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Northern Indiana Public Service Co. is planning to build a 400-megawatt natural gas-fired power plant that critics say is unnecessary, out of step with clean energy goals, and happening outside the usual planning process.
In September, the utility asked the Indiana Utility Regulatory Commission for a needed certificate of public convenience and necessity to build the $643 million peaker plant on the site of the retiring R.M. Schahfer coal plant in Jasper County in central Indiana.
The utility, known as NIPSCO, says it needs the plant to provide power during times of high demand, since it will be phasing out coal by 2028 and transitioning to renewables.
“Energy from renewable resources does not follow the load,” David Walter, NIPSCO vice president for power delivery, testified before the commission. “In order to have generation available when the load is there but sufficient energy from renewable resources is not, it is critical to have sufficient fast-starting, quick-ramping dispatchable generation,” meaning the natural gas plant.
NIPSCO also says the plant could be converted to run on natural gas blended with hydrogen — a fuel being pushed by the U.S. Department of Energy, including with the recent funding of regional hydrogen hubs.
Groups with intervenor status — including Citizens Action Coalition and the Industrial Group of NIPSCO customers — are in the process of filing testimony about the proposed gas plant, due Dec. 12.
Just Transition Northwest Indiana legislative director Susan Thomas said the organization “is actively opposing this build-out of what will most likely be only an occasional-use facility that either prolongs the use of fossil fuels for another 50 years or will be rendered obsolete due to more stringent climate regulations in the future.”
Currently, NIPSCO’s generation mix is 43% coal, 26% natural gas, 17% solar and 15% wind. In its 2018 integrated resource plan, NIPSCO proposed to close all its coal plants by 2028, and keep running its existing Sugar Creek natural gas plant.
NIPSCO told the commission in recent testimony that by 2028, it expects to get 31% of its capacity from natural gas-fired power, 13% from wind and 55% from solar plus storage.
NIPSCO’s 2021 integrated resource plan called for 300 MW of natural gas. In its September filing, NIPSCO said that the proposal for a 400-megawatt gas plant is based on a recent analysis including “market shifts” since 2021, like rule changes in the MISO wholesale market and passage of the Inflation Reduction Act.
“They’re backsliding off their 2018 commitment,” is how Thomas sees it.
NIPSCO had originally planned to retire two units of the Schahfer coal plant in 2023, but had to extend to 2025 because of delays in getting planned solar online, it told the commission. Two more units at Schahfer are scheduled to close by 2028, and existing gas-fired peaking units at that site are scheduled to close in 2026. NIPSCO’s Michigan City coal plant is scheduled to close by 2026.
Citizens Action Coalition program director Ben Inskeep noted that NIPSCO has another integrated resource plan due next fall. He said that process would be the appropriate place to explore and explain the need for new gas peaker capacity, offering more chances for public scrutiny and input.
“We’ve had great dialogue with them in the [integrated resource planning] stakeholder process in the past; they’ve been receptive to feedback,” Inskeep said. “One of the sad parts about this proceeding is it’s a step backwards in the process with them; it kind of breaks trust when you have an understanding about how things will operate and you’ve been successful, and then they’ve gone outside the process to come up with a different answer.”
Walter told the commission that NIPSCO could not wait to launch the gas plant request during the 2024 integrated resource planning process, since that would delay plant construction “until late 2027 at the earliest,” while the company said it needs the capacity by 2026.
Advocates say that rather than constructing a natural gas plant to fill gaps in renewable generation, NIPSCO could buy power from the MISO wholesale market, while also reducing energy needs through demand response and energy efficiency programs.
Inskeep said the math behind the gas plant proposal is especially tricky given that it depends on both wholesale power prices in the future, and natural gas prices, for NIPSCO to supply its own plant. Natural gas prices have been particularly volatile over time, severely impacted by things like the fracking boom and the Ukraine-Russia war.
“They’re saying that additional capacity will give them the ability to basically buy less electricity from the MISO wholesale power market, an insurance mechanism so they’re not buying wholesale energy during the few hours of the year when the solar and wind they are building might not be operating,” Inskeep said. “Whether this resource meets the cost-benefit analysis is unclear to me. Is it really going to make the gas plant worth it, even if you don’t take into consideration the climate change and local pollution impacts?”
Opponents are also worried that NIPSCO is for the first time proposing to construct the plant itself, hiring individual contractors rather than hiring one firm to oversee the entire process.
