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As the growth of Xcel Energy’s demand response programs in Minnesota lags a state target, some stakeholders say it’s time to expand the use of third-party companies to enroll customers.
Demand response refers to a broad range of voluntary programs in which utility customers agree to reduce energy use during periods of peak demand. The best-known programs involve smart thermostats or other technology that remotely switch off customers’ air conditioners in short increments when the electric grid is under stress.
The programs are expected to play a bigger role as the country transitions to more variable, renewable generation such as wind and solar power. Having the ability to shift customers’ energy use into hours when those sources are providing lots of clean and inexpensive electricity could help lower costs, reduce fossil fuels use, and improve reliability.
In Minnesota, Xcel Energy operates one of the country’s largest demand response programs. A 2019 analysis by the Brattle Group ranked its portfolio eighth in the country as a percentage of peak demand. More than half of that capacity comes from its “interruptible tariff” program, in which commercial and industrial customers are offered bill savings in return for committing to curtail electricity use if called upon by the utility. The next largest source is its residential air conditioning Saver’s Switch program, which has enrolled more than 60% of homeowners with air conditioning.
As of 2017, the company had 850 megawatts of demand response capability in its Minnesota territory, about 10% of its system peak demand. That year, Xcel and state utility regulators agreed to a target of growing demand response enrollment by 50% over six years — an increase of 425 megawatts by 2023.
Earlier this year, Xcel reported slow progress toward that target, saying it had added just 117 megawatts in the previous half-decade. The company said the COVID-19 pandemic made it harder to recruit new participants and caused some of those in Xcel’s programs to go out of business.
The company also expressed confidence that program growth would be robust in 2023 and that it would achieve the target. The company continues to install smart meters, allowing more market demand response programs such as time-of-use rates that encourage customers to shift energy consumption. Other demand response programs involve customer-owned batteries, electric vehicles, building control systems and grid-connected appliances.
“We are very close to meeting the target this year, incentivizing growth through creative marketing, sign-on bonuses and a variety of new demand response offerings that give our customers choices to best fit their needs,” Xcel said.
Meanwhile, some clean energy and industry groups say Xcel’s apparent struggles to meet the demand response target shows there is a need for competition in the space.
In August, the Minnesota Public Utilities Commission heard debate over whether to allow the use of demand response aggregators — third-party companies that sign up customers for programs and then sell the capacity into wholesale markets. Xcel and other utilities argued against permitting retail aggregators because of unease over how they would impact the grid.
The commission voted 3-2 to table the topic.
Commissioner Joseph Sullivan said utilities will need more resources than just solar, wind and battery storage to maintain a resilient grid as fossil fuel plants close. Demand response is a flexible resource that can be an alternative to a gas power plant, he said. Sullivan said he has been surprised by how little Xcel uses demand response. Xcel tested but did not use demand response once last summer, he said.
“I think there is a tremendous opportunity for Xcel to be doing more,” Sullivan said.
Xcel has told the commission that exercising demand response programs too often increases the risk of participants dropping out.
Frank Lacey, a founder and former chair of Advanced Energy Management Alliance, which represents demand response companies, said Xcel and other utilities don’t embrace demand response because building new generation is more profitable, offering a guaranteed rate of return. “Utilities have an inherent conflict in growing demand response,” Lacey said.
But the programs save consumers money, with programs sometimes paying six times their cost. They offer a way for utilities to balance loads when solar and wind production fluctuate and fossil fuel plants no longer exist to fill in the gaps. Lacey said he hopes Minnesota looks again at the aggregator issue.
“What’s the expression about shutting the barn door after the horse escapes?” he said. “If you wait until you need it, you won’t recognize you need it until you need it, and it’s too late at that point.”
Wisconsin has ambitious climate plans, but the Republican-controlled legislature has refused to pass funding to carry them out.
That’s why Wisconsin city and state leaders are especially glad for a nearly $5 billion federal initiative meant to help states and municipalities advance climate action plans.
The Climate Pollution Reduction Grant program, created by the Inflation Reduction Act, has already provided a $3 million planning grant to Wisconsin’s Office of Sustainability and Clean Energy, as well as smaller grants to the Southeastern Wisconsin Regional Planning Commission and four tribal governments within the state’s borders.
“This is a really awesome kickstart to emissions reductions in the state,” said Maria Redmond, director of the Wisconsin Office of Sustainability and Clean Energy.
“The challenge in Wisconsin is we haven’t been able to get a lot of resources [for climate programs] because the legislature hasn’t allocated them. The last three budget cycles, the governor proposed significant funding for climate action, including for this office. None of that has been approved. Through this grant, we can get a lot more done.”
The program this year awarded $250 million in non-competitive grants to states, tribes and major metropolitan areas for climate action planning. The entities that received the planning grants can then apply for implementation grants totaling $4.3 billion to carry out their climate action plans.
The implementation grant application deadline is April 1, 2024. In a guidance document released in September, the U.S. Environmental Protection Agency said it anticipates awarding 30 to 115 such grants ranging between $2 million and $500 million.
Redmond said the state has “already been doing a lot of work on decarbonization,” including in keeping with Gov. Tony Evers’ 2020 action plan, and “this gives us the resources to really ramp up this work locally,” including by “identifying pathways to reduce emissions, renewable deployment, optimizing energy efficiency, innovating in transportation, and improving our building stock,” and also potentially looking at agriculture, forestry and carbon sequestration.
Wisconsin lawmakers have pushed legislation that limits municipalities’ ability to pursue climate goals, like a ban on local zero-emissions mandates and a bill that would prevent local governments from operating pay electric vehicle charging stations. They’ve also thus far declined to pass a bill enabling community solar, and rebuffed advocates’ requests for legal clarity on third-party-owned solar.
Justin Backal Balik is the state program director for Evergreen Action, which was among organizations offering the administration input on designing the federal program. He said the grants are “tailor-made for a state like Wisconsin at this particular moment in time, when you have the leadership of Gov. Evers that has articulated a clean energy plan to achieve 100% decarbonization in the electricity sector, and also looking at the industrial sector and clean transportation goals.”
“One of the reasons Evergreen advocated for the [Climate Pollution Reduction Grant] was that it is specifically designed to focus on sectoral transformations and unmet funding needs — Wisconsin has a lot,” Backal Balik continued. “The policy vision is there, and particularly with the capacity Wisconsin has with the $3 million planning grant, there are a number of directions they could go in. This is a generational opportunity that’s not going to come around again, an opportunity to meet a good chunk of the unmet funding needs that have popped up as a result of the Republican intransigence in the legislature.”
Redmond said the $3 million planning grant has allowed her office to hire a full-time community engagement facilitator and another full-time staffer, basically doubling the staff. The planning grant is also used for carrying out analysis, modeling, community outreach and status reports over a four-year period.
Environmental justice is a focus of the funding, and a key metric in the scoring system for implementation grants. Redmond said this dovetails with Wisconsin’s focus on equity and inclusion.
“Understanding lived experience is one of the things we’re most excited about” augmenting with the planning grant dollars, she said. “This gives us the ability to go out to communities instead of having them come to us. It’s also about supporting organizations working in communities, making sure we are not expecting them to volunteer their time.”
That could include honorariums for people to attend community meetings.
“We’re asking people to step away from their lives, maybe in the evening when they need child care, or to step away from their jobs,” she said.
Redmond said the state is also planning to work with Illinois and Minnesota to “make sure we are in alignment with state plans, and not working against each other” — especially since Wisconsin metropolitan areas overlap with those states.
Allison Carlson, executive director of the Wisconsin Local Government Climate Coalition, said staff capacity is a common need for local governments on the climate front, and she’s glad the planning grants can be used to hire staff.
“A lot of local governments have one person dedicated to climate action, probably being shared with other departments like recycling; they have a lot of other things on their plate,” she said. “We need to be making sure we’re building capacity in local governments and in communities to sustain efforts over time.”
Backal Balik noted the planning grants are meant to help governments make sense of all the incentives and opportunities on the table.
“EPA is really encouraging states and other jurisdictions to use the CPRG process to step back and look at their federal funding deployment strategy as a whole,” he said. “You have Solar for All here, and direct pay here, so many different pieces. The planning process is asking states to think about how all these funding streams can be accessed together. The parts are pretty consequential in their own right, but you have the opportunity to really scale up the impact of what all the federal investments can achieve.”
States or metro areas that received planning grants can serve as coordinating entities to collaborate with other government bodies to seek grants. Redmond said her office is eager to work with Wisconsin municipalities and agencies on meeting their climate goals, and will hold nine regional meetings for that purpose.
The Wisconsin Local Government Climate Coalition is also focused on helping municipalities participate in the CPRG program.
“Many member communities have their own climate action or clean energy plans in place. They’ve done data analysis, engaging with their communities to understand what the needs are — a lot of them are already making strides,” she said. “One of the big barriers is: where are the dollars to actually do these things? The competitive CPRG grants and other IRA funds are allowing communities to put their plans into action.”
She added that “a lot of the climate action plans were already in place or in process, not necessarily prompted by the CPRG process.”
“But what the CPRG process does is create opportunity to align the needs of local communities with the state and other stakeholders, so we can leverage even more IRA dollars and become more organized together.”
Kelly Hilyard is the sustainability coordinator for the city of Middleton, not far from Madison. She said the office has been stymied by legislative inaction around electric vehicles. They had applied for federal funding for electric vehicles under the Carbon Reduction Program, a program separate from CPRG under the U.S. Department of Transportation. But the county had to switch its proposal to seek funding for LED lights instead because of constraints placed on the program by the legislature.
