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November 16, 2024

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Vineyard Wind 1 Aims to Start Exporting Power This Year

With its substation now in place off the Massachusetts coast, Vineyard Wind 1 expects the first electricity to start flowing to land before the end of this year.

Avangrid last week provided an update on the landmark offshore wind project, which has been the subject of years of intensive planning but saw its first “steel in the water” only in June.

Several monopile foundations for turbine towers have been fixed to the ocean floor, and Avangrid announced Thursday that the substation has been placed on its four-pile jacket foundation, roughly a dozen nautical miles south of Martha’s Vineyard.

The Danish-built substation now looms over nearby vessels but soon will be dwarfed by the towers nearby.

It will give up nothing in bulk, however, weighing in at more than 6 million pounds.

Manufacturer Bladt Industries said the combined weight with its foundation is roughly 10.4 million pounds — equal to 2,300 of the Tesla Model Y cars Vineyard Wind 1 eventually will help charge.

Avangrid said in a news release that this is the sixth and largest substation in the fleet installed by parent company Iberdrola, which previously has placed units off the coasts of France, Germany and the United Kingdom.

It also is the first offshore wind substation installed in U.S. waters.

Vineyard Wind 1 and South Fork Wind are racking up a series of firsts in the emerging U.S. offshore wind sector this spring and summer as a flotilla of construction vessels large and small plies the waters south of Massachusetts and Rhode Island.

One of the two will become the first commercial-scale offshore wind farm in the U.S. Or perhaps both will claim the honor with an asterisk — first to produce current and first to reach full power.

South Fork has an edge: It is less than one-fifth the size of Vineyard.

(South Fork’s substation is relatively svelte, at only 3 million pounds — but it was the first offshore substation ever built in the US.)

The two are roughly 30 nautical miles apart in the patch of the Outer Continental Shelf that the Bureau Of Ocean Energy Management has divided into multiple wind leases.

Vineyard, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners, will have 62 turbines with a nameplate capacity of 806 MW and will feed into the grid in Massachusetts.

South Fork’s 12 turbines will have a capacity of 132 MW and feed into the New York grid. It is a joint venture between Ørsted, the world’s largest offshore wind developer, and New England utility Eversource, which is looking to sell its share of South Fork and other offshore projects.

Avangrid, Ørsted and other developers have run into major financial problems with other offshore wind projects they are pursuing in the Northeast, because of soaring costs and interest rates.

But Vineyard and South Fork already were far along in the process by the time those costs started rising.

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RF Workshop Hears Lessons from ‘Close Calls’

Utilities can learn as much from their close calls as from their emergencies, but everything depends on the approach they take, presenters said at ReliabilityFirst’s annual Human Performance Workshop on Thursday.

A team from New York-based vegetation management company Lewis Tree Service joined the webinar to share some insights from their close call program, which the company began in 2019. The company defines close calls as events in which an injury or property damage almost occurred, but was prevented either by employee intervention — what the company calls a “good catch” — or events outside their control, which are dubbed “got luckies.”

The company, which has more than 4,000 employees, provides vegetation management services to investor-owned utilities, municipal electric utilities and cooperatives in 27 states.

Beth Lay, Lewis Tree’s director of resilience and reliability, compared the program to NASA’s Aviation Safety Reporting System (ASRS), which launched in 1976. Lay called the ASRS “groundbreaking” for allowing “good faith mistakes and procedural violations” to be reported without punishment. Lewis Tree wanted to create a similar culture of mutual support and information sharing among its employees.

“What we’re trying to accomplish here is [creating] a learning organization where we’re not only learning from our incidents [of injury or damage], but we’re learning from the day-to-day work that’s going on out there, and what our folks [are] encountering and the challenges that they’re adapting to every day,” said Bret Kent, the company’s training manager.

Overcoming Employee Reluctance

At the close-call program’s launch in 2019, Lewis Tree recognized that its workers already understood that close calls could be useful:  employees frequently shared such stories among themselves informally. The challenge was collecting and storing the data systematically so that it would provide the most benefit to the company, while convincing workers that they would not be punished for sharing their experiences.

The company started by defining the information it wanted about each event. Kent said this boiled down to three questions: “What happened, what surprised us and what did we learn that would help others?” This was also the stage at which Lewis Tree identified the “good catch” and “got lucky” categories. While some organizations’ close call programs focus on the second type of incident, Lewis Tree’s leadership felt that incidents in which employees successfully averted injury or damage could also be valuable for training purposes.

Bret Kent, Lewis Tree Service | ReliabilityFirst

Next, management introduced the program to employees. The rollout initially took the form of what Lay called “close call mining,” in which leaders met with field workers to ask for their stories about memorable events they had witnessed.

Lay described these sessions as informal “tailgate” sessions featuring questions such as “what experience do you always share with a new teammate,” “what’s the scariest experience you’ve had during storm restoration” and “if your chaps [protective clothing] could talk, what would they say?” — a suggestion of Lewis Tree’s COO. The questions were calculated to put employees at their ease.

“It allowed people to share scary, dangerous things that they had seen in the past without fear of any repercussions,” said Kent. “It wasn’t something that they were afraid of reporting because it [had] just happened. … That was really the key to beginning to build trust for people to share openly about what was actually happening on the front line.”

As workers got more comfortable with the program, the company began to move its focus toward reporting more recent incidents. It introduced a smart phone app and a standardized reporting form; submissions are collected into a weekly report and notable incidents are discussed in regular conference calls with management.

Putting Faces to Reports

One area in which Lewis Tree’s close call program differs from similar initiatives at other organizations is that names are always attached to submissions. Kent acknowledged that this step could be intimidating for employees reporting incidents in which they may have made mistakes, but said it was vital to maintain the supportive atmosphere the company desired. Attaching names to reports meant that managers could ask follow-up questions to delve deeper into the event.