“They’ve never built a plant on their own, but now they’re going to freelance this,” Thomas said. “Where will there be transparency in this process? The potential for cost overruns is rampant.”
Under Indiana law, a company can bill ratepayers for a “construction work in progress,” long before it is “used and useful,” the usual standard for recouping cost and a profit from ratepayers.
Kevin Blissmer, regulatory manager for NIPSCO’s parent company, testified to the commission that this arrangement actually saves ratepayers money, since they are paying costs upfront rather than later, including costs the company took on to finance its investment. Blissmer said billing ratepayers while construction is ongoing would mean a difference of $149 million in financing savings over the project’s life.
But the Citizens Action Coalition website describes the group’s concerns with construction work in progress, saying it “converts consumers into involuntary investors, placing the burden of up front financing costs onto them. The costs end up on their bills sooner, before they ever receive electricity from the plant in question, and there is little recourse should the costs skyrocket or the project be abandoned.”
In July, NIPSCO announced its first two Indiana solar farms are operating: a 265-megawatt solar farm in Jasper County, not far from the Schahfer coal plant, and a 200-megawatt array in White County. In April, NIPSCO signed a power purchase agreement with a 198-megawatt wind farm in Jasper County.
In its September filing, NIPSCO said the gas plant meets the state 21st Century Energy Policy Development Task Force’s recommended five pillars, helping to ensure reliability and resiliency, stability, affordability, and environmental sustainability.
But Inskeep called building the gas plant on the retiring coal plant site a “missed opportunity,” since it precludes the chance to put wind and solar on the site and utilize the existing grid interconnections, without having to go through the otherwise lengthy process to interconnect new solar and wind to MISO’s grid.
Clean energy advocates have also asked NIPSCO to focus on reducing peak demand rather than building more generation.
“Solutions are there and available,” Thomas said. “We’re not even giving those solutions a fair chance. They should have considered energy storage, demand response or purchase from the MISO market before they did this.”
Rhode Island’s top utility regulator says a statewide moratorium on new gas hookups is on the table as the state works to meet its ambitious climate goals.
“That doesn’t mean it happens tomorrow,” said Ronald Gerwatowski, chair of the Rhode Island Public Utilities Commission, during a proceeding Thursday. “But it surely begs us all to ask the question: If not tomorrow, then when?”
Gerwatowski’s comments came as the commission held its first technical conference in its investigation into the future of natural gas.
A wide-ranging discussion followed about the many challenges and conundrums facing the commission in the so-called “Future of Gas” docket. Regulators opened the investigation in response to the passage of the state Act on Climate, which includes a mandate to zero out greenhouse gas emissions by 2050.
Building emissions, including those that result from the use of natural gas, account for about 35% of the state’s total emissions. The commission regulates the gas distribution system, which is operated by Rhode Island Energy.
The purpose of the first proceeding was “to prepare the commission to make big and ambitious decisions,” said commissioner Abigail Anthony.
The breadth of the challenge ahead was laid out by Rhode Island Energy executives, who provided a factual representation of the state’s gas distribution system. The company has more than 273,000 residential, commercial and industrial gas customers served by some 3,200 miles of gas distribution main, said Michele Leone, vice president of gas.
Through the company’s ongoing pipeline replacement program, 60 to 65 miles of gas main are replaced every year, she said. About half of the mains have been replaced with less leak-prone pipes so far.
Whether or not to continue that program is a particularly vexing question for the commission, Gerwatowski said. Replacing leak-prone pipes is both a safety issue and an environmental issue, he said. Right now, those infrastructure investments are factored into the rate base and are depreciated over 40 years, a timeline that is now far too long.
“We could depreciate it more quickly, but that has an impact on rates. So what do we do here?” Gerwatowski said. “Do we stop the program on the assumption we’re going to close the system down,” allowing for some continued methane leaks?
Or, he said, do they allow the program to continue, and then likely face lawsuits over who should be responsible for the stranded costs once the assets are no longer in use?
Ben Butterworth, director of climate, energy and equity analysis at the Acadia Center, said in response that the commission must prioritize safety above all else first, but could perhaps investigate ways to repair pipes rather than replace them. That would reduce costs and the time period over which the utility is spreading those costs.
“That’s why it’s essential to determine a plan as soon as possible for the future vision of the gas system,” Butterworth said. “It might make sense to do it on a case-by-case basis.”