Hilyard said the city “scrambled” to put together a proposal to transition their street lights to LEDs, which was necessary “low-hanging fruit,” but they still hope to seek federal funds for electric vehicles.
Since being part of a seven-city collaboration on an energy plan in 2020, Middleton has been “ticking things off” on a list of priorities like increased building efficiency and putting solar on city buildings. They are working on a battery storage project at the police station, where a planned microgrid had to be scaled back because of the pandemic.
Hilyard said the city has not been very focused on the CPRG thus far, but is looking for multiple sources of federal and other funding for its goals, and for the advance study and planning needed to bring goals to fruition.
“It’s chicken or the egg — what information do you need to get the grant to do the work, and how do you get the grant to get the information?” she said. “You have to work it from both ends constantly.”
A top priority is energy efficiency for the city’s affordable but often aging and inefficient housing units. A separate federal grant is helping the city take inventory of its housing stock.
“Once you stack all those incentives, decarbonizing entire neighborhoods becomes possible,” she said. “You can do major projects, and reduce the energy burden for people most affected by climate change and high energy bills.”
La Crosse environmental planner Lewis Kuhlman is hopeful that federal programs like the CPRG could help the city acquire more electric city buses or other electric vehicles, as well as creating an electric bike share program.
The city’s sustainability efforts have largely been through a partnership with the company Johnson Controls, which has provided the city with solar, energy efficiency and other energy investments, with a performance contract guaranteeing savings. The partnership helped the city access solar despite the state’s failure to clarify the legality of third-party-owned solar, which has made it more difficult for municipalities to finance solar energy.
“Huge grant opportunities like this are going to take collaboration, because communities the size of LaCrosse don’t really have the staff to implement or prepare for a grant like this,” Kuhlman said. “There are so many different types of projects that can get funding; we need to keep an eye on what we have in our plan — and how can that fit into what’s available for funding? And do state regulations allow it?”
The implementation grants are meant to help states and municipalities meet their climate goals; reduce hazardous air pollutants, especially in disadvantaged communities; complement other funding sources for greenhouse gas reductions; and create programs that are replicable and scalable. The agency is encouraging collaborative proposals that cross local and state lines. Points in the competitive grant scoring process are awarded based on criteria including the funding need, the extent of emissions reductions, benefits to low-income and disadvantaged communities, and community outreach.
Redmond noted that doing extensive engagement, figuring out what different stakeholders need and want, and meeting the application deadline all in six months will be a challenge.
“One of the things that keeps me awake at night is the timeline,” she said. “We need to have a thoughtful and meaningful process” in a tight time frame, “but we’ll make it happen.”
Milwaukee’s Climate and Equity Plan calls for making the city carbon-neutral by 2050, and creating green jobs that drive racial and economic equity. The city proposes to do this through projects including clean energy, a green jobs accelerator, and transportation electrification.
Erick Shambarger, Milwaukee director of environmental sustainability, said they hope CPRG funding will help the city implement its long-standing ambitious climate goals. He said other municipalities in the metropolitan area that received the grant have taken inspiration from Milwaukee in crafting climate action plans of their own.
“It took several years for us to get our climate plan together, and we don’t have that kind of time relative to getting everything in place for these implementation grants,” Shambarger said. “We don’t want to start from scratch. We want to share lessons we’ve learned; we don’t want to reinvent the wheel on planning processes.”
He said a key focus of the planning grant is a greenhouse gas emissions inventory, which has never been done for the region as a whole. He said that the metro group still hasn’t decided where to focus their CPRG-related plans.
“It could be everything from a major transportation project to a focus on buildings,” he said. “It could go in a lot of different directions. We’ve been doing pilot projects, but this will really be important to take it to the next level.”
Marco Marquez is the Wisconsin state director for the organization Action for the Climate Emergency, which mobilizes youth. He said IRA programs could provide federal funding for multiple climate-related initiatives that young people are passionate about and that affect them directly — like electric school buses and energy efficiency and updated HVAC systems in aging school buildings. He said young people are especially frustrated by the inertia of the Wisconsin state legislature on such issues.
“It’s unfortunate that we see a lot of effort from elected officials trying to dictate how each municipality can run and what they’re able to seek in terms of funding,” he said.
The funding available under the IRA and the potential for entities to apply for it without going through the state legislature holds much promise, he added. While his organization has not been specifically focused on CPRG, he sees it as symbolic of larger trends and opportunities.
“This is an amazing opportunity for young people to rewrite and rethink how our society should operate,” Marquez said. “And climate is the justice issue.”
Four states — Florida, Iowa, Kentucky and South Dakota — declined to participate in the CPRG program. Metropolitan areas in those states that received planning grants can still participate. In Iowa, the Des Moines, Cedar Rapids and Iowa City areas received planning grants and can apply directly for CPRG implementation funds.
Backal Balik said advocates hope the CPRG dollars can not only help work around inaction from the legislature in Wisconsin and other states, but actually change a state’s direction on climate as people see the benefits of the funding play out.
“As in Wisconsin, the program is purposely designed to achieve emissions reductions in states where they wouldn’t otherwise occur,” he said. “It’s not just moving money around, but incentivizing the next round of leadership. We had administrations willing to act but with constraints outside of their control. This is a moment in time where they can get a huge chunk of resources to move forward their climate vision.”
By now, solar trailblazer Tony Smith figured he would be on the verge of linking at least 100 low-income households in Virginia’s Shenandoah Valley with affordable power from the sun.
Secure Solar Futures, the Staunton-based company he leads, had selected an ideal 10-acre, south-facing site in Augusta County for the 1.2-megawatt project. It carried a $2 million price tag and was set to go online after July 2023, per Virginia’s recent community solar law.
County officials heartily embraced Smith’s plan and praised his vision to preserve the region’s agricultural traditions by grazing sheep among the arrays.
And, in the spirit of a true community solar venture, the developer had partnered with an energy-centric nonprofit in nearby Charlottesville to identify potential customers.
“People want to feel a connection to where their energy is produced,” Smith said about seeking local customers. “That’s part of our game plan.”
What could possibly derail such a well-intentioned plan?
As it turns out, plenty.
But the major obstacle emerged when Smith broached Dominion Energy in August 2021 about interconnecting the project to the distribution grid.
Dominion rejected the proposal. In the ensuing back-and-forth, Secure Futures discovered that Plan B would mean footing an extra $1 million bill to install a type of fiber optic wire known as dark fiber between the array and the substation to meet Dominion’s standards.
“Suddenly, the project would cost $3 million,” Smith said. “That made it too expensive. To make it appealing to low-income customers, the price has to be less expensive than the rate they’re already paying to Dominion.”
For distributed energy, Dominion frames dark fiber as a reliability and safety necessity. In tandem, the utility insisted that Smith’s proposed array be able to go offline within one-sixth of a second of a power outage being detected.
That surprise blink-of-an-eye demand has stalled Smith’s array — but not his resolve.
“We were shocked to get this news from Dominion, because no other utility has these requirements,” he said, noting a two-second shutoff is the industry standard. “But we’re still trying to make this project happen.”
Dominion spokesperson Jeremy Slayton didn’t comment on this specific case.
Generally, he said, the utility administers regulations laid out in Chapter 314 of the Virginia code that governs the interconnection of small electric generators in a “consistent and equitable manner” for all customers that “desire to operate generation in parallel with the Company’s distribution grid.”
He added that Dominion performs site-specific, customized interconnection studies to identify modifications needed to ensure the safety, reliability, and operability of the grid.
In May, the State Corporation Commission opened a docket to comprehensively explore interconnection issues related to distributed energy resources.
“Dominion … looks forward to continuing to participate in this docket as it evolves,” Slayton said.
For Smith’s project to come to fruition, Virginia’s solar industry will likely have to convince utility regulators that developers in Dominion territory, especially small ones, not be saddled with installing expensive dark fiber when other — and cheaper — existing technology can meet the same safety and reliability standards.
Dominion evidently insists that dark fiber should be the heart and lungs of grid equipment known as Direct Transfer Trip, or DTT.
The Chesapeake Solar & Storage Association, or CHESSA, challenged Dominion’s dark fiber assertion in testimony submitted to Virginia utility regulators this summer.
“This [DTT] requirement is an unnecessary and arcane approach to addressing anti-islanding, given the fact that certified inverters already perform this function,” said GreeneHurlocker attorneys representing CHESSA.
With DTT costs averaging $2 million to $3 million — and reaching as high as $7 million, CHESSA and Coalition for Community Solar Access have withdrawn multiple projects in Virginia.
CHESSA noted that states with high levels of distributed energy penetration have “long moved away from requiring DTT and instead use inverter-based solutions.”
Virginia solar developers agree that it’s unfair for the first project in the queue at a substation to bear the financial brunt of an entire substation upgrade that essentially becomes a grid modernization project. CHESSA also noted that some states are exploring the idea of cost-sharing among distributed energy projects.
Cliona Robb, an energy attorney for 22 years, is frustrated that Smith’s project is being stymied by Dominion’s dark fiber rationale when she says the utility is clearly an outlier on that front. In August, she filed comments with the commission on behalf of Secure Futures.
“The message is that you can get solar, as long as it’s utility solar. Otherwise, you’re out of luck,” said Robb, of Richmond-based Thompson McMullan. “It’s outrageous to me that a utility can unilaterally adopt a practice that’s not consistent with industry standards.”
In her comments to regulators, she outlined several changes that would help smaller solar developers complete projects without bankrupting themselves.
