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This story was originally published by Grist.
This coverage is made possible through a partnership with Grist and Interlochen Public Radio in Northern Michigan.
Michigan isn’t known for sunny weather. Yet in recent years, it’s seen a strong push for solar energy — including in Traverse City, the largest community in northern Michigan. Along the M-72 highway, rows of huge solar panels gleam in the sun, covering about 30 acres of grassy field.
In the shade underneath the panels are sheep.
This is called “solar grazing,” where livestock are placed on solar installations to keep vegetation in check. Sheep have grazed at the site for the past three summers, eating grass and depositing droppings along the rows of panels.
Bart Hautala, operations manager for Heritage Sustainable Energy, said hosting some 30 sheep is a win-win: Sheep eat the grass, and that prevents foliage from shading the panels.
“It’s a multiuse land now,” he said. “It’s environmentally friendly. We’re helping out a farmer. He’s got more space to put more sheep.”
But across the state and the country, similar collaborations between farmers and companies have faced roadblocks.
Solar power is central to the nation’s transition to renewable energy, including in Michigan, which is aiming for carbon neutrality by 2050. Reaching that goal will require a lot of land, and some solar companies, researchers, and farmers are trying to use land for both agriculture and renewable energy — a practice called agrivoltaics. But local opposition has hampered those efforts, and solar advocates say Michigan is a prime example of how townships can slow renewable energy development.
This debate is playing out around the country, as people grapple with what a transition to clean energy actually means. A May 2023 report by the Sabin Center for Climate Change Law at Columbia University found that across 35 states, there are 228 local restrictions strong enough to stop projects. That opposition has grown steadily, up 35% from the year before. And local restraints severely restrict renewable development, according to a 2022 report from the National Renewable Energy Laboratory.
Michigan exemplifies the tension between solar and local concerns. Since townships decide where renewable energy projects are located, residents have a lot of say and many have placed moratoriums on solar and wind. The Sabin Center found that as of last May, 26 local Michigan governments had delayed or blocked utility-scale developments, the most of any state in the study. It didn’t compare restrictions to the number of existing projects, but 118 wind and solar projects are already operating or under development, according to the state. As more are proposed, much of the focus is on the relationship between solar and farmland.
“Michigan has the most restrictive measures when it comes to siting solar on agricultural land,” said Matthew Eisenson, who authored the May report. “There’s a lot of apples to oranges, but I think Michigan just has the most activity on this issue of anywhere.”
Debates over renewable energy have roiled communities in the state. A group called Michigan Citizens for the Protection of Farmland petitioned to block utility-scale solar on agricultural land last spring, though they withdrew it. In some places, residents have recalled officials who approved projects they didn’t agree with.
Milan Township, in southeast Michigan, held a recall election last spring after residents voiced concerns about an ordinance that would have allowed large solar projects on agricultural land. Stephanie Kozar was elected township clerk during that recall. She’s spent her whole life in Milan, and said it was a rough time for the community.
“There have been rifts between friends, between relatives, between acquaintances, because it is such a hot topic, and there are so many strong opinions and emotions about it,” she said.
The township’s original ordinance allowing solar on agricultural land had passed during the height of the pandemic, which Kozar said raised issues of transparency. Since then, she said, more people have started attending meetings and gotten involved in local politics.
“We’re just trying to make the township a place where people want to come, want to live, and keep it in the agricultural spirit,” she said. “It’s about what the majority of our township wants. And that’s our biggest goal, is making sure that their voices are heard.”
Local opposition to renewable projects can often be nuanced, rooted in a wide array of reasons. Those include concerns about a project’s impact on the environment and economy, and extend to governmental failures to consult Indigenous tribes, according to a 2021 study by Science Direct. Some rural communities worry that losing farmland to solar could fundamentally change their culture.
“I think this is a hot-button in most townships, one way or the other,” said Bob Schafer, the supervisor of central Michigan’s Keene Township, who took on the job after his predecessor was narrowly voted out during another recall election held last spring.
Schafer stressed that people there have a variety of opinions on renewable energy — many people support it, and some oppose “mega projects” but not smaller installations.
“All the landowners have some say,” he said, “both those that are trying to obtain a project and those that may be surrounded by a project. We’re trying to find a balance.”
But that balance is hard to strike, and some Michigan lawmakers are trying to streamline the path to renewables. With a slim Democratic majority, Michigan’s legislature is tackling a heap of ambitious climate legislation this fall.
Abraham Aiyash, a Democrat from Hamtramck, is the house majority floor leader and one of the sponsors of a climate package. He and other lawmakers want the state to have the power to approve utility-scale projects, which he said is necessary to reach their climate goals.
“There is no other way,” he said. “If we are not setting a rapid pace for investing in solar and wind we will not meet the energy centers that we are going to be setting.”
Still, Michigan has a deep history of local decision-making, and for some, the idea of transferring power to the state is unacceptable. Judy Allen, the director of government relations for the Michigan Townships Association, said doing so would create a one-size-fits-all approach.
“It’s not a cookie-cutter situation, and that’s why we think it’s incredibly important that you have that local voice and that local process in terms of location and permitting,” she said — even when it means farmers can’t do what they want with their lands. Read Next
As utility-scale renewables expand, some Midwest farmers are pushing back
Michigan isn’t the only state debating who should approve renewable projects. Ohio’s legislature gave authority to counties to block them in 2021, and local opposition has stymied what’s projected to be some of the biggest renewable energy growth in the country — based on large projects planned on farmland and funded by Fortune 500 companies like Amazon, Google, and Facebook.
Despite those roadblocks, project development hasn’t stopped, and Ohio utilities are on track to meet their renewable requirements, said Matt Schilling, the director of public affairs for the Public Utilities Commission of Ohio and the Ohio Power Siting Board.
“We are continuing to see more development projects come into the power siting board,” he said. “I think time will tell, but the work is still going on.”
States like Minnesota, Illinois, and Wisconsin have seen local challenges as well. But unlike Michigan, those states have the authority to approve large renewable projects — even if local opinions differ.
In Michigan, township control is a big problem for companies, governments, and individuals trying to develop renewable energy, said Scott Laeser, a senior advisor for the Rural Climate Partnership and a farmer in southwest Wisconsin.
“If the opposition were to continue to advance, I think there would be some legitimate concerns about whether we can meet the renewable energy goals that states like Michigan, and quite frankly, the nation have,” he said.
According to Laeser, who has been involved in renewable energy planning for years, outside interests have also gotten involved in local debates, often spreading misinformation. “Some of the opposition is being funded by fossil fuel energy interests who don’t want renewable energy to succeed,” Laeser said. “So there’s a lot of complex dynamics that are mixed up in all of this.”
One way to turn down the temperature may be through projects that use land for both agriculture and energy production.
Proponents see solar grazing and other farm collaborations as an answer to the debate around land use in Michigan. Some studies back that up; a Springer survey in Houghton, Michigan, and Lubbock, Texas, found that most respondents were more likely to support solar projects if they incorporated agriculture. In practice, however, that can be difficult.
Samantha Craig has worked as a shepherd for about six years, first with her husband, and now their children. The family is based in Van Buren County in southwest Michigan, where they manage Craig Farms Katahdins — and a flock of over 200 sheep.
The pandemic and inflation have made the past few years tough, Craig said, and solar could be a path toward a steady income and long-term viability for farmers, as solar operators pay them to lease land or graze down grass.
Craig is excited about the prospect of sheep as vegetation managers. The farm’s website has a section called “lambscaping,” and the family has partnered with United Agrivoltaics, which works to help solar providers and farmers set up solar grazing. Still, Craig hasn’t been able to get her sheep on any solar farms yet. The logistics can be challenging; sheep need water, routine care, and shelter — things many existing solar sites aren’t built to accommodate — and it can cost a lot.
Local ordinances, zoning, and bureaucracy can also mean a lot of red tape. Craig had hoped to get her sheep onto a nearby solar farm, but she hasn’t gotten far with the local government.
“It was just definitely disappointing not to have the sheep out there this summer,” she said. “We were really hoping that that would come to fruition.”
Increasing tensions around renewables complicate potential partnerships. Craig’s neighboring township voted against solar on agricultural land in August and is now being sued by the solar company. To the east, Milan Township, which held the spring recall election, only wants solar erected in industrial areas, which township clerk Stephanie Kozar said excludes collaborations between large-scale solar and farming.
“We feel solar panels, even with crops or animals of some sort, it’s still a very industrial-looking project,” she said. “And so we feel like the industrial zoned area is probably the most appropriate place for it.”
Despite many hurdles, some still think partnering solar and agriculture will play an important role in debates around land use. Charles Gould is an educator at Michigan State University Extension. He started working at the intersection of farming and renewable energy about a decade ago, when farmers began asking him for advice on solar company lease agreements.