In the case of particularly noteworthy reports, management may ask the employee who submitted it to review the event with them. Brian Temas, an area manager with Lewis Tree, recounted a call in which his employees discussed a near-injury by a falling tree. He described management’s attitude as appreciative of the workers;  the employees reported that they felt “jazzed” to be included in the review.

“One of the things that we … found very useful was asking the question, ‘What were our workers trying to accomplish here?’” said Temas. “That can sometimes feel as though it’s a loaded question, but through our process … we were able to get our team to understand that this was an honest question to … help not only our leadership team, but everyone on the call.”

The company considers the close call program to be a major success; while just 317 reports were received the first year, Lewis Tree received nearly 3,000 reports in 2022 and so far this year has gotten more than 3,500. Lay urged organizations considering a similar program to keep things as collegial as possible.

“I’ve heard that [for] some organizations, just like … they link mandatory corrective action programs to an incident [of injury or damage], they may think about doing the same [for] the close calls,” Lay said. “I would recommend against it, because I think that would really inhibit people from submitting close calls.

“What happens in these learning conversations is … different leaders in our organization sharing, ‘Hey, here’s a good practice for this’ … and the [employee] who submitted the close call walked off going, ‘I’m going to try these things,’” Lay continued. “Well, multiple other leaders on the call will walk away with those as well.”

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DOE Opens Applications for $8.5B in IRA Home Efficiency Funds

The Department of Energy wants to give $690 million to Texas for home energy efficiency rebates. But for Texas and the 49 other states, D.C. and U.S. territories, getting those funds will require a complex application process and careful implementation to ensure the money actually helps consumers get big cuts in their utility bills.

Texas qualified for the most money out of the $8.5 billion in efficiency rebates from the Inflation Reduction Act, which state energy offices can now apply for, DOE announced July 27.

The IRA split the money roughly evenly between two programs: The Home Efficiency Rebates Program will help fund “whole-home” upgrades, and the Home Electrification and Appliance Rebates Program will provide rebates on major home appliances, such as electric heat pumps and stoves.

Depending on income, consumers doing whole-home upgrades may be eligible for rebates of up to $4,000 or 80% of project costs, whichever is smaller. The appliance rebates range from $840 for an electric stove to $8,000 for a heat pump for space heat or cooling, up to a maximum of $12,000 per household.

DOE is estimating total consumer savings of $1 billion over the life of the programs, which will run through Sept. 30, 2031.

“Americans living in energy-efficient, electrified homes bring us one step closer to a cleaner, safer future,” Energy Secretary Jennifer Granholm said in the announcement.

Promoting home electrification has become a hot-button issue in Congress and in certain states where legislatures have passed laws prohibiting any bans on natural gas hookups. DOE treads carefully on the issue, stating the rebate programs “will offer support and incentives to consumers to retrofit and electrify their homes, without banning or restricting the use of other technologies.”

At the same time, the programs are aimed at growing the market for energy efficiency and electrification, with states required to submit market transformation plans as one step in a phased application process that releases the funds in four stages.

The funds can only go to state energy offices, and the dollars involved are significant, with more than half the states receiving more than $100 million. After Texas, California comes in second with $582.2 million, while at the bottom of the list, American Samoa and the Northern Mariana Islands are slated for $49.9 million and $49.8 million, respectively.

DOE is asking states and territories “to prioritize households that stand to benefit most from the funds, including allocating at least half of the program funds to reach households with incomes at or below 80% of their area median income,” according to the announcement.

But states will probably vary in their ability to apply for and channel the money to their residents, said Lowell Ungar, director of federal policy at the American Council for an Energy Efficient Economy.

“There are some states that have very substantial [energy efficiency] programs already. They have infrastructure in place to design programs; they have contractors to implement them,” Ungar said. Other states “have new programs or no programs and small state energy offices. They’re going to have more difficulty. It’s going to take them longer to set these programs up.”

So far, only one state, Florida, has signaled it will turn down the IRA funds. Gov. Ron DeSantis (R) directed the state’s energy office to notify DOE it will not apply for any of the $346.3 million that the state is eligible for. (See DeSantis Rejects $346 Million in IRA Energy Efficiency Funds.)

States have until Aug. 16, 2024, to let DOE know if they are going to apply for the money and until Jan. 31, 2025, to submit an application, according to a department spokesperson. If Florida or any other states do not apply for their allocations by that date, the money will be split among the other states.

The Requirements

Getting the money involves a four-step process for each program, as spelled out in extensive detail in a 100-page document.

Approval of an initial application releases 20% of a state’s allocation and triggers a second phase in which an implementation blueprint must be submitted at least 60 days before a program launch. Approval of the implementation plan releases another 35% of the funds.

A market transformation plan is required for the next 25%, followed by quality assurance plans and program reviews for the final 20%.

The whole-home energy rebates are particularly complicated, as they can be based either on a contractor estimating energy savings based on computer modeling, or actual performance, in which savings are measured over time.

With the programs’ focus on low-income households, having systems in place to verify homeowners’ or renters’ incomes will be another big challenge.

DOE has promised a range of support measures, from sample responses to application questions and one-on-one meetings, to targeted analysis to help states design programs to reach “specific housing, climate or economic objectives.”

States also can apply for special “early administrative funds” to help them with the application process; according to a DOE spokesperson, dozens of states have applied. A state may apply for up to 2.5% of its allocation for each program, with a cap of $2.5 million if they apply for the funds for one program and $5 million if they apply for the funding for both, the spokesperson said.

Any early funding will be subtracted from a state’s total allocation, but states are also allowed to use up to 20% of their total allocation for administration and implementation.