For instance, Robb urged commissioners to adopt a rule eliminating the need for dark fiber for interconnections under 5 MW. In Virginia, Level 2 interconnections generally apply to projects between 500 kW and 2 MW, while Level 3 projects can be up to 20 MW.
As well, she advised that expenses for those smaller projects be limited to the cost of inverters and reclosers and not costs related to upgrades to a utility’s substations or other pieces of its distribution system. As well, she said, inverters or cellular communications should be the standard in lieu of dark fiber.
Robb pointed to a case study published by the Institute of Electrical and Electronics Engineers (IEEE) concluding that DTT cellular communications provided an efficient and cost-effective approach for utility communications with distributed generation systems.
The study looked at three installed DTT systems — one in Central Virginia Electric Cooperative territory and two in Dominion’s service area. It compared copper telephone lines to cellular communications. The latter was considered because the authors noted that fiber installation is not always feasible because it can be cost-prohibitive.
The Institute of Electrical and Electronics Engineers is the professional body that sets scores of standards, including one that covers inverters and minimum distributed energy performance requirements. Secure Futures and other developers maintain that Dominion’s strict interpretation of that standard is squeezing their projects.
Even if Secure Futures did splurge on fiber optic cable for its Augusta County project, Smith noted that it would be using only two of the 24 total “strands.”
“So, the other 22 fibers would be dedicated to some other purpose not involving our project,” Smith said. “With that, Dominion is putting the cost of infrastructure development on the backs of solar developers.”
Slayton, the Dominion spokesperson, said the inverter performance criteria is not related to the dark fiber requirement. He noted that the inverter specifics had been among the utility’s protection requirements since September 2016.
Utilities, installers, environmental advocates and others in the solar community flooded regulators’ inboxes after the May request for comments.
Two of the eight questions commissioners asked participants to address small solar generators. In addition to dark fiber, solar advocates weighed in on a number of interconnection concerns, including lengthy timeliness, excessive studies, lack of transparency and dispute resolution.
The state General Assembly recognized the benefits of distributed energy by passing both the Virginia Clean Economy Act and a shared solar statute in 2020.
Those and other clean energy laws prompted regulators to update interconnection rules from more than a decade ago. However, advocates had complained that those tweaks weren’t adequate enough to match the rising volume of interconnection applications.
“While the changes made to the rules provided modest improvements to the process, the distribution interconnection process continues to be antiquated and ill-prepared for the 21st century grid,” CHESSA wrote. “The existing procedures [are] not sufficient to enable the amount of renewable energy additions required by the Commonwealth’s transformational energy goals.”
Dominion submitted 15 pages of comments. Two of those pages addressed regulators’ query about how commissioners could facilitate its approach to the Institute of Electrical and Electronics Engineers standard on inverters and distributed energy.
Dominion stated that it believes any use of distributed energy “ride-through or voltage regulation functionalities should be at the Company’s discretion and evaluated based on system needs on a case-by-case basis.”
The utility told commissioners that the regulations centering on the standard don’t need to be revised.
“Specifically,” commission staffers summarized, “Dominion commented that anti-islanding functions of [distributed energy resources] inverter-based resources alone do not replace the multiple functions and layered protection that DTT provides to the electric power system.”
On Sept. 19, commission staff released a 57-page action plan, of sorts, after reviewing input. They concluded that some concerns could be addressed immediately, others would be more time-consuming and still others would likely require a separate docket.
“The requirement for usage of dark fiber-optic cable for DTT implementation was one of the most pressing issues commented on by the parties,” commission staffers said.
Solar developers echoed Secure Futures’ concerns about dark fiber. However, they also pointed out that the fiber can cost more than $250,000 per mile to install. The total price tag is a blow to project planners because utilities don’t deliver those cost estimates until the “facilities study phase,” the final study phase of a long and involved process.
Smith said he is disappointed that working groups will likely be handling the issues delaying his Augusta County project — dark fiber and the excessive cost of interconnection — in a far-off timeline.
“We have a need for speed,” he said. “But we’re looking at four to six years until anything is settled.
“In the meantime, while Rome burns, solar investment will bypass Virginia. Social policy and interconnection barriers are hindering the promise of solar.”
Robb, his attorney in this case, said commissioners need to be aware of the damage they are inflicting by pushing immediate concerns off to slow-moving work groups instead of acting themselves.
“Not advancing community solar is harming the public interest,” she said.
Smith, who founded Secure Futures in 2004, is no clean energy rookie. The entrepreneur has been immersed in solar since 1978 when he created his first job in the industry with the Philadelphia Solar Energy Association.
Thus far, his Staunton company has developed more than 11 MW of arrays in Virginia, West Virginia and the Carolinas.
Five years ago, the business became a certified B Corporation to reflect its commitment to solving social and environmental problems. It prides itself on innovations in financing, public policy and energy education that extend the reach and affordability of solar power.
For instance, that spirit is reflected in an endeavor Smith’s company is undertaking in the state’s seven historic coalfield counties, at the behest of the Solar Workgroup of Southwest Virginia.
A public-private partnership launched in September 2020, appropriately named Securing Solar for Southwest Virginia, is in the midst of installing 12 MW of solar arrays at five commercial buildings, five multifamily housing units and 10 schools. The optimistic completion date is next year.
Relatedly, Smith viewed the Augusta County project as an innovation to connect underserved Virginians with community solar, a new concept in Dominion territory.
He praised the utility for setting up a program but lamented how interconnection challenges are “killing it on the implementation side.”
Dominion’s program, set to debut next year, sprang from state legislation passed in 2020. Initially, total capacity will be capped at 150 MW. Both solar and environmental justice advocates had lauded the law for requiring that at least 30% of the enrolled customers qualify as low-income. If that bar was met, the program could grow by another 50 MW.
In addition, no single community solar project could be larger than 5 MW. The idea was to incrementally stimulate a series of small-scale distributed generation projects, roughly 1 MW apiece.
This summer, regulators set off an uproar among solar advocates by allowing Dominion to charge a $55 monthly minimum fee to enrollees. The legislation had included a measure allowing commissioners to set a monthly fee that let Dominion account for costs of implementing shared solar and for use of the grid infrastructure.
Low-income subscribers, however, are exempt from that minimum fee. Aiding that poorer audience is why Secure Futures sought out a local collaborator in Augusta County.
Now, that affiliation also might be unraveling.
Due to delays, it’s not clear where the partnership with the Charlottesville-based Local Energy Alliance Program now stands. Leaders of the nonprofit didn’t return requests for comment. Since 2010, LEAP has offered home and commercial energy upgrades, as well as solar services.
Even though Smith has “come to the sad conclusion that we’re not going to get any help on the regulatory level,” he is forging ahead.
After withdrawing the project in April, Secure Futures is now in the midst of resizing it and preparing a new interconnection application.
“We’ll see what happens,” Smith said. “We’re not holding our breath.”
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.”
Prospects are dimming for an offsite solar innovation promoted as a bright and affordable renewable energy option for Virginia apartment dwellers when legislation was greenlighted two years ago.
Now the fate of the new multifamily shared solar program is in the hands of utility regulators.
Solar advocates have pleaded with the State Corporation Commission to reject “program-killing” double-digit monthly fees that Dominion Energy would be allowed to charge solar subscribers.
Dominion has proposed an $87.68 fee, while commission staffers have suggested one as high as $57.26 a month. Figures are based on enrollees with a 1,000-kilowatt subscription.
Charlie Coggeshall, who directs policy and regulatory affairs for the Coalition for Community Solar Access, said Dominion arrived at its fee by lifting a page from its docket related to a similar, but separate, shared solar program for homeowners.
“The utility basically cut and pasted the charges it had proposed on a parallel docket,” Coggeshall said.
In late March testimony to commissioners, Coggeshall’s coalition asked regulators to also dismiss a $16.78 fee option floated by regulators.
Instead, his coalition of solar developers joined the Mid-Atlantic-based Chesapeake Solar & Storage Association in calling for commissioners to approve an interim administrative charge floated by Virginia environmental advocates.
That charge would amount to 1% of the bill credit value per month until Dominion “demonstrates a reasonable administrative charge.” The law calls for enrollees to be credited for their share of electricity the off-site panels generate.
“It is critical that the Commission send a clear message … that Dominion will not be allowed to use the administrative charge as a vehicle to block customer access to the benefits of solar or prevent investment in Virginia’s clean energy transition by non-utility shared solar developers,” attorneys for the two trade groups testified.
Commissioners could reach a ruling this spring.
Multifamily shared solar was just one piece of the wide-reaching Solar Freedom laws spearheaded by state Del. Mark Keam, D-Fairfax, in 2020.
The measure was designed to allow people living in apartments, condominiums and duplexes in Dominion territory the ability to buy solar energy via subscriptions to local arrays instead of having to install panels on their own rooftops. In most cases, shared off-site power facilities are built and owned by third-party entities, not utilities.
Ideally, subscribers earn credits in the form of savings on their monthly electric bills while also helping to pay down the developers’ cost of the array.
Such flexibility is attractive to low-income customers who can’t afford the upfront cost of rooftop panels, those with shaded southern exposure, people subject to homeowner association restrictions, and apartment renters and condominium owners without control of their rooftops.
Keam’s multifamily measure is separate from a different shared solar program, Senate Bill 629, designed mostly for homeowners and shepherded through the General Assembly by state Sen. Scott Surovell, a Democrat who also represents a district near Washington, D.C.
