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November 16, 2024

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Overheard at Deploy23

WASHINGTON — Every energy industry conference has its own particular buzz ― what attendees are talking about, not only on stage but in the side conversations between sessions, at lunches and receptions. At Deploy23, it was all about two questions: How can we do more and how can we do it faster?

Coming off the Earth’s hottest summer on record, the two-day conference Sept. 26 and 27 zeroed in on the public-private partnerships that will be needed to optimize the impact of every single penny of the billions in clean energy funding in the Infrastructure Investment and Jobs Act (IIJA)  and the Inflation Reduction Act (IRA).

More than one speaker said that building and maintaining a sense of urgency is critical. A recent report from the International Energy Agency calls for a tripling of renewable energy and doubling of energy efficiency improvements by 2030, along with a major ramp-up in electric vehicle (EV) and heat pump sales, to limit climate change to 1.5 degrees Celsius.

The IIJA and IRA funds, while unprecedented, are insufficient, said Jonah Wagner, chief strategist for the Department of Energy’s Loan Programs Office (LPO), which cosponsored the event with the Cleantech Leaders Climate Forum.

“We have to execute,” Wagner said. “And we have to execute in a way that captures the complexity and the implications of government engaging in competitive markets and supply chains, labor, workforce and community engagement, all of it. … We have to develop a shared understanding between the public sector and the private sector and then a whole broader ecosystem around how we’re going to get there.”

In his opening remarks, White House Senior Advisor John Podesta called for private sector “ownership” on the three key issues creating a drag on clean energy deployment — permitting, supply chains and workforce.

“We need you to keep voicing support for broader permitting reform at the federal, state and local level, and we need you to take responsibility for community engagement for your own projects,” Podesta said. “Get in early, engage local leaders early; and often we can address concerns that are raised at the community level, find ways to mitigate challenges on the ground and get these projects built.”

Breaking China’s dominance over clean energy supply chains is a more complex issue. While Podesta and other administration officials typically boast about the $150 billion in private sector investments in clean energy supply chains announced since the passage of the IRA, that early money has been concentrated in certain low-hanging opportunities – electric vehicles, batteries and solar panels.

But companies need to “get creative … to invest in projects up and down the supply chain, innovate in pursuit of a circular economy,” he said.

Podesta stayed on message on workforce development, calling for good wages and benefits, apprenticeship programs and opportunities for unionization. But, according to Undersecretary for Infrastructure David Crane, the immediate need at the Department of Energy is for professionals who know the nuts and bolts of project development.

“We’re looking at having 200 to 300 projects in active development by next year,” Crane said. “The skilled workforce that we need now, and where we’re entirely dependent on the private sector, is on structuring these transactions. We need the lawyers, the financiers, the tax advisors. We need the developers that can structure these transactions.”

Communication, Collaboration, Coordination

Getting projects built often means people who disagree on some issues have to find ways to work together, said Mitch Landrieu, White House infrastructure coordinator.

Recalling his own experiences as mayor of New Orleans, rebuilding the city in the wake of Hurricane Katrina in 2005, Landrieu said creating a “virtuous cycle of success” for infrastructure development required alignment of federal, state and local government, along with the private, nonprofit and community sectors.

“It’s about setting up what I call a mousetrap, the scaffolding of government where not only are we trying to do a thing, but how we’re trying to do it is coordinated — so, communication, collaboration, coordination,” Landrieu said. “If, for example, we get in a fight with a red state governor or … a blue state mayor, or the mayor and the governor are not on the same page, it will slow down our ability to move stuff to the ground because government is kind of an essential part of the spine in partnership with the private sector.”

Landrieu also argued for a broad definition of “infrastructure,” encompassing bridges, broadband and childcare.

“If you sit in a room of all women ― CEO all the way down to the person who’s cleaning the floor ― and you ask them what’s the most important thing that they need to actually show up and do that work, they’ll say childcare ― 100%,” he said. “So, my brain goes with ― childcare is infrastructure ― because if you can’t have people that do it, you can’t build stuff.”

Whether for clean energy or childcare, the foundation of public and private partnerships, he said, is “a commitment and then a willingness for everybody to show up and find common ground by pushing away the extremes and staying focused” on shared goals.

‘Getting Scrappy’

A “fireside chat” on electric cars and buses as grid assets explored both the opportunities that managed charging and virtual power plants (VPPs) present and the challenges of working with utilities to get charging stations and manufacturing plants interconnected.

Light-duty electric vehicles (EVs) typically use about 12 kWh of power a day, but when fully charged, their batteries have a much larger capacity, said Patrick Bean, director of infrastructure policy and business development at Tesla.

“So, there’s a lot of opportunity and diversity in [when people] charge … and their cars are typically sitting either 23 hours a day, 22 hours a day,” he said. “It’s a great opportunity to optimize that charging behavior for the best off-peak time, low-carbon times.”

Tesla has been piloting virtual power plants that aggregate capacity from its residential Powerwall energy storage units, and it recently launched another pilot in Texas offering Tesla EV owners a flat monthly rate of $25 for unlimited charging scheduled by the company for off-peak hours between 10 p.m. and 6 a.m., he said.

Customers can enroll via a cell phone app, “so it’s something we’re trying to make very digestible, very easy for customers to understand because if it gets too complex, they’re going to say, ‘This is too much,’” Bean said.

California–based Zum is offering school districts electric transportation — buses, vans and passenger vehicles — as a service, with apps so parents can track when their kids will be home from school.

School buses are “the largest mass transit system in the U.S.,” getting 27 million students to and from school each day, said founder and CEO Ritu Narayan, and their set schedules and evening, weekend and summer availability make them perfect for electrification and managed charging applications, like VPPs.