Since then, he’s delved into the dynamics of local governance, farming, and solar power. Gould said many farmers have come to see solar lease agreements as a sort of retirement package, and some consequently bristle at local efforts to restrict solar development, seeing them as a threat to their chances at financial stability.
“It evolved to, ‘This is a takings issue,’” he said. Farmers were asking, “How does a township have the right to tell me how to use my land?”
Of course, farmers are far from united on the issue. Some don’t like the idea of using their land for renewables. Gould agrees that areas like brownfields and right-of-ways should be considered for solar projects before farmland. But he said the many benefits of solar–agriculture collaborations mean it’s imperative to work with local governments and those who have concerns about the impacts of solar on their communities, something echoed in a federal study on successful collaborations.
As Michigan pursues its renewable energy goals, companies will continue to approach communities with these plans, according to the extension service. To help local governments tackle solar planning and zoning, Gould and others created a guide that includes templates for solar-specific ordinances and steps on how to plan for various situations.
The goal of this work is to help communities, solar companies and farmers hash out plans before the panels go up.
“Really, if we want to be successful at this, we need to back up and think ahead of time before that solar project is on board,” Gould said. “Bring all the partners together, have them all sit down and figure out what that’s going to look like.”
This article originally appeared in Grist at https://grist.org/agriculture/in-michigan-not-so-sunny-prospects-for-solar-farms/.
Massachusetts officials are proposing policy solutions to address a bureaucratic backlog that municipal leaders and clean energy advocates say is bogging down one of the state’s most successful drivers of clean electricity purchases.
Nineteen communities across the state are waiting for public utility regulators to rule on proposed community choice aggregation plans, in which local governments negotiate with power suppliers for lower prices or a higher share of renewables.
Some of these municipalities have been waiting for more than two years to launch their programs. Another 16 are waiting to see if the state will let them modify existing programs. As the proposals languish, municipalities are missing out on chances to save residents money and cut carbon emissions.
In response to this backlog, the state energy department has proposed a new system to streamline the process, though many advocates are highly skeptical of these guidelines.
“I’m not sure that the way they’ve drafted them is really going to address the backlog,” said Martha Grover, sustainability manager for the city of Melrose, which first adopted community choice aggregation in 2015 and has held off updating the program in recent years because of the delays.
In addition, state Rep. Tommy Vitolo has introduced a bill that would require faster response times and allow municipalities to make some changes to programs without seeking state approval.
Massachusetts was the first state to introduce these programs, as a part of electricity restructuring legislation passed in 1997. The policy allows individual cities and towns or groups of municipalities to use the promise of a built-in customer base to negotiate with power suppliers for prices. Generally, residents are automatically enrolled but can opt out at any time.
The Cape Light Compact, a group of 21 towns on Cape Cod and Martha’s Vineyard, formed the state’s first aggregation program in 2000. The idea was slow to catch on, however, until electricity prices started rising in 2013 and 2014, prompting more municipalities to seek alternatives. Today, there are 168 municipal aggregation plans active in the state, saving consumers more than $200 million annually, according to a report from the nonprofit Green Energy Consumers Alliance.
Though not explicitly an emissions reduction program, aggregation also allows municipalities to include more renewable energy in their portfolios than legally required. And many of them do exactly that: 76 of Massachusetts’ aggregation programs included extra renewable content in 2022, according to the consumers alliance. Another 40 communities let individual residents opt-in to higher levels of renewable energy. In 2022, Massachusetts’ green energy aggregation programs increased demand for renewable energy in the state by more than 1 million megawatt-hours, the Green Energy Consumers Alliance calculated.
“There is no other program in the commonwealth that produces cleaner electrons without subsidy,” said alliance executive director Larry Chretien.
The delays were first caused by the COVID-19 pandemic, according to a statement from the state energy department. Additionally, the complexity of the rules and requirements for a successful application have also slowed things down, state officials and municipal leaders agree. Each time regulators rule on a plan, any new precedent set by that ruling must be complied with by all future applicants. This requirement makes it hard for municipalities to understand the rules and forces frequent revisions. It also makes it more painstaking for the state to ensure a proposal meets the ever-changing slate of requirements.
“There are now 168 approved plans and we are held accountable to rules and ways of operating that are buried in the footnotes,” Grover said.
The state has responded to the backlog by releasing draft guidelines that summarize and simplify the detailed requirements. It has also issued an application template and proposed an expedited approval process for municipalities that use the template.
“Addressing these delays is a top priority for the [Department of Public Utilities], and we look forward to announcing finalized guidelines that will help facilitate a timely review of applications,” said department chair Jamie Van Nostrand.
For many municipalities, however, the guidelines make no changes to the process, but only formalize the existing approach, which many say amounts to micromanagement. At least eight cities and towns have filed testimony so far arguing that the proposal erodes local control and would be unlikely to speed up approvals. The draft guidelines would make the process “more burdensome and less efficient,” testified Michael Ossing, city council president in Marlborough, which adopted community choice aggregation in 2006, saving residents an estimated $26 million over the past 17 years.
“Aggregation should be under municipal control,” said Anthony Rinaldi, an Amesbury city councilor. “We should control how we implement the program, how we inform our citizens. But they want to control every little thing.”
Vitolo’s bill offers an alternative approach. It would address the delays by requiring the state to issue a decision on aggregation applications within 90 days. If this deadline is not met, a program would automatically be approved. If regulators rejected a program, and applicants resubmitted an amended plan within 30 days, the state would then have 30 days to issue a decision.
The bill would also allow cities and towns to make certain changes — including periodic changes to prices and product offerings, means of providing notifications to customers, and sharing translated materials — to their programs without returning to utility regulators for approval. Vitolo points to Boston, which launched a community choice program in 2021, as an example: the city wants to distribute translations of its information materials, but can’t do so without getting in the slow-moving line for approval.
“It’s been frustrating,” Vitolo said. “We want to allow these aggregators to make simple straightforward changes without going to the [state].”
Vitolo’s bill had a committee hearing in late September. Now supporters must wait to see if it gains traction in the legislature.
The rig operator was stumped. He’d been making good progress, but now something blocked the way forward. The operator, Denny Mong, stared at an unassuming metal tube in the ground — the fossil of an oil well. Spread around it was an array of industrial detritus and steel tools like giant surgical implements, which sunk into the spongy Western Pennsylvania meadow.
Above the hole, Mong’s rig, which towered 50 feet into the air, suspended a vertical ramrod. When it dropped, the ramrod only shot 17 feet into the ground before slamming to a stop. Earlier, Mong had managed to reach more than 500 feet deeper into the well. Then this obstruction, whatever it was, sent him back to the start.
Clearing it — prime suspects included metal casing, rocks, or a tree branch — would allow him to send cement and pea gravel into the hole, which reached hundreds of feet into Appalachian rock formations. Once an active oil well, now it was an environmental nuisance and the target of an ambitious federal cleanup program.
The well needed to be decommissioned, along with at least 21 more spread across woodlands and fields in McKean County, Pennsylvania. The job fell to Mong and other employees of an oil service outfit called Plants & Goodwin, which specializes in plugging so-called orphan wells. Oil and gas companies are supposed to plug and clean up wells that they’ve drilled, but if they go bankrupt or otherwise disappear, that responsibility falls to the state, which then contracts with companies like Plants & Goodwin. If left festering, these wells can leak contaminants into surrounding groundwater or release methane, a greenhouse gas at least 25 times more powerful than carbon dioxide at trapping heat in the atmosphere.
Uncorking a well in this part of Appalachia reveals a blend of oil and gas that has a nauseous maté color and gurgles like witch’s brew. After generations of drilling, the remnants of both vernacular backyard digs and professional oil operations pockmark the land. Since drillers operated for more than a century with little regulatory oversight, documentation of well locations is scarce and cleanup quality is inconsistent.
“Until the 1970s there were no strong plugging standards in place,” said Luke Plants, who heads Plants & Goodwin. “People just shoving tree stumps down a well to plug it, or a cast iron ball or something like that.”
The exact number of orphan wells nationwide is unknown. In late 2021, The Interstate Oil and Gas Commission, a multi-state organization, had more than 130,000 orphan wells on record but estimated that anywhere between 310,000 and 800,000 remained unidentified. That year the federal government took notice, folding $4.7 billion into the Infrastructure Investment and Jobs Act to help states handle their orphan well inventories. The first batch of that money has trickled down to states and has been distributed to contractors like Plants & Goodwin. It’s easily the most funding ever spent to address the problem, but both states and pluggers are now facing hurdles as they begin to identify and plug wells.
