater role for offshore wind, industry opponents may also be growing.
It’s a pattern that has played out in other coastal states as offshore wind proposals draw pushback from beachfront homeowners who don’t want steel marring their ocean views and town councils concerned the industry could hurt tourism. Conservative groups such as the Delaware-based Caesar Rodney Institute also are supporting the opposition movement.
Richardson, the Delaware Republican, said he’s been reading material put out by the institute on offshore wind and connecting with opponents who share his skepticism about the industry, its costs and its impacts.
“I hope it will fail,” he said of the state’s plan on offshore wind.
Critics say a pair of proposals to make Appalachian Ohio part of regional hydrogen hubs is likely to benefit the state’s oil and gas industry more than the climate.
The two proposals are among 21 projects competing for shares of a $7 billion pot of grant money under the 2021 Bipartisan Infrastructure Law. The law defines hydrogen hubs as networks of clean hydrogen producers, their potential consumers and infrastructure connecting them. At least one of the winning projects is to be a “blue” hydrogen hub, meaning it would make hydrogen from fossil fuels with carbon capture, storage and possible reuse, or CCUS.
The Appalachian Regional Clean Hydrogen Hub plans to collect methane from a web of natural gas pipelines in Ohio, West Virginia, Pennsylvania and Kentucky for a hydrogen production facility in West Virginia. The ARCH2 coalition includes Battelle, natural gas industry companies, the state of West Virginia, and more.
The Decarbonization Network of Appalachia, or DNA H2Hub, has the economic development group Team Pennsylvania as its project lead and is also proposing a blue hydrogen hub for Pennsylvania, West Virginia and Ohio. Equinor and Shell are among the group’s corporate partners.
Because both hubs would use methane from the region as feedstocks, they represent potentially large customers for the natural gas industry.
“We believe there are opportunities for the industry in a regional hub or hydrogen ecosystem and that Appalachia is more suited than most areas because of our compactness, access to natural gas and manufacturing infrastructure,” said Rob Brundrett, president of the Ohio Oil & Gas Association. “There certainly would be a benefit, especially the role natural gas plays in the creation of blue hydrogen, but we think it is too early to tell exactly what and how much benefit it may be to the industry.”
Much will depend on how hydrogen from the hubs will be used, whether it will displace other current uses of methane, and overall costs and market prices for natural gas. Rough estimates from the Ohio Oil & Gas Association are that recent production has gone in equal shares to power generation, heat and chemicals.
On the high end, blue hydrogen hubs might increase natural gas consumption and industry revenues. On the low end, sales to hydrogen hubs could offset potential losses if other uses decrease as a result of the energy transition.
Hydrogen production with natural gas and capture of carbon emissions from burning natural gas have gone on for decades, said policy advisor Rachel Fox at the American Petroleum Institute. Current U.S. hydrogen production is approximately 10 million metric tons per year, she said.
“The new challenge and opportunity is to scale these two complementary technologies together,” Fox continued. “API and our members are excited about the H2Hubs program and the impact it could have on the growth of a low-carbon hydrogen economy.” She said the industry has shown 65% to 90% carbon capture rates are commercially achievable.
As a decarbonization strategy, a blue hydrogen hub would be “a really energy-intensive, really water-intensive thing that commits that sector to being fossil-based forever, essentially,” said Emily Grubert, an energy policy expert at the University of Notre Dame.
It’s unclear whether blue hydrogen “would even result in a net reduction of carbon emissions,” said Ben Hunkler, communications manager for the Ohio River Valley Institute. In a 2022 analysis, he said a blue hydrogen hub would be “a risky gamble,” whose costs likely outweigh environmental benefits when compared with other options, such as renewable energy.
Although industry and government “now talk about carbon capture as having been proven, it really hasn’t,” said David Schlissel, director of resource planning and analysis for the Institute for Energy Economics and Financial Analysis. There hasn’t been any long-term, large-scale demonstration of its effectiveness over the time frame when promoters expect blue hydrogen hubs to operate.