Both were signed into law by former Gov. Ralph Northam, a Democrat.
All along, Surovell’s law was set to launch in Dominion territory next year. Any day now, utility regulators will be announcing how much the utility is allowed to charge subscribers for minimum fees and administrative fees in that program.
Solar advocates challenged those charges at recent commission hearings, claiming they could put the kibosh on the whole program if they’re out of reach for market participants.
Surovell’s measure builds in a component that offers cost breaks to low-income subscribers. For instance, those enrollees are exempt from paying minimum and administrative fees.
Initially, that program is capped at 150 megawatts of solar. However, it can be boosted to 200 MW if it reaches an incentive requiring at least 30% of enrollees to meet pre-established low-income standards.
Keam’s original multifamily program could have been up and running in early 2021 if it hadn’t become mired in legislative and regulatory twists and turns.
For instance, regulators began writing rules based on a final version of the law that allows “the investor-owned utilities to recover reasonable costs of administering the program.” How that phrase is being interpreted is at the heart of the dispute. Dominion assumed it had broad leeway to set administrative charges. Solar advocates accuse Dominion of piling on costs in an effort to hamstring a program that should hardly make a dent in the utility’s budget.
Multifamily participants would be on the hook for those administrative fees because the measure doesn’t have a low-income exemption.
Robert J. Trexler, Dominion’s director of regulation, argues that because solar is intermittent, subscribers will continue to rely on the utility’s transmission and distribution systems.
An administrative charge is “a reasonable means to ensure that participating customers pay for the costs of services they will be utilizing,” he said, adding that “it is the only safeguard to minimize cost-shifting to non-participating customers.”
The administrative charge would vary based on subscription level.
However, solar advocates counter that Dominion’s proposed $87.68 fee or the $57.26 option presented by the commission staff make the program inaccessible because those charges are higher than customers’ regular electric bills.
“It is concerning that the utility is trying to use this administrative fee to preemptively charge for cost-shifting for which Dominion presents no evidence,” said Laura Gonzalez, energy policy manager for the Charlottesville-based nonprofit Clean Virginia.
Gonzalez emphasized that all three proposals before the commission should be rejected because regulations defined the fee as the reasonable incremental cost Dominion would incur to administer multifamily shared solar, not costs already incurred that are neither incremental nor related.
Acceptable administrative charges, she said, are new expenditures Dominion would need to make to operate the shared solar or handle billing. Examples include upgrading infrastructure or hiring employees.
She added that Dominion should recognize that enrollees are contributing to the big climate change picture by boosting electric grid resiliency and reducing emissions of heat-trapping gases.
“These programs have lots of benefits,” Gonzalez said. “The commission should rule based on the facts.”
Will Cleveland, a senior attorney with the Southern Environmental Law Center, said Dominion’s “extremely high” monthly charge “would result in an unworkable program.”
He added that the utility is seeking to recover lost revenue from program enrollees under the guise of an administrative fee.
“Dominion undermines both the plain language and spirit of the multifamily statute and rules by recycling its minimum bill proposal from a separate shared solar proceeding and renaming it an ‘administrative charge,’” Cleveland wrote in a March 24 document filed with regulators. “Moreover, Dominion has failed to demonstrate … that any of the costs of its proposed administrative charge are needed, just or reasonable.”
Many of the third-party developers who would build and own the off-site power facilities in Virginia are reluctant to speak on the record about shared solar because they don’t want to rock established relationships with utilities.
Nor, evidently, has there been a hue and cry for multifamily shared solar from trade organizations such as the Virginia Apartment Management Association.
The concept would be more appealing to affordable housing builders if it included carveouts aimed at attracting low- and middle-income residents.
For instance, Sunshine Mathon, executive director of the Charlottesville nonprofit Piedmont Housing Alliance, supports multifamily shared solar in theory but he’s far less intrigued by a program lacking affordability guardrails.
“The bottom line is that we’re going to advocate for something that makes financial sense for our residents,” he said. “They’re already struggling with enough cost challenges around every corner.”
Mathon is no stranger to solar energy. He’s currently overseeing the transformation of a public housing complex built in the late 1970s from an energy sieve into a community of energy-efficient homes. Part of that includes navigating the intricacies of installing rooftop solar panels that won’t empty residents’ wallets.
What should be appealing about solar is allowing customers the peace of mind of locking into fixed, long-term costs.
That predictability is nonexistent in the multifamily solar program wending its way through the regulatory process, he noted.
“I won’t say we would reject it, but I would look at any potential installation with a level of healthy skepticism as to whether it’s a good deal or not,” Mathon said. “I wouldn’t know that until I saw the details.”
With two-plus decades of retail experience, Rachel Brown well knew her internal fraud detector should be on high alert when weighing any offer touted as “free.”
That’s why the retired quilt store owner paused — and did her homework — when a tempting overture for no-cost rooftop solar crossed the transom of her Augusta County home a year ago.
Brown’s research involved querying her utility-savvy nephew, Everett Brubaker, who assured her that Dominion Energy’s solar plan targeting elderly and low-income Virginians is indeed a legitimate deal.
“Everett would not be recommending anything that wouldn’t be good for me,” she emphasized. “It came from a very trusted source. That really mattered to me.”
Brubaker’s nod motivated his aunt to sign up for solar.
And, true to its promise, the only money she has spent — all voluntarily — was on ingredients for the chocolate caramel oatmeal cookies she baked for the SunDay Solar crew that arrived Sept. 12 to attach a 12-panel array atop her house. The 5-kilowatt system was scheduled to go online this month.
“Just the idea that this will help me move off fossil fuels is exciting,” Brown said about a system configured to cut her power bill by at least one-third.
“I know Dominion is a huge corporation and my little electric bill is nothing to them. But I’ll be saving and that’s big for someone on a fixed income.”
Brubaker, based in the nearby Shenandoah Valley city of Harrisonburg, is an outreach specialist on the Energy Solutions team at Community Housing Partners. His employer is the largest of roughly a dozen nonprofits statewide qualified to perform weatherization services.
Linking homeowners who live paycheck-to-paycheck to a suite of age- and income-qualifying programs is the bread and butter of that network. Those connections are all about enhancing affordability, adding value and ensuring residents are safe and healthy in their homes.
However, that holistic approach falls flat, Brubaker said, if he doesn’t devote time to building relationships with people who have every right to be wary of anything promoted as free.
“For my Aunt Rachel, that little 5-kilowatt system is a gamechanger,” he said. “But seniors are inundated with scams about solar so it’s nearly impossible to sift through what’s legitimate and what isn’t.
“It’s important that there be comfort and trust.”
While Brown credits Dominion’s “charitable” action, the investor-owned utility isn’t as altruistic as she might think.
The three-year program — which carries the cumbersome name, Income and Age Qualifying Solar — grew out of 2019 legislation (HB 2789) introduced by Del. Israel O’Quinn of Bristol.
O’Quinn, a Southwest Virginia Republican, called on both Dominion and Appalachian Power to craft pilot programs geared at offering energy efficiency and solar incentives to low-income and elderly customers. After it became law, utility regulators at the State Corporation Commission rolled out program rules in 2021.
Dominion and its contractors began installing the small-scale arrays last October. Thus far, they’ve served 116 households, and more are in the pipeline.
The no-hidden-fees program includes a 25-year warranty for panel maintenance and repairs.
While activating small arrays — they range from 3 kW to a maximum of 5 kW — might not be a juggernaut, Dominion’s maxim is that every kilowatt matters as the utility transitions to renewable power.
“While not the largest, they provide meaningful benefits to customers, especially in areas that may not otherwise be near a solar installation,” said Dominion spokesperson Jeremy Slayton.
The initial legislation, which covered both utilities, called for a total investment of $25 million in the solar portion.
In Dominion territory, costs for the rooftop installations are shared among all customers via a demand-side management rider, Slayton said. Briefly, those initiatives modify consumer demand for energy by deploying financial incentives and behavioral changes.
One prerequisite is that each solar installation be paired with an energy efficiency makeover, via a related Dominion endeavor, so homes are as airtight as possible beforehand.
It never pays to outfit a leaky home with photovoltaic panels, Brubaker said, adding with a laugh that homeowners must partake of their energy efficiency “vegetables” before indulging in a solar dessert.
Brown checked that box in the spring when workers from the Local Energy Alliance Program — a sibling organization to Brubaker’s CHP — conducted an energy audit on her all-electric, early 1970s home in Verona.
“They added insulation and made sure my house was sealed up,” Brown said. “The energy efficiency part really matters.”
In addition to saving money, Brown figures the panels on her roof will serve as a lesson in environmental stewardship for her 13-year-old granddaughter, Emma Rose.
“All that I do and know and share influences her,” Brown said. “So, if this can increase the percentage of renewable energy for her future, I’m all for it.”
Emma Rose bonded with her grandmother because she spent so much of her childhood at the Staunton quilt shop Brown operated with her daughter, Emma Rose’s mother, for 23 years. They opted to close the store in March 2020.
“I’m now 76 and happy to have reached that age,” Brown said, reflecting a bit on how the COVID-19 pandemic reshaped her life. “My philosophy was always to be more open, sharing and nonjudgmental. But it became more pronounced after the pandemic set in.”
While the Pennsylvania native stuck with her longtime passions of cooking, gardening and creating pottery, she also began noticing opportunities where she could grow differently.
Planet preservation became a priority — and she figured she could start by greening her energy supply.
She’s now hoping that leery friends and neighbors will be open-minded and trusting enough to follow her solar lead. They’re the doubters who repeatedly told her, “Just wait until the bill comes,” when she relayed her story about taking a chance with Dominion.