The state oil and gas regulators responsible for issuing well-plugging contracts are typically understaffed. As a result, the pace of contract assignment in some states has been inconsistent, making it difficult for plugging companies to staff up and plan ahead. Well pluggers are also few and far between. Since oil operators tend to avoid the costly work of well capping, the service has remained a niche industry. Plugging companies have also struggled to find trained workers, not to mention the specialized equipment required to plug wells. Along the way, some states have handed out millions of dollars in contracts to a subsidiary of an oil company with hundreds of compliance violations.
All the while, the oil and gas industry continues to spawn new orphan wells — magnitudes more than the number being plugged. Between 2015 and 2022, more than 600 oil and gas companies filed for bankruptcy, leaving thousands of wells unplugged. Market downturns affecting oil prices during the mid-2010s pushed many operations to insolvency. And even in times of industry booms, wells near the end of their production lifespans often end up in the hands of small oil patch operators with tight margins. Further, state laws requiring companies to post collateral for their wells in case of bankruptcy are meager. This combination of weak rules and bankruptcies has caused orphan well inventories to balloon. For example, Pennsylvania’s list of 20,000 orphan wells grows by about 400 each year; the state has plugged just 73 wells with the federal money that began to arrive last year.
In the muddy pasture in northwest Pennsylvania, Mong was trying to unclog his way to the well’s bottom. Using a rig attachment called a cherry picker — imagine a four-foot steel clothespin — he worked to spear unknown detritus from the depths. Next to the hole lay 30-foot-long clay-frosted tubes of steel casing already hauled out. After reducing the borehole to a hollow dirt cavern, the pluggers will pour cement until it nearly fills to the surface and top the rest of the way with gravel, insulated by steel casing to protect groundwater. They will then decapitate the casing to a few feet below ground and cover it with dirt.
For the pluggers, the work is a bespoke combination: a little science and a lot of art. Sharp intuition, engineering know-how, grit, and luck imbue each effort. One capping can take anywhere from three days to three months, sometimes costing more than $100,000.
A lot needs to happen to orphan wells before they’re plugged — at least on paper. The state has to identify them, the threat they pose, the costs to plug them, and search for any elusive owner to pin the costs on. And while that’s a process states have handled for many years, most state plugging programs have relatively small budgets and staff compared to the well inventories. Now, federal funding is compelling those programs to exponentially increase the number of well-capping contracts, an impossible task without bigger staffs and nimbler processes.
In a normal year, the California Geologic Energy Management Division (CalGEM), which regulates oil and gas production in the state, might contract plugging for 30 wells. According to former CalGEM employees, decommissioning even that number of wells had the agency running on all cylinders.
“Available staffing for oversight was definitely a major limiting factor,” said Dan Dudak, who was the Southern District Deputy of CalGEM from 2011 to 2020, and now acts as a consultant on well-plugging projects. In just the last five years, the department “lost a lot of their institutional knowledge” in three different leadership changes, he said. Nonetheless, CalGEM revealed an $80 million project last July to cap 378 wells with funding from state and federal money along with industry fees.
Other states also have catching up to do. One 2022 Ohio state audit observed that its Department of Natural Resources struggles to meet orphan well program spending targets, in part due to staffing shortages. “[T]he Division can only increase efforts dedicated to well plugging preparation work as fast as it can recruit, train, and hire permanent employees,” the audit claimed, recommending that the agency double its staff to post plugging contracts in a more timely fashion and consider outsourcing the task of drafting contracts.
Pennsylvania has 70 well inspectors and a tally of around 20,000 orphan wells. According to Neil Shader, spokesperson for the state Department of Environmental Protection, or DEP, the agency is considering hiring more inspectors to increase its oversight. Earlier this year, the state legislature approved a $5.75 million budget increase for DEP, some of which may boost its well plugging contract capacity.
Still, the pace of contract creation in Pennsylvania has put pluggers in a precarious place. Plants said that when Pennsylvania received $25 million in its first batch of federal funding, he staffed up. A torrent of contracts were awarded but then stopped — leading from feast to famine. A six-month gap meant furloughs and mothballing equipment. “It costs contractors a tremendous amount of money to do all that,” he said. “You end up creating an incentive to not scale at all, just stay small.”
To expedite aspects of the contract-drafting process, DEP has signaled that it may outsource some of that work. Meanwhile, Ohio is putting some of its federal money into an expedited process called the Landowner Passover Program, where approved landowners who find orphan wells on their land may act as a surrogate for the state, awarding a contract to a plugger that Ohio will pay for.
Ohio has 44 contractors on its rolls and utilizes a pre-approval process for its pluggers to maintain quality control. Pennsylvania’s DEP is considering adopting its own vetting process, according to Shader, the agency spokesperson. Without it, there is no central parapet to separate under-qualified contractors from federally funded plugging. “There are not enough defined rules in place,” said Plants. “And even the rules that are there don’t get followed so well all the time.”
Not much stands in the way of a corner-cutting contractor. In remote pockets of Appalachia, improperly dumping chemical fluids from a site or shoddy plug job could go unnoticed. “I think it’s even less likely to get checked now,” Plants said. “Because nobody wants to limit the pool of potential well pluggers. We need to get more pluggers involved — whether that plugging is being done correctly or not.”
Last year, Pennsylvania Deputy Secretary Kurt Klapkowski of the DEP’s Office of Oil and Gas Management addressed that anxiety by announcing that parties with significant outstanding violations, such as contractors with a poor service record or operators with environmental infractions, wouldn’t receive state contracts. “I feel pretty confident that we would not be issuing contracts to operators that had significant outstanding violations — either on the contracting side of things or on the environmental protection side,” he said.
For a plugger, non-compliance could mean illegal dumping or improperly sealing a well; for an operator, it might mean abandoning a well without plugging it. But such policies can be difficult to implement when oil and gas companies sometimes operate through a bevy of subsidiaries in multiple states.
In December of last year, the Pennsylvania DEP awarded Next LVL Energy contracts to plug 30 wells in the state. The company is a subsidiary of Diversified Energy, an energy giant that has amassed a massive number of wells at the end of their lives, stoking fears that the company is likely to orphan them. According to one class action lawsuit against Diversified in West Virginia, around 10 percent of its 23,309 wells in the state are technically abandoned but unplugged. Just this year Pennsylvania inspectors slapped the operator with around 300 new or unresolved operational violations. (The state DEP didn’t respond to a request for comment on Next LVL’s contracts.)
Ohio has also given half of its first installment of federal money, $12.5 million, to Next LVL Energy to oversee the plugging of as many as 320 wells. To the southeast, West Virginia has given the company a similar sum to plug 100 wells. Spokespeople for both state environmental agencies defended their decisions, noting that they followed state and federal guidelines while selecting pluggers. “We will keep a close eye on implementation,” said Andy Chow, a spokesperson for the Ohio Department of Natural Resources. “Should any violations in this contract be discovered or otherwise come to our attention we will review those actions.”
In West Virginia, Next LVL isn’t plugging any wells associated with Diversified, according to Terry Fletcher, chief communications officer with the state’s Department of Environmental Protection. “At the time the contracts were awarded, Next LVL had no outstanding environmental violations in the state,” he added.
Finding qualified workers for the oil field is no easy feat, either. The last decade has seen drops in oil prices that rendered many fossil fuel companies insolvent, along with a shift to shale exploration, which requires fewer workers. As a result, job openings have dwindled and many qualified workers have left Appalachia.
Plugging wells also requires skilled labor. Thus, the limited number of qualified workers is in high demand. That’s good for wages, but without a large workforce to fill positions as states push out contracts with increasing frequency, another problem arises: “You just get this arms race for the same small pool of workers,” said Plants. “That’s not actually helpful for scaling or expanding the supply side of this business.”
Plants has brought in experienced pluggers from Texas oil fields to help train up a new generation of skilled Pennsylvania hands. “We want to develop a local workforce that understands this work,” he said. But “you can’t just put whole crews of inexperienced people out there.”
There’s a lot of on-the-job training, but that extra work advances his vision. Some of his most recent hires came from area high schools and technical schools, where he has made a pitch: “We want to give you a long-term career.”
Bronson Knapp, who owns Hagen Well Services in Ohio, has faced similar challenges. “The good old farm boy is hard to find,” he said. A worker shortage is one of the reasons Ohio is behind on well pluggings. The state has awarded new contracts even as work from previous contracts hasn’t been completed. “We awarded 380 wells this year, but our contractors are still 400 wells behind us,” said Jason Simmerman, the orphan well program engineer with the state’s Department of Natural Resources.
Rigs used to plug wells can be hard to come by, too. Drilling technology may advance, but orphan well-plugging is frozen in time. The tech required is often vintage, which means pluggers are on the prowl for a shrinking number of rigs that may be older than the wells they plug. It’s not unusual for a plugger in New York to look as far as Texas for a used rig. Mong’s rig was from the 1950s. Another rig at a nearby work site was manufactured in 1981 and welded to the bed of a Vietnam War-era military truck.
