Back
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.”
New Hampshire’s electric utilities have come out in favor of continuing the state’s current system for compensating customers who share surplus solar power on the grid.
Eversource, Unitil, and Liberty Utilities surprised clean energy advocates by submitting joint testimony to state regulators last month endorsing the state’s current net metering structure. The program credits customers roughly 75% of the standard electricity rate for any unused solar generation that flows back onto the grid and is used by other customers.
“I am delighted that our utility friends have come over to our way of seeing things,” said Sam Evans-Brown, executive director of Clean Energy New Hampshire.
The utilities’ testimony is part of New Hampshire’s current deliberations over whether the state’s net metering rules should be adjusted. The process in New Hampshire is playing out as many other states are also debating what role net metering should play in the transition to clean energy.
Net metering provides an important source of revenue for solar customers when their generation doesn’t perfectly match their electricity use, but critics contend that it unfairly shifts costs to consumers who don’t generate their own renewable energy.
“I think renewable energy is great,” said Rep. Michael Vose, chair of the state House’s Science, Technology and Energy Committee, who has supported bills that would have cut net metering rates. “If people can afford to buy it and want to buy it, they should go ahead, but I am not in favor of subsidizing renewable energy and shifting costs to people who don’t directly benefit from that renewable energy.”
New Hampshire’s current rules, put in place in response to 2016 legislation, replaced a previous system that gave participants credits equal to the price utilities charge customers for electricity. This same law also required the state to conduct studies on the impact and effectiveness of net metering and make changes to the regulations if the findings warranted.
Previously, the utilities had advocated for much lower rates for net metering customers. Nationally, utilities have often taken the same position as well, arguing that higher net metering rates push costs onto customers who can’t afford to buy solar panels.
At a glance, it’s easy to dismiss: if a homeowner sends 1 kilowatt-hour of power to the grid and receives a credit worth the price of 1 kilowatt-hour, it would seem everything should come out even. But the retail price of electricity includes more than just the cost of the power itself — everything from the salaries for lineworkers who do maintenance to the cost of debt on construction projects to keep the wires and poles safe and reliable.
“The whole system is packaged up and rolled into the price,” Evans-Brown said.
So when a homeowner receives a full retail credit for their power, they are getting paid for more than just the energy they are providing, increasing the cost to run the utility. These costs are then passed on to the utility’s entire consumer base. A lower net metering credit means less of this sort of cost shifting and, some argue, a fairer deal for customers without solar.
The gap between net metering rates and utility costs can be even more pronounced at certain times of day. In the early afternoon on a sunny summer day, demand on the grid is low, meaning the price for power from the grid drops as well. At the same time, solar panels are producing plenty of excess energy. Utilities can end up paying higher rates for this electricity than they would have had they been buying from a power plant, at a time when excess residential solar energy wasn’t even needed to help meet high demand.
“Solar does not make the grid more reliable or resilient, nor does it improve power quality in any way,” Thomas Meissner, chief operating officer of Unitil, testified in 2016.
Supporters of a strong net metering rate, however, argue that net metering creates an array of benefits for utilities that solar generators should be compensated for. The report produced in accordance with the 2016 law notes that solar can reduce capacity payments the utilities must make, reduce the cost of complying with renewable energy standards, and lower the amount of power lost traveling through transmission lines, among other benefits.
Utilities, however, have generally downplayed these benefits. However, in their joint testimony, the utilities go so far as to praise the economics of the system.
“New Hampshire’s net metering policy — which is among the most balanced in New England — has been effective in encouraging the growth of [solar] resources in our state, and there is no evidence that the current compensation level is creating unjust cost shifts,” said Eversource spokesperson William Hinkle, after the testimony was filed.
The state report presents similar findings. It concludes that distributed solar generation should provide increasing value to the grid over the next 12 years. It also found evidence that limited cost shifting would occur, increasing the average residential bill in the range of 1% to 1.5%.
Supporters of net metering say this number is so small that it is an acceptable price to pay for the benefits of increased renewable energy. Vose, however, is concerned about any increased costs for consumers who have not chosen to install solar panels.
“That is one of the problems we’ve tried to ameliorate, to minimize such cost shifting whenever possible,” he said.