When it comes to transitioning from the use of natural gas, the state will need to find pathways “that ensure safety and reliability, equity, and affordability,” said Dan Aas, director at E3, an energy consulting firm representing Rhode Island Energy.
He recommended a “portfolio-based” approach that might include a combination of air-source heat pumps, hybrid electrification, renewable natural gas, and geothermal.
He noted that in California, Pacific Gas and Electric is experimenting with targeted electrification, in which they target for electrification a small cluster of customers on a segment of the distribution system that is costly to maintain.
But the prospect of converting hundreds of thousands of residential customers to air-source heat pumps poses another daunting question, Gerwatowski said.
“There’s a huge upfront funding cost — where does the funding come from?” he said.
The commission also heard from speakers representing consumer perspectives. Chelsea Siefert, director of planning and development for the Quonset Development Corp., a 3,200-acre business park in North Kingstown with more than 220 companies, urged regulators to consider the impacts of phasing out natural gas on industrial manufacturers.
For example, she said, burning natural gas generates the high temperatures Toray Plastics requires to convert plastic pellets into plastic film. Toray employs about 600 people at its Quonset facility.
And Jennifer Wood, executive director of the Center for Justice, which represents low-income utility consumers, called on the commission to prioritize any electrification efforts in the neighborhoods that have been impacted by fossil-fuel pollution for generations due to redlining and other discriminatory lending practices.
In the city of Providence, those old redlined areas now coincide with areas with the highest poverty rates and incidences of childhood asthma, she said.
“The remedies for meeting the goals of the Act on Climate should be targeted to the neighborhoods that have been the most adversely impacted along the way,” Wood said.
As the next step in the process, the commission will issue an invitation for interested parties to apply to join a stakeholder committee. The committee’s first meeting will likely be next month, said Todd Bianco, chief economic and policy analyst. The overall goal is to have a report with recommendations to the commission by next spring, he said.
This story was originally published by Mountain State Spotlight. Get stories like this delivered to your email inbox once a week; sign up for the free newsletter at https://mountainstatespotlight.org/newsletter.
WEST UNION — Nearly 20 years ago, Cindy Dotson bought more than 200 acres of farmland and forest in her native Doddridge County. The property is beautiful — but there’s one part Dotson doesn’t care for. At one end sits a massive, yellow tank painted with a bygone advertisement: an eye sore that renders the section of property mostly useless.
The ten-foot above-ground storage tank, accompanied by an underground oil or gas well and guarded by barbed wire and wooden stakes, is just one of the thousands of orphaned oil and gas wells littered across the state.
With no living mineral rights owner and no existing operator, the oil tank and well have sat untouched on Dotson’s property for the last 15 years. She’s concerned about its proximity to a creek, where cattle used to drink. And now, she leases the land to tenants who share those concerns.
“We would just like it to be plugged so that we can reclaim this property, and we never have to worry about anything leaking out of it,” Dotson said. At times, she says she sees a film she thought was oil leaking at the base of the tank but has never been able to confirm it.
But unless she shells out the cash herself, the well will remain a concern for Dotson until the state gets around to plugging it.
Both orphaned and abandoned wells no longer produce oil or gas. But abandoned wells still have a solvent owner, while orphaned wells don’t — either because the company went out of business or there is no existing record of the driller. So here, the responsibility of plugging and remediating these wells falls to the state. And it’s a massive undertaking that West Virginia regulators don’t have many resources to tackle.
Now, the state is getting some help: up to $212 million from the federal government to plug orphaned wells. But even then, for West Virginia, it’s only a drop in the bucket.
Thousands of orphaned wells are littered throughout West Virginia but are most heavily concentrated in Ritchie, Tyler and Doddridge counties. Some date back to the early 20th century, while others are more recent. Some are hazardous and leak large amounts of methane, while others don’t. But all are a result of operators abandoning them after bleeding them dry of their natural resources.
Under West Virginia law, oil and gas companies are responsible for plugging and remediating their wells, and a spokesman for the state Department of Environmental Protection says the agency often pursues enforcement measures. But despite that, wells across the state remain abandoned and unplugged.
Now, this new influx of federal cash from the 2021 Bipartisan Infrastructure Law will allocate $4.7 billion to states, tribes, and the Federal Bureau of Land Management in an effort to address some of the damage left by the oil and gas industry, according to the federal Department of the Interior.
