Vistra (NYSE: VST) said Monday it will buy Energy Harbor and combine the two firms’ nuclear plants, renewable facilities and retail businesses into a new subsidiary called “Vistra Vision.”
Vistra is paying $3 billion and assuming $430 million in debt, while Energy Harbor’s two biggest shareholders, Nuveen and Avenue Capital, will continue to own 15% of Vistra Vision. Vistra’s fossil assets, which total 24,000 MW of natural gas units and 8,400 MW of coal, will be in a separate subsidiary called “Vistra Tradition.” The deal needs to be approved by the Department of Justice, FERC and the Nuclear Regulatory Commission; Vistra expects it will close later this year.
“Through this creative transaction we will combine Vistra’s nuclear, retail, renewables and battery storage assets with Energy Harbor’s nuclear and retail assets to create one of the largest clean energy businesses in the country,” Vistra CEO Jim Burke said on a conference call with analysts.
Energy Harbor, which was spun off from FirstEnergy (NYSE:FE), owns three nuclear plants in Ohio and Pennsylvania and has a competitive retail power business serving 1 million customers in PJM and MISO. That will be matched with Vistra’s Comanche Peak nuclear plant in Texas, its renewable and storage projects around the country, and its retail business in Texas and other states.
Vistra Vision will have a about 7,800 MW zero-carbon generation, about 5 million retail customers and access to a pipeline of 1,100 MW of additional renewables projects. It would be the second largest operator of nuclear plants in the country with six reactors across its four plants.
With the country navigating a transition to cleaner energy, nuclear provides the unique capability of being both carbon free and available around the clock to serve demand, Burke said.
“The nuclear production tax credit provides significant downside protection while maintaining the ability to capture upside through market volatility and … hedging forward,” Burke said.
The federal PTC for nuclear, part of last year’s Inflation Reduction Act, will effectively give the firm’s four nuclear reactors an earnings floor. It provides revenue support when a nuclear plant’s “gross receipts” are below $43.75/MWh and can contribute up to $15/MWh when gross receipts drop to $25/MWh.
Power prices were much higher when Vistra first considered the deal last summer because of spiking natural gas, but Burke said his firm is doubtful that prices can go much lower and does not expect cheap natural gas, or resulting power prices, to stick around long.
“Our returns on our PTC case are not that much further below the returns that we actually modeled for this,” Burke said. “And we think we’re modeling closer to the downside of the opportunity with still a lot of upside opportunity, depending on how gas and power … behave from this point forward.”
While Vistra Tradition would be home to the firm’s fossil assets, Burke said that Vistra Vision would use its generation to firm up supplies for retail customers as needed.
Keeping the traditional generation around also gives the firm a larger scale, which could help it invest in new technologies as they become viable, he said.
“We’ve got some opportunities with sites to do things with future nuclear technologies, potentially even at existing coal sites and sites that we’re retiring,” Burke said.
The firm’s coal plants are eventually going to retire, but Burke expects the natural gas generators will be needed for a long time to come.
Separating the two businesses gives investors and customers more visibility into the clean energy assets that Vistra has, Burke said, conceding that it might eventually make sense to split the two businesses completely.
“But right now, these are both scaled businesses with some interdependencies, and so I think we’re going to focus on running this in an integrated fashion for a while,” he added.
SAN FRANCISCO — CAISO had just won approval from its Board of Governors last month for a day-ahead extension of its Western Energy Imbalance Market when a state lawmaker introduced a bill a week later to allow the ISO to become an RTO, CEO Elliot Mainzer recalled Thursday in his keynote address at the Energy Bar Association Western Chapter’s annual meeting.
“Some of us thought, ‘Oh boy, we just got EDAM [the extended-day ahead market] done. Wouldn’t it be nice to have a little bit of time just to let that play out and let that evolve?’” Mainzer said. But the “zeitgeist in the West” is one of rapidly evolving efforts to organize the region’s balkanized electricity sector into markets and programs that could lead to RTOs, he said. (“Zeitgeist” is a German word meaning “the spirit of the times.”)
The measure introduced Feb. 8, Assembly Bill 538, by Assemblymember Christopher Holden would allow CAISO to develop a plan for governance independent of California’s governor and legislature, with a governing body that could include members from other states. (See Lawmaker Introduces Bill to Turn CAISO into RTO.)
“The reality is that … outside of California, I think a lot of people who are thinking about making significant additional investments either in the day-ahead market or even beyond … want to see a pathway to independent governance for the ISO,” Mainzer said. “And I think they need to see that as a way to get them comfortable staying with [CAISO and the Western EIM] and continuing to invest and grow with our organization as it evolves.”
Mainzer’s remarks in his keynote address were part of a discussion at the meeting about efforts by CAISO, SPP, the Western Power Pool (WPP) and others to assemble the West’s 39 balancing authorities into mutually beneficial organizations for resource adequacy, transmission planning and market transactions.
About 100 energy lawyers gathered at the historic Westin St. Francis hotel on San Francisco’s Union Square for the chapter’s first in-person meeting since the COVID-19 pandemic began three years ago.
In a panel on resource adequacy, WPP Executive Director Sarah Edmonds described FERC’s recent approval of the group’s Western Resource Adequacy Program, a West-wide RA effort with 18 participants and three more expected to join. (See FERC Approves Western Resource Adequacy Program.)
The order allows the WRAP to move forward with a binding phase of its program, which would hold members accountable for failing to meet their resource requirements as part of the RA pool.
“We are currently working to identify what season WRAP goes binding,” Edmonds said. “The tariff that [FERC] approved allows flexibility for the region to determine which season, winter or summer, between now and 2028, [that] we’re going to select.”
CAISO and SPP executives described their efforts to organize markets in a panel on Western regionalization, while a strategic planner for Arizona’s Salt River Project offered the views of one potential market participant.
Anna McKenna, CAISO’s vice president of market policy and performance, highlighted the success of the Western EIM (WEIM), which has generated $3.4 billion in participant benefits since it began in 2014. The performance of the market, which has dealt only in real-time transactions, is the ISO’s main selling point for utilities to join the EDAM, which would encompass the much larger day-ahead market.
The WEIM has 19 members, including some of the West’s largest utilities such as PacifiCorp and the Bonneville Power Administration. After three new members join this year, it will encompass roughly 80% of load in the Western Interconnection.
“It’s been extraordinarily fruitful for all of us,” McKenna said.