Methane leakage from pipes and other infrastructure would add to emissions, Schlissel said. Methane is a more potent greenhouse gas than carbon dioxide, and numerous studies have found methane emissions are vastly underreported.
Hydrogen can also leak, especially because its molecules are so small. “We think it leaks everywhere, but there’s no commercially available technology that can measure hydrogen leakage,” Schlissel said. Leaked hydrogen could prolong methane’s impacts in the atmosphere, researchers reported in Nature Communications last December.
Notably, both the Ohio Oil & Gas Association and the American Petroleum Institute have commented against the U.S. Environmental Protection Agency’s proposed rules that would effectively require carbon capture and storage for fossil fuel-fired power plants.
The ability to outfit power plants with carbon capture equipment isn’t advanced enough to be feasible yet, Brundrett said. “Therefore, at this time we would not encourage any mandates regarding a technology that isn’t available to the scale required by the rules.”
It’s unclear how the CCUS technology for a power plant would differ from that for a hydrogen production facility. Brundrett said the technology “has a promising future, and we will remain engaged in the hydrogen hub process with the hope that Appalachia is able to utilize our natural advantages if awarded by the federal government.”
For now, chances seem good that at least one of the projects will get funding. The Bipartisan Infrastructure Act requires at least two regional clean hydrogen hubs to be in places with “the greatest natural gas resources.” Separate provisions let the Appalachian Regional Commission provide grants and technical assistance for a regional hydrogen hub.
The federal funding is meant to act like a “moon shot,” to quickly ramp up clean hydrogen production.
“The reality is that we believe that there’s a near-term climate need that we need to be addressing, [and] that we need to think about how quick can we bring one of these technologies or a lot of these technologies to the marketplace,” said Thomas Murphy, senior managing director for strategic energy initiatives at Team Pennsylvania, during a webinar presented this summer by Appalachian Energy Future, an industry-led alliance promoting hydrogen hubs.
The DOE initiative aims to “[drive] down the cost of getting new technologies into the market,” said Grant Goodrich, who heads the Great Lakes Energy Institute at Case Western Reserve University. “You’re increasing market readiness and market demand.”
And while scaled commercial carbon capture and storage technologies don’t yet exist and can’t operate without government support, the Department of Energy’s hydrogen hub initiative could jumpstart a hydrogen economy for hard-to-electrify uses, such as high-heat industrial processes, heavy-duty transportation, or aviation, Goodrich said. That in turn might lead to effective carbon capture for other hard-to-decarbonize industries that produce greenhouse gases, such as the cement industry.
The DOE guidelines also call for projects to track how clean their processes turn out to be, Goodrich said. That should provide some accountability.
DOE’s decisions on the grant applications could come before the end of the year. DOE will also spend $1 billion to develop demand for hydrogen from the hubs, the agency announced in July.
One by one, tiny solar companies abandoned their rooftop ambitions in Prince William, defeated by tangles of red tape in the booming Northern Virginia county.
Undeterred, Ray Masavage, owner of CAVU Solar since 2018, hung in there. Why?
It pained him to see seas of array-less houses in sprawling subdivisions as the planet cooked. And he had faith that officials in the county he calls home yearned to shed the label of worst solar permitting jurisdiction in the state.
Now, he’s hopeful that a Board of Supervisors vote to waive fees associated with new residential solar installations beginning Sept. 1 represents a crack in county bureaucracy. It’s just one piece of a long checklist of potential improvements to streamline solar permitting.
“In terms of diplomacy, this is a big deal,” Masavage said. “I give county officials credit for looking at the problems and doing something about them.”
He also praised Solar United Neighbors, an advocacy organization with roots in Virginia, and the Chesapeake Solar & Storage Association, a Mid-Atlantic trade group, for pressuring the county to simplify long-lingering, tedious permitting requirements and boost transparency.
“We’re contractors working 24/7,” Masavage said. “We can’t stop when we’re on a roof somewhere and go back to address a resubmission in Prince William County.”
The county’s balky application website, higher-than-average permitting fees, and nitpicky reviews requiring multiple plan submissions had paralyzed many solar companies and bedeviled homeowners puzzled by the lack of forward movement on planned arrays.