An additional $150 million in IRA funding is available to states for grants to help with contractor training in home energy efficiency. DOE issued guidelines for this program in mid-July, with applications for the grants due by Sept. 30.

As Ungar noted, this extra support may be especially needed for states with small energy offices. Ohio does not have a separate energy department to manage the $249 million the state could receive. Rather, the state’s energy efficiency programs are housed within the Department of Development.

Brian Bohnert, the department’s public information officer, said the staff is “well equipped” to handle the funding. But, he said, they have applied for early administration funds and are working on an application for the contractor training grants to “ensure a smooth rollout of the rebate programs, as well as guarantee we have the sufficient workforce to best address the needs of Ohioans.”

The States

State energy offices began talking about the IRA’s energy efficiency money almost from the moment President Joe Biden signed the law on Aug. 16, 2022. What it will take to implement these programs effectively and efficiently also has been a hot topic at energy industry conferences, with concerns raised about a range of issues, from the staff that will be needed, to workforce training and consumer education.

David Terry, president of the National Association of State Energy Officials (NASEO), says his members are ready, but the complexity of the rebate programs will require a certain amount of flexibility in how they are implemented. While state energy offices have handled multimillion-dollar federal programs in the past, he said, “what is new and different is [that] residential energy efficiency is a complicated task.”

Housing markets vary widely within states and nationally, Terry said. “By that I mean housing type, structure, the quality from a maintenance or structural perspective; the climate zone for weatherization ― hot and cold and humid,” he said. “Some technologies that make sense in Ohio or Virginia don’t make sense in Hawaii or Puerto Rico.”

Nick Burger, deputy director of the Energy Administration at D.C.’s Department of Energy and Environment (DOEE), said his office has been doing “a lot of planning” for the $59.4 million coming to the nation’s capital. But, he said, “there are limitations to what we’ve been able to do up until this point because we were, like everyone else, waiting on more detailed guidance from the Department of Energy.”

For D.C. a major challenge is figuring out how to use the IRA money to build on the city’s existing programs, without replicating them, Burger said. “We’ve had a multifamily electrification and efficiency program up and running here for almost two years, so we have some sense of what it costs to sort of make transformative change,” he said.

DOEE will be collaborating with the DC Sustainable Energy Utility, which runs a range of energy efficiency programs in the city, and the Department of Housing and Community Development, he said. The D.C. Council also is considering a bill called the Healthy Homes and Residential Electrification Amendment Act (B25-0119), which would set a target for the city to provide residential electrification retrofits for 30,000 low-income households at no charge to residents by Dec. 31, 2040.

DOEE will likely need to bring on additional workers for the IRA programs, but Burger said the department is well staffed so “we at least have the ability to sit down and start thinking through in some detail how we want to create and implement a program.”

“It’s one thing to make these upgrades free for households; that’s important,” he said. “But in my mind … the second step is to make sure that they’re getting through the whole process of auditing a home, identifying what the upgrades are that the home needs, helping the household or the homeowner navigate the process of working with a contractor, doing the paperwork. These are all steps that aren’t even about money,” he said.

Burger also cautioned that as big and welcome as the federal dollars are, they are not sufficient. DOEE has identified 100 multifamily dwellings that need upgrades, and he said about 67% of the city’s 170,000 rental units are more than 45 years old.

“When you think about a single-family home, we’re talking about replacing all of our gas appliances and upgrading our old-fashioned air conditioners and ideally making the home more energy efficient,” he said. “As we do that, the total cost per house could be $30,000 or more. … For the kind of scale of change that we would like to see, it’s going to take more resources.”

Contractors and Consumers

While state energy offices will apply for and administer the rebate money, contractors will likely be the main point of contact for getting consumer buy-in for the programs.

Speaking during a media call on Tuesday, Steve Skodak, CEO of the Building Performance Association (BPA), said his organization and its members have been calling for federal funding for rebate programs and worker training for the better part of a decade. The IRA energy efficiency funds are widely seen as unprecedented and a potential economic bonanza for the industry.

But, Skodak said, “a lot still needs to be decided at the state level before these funds are put to use.”

The IRA’s funding for contractor training also comes with a complicated application process, beginning with a state-level needs assessment to identify “the gaps in the industry where workforce needs to be and how to get them trained,” said Robin Yochum, BPA’s state outreach coordinator.

Similar to the rebate funding, the training funds will be allocated to individual states based on a formula and will be awarded in two phases, with half paid out after an application is accepted and the remaining half following a program evaluation and update.

Yochum acknowledged that even with the training funds, building up a workforce will take time. “Some of the certification programs can take six months to a year to get somebody fully trained, depending on where they want to go,” she said. “We can start out with basic building science principles training, get them in the door … and then they can move up and do the rest of the certification program.”

But Burger said the technical training is only part of what’s needed. “There’s also kind of a mindset piece,” he said: “working with our contractors who have spent the last 20 or 30 years doing excellent installations of gas furnaces or traditional air conditioners and helping them understand the new technologies — why they’re good; why they work — because I think there are a lot of misconceptions.”

BPA and its members are focusing more on selling homeowners on the whole-home upgrades, but Terry thinks the electrification and appliance rebate program may be simpler for states to roll out first.

At the same time, he said, NASEO members “have been crystal clear [that] efficiency, as in insulation and proper air sealing, comes first so that whatever form of heating and cooling is used, that [utility] bill does not go up,” especially in colder climates.

“The states are keenly aware of the importance of consumer protections around both these programs” to ensure any home upgrade, be it insulation, a heat pump or water heater, is installed and functions properly, Terry said. Mechanisms will be needed to “address things that will go wrong ― as you know, something always goes wrong ― and how you make sure that gets rectified.”