Adding a day-ahead market would leverage the WEIM’s success by allowing Western entities to coordinate their diverse resources — hydropower, solar, wind and thermal generation — into the day-ahead time frame, “which of course, as you can imagine, really unleashes an extraordinary amount of opportunity for our diversity to be really optimized across those footprints.”
A study commissioned by CAISO found the EDAM could produce $1.2 billion a year in benefits, or 60% of the savings of a West-wide RTO, if it encompassed the entire U.S. portion of the Western Interconnection. (See West Could Save $1.2B a Year in CAISO EDAM.)
The CAISO board and the WEIM Governing Body approved the EDAM on Feb. 1. It still requires FERC approval. The ISO is developing a tariff for stakeholder review and hopes to submit it to FERC later this year.
“With all the attorneys in this room, you guys can’t wait to get your hands on that. It’s coming,” McKenna said to laughter. “One thing I’d like to do is invite you all to really participate closely in that process because one of the benefits we get is your legal input and insights on the documentation we put out there. So please do participate.”
RTO West, Markets+
SPP is planning to offer its own day-ahead energy imbalance market as part of Markets+, a program currently in development, said Paul Suskie, SPP’s general counsel and executive vice president of regulatory policy.
SPP is also planning RTO West, a Western version of its Eastern Interconnection RTO. Nine entities have committed in writing to joining the RTO, including three regions of the Western Area Power Administration and utilities in Colorado and Wyoming.
Markets+ has signed funding agreements with eight Western entities for the program’s first phase, in which stakeholders will help draft tariff language and outline a governance plan. (See related story, SPP Moving Quickly on Markets+’s Development.)
Suskie said SPP plans to apply its governance model — with an independent board, a committee of state regulators and stakeholder groups that develop and vet policy proposals — to Markets+.
“It’s a very effective process [that] … empowers organizations and people to get in the room discussing … issues, to develop the actual tariff language and vote on [what] is ultimately filed at FERC. So, when we make a filing at FERC, it’s language that has been vetted, voted on, debated and amended through the stakeholder process.”
Suskie said he thinks FERC will approve RTO West before Markets+ because the RTO model is more familiar than the novel Markets+ design.
‘Towards an RTO’
The Salt River Project, a participant in the WEIM and one of the utilities that signed a funding agreement for Markets+, wants to “see two really good [day-ahead] market options come forward” from SPP and CAISO to determine which would benefit its customers most, said Josh Robertson, the utility’s director of energy market strategy.
The utility favors an incremental approach to market development, and a day-ahead market is already a big step compared to a real-time market, Robertson said.
“EDAM, potentially the next step, might be enough,” he said. “We don’t know. We might be good with that. But we do value the possibility of moving forward with an RTO, and seeing a pathway towards an RTO will be an important aspect in terms of our eventual decision-making and our engagement,” Robertson said.
As one or more RTOs emerge in the West, independent governance will be key to SRP and others joining, he said, echoing Mainzer’s keynote remarks.
“It’s just really important that these markets have a transparent, independent governance process,” Robertson said. “We don’t want a single entity, region [or] state … to be able to drive the decision-making here. It really needs to be independent and transparent.”
VANCOUVER, British Columbia — Scott Stephens, professor of fire science at the University of California, Berkeley, last week offered an unexpected piece of advice for Western U.S. states and Canadian provinces that face a rising danger of catastrophic wildfires.
“Don’t do what California did,” Stephens said Wednesday during the opening panel of the Western Interstate Energy Board’s (WIEB) Winter Wildfire Meeting.
Scott Stephens | University of California, Berkeley
At the core of Stephens’ advice was a seemingly paradoxical message that would be reinforced by other panelists throughout the conference: that the growing wildfire threat in the West is as much a product of a century of strict fire-suppression practices than of climate change.
Stephens opened his presentation with a picture showing the aftermath of the 2021 Dixie Fire, the second largest wildfire in California history, which scorched more than 963,000 acres and destroyed several small communities over that summer. California’s Department of Forestry and Fire Protection later pinned the source of the fire on a Pacific Gas and Electric distribution line that was struck by a tree. (See Cal Fire Finds PG&E Started Massive Dixie Fire.)
“The Dixie Fire was horrendous. It is a disaster times 10,” he said. “I’ve been in that thing [burn area] for about three weeks in June of last year to see some of the effects. It literally is something that can make you cry: the damage to the forest ecosystem; [it] burned down the town of Greenville. There’s so many connotations to this that we’ve got to do better.”
‘This is a Disaster’
For Stephens, doing better means looking back to a time before the displacement of indigenous peoples, who for centuries engaged in the practice of controlled burns to maintain forest health and prevent large-scale wildfires that could threaten their living spaces.
Stephens pointed to a study from 1924 that described California’s pine forests as “broken, patchy, understocked stands, worn down by the attrition of repeated light fires.” The ground contained little surface fuel, and extensive crown fires — in which the fire moves from treetop to treetop rather than along the forest floor — were “almost unknown,” the researchers found.
But since that time, federal and state policy has aimed to discourage the spread of any fires, even those occurring naturally. That has fostered the development of denser forests where trees increasingly compete for space, compromising the health of many of the oldest, most fire-resistant trees, and creating fuel load to feed the fast-moving and highly destructive crown fires that have plagued California in recent years. On top of that, many of the largest trees most resistant to burning have been harvested for lumber.
A 2022 study cited by Stephens found that in 1911, 73 to 85% of California’s mixed conifer forests were in a condition of “free” or “partial” competition among trees. By 2011, 82 to 93% of those forests were in “full occupancy” or “imminent mortality.”
“This is a disaster,” he said. “If you have a forest ecosystem going into climate change with those characteristics, you better just hold on, because that forest is not resilient.”
Stephens said the increasing number of unhealthy, fallen trees on the forest floor translates into heavy fuel loads that make it impossible to predict how fires will behave once they start. He noted that the 2020 Creek Fire in the Sierra National Forest, which burned nearly 380,000 acres, occurred under normal wind, temperature and humidity conditions. The fire was not driven by wind but by dead wood on the ground, and its movement defied models designed to predict how it would spread.
“This was actually kind of scary, both for our managers [and] utilities … because it tells us that not a single model in the United States is able to predict what these fires can do under the worst conditions,” he said.
Stephens finds hope in a different approach to forest management that draws on the historical practices of indigenous peoples. For more than a year he’s been participating in the Stewardship Project, which he described as a “50/50 partnership” among tribes and “Western science” across the Western U.S. The project aims to address issues such as a tribal right to steward forests, regulatory reform around fire-management practices and workforce development to manage woodlands.