Nationally, net metering remains contentious in many states. For example, North Carolina’s public utility authorities have angered environmental groups and many in the solar industry by approving a utility plan to reduce payments to net metering customers. And earlier this year, California cut rates by about 75% for new net metering customers, with utilities pushing for even more cost-cutting concessions.
“They’re hugely disincentivizing rooftop and community solar,” said Patrick Murphy, senior scientist at PSE Healthy Energy, who researches clean energy transitions and energy equity.
Overall, the more a state lowers its net metering credits below the retail price, the more likely utilities are to embrace — or at least accept — the program, Murphy said. In New Hampshire, the reduction from full retail price to 75% has been enough to satisfy utilities.
The New Hampshire net metering docket remains open and the matter is under consideration by the Public Utilities Commission. Vose thinks it very possible that net metering rates will be further lowered. Evans-Brown, however, thinks the utilities’ recent testimony could have a significant influence toward keeping the current system in place.
“This makes it more likely that we will get a favorable outcome,” he said.
Thermo King, headquartered in the Minneapolis suburb of Bloomington, has for decades manufactured diesel-powered refrigeration and heating units for use in semi-trailers, trains, ships and buses. The company’s logo can be seen on ubiquitous “reefer” trailers being pulled along highways across the country.
As Thermo King has begun a massive transition to electrify its product lines, training employees has been a challenge — and a common one facing other companies moving toward electrification.
Last year, the company contacted the University of Minnesota’s Technological Leadership Institute to co-create and pilot a 12-credit engineering electrification graduate certificate. They believe the program offers the nation’s first graduate-level certificate specifically for electrification.
The collaboration led the state to fund the Minnesota Center for Electrification Opportunity, an initiative announced in July that will train workers in companies moving toward electrification and hybrid systems.
Jodie Greising, director of the Minnesota Job Skills Partnership at the Department of Employment and Economic Development, said that “to ensure Minnesota businesses remain competitive and to help workers retain jobs, it’s imperative that training is available to upskill and reskill workers in occupations such as technicians, electricians, and engineers to help integrate, troubleshoot, and design the systems that leverage these evolving technologies.”
Grant Ovsak, Electrification Center of Excellence leader for Thermo King Americas, helped develop the certificate.
“We’re moving towards a sustainable power source from diesel, which is the same transition as the automotive industry,” he said. “We have a large employee base that needs to be brought along for that journey.”
A division of Trane, Thermo King has more than 200 engineers at its Twin Cities campus who could benefit from the certificate. But Ovsak said he wants employees in many disciplines to take the courses.
“The certificate is not just for engineers,” he said. “We want human resource [managers] to take the courses because we’re hiring in that area, and they need to be able to talk the lingo. Even quality, aftermarket and project management employees can take the courses.”
As companies move toward electrification, all their employees must learn a new technical language that will take time and practice, Ovsak said. The courses will allow students to test batteries in a lab and see the problems, such as thermal runaway, that electrical systems potentially face, Ovsak said.
John Hurst, senior director of the landscape appliance company Toro’s Center for Technology, Research & Innovation, said around 20% to 25% of the company’s sales involve electric products, some of which have been on the market for years. Employees’ training on electrification has been primarily offered in-house or on the job.
In the past, Toro, also headquartered in Bloomington, has worked with higher education providers on training programs that proved hard to sustain, he said. Hurst said that having the university deliver the classes and offer credits should appeal to Toro employees and other companies. The ability to count the courses toward a graduate degree should also attract more ambitious employees.
“What excites me about this is it’s a pathway we can use to continually send people through year after year as we hire or retrain staff,” he said, adding that Toro plans to encourage rather than mandate the training.
Keith Dennis, president of the Beneficial Electrification League, said the confluence of federal, state and industry investments in electrification “merit more deliberate training opportunities. We are seeing some of this around the country, but it is mostly from an increased awareness of sustainability officers and from companies who sell the products themselves.”
The Minnesota Center for Electrification Opportunity is working on a long-term vision to quicken the pace of electrification, a strategy it believes will create employment growth in Minnesota and position its workforce for jobs in a variety of fields, from utilities to renewable energy companies.
The state has few options for retraining employees in companies moving to electrification. Like many states, Minnesota has created clean energy training programs at state schools for students seeking jobs in the solar, wind energy and biofuel industries.