On the whole, a few recent high school graduates on Plants’ payroll might not seem like bellwethers of a next-generation workforce. But some experts watching the federal orphan well program contend that a well-plugging wave could revive regions whose economic fates are tied to dwindling resource extraction sectors. “The most positive thing that could happen is that we begin to get more companies plugging wells, especially in rural, distressed areas to help their local economies,” said Ted Boettner, a senior researcher at the Ohio River Valley Institute, a think tank focused on economic and environmental sustainability in Appalachia.
“Oil and gas industries have lost thousands of jobs over the last decade,” he told Grist. “This is helping people who lose their jobs” and providing “a way for people to transition into cleaning up this mess of the last 150 years.”
The federal program includes requirements and guidance to help ensure that the work on the ground benefits workers. In order to qualify for funding, states must ensure that plugging contracts meet standards outlined by the Davis-Bacon Act, a federal law that guarantees government-funded labor matches average pay rates for similar work in a region, known as the prevailing wage.
Failure to follow the federal government’s requirement risks its scrutiny. For example, last year the GOP-led Pennsylvania legislature passed a law dictating how much a contractor might receive to plug a well as part of Pennsylvania’s orphan well program. The amounts allocated were a fraction of typical costs, likely leaving contractors unable to pay their workers the prevailing wage. With federal money tied up in the program, the Department of Interior filed a brisk response warning that the law could threaten Pennsylvania’s ability to comply with program standards and that the state could be cut off from federal funding.
In Ohio, Davis-Bacon requirements appear to have an effect on well-capping work not funded by the federal program. Though the Buckeye State doesn’t have any wage requirement for general well-plugging work, cappers who have taken contracts appear to be paying higher wages — whether or not the job is federally funded. “Because nobody wants to make one wage one day and another the next day, our contractors that are working on our federal program are taking that perspective and paying those wages across the board now,” said Simmerman, Ohio’s orphan well program engineer.
Out west, California is working to nurture a workforce at a much larger scale. Last year, the state legislature passed a law directing the California Workforce Development Board, or CWDB, to launch apprenticeship programs to train new classes of well pluggers. It could become a model for skilled labor creation. Its first pilot program is using the expertise of a Kern County well-capping company, California Legacy Well Services, which is creating a plugging curriculum to fold into existing training provided by Local 12, the International Union of Operating Engineers. As a result, union-affiliated labor will represent part of the well-plugging workforce.
The thinking is two-pronged: access to quality jobs and layoff mitigation. That means offering good work to skilled laborers vulnerable to the energy transition. “So rather than just worry about the loss of jobs, it’s an opportunity to think about the new jobs for trades workers,” said Tim Rainey, executive director of CWDB. The program is in the early stages, but it offers a glimmer of what an effective orphan well program could yield.
Organized labor in California’s oil fields is of two types: industrial unions and trades unions. Members of industrial unions cultivate skills on a worksite, while trades unions learn the ropes through training apprenticeships like the ones CWDB is developing.
A quirk in California law may lock out the industrial unions. The law requires “a skilled and trained workforce” for capping jobs, an innocuous-sounding phrase that refers to highly technical requirements in the state labor code that disqualify oil workers from industrial unions such as the United Steelworkers, or USW.
Norman Rogers, a spokesperson and member of USW Local 675 in Southern California, called the legislative sleight of hand “a control job.” Trades unions “have a larger workforce and are able to influence the political landscape,” he said. “They can have all sorts of people go to lobby.”
By expanding the language to characterize eligible workers as “skilled and trained or covered by a labor management agreement,” the law could tap into tens of thousands of union workers represented by USW, Rogers said.
The question of who dominates the green jobs of tomorrow remains an open one. Despite the many bottlenecks, the orphan well program could be an attractive coda to the fossil fuel era if it benefits workers.
“We drilled the first oil well in America,” said James Kunz, an administrator at the Pennsylvania Foundation for Fair Contracting, who has worked to ensure favorable wages in state capping contracts. “We have the scars of that and a real opportunity.”
This article originally appeared in Grist at https://grist.org/energy/abandoned-oil-well-job-solution-pennsylvania/.
Grist is a nonprofit, independent media organization dedicated to telling stories of climate solutions and a just future. Learn more at Grist.org
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The Biden administration is about to get more young Americans working for the planet.
Last week, the White House announced it’s launching an American Climate Corps. The workforce training and service program aims to get young people ready for climate and clean energy fields. It will put an initial cohort of 20,000 to work installing clean energy technologies, restoring coastal wetlands to prevent flooding, and taking on other jobs in climate-vulnerable communities.
It’s all reminiscent of the New Deal-era Civilian Conservation Corps, which hired young people to fight forest fires, build wildlife refuges, and take on other environmental jobs during the Great Depression.
Flash forward to the 21st century, and a Climate Corps has been a priority for Democratic lawmakers. The Biden administration initially proposed the work program as part of its Build Back Better infrastructure plan, but it was left out of the Inflation Reduction Act. But by combining programs and funding authorized in the climate law and other legislation, the White House has created something pretty close to the program it’s been working toward for years, Inside Climate News reports.
There are a lot of details we don’t yet know about the American Climate Corps, including how interested workers can apply and how much they’d be paid. But for now, there’s a White House website where you can share if you’re interested in joining or otherwise helping the burgeoning corps out.
This article originally appeared in Canary Media.
Local Law 97, New York City’s groundbreaking, multistage effort to rein in carbon emissions from its big buildings, is facing its first major test — and it’s just a preview of the much steeper challenges to come.
Last week, New York City Mayor Eric Adams released proposed guidelines for how owners of the worst-performing buildings can comply with the law’s mandate to curb emissions by 2024. Next year, the city will begin imposing fines on buildings that haven’t reduced their emissions below certain thresholds, with even steeper cuts and rising fines to come in 2030 and 2040.
The response to the new compliance guidelines was swift. Real estate owners opposed to the law reiterated long-standing complaints that the mandates will force them to choose between paying steep fines or making efficiency investments that don’t make economic sense today.
Environmental activists countered with evidence that near-term compliance is not nearly as costly as opponents say it will be. They also worry that two parts of the proposed regulations, which would allow laggard buildings to postpone compliance for two years and use clean-energy purchases to offset continued building emissions after that date, amount to a surrender by the Adams administration to real estate interests at the expense of fighting climate change.
“Mayor Adams is proposing a gigantic giveaway to his real estate buddies that’s going to increase pollution and crush jobs,” said Pete Sikora, climate and inequality campaigns director of New York Communities for Change and a former member of the Local Law 97 advisory board.
That’s why Sikora’s group and a host of environmental and community activists are protesting what they describe as loopholes in the new proposed guidance. The conflict over these proposals underscores a key tension around the broad goal of decarbonizing buildings: how to balance the carrots with the sticks. If the cost of meeting the law’s emissions-reduction mandates is too high, building owners may simply choose to pay the fines instead, an outcome that does little to help the climate.
But building-efficiency experts agree that meeting the law’s 2024 targets should be relatively simple for the vast majority of commercial and multifamily residential buildings in New York City. As evidence, they point to the fact that 89 percent of buildings covered by the law are already in compliance with its requirements, including many older buildings that are harder to retrofit to become more energy-efficient. They also note that alternative compliance options have been established for more challenging buildings such as low-income housing.
“I do not believe there is a serious building professional in this city who would say that a building making a good-faith effort, absent very unusual circumstances, would not be able to get under the 2024 limit,” said Sikora. “In some buildings, they could do it almost immediately if they wanted by making some very basic changes — putting in LEDs [and] aerated shower heads, insulating exposed heating pipes, tuning the boiler correctly” and other such remedial actions.
What will be harder, he said, is meeting Local Law 97’s longer-term goals. Roughly 70 percent of the city’s buildings do not yet comply with the law’s tougher targets of cutting carbon emissions by 40 percent from 2019 levels by 2030.
Hitting that end-of-decade figure in particular will require far more extensive efforts to switch from the oil- and fossil-gas-fueled systems that heat the majority of buildings today to electric heat-pump systems or low-emissions steam heat systems. It will also require deeper building-efficiency retrofits to ease stress on the power grid.
Difficult as it may be to pull off, it’s crucial to meet these targets. Buildings contribute 70 percent of the carbon emissions in New York City, which means “we will not achieve our climate goals without addressing buildings,” said John Mandyck, CEO of the nonprofit Urban Green Council, which has played a key role in creating the law and monitoring its implementation. While building owners have been waiting for key guidelines on how the law will be enforced, with last week’s proposed guidance, “the compliance pathway is now evidently clear,” he said.