“What we’re trying to do is come up with some policy recommendations for the federal government,” said Stephens, who sits on the Wildland Fire Mitigation and Management Commission, created by the Infrastructure Investment and Jobs Act of 2021.
He recommends that policymakers allow forest managers to adopt practices that include prescribed burns when conditions permit, as well as “restoration thinning,” which would entail mechanical removals that focus on what should be left behind to create a more resilient forest — based on tree species, sizes and spatial patterns — rather than what should be taken out. And although some tree removals might end up in sawmills, economic harvesting of timber would not be a priority.
‘Era of Megafires’
“When Scott comes here and tells me, ‘Don’t do what we did,’ it makes me nervous because we keep watching to learn from California and to help us track where we’re going and the attempts that we’re making to be proactive in this same space,” said Lori Daniels, a professor in the Department of Forest and Conservation Sciences at the University of British Columbia.
About 95% of British Columbia’s land is publicly owned, and the province contains about 235.8 million acres of forest, of which nearly 59.3 million are actively managed. Roughly 494,000 acres are harvested annually, although that number has declined in recent years, according to Daniels.
Daniels said the province has already adopted a timber harvesting policy that is “meant to emulate what fire used to do on our landscapes.”
The province experiences about 1,700 fires a year, with lightning causing 60% and humans the other 40%. About 94% of all fires are quickly extinguished.
“So the only fires that we have experienced in our lifetime are the top 6% that burned under extreme weather, heat, drought [and] wind and escaped all our modern technologies to put out fires. So we have this really biased view of what fire is,” she said.
As in California, fire-suppression practices over the past century have resulted in denser forests that are now fueling larger wildfires in British Columbia in recent years. While the province has experienced some large burns in the past (about 1.7 million acres in 1920 and 2.1 million acres in 1958), recent years have seen fires growing even bigger. In both 2017 and 2018, it saw burns exceeding 2.9 million acres. During the Pacific Northwest heat wave of summer 2021, temperatures in the village of Lytton hit a record-shattering 121.3 degrees Fahrenheit on June 29. The next day, a fast-moving wildfire swept through the area, destroying 90% of the village and killing two people.
“It’s the cumulative impacts of both extreme weather [and] these land-use changes that have been building up over a century,” Daniels said, adding that we live in an “era of megafires.”
Daniels said British Columbia’s success in extinguishing wildfires has made residents “naive,” thinking they can dial 911 to have firefighters put out any fire.
“Our fear and our desire to protect our lives and homes — and our forests and our livelihoods — from fire has contributed to the problem,” Daniels said, noting the importance of logging to the region’s economy. The province’s forests are still managed with an eye to maintaining timber harvests, which has “homogenized the landscape” and puts the focus on economics rather than forest resilience.
But conditions have changed, she said, and there is now a need to put “pressure on our decision-makers to make it a priority to make the [policy] changes that are needed.”
Key among those changes is the need to “coexist with fire” in the landscape. The province has already moved in that direction, having in 2014 adopted a policy of permitting some fires to burn in locations away from communities when it’s considered safe to do so — allowing “fire back as part of the ecosystem, creating heterogeneity and breaking up those fuels,” Daniels said.
It’s an approach to forest management that New Mexico has also recently adopted, according to Lindsey Quam, deputy state forester and tribal liaison for the New Mexico Energy, Minerals and Natural Resources Department’s Forestry Division, who spoke on a separate panel Thursday.
Quam said that in New Mexico, climate change is bringing higher temperatures and a windy season that starts earlier and lasts longer, “which is drying out our fuels a lot faster,” particularly in the “high country” areas at elevations of about 12,000 feet.
“We’re working outside the norms of what we’re used to, predicting what fire may do; what winds may do; what temperatures may do. How that’s going to impact or affect fuels is getting harder and harder” to predict, Quam said. “Our models can’t keep pace. Our models are working beyond what they were built and designed for, so we don’t have a good prediction in order to know what we may be facing out in the forest.”
‘Fire is not the Enemy’
In response to the changing conditions, in 2020 the New Mexico Forestry Division implemented the Forest Action Plan, a “science-based” plan that uses geospatial analysis to assess threats to the state’s natural and cultural resources. The plan includes 10 strategies, including those related to forest and watershed restoration, fire management and utility rights of way (ROWs). The latter strategy seeks to work with utilities to clear out ROWs to reduce wildfire risk and ignition, providing $1 million in state funds to support those efforts. It also works to incorporate state utility data into the federal Wildland Fire Decision Support System for guidance during wildfires.
Additionally, New Mexico lawmakers in 2021 passed the Prescribed Burning Act, which focuses on encouraging more prescribed burns on the state’s private lands. The law is intended to reduce liability for private landowners and created a program to certify burners.
Lindsey Quam | New Mexico Forestry Division
Quam pointed out that recent studies on New Mexico’s Jemez Mountains and Gila National Forest indicate that past fires in those areas were larger but less destructive than present-day burns. He said the research is finding that those fires were purposely set by tribes “to create a defensible space around their living areas.”
“We have to consider that we really need to look at science and what science is telling us and incorporate that into our times, but we also need to incorporate a lot of traditional cultural knowledge as well,” Quam said.
Speaking on a different panel Thursday, Oregon Public Utility Commissioner Letha Tawney said she was struck by the fact that when colonists and “resource extractors” came into the West, they were encountering a land that was being actively managed by the indigenous inhabitants.
“I think we still persist — or I still persist — unwittingly in a very strong sense that there was a pristine wilderness” until the intervention of the past 150 years, Tawney said, but the evidence is clear that European settlers “walked into a landscape that was being actively and quite professionally managed, and had been for probably millennia.”
“Fire is a cycle. Fire is a process. Fire is not the enemy,” said Kit O’Connor, a research ecologist with the U.S. Forest Service.
“Wildfires are treating acres faster than we ever will be able to, so if we’re not using wildfire as part of our equation in solving this problem, then we’re ignoring the biggest tool that we have in front of us,” O’Connor said.
“Sometimes it just feels like hope is out of the sail,” Stephens said. “It’s just like, ‘Wow, what are we going to do? All we’re going to do is basically get beat up.’ That is not necessary. There really is hope to actually do some work that actually can make a difference.”
New York Department of Public Service staff on Wednesday recommended a 58% funding increase for the state’s EV Make-Ready Program for electric vehicle infrastructure.
When it created the program in July 2020, the Public Service Commission stipulated a midpoint review. The DPS’ white paper published Wednesday updates the PSC on the progress made to date and recommends a series of changes for the commission to make.