“But it never did,” Brown said. “Maybe it sounds too good to be true, but it is true. I haven’t paid a penny.”
Indiana solar installers knew their customers would be worse off when new, reduced rates for surplus solar generation took effect on July 1.
But changes being ushered in by utilities go far beyond what the industry had been bracing for, say solar and consumer advocates who are now challenging regulators’ interpretation of a 2017 law that gutted net metering.
All five of Indiana’s investor-owned utilities have won approval to not only slash the rate paid for customers’ surplus solar power, but also change how solar output is calculated in a way that drastically reduces the payments.
Utilities say they are protecting other customers from subsidizing those with solar panels, but advocates say the outcome threatens to put rooftop solar out of reach for all but the wealthiest customers.
“Unfortunately, utilities used the opportunity to completely change the policy, and [state regulators] went along with what utilities wanted,” said Ben Inskeep, program director at Citizens Action Coalition, a consumer and environmental advocacy group based in Indianapolis.
Indiana solar customers until now have been paid for extra solar generation at the end of each billing cycle. The amount of electricity sent back to the grid that month is subtracted from the amount of power the customer used from the grid, and any extra is paid out at a rate lower than the retail rate but robust enough to make solar panels financially viable for many customers.
The arrangement allows a homeowner, for example, to use extra daytime solar generation to offset evening grid power use, but they can’t bank solar credits in the summer to reduce their electric bill during the darker winter months.
A bill (SA309) signed by Gov. Eric Holcomb in 2017 put the state on a path to phasing out net metering by 2047. Meanwhile, it let utilities begin paying solar customers a lower rate when solar penetration reached 1.5% of their summer peak load, or by July 2022.
CenterPoint, previously known as Vectren, was the first utility to reach that benchmark and early last year filed a request to institute the new, lower rate — known as the “excess distribution generation” or EDG rate. CenterPoint also proposed switching from monthly net metering to a new model known as “instantaneous netting,” in which customers pay the full retail rate for all power used from the grid, and all solar power sent back to the grid is paid at the much lower EDG rate. The arrangement turns out so badly for customers that advocates like Inskeep refer to it as “no netting.”
The Indiana Utility Regulatory Commission approved CenterPoint’s full request in April 2021 despite arguments from consumer and solar advocates that the plan oversteps what’s called for in the 2017 law.
“SA309 does not authorize instantaneous netting. It made no mention of changing the netting interval,” Inskeep said.
In March 2021, NIPSCO had submitted testimony seeking an EDG tariff with monthly netting. But NIPSCO withdrew that proposal and sought instantaneous net metering after the commission’s decision on CenterPoint. Utilities AES, Indiana Michigan (I&M) Power, and Duke Energy also sought the same instantaneous netting arrangement. The commission approved all of the proposals — most recently Duke’s on July 6.
The Office of Utility Consumer Counsel, a governmental office set up to advocate for consumers, joined solar advocates in arguing against instantaneous netting, saying it would be inconsistent with SA309.
But the commission has argued, including in its Jan. 26 approval of I&M’s proposal, that the intent of SA309 was to end net metering, and instantaneous netting would basically be a way to do that. The commission acknowledged that customers would save less money through instantaneous netting, but invoked an argument long used by utilities against solar energy: that the savings of customers with solar would be costs shifted onto customers who don’t have solar.
Duke Energy echoed this sentiment in response to Energy News Network questions about the change to instantaneous netting.
“The intent of the legislation is to help ensure that customers who do not own solar generation are not subsidizing those who do,” said Duke spokesperson Angeline Protegere, noting that 2,600 customers in Duke’s Indiana service territory have solar.
“Even though they generate some of their own power, solar customers still rely on electric infrastructure such as power lines, and the new rate reflects the costs of that. It’s important to realize that customers ultimately pay for the credits we give to solar customers.”
Advocates including the Indiana Distributed Generation Alliance and Citizens Action Coalition appealed the commission’s decision on CenterPoint’s proposal and won a favorable ruling in the Indiana Court of Appeals.
But now the matter is before the state Supreme Court, and the appeals court decision is negated until the higher court hears the case, with oral arguments scheduled to start Sept. 15.
“This is a matter of law,” said Laura Arnold, executive director of the Indiana Distributed Generation Alliance. “The commission and CenterPoint have been trying to portray that the General Assembly intended to allow instantaneous netting, but that is just not true.”
Under SA309, the EDG rate paid for energy from solar is equivalent to 125% of the average hourly market rate during that month. Using this calculation, CenterPoint originally proposed to pay their customers 3.1 cents per kilowatt-hour for solar, and NIPSCO proposed 2.6 cents.
Utilities have increased the prices they plan to pay customers for solar as market power prices have risen due to the war in Ukraine, to the 4 to 5 cents per kilowatt-hour range; meanwhile retail prices customers pay for power from the grid have also risen. Duke’s retail rate is 16 cents per kilowatt hour for an average residential customer, Protegere said. (CenterPoint and NIPSCO did not respond to requests for comment.)
Brad Morton, founder and CEO of Morton Solar, told the commission that the switch to instantaneous netting and EDG rates “grossly lengthens the customer investment pay-back period,” with instantaneous netting at the 3.1 cents per kilowatt-hour originally proposed by CenterPoint changing the typical residential solar payback period from the current 7- to-10 years to 21 years.
The 3.1-cent payment rate alone, without instantaneous netting, would result in a typical payback period of 14 years, he testified. When the phaseout of the federal Investment Tax Credit is added to instantaneous netting and the EDG, it would take 25 years for a typical solar system to break even, Morton said.
Morton was the first to install solar in Vectren (now CenterPoint Energy) territory, he told the commission, and among the first to do grid-tied solar in Indiana. His family members had worked in Indiana’s coal mines, and he wants to help transform former coal mine land into solar fields, replacing declining coal mining jobs and revenue with a solar economy in the process.
Last year Morton did $2.5 million worth of solar installations in Vectren’s service area, and $3.1 million in Indiana as a whole. If the instantaneous net metering goes forth, he said he might have to stop doing business in Indiana altogether, and lay off some of his 17 staff members.
“This will be devastating to Indiana’s fledgling solar industry and result in job losses and probable market contraction to an industry that was just beginning to blossom,” he testified.
Customers who have recently installed solar are exempted for a decade, governed by the old terms through 2032. But that just barely covers a typical pay-back period, so right when customers would have hoped to start reaping the savings of solar, the opportunity will stagnate. Customers — like Arnold herself — who installed solar before SA309, can net meter under previous terms until 2047.
Arnold said that if utilities get their way and institute EDG plus instantaneous metering, solar would only make sense for most customers if they have a battery system to use all their energy themselves rather than sending it back to the grid for pennies. But batteries cost thousands of dollars and make the already slim margins on solar unworkable for many customers.
She noted that if “no netting” takes effect, customers would rarely install solar systems that generate more power than they need at any given time, wasting the chance to get more clean power on the grid by installing larger systems.
Arnold added that on top of the gloom facing the solar industry for years to come, there is debilitating uncertainty for customers who’ve signed solar contracts and hoped to install them by the end of the year. Duke Energy and NIPSCO have told customers they could qualify for previous net metering terms if their solar is contracted now and installed by the end of 2022. Protegere confirmed that is Duke’s plan.
But Arnold said solar developers and lenders are worried that the commission might block this arrangement, perhaps if another utility complains.
Arnold said that months ago, advocates had asked the commission to issue an opinion clarifying the deadline, to provide certainty for developers and customers, but the commission has not done so.
Inskeep noted that the changing price of power — and hence the 125% EDG rate people are paid for solar sent back to the grid — means uncertainty for anyone who is considering solar.
“It’s hard to say what your compensation will be in the future — it will change every single year,” said Inskeep, who was principal energy policy analyst at EQ Research, a clean energy consulting firm, at the time the commission decisions were playing out.
“You’re making a 25-year investment, but the value is updated on an annual basis. You have no ability to see if your investment will pay off. Utilities never make large investments for 30-year assets without having certainty for that cost recovery. Now they’re asking residential customers to take that risk — with no ability to understand when their investment will pay off or if it will never pay off.”
Elizabeth City, North Carolina, once sought to lure boaters up the Pasquotank River with free docking at its marina and welcome baskets of wine, cheese and roses.
Today, the “harbor of hospitality” is preparing a new pitch, trying to attract offshore wind manufacturers with the region’s workforce and manufacturing capacity.
“Northeastern North Carolina is a special place,” commerce secretary Machelle Sanders said at a recent summit hosted by the historically Black Elizabeth City State University. “Just as North Carolina has provided a runway for the Wright Brothers to take flight, the region is helping to develop clean energy.”
With two offshore wind farms underway off the Outer Banks and a major turbine blade facility announced just across the state border, the potential in this largely impoverished region is vast. But experts and advocates stress that extreme poverty and economic disparity won’t be erased without effort.
“We have to be strategic about it, to make sure that the communities that really, really need this are benefiting from it,” said Montravias King, an Elizabeth City State graduate and former city councilor. “And if we don’t, it’s not going to happen.”
Regional pride ran high at the conference, with Sanders, a native of tiny Belhaven on the Pungo River, delivering the keynote address. Citing the area’s ties to the Coast Guard and its tourism industry, she declared, “we do have assets in this great part of the state.”