The newly established federal program is a key part of the Biden administration’s efforts to curb the release of methane — a greenhouse gas that greatly contributes to global warming. The U.S. Environmental Protection Agency estimates that the unplugged, non-producing oil and gas wells emitted 275,000 metric tons of methane in 2020; equivalent to emissions of more than 1.7 million gasoline-powered vehicles driven in one year.
West Virginia’s DEP, along with 23 other states, received an initial $25 million grant from the federal program earlier this year, which is the first of three expected rounds of funding the Biden administration is set to award. With that, the state’s Office of Oil and Gas estimates it can plug 202 orphaned wells in West Virginia, which it has decided to outsource to contractors, despite criticism.
Beyond the initial grant, West Virginia is likely to receive a total of $117 million in formula grant funding and has an opportunity to receive an additional $70 million through the performance grant portion of the federal funding — resulting in an overall total of $212 million.
Historically, progress on remediating orphaned wells has been slow. The state used to only be able to afford to plug one or two wells a year. More recently, state lawmakers directed more money to the issue, which enabled the DEP to remediate six wells last fiscal year and 22 this fiscal year, according to spokesman Terry Fletcher.
But the $212 million boost in federal funding will speed up the pace. It could go as far as to help plug roughly 1,700 orphaned wells. However, this would still only be a fraction — about 26% — of the documented orphaned wells scattered across the state.
In reality, the need could be much larger because the exact number of wells isn’t known, largely due to the fact that wells drilled before 1929 were not required to be registered with the state. Because of that, there are tens of thousands of undocumented orphaned oil and gas wells scattered throughout the state, according to the West Virginia Geological and Economic Survey. And the state’s current estimates also don’t account for all the thousands of abandoned oil and gas wells that are likely to become orphaned in the future.
“This is just scratching the surface,” said Ted Boettner, a senior researcher at the Ohio River Valley Institute. “That’s just the orphaned wells. There’s another 12,000 abandoned wells and tens of thousands of undocumented orphaned wells in West Virginia.”
Among those undocumented orphaned wells is the one on Dotson’s property.
Dotson maintains the fencing around the giant above-ground storage tank that accompanies the well, fearful of a car hitting it and causing a leak — all she really can do at this point.
The monthly visits by a gathering company to empty the tank stopped years ago when there were no longer any remaining living mineral rights heirs and Dotson couldn’t get anyone else to pump the tank. She even briefly considered plugging the well herself, but the cost was too high to afford.
Now, her frustration is only further exacerbated by the slim chance that any portion of the millions in federal funding the state is getting will go towards the well on her land because of its undocumented status.
“So, again, we can do nothing. We’re stuck,” Dotson said. “So, what is the state doing for these undocumented orphaned wells? If there’s thousands of them, they need to do something about them also.”
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
The following commentary was written by Meredith Connolly and Shelley Wenzel. Connolly is the Oregon director for Climate Solutions, a Northwest-based clean energy policy nonprofit. Wenzel is an energy data analyst at Energy Innovation, a nonpartisan climate and energy policy think tank. See our commentary guidelines for more information.
No matter what happens with federal climate progress, state climate action is imperative to cut greenhouse gas (GHG) emissions and help achieve the United States’ commitment to the Paris Agreement. Outside the media spotlight, Oregon has adopted some of the nation’s most significant climate policies, recently finalizing rules to slash emissions from fossil gas and transportation, while targeting 100 percent clean electricity by 2040.
But new research shows the state won’t achieve its climate goals without coupling power sector progress with additional policies that get vehicles, buildings, and industry off fossil fuels. In short, the winning climate playbook for all leading states must be “clean the grid and electrify everything.”
In 2020, Governor Kate Brown enacted an Executive Order (EO) to set a statewide goal of cutting greenhouse gas pollution 45 percent by 2035 and 80 percent by 2050. The same EO led to increased transportation electrification, cleaner fuels, and a Climate Protection Program (CPP), which sets emissions caps for transportation fuels and fossil gas.
And last year, Oregon’s legislature passed the fastest 100% clean electricity target in the West, requiring the state’s largest utilities slash emissions from power generation 80 percent by 2030 and 100 percent by 2040.
Even with these successes, Energy Innovation modeling shows the state is off track for reaching its own goals: If all recently adopted policies are rigorously implemented, Oregon would still only cut emissions 60 percent by 2050.
But there’s good news. The modeling also finds that adopting additional policies – especially for transportation and buildings – would not only cut emissions by 75 percent, but would also boost statewide GDP by $4 billion, create 18,000 jobs, and prevent nearly 900 asthma attacks annually in 2050.