The recommendations reflect data and feedback gathered in the nearly three years since the order was issued, including through a series of technical conferences with the investor-owned utilities that are carrying out the program — Central Hudson Gas & Electric, Consolidated Edison, National Grid, New York State Electric and Gas, Orange and Rockland Utilities, and Rochester Gas and Electric — and other stakeholders. (See Inflation Hampering Efforts to Expand EV Charging Network in NY.)
Installing charger plugs has proved to be more expensive than was projected in 2020, and analysis has indicated a different mix of direct current fast chargers (DCFC) and Level 2 chargers should be incentivized.
The 2020 order authorized the utilities to spend $701 million in ratepayer money to help reach a buildout target of 53,733 L2 plugs and 1,500 DCFC plugs. Staff are recommending that be changed to $1.11 billion to incentivize buildout of 43,122 L2 plugs and 6,302 DCFC plugs.
Buildout through the Make-Ready Program has also been slower than anticipated.
Only 4% of the original L2 goal and 14% of the original DCFC goal had been completed as the midpoint review was prepared. With the addition of projects committed but not completed, the totals rise to 23% and 42%, respectively.
The pace was such that all six utilities failed to qualify for incentives through the earnings adjustment mechanism specified for L2 chargers, and only National Grid reached the midpoint goal that would qualify it for a DCFC incentive.
The Make-Ready Program supports New York’s landmark Climate Leadership and Community Protection Act of 2019, which mandates a 40% reduction from 1990-level greenhouse gas emissions by 2030 and an 85% reduction by 2050.
The transportation sector is a major source of those emissions. A 2022 New York law mandates that a gradually increasing percentage of passenger vehicles sold in the state be EVs, reaching 100% by 2035. For that to happen, many more publicly available chargers will be needed.
“At the time the Make-Ready order was issued, the commission was confident that the electrification of the transportation sector would help attain the goals of the CLCPA,” DPS staff wrote. “In the three years since the Make-Ready order was issued, it has only become clearer to DPS staff that the electrification of the transportation sector is paramount to the achievement of the goals of the CLPCA.”
The following recommendations by the DPS staff are among those included in the white paper:
Continue to limit administrative costs to 15% of the original program incentive budget in the 2020 order.
Budget $25 million for micromobility charging, for devices such as electric bicycles, skateboards and scooters, and earmark $20 million of that for the New York City area.
Boost the budget for the medium- and heavy-duty vehicle make-ready pilot program from $24 million to $54 million.
Shrink the eligibility radius for the enhanced funding offered for siting L2 chargers in disadvantaged communities, so that wealthier surrounding communities do not benefit.
Seek continued input to shape a workforce development program focusing on disadvantaged communities.
Direct the Technical Standards Working Group to identify barriers to vehicle-to-grid integration and propose solutions.
Convene a technical conference to streamline the collection of charger site data, which is critical to achieving the goals of the Make-Ready Program but has proved challenging to carry out.
Seek additional shareholder input and analyze it before modifying or expanding the transit electrification efforts authorized in the 2020 order.
Do not move forward with consideration of a make-ready program for installation in private residences, because brisk EV sales suggest such incentivization is not necessary.
PJM stakeholders are requesting that the Board of Managers provide more information about its initiation of a fast-track process to address reliability concerns, which it announced in a letter published last month.
“This is not giving us any clear direction … and I think that we’re going to waste a lot of time if we don’t get some clear direction,” Paul Sotkiewicz, president of E-Cubed Policy Associates, said during the Feb. 28 meeting of the Resource Adequacy Senior Task Force.
The board released the letter Feb. 24 in response to “numerous data points suggesting that grid operators may face challenges in maintaining reliability during the transition,” as shown in a white paper released by PJM the same day detailing an imbalance between future resource development and retirements through the rest of the decade. (See PJM Board Initiates Fast-track Process to Address Reliability.)
Invoking the Critical Issue Fast Path (CIFP) stakeholder process, the board identified a set of key work areas it would like to see addressed by proposals for it to consider and potentially send to FERC by Oct. 1.
The four primary areas the board identified include revising the Capacity Performance (CP) model and ensuring any penalty risks can be accounted for in capacity offers; improving resource accreditation to ensure that reliability contributions are accounted for and compensated; enhancing risk modeling to improve understanding of winter risk and correlated outages; synchronization between the Reliability Pricing Model and the fixed resource requirement rules to ensure that supply and demand are held to comparable standards.
Steve Lieberman of American Municipal Power said the letter is eliciting a lot of questions from stakeholders and it would be beneficial for representatives of the board to attend one of the upcoming Markets and Reliability Committee meetings to set the grounds of what they’re looking for in a solution package.
“If we’re going to be jumping through hoops for the next six [or] seven months, let’s make sure we’re jumping through the right hoops,” he said during the RASTF meeting.
Vice President of Market Design Adam Keech said PJM’s understanding of the board’s intent with the letter was to avoid steering stakeholders in the direction of a specific solution, but to identify areas of importance that a solution must address.
“I think this is the scope we have to work with, and it was written for this reason,” he said.
Going through the work areas, Keech noted that many of them have long been under discussion by stakeholders before giving PJM’s interpretation of each of them. Regarding any changes to the CP construct, he said the board believes any risk generators face from penalties should be reflected in their market seller offer cap.
“I see the board saying ‘review CP’ in terms of Winter Storm Elliott and the market seller offer cap,” he said. In the wake of the December 2022 storm, PJM announced that generators could face $1 billion to $2 billion in CP penalties, which has prompted many generators to say they are not adequately able to incorporate the risk of future penalties in their capacity offers. (See PJM Weighs Options for Winter Storm Elliott Follow-up.)
Keech said PJM believes the board wants to incorporate growing risk during winter months into the calculation of reliability requirements.
He also said PJM is likely to pursue a marginal accreditation framework for its effective load-carrying capability method, whereas it currently uses an average, though he acknowledged stakeholders can opt to move in a different direction.
Part of the board’s letter noted that it is interested in exploring if any changes made can be implemented before the 2027/28 Base Residual Auction. But state consumer advocates said any delays to future capacity auctions could interfere with states that procure their own capacity.
“I know that is a concern for at least some of the auctions: further delays and how that affects state auctions,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States.
David “Scarp” Scarpignato said he would like to see additional information about the impact auction delays could have on states at future meetings. He also encouraged PJM to create a framework for presenting the particulars of any proposals that may come forth in an easier-to-read format than the matrix that is typically used, predicting that the process of drafting packages is likely to be “unwieldy.”
“I don’t think someone is going to be able to read a 100-line matrix and understand what it’s saying,” he said.