But the ongoing political fight over the law’s short-term targets could derail these longer-term efforts, Sikora said. New York City officials estimate the costs of hitting the law’s 2030 targets to range from $12 billion to $15 billion. If building owners don’t start making investments now, they run the risk of missing the law’s targets, which are designed to reduce the city’s carbon emissions in line with the Paris Agreement, he said.
“The law’s limits are achievable and affordable,” he added — a view backed by the Urban Green Council and other groups. The 2024 targets were meant to “get the most polluting buildings here to cut their pollution as a warmup to the 2030 requirements, which are quite a bit tougher.”
Environmental groups have two key complaints about the regulation proposed by the Adams administration last week.
The first is the proposal to allow the roughly 11 percent of buildings not yet hitting their targets to escape fines through 2026 if they make a “good-faith effort” to get on track. Some environmental groups argue that building owners have already had four years to prepare for 2024 targets and shouldn’t be rewarded for inaction.
“Responsible landlords are already doing that, not just to cut pollution but to save money on bills, too, and raise the property value,” Sikora said. “The mere fact that some landlords are incompetent doesn’t mean they should be let off the hook.”
But in Mandyck’s view, the good-faith exemption is a reasonable approach to forcing buildings that are behind schedule to meet the law’s mandates. Since Local Law 97 was passed in 2019, “we had Covid; we had supply-chain delays,” he noted. “It took the appropriate amount of time for regulations to unfold. And we’re now months away from compliance. So we have two options: We fine all those buildings and forfeit the carbon savings, or we find a pathway for compliance.”
The law’s fines — $268 per metric ton of carbon dioxide emissions that exceed an individual building’s cap — equate to “the highest price of carbon in the world,” he noted. “Do we tie up the administrative courts and start issuing fines? Then people are paying fines and not doing investments in the buildings. We need carbon savings — we don’t need fine revenue.”
Tristan Schwartzman, energy services director and principal at New York City–based building engineering consultancy firm Goldman Copeland Associates, agreed that a two-year extension could help a number of his clients that “do have a path that’s going to be arduous but feasible” to meet their compliance deadlines.
To qualify for the good-faith exemption, “you have to have a plan in place; you have to show that you’ve done something that’s been impactful,” he said. “There are a lot of hurdles you’re supposed to jump — but those are hurdles you’re supposed to be jumping anyway.”
But as Sikora and other environmental groups point out, it’s virtually impossible to discern whether owners of noncompliant buildings are indeed acting in good faith. These critics fear that the exemption will instead offer a two-year reprieve from fines for a subset of property owners who have been working to undermine the law.
Those efforts include a lawsuit filed last year by groups representing residential cooperative buildings in the borough of Queens demanding that the law be overturned. They also include millions of dollars of advertising and lobbying by the Real Estate Board of New York, a politically powerful group led by Douglas Durst, the owner of high-profile properties including some that are out of compliance with the law, such as the Bank of America Tower at 1 Bryant Park in Manhattan.
The group issued an analysis in January claiming that the fines from Local Law 97 could add up to $213 million for 3,780 buildings in 2024 and $902 million for 13,544 buildings in 2030, citing these findings as proof of “significant economic disruption that will occur if property owners are not provided adequate tools to reduce emissions.”
But Sikora noted that these figures misrepresent the financial impact on individual buildings and their tenants.
He cited the example of Bob Friedrich, the board president of Glen Oaks Village, a 2,900-unit co-op in Queens, who has been an outspoken opponent of Local Law 97 and a plaintiff in the lawsuit seeking to overturn the law. Friedrich has claimed that Glen Oaks would have to invest about $24.5 million to upgrade its gas and oil boilers to seek to comply with the law, and may still face an estimated $400,000 per year in fines from 2024 to 2030.
But divided among 2,900 units, that fine adds up to about $130 per unit per year through 2030, or “the equivalent of a parking ticket,” Sikora said. Similar economics apply to many other properties, making the law’s fines far from the death blow that many property owners have claimed they will be, he said.
Offering noncompliant buildings a route to avoid penalties for failing to achieve the relatively lax 2024 standards also risks setting a bad precedent for the much tougher 2030 targets, he added. That makes the good-faith exception a potential “signal to landlords and others that, well, maybe they’ll be delayed too.”
It’s certainly true that the carbon-intensity of New York City’s electricity supply will influence the emissions impact of building electrification, Sikora said. But that doesn’t mean building owners should be able to use clean-energy accounting to avoid investing in fundamental efficiency improvements.
And that brings us to the second key criticism environmental groups have made against the Adams administration’s proposed regulations. This critique centers around the role of renewable energy credits (RECs) — contracts between building owners and clean-energy producers — in the Local Law 97 scoring regime.
Today, building owners can use RECs to procure clean electricity that can be delivered to the larger New York City grid to offset their building’s emissions from electricity usage. But environmental groups have been demanding that the Adams administration set a more stringent standard, one proposed by the Local Law 97 advisory board and supported by energy experts, to limit the use of RECs to offset no more than 30 percent of a building’s total emissions.
The problem with RECs, Sikora said, is that Local Law 97 doesn’t require that they be “additional,” or tied to paying for a renewable energy project that wouldn’t have been built without the money from their purchase. Instead, building owners can purchase RECs from already existing clean-energy projects and use them to comply with the law.
That’s a problem, because in New York state, as with many other parts of the country, these RECs are becoming so plentiful that they offer building owners a much cheaper path to compliance than investing in energy-efficiency upgrades to their properties.
Today, New York City gets most of its electricity from fossil-fueled power plants. But with new transmission lines capable of carrying massive amounts of zero-carbon energy into New York City now being built and expected to be complete by 2026, building owners will soon have access to plenty of RECs from clean-energy projects that have already been built.
The Real Estate Board of New York has pushed for expanding the opportunities to use RECs to offset not just building emissions associated with electricity consumption but all building emissions. The new proposed compliance guidelines did not take up that proposal — but it also declined to institute the 30 percent cap that environmental advocates are pushing for.
It’s important to note that buildings that take the good-faith alternative pathway will be barred from using RECs to meet their requirements. But Sikora said the real danger of the current REC policy is that it could be extended to 2030 and later, threatening the law’s more ambitious longer-term goals. The Urban Green Council has estimated that 40 percent of multifamily properties and 80 percent of office buildings could offset their emissions over their 2030 limits through the use of RECs alone.
That’s a problem because “in reality, it’s not possible for the city and the state to reduce pollution unless they reduce pollution at the source — at the buildings,” Sikora said. “And that means they have to get a lot more energy-efficient.”
Green groups including Sikora’s are calling for the Adams administration to put a REC cap into place and reconsider the good-faith exemption over the coming month of public comments and hearings on the proposed rules.
Sikora didn’t downplay the challenge of paying for the deep efficiency and electrification efforts that New York City buildings will need to undertake to meet Local Law 97’s longer-term mandates. But he sees a much larger role for public funding to close that gap — and while city and state agencies are providing money through a variety of programs, it isn’t yet enough, he said.
“We think the city and state should apply billions of dollars per year to decarbonize the building stock,” he said. That big one-time transition away from gas or oil to heat pumps is a big cost.” On the other hand, “we do not think the city needs to subsidize affluent [building] owners.”
That work must start with increased funding for the variety of affordable-housing units that are currently allowed to comply with the law via so-called “prescriptive pathways,” he said. The Urban Green Council estimates that rent-controlled apartments, public housing and other affordable-housing units make up one-third of all buildings covered by Local Law 97.
Mandyck noted that the new proposed guidance provides more clarity on how those buildings can comply via “commonsense” measures, such as insulation on water heaters and steam pipes and thermostats or temperature controls on radiators.
But Schwartzmann contended that many of these buildings “are really poorly maintained because they don’t have money to maintain them properly,” due to the challenging economics of financing improvements in rent-controlled buildings or tight budgets for public housing. “The city should be throwing money at that problem, not pushing it downstream.”
Last week’s proposed regulations also included a booster for buildings exploring the switch from fossil-fueled to electric heating, primarily via heat pumps — a new credit that increases the value of electrifying at least part of their heating demands.
The new credit system “not only gives you a zero-emissions equivalent for the electricity it uses, it gives you a negative” carbon score, said Jared Rodriguez, a principal with Emergent Urban Concepts and adviser to the New York State Energy Research and Development Authority. “It’s a very clear signal that they want you doing at least partial load electrification — and that you’ll get some credit for it.”
That’s an important boost for a technology that still costs more than fossil-fueled boilers and furnaces, both in terms of upfront equipment and installation costs and in ongoing utility costs, Schwartzman said. “There was a real hesitancy to move toward these electrified options because they’re not going to save you money at this point, because electricity costs more than gas,” he said.