Last December, mounting discontent prompted Solar United Neighbors to invite frazzled homeowners in Prince William to participate in an Action Alert. SUN wanted residents to know that the county — not installers — was to blame for delays and setbacks.
That alert encouraged residents to send complaint letters to both their local county board supervisors and the editors of local newspapers.
Prince William authorities took note.
In February, the county named Mandi Spina as acting director of the Department of Development Services. She replaced — at least temporarily — Wade Hugh, a county employee for 27 years.
In her new role, longtime county employee Spina said she had multiple phone calls with Aaron Sutch of Solar United Neighbors and wanted “to thank him for his continued advocacy of the solar community as well.”
Spina also lauded what’s called the Residential Solar Working Group, which Hugh had rolled out last November. Its 14 members included county staffers and industry representatives intent on repairing the fumbles of the past.
She noted that the impasse began to break when more than 55 stakeholders met on July 12 to hash out their differences.
“This is important as we are committed to partner with industry,” she said.
Sutch, director of SUN’s Atlantic Southeast Region, said he’s encouraged that the campaign has yielded results.
“This feels good and we applaud the county’s decision,” he said. “It’s the first measurable step. But it still has to be followed up with other major improvements.
“Solar is not going away. People in the county want it.”
In late July, supervisors allocated $1.2 million from the county’s year-end savings to a one-time fee reduction on new solar installations through June 2024.
Earlier this month, Spina was named deputy director of the Department of Development Services. That followed an earlier personnel shift, when Hugh was promoted and appointed deputy county executive for community development in late June. He now oversees numerous county agencies, including development services, which he used to lead.
The development agency will initiate a budget request for the next fiscal year to extend the waiver beyond the June 2024 deadline, possibly making it permanent, Spina said.
“I understand we are an outlier compared to our neighboring jurisdictions,” she said about the urgency of reducing permit costs and speeding up timelines.
Indeed, by digging into a federal Solar Trace database, Solar United Neighbors researchers confirmed that Prince William’s median solar permitting fee of $586 was more than double that of four surrounding counties, where fees ranged from zero to $200.
As well, between 2018 and 2021, solar permitting took longer in Prince William than it did in Arlington, Fairfax, Stafford and Loudoun counties.
While waiving the permit fee attracted across-the-board kudos, solar contractors and advocates are encouraged by a handful of other actions to be initiated by the county because of the due diligence of the working group.
For instance, Prince William is issuing a standard list of pre-approved solar components, which will save the industry from having to submit safety compliance listings with each application.
In addition, the county and industry representatives are jointly designing what’s called a residential solar county typical plan. This will eliminate the need for engineers to sign and seal documents because all pertinent information is already included. Instead of dragging on, review time is limited to five business days.
The county is also on track to adopt a pilot program for Solar APP+, a tool developed by the National Renewable Energy Laboratory to standardize the rooftop permitting process.
Solar APP+ is deployed widely in California and Arizona. In Virginia, Prince William would join Richmond, Culpeper County and Harrisonburg, three other jurisdictions testing it on trial runs.
Warming to the online application would be fantastic for smaller operators, advocates say. The conversion would allow all players to be on the same page because the software integrates with existing government regulations, automates plan reviews and provides final signoff of inspections.
“I am confident that” these upgrades “will provide a wide range of options to alleviate frustration surrounding the time and cost to permit in Prince William County,” Spina said.
Sutch said the county of 484,000 residents could be a solar haven if updated policies fulfill the promise of matching contractors and homeowners.
“We feel we’re 40% to 50% of the way there,” he said about busting up the logjam. “This is proof that if you are persistent enough and know the levers of power, you can make a difference. Now, we want to hear positive stuff.”
“We’ve seen tremendous growth with solar projects,” Spina said. “And we know that growth is going to continue.”
Successful applications for installations, which stood at just 14 in 2016 and 19 in 2017, leaped to triple digits — 149 — by 2018. Except for a setback caused by the pandemic, they have ramped up at a steady clip.