PJM’s Dave Anders gave an overview of a target roadmap for drafting and voting on packages, with first reads anticipated in June and votes at the MRC and Members Committee in August and September, respectively. Anders and Keech told the task force that the RTO plans to present a draft problem statement, issue charge and proposal, with a target posting date of March 13.
The Market Implementation Committee will continue the discussion of potential auction delays during its March 8 meeting, as well as at the March 15 RASTF.
AUSTIN, Texas — ERCOT staff reported to the grid operator’s Board of Directors last week that despite “not insignificant” forced outages during the December winter storm, it set a new winter demand record and supported “reliable execution throughout event.”
Fossil fuel outages from fuel restrictions and cold weather spiked in the early-morning hours of Dec. 23, knocking more than 14 GW of generation offline at one point. Fortunately for ERCOT, wind resources, the early fall guys during the deadly February 2021 storm, helped fill the gap with about 30 GW of energy at times during the night Dec. 22-23.
“This is a great example of the dependency we have on renewables, because for part of the 22nd and the 23rd, we were in renewable territory,” Director John Swainson said during the board’s Feb. 28 meeting. “If the wind had stopped blowing, we would have been in deep [expletive].”
“As load shot through our forecast, we needed another [6,000] or 7,000 MW,” Texas Public Utility Commission Chair Peter Lake said.
Stoic Energy principal Doug Lewin — who follows ERCOT and, among other data, its forced outages — told RTO Insider that about 25 GW of capacity was offline at some time between Dec 22 and 24. ERCOT went into the event with 6 GW already offline, despite the lack of snow and ice, he said.
The grid operator’s data included 655 individual outages at 348 units, peaking at close to 20 GW during the storm. Initially, 127 outages were considered weather– or fuel supply–related, with a high of almost 4.5 GW. Outages or derates at 97 units were considered weather related (35 were wind), and another 30 were caused by fuel issues; 23 of the latter were at gas units.
Almost 1.5 GW of large flexible loads, such as data centers and bitcoin miners, responded to market prices and curtailed their usage. ERCOT also deployed a total of about 2.5 GW of firm fuel supply service to make up for gas restrictions in North Texas.
Like other grid operators during the storm, ERCOT underestimated the drop in temperatures and its effect on load. In the days before the storm, staff had projected demand would almost reach 70 GW. Instead, it peaked at 73.9 GW on Dec. 23, more than 4 GW than the official record peak set during the 2021 storm and its load shed.
“It was a fairly successful event from a risk perspective. It was also one of the coldest events that we’ve seen in the last 15 years,” said Dan Woodfin, vice president of system operations, referencing the more recent storm. “The key message here is that this under-forecast didn’t have any impact on reliability because pretty much all the generation was all buying, and so we were prepared for much higher load than what actually occurred.”
Woodfin said national weather models underestimated “how quickly and how deep” the storm arrived in Texas. Dec. 22-23’s load-weighted daily minimum temperatures of 13.4 and 16.3 degrees Fahrenheit during the December event were lower than all but two of the 2021 storm’s days.
He said the load-forecast models “overplayed” the demand reduction from businesses shutting down for the holiday weekend and were unable to rely on historic data without load shed for the temperatures. Staff have since identified lessons learned and begun improving the forecast models with a focus on extreme cold events, Woodfin said.
ERCOT is still investigating the forced outages’ root causes.
Carrie Bivens, ERCOT’s Independent Market Monitor, attributed prices that peaked at $4,500/MWh on Dec. 22 to the normal economic dispatch of energy storage resources.
“It was fairly significant pricing event,” she said. “The reason the prices were high is price-setting resources were energy storage resources during that time. They typically have high opportunity costs and high offers, and they were mostly setting the price during that time.”
She said the issue was an example of a case in which real-time co-optimization would have had an effect. The IMM has for several years pushed the market tool’s implementation, which is currently sidelined by the state’s market redesign efforts.
Vegas Applauds Sunset Review
ERCOT CEO Pablo Vegas told the board that the grid operator supports recommendations made following a review by the state’s Sunset Advisory Commission.
“Fundamentally, I think some of the changes can be summarized as improvements to communication, making sure that when we communicate information and reports; … that we’re clear [and] transparent, and we take out the engineering jargon,” he said, “and that what we’re recommending needs to happen in order to always keep reliability at the forefront.”
The commission, which also simultaneously reviewed the PUC and the Office of Public Utility Counsel because of their interrelated responsibilities, recommended:
process changes so ERCOT can restrict the commissioners’ presence during executive sessions and to better define the sessions;
adding a second commissioner to the ERCOT board as a non-voting member;
requiring ERCOT to send a biannual industry report to the legislature;
directing ERCOT and the PUC to re-evaluate the grid operator’s performance metrics and create a public communication guidance document; and
ordering ERCOT to include appropriate budgetary funding for “qualified” economic planning staff.
Under state law, ERCOT, the PUC and OPUC, as do all state agencies, undergo regular sunset reviews to assess their continued need and their programs’ efficiency. The Legislature will consider the sunset commission’s recommendations when the report is filed and make final decisions before its session ends May 29.
Directors Approve Rule Changes
The board approved seven nodal protocol revision requests (NPRRs) and single changes to the Planning Guide (PGRR) and Retail Market Guide (RMGRR) previously endorsed by the Technical Advisory Committee:
NPRR1144: provides a limited exception to the requirement that loads included in an ERCOT-polled settlement metering facility’s netting arrangement only be connected to the grid through the facility’s metering point(s). The exception would allow no more than 500 kW of auxiliary load connected to a station service transformer be connected to a transmission or distribution service provider’s (TSP/DSP) facilities through a separately metered point using an open transition load transfer switch listed for emergency use.
NPRR1147: sets fast frequency response’s ancillary service offer floor 1 cent/MW lower than other responsive reserve services categories to allow fast frequency response’s procurement up to the current limit, without proration with other categories.
NPRR1149: charges qualified scheduling entities (QSEs) an ancillary service failed quantity if their supply responsibility is not met in real time by their portfolio’s resources, based on a comparison of their real-time telemetry.
NPRR1151: eliminates the protocol requirement that the Protocol Revision Subcommittee hold at least one meeting per month.
NPRR1153: adds two existing fees (public information request labor and ERCOT training) to the grid operator’s fee schedule; creates a $500 registration fee for resource entities, TSPs and DSPs, and subordinate QSEs; deletes the system administration fee’s current value and the map sales fee; and restructures existing fees for generator interconnection or modification, full interconnection study applications and wide-area networks.
