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August 2, 2024

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NEPOOL Approves ISO-NE DASI Proposal

NEPOOL approved a set of tariff changes related to ISO-NE’s Day-Ahead Ancillary Services Initiative (DASI) proposal at the August Participants Committee (PC) meeting, held virtually Thursday. The vote gave final NEPOOL approval of the DASI proposal, as the changes previously had been approved by the Market, Reliability and Transmission Committees.

“ISO New England has been working with stakeholders on … DASI for almost a year and we’re pleased NEPOOL approved DASI,” ISO-NE told RTO Insider in a statement following the vote. “We plan to prepare and file our DASI proposal with FERC in October of this year. Our plan is to have DASI integrated into New England’s wholesale markets by March 1, 2025.”

The DASI proposal is intended to procure and price ancillary services to ensure the reliability of the day-ahead market. (See ISO-NE Plans 2025 Launch for Day-Ahead Ancillary Services Initiative.)

In a July memo, ISO-NE wrote that the current Day-Ahead Energy Market, which clears just one energy product based on supply offers and demand bids, leaves gaps when unforeseen generation and infrastructure issues arise and when the market clears less supply than forecasted load.

“The DASI proposal creates a Day-Ahead Ancillary Services Market that, together with today’s Day-Ahead Energy Market, creates a single, jointly optimized Day-Ahead Market,” ISO-NE wrote. “These new day-ahead ancillary services will encourage reliable resource performance and prepare the system on a day-ahead timeframe with the flexibility needed to manage operational uncertainties.”

While approving the proposal, members of the Markets Committee have asked ISO-NE to reassess the strike price adder when more data is available following implementation. NEPOOL members also have raised concerns related to the DASI’s effects on peaker plants, as well as concerns about the elimination of the Forward Reserve Market (FRM). ISO-NE plans on removing the FRM when DASI takes effect in March 2025.

“The FRM is no longer necessary in its suite of markets, given the development of the new Day-Ahead Ancillary Services and in light of the significant transmission and market improvements that have been made over the last decade to relieve locational constraints and reward resource flexibility and performance,” ISO-NE said.

Also at the August PC meeting, the committee voted to approve ISO-NE’s proposed Order 881 compliance changes drafted in response to a June 15 FERC order (ER22-2357), as well as tariff changes related to FERC’s request for further compliance with Order 2222 (ER22-983). (See FERC Gives ISO-NE Homework on Order 2222, Order 881 Timelines Need Explaining, FERC Says.)

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Appeals Court Denies Review of SPP Z2 Charges

The D.C. Circuit Court of Appeals on Friday dismissed a review petition filed by Xcel Energy, on behalf of its Southwestern Public Service (SPS) subsidiary, and Kansas Electric Power Cooperative (KEPCo) over FERC’s rejection of their rehearing requests related to SPP’s filed-rate doctrine (20-1429).

FERC last year denied the SPS and KEPCo rehearing requests of SPP’s assignment of network upgrade charges under Attachment Z2 of its tariff. It said the grid operator did not violate the utilities’ service agreements or the RTO’s tariff. (See KEPCo, Xcel Rehearing Requests on Z2 Fail.)

The utilities argued that Attachment Z2 — which awards credits to transmission upgrade sponsors from any upgrade users whose service could not be provided “but for” the upgrade — required using an N-1 contingency analysis, rather than the reservation stack analysis (RSA) that SPP used. They also said the RTO violated the filed-rate doctrine and tariff because the rate was unclear about how much they would be charged, and because it didn’t identify the upgrade facilities that would meet their requests nor provide them with an estimate of the costs.

The D.C. Circuit denied in part and dismissed in part the review petitions because it said FERC correctly concluded that Attachment Z2 “does not plainly require” the N-1 methodology. It also said the commission’s reliance on extrinsic evidence to determine SPP’s tariff allows the RSA methodology was not arbitrary and capricious, as SPS and KEPCo had alleged.

The court also said it lacked jurisdiction to consider the utilities’ filed-rate doctrine argument because they failed to exhaust it at the rehearing stage.

Applying the RSA methodology, SPP imposed upgrade charges in 2016 that had not been specifically mentioned in the utilities’ service agreements. SPS was billed $12.8 million for 101 creditable upgrades, 96 of which were not included in its service agreement. KEPCo was billed $6.2 million for seven creditable upgrades; none were included in its service agreement.

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Texas PUC Approves ERCOT’s ORDC Modifications

Texas regulators last week endorsed ERCOT’s proposed modifications to the operating reserve demand curve (ORDC) designed to retain and attract dispatchable generation.

“I believe that near-term action is important to retain our long-duration, dispatchable thermal generation assets that I believe are extremely necessary to maintain reliability during extreme weather conditions,” Commissioner Lori Cobos said during the Public Utility Commission’s open meeting Thursday.

Under ERCOT’s multistep proposal, price adders of $20/MWh and $10/MWh will be set when operating reserves hit floors of 6,500 MW and 7,000 MW, respectively. Staff’s analysis indicates the floors would have increased revenues to generators by about $500 million during the 2020 and 2022 pricing years. Thermal generators would have received 80% of those revenues.

ERCOT says the ORDC increasing during substantial operating reserve surplus periods will improve pricing signals, help retain existing assets, add new dispatchable generation and reduce the frequency of reliability unit commitments (RUCs).