By 2022, applications for solar projects had exploded to 1,087 — roughly quadrupling the 2021 total of 274. Each one required both an electrical and a structural permit.
Hugh stood by the rooftop solar data he compiled, although advocates questioned the validity of his records. They constantly questioned why it took so long to greenlight projects — which often didn’t happen until a developer made a second try. Each repeat submission added roughly $100 to the permit cost.
Ideally, developers desire approval within a month for the sake of efficiency and to keep installation costs close to the estimate provided to homeowners. They had to walk away when waits were interminable, thus rendering projects cost-prohibitive.
Masavage is a licensed pilot whose company, CAVU, is shorthand for the aviation term “clear and visibility unlimited.” Prince William’s efforts to expedite permitting are encouraging him to double down.
“To have all of these homes that are perfect candidates for solar is an amazing dream,” he said. “We’re facing a world crisis and, as installers, we have the ability to do something about it.”
Spina is optimistic that the changes will lure solar contractors to the county — and allow the local government to meet its strategic goals of sustainable energy consumption.
Still, some installers remain content to keep their distance.
Nolie Diakoulas, who heads up 10-year-old Virginia Beach-based Convert Solar, expanded his small business’ reach statewide three-plus years ago as interest in renewable energy swelled.
However, he began second-guessing his forays into Prince William when the hurdles proved constant and insurmountable.
Diakoulas backpedaled when basic fees connected to permitting escalated beyond $1,000, too big for an installation to be profitable. He figured the county was a better fit for Ion, Tesla and other solar giants with access to a cadre of internal system designers, engineers and other specialists.
The recent county turnaround isn’t even on his radar.
“We have stopped installing in Prince William County,” he said, “so I have not been keeping up with the news.”
Correction: Buildings account for about 40% of Minnesota’s total energy consumption. An earlier version of this story misattributed the figure to heating only.
Michael Overend and Lucy Grina love to show visitors around their home, a modest four-bedroom rambler, built in 1965 on a gravel road just north of Duluth, Minnesota.
The couple’s pride, however, did not always extend to one feature: the utility bills.
“We were embarrassed about how much heat this old house was leaking,” Overend said, “and we were cold a lot.”
Today, the couple is among a small but growing number of northern Minnesota homeowners finding comfort and savings by pairing energy-saving weatherization with an all-electric heating and cooling system known as a heat pump.
Heat pumps are highly efficient, two-in-one appliances that can both heat and cool a home, even in a notoriously cold climate such as northern Minnesota. The technology will likely be a key component of the state’s climate strategy, as buildings are a significant contributor to the state’s greenhouse gas emissions.
While still a niche, utilities, contractors, and advocates expect the technology to take off as more incentives become available and more people become familiar with what it can do.
For Overend and Grina, it started with consulting an expert on building super-efficient homes. They had raised two children in their home, but as they retired they had to decide whether to keep the house and improve its livability or buy elsewhere.
The first step was to get an energy audit, and then contractors plugged holes and added insulation and efficient windows. Eventually, the home was so tight they had to install an air exchanger to keep the air fresh and healthy. That’s standard practice in energy-efficient home construction these days.
Next came the heat pump. The systems have been around for decades, but their performance and efficiency improved by leaps and bounds in recent years. Those improvements, along with growing awareness about climate change and the hazards of burning fossil fuels indoors, have helped raise the appliance’s profile in recent years.
Heat pumps are more efficient than furnaces because they don’t make heat; they move it from one place to another, the same as refrigerators do. The outdoor unit looks essentially like a standard air conditioner. It has a coil filled with refrigerant and a fan that blows air across the coil. The indoor unit also has a coil and a fan. As the refrigerant moves through the system, a compressor pressurizes it and then allows it to expand, causing it to shift between a gas and a liquid. This enables it to absorb heat outdoors and release it inside.
In the summer, the system can be reversed, removing heat from inside more efficiently than a standard air conditioner can.
The most advanced heat pumps can extract heat from the air even on very cold days. This is because of newer, variable-speed, inverter-driven compressors. They are more efficient because they run continuously at varying speeds to match the heating or cooling load in the house, rather than stopping and starting as most furnaces do.