Both he and Burger stressed that getting the programs up and running will take time, and consumer expectations have to be dialed back.

“I think that inadvertently, we collectively have set this expectation that everyone in America is going to get a rebate, and they’re going to get it tomorrow morning,” Terry said. “Not many people will get it unfortunately; those that get it are those most in need.”

D.C. residents looking for rebates are going to have to “hang on a little bit longer,” Burger said. “The speed is going to be dictated by how fast the Department of Energy can get the funding out to the states, and then once we have the money, we still have to go through our process of getting authorization to spend those funds, getting them loaded into our budget.

“We’re going to try to go as quickly as we can, while making sure that we set up good programs that are likely to succeed,” he said.

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WEIM Tops $4B in Benefits Months After Hitting $3B

CAISO’s Western Energy Imbalance Market topped $4 billion in cumulative benefits for its participants in the second quarter of 2023, just six months after it topped the $3 billion mark at the end of 2022, the ISO said this week.

The WEIM generated nearly $799 million in benefits in the first half of this year, including $380 million in Q2, bringing its total benefits to $4.2 billion since it began in 2014. It reached $3.4 billion in cumulative benefits in the fourth quarter of 2022.

The market’s benefits come primarily from transfers of lower-cost energy between Western entities, as well as operational efficiencies and increased uptake of solar and wind power.

The benefits of the WEIM, a real-time interstate trading market, grew rapidly as more participants joined in recent years. It now includes 22 entities in 11 states and British Columbia that collectively represent about 80% of load in the Western Interconnection.

Those with the most benefits in Q2 were CAISO, with $70 million in benefits; NV energy, with $46 million; and PacifiCorp, with $37.5 million.

The second-quarter results were notable for the large quantities of exports from California. CAISO had net exports of 2,758,377 MWh, nearly five times as much as the next-highest exporter, Arizona’s Salt River Project, which had 564,023 MWh. NV Energy came in third with 531,979 MWh. Net exports for all other WEIM participants fell well below those figures.

Inexpensive solar energy flowing from California in the middle of the day was a likely cause of CAISO’s vast net exports. The state has been adding utility-scale solar arrays at a fast pace as it tries to meet its 100% clean energy goal by 2045.

California’s ample spring sunshine and moderate temperatures combined to produce an excess of solar energy in the second-quarter months from April to June.

CAISO statistics show that solar output peaked May 23 at more than 15,000 MW, exceeding a 14,000-MW peak in May 2022. Then, on June 13, the ISO again broke its record for solar production with 15,718 MW.

With the latest numbers in, CAISO is hoping the proven benefits of the WEIM will convince participants to sign up for its planned extended day-ahead market (EDAM). The WEIM EDAM is likely to face stiff competition from SPP’s Markets+ offering, which is planned to include real-time and day-ahead markets.

CAISO expects to file its EDAM tariff language with FERC this month. It recently announced a public EDAM Forum on Aug. 30 in Las Vegas, which it will co-host with PacifiCorp, NV Energy, Southern California Edison and the Balancing Authority of Northern California.

WEIM cofounder PacifiCorp has already committed to join the EDAM and several other entities are nearing a decision, CAISO said.

“The forum’s panel discussions will allow a broad spectrum of utility and thought leaders to delve into the potential benefits and outstanding questions regarding EDAM participation, its evolution, and how it could transform and optimize energy delivery in the future,” CAISO said in its announcement.

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Clean Energy Group Urges Utilities to Replace Peakers with VPPs

Virtual power plants can economically replace many of the country’s 217 GW worth of peaking power plants, which emit pollution like nitrous oxide and are often located in population centers, the Clean Energy Group (CEG) said in a webinar Thursday.

VPPs are portfolios of distributed energy resources that include resources like demand response, rooftop solar, smart water heaters, plugged-in electric vehicles, batteries and other resources that are controlled by utilities or independent aggregators, said Brattle Group Principal Ryan Hledik. He authored a study released earlier this year finding VPPs were the cheapest option for resource adequacy. (See Brattle Group Finds VPPs Cheapest Alternative for Resource Adequacy.)

“The idea with a virtual power plant is that a utility or an aggregator will control those distributed energy resources,” Hledik said. “And then ultimately, the control of those resources is done in an orchestrated, managed way to provide benefits to the power system.”

Using the pre-existing resources is cheaper up front than installing peaking power plants or energy storage systems, and it helps cut emissions. Those benefits are split between the firm running the VPP program and its customer participants, Hledik said.

VPPs are gathering momentum because many of the costs of the DER technologies they rely on are coming down, and the expectation is that this will continue over the long run. The Inflation Reduction Act provides incentives for many of the resources, while policies like FERC Order 2222 require markets be open to aggregations of DERs.

The industry spent $120 billion on capacity that was needed to maintain resource adequacy in the last decade, and most of that went to natural gas plants, though in recent years batteries have seen an uptick in investment, said Hledik.

Brattle’s analysis found that a utility with about 1.7 million customers could use a 400-MW VPP to maintain reliability. The VPP in that scenario would help lower load in both summer and winter, and be dispatched in seven months for a total of 63 hours, up to seven hours at one time, said Hledik.

While some utilities have adopted VPPs already, with the Upper Midwest’s Otter Tail Power and Vermont’s Green Mountain Power being listed as examples on the webinar, others are more cautious about relying on VPPs for the same level of reliability as power plants or grid-scale batteries.

“A lot of times we do encounter utilities or system operators who don’t yet trust the ability of VPPs to operate and perform the way a gas peaker might or utility-scale battery might,” Hledik said. “Just pushing the button and getting it to run is a little different when you think about the fact that there are customers on the other end of this.”