Non-degree and certificate programs exist for electricians and people in construction through unions and clean energy training centers. Electrification courses designed for employees, however, are challenging to find.
The Center for Technological Leadership resides in the university’s College of Science and Engineering. Travis Thul, senior fellow and operations director at the Technological Leadership Institute, said the center’s role has been to work with industry to develop continuing education seminars, short courses, master’s degree programs and other training opportunities.
The electrification certificate will serve as the foundation of an eventual master’s degree, Thul said.
For now, he worries about attracting students to the program in a tight labor market where many employees are comfortable in their jobs and have little incentive to give up their nights to attend classes.
“We’re facing an unbelievable demand from the industry standpoint,” he said. “We need this talent for the United States’ economic competitiveness to be assured, while simultaneously we’re limited on human capital motivated and inspired to come and pursue these topics.”
The certificate courses will be taught by professors of practice who work at the United States Army Corps of Engineers, Toro and Polaris. A full-time tenure track professor at the university assisted in developing the coursework to reflect academic standards, Thul said.
One of those professors of practice is Toro electrical engineer Robb Anderson, who delivered the first introduction to electrification course to around 20 people, including managers, engineers and service departments who worked at Thermo King.
One challenge is keeping up with the fast-evolving field, Anderson said. Another is motivating people with full-time jobs to finish their classwork. By late August, the first cohort had a few procrastinators still filing the final papers, though Anderson felt confident they would make the deadline.
Anderson said the classes feature field trips to different companies at various stages of electrification. Classes visited a University of Minnesota wind turbine research facility, a Wabtec Corporation electric train operation in St. Paul, and Toro’s headquarters.
“Students hear about the challenges companies face, which makes the courses very real,” he said.
Hurst, a 23-year veteran of Toro, believes the certificate helps employees stay up to speed in an industry facing a monumental transformation. “I think for us, it’s an exciting journey,” he said. “I tell people walking in the door that it’s the best time to come right now because we have so much change.”
The Minnesota Center for Electrification Opportunity holds an “Electroposium” Oct. 9 at the university’s McNamara Alumni Center. The event offers training and information sessions on the future of electrification.
This article originally appeared in the Idaho Capital Sun.
Todd Fischer, an electrical engineer, has lived in his North End home since 1988. Built in 1905, the Victorian-style home is a juxtaposition between Boise’s historical architecture and modern energy technology.
On the inside, the home is aligned with wooden columns and a wooden staircase, but on the outside sit 16 solar panels on the south side of his rooftop that generate electricity for his home.
In an interview, Fischer said he installed his solar panels in 2016 and receives monthly credits for providing additional energy to Idaho Power’s grid. In the winter he pays $5.24, and in the summer months he pays $0.24.
“My power bills are beautiful,” he said, while holding a stack of power bills he has collected since installing the panels.
Fischer’s solar panels are a part of Idaho Power’s “legacy” system, meaning he qualifies for the company’s original credit system for homeowners providing extra energy to the grid. Fischer does not get paid for over generation, but instead he accumulates credits from Idaho Power that compensate for the cost of his energy usage from the grid at another time.
But soon, homeowners who are a part of the “non-legacy” system, meaning they installed solar panels after December 2019, could face changes in the amount of money Idaho Power credits to their account.
Idaho Power is awaiting a decision from the Idaho Public Utilities Commission on a proposal to decrease the amount it credits customers who sell their rooftop solar back to the grid. Fischer, who is compensated under the “legacy” system, would not be affected by the changes if approved by the utilities commission.
But along with local environmental advocates, Fischer argues that Idaho Power’s proposal disincentivizes home owners from installing solar panels.
On Aug. 5, the Idaho Climate Justice League, a youth environmental advocacy group, held a rally outside of the Idaho Power building in downtown Boise addressing concerns about the company’s proposal to reduce its credit rates for solar.
In a letter to Idaho Power CEO Lisa Grow, the youth advocates said the proposal is contradictory to the company’s 100% clean energy goal by 2045.
“We, the youth, demand change,” the justice league letter said. “We are the ones who will face the future consequences of your inaction. As the climate crisis intensifies, and as the date on your commitment to 100% clean energy draws closer, we will not stand idly by.”
But Idaho Power negates the justice league’s claims. In a response letter to the justice league, the company said it is committed to reliability and affordability for all of its customers.