Examining statewide GHG sources illuminates why a broader set of policies in Oregon, along with a pathway for how they will be achieved, is needed. As with most of the U.S., transportation has surpassed the power sector as the largest greenhouse gas source, composing 35 percent of all emissions. Meanwhile, homes and buildings consuming power and gas make up the second largest source at 34 percent, followed by industry and agriculture at 10 percent each.
With Oregon’s population expected to hit almost 4.6 million by 2030, these emissions will trend upward unless policies to shift from fossil fuels to clean electrification start right away. Every new gasoline car or truck, every new gas furnace and new gas-heated building or home locks in emissions for decades. Without meaningful progress in these other sectors, the state won’t hit its 2050 climate goals.
The Oregon policy modeling used the Energy Policy Simulator, a tool created in collaboration with Power Oregon and the Green Energy Institute, to evaluate the state’s new 100% clean electricity by 2040 law and the Climate Protection Program, finding they get Oregon much closer but still fall short of the state’s 80 percent reduction by 2050 goal. The open source, peer-reviewed EPS estimates the emissions, jobs, and health impacts of climate and energy policies using federal and state data.
The Oregon EPS research modeled a set of broader climate policies for all sectors that would put the state on track to achieve its goals and align with the U.S. Nationally Determined Contribution (NDC) to the Paris Agreement (i.e., Oregon doing its proportional fair share). The findings show an “NDC Scenario” for Oregon would avoid $4.8 billion in climate and health costs in 2050 (on top of the $4 billion in GDP growth).
Oregon is in a perfect position to adopt additional policies that leverage its clean electricity sector to secure compounding emissions reductions across the economy through efficiency and electrification policies. And state policymakers must ensure the clean energy transition’s health and economic benefits are broadly shared and reach frontline communities hit the hardest by pollution and climate impacts.
First, Oregon should adopt a 100 percent all-electric new vehicles sales standard by 2035, paired with an EV subsidy lasting through 2030, to supercharge transportation electrification. These policies must be accompanied by EV charging investments to plug in rural areas, low-income communities, and trucking corridors.
Second, increased investments in public transportation, as well as safe walking and biking paths, would reduce emissions while improving equity and air quality. An expansion of the state’s Clean Fuels Program could further cut emissions as the state moves toward a zero-emission future. These transportation sector policies achieve nearly one quarter of all the reductions under the NDC Scenario, showing how vital they are to reaching Oregon’s climate goals.
Third, Oregon must phase out fossil fuels for indoor uses. Similar to Washington’s recently passed commercial and large multi-family building heat pump requirement, the NDC Scenario modeling finds the most important policy for cutting greenhouse gas emissions from buildings would be a building code or standard requiring all new buildings or building equipment to be electric by 2030. This policy alone achieves over 10 percent of all the NDC Scenario’s reductions. To be most impactful, this transition must be coupled with strong efficiency standards.
These policies also create other health and economic benefits. Transportation electrification, along with greater reliance on active transportation, cuts health-damaging particulate and NOx emissions. Electric vehicles are also cheaper to own and maintain than gas cars and protect drivers from volatile oil prices. Electric heat pumps for space or water heating are more efficient than their fossil gas burning counterparts, and electric or induction stovetops avoid harmful fumes from gas cooktops that experts say may cause childhood asthma symptoms.
Together, a broader set of policies like those included in the modeling would get Oregon within a couple percentage points of the state’s 2050 emissions reduction goal, while additional land use and climate-smart agricultural practices could make up the difference. Equitable policy design and planning that prioritizes access and affordability for low-income households and communities will ensure the benefits are enjoyed by all residents, not just the wealthy.
While transitioning the power grid to 100 percent clean electricity is a critical step, Oregon’s lesson is that state climate action can still fall short if that isn’t coupled with rapid electrification. Cutting power sector emissions alone will not solve climate change, but it can make a big difference and leverage clean electricity to secure urgently needed emissions reductions in the transportation, buildings and industrial sectors. If we equitably and rapidly electrify as we clean up our grid, more of our cars and homes will be emissions-free, hopefully in time to avoid climate catastrophe.
Years of work crafting climate and clean energy plans have left New England states in a prime position to take advantage of renewable energy incentives in the historic climate bill enacted by Congress over the summer, advocates say.