But in many ways, northeastern North Carolina is a tale of two banks. On the Atlantic Ocean, there’s the overwhelmingly White Outer Banks, once a string of modest fishing villages that today is a multibillion-dollar tourist attraction. Dare and Currituck, the two counties that encompass most of these barrier islands, are some of the state’s wealthiest by income and property value. In the last decade, Currituck’s population grew by 19%, not far behind the Triangle and Charlotte.
Then there are the roughly 20 counties of the mainland, sometimes dubbed the “Inner Banks” by tourism promoters. With few exceptions, these communities have a higher portion of Black people than the state overall. In Bertie County, where the Chowan River empties into the Albemarle Sound, nearly two-thirds of the population is Black, the highest fraction in the state.
People of color were systematically shut out of the region’s economic opportunities for centuries, and in recent decades, textile manufacturing jobs were lost to the North American Free Trade Agreement. Today, populations here are shrinking at the fastest rates in the state, and the economic indicators rank these counties among the poorest. Property values in Dare are four and a half times that of Pasquotank County, home to Elizabeth City.
Many feel little connection to the Outer Banks, said King, who now directs clean energy campaigns for the North Carolina League of Conservation Voters in Raleigh. “It’s a different world out there.”
In her address, Sanders acknowledged these inland counties — and other rural areas of the state — had often been left behind economically, a dynamic she knows well. “I know very well what it’s like to be excluded,” she said, “because I’m Black. I’m a woman, and because I’m from Belhaven.”
But she and others at the conference said the entire region could benefit from offshore wind. In March, a report commissioned by her department found the industry was poised to invest $140 billion up and down the East Coast — manufacturing specialized wind turbine components, shipping and assembling them at sea. “We do deserve our fair share of that,” she said. “We are looking forward to that blossoming economy.”
Already, there’s economic activity underway in northeastern North Carolina because of two major offshore wind projects. Twenty-seven miles east of Virginia Beach, a Dominion Energy project is scheduled to begin delivering power in 2026. With a capacity of 2.6 gigawatts, the wind farm could create enough power for nearly 700,000 homes.
Avangrid Renewables plans a similarly sized project off the North Carolina coast, Kitty Hawk Offshore, slated for completion in 2030. (Larry Lombardi, the economic development director for Currituck County, says the wind farm is actually closer to his town, despite the name. “I have to clarify so people understand,” he told the Energy News Network, “it’s 27 miles off the coast of Corolla.”)
Power from both projects will come onshore to Virginia, and they’ll be built and staged in that state’s Tidewater region. Together, they’re expected to create upwards of 1,700 construction-related jobs annually. Once the wind farms are up and running, they’ll spur another 2,000 jobs for technicians, vessel managers, and other operations and maintenance workers.
Most of these jobs will be in Virginia, but within reach of Tar Heels across the border, many of whom already commute north for work. In Gates County, more than half of the employed work out of state, according to commerce officials.
Situated carefully beyond the coastal horizon, the Kitty Hawk wind turbines aren’t expected to be visible to beachgoers. But even if they were, Lombardi and others believe they could be a boost, not a bane to tourism.
“We know from the offshore wind in Europe,” he said, “they have tourism boats going out there. They have fishing boats going out there. It’s just going to add to what we’re already doing.”
These two wind farms could be just the tip of the iceberg. According to the March report, 41 gigawatts of offshore wind could be installed up and down the Eastern seaboard by 2035. Gov. Roy Cooper, a Democrat in his second term, wants a fifth of that to be off North Carolina’s coast.
With today’s technology — in which one turbine has about 6 megawatts of power capacity — those figures translate to more than 1,000 turbines off the state’s coast alone, with another 5,500 or so off the rest of the East Coast.
The structures require specialized parts, like towers 30 stories high, blades the length of football fields, and nacelles that would dwarf most office buildings. Today, all these components are made in Europe — creating an unprecedented opening for suppliers in North Carolina.
“There’s nothing else like this where you have a multibillion-dollar global industry that has zero footprint in the United States,” said Steve Kalland, the director of the North Carolina Clean Energy Technology Center and contributor to the March study. “It’s wild.”
Even when the ocean-based turbines reach the end of their useful lives, they’re likely to be refitted with the latest technology and reused. Manufacturers will need a steady workforce for decades to come. “It’s a multigenerational opportunity,” said Kalland. “We’re not just going to build wind turbines for five years and then everybody’s unemployed.”
Though the Northeast states are ahead of the Southeast ones when it comes to establishing a market for offshore wind — requiring some 20 gigawatts of the resource by 2035 — there’s still ample chance for North Carolina and its neighbors to play a leading role in the supply chain.
That’s part of why Cooper joined the governors of Maryland and Virginia last year in an agreement to work cooperatively to boost the region’s participation in the offshore wind supply chain — including through workforce training, enhancing deepwater ports, and upfitting and expanding factories.
It’s already paying off. Last month, Siemens Gamesa announced it would build the country’s first offshore wind turbine blade facility in Portsmouth, Virginia, creating an estimated 300 direct jobs.
The factory is expected to supply the entire East Coast, but another major blade maker in North Carolina is not out of the question, Kalland said. And there’s still potential for other major factories to produce towers, foundations, undersea cables, nacelles and more.
“All of these things are going to have to get sourced out here in some way, shape or form,” he said. “We really think that the opportunity for job creation — as you work your way through the parts and pieces — is huge.”
That’s especially true because North Carolina’s manufacturing sector is already the largest of the East Coast states, and many companies here already produce onshore wind turbine components. More than 40 have already expressed interest in participating in the offshore wind supply chain.
At Wilmington, Morehead City, and Southport, the state also has opportunities to enhance its ports to assemble and ship large offshore wind components. Radio Island, between Morehead City and Beaufort, is considered the best near-term option.
Jeff Andreini, the vice president of new energy for Crowley Marine Services, glowed about the site at the Elizabeth City State conference. “Radio Island is a tremendous opportunity,” he said. “It’s a direct shot out to the Atlantic Ocean.”
Andreini, whose company has a network of barges that can deliver offshore wind components to the point of construction, isn’t the only one excited about the spot, said Jaime Simmons, program manager for the Southeastern Wind Coalition. “The county commission and the economic development office are thrilled about it,” she told the Energy News Network.
And though North Carolina is a so-called right-to-work state, which allows workers to be represented by unions without having to pay dues, the state AFL-CIO is still hopeful that offshore wind could help inject more union jobs into the state’s economy. “It’s so early and it’s so new,” said Aiden Graham, campaign manager for the group, “that nothing is set in stone.”
To be sure, not all of these supply chain opportunities are in the state’s northeast corner, and it’s not the only area struggling economically. But experts and locals point to evidence that the region could get a significant boost from the industry.
First, there’s the spillover effect from Virginia. “There is a significant workforce opportunity, even if a lot of this manufacturing and construction work happens in the Hampton Roads area,” Kalland said. “There’s not enough specialized people in Hampton Roads — they’re going to be drawing people from all over the place, and northeastern North Carolina is clearly one of those places.”
Second, there’s the presence of “anchor companies,” which provide direct jobs in manufacturing major components and open the door to industries further down the supply chain. Of the five existing potential anchor companies listed in the March report, three have a major presence in northeastern North Carolina.
One is Avangrid, which also operates the state’s only land-based wind farm, just outside of Elizabeth City. Based in Virginia Beach, Ashley McLeod directs stakeholder engagement for the company’s Kitty Hawk project. At the conference, she stressed its expected boon: a $2 billion economic impact.
At the same time, the former school board member sought to assure the audience her company would protect the natural environment during siting and construction. “We’re making sure we’re doing it in the most responsible way,” she said.
Another potential anchor in the area is L.S. Cables, a New Jersey company with a facility in Tarboro, just east of Rocky Mount in Edgecombe County, the most economically distressed in the state.
The company already supplies onshore wind and solar projects in the United States, according to the March report, and the Tarboro factory could, “possibly with some modifications, play a key role to support the ocean cable needs” of offshore wind.
Perhaps most promising is Nucor Steel, the largest U.S. steel producer in the country, with headquarters in Charlotte and a sizable facility in Hertford County.
“They very much want to be part of constructing the towers,” said Amy Braswell, the economic development director of Ahoskie, the county’s largest town, population 4,659. The interest is already having a ripple effect. “We’re contacted by people who want to be in proximity to Nucor,” she said, “to work with them.”
The county’s economy could undoubtedly use more than a ripple. The 10th most economically distressed in the state, it has a median household income of $38,000 and an unemployment rate of over 6%.
“I think it’s going to be a boon for eastern North Carolina and eastern Virginia,” said Braswell of the offshore wind industry. “It’s going to be a boon for the citizens who are going to get really good jobs.”
The area’s numerous rivers and sounds could serve to transport large components by barge up to Virginia ports and down to North Carolina ones. The area also has a network of railroads and highways that ease transport.
“We are not as susceptible to storm damages and things that you have to worry about closer to the coast — yet we are an hour from anything,” Braswell said. “We think we’re ideally situated for it.”
Still, these economic opportunities could be limited if North Carolina misses its offshore wind targets set by Cooper — not an impossibility.
While the federal government is moving forward on a lease area 17 miles off the state’s southernmost shores, it will have to overcome opposition from over half a dozen local governments who oppose any turbines beachgoers might glimpse from the sand.
At the same time, a Trump-era ban on offshore wind, set to take effect next July, must be lifted by Congress for any other wind energy areas off North Carolina’s coast to come to fruition. The Build Back Better bill contains language that would do just that, but its fate is still uncertain.