“We support solar and we’re seeking to pay a fair market price for it, whether that’s from a large solar array or a customer’s rooftop,” the Idaho Power letter said. “We are proud to have some of the lowest energy costs in the nation, but we can only maintain that by making sure we’re looking out for the interests of all customers while we invest in our clean energy future.”
Jordan Rodriguez, the spokesperson for Idaho Power, told the Sun that residential solar power brings many benefits to the company, but that its current credit system, established 20 years ago, is outdated.
Rodriguez said Idaho Power supports customer choice, and it acknowledges that residential solar saves the company money on expenses that it would take to generate and distribute that same energy using other sources.
However, the proposal to change its credit system is meant to be more equitable to customers without solar, Rodriguez said – noting that the number of customers with solar generation in the company grid has grown significantly in recent years.
The number of Idaho Power customers with residential solar power has increased from nearly 1,000 in the Idaho Power system in 2016 to more than 13,000 in 2022, according to a company report.
Rodriguez said the rise in Idaho homeowners with solar panels is largely driven by the decrease in costs associated with installing solar.
Solar installation costs have declined by more than 50% over the past decade, so in addition to a decrease in installation costs, the desire to run on clean energy or save money on electric bills is driving solar adoption across the country, according to an article from the Solar Energy Industries Association.
“An average-sized residential system has dropped from a pre-incentive price of $40,000 in 2010 to roughly $25,000 today (2022),” the article said.
“We are looking to change the way we credit customers for energy they generate because the current credit structure is unfair to the 98% of our customers without solar panels,” Rodriguez said. “Customers without rooftop solar currently pay an unfair share of grid maintenance and improvement costs.”
The change would more accurately reflect an on-site generator’s use of the electrical grid, he said.
If approved by the utilities commission, the changes would include:
Idaho Power requested an effective date of Jan. 1, 2024, but the case is ongoing and the timing of the order is at the discretion of the Idaho Public Utilities Commission.
Rodriguez said the outcome of the utilities commission case will not impact the company’s 100% clean energy by 2045 goals, adding that the company has several large-scale solar projects under construction.
“We support solar energy — our proposal is intended to ensure our customers don’t pay more for solar energy from one source than they would from another,” he said. “Looking into the future, Idaho Power expects solar energy will continue to be an important part of our energy mix and clean energy goal.”
In late 2022, Idaho Power began purchasing energy from the Jackpot Solar Project at some of “the lowest prices for solar energy in the nation,” Rodriguez said. The project brings up to 120 megawatts to Idaho, providing energy to roughly 24,000 homes, the Idaho Capital Sun previously reported.
Rodriguez said the company is also working on pairing the solar projects with batteries. The batteries would help store power generated during periods of lower use and deliver the power during peak energy consumption times, which he said are typically during hot summer evenings when the sun has set but energy use remains high.
Rodriguez said misinformation about residential solar plays a role into public discontent with the company’s credit rate proposal.
“Customers are encouraged to get the facts about solar energy before making a financial commitment,” he said. “Any Idaho Power visits to customers’ homes will be preceded by a phone call or other communication. Idaho Power employees will arrive in a company vehicle clearly marked with Idaho Power’s logo.”
Idaho Power is hoping to dispel misinformation and scams related to residential solar power on its website.
Common tactics being reported include solar sales representatives:
While Fischer believes a new credit system at Idaho Power would disincentivize homeowners from installing solar panels, he said his decision to install solar panels was “definitely not a financial” decision—adding that installing them cost him about $17,700.
Additionally, the amount of time it will take to get a return on the investment is so long, assuming that he will be living in the same home until then, he said.
Fischer said he acknowledges that Idaho homeowners already enjoy a low electricity rate because of the state’s rich hydroelectricity production.
As such, he said investing in solar panels is not as “financially viable” as it would be in a state like California, which ties with Maine as the state where electricity prices are increasing the fastest in the country. Both states have seen a rise in electricity prices by 78% in the last decade, according to the Sunpower Solar Energy Report.
So what motivated Fischer to install solar panels? The decision was based on curiosity, he said.
As an electrical engineer, Fischer said he was “intrigued by solar power,” and wanted to get firsthand experience with it. He said his biggest concern when deciding to install solar panels was finding a reputable installer.