Cobos filed a memo before the meeting explaining the need for a “market-based tool” that incents generators’ self-commitment in the real-time market to help reduce RUCs. To ensure the ORDC modification’s goals are met, she also laid out three metrics ERCOT will be required to track and report back to the commission (53298):

    • The amount of new revenue specifically resulting from the adders;
    • The specific type of generation resources that received the new revenue; and
    • Performance data showing whether the adders have reduced ERCOT’s use of RUC.

“I think these metrics will help us keep track of whether or not this action is accomplishing what we set out to do,” Cobos said.

She also recommended the PUC re-evaluate the need for the price-floor adders after ERCOT deploys dispatchable reliability reserve service in December 2024 to check that RUCs are reduced by the amount of the new ancillary service ERCOT procures.

Commissioner Jimmy Glotfelty said he struggled with ERCOT’s proposal but joined the PUC’s unanimous decision.

“It’s not clear to me that we are creating a bridge solution to eliminate RUC or that we’re creating a bridge solution to bridge us to a reliability capacity issue to solve our resource adequacy issue,” he said. “If we want to eliminate RUC, I think we should be looking at all of the solutions that could eliminate RUC, not just one. I know RUC is problematic for generators, but what I don’t want is another out-of-market solution to solve an out-of-market solution that we created which solved a conservative operations out-of-market solution that we created. We’re just piling on by trying to fix the market with other modifications.”

The PUC in January directed ERCOT to propose a bridge to the commission’s proposed market redesign, a performance credit mechanism (PCM). However, the design’s chief proponent, former commission Chair Peter Lake, stepped down from his post in June after Texas lawmakers suggested other market structures during their recent legislative session. (See Texas PUC’s Lake Steps Down as Chair.)

The grid operator’s stakeholders and Board of Directors approved the staff’s proposal in April. (See ERCOT Stakeholders Endorse Staff’s Bridge to PCM.)

ERCOT’s ORDC values the wholesale market’s operating reserves on their scarcity, reflecting that value in energy prices.

The curve has been modified several times since it became part of the market in 2014. The value of lost load, which is set equal to the system-wide offer cap, was changed from $9,000/MWh down to the $2,000/MWh low-system-wide offer cap after the 2021 winter storm, then back up to $5,000/MWh in January 2022. The minimum contingency level also was increased last year from 2,000 MW to 3,000 MW.

Entergy Texas Gets Rate Increase

In other actions, the PUC approved an unopposed settlement that increases Entergy Texas’ base rate revenues by $54 million, resulting in a nonfuel revenue requirement of $1.23 billion. PUC staff, the Office of Public Utility Counsel and Texas Industrial Energy Consumers were among the signatories to the agreement (53719).

At the same time, the commission severed into a new proceeding two contested issues related to Entergy’s proposed electric vehicle charging riders. The PUC will determine whether it is appropriate for a vertically integrated utility to own EV charging facilities or other transportation electrification and charging infrastructure.

The commission also rejected rehearing requests by Texas Energy Association for Marketers, Alliance for Retail Markets and Texas Competitive Power Advocates over the approval of a partial settlement that reduced CenterPoint Energy’s distribution cost recovery factor by $7.8 million (53442).

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Illinois Regulators Open NOI on Ameren MISO Membership

The Illinois Commerce Commission last week instituted a Notice of Inquiry over the potential benefits of Ameren Illinois quitting MISO to join PJM.

The ICC’s NOI focuses on a recent Ameren Illinois study, prepared by Charles River Associates, which concluded that if all MISO Zone 4 utilities left for PJM, it would cost the State of Illinois $3.4 billion over the 10-year period from 2025 to 2034 (23-NOI-01). The firm recommended Ameren Illinois stay on with MISO after it analyzed energy trade benefits, transmission expansion costs, capacity costs, RTO administrative fees, and exit and integration fees.

“Joining PJM did result in some benefits, such as reduced emissions and increased resiliency, but these benefits are outweighed by the significant economic costs,” the study authors wrote.

Ameren commissioned the cost-benefit analysis at the behest of the ICC last July after MISO’s 2022/23 capacity auction unearthed a 1.2-GW shortfall across its Midwest region. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest; MISO Reacts to Ill. Legislators’ Criticism of Capacity Shortfall.)

“Safe, reliable and affordable electricity is always top of mind at the commission, and with the ongoing changes to our power system, it makes sense for the ICC to consider how the workings of our electric grid operators are or are not benefiting Illinois consumers,” ICC Chairman Doug Scott said in a press release. “This study is a helpful resource in determining if continued participation in MISO makes the most sense for Illinois and Ameren Illinois customers.”

The ICC said that without reform, “structural market shortcomings” in MISO could lead to insufficient supply and a spike in bills for ratepayers in central and southern Illinois.

ICC’s NOI includes a three-month comment period for interested parties, with initial stakeholder comments due Oct. 2 and reply comments due Nov. 1.

The ICC said comments will “inform any future or potential commission action regarding the state’s ongoing participation in its two power grid operators.” The ICC emphasized that its NOI proceeding is not a rulemaking. It said the information it receives “may or may not form the basis for the initiation of a formal ICC rulemaking or other purposes.”

On Aug. 3, Ameren reported a profit of $237 million ($0.90/share) for the second quarter, compared with $207 million ($0.80/share) this time last year. It said more significant investments in transmission and distribution infrastructure boosted its fiscal performance.

MISO declined to comment on Ameren Illinois’ cost-benefit analysis, whether it thinks the ICC might have a change of heart on its capacity market structure if it adopts changes such as a sloped demand curve, and whether it will file comments in the NOI.

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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.