Fulfilling Cooper’s targets will almost certainly require additional state-level legislation, said Simmons. Even with a new law requiring a 70% reduction in Duke Energy power plant pollution by 2030, the state probably needs specific mandates for offshore wind to draw development off its coast and supply chain jobs with it.
“This is such a new industry that we’re bound to get part of it,” she said, “but it will require a designated effort for North Carolina to capture what we know is economically possible.”
While the AFL-CIO is optimistic about the possibilities for union jobs, those odds increase if federal or state policymakers tie green energy incentives to the opportunity to be in a union.
“We can remake the economy to benefit working people and the planet and to grow the labor movement,” Graham said, “but it’s not a foregone conclusion.”
The degree to which northeastern North Carolina benefits economically from offshore wind will also depend on how well prepared residents are to work in the industry. That’s why boosters say training programs at community colleges and at historically Black universities such as Elizabeth City State are critical.
“Education is important,” King said. “Don’t bring in people from outside — we want to see those dollars flow in our communities.”
The Cooper administration has already dipped its toes into these waters, working with Halifax County schools to create a pilot program for 20 high school students to work in solar and wind energy and earn course credit toward a bachelor’s degree.
“The Governor’s Office and other partners are working to expand this program to include additional school systems, companies and industries — including offshore wind,” spokesperson Jordan Monaghan told the Energy News Network in an email.
King, who with Simmons and other clean energy groups is part of a new coalition to promote offshore wind, remains cautiously optimistic.
“We’re on the cusp of a clean energy revolution,” he said. “We have the opportunity to produce some real, high-earning jobs for people, that can change people’s lives. But it doesn’t happen overnight — you have to prepare people for it.”
Shipbuilders in the port city of Brownsville, Texas, are nearing the halfway mark on shaping 14,000 tons of steel into a vessel designed to ensure the country’s gamble on offshore wind is less dicey.
Meanwhile, 1,676 miles east in Virginia, executives with Richmond-based Dominion Energy who ordered the ship have their fingers crossed.
They are hopeful home-state regulators will greenlight a request by their subsidiary, Dominion Energy Virginia, to deploy the $500 million colossus to “plant” the country’s hugest — and Virginia’s first — full-scale commercial offshore wind farm beginning in summer 2025.
Dominion has dubbed its hulk Charybdis, after the daunting sea monster of Greek mythology. Eventually, the brawny, 472-foot-long vessel will be equipped with sturdy “legs” that stabilize it on the seafloor and a main crane capable of toting 2,200 tons — the equivalent of 4,400 grand pianos.
The looming challenge of efficiently securing 176 mega-turbines to the ocean floor off the coast of Virginia Beach is what prompted the parent company to dip its corporate toe into ship construction.
After enduring a convoluted but ultimately successful process to install its precursor two-turbine pilot project in 2020, Dominion decision-makers are confident that investing in the nation’s first specialized installation vessel is wise — and potentially lucrative.
“The pilot helped educate us,” said Charlotte McAfee, director of construction projects at Dominion who has guided progress on Charybdis since early October. “It showed us that this commercial project is really best managed with a vessel with a U.S. flag.”
Even if the State Corporation Commission nixes the utility’s proposal for Charybdis to install what’s known as the Coastal Virginia Offshore Wind (CVOW) project, Dominion doesn’t expect the giant expensive ship to sit idle.
In fact, it is already chartered to handle turbine installation duties for two separate offshore wind projects in the Northeast slated to be completed before Dominion’s 2,640-megawatt farm.
As well, Dominion figures Charybdis can continue to be a workhorse as the Biden administration has set a goal of reaching 30 gigawatts of wind power by 2030 along the Atlantic and Gulf coasts and in Pacific waters.
“Dominion has really been pioneering on this front,” McAfee said. “I’m proud to be part of it.
“We’ll find good uses for the vessel whether we’re permitted to use it for CVOW or not. The market is ready for the whole United States and this is the best way to install renewable energy.”
One monumental hurdle to harvesting the ample wind along U.S. coastlines is the lack of homegrown industries that craft the foundations, blades, nacelles (which house the generating parts) and other distinctive components fitted together to create the sophisticated turbines. Now, they withstand lengthy and expensive journeys from Europe, where the industry has matured.
Another key obstacle is the obscure Merchant Marine Act of 1920. Known as the Jones Act, it shields domestic shipbuilding enterprises by restricting water transportation of cargo between U.S. ports to American-built and -owned vessels crewed by U.S. citizens.
Charybdis represents Dominion’s commitment to advancing American offshore wind out of its longtime infancy.
Offshore wind is crucial if the investor-owned utility’s portfolio is expected to achieve 100% carbon-free electricity generation by 2045, as required by the 2020 Virginia Clean Economy Act. The utility is also intent on reaching net-zero carbon dioxide and methane emissions goals by 2050.
The Coastal Virginia Offshore Wind project, scheduled to go online in 2026, will power the equivalent of 660,000 homes.
Karl Humberson, a marine engineer hired by Dominion in 2011, oversaw progress on Charybdis before McAfee inherited those duties. He is responsible for the installation and construction of the wind farm.
Four years ago, the company tasked Humberson with exploring potential turbine installation solutions. In May 2020, Dominion announced it was leading a consortium to build a Jones Act-compliant vessel. By autumn, the company had contracted with the global firm KeppelAmFELS to build Charybdis in Texas.
Humberson is aware insiders and outsiders are curious why an energy company took the initial plunge on a vessel that might not even ply Virginia’s coast.
“Let’s take a couple of steps back and look at CVOW,” Humberson said. “The idea is that this is something necessary and aligns with Dominion’s renewable energy and sustainability goals.”
Investing in a “purposeful vessel,” he said, is a boon for all U.S. players intent on advancing wind.
“If you want to be successful, you want to have the right tools,” Humberson said. “What we’re saying is to expand the industry, here’s the only right way we know to do it right now.”
Assembling and installing the pilot — a pair of 6-megawatt turbines in federal waters adjacent to the larger wind farm — was a logistical headache due to lack of a Jones Act-compliant ship.
First, the components manufactured in Europe made a transatlantic journey on a cargo ship, the Bigroll Beaufort, which docked in Halifax, Nova Scotia.
There, the foundations were offloaded onto an installation vessel, the Vole-au-vent, and transported to the construction site off the coast of Virginia. Then, that same vessel completed a second trip from Canada with the turbine components on board.
“This time, we’ll have 176 turbines, not two, so coming down from Canada would not make a lot of sense,” Humberson said.
Without Charybdis in the picture, an alternative method is to put the components on a barge and transfer them to an onsite European vessel that could serve as the installation base.
“Using a barge and tugboat means double-handling everything,” Humberson said, emphasizing that turbine blades are fragile. “If you need to move this equipment, you want to do it once and you want to get it right.”
One of Charybdis’s benefits is providing an extremely stable work platform whether seas are calm or choppy, he said.
The height and weight of components are serious considerations. For instance, blades for the pilot project measure 253 feet. The monopile foundations are 220 feet long and weigh 1,000 tons apiece.
Those measurements are diminutive when compared to the heavy lifts in store with the commercial project. For instance, the turbines — the largest available — have a capacity up to 14.7 MW. Just one of those turbines has more generating capacity than the entire pilot project.
A blade alone measures 354 feet — longer than a football field. And just the visible part of each turbine is skyscraper height, stretching a soaring 800 feet from the top of the ocean to the tip of a blade pointed straight up.
David McFarland, Dominion’s director of investor relations, knows $500 million is a whopping price tag for anything, never mind a unique Jones Act-compliant ship.
“What Dominion Energy is doing is showing confidence in the offshore wind industry” and opportunities for it to thrive domestically, McFarland said.
The question he fields most often: Who is footing that bill?
It’s not ratepayers — at least not directly. Instead, the ship is being built for the mammoth parent company that owns multiple subsidiaries nationwide, including Dominion Energy Virginia.
The majority of capital for funding Charybdis is being borrowed from third parties and banks, McFarland explained, adding that “making payments to banks is a shareholder expense, not something passed on to a utility customer.”
Leasing out Charybdis to other coastal wind projects allows the parent company to reap a return — somewhat indirectly — on that $500 million investment.
For instance, Dominion Energy Virginia has folded the cost of leasing — not building — Charybdis into its request before state utility regulators seeking the go-ahead for the entire $9.8 billion wind farm project.
“That lease is included in the cost of [the wind farm’s] construction,” McFarland said. “It’s spent on behalf of customers and is expected to be recovered from customers. Dominion Energy Virginia is looking to recoup that money.”
He is convinced Charybdis is a boon for the company’s utility customers.
“They’re better off with this vessel, because otherwise the cost [of turbine installation] would be higher,” McFarland said. “You do want the best solution for customers.”
Charybdis is on track to be completed on schedule by December 2023, McAfee said.
Thus far, Ørsted and its joint venture partner Eversource, are the first to book Charybdis for its Revolution and Sunrise wind projects. Their construction and operations plans are undergoing environmental review now.
Revolution is a 704-megawatt project designed to serve customers in Connecticut and Rhode Island, while Sunrise will provide electricity to New Yorkers. Both are expected to be operating by 2025.
Ørsted, a global leader in the wind industry, has also partnered with Dominion on both of its wind projects.
Dominion said it was unable to provide figures for the daily rental fee required because those numbers are “competitively sensitive.”
Willett Kempton, a professor at the University of Delaware who is a nationally renowned expert on offshore wind power, said wind developers negotiate those fees with Dominion.
Kempton said in an interview that he had heard from industry sources that those daily rates could be as high as $500,000, but didn’t know how accurate that number will turn out to be.