After installing the solar panels, he said there were other costs outside of the installation that he did not initially take into account such cutting down trees, replacing his roof and fixing water damage in his home after the solar panels were incorrectly installed.
“My advice would be to talk to your friends that have solar, find out if they were happy with the quality of work that installer did,” he said. “They can fall off your roof in a windstorm, and they can cause a leak in your roof.”
Despite the lessons he learned along the way, Fischer said he has no regrets after installing his solar panels.
“There’s a lot better investments you could do than solar panels,” he said. “If you wanted to spend that much money to have a lower carbon footprint, I suspect there are better options than solar panels.”
A share of $9.7 billion in funding under the Inflation Reduction Act can help Ohio’s rural electric cooperatives save money while cutting greenhouse gas emissions.
Buckeye Power, which provides generation and transmission services for the group’s 25 rural electric cooperative members, “has more exposure to coal” than any comparable group in the United States, said Neil Waggoner, federal deputy director for energy campaigns for the Sierra Club, so the IRA funding is an especially huge opportunity.
The U.S. Department of Agriculture’s New Empowering Rural America program is accepting notices of intent to apply for up to $970 million in funding for projects to cut greenhouse gas emissions and add renewable energy. Funding can include grants of up to 25% of project costs, as well as low- or no-interest loans.
The notices are due by Sept. 15. Full applications would follow later in the fall.
“We are aware of and actively working on a proposal for the USDA New ERA program but do not have anything to report publicly until the application is complete,” said Caryn Whitney, director of communications for Ohio’s Electric Cooperatives, referring to both the cooperative organization and Buckeye Power. The New ERA program is part of the IRA.
Environmental groups’ analyses suggest the member cooperatives’ 380,000 residential and business customers could see big savings if Buckeye Power replaces some or all of its coal-fired generation with renewables and storage.
Most of Buckeye Power’s current generation mix comes from the 1.8-gigawatt coal-fired Cardinal Power Plant in Brilliant, Ohio. Units 1 and 2 at the Cardinal plant are 56 years old, and Unit 3 is 46 years old. Buckeye Power also has an 18% share in the Ohio Valley Electric Corporation, which owns the two 1950s-era coal plants involved in the state’s ongoing House Bill 6 corruption scandal.
The marginal costs to run almost all existing coal plants in the United States already exceed the levelized all-in costs of new solar or wind generation, Energy Innovation Policy & Technology reported earlier this year.
Also, a report released in August by the Evergreen Collaborative estimated the Cardinal Plant’s costs going forward will be roughly $31.16 per megawatt-hour. Regional wind generation is 18.6% less costly than coal, and local solar is about 11% cheaper, the report said.
In addition to New ERA grants, Buckeye Power could “stack” money from other funding opportunities and tax incentives to further cut costs for switching to clean energy, said Mattea Mrkusic, energy transition policy lead at Evergreen Collaborative. The IRA provides larger credits if projects meet criteria for prevailing wages and domestic materials, for example.
Much of the territory served by members of Ohio’s Electric Cooperatives falls within areas designated under the IRA as “energy communities,” Mrkusic also noted. Those are areas that have had coal closures or disproportionately relied on coal, oil or natural gas. The designation qualifies clean energy projects for even larger tax credits.
“Rural co-ops should really take this money on the table to make power more affordable for lower-income communities,” Mrkusic said. “This is an equity issue.”
A July 2023 analysis prepared for the Sierra Club’s Beyond Coal program reached similar conclusions.
Heavy reliance on an aging coal fleet already means many rural cooperative customers pay more than those of investor-owned utilities, the analysis said. The report used 2020 data from the Energy Information Administration for an example in which residential customers of a co-op in southwestern Ohio paid roughly twice the per kilowatt-hour rate that AES Ohio’s residential customers paid in neighboring areas.
Overall, the Sierra Club report estimated Buckeye Power could save 4% on wholesale power costs by 2032 by switching all its current coal generation, including both the Cardinal and OVEC plants, to a mix of 2,370 MW of solar generation, 1,080 MW of wind power, 1,700 MW of battery storage and just 5 MW of combustion turbines.
Funding under the New ERA program, tax credits and other federal funding opportunities could offset up to 73% of the plan’s estimated costs of $5.66 billion, the analysis said.