That kind of resistance can be overcome by doing pilot programs and seeing other utilities already successfully relying on VPPs, he added.

The shift to VPPs from gas-fired peakers can have major health benefits because some 154 GW of the power plants are in urban areas, and 32 million Americans live within three miles of one and their NOx emissions, said CEG’s Shelley Robbins.

“Because of the way they run, you pretty much can’t capture that NOx,” said Robbins. “Because they don’t run at a baseload level, the systems that capture pollutants don’t work on these plants.”

NOx is a small particle that easily gets into the entire body through the lungs and is associated with conditions such as asthma, inflammation, cognitive decline, Parkinson’s, Alzheimer’s, premature birth and other medical conditions.

The peaking power plants are often located in urban areas, with a map CEG produced showing their locations overlaid on the most populous areas of the country. New York City is home to about 6 GW of peaking capacity, including some plants that are more than 55 years old, said CEG President Seth Mullendore.

To grow VPPs going forward, one policy that states could adopt is what CEG calls the “Connected Solutions Model,” said its senior project director, Todd Olinsky-Paul.

“Through this mechanism, homes and businesses with batteries and other types of renewable resources can supply capacity and energy to the grid during peak demand times and also retain the use of those batteries for resilience and other needs,” said Olinsky-Paul. “And in return, they get paid by the utility; whereas the utility would ordinarily pay a peaker plant, now they’re paying participating customers for these services.”

Customers would purchase distributed resources and sign multiyear contracts with utilities to be able to dispatch them using a VPP model, he added. It is important that such programs offer some upfront equity because often the people who want to participate the most and save on their monthly bills can least afford the upfront payments for DERs.

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Constellation Expands Nuclear Clean Energy Matching

Constellation Energy championed its nuclear fleet as being ready to match clean energy load when and where it’s needed during the company’s second-quarter earnings call Thursday.

“Our businesses are essential to addressing the climate crisis, and our assets are endurable. The Inflation Reduction Act provides unique opportunities for Constellation and its investors. We believe that we will be able to use nuclear energy to produce hydrogen. We will be able to re-license our nuclear fleet to run at least 80 years without needing to replace it, and the [Inflation Reduction Act] provides, at long last, a long-term commitment that nuclear energy is part of the national security of this great nation,” CEO Joseph Dominguez said.

He said value already is being realized through an hourly carbon-free matching agreement with Microsoft to use nuclear power sourced from Constellation to reduce the carbon footprint of the company’s Boydton, Va., data center. Under the agreement, announced last month, Microsoft will receive up to 35% of its clean energy attributes from Constellation’s nuclear capability, allowing the company to procure almost the entirety of its energy from carbon-free sources when combined with other renewables.

The two companies also partnered in March to develop an hourly carbon-free energy matching program, which Microsoft will use to track its performance for the new procurements.

Dominguez said he expects more wholesale price volatility and shrinking RTO reserve margins over the foreseeable future, but he believes the company’s generation portfolio, helped by the value of its clean energy attributes, positions it well to manage the changing grid.

“Reserve margins are about as thick as they’re going to be in these markets, and as you see fossil generation being replaced with renewable generation, the underlying markets are going to be very volatile and it’s going to take a special kind of company with a special balance sheet to cover that. I think sustainability solutions also allow us to enter into longer deals with customers that really want that sort of product support,” he said.

While wholesale energy revenues were down this year, Executive Vice President Dan Eggers said Constellation thinks that will be offset by the incentives included in the IRA. He also credited the production tax credits with contributing to the company’s increased credit rating outlook from Moody’s, which went from stable to positive.

“Lower prices were offset by an increase in expected PTCs from plants without existing ZEC [zero-emission credit] programs, reinforcing the downside protection the PTC provides against declining power prices,” he said.

In New York, an agreement the company has with the New York State Energy Research and Development Authority (NYSERDA) to receive ZECs for its three nuclear generators in the state stipulates that the company will return a portion of the revenue from those credits when federal incentives are available. Gov. Kathy Hochul (D) said the tax credits provided by the IRA will reduce electric rates while maintaining incentives for nuclear production in the state.

Eggers said the company saw significant year-over-year gains in the last quarter, leading it to increase its guidance range from $3.3 billion to $3.7 billion, up from $2.9 billion to $3.3 billion, raising the midpoint by $400 million.

Dominguez said nuclear generation meets all the attributes sought for green hydrogen production and he’s confident Constellation’s existing nuclear fleet will be eligible for federal incentives for green hydrogen.

“We’re having very productive conversations with the administration about means of addressing this from a regulatory standpoint so that existing nuclear can be used to make hydrogen and re-licensed nuclear plants would effectively count too,” he said.

Existing generators will be needed to meet the upcoming hydrogen demand, he said, particularly under EPA rules that require gas-fired generators to begin blending hydrogen into their fuel.

Questioned on how the company will prioritize nuclear generation for clean energy credits and producing green hydrogen, he said both can be accomplished at once. For industrial customers looking to decarbonize with hydrogen electrolyzers at their sites, he said they can buy the company’s carbon-free certifications and be eligible for federal tax credits for clean hydrogen production.

Executive Vice President Kathleen Barrón said Constellation has been encouraging onshore nuclear fuel production and pushed for the Nuclear Fuel Security Act to be included in the National Defense Authorization Act (NDAA). The U.S. Senate overwhelmingly voted to approve both the amendment and the NDAA on July 27.

Constellation’s 21-GW nuclear fleet also is to grow following a deal to buy a 44% stake in the 2,645-MW South Texas Project nuclear generator announced last month. The announcement says the company anticipates Nuclear Regulatory Commission and Department of Justice approval of the transaction by the end of the year.