Last year’s Inflation Reduction Act will help make efficiency and electrification more affordable via tax credits and incentives for equipment, installation and workforce training, Mandyck noted. City officials have said they will pursue funding from a variety of federal sources, such as “green bank” loans, to ease the cost burden.
The New York state government is also funding efforts to bring down the cost of novel decarbonization technologies, he added. Some examples include a $70 million initiative to develop window-mounted heat pumps that both cool and heat apartments and the $50 million Empire Building Challenge that’s targeting high-rise commercial and residential buildings for complex efficiency and electrification retrofits.
“Because of the scale of New York City and the state…we’re going to spur innovation that’s going to help the whole market,” he said. Local Law 97 is just the most ambitious of a number of similar mandatory building-performance standards already in place in cities including Boston, Denver and Washington, D.C. and in states including Colorado, Maryland and Washington, he noted.
Finally, it’s important to remember that the climate emergency requires building owners to think differently about the costs and benefits of efficiency and electrification, Mandyck said. “We need to think about payback differently. Climate is a life-safety issue now. Nobody asks what the payback is to put a sprinkler safety system in your building. There’s no payback there — if there isn’t a fire.”
The following commentary was written by Alli Gold Roberts, senior director for state policy at Ceres. See our commentary guidelines for more information.
As the harmful economic and financial effects of climate change become increasingly clear, investors and companies around the world are rapidly adjusting their business models — not just to reduce the risk and their exposure to climate catastrophes, but to capitalize on the industries of the future.
That’s why, across the U.S. and in Colorado, businesses and investors are doubling down to the tune of hundreds of billions of dollars in innovative and sustainable clean technologies. And as that technology has advanced to make it easier and more advantageous for companies to cut their pollution, policymakers at both the state and federal level have worked to incentivize exactly these kinds of investments — to ensure their economies benefit from this windfall as they build for the future.
In Colorado, we have seen officials take bold policy action to accelerate the adoption of clean electricity, clean transportation, clean buildings, clean appliances, and even clean lawn tools — an impressive suite of policies that have helped the state keep pace with other national climate leaders. Now the state has an opportunity to trailblaze in another sector of the economy, one that has so far lagged in pollution reduction: heavy industry and manufacturing.
Under Colorado’s ambitious climate and environmental justice laws, the state is required to slash climate pollution from industrial sources — like factories and plants — by 2030. To achieve that goal, policymakers are in the process of crafting what will be a first-in-the-nation regulatory program: Phase II of the Greenhouse Gas Emissions and Energy Management for Manufacturers, otherwise known as GEMM II, will be adopted later this year and go into effect as soon as next year.
At a time when cleaner products are growing their competitive advantage in the global marketplace, GEMM II gives the state a real chance to be at the vanguard of clean manufacturing. But to reap the economic benefits promised by this transition, Colorado must get the policy right.
The sustainability nonprofit I work with, Ceres, partners with companies and investors to capture the economic benefits of clean energy and reduce the financial risks of climate change. Having done this work for more than 30 years, Ceres has developed a robust understanding of how public policy can best help the private sector achieve these goals so that they can benefit entire state economies. Even companies that are not part of the manufacturing sector have a strong interest in reducing emissions from within it, because they often rely on its products — from microchips to glass bottles — within their supply chains and know they cannot fully clean up their own operations without policy support.
That is why Ceres recently submitted a letter to state officials outlining what we believe are the best ways to successfully achieve the goals of GEMM II. Chief among them is simplicity. Colorado is on the clock to meet its climate goals, and 2030 is coming up fast. Policy clarity is essential to helping manufacturers prepare.
This is not the time to introduce complex programs that essentially allow manufacturers to keep polluting at the same rate. Instead, GEMM II should prioritize rules that directly reduce climate pollution from manufacturing sites, encouraging them to adopt innovative yet proven technologies that will achieve the program’s goals while better positioning industry to thrive into the future.
The GEMM II program must also strongly favor solutions that reduce not only pollution that harms the climate, but also air pollution that harms people and often comes from the same sources. Air pollution is a serious issue in its own right, causing increased rates of heart disease, lung disease, and other serious health problems in nearby communities. Almost all of the facilities that would fall under the GEMM 2 policy are located in communities that currently suffer from disproportionately high levels of pollution. Beyond its health effects, the threat of air pollution to their health and livelihood is also a drag on local economies. In addition, Colorado law requires that these communities must benefit from GEMM II — and reducing their exposure to toxic pollution is a clear benefit.
While GEMM II may sound like a challenge to some manufacturers, it should be better understood as an opportunity. New incentives from the Inflation Reduction Act and other recent federal climate investments, as well as state tax credits and grant programs for the industrial sector, have made it more feasible for manufacturers to clean up their operations. What’s more, they have also sparked a rush of investor and corporate interest in clean manufacturing, and a number of success stories as industry leaders move to embrace clean solutions.
We urge Colorado policymakers to seize this momentum and help manufacturers capture the swelling interest by adopting the most ambitious version of GEMM II possible. This is a chance to set a gold-standard policy that will make the state’s industrial sector more competitive, its climate goals more achievable, its air cleaner, its communities healthier, and its economy better positioned for the decades ahead.
A St. Paul, Minnesota, college’s microgrid research center is preparing to expand after securing significant new state and federal funding.
The University of St. Thomas’ Center for Microgrid Research plans to triple its three-person staff and enroll more students thanks to money from a $7.5 million state legislative appropriation and $11 million in federal defense bill earmarks secured by U.S. Rep. Betty McCollum.
State officials who championed the funding said they hope the center’s education and research efforts can help train future grid technicians and smooth the state’s path to 100% clean electricity by 2040.
“We’re at a time of not only a great transition but of a great opportunity,” said state Sen. Nick Frentz, a Democrat from Mankato. “We’ll be looking at transmission, distributed generation and innovation as we transition, and funding for the St. Thomas microgrid research is a part of the state’s plan to lead.”
Microgrids are small, hyperlocal networks of electricity generation and storage systems that together can operate independently of the rest of the power grid. They’re often used by military, healthcare or research campuses that require a level of reliability greater than what the local utility can provide.
But they’re not just expensive backup power for wealthy institutions. Microgrids are also expected to play a role in the clean energy transition, helping to get the most value out of clean energy investments and connecting customers to one another in new ways.
“Microgrids are another opportunity for clean energy,” said John Farrell, co-director of the Institute for Local Self-Reliance and director of the Energy Democracy Initiative.
Microgrids could help balance variable power sources such as wind and solar, helping to absorb and store surplus generation and share it with the grid later when it’s needed, Farrell explained. While microgrids can be powered by fossil fuel backup generators, they also can run on solar panels, whose value can be greater when they are networked with arrays on multiple sites.
The University of St. Thomas has been developing its campus microgrid for about a decade. Today, it consists of a 48-kilowatt rooftop solar array along with a diesel generator, a lead acid battery pack, and an inverter that converts direct current to alternating current. A campus substation connects to Xcel’s local grid.
Like most microgrids, the St. Thomas system can run in “island” mode, meaning it can operate even when the power grid fails by drawing on the battery, solar panels and backup generation.
The Center for Microgrid Research opened in 2020 as a way to build research and education programming around its campus microgrid. Mahmoud Kabalan, the center’s director, was hired in 2017 from Villanova University to teach engineering and helped secure seed funding from Xcel Energy’s Renewable Development Fund for the program.
Don Weinkauf, the school’s dean of engineering, said the new state and federal funding will allow the center to expand both the program and the microgrid system itself.
“This stuff is expensive,” Weinkauf said. “Each piece of equipment is on the scale of a million dollars, and right now, we are expanding to reach a 1-megawatt capacity.”
The center will have 10 full-time employees next year and be able to enroll up to 25 students. More staff and students will allow more collaboration with utilities, corporations, and fellow researchers. Within the next few years, the microgrid will connect to more than five buildings, including a new science, technology and arts center, dorms and a parking facility.
Kabalan said he expects more funding from the U.S. Department of Defense, which sees the program as a workforce training ground and source of applied research to help design, test and implement microgrid technologies.
“This funding will position the state and the nation to produce innovative engineers that can address the need for microgrids and distributed energy technologies,” Kabalan said. “A big part of what we do is educate and train engineers.”
The center is collaborating with the U.S. Army Corps of Engineers on a military initiative to install microgrids at every military base by 2035, Kabalan said. Research related to that project will be publicly available to other microgrid operators and researchers. Students and faculty have other clients and supporters, including utilities Xcel Energy and Connexus Energy.
Part of the center’s design and strategy has been to serve as a place where clients can test how their equipment works in a microgrid. The technology available includes test bays to plug in products, controllers, relayers and emulators capable of creating simulated environments.