NPRR1158: eliminates the weatherization-inspection fee’s sunset date and changes its invoicing period from a quarterly to a semiannual basis.
NPRR1159: provides needed references to the Retail Market Guide accounting for Texas standard electronic transaction processing options for municipally owned utility or electric cooperative service areas. The change is aligned with RMGRR171, which adds language establishing the mechanism that opt-in munis or co-ops without an affiliated provider of last resort (POLR) that have not delegated authority to designate POLRs to the PUC would follow to provide their initial POLR allocation methodology; and updates and confirms such allocation methodology.
PGRR102: requires resource entities and interconnecting entities to provide operations dynamic model quality test results that demonstrate appropriate performance for submitted operations dynamic models, and makes non-substantive clarifying changes.
The board also approved:
Vegas’ selection as CEO and the corporate officers’ ratification;
CARMEL, Ind. — MISO’s attempt last week to justify a sweeping new resource accreditation process gave way to heated debate over how to best alleviate the footprint’s reliability challenges.
The RTO has proposed accrediting all resources based on their performance during predefined resource adequacy hours, or tight operating conditions. It will then adjust unit accreditation by a capacity value determined by loss-of-load expectation. The equation’s direct LOLE piece would replace the grid operator’s use of unforced-capacity values that rely on historic forced-outage rates.
The proposed probabilistic, direct loss-of-load hours calculation would have MISO filing edits at FERC to its availability-based accreditation design for thermal resources that was approved last year. It would also eventually assign solar generation near-zero capacity credits by 2031, based on their marginal value.
During a Feb. 28-March 1 Resource Adequacy Subcommittee (RASC) meeting, MISO adviser Davey Lopez said staff still believes a direct loss-of-load approach is an improvement over the status quo’s accreditation. He said MISO’s responsibility is to accredit resources based on their availability at times of greatest risk, even as that risk profile fluctuates.
“We know that there’s a rapid rise in solar coming, and we know that solar is going to shift periods of risk to late-afternoon and early-morning hours,” he said.
Lopez said a direct loss-of-load methodology balances known operational risk with probabilistic future risks.
“It’s a wide range of reliability risk that we’re capturing, and that’s why we’re proposing the direct LOLE approach. Change is coming; risk is shifting,” he said, adding that the design “better informs the future” while providing stability now.
MISO currently has 23 GW of solar resources with executed generator interconnection agreements that have yet to come online.
Lopez said MISO will propose a three-year transition to the accreditation method, which aligns with an influx of in-service dates for solar generation. It intends to seek the design’s approval from FERC by the end of the year.
Some stakeholders said it’s inappropriate for staff to send forward signals with accreditation instead of simply reflecting a resource’s capacity contribution. They said effectively reducing solar generation’s capacity credit to zero isn’t the solution during the clean energy transition.
Entergy’s Wyatt Ellertson asked whether the RTO intends to incent the market to cease investment in the solar fleet by assigning it little to no capacity value. He said if all MISO’s solar is retired, the daytime risk that solar had mitigated will resurface.
“Accreditation needs to capture availability during reliability risk hours. Period. It’s as simple as that,” Zakaria Joundi, director of resource adequacy coordination, said. “We’re not looking into why the risk is shifting. We’re looking into the risk hours and the reliability contribution of all resources.”
January’s tense accreditation discussion gave rise to two stakeholder motions introduced at the RASC: one denouncing the direct loss of load approach and another calling on MISO to share analysis behind its accreditation philosophy.
MISO’s environmental sector said the grid operator has displayed a “relative lack of transparent data supporting the proposal,” with stakeholders not privy to “any of the probabilistic analysis supporting” a change in resource accreditation.
The sector added that stakeholders don’t yet know which risky hours would be singled out under the direct loss-of-load approach.
“The best way to resolve these concerns is through the evaluation and discussion of transparent analytical data supporting MISO’s proposal, rather than discussion guided mostly by narrative,” sector representatives said.
“I think we’re a long way from understanding how this actually works,” Minnesota Power’s Tom Butz said in agreement. “It can’t be just platitudes of how the system risk is changing.”
Sustainable FERC Project senior advocate Natalie McIntire said staff appears “too wedded” to the direct loss-of-load approach.
WEC Energy Group’s Chris Plante also lodged opposition to the design with a stakeholder motion. He said, “any marginal approach to resource accreditation is inconsistent with MISO’s existing resources adequacy construct.”
Plante said MISO’s current prompt-year capacity auction design doesn’t pair well with an accreditation that attempts to send investment signals. He argued that the capacity auction design is residual in nature and was never intended for members to fully procure their capacity needs.
Senior VP Makes Rare RASC Appearance
MISO Senior Vice President Todd Ramey made an unusual visit to the RASC meeting. He reminded stakeholders that MISO Midwest last year came up short against its planning reserve margin requirement in the capacity auction. He said while installed capacity additions are on the rise over the past five years, accredited capacity is on a downward slide.
As a result, Ramey said, the methods for counting available capacity are more important than ever.
“That is the primary reason we’re having discussions about how we approach accreditation,” he said.
A capacity shortage may play out again this year in the seasonal auctions held at the end of March. The RTO reported that Illinois’ Zone 4, Missouri’s Zone 5, Indiana’s and Kentucky’s Zone 6 and Michigan’s Zone 7 appear to have smaller amounts of accredited capacity available this summer versus their planning reserve margin requirements. MISO Midwest has almost 98 GW in accredited capacity to meet more than a 99-GW requirement, staff projected. They said the region will likely require assistance from either load-modifying resources, MISO South’s predicted capacity excess, or external capacity contributions to avoid a deficiency.
While other seasons show zonal deficits in midwestern zones and Texas’ and Louisiana’s Zone 9, no other season exhibits risk for a region-wide capacity shortage.
MISO’s Durgesh Manjure said he couldn’t conclusively say whether the grid operator will avoid a shortfall in the capacity auctions.
“System risk is shifting from being driven by peak load today, to being driven by the unavailability of weather-dependent resources — primarily solar — in the future,” he said.
McIntire cautioned MISO against categorizing resources as either strictly “weather-dependent or controllable,” saying “that doesn’t serve anyone well.”
“Wind and solar are controllable,” she said.
Ramey said MISO agrees that other kinds of resources beyond wind and solar can be weather-dependent.
Customized Energy Solutions’ David Sapper said MISO could adopt the phrase, “dependably capable of ramping up,” to describe the resources it’s looking for.