Dominguez said the company views natural gas as an important bridge fuel as the nation decarbonizes and it is making investments to reduce emissions from its gas-fired generators, including blending hydrogen into its fuel and developing carbon capture technology. Constellation announced in May that it had set an industry record by operating on a blend of 38% hydrogen at its Hillabee gas generator.

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States Call for an Executive-level EJ Position at ISO-NE

High-level energy officials from Connecticut, Maine, Massachusetts, Rhode Island and Vermont asked ISO-NE to establish an executive-level environmental justice position, in a letter on Tuesday.

“At the highest level, this position would provide an EJ and equity lens to ISO-NE’s management and staff, inform the development of ISO-NE initiatives, rules and operations and engage EJ communities and stakeholders,” the letter says.

The officials said responsibilities of the position could include advising the ISO-NE Board of Directors and senior management on market rules, transmission planning, operations and new initiatives, along with performing outreach to environmental justice communities and facilitating internal training.

The environmental justice needs at ISO-NE may require multiple positions, the commissioners and energy officials said.

“As community engagement and responsibilities grow, this executive position could build out and manage additional team members providing EJ expertise to ISO-NE and enhancing community, government and industry engagement,” the letter says.

All the states represented in the letter have environmental justice provisions written into law intended to protect communities that disproportionately face the negative effects of energy infrastructure. These communities frequently are lower-income, non-white and non-English speaking. New Hampshire, which did not sign the letter, is the only New England state that does not have an environmental justice statute.

The state officials’ request came in response to ISO-NE’s presentation to the New England states in June on the preliminary operating and capital budgets. ISO-NE proposed a 21.5% budget increase for 2024 in its presentation to the NEPOOL Participants Committee. The RTO framed the budget increase in part as “ramping up its capabilities” to help facilitate the transition to clean energy resources. (See ISO-NE Considers Major Capacity Market Changes.)

“There is a gap in ISO-NE’s budget proposal and its current management team without a position reflecting EJ experience,” the letter says. “A successful clean energy transition cannot happen without community engagement and a meaningful role for EJ communities in helping to shape decisions that impact wholesale power and transmission rates and affect how the benefits and burdens of our electric system are apportioned.”

The letter acknowledged that such a position may be unprecedented at RTOs across the country.

“We understand that if ISO-NE creates a dedicated EJ position, it may be the only independent system operator or regional transmission organization in the country that has established such a role,” the state officials wrote. “We encourage ISO-NE to be first in this critical area.”

In response to the letter, ISO-NE said it is open to input from the states on environmental justice issues.

“We’ve received the letter and look forward to continuing our conversations with the New England states and stakeholders on issues related to environmental justice and the clean energy transition, both in the context of our annual budget and beyond,” ISO-NE said in a statement to RTO Insider.

Mireille Bejjani, co-executive director of the environmental justice organization Slingshot, applauded the state’s proposal, saying it’s an important step.

“ISO New England doesn’t have a track record on environmental justice; it hasn’t been something they have taken into account,” Bejjani said, noting that ISO-NE’s main considerations have been limited to cost and reliability. “The potential creation of the position is really exciting because it could change the conversations that are happening so that when reports are being put together and decisions are being made, we’re taking into account the human side of the grid.”

Bejjani said it is important to give the position real authority and decision-making power, and not to use it as justification for a business-as-usual approach. She also echoed the need to expand the role beyond a single position.

“It’s too much work for one person to manage all of the environmental justice concerns for an entire grid operator,” Bejjani said.

Susan Muller, senior energy analyst for the Union of Concerned Scientists, said it’s especially important to give environmental justice communities representation in the NEPOOL process, which was not specifically mentioned in the letter.

“The NEPOOL stakeholder process is where most of the decisions are made,” Muller said. “The person in this position should be thinking about how to make the NEPOOL process accessible to the impacted communities … right now, it would be almost impossible for most communities to participate in the NEPOOL committee process.”

Muller added a distinction must be made between outreach to energy infrastructure host communities and energy consumers. ISO-NE’s Consumer Liaison Group meets to engage with energy consumers four times a year. She added that ISO-NE is not alone among the country’s ISOs and RTOs in its historical lack of consideration of environmental justice.

In June, a coalition of climate and environmental justice organizations (including the Union of Concerned Scientists) submitted to MISO a set of “equitable grid principles,” calling on the organization to prioritize human rights, accessibility, and climate resilience in its decision-making processes. (See MISO Stakeholder Activists Propose Equity Principles.)

MISO responded by acknowledging the importance of the principles but argued that their members and state regulators were better situated to address the issues.

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Renewable Developers Challenge MISO’s Lower Congestion Limit

A group of renewable energy developers lodged a complaint at FERC last week over MISO’s pursuit of a smaller system impact threshold on interconnecting generation, which will induce more network upgrades.

The group of eight developers, including National Grid Renewables, Invenergy and NextEra Energy, said MISO’s new rule — which halves some interconnecting generation’s allotted distribution factor (DFAX) to 10% — means the RTO is making “sweeping” cost allocation decisions while circumventing FERC approval (EL23-85). The grid operator did not run the change past FERC, entering the stricter cutoff into a Business Practices Manual (BPM) rather than its tariff. (See MISO, Stakeholders Debate Lower Congestion Limit.)

The new rule applies to MISO’s basic and unguaranteed level of interconnection service, called energy resource interconnection service (ERIS). The DFAX, which represents how much a generator impacts transmission congestion, is used to assign the costs of transmission upgrades to ERIS customers. The RTO is applying the more stringent DFAX threshold to customers within certain subregions and at certain transmission voltage levels.