Overend said his system keeps the house toasty down to 20 degrees below zero Fahrenheit. There are backup electric radiators, and the system can switch automatically to the backups, but Overend said they hardly ever come on.
Overend said the new system — including removing the old furnace, installing the two heat pumps and some new ductwork, and adding the air exchanger and a new water heater — cost the couple about $25,000, and it has lowered the home’s energy use by 40%.
Savings depend on the type of system the heat pump is replacing. Homeowners who rely on propane can save as much as 30% on home heating costs; those using electric resistance (baseboard) heat can save as much as 50%, according to the Air Source Heat Pump Collaborative, a project of the Minneapolis-based nonprofit Center for Energy and Environment and major utilities in the state.
The collaborative’s manager, Rabi Vandergon, said rebate applications for heat pumps spiked in 2020 during the COVID-19 pandemic, as more people focused on home improvement. Supply chain problems slowed sales some, but numbers are up again this year, he said.
“We expect to see another jump,” Vandergon said. “People want to help with climate change, especially if it doesn’t hurt their pockets.”
Vandergon said the new systems are most valuable for rural residents currently served by propane or electric baseboard heating. The financial case is less clear to natural gas customers, but he’s excited about the rebate and tax credit programs soon to be available through the federal Inflation Reduction Act and Minnesota’s landmark 2023 energy legislation.
Homeowners can save more when they combine heat pumps with dual-fuel programs offered by some utilities. Minnesota Power, for example, offers customers a lower rate in exchange for the ability to stop the heat pump during times of high energy demand, forcing the home to switch to backup heat from another source.
Limited research and the increasing confidence of experienced installers are persuading homeowners that heat pumps really can work in cold climates.
HVAC contractor Chad Thompson has been installing heat pumps since he started Twin Ports Custom Climate just across the border in Superior, Wisconsin, 20 years ago. He’s witnessed monumental improvements in technologies and equally encouraging changes in consumer attitudes.
“The capabilities of the new units have gotten probably 10 times better over the last 10 to 15 years,” Thompson said.
Sales growth has occurred mainly by word of mouth. Things took off during the pandemic, Thompson said, while the region’s increasingly hot and humid summers have probably prompted interest, too. Others are motivated by climate change and the desire to stop burning fossil fuels.
The number of applications for utility company rebates for heat pumps in Minnesota more than doubled over four years, from just over 2,000 in 2019 to 4,600 in 2022, according to the Air Source Heat Pump Collaborative. And sales of heat pumps in the U.S. surpassed sales of natural gas furnaces in 2021, according to the International Energy Agency.
In the northeastern part of the state, Minnesota Power is bullish on heat pumps, offering rebates for the last several years. The company holds annual training events for contractors to learn from experts and manufacturers, and it requires customers to use preferred contractors to get a rebate.
“We want to encourage customers installing electric heat to do something that’s high efficiency, something that’s beneficial to the grid,” said Minnesota Power’s Jon Sullivan, lead worker in customer programs and services. “This technology really helps us along the path to 100% carbon-free energy. It’s also beneficial for other customers who want to cut back fuel combustion as much as possible.”
In 2017, Minnesota’s buildings consumed 40.6% of the total energy used in the state, according to the Minnesota Department of Commerce. Most of that comes from homes, where heating and cooling use more than half of the energy consumed. In spite of efforts to boost efficiency, energy use in buildings is increasing in Minnesota.
Advocates say switching to electric cars and appliances is among the most impactful things a homeowner can do to combat climate change. That’s because electricity is increasingly generated from clean sources. In Minnesota, all electricity sold will be required to come from clean energy by 2040.
As for Overend and Grina, they’re thinking about possible next steps, including an electric vehicle and possibly battery storage to tap during power outages.
“Ten years ago, I had no hope,” Overend said. “I thought climate change was too big for anyone — or for all of us — to solve. I’ve learned that there truly is hope. What we do as individuals makes a very, very tiny contribution to the overall picture. But we can be an important example to our friends, our family, our community.”
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