A more scaled-back plan to replace just Cardinal Unit 2 would cost about $1.56 billion, the Sierra Club analysis said. Up to four-fifths of that amount could be recouped through federal funding and incentives, the report added. The plan would replace Unit 2 with 300 MW of wind energy, 650 MW of solar generation and 470 MW of battery storage.
Applying for the New ERA funds is a necessary step for getting money, but getting funding won’t be automatic. Buckeye Power should expect competition from other rural electric cooperatives seeking a piece of the New ERA funding pie, the Sierra Club’s Waggoner said.
“The folks at Buckeye need to be thinking proactively,” Waggoner said. “They need to be thinking about what they can do to best show the largest amount of emissions reductions, considering how heavy they are in terms of carbon with their coal exposure.”
Replacing the older coal generation would make a big dent in Ohio’s greenhouse gas emissions, which drive human-caused climate change. Ohio ranks fifth among U.S. states for carbon dioxide emissions, the Energy Information Administration reports.
The Cardinal plant’s three units emitted more than 11 million tons of carbon dioxide in 2022, an increase of more than 365,000 tons compared to the year before, according to data from the U.S. Environmental Protection Agency.
The U.S. EPA’s data set also shows OVEC’s Kyger Creek plant emitted roughly 6 million tons of carbon dioxide last year, and its Clifty Creek plant in Indiana released about 6.5 million tons of carbon dioxide. Collectively, the emissions of those plants are comparable to roughly 5 million passenger cars.
For now, Buckeye Power’s plans appear to call for shutting down roughly one-third of the Cardinal plant’s total generating capacity within the next five years.
American Electric Power sold its ownership interest in Unit 1 to Buckeye Power in August 2022. The website for Cardinal Operating Company, which runs the Cardinal Plant for Buckeye Power, said the purchase “paves the way for Buckeye Power to shut down Unit 3 by the end of 2028.”
New federal rules proposed in May call for additional big cuts in greenhouse gas emissions by 2038, primarily by adding carbon capture and storage.
The Edison Electric Institute and multiple utilities have objected to the rules, claiming carbon capture technology is not commercially proven and power shortages could result if plants must shut down within the rules’ proposed timeline. Buckeye Power likewise opposes the proposed rules.
“It is unknown at this time how much, if any, funding Buckeye Power would receive from the funding opportunities,” said Pat O’Loughlin, president and CEO for Ohio’s Electric Cooperatives and Buckeye Power. “We do know that replacing the energy from existing resources that the proposed rule would likely force to retire prematurely would have costs much greater than the maximum available from these programs.”
For now, work on a proposal under the New ERA program is underway, said Ben Wilson, director of power delivery engineering for Buckeye Power. Buckeye Power also submitted an application under the Bipartisan Infrastructure Law’s $10.5 billion GRIP program. GRIP stands for Grid Resilience and Innovation Partnerships and aims to boost electric grid flexibility and resilience in the face of climate change.
“Under both applications [for GRIP and New ERA], without sharing too much detail, we are aiming to position Buckeye Power to have a reliable, cost-effective power supply that we can confidently count on for many years to come,” Wilson said.
The following commentary was written by David Wooley, director of the Goldman School of Public Policy at the University of California-Berkeley. See our commentary guidelines for more information.
The Gulf Coast’s power grid and economy share a common need: diversity. Diverse electric generation supplies increase power system reliability and resilience in the face of rising demand and extreme weather. Diverse economic activity supports employment, expands the tax base and boost overall prosperity. Offshore wind could help achieve both goals for the Gulf Coast region — if state governments act.
Offshore wind is surging, with over 700 gigawatts in the global development pipeline. European nations plan to install at least 120 gigawatts of offshore wind by 2030 and 300 gigawatts by 2050. China added nearly 20 gigawatts of offshore wind in the last two years alone.
Those rising tides are also lifting American boats. On Aug. 29, the U.S. Bureau of Ocean Energy Management (BOEM) will hold an offshore wind energy lease sale for three areas on the Outer Continental Shelf in the Gulf of Mexico. In July, the nation’s first large-scale offshore wind plant began construction off the northeast coast. Twenty-nine U.S. ports are being refurbished to support offshore wind turbine construction and maintenance. Factories are going up across the U.S. to produce offshore wind energy components.