Butz asked Ramey how MISO intends to address the “common conclusion” that there’s a gap between the intermittent resources in the IC queue and the level of on-demand resources it needs.
“I’m taking advantage of your title in this organization to ask how this plays out,” Butz said.
Ramey said MISO and members must enter a “paradigm change” in reliability planning. He said staff stands ready to work with stakeholders on an appropriate accreditation process and implementing a sloped demand curve to better value capacity in the seasonal capacity auctions.
“MISO doesn’t make retirement or investment decisions. You all do,” Ramey told stakeholders. He said, “all MISO can do” is provide its most accurate insights to inform decision making.
Clean Grid Alliance’s Beth Soholt said MISO hasn’t adequately explored the reliability value of the energy storage and hybrid resources in the IC queue. She said the spike in storage queue applications is a response to the RTO’s call for dependable resources.
“It might only be four-hour batteries, but we haven’t fully the run the ground in what batteries can do for the reliability problem,” Soholt said. “Saying we don’t have the right resources in the queue, that’s not the case.”
Bill Booth, a consultant to the Mississippi Public Service Commission, disagreed that MISO isn’t trying to guide generation investment decisions, noting the RTO is considering marginal, declining capacity credits for solar generation as more come online. Booth said the design effectively means the grid operator is “marching down the path” to making solar facilities energy-only and incapable of serving as capacity resources. In that case, they would be rendered useless in the footprint, Booth argued.
“I think you need to listen to the states here: no effect on cost and no effect on our [planning reserve margin requirement],” Booth said of changes to its resource adequacy construct.
Sapper said he took issue with MISO’s approach to resource adequacy, questioning why staff took liberties with its most recent regional resource assessment by envisioning “an optimistic, or ‘best case’ view” of capacity additions. He questioned why projections differed from MISO’s annual resource adequacy survey that is conducted in partnership with the Organization of MISO States. (See OMS-MISO RA Survey Says Supply Deficits Could Top 10 GW by 2027.)
Sapper asked whether MISO is angling for a regional resource-planning process.
“There’s no hidden agenda here,” Ramey said. “We realize we don’t have authority to make these decisions. The only possible path forward here is to partner with those who are in the driver’s seat on investment and retirement decisions.”
“I’m not buying it,” Sapper responded.
“I think we’re at an inflection point in the history of MISO,” Plante argued.
Plante said the capacity market has evolved from its “humble beginnings” of a voluntary reserve-sharing group among load-serving entities. He said MISO and stakeholders should reestablish what they want from their capacity market.
“Do we want a full-blown capacity market? If we do, I think we need to stop putting lipstick and eyelashes on our current RA construct,” he said. “We need to start over from the ground up.”
Plante said a full compulsory capacity market might mean that MISO conducts forward auctions.
FERC last week rejected SPP’s capacity accreditation methodology for wind and solar resources on procedural grounds and granted clean energy interests’ rehearing request of its prior acceptance.
The commission on Thursday agreed with arguments that it had erred in its August 2022 order accepting SPP’s proposed tariff revisions to accredit wind and solar resources based on historical performance using an effective load-carrying capacity (ELCC) methodology. FERC accepted the proposal subject to the condition that the RTO revise its tariff to include additional details about the methodology (ER22-379).
Clean energy advocates — comprising the American Clean Power Association, Advanced Energy United, the Solar Energy Industries Association, Sustainable FERC Project, Natural Resources Defense Council, Advanced Power Alliance and Sierra Club — appealed the order.
They claimed FERC erred by accepting a Federal Power Act Section 205 filing that omitted tariff details that would significantly affect rates, terms and conditions of service. They contended the order failed to satisfy the rule of reason while also determining that these “manifest flaws” could be remedied by a later compliance filing.
The advocates said SPP’s new capacity accreditation methodology is not “some minor technical modification; rather, it is a new ‘complex’ rate scheme that represents a ‘substantial market design change.’” They charged the commission with relying on generalities rather than specific tariff language, noting that “specific critical elements of SPP’s methodology, including the determination of the base and change cases and the definition of seasonal net peak load, were missing.”
Upon consideration of the arguments, FERC said Section 205 and its regulations require that rates be “clearly and specifically” stated to ensure adequate notice of the proposed rate. It said it accepted SPP’s accreditation methodology without a definition of seasonal net peak load, thus resulting in a lack of adequate notice.
The commission encouraged SPP to expeditiously submit any future filing in the proceeding and found its compliance filing moot.
An SPP spokesperson said the grid operator is reviewing the order and will work with stakeholders to address the next steps.
“As FERC noted, the order has an impact on reliability, so SPP will proceed with reliability as the top consideration,” Meghan Sever said in an email.
The advocates celebrated the decision, arguing that fossil fuel resources, not renewables, have their own issues with intermittency.
“FERC did not address the underlying flaws in SPP’s approach, which clean energy advocates say ignores the risks of SPP’s large fleet of coal and gas plants going offline when needed most,” they said in a joint press release. “Clean energy advocates urge SPP to overhaul its approach to ensure that fair accreditation rules are applied to all resource types.”
“We’ve seen repeatedly over the last few years that fossil fuels fail when electricity is most needed. SPP has been given another bite at the apple to take this into account and evaluate renewables in a considered and fair manner,” Caroline Reiser, an NRDC senior staff attorney, said in a statement. “Fossil fuels are not infallible, and customers will lose out on reliability and affordability so long as grid operators continue to over-reward underperformance.”
Commissioner Allison Clements concurred in a separate statement and posted a Twitter thread explaining her decision, calling the order “an important course correction.”
“As I argue in my concurrence, SPP proposal unduly discriminated against wind and solar resources, over-crediting other types of generation by comparison,” she said. “SPP’s proposal was unjust and unreasonable because it penalizes wind and solar resources for outages while simultaneously declining to adjust the credit of other resources when they experience outages. As SPP goes back to the drawing board, I strongly urge it to develop a fair capacity accreditation methodology that is consistent across all resource types.”
Commissioner James Danly dissented on procedural grounds, arguing that the decision’s reasoning “fails to address the merits at all.”
“Were there procedural defects, we should have cured them in the course of this proceeding’s interminable back-and-forth,” he wrote. “Instead, having repeatedly returned to the filer for more information, we now declare that which we asked for insufficient and grant rehearing, implicitly terminating decades of (admittedly questionable) FERC practice without even acknowledging it.”
Order on GridLiance ATRR
FERC last week also affirmed an administrative law judge’s initial decision approving SPP’s proposed tariff revisions to add an annual transmission revenue requirement (ATRR), a formula rate template and implementation protocols for GridLiance High Plains-owned facilities in Nixa, Mo.