But, Narayan said, “the challenges are various. … The first step to that is optimizing the entire system and application, and second is establishing of the entire ecosystem, right from the manufacturers to the charging infrastructure to establish the aggregation around it” so Zum can be a one-stop shop for school districts seeking to electrify fleets.

On the interconnection side, working with utilities has become a critical part of Bean’s work at Tesla, as the company looks to expand its factories and charging networks and runs into the multiyear timeframes utilities often set for distribution system upgrades and interconnection.

As Tesla looks toward exponential growth in EV sales, he said, it can be “really hard to build utility infrastructure at an exponential rate, and I hope we can try it … because there are a lot of no-regrets investments [in] infrastructure that we know are going to be necessary. …

“There’s a lot that can be done just from a process perspective and better coordination … and just getting scrappy and coming up with new ideas to get infrastructure built,” he said, pointing to a recent example in which Tesla was able to get a new energy storage factory interconnected in 12 months.

The challenge, Bean said, is getting utilities and industry trade groups to “realize and understand that what has worked in the past is not going to work going forward. So, we need to change the processes together. …

“This is not a distributed grid versus a central grid,” he said. “Seven or eight years ago, there were concerns about a ‘utility death spiral.’ Now we’re just trying to figure out how can we support double-digit load growth, and that’s going to take a lot of coordination between the central grid and the distributed grid.”

Getting to Scale

JB Straubel, founder and CEO of Redwood Materials, knows all about scaling a business. The former cofounder and chief technology officer at Tesla, says the U.S. EV and battery supply chains have a long way to go, which is part of why he started Redwood, which recycles lithium-ion batteries to produce the critical minerals needed for EV production.

Tesla received a $465 million loan from the LPO in 2010 and finished paying it back in full by May 2013, according to the agency website. Earlier this year, Redwood received a conditional commitment from the LPO for a $2 billion loan to help it expand its plant in Nevada.

But, Straubel said during an on-stage conversation with LPO Director Jigar Shah, “I think it’s underappreciated, especially by some of the … early investment community and a lot of startups, how difficult it is to achieve scale. It’s a whole new category of problems.

“Supply chains break, geopolitics come into it. [Challenges] rise to a whole new magnitude in terms of what you’re doing when you do 100 times as much of it,” Straubel said. “It requires a different set of engineering skills and a different set of business skills.”

With a series of recent announcements on new EV and battery manufacturing facilities across the U.S., “it’s sort of tempting to feel like we’re almost there,” he said.

“But we really looked at the objective numbers on where we are on supply chain onshoring or even just supply chain geopolitical security … it’s not very far along,” he said. “Building out that robust supply chain, making sure we are being strategic ahead of time about where we invest, to kind of [look] at where the puck is going — it is just going to be critical.”

While Redwood is producing lithium and nickel, Straubel said, “until there is an entire EV supply chain, there’s nothing to do with it. … If I had a pile of lithium sitting here on the stage and went to go sell it, where do we think all the buyers would be?”

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Draft Environmental Statement Prepared for Maryland OSW

Federal regulators have completed their environmental review of a Maryland offshore wind plan, moving the potential 2.2-GW project one step closer to final approval.

The Bureau of Ocean Energy Management will publish the draft environmental impact statement on US Wind’s proposal in the Federal Register on Oct. 6, starting a 45-day public comment period.

The comments will be considered as BOEM prepares the final environmental impact statement, which typically has been followed closely by the decision on whether to approve construction and operation.

Lease Area OCS-A 490 was awarded in 2014 to US Wind, which is owned by Lenexa S.p.A., a subsidiary of Toto Holding S.p.A. and Apollo Global Management. The 46,970-acre lease area is near the Delaware-Maryland border on the Delmarva peninsula.

US Wind proposes to install up to 114 wind turbines with up to 2.2 GW of combined nameplate capacity as close as 10 miles offshore, with export cables making landfall and interconnection in Delaware.

The company thus far has proposed two phases — the 300 MW MarWin and the 808 MW Momentum Wind — and secured offshore renewable energy certificates for both from Maryland. It also plans to create an offshore wind component factory at a former steel mill near Baltimore.

“This is the most significant step forward in the history of Maryland offshore wind,” US Wind CEO Jeff Grybowski said in a news release Friday. “BOEM’s draft environmental impact statement sets us on a path toward starting construction on our offshore wind projects in 2025, putting Maryland’s goals that much closer to reality. We are proud to be the first to deliver this clean energy to Delmarva and look forward to the day we can get steel in the water.”

The draft EIS for the Maryland Offshore Wind Project is similar to others BOEM has prepared for the profusion of offshore wind farms proposed off the Northeast coast — it presents a range of possible adverse and beneficial effects that construction and operation could have.

As with the other studies, the Maryland draft EIS predicts an adverse impact on the fishing industry, the critically endangered North Atlantic right whale and scientific research.

The adverse impact could be major once the cumulative effects of all the other proposed wind farms are factored in. A major adverse visual impact also is predicted.

Minor to moderate beneficial impacts also are predicted in the draft EIS. Seals and toothed whales, for example, might have better feeding conditions near the turbine tower foundations. Air quality might improve to some degree, and birds might derive minor benefit from improved foraging opportunities.

Sea turtles likely would suffer moderate negative effects but recover completely once the factors causing those effects cease.

The draft EIS and its appendices are available on BOEM’s website.

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PUCT Rules Against SWEPCO on Pirkey Retirement

The Public Utility Commission of Texas last week approved an unopposed agreement over Southwestern Electric Power Co.’s (SWEPCO) request to reconcile its 2020-21 fuel costs related to the retired Pirkey coal plant, but rejected an administrative law judge’s proposed order that found the plant’s retirement prudent (53931).