The developers argued that MISO’s tariff is unjust and unreasonable because it is silent on cost allocation criteria for interconnection customers. They asked FERC to order MISO to revise its tariff to incorporate the previous 20% DFAX standard and only allow a smaller threshold if the RTO makes a formal proposal before the commission with evidence that the change is reasonable and necessary.

The developers argued that the Federal Power Act and FERC policy require that MISO keep its cost allocation criteria for interconnection customers on file with the commission.

“Should a public utility be permitted to change the cost allocation criteria that it uses to assign interconnection customers hundreds of millions of dollars in costs each year without commission oversight and without complying with the filing requirements of the FPA?” the developers asked rhetorically in their July 25 complaint. “MISO’s use of a BPM to make drastic changes to its cost allocation criteria reflects a fatal defect in MISO’s tariff: The tariff does not include the cost allocation criteria applied by MISO to determine the rates that a customer must pay to obtain interconnection service.”

MISO has said the lower tolerance on congestion contributions will allow upgrade costs to be shared among more interconnection customers and result in fewer unaddressed reliability issues passed on to later queue cycles or turning up in the RTO’s annual transmission expansion plans.

But the developers contended MISO has flouted statutory requirements by dodging the filing process on a proposal that will “materially affect the costs that customers are required to pay to obtain interconnection service and access the wholesale markets.” They said it didn’t respond to stakeholders’ requests that it justify its proposal.

“Although MISO may believe that a selectively applied 10% standard represents an improvement over prior practice, the only standard that has been shown to be within the range of reasonableness is the longstanding 20% standard. MISO has not provided any empirical data that shows the 20% DFAX standard is unjust, unreasonable or unduly discriminatory,” the developers said.

They also charged that MISO’s goal is reducing congestion for the sake of economics, not supporting reliability. The RTO should also employ a DFAX threshold uniformly, the developers argued.

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NJ Plans for Transition Away from Natural Gas

Assuring consumers that the government is not “coming to take your gas stove,” New Jersey’s Board of Public Utilities (BPU) opened a two-day conference Tuesday into the contentious issue of how to dramatically reduce the use of natural gas and promote alternatives in pursuit of cutting carbon emissions.

Representatives of government, environmental groups, ratepayer advocates and utilities mapped out scenarios, challenges and potential pitfalls on how to manage the transition away from gas while protecting ratepayers and overburdened communities.

BPU President Joseph L. Fiordaliso | © RTO Insider LLC

BPU President Joseph L. Fiordaliso began by dismissing what he sees as widely circulated misinformation that the state planned to mandate the use of electricity for heating, hot water and other appliances.

“Natural gas is not going anywhere anytime soon,” Fiordaliso said. State officials say a transition away from gas will be adopted voluntarily by consumers.

That switch will be difficult, complicated and unpredictable, and require extensive planning and investment, speakers said. Key to success will be balancing support for the declining natural gas sector and its users, while boosting the capacity of clean energy to handle the influx of former gas users, speakers said.

“We’re talking about a fundamental transformation of two important energy systems in the state in a relatively short amount of time,” said Bob Brabston, the BPU’s executive director, near the end of a 90-minute panel Tuesday morning on the cost impact and challenges of the shift.

“What does that mean for us as a state from an economic competitive standpoint? What does it mean to the businesses that operate here? And what are some of the things that we as policymakers should be thinking about as we talk about some of this stuff?”

‘Flat’ Building Emissions

The BPU convened the conference, which ran Tuesday and Wednesday, after Gov. Phil Murphy (D) signed an executive order requiring the agency to solicit stakeholder input and draft recommendations by August 2024 on how to shrink the natural gas sector. The state is seeking by 2030 to cut greenhouse gas emissions to 50% below 2006 levels.

State policy does not mandate a shift to electrify building water and heat systems, but a series of policies introduced by the Murphy administration heavily promote the shift, including rules approved by the BPU on July 26 that would create a series of “startup” building electrification programs backed by incentives. (See NJ BPU Backs Building Decarbonization Plan Despite Opposition.)

A separate executive order signed by Murphy calls on the state to electrify 400,000 dwelling units and 20,000 commercial spaces or public facilities by 2030.

Opponents of the plans, including business groups and fossil fuel interests, say electrification is expensive and the state’s strategy is heavy handed and doesn’t take into account alternative fuels. Meanwhile, some environmental groups say the state is electrifying too slowly.

Eric Miller, NRDC | © RTO Insider LLC

Eric Miller, New Jersey energy policy director at the Natural Resources Defense Council, speaking on the same panel as Brabston, said the need for a solid strategy to cut emissions from natural gas use in buildings can be seen in the history of the energy generation and building sectors, which are the second- and third-largest generators of carbon emissions. While emissions from energy generation have been about halved in the past two decades, building emissions — which account for 26% of state emissions — “are about flat,” because of the lack of a policy, he said.

The solution is a Clean Heat Standard, under which the state sets a steadily increasing goal for the percentage of clean energy used by buildings, he said. Such an initiative would be flexible enough to “allow a broad range of technologies” to replace fossil fuels, he said.

Abe Silverman | © RTO Insider LLC

Abe Silverman, former BPU general counsel who now runs a clean energy policy program at Columbia University, echoed Miller’s call for a standard, which he described as “bringing in a competitive, technology-agnostic standard for the natural gas sector.”

“That has really profound implications for how we drive investment in the sector and how we think about things going forward,” Silverman said. “When we see this in other states, we largely see this as negotiated political settlements, where you establish the benchmarks upfront, and then you use the competitive market to achieve those standards.”

Adopting such a system likely would trigger “a very difficult, contentious discussion” over the levels at which the standard is set, he said. Other thorny issues include what entities and institutions are covered by the standard, which fuels are considered clean and who will ensure compliance, he said.

Even more complicated is how to assess the “cost effectiveness” of the strategy, he said.