A new report — 2035 and Beyond: Abundant, Affordable Offshore Wind Can Accelerate Our Clean Electricity Future — shows our coastlines have the world’s highest-quality offshore wind resource. The new report details a pathway for offshore wind to provide up to 25% of total U.S. electricity generation by 2050, while producing large economic benefits and without increasing electricity costs. It could help meet rising electricity demand from electrification of transportation, industry, and buildings — which will triple U.S. electricity demand by 2050.
The U.S. is currently targeting 30 gigawatts of installed offshore wind generation by 2030. Our new research shows that offshore wind technology can be 10 to 15 times larger than that by 2050. Offshore wind along the Eastern seaboard, Gulf of Mexico, Great Lakes, and Pacific Coast can supply more than 1,000 gigawatts of generating capacity with operational characteristics comparable and complementary to existing power plant production (i.e., more than 50% capacity factor). This would create hundreds of thousands of new jobs nationwide and attract billions in investment to revitalize port and manufacturing communities.
The Gulf of Mexico is particularly well-suited for offshore wind deployment. The region could host more than 100 gigawatts of new offshore wind by 2050. With its existing manufacturing, port, and logistics infrastructure, and skilled workforce, the region could become a hub for new offshore wind generation. Many of the requisite offshore wind labor skills, ships, and port facilities can be adapted from existing Gulf offshore oil and gas industries. The Gulf of Mexico hosts most of the U.S. shipyards able to build wind turbine installation vessels. The region is already producing ships, turbine foundations, and steel components for offshore wind farms on the east coast.
New research by Cambridge Econometrics finds that offshore wind could employ 20,000 workers in the Gulf region by 2040 and 60,000 in 2050. Billions of grant and tax-credit dollars are available to repurpose existing infrastructure for jobs and clean energy production. The areas appropriate for offshore wind development in the Gulf are so vast that large amounts of offshore wind generation can be developed without interfering with fisheries, existing offshore infrastructure and sensitive marine ecosystems.
But offshore wind has far wider benefits than just jobs. Wind energy produced offshore can add large amounts of new electric power generation to bolster electric grid reliability — particularly important given Texas’ recent blackouts and near misses. Offshore wind in Gulf waters tends to kick up when solar production drops at sundown, and offshore wind turbines are less affected by extreme cold and heat events than land-based renewable and gas generation.
Several policy changes can achieve this potential. In the near term, the federal government must accelerate the identification and assessment of offshore wind sites, and leasing and permitting in federal waters. But state leadership is also needed to tap the Gulf Coast’s offshore wind potential.
Louisiana has shown its neighbors how to get started. Its 2022 Climate Action plan set a target of 5 gigawatts of installed offshore wind capacity by 2035, prioritized planning for transmission and workforce needs, established an interagency working group to address permitting, and enacted legislation to secure state tax revenues from offshore wind developed in state waters. Ports there have responded to the policy signals by making changes to accommodate offshore wind development and ships are being built in the state’s shipyards. Plans are in place to establish an offshore wind technology research, training, and technology demonstration center, but even all this isn’t enough to establish the state as an offshore wind hub.
A recent roundtable event organized by C2ES recommended, among other things, that the state take three steps. First, map out the unique roles each of Louisiana’s ports could play in the offshore wind industry. Second, open public utility commission dockets to consider how to interconnect and provide transmission support for new offshore wind projects. Third, undertake initiatives to prepare its workforce for offshore wind development.
Meanwhile, Texas stands in stark contrast, turning a blind eye to offshore wind energy, despite being desperately short of electricity during extreme winter and summer weather. The ultimate result may be that Louisiana’s ports and industries become the region’s offshore wind port and manufacturing hub for project development in waters off the Texas coast.
Texas’ policymakers could take a better approach by actively coordinating infrastructure and supply chain development with Louisiana, and pushing together for federal dollars to de-risk port and vessel construction through revenue guarantees for port and ship owners.
Punishing heat waves gripped the Gulf this summer, straining the electric grid to its limits. It’s a harbinger of things to come. Offshore wind can supply large new power supplies and help make electric power systems more reliable. The Gulf Coast states could be global leaders in this new industry, building a stronger economy and more resilient grid along the way.
.svg)