Opponents of SWEPCO’s 2020 decision to retire the plant in East Texas contended the plant still had years of useful life.

Among the opponents was Commissioner Will McAdams, who said in a memo last week that because the utility’s action was not prudent, it should not be allowed to recover carrying costs from the mine that provided its fuel.

“I understand that the prudent standard is not a high bar, but the lack of depth in the 2020 analysis, especially when you’re retiring a plant 12 years early, it simply did not sit well with me,” he told his fellow commissioners Thursday.

McAdams said SWEPCO could have re-examined its analysis after the February 2021 winter storm “exposed reliability and resiliency issues of a kind never seen before and reinforced the need for existing dispatchable generation.” He said the utility’s decision to continue with its application as if the storm had not occurred “lacks fundamental credibility and common sense.”

“Had SWEPCO acted prudently, it would have updated the analysis based on the new reliability needs of grids, the volatility of the 2021 natural gas market, increased construction costs, supply chain issues and inflation,” he said. “It tells me that SWEPCO knew what outcome they wanted to achieve and may have nudged the analysis parameters to match that.”

The plant retired last spring after 38 years of operation.

The PUC also approved a pair of amended certificates of convenience and necessity for system improvements in the lower Rio Grande Valley. (See Texas PUC Directs Tx Construction in Valley, “Board Approves $1.28B Tx Project,” ERCOT Board of Directors Briefs: Dec. 10, 2021.)

It signed off on unopposed agreements filed by South Texas Electric Cooperative  (54936) and AEP Texas and Electric Transmission Texas (55001) for their proposed routes. The utilities are building new double-circuit 345-kV transmission lines and related facilities in South Texas.

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NJ to Add 400 EV Chargers with $12.7M Investment

New Jersey has awarded $12.7 million in grants to install electric vehicle chargers at 405 new locations, including multiunit dwellings and tourism hot spots, as the state seeks to dramatically increase EV use in the face of some opposition to the move.

The New Jersey Board of Public Utilities (BPU) made the awards in three programs designed to provide incentives for specific market sectors believed to be key to creating a critical mass of EV chargers. The awards were made in the program’s third round, from the 2023 budget, and the agency is accepting applications for the 2024 funding round, which closes Nov. 30.

The targeted sectors include: multiunit dwellings, because they are tough for EV-owning occupants to install their own chargers in; tourism sites, to encourage EV drivers who might balk at coming to New Jersey visitor attractions for fear they won’t be able to recharge; and publicly owned fleets supporting local governments, which can lead by example, showing residents the benefits of EVs.

BPU President Christine Guhl-Sadovy announced the awards Monday, saying they are part of the agency’s effort to ensure drivers in all corners of the state have a place to plug in. The state had 2,047 Level 2 chargers and 972 Direct Current Fast Chargers in June, or about one charger per 3,050 residents, according to EvaluateNJ, an EV information website run by Atlas Public Policy.

“As we strive to combat the increasingly devastating impacts of climate change, reducing barriers to using an EV by building a robust network of public charging stations and supporting municipalities in electrifying their fleets remains a key focus of our clean energy agenda,” Guhl-Sadovy said.

The funding outlined Monday would increase the state’s charger total by about 13.5%.

Convenient, Affordable Charging

Last week, Gov. Phil Murphy (D) outlined a $10 million funding allocation to the state Department of Environmental Protection, about 80% of which went to “workplace and multi-dwelling charging station projects across the state.” He said the state is trying to make “the transition to electric vehicles more accessible and affordable than ever.” A BPU spokesperson said the two programs are unrelated.

The DEP’s EV charging funds go through the agency’s “It Pay$ to Plug in” program, which offers up to $4,000 for the installation of a single-port charger. The program has awarded about $14 million, funding the installation of 1,261 charging stations with 1,891 ports at 389 locations, according to the DEP.

“Convenient and affordable charging at home and at the workplace is core to our overall charging ecosystem, since that’s where the majority of charging will occur,” DEP Commissioner Shawn M. LaTourette said in a release at the time. “We must continue to act with the sense of urgency the climate crisis demands.”

About 37% of New Jersey’s carbon emissions are generated by transportation. The BPU’s EV charger announcement comes as the DEP moves to enact California’s Advanced Clean Cars II (ACC II), which requires that EVs account for a steadily rising share of new car sales until 2035, when all new vehicles bought in New Jersey must be EVs.

The rules, which eight states have adopted, is opposed by businesses, car dealers and fossil fuel interests, who say consumers aren’t ready for the move and the state doesn’t have the grid or charging infrastructure to cope with such a dramatic increase in EVs. (See NJ’s Push Toward Clean Cars Rule Sparks Vigorous Debate.)

Wine, Farming And A 280-year-old Restaurant

The round of BPU funding detailed Monday was about the same as in the previous round, which awarded $12.65 million through the three programs for the collective installation of 1,150 Level 2 and DCFC chargers and 106 public vehicles.

About half of the money outlined Monday — about $6.1 million — will pay for the installation of more than 1,300 chargers in multiunit dwelling residences. The agency’s MUD EV Charger Incentive Program awards up to $4,000 for a dual-port, Level 2 charging station in a multiunit development and up to $6,000 if it is in an overburdened community.

The Electric Vehicle Tourism Program, which provides up to $5,000 for a Level 2 charger and up to $50,000 for a Direct Current Fast Charger, awarded nearly $800,000 in two phases of the announced funding. The money will trigger the installation of 37 chargers, including: four Level 2 chargers at Phillips Farms, a 300-acre Central Jersey family farm that allows you to pick your own fruit and vegetables; two Level 2 chargers and two DCFC’s at Beneduce Vineyards, a fourth-generation winery in South Jersey; and two DCFCs at The Clinton House, a historic restaurant first opened in 1743.  (See NJ Seeks to Lure Tourists with EV Chargers.)