In a Feb. 28 order, the commission said incorporating the Nixa assets into one of the RTO’s transmission pricing zones is consistent with cost-causation principles and otherwise just and reasonable. The GridLiance assets, acquired from the city in 2018, include 10 miles of transmission lines and related facilities interconnected to Southwestern Power Administration in the same zone and to City Utilities of Springfield in a neighboring zone (ER18-99).
At issue was SPP’s decision in 2017 to place the Nixa facilities into Zone 10 because they serve load there. Several cities in the zone protested, as did other parties, leading the commission to set the tariff revisions for hearing and settlement judge procedures. FERC rejected SPP’s initial settlement offer in 2021 and remanded the proceeding to resume hearing procedures. (See FERC Remands GridLiance ATRR Settlement.)
The ALJ in December 2021 found that the Nixa facilities will result in a $1.8 million cost shift to its Zone 10 customers; that they will accrue “substantial, specific but unquantifiable” benefits; and that those benefits justify the cost shift. Intervening parties filed countering briefs on exceptions in January 2022.
The commission agreed that the ALJ “properly balanced competing testimony” in reaching his cost-shift finding and said the record supports the finding that the Nixa assets provide integration, reliability and power-transfer benefits to Zone 10’s customers and that those benefits justify their costs.
FERC also affirmed the judge’s dismissal of alternative rate proposals made by the intervenors, finding that SPP had met its burden under Section 205 to show that its proposal was just and reasonable.
A three-judge panel of the D.C. Circuit Court of Appeals on Friday rejected a challenge from the Midwest Ozone Group to EPA’s Cross-State Air Pollution Rule for the National Ambient Air Quality Standards (NAAQS).
The Midwest Ozone Group (MOG) is made up of numerous large industrial firms from the region, including utilities such as Ameren, American Electric Power, Associated Electric Cooperative Inc., Buckeye Power, Duke Energy and FirstEnergy.
The rule that the group challenged was updated by EPA after the court remanded it to the agency in a 2019 decision. In the revised rule, the agency addressed its failure to balance emissions obligations in accordance with the 2008 NAAQS and its date of attainment.
MOG argued that the revised rule is arbitrary and capricious and that the agency failed to conduct a legally and technically appropriate assessment of it.
The Clean Air Act authorizes EPA to adopt NAAQS to regulate air pollutants including ozone, which can be blown from facilities in one state into another. The law includes the “good neighbor provision” that requires every upwind state to prevent its pollutant emissions from contributing significantly to nonattainment in downwind states.
For 2021, EPA set specified, enforceable measures in federal implementation plans for Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia and West Virginia.
MOG argued that EPA took mathematical and analytical shortcuts in its analysis of upwind states’ ozone contributions under the good-neighbor rule. Eleven of the 12 states identified were considered significant pollution contributors based on that flawed data, it said. EPA also failed to consider programs in downwind states to control pollution and exceptional events that could impact air quality monitors, MOG said.
EPA said it used the method to figure out how much improvement should have been expected by 2021, but even if it used MOG’s preferred method, the same states would have obligations to clean up their ozone pollution.
The court said its review of the case was simple: As long as the action was not against the law, all EPA had to do was act reasonably and reasonably explain its actions. The court had to give deference to the agency’s interpretation of “highly complex and technical matters.”
The kind of statistical analysis EPA used has been described as “perhaps the prime example of an area of technical wilderness into which judicial expeditions are best limited to ascertaining the lay of the land,” the court said.
The D.C. Circuit has never required EPA to use a particular method to generate its data, or to adhere to past practice; it just has to show a reasonable connection between the facts on the record and its decision, the judges said.
“MOG fails to demonstrate that EPA’s promulgation of the revised rule was arbitrary, capricious or promulgated in violation of its statutory authority under the good-neighbor provision,” the court said. “Accordingly, we deny MOG’s petition.”
CARMEL, Ind. — MISO says it is leaning towards a simple and existing method to handle the market participation of a growing number of combined battery storage and renewable energy resources.
The grid operator last week released a draft market participation model under which hybrid resources’ components will be required to register and participate separately by resource type.
MISO currently maintains two definitions for resources that share a point of interconnection: “co-located” or “hybrid.” While co-located resources participate in the market separately, hybrid resources would participate in the market as a single resource. (See MISO Prepares Hybrid Participation Model for Unknown Numbers.)
Bill Peters, a market design adviser for the RTO, told a Market Subcommittee meeting Thursday that there are advantages to requiring components of a hybrid resource to operate individually. He said renewables can still confidently use MISO’s forecasts for intermittent resources, and storage components of hybrid resources are free to clear as operating reserves. He said a single-offer hybrid participation limits MISO’s visibility into the capabilities of the multiple resource types that comprise the hybrid resource.
“As we learned from Ghostbusters, this will help prevent us from crossing the streams, which we know is bad,” Peters joked.
He said MISO’s proposal will prevent storage assets from being “shackled” to renewable resources and storage will be free to operate independently and “capture otherwise curtailed or clipped renewable generation.” Peters said resources sharing physical infrastructure already can be dispatched and settled separately.
The RTO has about 1 GW of hybrid resources projects that have executed generator interconnection agreements, though none are coming online over the next year.
MISO’s hybrid IC queue numbers may underrepresent the number of hybrids that eventually will materialize in the footprint. Staff has said interconnection customers sometimes request separate applications for the storage and generation components; others request surplus IC capability for storage that is added later. Clean energy advocates have been pressing MISO for several years to make its markets friendlier to hybrid resources.
Staff said that it is challenging to build a singular hybrid-participation model because any number of resource combinations are possible.
MISO is unable to provide forecasts for partial intermittent resources, Peters said, and wouldn’t know when hybrid resources are operating under a generation designation or a dispatchable intermittent resource designation.
Peters said MISO staff went over a “legal reading of the tariff” and found few clear answers as to how hybrid resources should participate in the markets. “It becomes clear that when a lot of answers are ‘maybe,’ that’s maybe not the best,” he said.
Peters said if MISO’s idea works well, it may “obviate” the need to work out a comprehensive participation model for hybrid resources.
“This may be the best way to operate these resources,” he said.
Peters said MISO might want to update software so it can create a “family relationship” to make sure resources are maintaining the megawatt limit of a shared interconnection point. Market systems currently lack the capability to manage shared interconnection limits.
Peters asked for stakeholders’ input on the “good, the bad and the ugly” of the proposal. They have until March 16 to weigh in.