“Interested parties can literally roll in their equipment and we can test their technology at full scale,” Weinkauf said. “This is an industry-friendly center that can help us, and the state of Minnesota, navigate our future grid.”
Students like the hands-on quality of the microgrid center. Engineering student Oreoluwa John Ero, a research assistant at the center, has helped develop models to attach the new STEAM building to the university’s microgrid.
“I like the ability to see and practice the different things you learn in school and the chance to learn while on the job,” Ero said.
Utility industry professionals who have visited the center also like the hands-on approach. Connexus Energy engineering and system operations director Jared Newton said the center “immediately resonated with me because I saw students learn on real-world equipment that we use. The problems they were trying to solve and the tools they were using were familiar.”
As climate change and aging infrastructure make weather-related power outages more common, Kabalan thinks microgrids will become more common for critical infrastructure such as hospitals, prisons, data centers, food storage areas, cooling centers and government facilities.
Ero sees how the microgrid could transform the power grid in the United States and in his home country of Nigeria, where electricity outages are common and can last for hours and weeks.
“It’s a technology that should be made available to people,” Ero said, “not just in Nigeria, but all over the world.”
A battery storage development is replacing a fossil-fuel-burning power plant in western Massachusetts, providing a model that supporters say could be emulated elsewhere.
The project is only financially viable, however, because of a unique state incentive program designed to cut emissions related to peak electricity demand.
Power company Cogentrix is developing the facility at the site of the former West Springfield Generating Station, which was shut down in June 2022. The $80 million project includes 45 megawatts of storage that will be able to send electricity onto the grid for up to four hours. It is expected to come online sometime in 2025.
“This will be really big, and set a nice precedent for transitioning from fossil fuel to storage and renewables,” said Rosemary Wessel, founder of No Fracked Gas in Mass, a program of the Berkshire Environmental Action Team.
This transition is happening at a time when there has been increased discussion about the role of so-called “peaker plants” — facilities that are only called upon at times of peak power demand. Peakers are generally older facilities that emit more greenhouse gasses than other plants, and the power they generate is more expensive.
Utilities have said peaker plants are necessary to ensure a reliable electricity supply in emergencies and times of high demand. Wessel’s organization and other environmental groups, however, argue that storage technology, especially when paired with renewable generation, can also meet these needs. They contend no new peakers should be built, and old ones should be taken out of use as quickly as possible.
“These are really the low-hanging fruit for starting to take existing fossil fuels off the grid,” said Wessel, whose group has been pushing power companies that own peaker plants in western Massachusetts to consider transitioning to renewable energy generation and battery storage.
The plan for the West Springfield plant came about when longtime energy developer Chris Sherman, vice president of regulatory affairs at Cogentrix, wanted to take his work in a new direction. He has a background in clean energy — he was project development manager for the ill-fated Cape Wind offshore wind plan — and was interested in returning to this work.
His employer put him in touch with Wessel, who had reached out to the company about the future of the West Springfield Generating Station. The plant first started generating power in 1949, initially burning coal. In the 1960s it was converted to an oil-burning plant, and in the 1990s the ability to burn natural gas was added. It was officially shut down in June 2022.
Once power plants shut down, the land is often hard to redevelop, Sherman said. However, the properties are already surrounded by the infrastructure needed to send power into the grid, so building battery storage and renewable energy installations on these sites is a promising strategy.
Sherman and Wessel met in June 2021, and it was quickly clear that their goals aligned. The two began working together to create plans for the site, which had not yet closed officially. Their collaboration, Sherman said, has made it easier to bridge the perceived gap between the logistical, technological, and financial aspects of his work, and the environmental and social concerns of community members.
“If I were to just call people and say ‘energy developer,’ they might not be willing to enter into an objective discussion,” Sherman said. Wessel “has done an incredible job at generating interest and then facilitating communication in the broader stakeholder community.”
The plan that emerged is a pragmatic one that attempts to satisfy environmental goals while also dealing with the financial realities of the energy market. The initial plan calls for charging batteries during times when demand and emissions are lower, and then discharging at times of higher demand. Cogentrix hopes to eventually install solar panels to make the energy it stores even cleaner and lower cost.
The project is now in the early permitting stages, with the goal of beginning site work over the coming winter and installing battery containers in the spring.
West Springfield leaders have expressed support for the project and the chance to put the property, formerly the largest taxpayer in the city, back on the tax rolls, noting that revenue took a hit when the plant closed last year. They are also pleased to see emissions-free batteries and solar panels take the place of the pollution the former plant created.
“I look forward to the potential redevelopment of this site,” said West Springfield Mayor William Reichelt. “Though we are in the early stages of what’s possible, overall any improvement to the site will certainly benefit the community and the region.”
Because the plan for the site represents a new sort of energy development, existing revenue models don’t necessarily apply. Sherman had to work hard to convince investors that the novel approach will turn a profit. There is enough room on the site to develop about 100 megawatts of storage, but his investors are only willing to back 45 megawatts until they see convincing results, he said.
A small amount of revenue will be made by charging batteries during times, such as overnight, when prices are lower, then selling the power back onto the grid and higher-demand, higher-priced times. Another block of money will come from participation in the regional capacity market, in which power sources are paid for committing to be available to provide electricity at some future point.
Additionally, almost half of the project’s revenue is expected to come from the Massachusetts Clean Peak Standard, an incentive system unique to the state. The standard, which took effect in 2020, offers incentives to clean energy generators and battery storage owners that discharge power into the grid at times of peak demand, helping to lower the demand on power plants.
“But for that standard, our project would not be viable,” Sherman said.
Wessel and Sherman both express hope that this project might be the beginning of a trend toward locating storage and power plant sites. Cogentrix is looking at potential projects on sites in Maine, Maryland, and New Jersey. In these cases, the power plants have not yet been retired, though Sherman said the plans should still reduce emissions.
For the concept of replacing peakers with batteries to really catch on, states will need policies that add incentives such as Massachusetts’ Clean Peak Standard that can dispatch stored power at peak demand times, Sherman said. State-backed policies, he said, will help convince backers that such projects are financially feasible.
“What I need to demonstrate to investors,” he said, “is that we can have predictable, durable, long-term revenue streams.”
“As we mature towards the final investment decision, if the walk-away scenario is the economical, rational decision for us, then this remains a real scenario for us as an alternative to actually taking the final investment decision,” Chief Executive Mads Nipper said on an Aug. 30 call with investors.
Orsted shares fell 25% in the wake of the news.
Now, a top credit rating agency has cast further doubt on the company’s financial future. Moody’s Investors Service downgraded its outlook for Orsted from “stable” to “negative,” according to a Sept. 5 report.
“Whereas the impairments don’t change the company’s [earnings] guidance or expected investment levels in 2023, Moody’s expects the headwinds that Orsted is currently facing in the US to lead to its credit metrics being weakly positioned at least until the end of 2025,” the credit rating agency stated in its report.
Moody’s affirmed Orsted’s existing bond and credit ratings, but also warned of “downward pressure” on its future ratings if delays and cost overruns worsen.
Stephanie Francoeur, a spokesperson for Orsted, pointed to the affirmation of existing credit ratings, rather than the outlook downgrade, in an email on Friday.
“Ørsted is rated by the three rating agencies, Moody’s, Standard & Poor’s, and Fitch, and all three rating agencies have confirmed our current rating,” Francoeur said. “We note that Moody’s continues to have confidence in our commitment to our current rating, and we’ll ensure that we deliver on our financial plan to provide Moody’s the comfort needed to continue its confirmation of our current rating.”
Orsted is hardly the first offshore wind developer to run into economic headwinds. In neighboring Massachusetts, two companies – SouthCoast Wind Energy LLC and Avangrid Renewables – have canceled their power supply agreements with utility companies, saying the existing payments are too low given increases in their expenses.
Orsted insisted as recently as June that it had no plans to renege on its electricity agreements with Rhode Island. The existing, 2019 agreement inked with the-utility operator National Grid gives the developer 9.84 cents per kilowatt-hour for 400-megawatts of electricity from the offshore wind facility over the entire 20-year contract. National Grid in turn would earn $4.6 million in renewable energy credits sold from the project.
In its August announcement, Orsted executives pledged to secure final investments in its projects, including Revolution Wind, no later than early 2024.
“The US offshore wind market remains attractive in the long term,” David Hardy, executive vice president and CEO of Region Americas at Ørsted, said in a statement. “We will continue to work with our stakeholders to explore all options to improve our near-term projects.”
State officials, including Gov. Dan McKee, have repeatedly stressed the importance of the offshore wind industry to the state economy, creating jobs and boosting state GDP.
Olivia DaRocha, a spokesperson for McKee’s office, said in an email Friday that Orsted assured the state of its commitment to the Revolution Wind project despite its recently announced financial woes.