The $5.75 million awarded in the Clean Fleet EV Incentive Program will fund local schools, municipal commissions, state agencies or boards, and other local government bodies to help transition their fleets to EVs. The program awards up to $4,000 for the purchase of a light-duty EV, up to $10,000 for a Class 6 electric truck, up to $5,000 for a Level 2 charger and up to $50,000 for a DCFC.

The 36 grants will pay for 140 EVs, 25 DCFCs and 124 Level 2 chargers. The recipients include the Passaic Valley Sewerage Commission, which received $1.4 million for five EVs, eight DCFCs and 15 Level 2 chargers. New Jersey Transit, the state’s mass transit agency, received about the same for 20 EVs, six DCFCs and 15 Level 2 chargers.

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NY Makes Down Payment on School Bus Electrification

New York state has issued the roadmap for its first-in-the-nation school bus electrification program and is preparing to draw the first tranche from a $500 million pot of money to start carrying it out.

The $100 million announced Thursday will be enough to replace only several hundred of the 45,000 fossil-powered school buses in the state. Electric buses are quite expensive, so the state is providing substantial vouchers to help fleet operators buy them.

These early efforts are not intended to fully electrify the nation’s largest school bus fleet. Rather, the goal is for every fleet operator to gain experience with a handful of electric buses before 2027, when the sale of internal-combustion school buses will be banned in New York.

The hope also is that electric vehicle technology and grid infrastructure will evolve over the next four years to the point the lifetime cost of owning and operating electric school buses (ESBs) decreases to parity with internal combustion engine (ICE) school buses.

Then the special incentives for conversion can be reduced.

New York state in 2022 mandated the gradual conversion of the school bus fleets operated by hundreds of school districts and private contractors. It’s a step toward meeting the goals of the state’s 2019 climate protection law, protecting the health of children who ride buses and improving the air quality in neighborhoods near bus depots.

Later in 2022, state voters approved a $4.2 billion bond act for environmental projects, $500 million of which was designated for ESBs.

Other states since have enacted phase-outs of their own, but New York was first. ICE school buses will be banned from roads in the Empire State in 2035.

Program Details

ESB adoption is in its early stages.

The World Resources Institute estimates only 69,000 of the 20 million-plus U.S. children who ride buses to school each day are riding emissions-free.

New York had just 310 ESBs by the most recent count, according to the New York State Energy Research and Development Authority, which issued the ESB Roadmap in mid-September.

The roadmap guides the ESB program through 2027. It focuses on helping fleet operators afford their first few ESBs so that they, utilities and the state itself can gain experience and plan the wider buildout.

The most popular category of bus — the full-length Type C — runs in the $140,000 range with a diesel, gasoline or propane engine when purchased through one of New York’s school bus dealers. The cost jumps into the high $300s or low $400s with a battery electric drivetrain, depending on options chosen.

The base-level voucher offered by NYSERDA for purchase of an electric Type C bus in this first round of funding is $156,000. Up to $125,000 can be added through four bonuses for being a high-needs priority district, scrapping an ICE bus, adding vehicle-to-grid capacity and installing wheelchair capacity.

With the vouchers, an ESB might cost a fleet operator no more than an ICE bus.

A chart shows the demand for various sizes of school buses and the cost of electric versions. | NYSERDA

Additional aid will be available for charging infrastructure, but that portion of the program still is being developed.

(Hydrogen fuel cell buses also will be eligible for vouchers if any come to market.)

The early stages of the program are intended to focus on easy-to-electrify routes — those that will not test the range of present-day bus battery systems.

NYSERDA hopes to have up to 3,000 ESBs on the road by 2027, which with charging equipment would represent a roughly $780 million incremental cost over 3,000 similarly sized ICE buses. State and federal funding streams are expected to cover most of the added cost.

Challenges And Opportunities

NYSERDA expects to update the ESB roadmap in 2026, by which time it hopes to better understand best practices and costs from the early adopters’ experiences.

The 2023 edition of the roadmap outlines some of the challenges facing the ambitious goals and some of the early opportunities to overcome those hurdles:

New York school buses travel an average of 80 miles a day, which is within the 100- to 200-mile range of current ESB models.

The cold winters and hilly roads in the northern part of the state could reduce range. But range is expected to improve steadily: Federal data show improvements almost every year. From 2011 to 2022, the median range of electric vehicles offered for sale in the U.S. rose from 68 to 257 miles and maximum range from 94 to 520 miles.

The cost of ownership is something of a three-dimensional chess game. Upfront costs for ESBs are higher but maintenance costs are lower. To recoup the upfront cost, the service life must be maximized. ICE school buses average only 8.9 years on the road in New York — many are retired in good working order because of rust. So, it is best to use an ESB on longer routes to maximize return on investment — but not so long as to risk a dead battery.

Outside New York City, 96% of school buses are parked an average of 12 hours overnight every night — a long, predictable period ideal for a slower Level 2 recharge, when time-of-use rates are lower. More than half of New York’s school buses also are parked for four or more midday hours, presenting a window for a partial Level 2 recharge or more-complete Level 3 recharge.

Charger costs can range from $5,000 for a Level 2 unit to $100,000 for a Level 3 unit. Ideally, there is one plug per bus, but some fleet operators have found success with a combination of Level 2 and Level 3 chargers that add up to less than one plug per bus.

Recent problems for early adopters center on limited selection and availability — ESB manufacturers need clearer signals on market demand.