“We’re talking about switching people off of the natural gas system to electrification, or otherwise decarbonizing the natural gas they’re using,” he said. “You have to think about both the costs of moving customers off the gas system onto the electric system, that’s one set of costs. But then you also have to think about the cost of maintaining the natural gas system.”

Planning Future Electricity Demand

A key issue as customers leave the gas sector is whether the electricity sector has the capacity to handle the increase with clean energy rather than electricity created with fossil fuels, said Michael A. Schmid, vice president for asset management and planning at PSE&G.

“We need to be talking with our RTOs. We need to be looking at how they’re doing their planning, what they’re estimating load forecast to be compared to what the utilities are estimating currently,” he said. One example of the challenge, he said, is how to plan for the rise in electric heating, which at some point — likely 20 years or so from now — will mean the winter electricity peak will exceed the summer peak. That planning task will be further complicated by the unpredictability of the rise in electric vehicles, which PSEG expects to reach about 800,000 vehicles in New Jersey in 10 years, he added.

Silverman said utilities that serve gas and electricity customers will lose a gas customer but add an electricity customer. But utilities that serve only gas customers, or only electric customers, will see a different impact, he said.

Maintaining the natural gas distribution system will be key to big gas users, such as industrial customers, Schmid said. Utilities will continue to improve the gas system and ensure it doesn’t harm the environment, such as through methane leaks, he said.

“How do we balance out the cost of the of the gas distribution system to the costs that are going to come in on the electric system?” he asked. As utilities like PSEG continue to invest in both sides, “we have to sit there and say: Are we ready for the future?”

Customer Impact

Utilities also will have to carefully manage the effects on customers, Silverman said. He cited a section of the natural gas grid that — from an “operational perspective” and for financial reasons — should be shut down even though there are gas customers in the area that don’t want to shift to electricity.

“How do we reach a consensus as a society about shutting down that little piece of grid because there are cost savings?” he asked.

David S. Lapp, of People’s Counsel in Maryland, which advocates for ratepayer interests, said it’s important to consider the impact of the shift away from gas falls heavily on low- and moderate-income consumers.

Lapp, speaking on a panel Tuesday afternoon about ratepayer costs of the energy transition, said a study by his office of the impact in Maryland found that initially, some customers would switch away from gas. Then, as their departure pushed up gas rates because the user base was smaller, that encouraged even more users to flee rising gas prices.

“So the customers who are … capable of leaving the system will,” he said. “So, then we will have people who can’t get off the gas system, whether it’s because they’re low-income, they can’t afford switching over the appliances or they’re renters, and they don’t have that ability.”

“What we saw is really a risk of rapidly spiraling, increased gas rates for customers,” he said. One solution, he said, is to slow the pace of infrastructure spending on the gas side, to “mitigate the possibility of stranded cost.”

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NREL Study Finds Wind, Solar Setback Regs Proliferating

A new analysis quantifies how setback ordinances are affecting wind and solar energy development.

The National Renewable Energy Laboratory said these local laws are multiplying but their broad effects typically have not been measured in large-scale assessments because of the extensive amount of data that is needed and the detailed modeling that must be built from it.

As a result, NREL said, previous assessments likely have overestimated the amount of land available for renewable development and underestimated the cost and difficulty of development.

If the most restrictive setback rules were imposed nationwide, the potential for wind development would drop almost 90% and solar nearly 40%, compared with a scenario in which no restrictions were in place.

It’s important to include these setbacks in resource assessments, the authors say, to accurately estimate the actual potential.

The NREL study — “Impact of Siting Ordinances on Land Availability for Wind and Solar Development” — was published Thursday in Nature Energy.

Reviewing state and local zoning laws and ordinances, the authors found 1,853 local wind rules in effect in 2022, compared with 286 four years earlier. They also found 839 local ordinances affecting utility-scale solar construction in 2022; no comparable data tally was made in previous years.

The most common types of regulations are minimum setbacks from roads, property lines and structures; noise level restrictions; and wind turbine height limits.

Setback distances typically are greater for wind turbines than solar arrays and often are calculated with some multiple of the turbine’s height.

Looking nationwide at land suitable for energy development — with no legal protections, wetlands, high elevations or other major limits — the study found the potential for construction of 147 TW of solar capacity and 14 TW of wind capacity if no setback restrictions were imposed.

This falls to 121 TW and 4 TW under the median distance among setbacks imposed nationwide and falls to 91 TW and 2 TW under the most restrictive setback rules — a decrease of as much as 38% for solar and 87% for wind.

“The increase in local zoning ordinances is a sign that the renewable energy industry is maturing,” lead author Anthony Lopez said in a news release. “Ordinances can provide a structured approach to thoughtfully weave clean energy infrastructure into society and our natural environments.”

A key takeaway, he said, is the importance of understanding the impact of renewable development on communities, and of providing communities with information to help them balance regulation of those impacts with the benefits of constructing renewable resources.

Other findings and caveats in the report include:

    • The impact of setback restrictions varies greatly depending on the nature of the community; Albany County, Wyo., and Erie County, Pa., have similar setback requirements for wind turbines, but Erie County is so much more densely developed that nearly the entire county is excluded from wind power installation.
    • Factors not examined in the report — such as environmental, ecological and security considerations — also influence land availability.
    • The report incorporates only zoning ordinances that had been posted online.
    • Energy developers sometimes can obtain exemptions from setback standards.
    • A few counties’ information is missing, so data was simulated for them.
    • There was no attempt to factor in local circumstances — such as when owners of two adjacent parcels agree to host wind turbines, and the setback requirements are canceled along the property line between them.

Setback data were combined with wind and solar data to model the renewable energy potential of a given area and the local ordinances’ impact on it.