The daily fee for using a non-U.S.-made installation vessel is likely close to $250,000, he said.
While $500 million is a hefty sum to invest in a vessel with Charybdis’ capabilities, Kempton said somebody had to go first seeing as “this is the only way the industry knows how to do installations.” One such installation ship likely won’t be enough if the U.S. wind industry booms as expected, he added.
Companies without access to Charybdis or a similar vessel will likely resort to a feeder barge system as a stopgap solution to keep their wind projects on schedule, he said.
The Department of the Interior’s Bureau of Ocean Energy Management has approved construction and operations plans for two other offshore projects: 800-megawatt Vineyard Wind in Massachusetts and 130-megawatt Southfork Wind in New York.
By 2025, the agency has vowed to advance new lease sales and complete review of at least 16 construction and operations plans, which represent more than 19 GW of renewable energy.
Charybdis will be based in Hampton Roads and staffed with U.S. crews. It’s one enormous piece of Virginia’s attempt to transform its existing regional advantages — a robust maritime workforce and a port in Norfolk with deep water and no height restrictions — into a supply chain hub.
“The supply chain is in Europe,” Humberson said. “There’s a lot of talk about building it up in this country, but it’s not here yet.”
As evidence, he pointed to Germany, Denmark, Finland and Italy as sources for turbine components and affiliated infrastructure. Most of it is destined for a 72-acre site at the Portsmouth Marine Terminal. That space will serve as a staging and pre-assembly area, courtesy of a 10-year lease with the Virginia Port Authority.
The terminal also will house a blade-finishing factory operated by Siemens Gamesa Renewable Energy, the company contracted to deliver the 176 CVOW turbines. That work entails sanding and adding protective coatings to the prebuilt blades.
Beginning in 2024, while Charybdis is readying for the two wind projects in the Northeast, Dominion plans to begin driving turbine foundation monopiles into the ocean bed at the 112,800-acre CVOW lease area. The site begins 27 miles offshore and extends 15 more miles out into the Atlantic.
The largest of those 176 steel monopiles, manufactured in Germany by EEW Special Pipe Constructions, is 268 feet long and weighs 1,755 tons. Into 2025, a separate company will transport, position and secure those foundations without the aid of Charybdis.
To protect the North American right whale, the window for that underwater chore is between May 1 and Oct. 31, per National Oceanic and Atmospheric Administration regulations.
When Dominion’s McAfee graduated from law school at Washington & Lee University in 2004, she figured pumps and suits would dominate her career wardrobe.
That changed after the young attorney was hired by the utility a decade ago. Eventually, she began amassing steel-toed boots as she pivoted to electric transmission and distribution projects.
Those boots are again serving her well for her regularly scheduled trips from Richmond to the Brownsville shipyard to monitor Charybdis’ progress.
“It’s not like I’m inspecting the welds, but I’m getting a sense of what I need to be coordinating at the shipyard,” she said. “In-person visits keep the communications open and candid.”
Devotees of Homer’s ancient and epic poem “The Odyssey” know that the mega-ship’s ferocious namesake lurked in a narrow passage between the island of Sicily and the toe of Italy’s boot. The monster was reputed to swallow the sea three times daily, causing a whirlpool that thwarted the protagonist as he sailed home from the Trojan War.
Part of McAfee’s job is ensuring that this version of Charybdis doesn’t wreak any such havoc before it’s ocean-bound.
So far, so good, despite two challenges. One was covering for her lack of maritime experience by burrowing into volumes about shipping. And the other was navigating an immense undertaking in the thick of a pandemic.“As far as the construction goes, Charybdis is a teenager now,” she said. “It’s just an honor to be involved. Once we’re finished, it will be ready to self-propel to Hampton Roads.”
As Maine comes close to finalizing its roadmap for the development of offshore wind, a coalition of labor and environmental groups is asking the state to strengthen its commitment to supporting union jobs in the burgeoning industry.
A group of 12 environmental and labor organizations has sent a letter to the Maine Offshore Wind Roadmap Advisory Committee asking that the final plan, expected by early February, incorporate explicit language recommending the use of project labor agreements and labor peace agreements as the offshore wind sector develops in Maine. Many of the same advocates are supporting a bill, announced by Democratic state Sen. Mark Lawrence last month, that would require union labor agreements on offshore wind projects.
“Organized labor needs to be a crucial part of this investment,” said Kelt Wilska, energy justice manager for Maine Conservation Voters. “And we need to make sure working families, both coastal and inland, benefit from this.”
As states from New England down to North Carolina work on their own plans for implementing offshore wind projects, Maine is expected to be a major player in the growing industry. With strong, consistent winds, the Gulf of Maine is widely considered to be one of the most promising areas for offshore wind development.
Maine convened its Offshore Wind Roadmap Advisory Committee in July 2021 with the mission of creating an economic development plan for the fast-emerging industry. The panel — which includes 25 members representing state and municipal governments, private business, community and environmental nonprofits, and organized labor — released its draft plan in early December.
The document outlines strategies for investing in infrastructure and workforce development; reducing costs and increasing resilience through renewable power; advancing Maine-based innovation; and protecting and supporting the seafood industry, coastal communities and the ocean ecosystem. Labor and environmental groups have praised much of the plan, particularly its focus on comprehensive planning, workforce and supply chain investment, and environmental monitoring and mitigation.
The draft roadmap, however, mentions unions and organized labor just three times, and not with any detail — an omission that some find problematic. It is essential that offshore wind jobs offer fair wages and benefits, as well as industry training and plans for worker safety, said Francis Eanes, executive director of the Maine Labor Climate Council, one of the groups that signed on to the letter to the roadmap committee.
“All those things are most effectively accomplished when workers can come together with each other in the form of a union,” he said. “It’s not rocket science here.”
Specifically, the letter’s signatories would like to see the roadmap call for the use of project labor agreements and labor peace agreements. Project labor agreements are pre-hire collective bargaining agreements that set the terms and conditions for the temporary employment of workers on a given construction project. A labor peace agreement is an arrangement in which an employer agrees to remain neutral should its permanent workers choose to form or join a union.
Robust union participation is the best way to make sure the economic benefits of the offshore wind industry are shared with working families, supporters argue. And, they say, project labor and labor peace agreements are the best way to ensure union labor is used in the construction, operation, maintenance, and supply of offshore wind. But the current roadmap language doesn’t reflect this urgency, said Jason Shedlock, regional organizer with the Laborers’ International Union and president of the Maine State Building and Construction Trades Council.
Representatives from the state’s energy office declined to comment as the roadmap development process is still ongoing. However, documents distributed to participants in a January 18 meeting of the committee noted that, “This is an all hands on deck moment — labor will be key, as will other actors — we don’t want to send signals of people being excluded.” The materials also indicated that the committee would possibly add to the roadmap a description of project labor agreements as an example of the kind of arrangement the state is looking for, but without going so far as to recommend or mandate these agreements.
“There is more wiggle room than we’d like,” Shedlock said.
The roadmap is already informing offshore wind legislation: Lawrence’s bill was heavily influenced by the recommendations in the draft document. The bill goes further than the roadmap on labor as it requires project labor agreements, but has a long way to go to become law. Advocates want the roadmap to call for similarly strong measures.
Using non-union contractors would prevent Maine residents from taking full advantage of the opportunities provided by offshore wind, Shedlock said. To meet the needs of such large projects, smaller, non-union companies would inevitably need to bring in temporary, out-of-state workers — workers who would then head home, contributing little to Maine’s long-term economic development, he said. Unions, on the other hand, have the resources and structures in place to recruit and train a substantial in-state workforce, he said.
“These are the partnerships we have in place,” Shedlock said. “This is the capacity that we bring.”
Formal union agreements have emerged as a significant feature of offshore wind projects. In Massachusetts, in 2021, the Vineyard Wind project signed a project labor agreement committing to use exclusively union labor. In May 2022, major offshore wind developer Ørsted announced an agreement to use American union labor to build all of its U.S. wind projects.
It would be a mistake for Maine not to follow this precedent, especially given the pressing nature of the climate crisis, Shedlock said.
“For Maine to think that they can do it differently than everyone else is only going to waste time,” he said.
Though these commitments have been widely hailed, not everyone is sure they are good for equity and diversity. When Vineyard Wind announced its project labor agreement, for example, some workforce diversity advocates declared the commitment would work against the goals of nurturing diversity and inclusion in the industry. Organized labor has a history of racial exclusion, they noted, and the majority of small construction businesses owned by people of color are non-union and would therefore be shut out of opportunities.
Labor advocates in Maine acknowledge this history, but say they are working hard to build opportunities for a diverse range of Mainers. The Maine Labor Climate Council has partnered with the Maine AFL-CIO to create a pre-apprenticeship program that will actively seek out participants from underrepresented groups. The program will help recruit and prepare potential workers for taking on an apprenticeship in the trades by teaching them soft skills and familiarizing them with unions. To help potential students overcome barriers to participation, stipends will be available to help pay for child care or transportation.
“It’s a model that is a really successful approach for bringing people currently and historically underrepresented into the union apprenticeship programs that we know lead to high-quality, stable careers,” Eanes said.
Advocates will now have to wait to see what language is included in the final version of the roadmap. Regardless of what emerges, however, they are committed to pushing the state to commit to organized labor in the long run.
“We really have one opportunity to get this right,” Shedlock said. “If we don’t employ local labor with good, family-sustaining jobs, that’s an unforced error right from the beginning.”
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