Future constraints as the 2027 and 2035 deadlines approach may include domestic content requirements, shortages of skilled labor for installation, permitting delays and extended timelines for transmission infrastructure upgrades.

Most school bus depots across the state lack the electrical capacity to charge more than a few buses, and many are in areas with limited grid capacity. There is no comprehensive database showing where these depots are and how many buses typically are parked there.

But the state Public Service Commission in April 2023 launched a planning process to address the charging needs of the medium- and heavy-duty vehicle sector.

Beyond the initial stages, electric infrastructure may range from 15% to 30% of the total cost of fleet electrification. This will be closely monitored.

Only 11% of fleet operators surveyed have assessed the electrification needs of their depots and their bus fleet.

With current technology limitations, fossil-fired cabin heaters may be needed for winter operation in the first generation of ESBs — battery-powered heaters would further limit mileage range already diminished by cold weather. This is counter to the whole point of bus electrification, but heaters can be turned on or off as needed while the bus is rolling, unlike the engine in an ICE bus.

Finally, the state has potentially put itself in a bind when it comes to paying for all of this.

NYSERDA expects the incremental costs of the first wave of ESBs — the 3,000 it hopes to see on the road by 2027 — will be covered by federal funds, utility incentives and the $500 million from the bond act.

That leaves 40,000 more electric buses to be purchased over the following eight years, and an untold number of megawatts of charging infrastructure to be installed. Whatever the eventual savings turn out to be, the up-front cost will be greater — high enough in some cases to cause sticker shock.

Public school budgets are subject to voter approval in New York state, as are supplemental capital spending proposals such as for a new building, roof replacements, a dozen electric school buses or rewiring a bus depot.

NYSERDA will help educate school district administrators and the public about the cost-benefit relationship in this conversion, and suggests districts conduct voter outreach of their own.

The state will focus its support of electrification in historically environmentally or economically burdened areas and those that are most at risk from transportation emissions.

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Texas PUC: 8.3 GW of Retirements ‘Ain’t Gonna Happen’

Texas regulators last week directed ERCOT to not include scenarios assuming the loss of more than 8 GW of fossil generation as the grid operator’s staff continues to develop a reliability standard.

ERCOT briefed the Public Utility Commission on its reliability standard study modeling results during Thursday’s open commission meeting. Staff shared the outcome of the 48 scenarios they developed for the analysis and recommended that an additional study iteration be performed (54584).

However, the commissioners balked at the inclusion of an aggressive 8.3-GW figure for assumed coal and gas units’ retirement. The figure is based on EPA’s proposed rules limiting greenhouse gas emissions and other regulations. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)

Commissioner Will McAdams said, “There’s no way the Public Utility Commission of Texas is going to allow this to happen.”

Commissioner Lori Cobos agreed with McAdams, saying ERCOT’s current 3.3-GW assumption for retirements would be more “reasonable” to expect.

“I think that 8,300 is an extreme scenario, and I don’t think it does any good to be opining for an extreme scenario that doesn’t seem to be coming to fruition, given market dynamics but also ERCOT actions and legislative action,” she said.

“Even then, the state will take steps to ensure that this doesn’t happen,” McAdams added. “We are not powerless and there are legal remedies here. There are market-driven remedies to keep these in system. We argued about this in the market design debate, and I said, ‘This ain’t gonna happen.’

“I fear that if we start subtracting massive amounts of megawatts out of the models — due to hypothetical federal regulations which we are sure to litigate and go all the way to the U.S. Supreme Court, which will take some time — I believe it will blow out the top of our models, unduly alarm the public and create a narrative that certain alternatives are better,” he said. “I would advise simpler is better. Provide focus to ERCOT, clear the field of the massively hypothetical scenarios and then just look at what we have in the range.”

ERCOT’s Kristi Hobbs, vice president of system planning and weatherization, agreed to reduce the retirement assumption to 3.3 GW. She also said staff would continue to include a one-day-in-five-years loss-of-load expectation in its frequency scenario limitations, along with LOLE expectations of one day in 10, one day in 15 and one day in 20 years.

Frequency Target

The PUC agreed with ERCOT’s recommendation to include a reliability frequency target in future studies that uses a capacity mix with additional inverter-based resources.

ERCOT has proposed a three-part framework that considers the duration and magnitude of a loss-of-load event, along with the occurrence’s frequency. It says this will better quantify LOLE risks when intermittent resources are a large percentage of the generation fleet. (See “ISO Prioritizes Market Changes,” Texas Public Utility Commission Briefs: Aug. 24, 2023.)

$30 Million Procurement

ERCOT staff also shared with the commission results of the firm fuel supply service’s (FFSS) second procurement, revealing the ISO acquired 3,319.9 MW of the reliability product for $29.9 million for the Nov. 15-March 15, 2024, obligation period (53298).

That was 13% more capacity and an estimated 43% cost reduction from the grid operator’s first procurement of FFSS capacity. That resulted in 2,940.5 MW of capacity for $52.9 million during the Nov. 15, 2022-March 15, 2023, obligation period.

Five qualified scheduling entities responded to ERCOT’s second procurement by offering 32 generation resources to act as FFSSRs during the obligation period. The grid operator awarded each resource the commission’s clearing price cap of $9,000/MW; 31 of the 32 generators offered fuel oil as the reserve fuel and one offered natural gas storage.

The first procurement saw 19 resources awarded at $6.19/MWh ($18,000/MW). Eighteen of the 19 generators offered fuel oil as the reserve fuel and one offered natural gas storage.

ERCOT added FFSS at the PUC’s direction after the disastrous 2021 winter storm, when curtailed gas supplies knocked numerous units offline and nearly collapsed the grid. The service is designed to provide additional reliability and resiliency during extreme cold weather by maintaining resource availability during gas curtailments or other fuel-supply disruptions.