“We’ve worked really hard to create fertile ground for this type of thing — in five of the six states, you have climate laws already passed,” said Sean Mahoney, executive vice president of the Conservation Law Foundation. “The states have prepared for this day. And now the Inflation Reduction Act is going to provide them with the resources to execute on it.”
The Inflation Reduction Act, or IRA, will allocate an estimated $369 billion over 10 years for energy security and climate change measures, according to the Congressional Budget Office. (It also includes many other forms of aid, including $64 billion to extend the Affordable Care Act and $4 billion for drought relief efforts in 17 western states.)
The wide-ranging climate change measures include tax credits for renewable energy production and storage, loans and grants for energy transmission projects and transmission planning, grants and rebates to replace heavy-duty vehicles with zero-emission vehicles, and financial assistance for clean energy technology manufacturing.
There are also rebates for consumers who install heat pumps and other energy-saving retrofits in their homes. Tax credits are available for the purchase of new or used electric vehicles by income-qualified buyers.
Passage of the law has generated “a whole bunch of enthusiasm” among the members of NECEC, a clean energy trade organization, because they see the coming injection of federal resources and private investment that will attract as an economic buttress in the face of inflation and an “up and down economy,” said Jeremy McDiarmid, vice president for policy and government affairs.
The Northeastern states overall are well positioned to jump on these opportunities because of the policy groundwork that has already been laid, he said.
“Climate targets, energy efficiency goals and programs — all of this makes them competitive,” he said.
Every New England state except New Hampshire has adopted a climate law obligating them to greenhouse gas emissions reductions. Most must cut emissions in half by 2030, and by 100% as of 2050.
Rhode Island has also passed a law requiring 100% of its electricity to be offset by renewables by 2033.
The incentives in the IRA can enhance some of the state-level programs already in place, such as by stacking federal tax credits on top of existing credits for electric vehicles or energy efficiency work, said Charles Rothenberger, climate and energy attorney for Save the Sound, in Connecticut. That state’s CHEAPR program provides incentives ranging from $750 to $4,250 for plug-in hybrid and battery electric vehicles, with the highest incentives for income-qualified buyers.
Other funding streams could help get clean energy or emissions reduction programs off the ground that have previously failed to win approval because of cost concerns, he said.
Because the federal funding has a limited time span, “states can’t take their eyes off the ball,” Rothenberger said. “The goal is to try to get as much done as we can quickly. We can make some structural changes at the state level to make some long-term progress, and show proof of concept through the federal funds.”
Indeed, the IRA’s focus on creating green jobs and green infrastructure could be transformative in how people live and do business, said Amy Boyd, vice president for climate and clean energy policy at the Acadia Center, a clean energy advocacy group that works in Massachusetts, Connecticut, Rhode Island and Maine. And those changes will not be easy or necessary to undo over time, she said.
“As technology moves forward, it doesn’t move back,” she said. “No one’s going to take the insulation out of their house so they can be colder, have more asthma and pay higher bills.”
The act also provides money to the Environmental Protection Agency to help the agency meet the requirements of President Joe Biden’s Justice 40 initiative, which calls for 40% of certain federal investments to benefit disadvantaged communities, Mahoney said. That includes money for frontline communities to address prior wrongs, something the Conservation Law Foundation is particularly interested in, he said.
Billions of dollars are available to help states figure out how to transition to a transportation system that doesn’t rely on gas or diesel, he said.
“We work in a lot of rural areas — how do you make the transportation system work there?” he said. “And in more-dense areas, there are now dollars available to help fulfill the promise of public transit that hasn’t been met in the past.”
In Vermont, passage of the IRA is “galvanizing the need for change” among lawmakers, who seem eager to act, said Peter Sterling, executive director of Renewable Energy Vermont, a clean energy trade association. He said one state senator recently told him that climate change is one of the top three issues he hears about when he’s out campaigning.
The tax credits for renewable energy production make it an ideal time to increase the state’s renewable portfolio standard, something advocates have been pushing for several years, Sterling said.
“Passage of the IRA is the extra shot in the arm Vermont needed to move forward to a 100% renewable energy future,” he said. The IRA also includes money to help states remove the barriers to wide-scale adoption of renewable energy, such as interconnection and transmission bottlenecks. New England will be competitive in vying for those dollars, McDiarmid said, as Connecticut, Maine, Massachusetts, New Hampshire and Rhode Island are already partnering on an initiative exploring ways to improve the electric transmission system to best integrate offshore wind and other renewable resources.
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