“The company communicated that there are no direct impacts on the RI Revolution wind project and associated work, which is scheduled to start over the next several months,” DaRocha said.
DaRocha referred additional questions to Orsted.
Onshore construction work related to the 700-megawatt Revolution Wind project has already begun, with construction offshore expected to ramp up in 2024 ahead of a 2025 operational date, the company said previously. The 65-turbine wind farm planned off Block Island’s coastline has already secured approval from state coastal regulators, as well as a final environmental assessment from the U.S. Bureau of Ocean Energy Management.
In preparation for Revolution Wind and other projects in nearby waters, Orsted has committed $40 million into infrastructure investments at Quonset and Providence ports, including a wind turbine manufacturing facility at ProvPort. It has also partnered with local shipyards to build crew transfer vessels and invested $1 million into a training program for industry workers at Community College of Rhode Island.
Secure Solar Futures president Tony Smith barely paused to celebrate last week’s David vs. Goliath victory for small-scale commercial projects.
The bustling but tiny solar operation he founded just couldn’t spare the time for a party.
Still, he’s jubilant utility regulators put the kibosh on Dominion Energy’s attempt to saddle rooftop installations with astronomical grid interconnection fees that was stifling the industry’s gains across an expansive swath of Virginia.
“We were joyful,” Smith said about the injunction the State Corporation Commission (SCC) delivered on Aug. 30. “Then, upon saying ‘Wow!’ for 15 minutes, we got back to work.”
After all, his Staunton-based company needed to redirect its attention to advancing two stalled rooftop installations in Prince William County. The threat of unexpected expenses from Dominion meant projects at Freedom High School and Potomac Shores Middle School — roughly 1 megawatt apiece — had been in limbo for eight-plus months.
Secure Solar Futures was far from alone.
Companies across Dominion’s service territory were also reassessing projects they had paused after the investor-owned utility rolled out new and expensive interconnection parameters last December for non-residential, net-metered solar projects.
Dominion’s surprise rules — announced more than two years after a major Virginia law bolstered solar — could have boosted the price tag of each school project by at least $1 million, Smith estimated.
“This hits Virginia right in the groin,” Smith said. “It wasn’t isolated and it created havoc.”
Regulators had not vetted the new requirements, which spelled out how solar companies would be on the hook to pay to upgrade substations, cables and other hardware, as well as cover the cost of a series of studies to guarantee the new projects met safety and reliability requirements.
Also, solar array recipients would be required to pay a monthly fee to Dominion to cover maintenance. Not only that, but the utility wanted solar customers to sign what it called a “small generator interconnection agreement” so it was clear they would be the ones held liable if their array caused a grid failure.
“We heard war stories from other solar companies who were throwing up their hands and saying they would have to back out of Dominion territory because it was a deal-stopper,” Smith said.
Handfuls of complaints weren’t confined to Northern Virginia, where the two Prince William County schools are. For instance, a solar array on a grocery store in the Hampton Roads region was put on hold. And near Richmond, Henrico County officials slowed plans for a 686-kilowatt array at the James River Juvenile Detention Center.
Those setbacks prompted Smith and others to reinvigorate the Virginia Distributed Solar Alliance. A decade ago, the group — spearheaded by Secure Solar Futures — had successfully strategized a legislative path forward for solar power purchase agreements. It’s a mix of solar installers, and advocacy organizations such as the Sierra Club of Virginia and Solar United Neighbors of Virginia.
“One of the virtues of being a network of players joined by a set of shared values and aspirations is that we could be extremely nimble,” Smith said. “We didn’t have to go through hierarchies.”
This time around, the alliance needed to convince regulators to order Dominion to back down on costly interconnection demands.
“We realized what Dominion was doing was unprecedented and harmful,” Smith said. “And it was illegal.”
The alliance, with Smith at the helm, started its conversation with Dominion via an April letter to CEO Bob Blue. It laid out roughly a dozen projects close to 1 MW in size that would be deep-sixed due to the time and money consumed by the parameters.
Within a week, Blue responded, telling the alliance that Dominion wasn’t budging, saying that the safety of customers and employees, and the reliability of the grid were paramount.
Eventually, alliance members concluded that utility regulators needed to hear their case. On June 1, they filed their first-ever petition with the SCC, calling on guidance from Cliona Robb, an energy attorney for 23 years.
Robb, a partner at Richmond-based Thompson McMullan, serves as legal counsel for the alliance.
The alliance’s June petition stated that Dominion’s interconnection parameters were illegal because they were never approved by regulators. It asked commissioners to rule on net metering projects between 250 kW and 1 MW.
“We narrowly cast our petition because these are the kinds of projects that have always been net-metered without any issues around safety and reliability,” Smith said.
Briefly, net metering is a billing mechanism that credits solar energy system owners for the electricity they add to the grid.
For years, net-metering models, which use power purchase agreements, have appealed to universities, public schools, hospitals, churches, municipalities and small commercial ventures because they are low-risk. They lock in an affordable kilowatt-hour price of electricity, the installer covers upfront costs and maintains the arrays for their 25- to 30-year lifespan, and the recipients can achieve sustainability goals.
Those entities can least afford to finance, much less build and operate solar, Smith said, adding that school arrays are often incorporated into hands-on lessons about renewable energy for students.
He noted that no net metering projects in Dominion’s service area exceed 1 MW, even though the Clean Economy Act of 2020 bumped that cap up to 3 MW for the state’s two investor-owned utilities. In Appalachian Power territory, just one net metered project is bigger than 1 MW, at roughly 1.5 MW, according to state records.
Smith and the alliance were encouraged in late July when SCC hearing examiner Mary Beth Adams recommended that Dominion’s interconnection rules be suspended until the commission resolved the interconnection-related issues raised in two other separate cases.
Adams referred to a section of Virginia code focusing on interconnection, stating that Dominion is bound to provide power distribution service that is “just, reasonable, and not unduly discriminatory to suppliers of electric energy, including distributed generation.”
She also said that Dominion lacks the authority to require net-metering customers to execute a small generator interconnection agreement.
Decisions by hearing examiners are non-binding. However, within a month, commissioners concurred with Adams’ conclusions in a five-page order. The injunction prevents Dominion from forcing solar companies and their customers to comply with the interconnection parameters and small generator interconnection agreements.
They noted that the suspensions are effective until commissioners have investigated and completed rulemaking on two separate cases dealing with interconnection issues.
Commissioners also made it clear that they have “neither disregarded, nor taken lightly, Dominion’s claims regarding safety and reliability.”
“Dominion should continue to take the actions necessary to maintain the immediate safety and reliability of its system,” the commissioners wrote. “This may include, but need not be limited to, seeking specific authority from this Commission in one or more formal proceedings.”
Utility spokesperson Jeremy Slayton stuck to that two-word mantra when asked to comment on the commission’s injunction.
“Our filings and interconnection requirements are designed to ensure the same safety and reliability standard regardless of who builds the project,” Slayton said. “We believe this to be critical to maintaining a reliable energy grid.”
Alliance members maintain that neither safety nor reliability is being compromised with current commercial solar net metering. They claim the unnecessary parameters add at least 40% to project costs.
For instance, one rule required the use of an advanced form of cabling, also called dark fiber, which costs $150,000 to $250,000 per mile. Another piece of hardware, a distributed generation relay panel, runs $250,000.
In addition, solar companies said they would have to spend between $200,000 and $1.2 million per project on engineering and construction costs to be sure all the pieces were operating efficiently.
Smith and Robb are no strangers to tangles with Dominion. They bumped into similar interconnection issues two years ago when trying to site a 1.2-megawatt community solar project for low-income residents on 10 acres in Augusta County. Issues with that project still have not been resolved, Smith said.
He’s relieved the commission’s ruling puts the pair of Prince William school projects back on sound economic footing.
“The biggest unknown was not knowing how long all of this would take,” Smith said about the timeline of the Dominion challenge. “We had already put in a lot of money upfront with the engineering and ordering the panels.”
As it stands now, he’s relieved both installations will go online — but in 2024 rather than later this year.
The solar trailblazer is also reassured that the commission’s ruling will quash other utilities’ pursuit of add-on interconnection fees.
“Our fear was, if we lost, Appalachian Power and co-ops in Virginia would take a cue from Dominion and impose similar restrictions,” he said. “Dominion may have underestimated our willingness and capacity to take this to the mat with them”
Indeed. That relentlessness prompted the trailblazing solar developer to draw upon the sentiments of noted author and cultural anthropologist Margaret Mead.
“‘Never doubt that a small group of thoughtful committed individuals can change the world,’” Smith said, reciting Mead’s notable words from memory. “In fact, it’s the only thing that ever has.”
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