The commission expanded eligibility to a broader range of resources for the service after its first phase.

Nuclear Working Group Meets

Following the open meeting, Commissioner Jimmy Glotfelty held an informational briefing for stakeholders interested in joining a PUC working group that will spend the next 14 months looking for ways to position Texas as a national leader in small modular reactors (SMRs) (55421).

In August, Gov. Greg Abbott (R) directed the PUC to create a working group to study and provide recommendations on SMRs. He also asked Glotfelty to chair the team, which the commission has labeled the Texas Advanced Nuclear Reactor Working Group. (See Texas Seeking Lead Role in Nuclear SMRs.)

“When the governor asks you to do it, you have to do it,” Glotfelty said.

PUC’s Jimmy Glotfelty briefs stakeholders on a working group that will address small modular reactors. | Admin Monitor

Nearly 20 market participants, companies and individuals already have filled out applications to join the working group. The first meetings will be held in October after the team members have been selected. Public meetings will continue into April before the team begins drafting a report with recommendations that is due to Abbott by December 2024.

“It’s exciting to see so much interest in this even when every day there’s another headline about something in this space. The challenge with those headlines is very few of them say Texas,” Glotfelty told stakeholders. “Our goal in this process is to figure out how we get more of them going.”

The commission says the group will evaluate how advanced reactors can provide safe, reliable and affordable power for Texas. It will study financial incentives, state and federal regulatory impediments to growth, the electric market’s effects, technical challenges and additional factors necessary to grow nuclear energy in the state.

“This is not going to be a government report that sits on a shelf. I’ve written plenty of those,” said Glotfelty, who brings years of experience at the U.S. Department of Energy to the position. “This is not to understand a good place to deploy these reactors. It’s to set the playing field so we can deploy these reactors.”

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PJM OKs 32% Cut in Elliott Penalties in Proposed Settlement

PJM has agreed to reduce its nonperformance penalties 31.7% for generators that could not meet their capacity obligations during the December 2022 winter storm.

A proposed settlement filed Sept. 29 by PJM and 81 other parties would resolve the bulk of 15 complaints generators filed against the RTO arguing that it had either improperly declared performance assessment intervals (PAIs) in regions where emergency conditions were not present or unjustifiably applied nonperformance penalties (EL23-53, et al.).

PJM did not admit to any wrongdoing or violation of its tariff in the settlement, and the agreement does not include any changes to the governing documents. The filing states that the settlement was either supported or not opposed by the “overwhelming number of active parties in the case.” (See Settlement Possible Between PJM And Several Generation Owners over Winter Storm Complaints.)

“These Winter Storm Elliott complaints had the potential to become the next ‘mega-litigation’ along the lines of the California Energy Crisis litigation or the Seams Elimination Cost/Charge Adjustment/Assignment litigation; instead, the settling parties have achieved a negotiated resolution that avoids years (or, in the case of the California Energy Crisis, decades) of litigation and now present that resolution to the commission for approval,” the filing said.

All 15 complaints would be resolved by the settlement except for portions of complaints by East Kentucky Power Cooperative (EKPC) (EL23-74) and Energy Harbor (EL23-63) to be decided by FERC. The settlement allows EKPC to pursue its request to modify its penalty charge rate and stop-loss rate.

EKPC argued that the Capacity Performance (CP) penalty rate and stop-loss limit are unjust and unreasonable by not being tied to the revenues market sellers receive through the capacity market — potentially resulting in resources being levied penalties larger than their capacity revenues. The complaint called for the commission to modify the penalty calculation to instead use the Base Residual Auction (BRA) clearing price, rather than the net cost of new entry (CONE) for both the charge rate and stop-loss. EKPC requested that the change be effective for the 2023/24 delivery year.

The PJM Board of Managers directed staff to revise the stop-loss to be based on the BRA clearing price as part of a larger reworking of the capacity market expected to be filed this month. The penalty charge rate would remain based on net CONE. (See PJM Board Releases Outline of CIFP Filing.)

The EKPC complaint also argued that PJM violated its tariff by not curtailing nonfirm exports during emergency conditions and that the company’s Bluegrass generator should be excused from penalties. EKPC agreed to drop both issues as part of the settlement.

The settlement asks the commission to “decide the merits” of Energy Harbor’s argument that PJM violated its tariff by assessing nonperformance charges against 300 MW of capacity that was unavailable due to maintenance outages. The company contended the capacity should be excused from penalties.

The settlement also includes an agreement that PJM will credit $4.4 million to Lee County Generating Station to resolve its complaint. The RTO will also extend collection of the company’s remaining penalty balance, and corresponding interest, to avoid depleting the collateral PJM holds to support Lee County’s exports to MISO.

Lee County’s complaint argued that it should not be subject to penalties, as it was on a forced outage at PJM’s request and would have been available during the PAIs if dispatchers had not requested that it go offline. In July, the commission approved a request from PJM and Lee County to defer the final six months of the company’s penalty billing schedule through June 2024 to avoid the company defaulting on its obligations in PJM and MISO (EL23-57).

The reduction applies to all market sellers assigned a share of the $1.8 billion in penalties associated with Winter Storm Elliott, including those that have already paid their penalties in full. Recipients of bonus payments — which are distributed to generators that overperformed during PAIs out of the pool of penalties collected — will be required to refund a portion of their allocation.

The penalty reduction is predicated on market sellers continuing to meet their payment obligations or already having paid off their penalties. If a party defaults or does not make a payment, the original full penalty will be reinstated with interest. Market sellers who opted for a longer nine-month repayment timeline, which comes with the tradeoff of being subject to interest, will have the interest due on their penalties recalculated to use the lower settled figure. Interest will not be due on the bonus payment refunds. (See “FERC Approves Alternative Billing Schedule,” PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)

PJM will also re-evaluate the collateral each market participant must provide PJM to take into account the reduced penalties. Parties that have paid off their charges in full will have their collateral released under the settlement.

The settlement is contingent on FERC approval “without material modification or condition,” and it states that the filing will be withdrawn unless the settling parties agree to any modifications the commission may condition its approval on. The filing requests commission approval no later than Dec. 29 and use of the default comment period, which would make responses due Oct. 19.

“Timely commercial certainty is a core objective of the settlement, and that objective would be significantly undermined if the commission does not approve the settlement by the end of this calendar year,” the filing said.

On Oct. 25, the commission granted a tariff waiver PJM and several complainants requested to allow the RTO to delay collection of unbilled penalties and distribution of bonuses until the settlement is acted upon by the commission and can be implemented by PJM. The order stated that delaying billing would be “administratively efficient” by reducing the potential for rebilling and resettlement should the settlement be accepted and result in a change in the penalties due.

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CAISO Proposal Seeks to Address Interconnection Backlog

As CAISO grapples with an “unprecedented” surge in interconnection requests, the system operator has proposed prioritizing requests in zones where transmission capacity now exists or is under development.

The “zonal approach” is outlined in a straw proposal CAISO released Sept. 21 as part of its 2023 Interconnection Process Enhancements (IPE) initiative.

CAISO has been overloaded with interconnection requests resulting from the rapid pace of clean energy development in California as the state works toward a goal of 100% clean energy by 2045.

The most recent group of interconnection requests, Cluster 15, included about 544 requests totaling around 354 GW. That compares to 150 requests in 2020 and 373 requests in 2021.

CAISO said the increased number of requests is “unsustainable” and has overwhelmed existing processes.

“The ISO needs a significantly reformed structure to advance viable projects and prevent stagnant projects from hindering the progress of viable projects in the queue,” CAISO said.

In response, the straw proposal lays out a “significantly reformed interconnection process” aimed at promoting “rapid deployment of new generation for reliability, affordability and decarbonization.”

Zones, Scoring and Auction

CAISO calls the zonal approach a “central tenet” of its straw proposal. The ISO said its 2022/23 transmission plan took a zonal approach to planning for the resources in the portfolio provided by the California Public Utilities Commission for that cycle, “setting the foundation for the alignment of procurement and interconnection process enhancements.”

Under the proposal, projects in zones with available transmission capacity would be prioritized to move into the study process.

CAISO noted the importance of publicly providing information on the priority zones before opening an interconnection request window, such as a heatmap showing available transmission capacity. A heatmap is one of the requirements of FERC Order 2023, issued in July, regarding interconnection reform. (See FERC Updates Interconnection Queue Process with Order 2023.)

In another proposal, CAISO would use a scoring system in situations where the capacity of interconnection requests exceeds the available transmission capacity within a zone by more than 150%. Scoring criteria might include interest from an offtaker, permitting status and commercial readiness.

In some cases, CAISO would also conduct an auction in which winners would be prioritized and studied in a certain zone. The auction would occur when proposed capacity exceeds the capacity limit for a zone, after viability criteria are applied.

CAISO said an auction process may be needed “to achieve manageable queue volumes and preserve the competition of viable projects in each zone.” The ISO acknowledged that the auction proposal raised a number of stakeholder questions, including how the auction proceeds would be spent.

Interconnection Option B

The proposal also includes a process, called Option B, for requests to interconnect outside of priority zones. Those projects would be required to pay for needed network upgrades.

CAISO held a series of stakeholder meetings over the summer to come up with ideas for addressing the high volume of interconnection requests. (See CAISO Tries to Shake up Its Interconnection Process.)

Comments on the new straw proposal are due Oct. 12. After that, CAISO will release a second draft, followed by another round of comments. The proposal is expected to go to the CAISO Board of Governors for approval in February.

The straw proposal is part of Track 2 of the 2023 IPE initiative. Track 1 involved changes to the Cluster 15 study schedule that were approved by the Board of Governors in May.

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MISO PAC Considers Lower, $9B MTEP 23 Transmission Package

MISO’s Planning Advisory Committee is deciding whether to approve the MISO 2023 Transmission Expansion Plan, which has dropped to just under $9 billion within a month.

Last month, MTEP 23 stood at 578 projects totaling $9.4 billion. Now the annual portfolio clocks in at $8.96 billion across 575 projects.

At a special Sept. 28 teleconference, the PAC opted for an email ballot through Oct. 5 on whether to recommend the portfolio to MISO board members. The PAC’s vote is advisory and can be bypassed.

MISO’s Jeremiah Doner said transmission owners have reviewed projects, made adjustments and refined cost estimates since the final round of subregional planning meetings on MTEP 23 in September.

Doner said some projects have been postponed to later MTEP cycles. Most notably, MISO has deferred the $260 million third phase of Entergy Louisiana’s Amite South reliability project into MTEP 24.

MISO is conducting additional analysis on possible alternatives to the project, which was among MTEP 23’s most expensive, Doner said.

Despite the deferral of the Entergy project, MISO South’s 77 projects still account for 46% of MTEP 23 spending. MISO remains committed to its recommended, $1.7 billion, 500-kV Commodore-Waterford-Churchill loop project, which will replace both the first phase of Entergy Louisiana’s Amite South project and the Downstream of Gypsy reliability project, another Entergy Louisiana proposal. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)

MTEP 23 contains $1.2 billion in generator interconnection upgrades, $1.7 billion in baseline reliability projects and nearly $6 billion in “other” projects, which includes reliability projects based on transmission owners’ self-imposed criteria separate from NERC standards, such as projects responding to load growth or addressing the age and condition of existing facilities.

Doner said MISO is confident it has assembled a package of “efficient, cost-effective solutions to identified system issues.”

Sector Critiques

MISO’s Competitive Transmission Developers Sector said the RTO should have reviewed more projects for “more efficient or cost-effective regional project alternatives.”

“Such a review is required by the MISO tariff and FERC Order No. 1000, and the failure to consider alternatives may lead to the approval of transmission projects that do not efficiently solve these and other system needs, which ultimately increases costs to customers,” the developers said.

Doner responded that MISO already prioritized alternative analyses for proposed new lines and larger, expensive projects that may affect the entire system.

“Roughly 75% of MTEP 23 projects didn’t meet criteria for alternative solution analysis, as they address needs with no cost-effective alternatives,” he said.

The RTO’s Environmental Sector said the MTEP 23 report should mention MISO’s “struggles to manage” its 242-GW generator interconnection queue and should describe what resources it needs to complete studies on time.

Doner said MISO continues to work on its queue processing time. He also pointed out that MISO is sitting on 49 GW worth of new generation that’s on hold despite MISO having already studied it and signed off on interconnection. He said “limitations on new interconnections are due to factors outside of MISO’s control, such as construction delays and supply chain issues.”

The Environmental Sector also asked MISO to pay more attention to HVDC lines in MTEP reports and do more to explore the potential for battery storage in MISO’s future.

Doner said MISO agrees that HVDC lines could be necessary. He said MISO and stakeholders will discuss HVDC needs as part of the second portfolio under MISO’s long-range transmission planning.

Doner also said, “MISO will monitor market performance and interconnection processes for potential improvements as more storage is constructed.”

Sustainable FERC Project’s Natalie McIntire said though the Environmental Sector often provides substantial comments, MISO “rarely” changes or adds detail to its MTEP reports based on the sector’s suggestions.

MISO said it will publish the comments it received as an appendix to the MTEP 23 report.

MTEP 23 will enter its next review at an Oct. 17 meeting of the System Planning Committee of the MISO Board of Directors.

MTEP 24

Meanwhile, MISO transmission owners have already submitted project proposals for MTEP 24, which will use the RTO’s new, one-stop model manager. The model manager project aims for one system of record for all planning and operations models to eliminate redundant data entry and review.

MISO and vendor Siemens are working to synchronize data collection fields between MISO’s different model structures. At the Sept. 27 Planning Subcommittee, MISO’s Scott Goodwin said he expects a few hiccups as MISO transitions to the new model system for MTEP 24.

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MISO May Use Inaugural Near-term Congestion Study to Plan Smaller Tx Upgrades

MISO’s exploratory study on alleviating near-term transmission congestion has led the RTO to consider adding near-term economic benefits to its existing long-term economic planning.

Speaking at a Sept. 27 Planning Subcommittee, economic planning engineer Sean Rogers said that, as a result of this year’s inaugural near-term congestion study, MISO “will continue to explore how to adapt economic models and processes to identify near-term issues and solutions.”

MISO’s economic planning models are geared toward long-term horizons, not short-term congestion relief and economic benefits.

Rogers called the study a “starting point” for MISO to translate its long-term economic planning processes into a near-term model. He said over 2024, MISO will investigate how it can modify long-term planning models to “be more applicable for near-term use” and that the continuing evaluation will be part of the 2024 MISO Transmission Expansion Plan (MTEP 24).

Under this year’s purely informational study, MISO studied its top 10 most congested flowgates in its day-ahead market from 2021 to 2022. It assigned an unlimited kV rating on the flowgates in the study to pinpoint when hypothetical upgrades were beneficial over a five-year horizon based on adjusted production costs.

The study is for informational purposes only, so MISO isn’t recommending any transmission projects from its conclusions. However, planners said they may suggest projects after 2024’s study.

Stakeholders had requested that the grid operator come up with smaller, congestion-relieving projects like its interregional targeted market efficiency projects with PJM and SPP. (See MISO Adding Near-term Congestion Study to MTEP.)

MISO has said it first needs to better understand the nature of its near-term congestion before proposing a new project type and potential cost allocation. Some stakeholders have expressed disappointment that the study hasn’t resulted in a new class of projects.

Nevertheless, MISO found that if Duke Indiana’s Cayuga 345/230kV transformer were upgraded in west-central Indiana, it could save $2 million annually in adjusted production costs. The facility racked up about $30 million in day-ahead congestion in 2022.

Southern Minnesota Municipal Power Agency’s Murphy Creek – Hayward 161-kV line could save a little more than $1 million per year with an upgrade, cutting into the $28 million in day-ahead congestion it accumulated in 2022.

All other hypothetical upgrades on MISO’s top 10 most congested flowgates saved less than $500,000 annually. Two showed negative benefits because of impacts on nearby facilities.

MISO found a contradictory, $5 million in additional annual costs when it studied an upgrade to Ameren Illinois’ Marblehead North 161/138-kV transformer. MISO said it will continue to examine the reasons behind the economic harms. The Marblehead flowgate accumulated more than $102 million in day-ahead congestion costs over 2022.

Some flowgate congestion cases were found to be linked to temporary outages. Congestion on Great River Energy’s Johnson Junction – Graceville 115-kV line in Minnesota — which surpassed $71 million in congestion costs in 2022 — was “directly related to the planned construction outage on the Johnson Junction to Morris line” from Oct. 1, 2021, to Feb. 1, 2022. Two other congested flowgates were linked to Duke Energy Indiana’s Cayuga Unit 1 outage.