Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings this Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will cover the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
The committee will be asked to endorse as part of its consent agenda:
C. proposed revisions to Manual 3: Transmission Operations drafted through the document’s periodic review. (See “First Read on Periodic Review Manual Revisions,” PJM OC Briefs: April 4, 2024.)
D. proposed revisions to Manual 36: System Restoration, including administrative changes identified through periodic review.
Endorsements (9:10-9:50)
1. Capacity Obligations for Forecasted Large Load Adjustments (9:10-9:35)
PJM’s Pete Langbein will present a proposal to revise how capacity obligations stemming from forecast large load additions are assigned. Lynn Horning, of American Municipal Power, will present an alternative proposal. (See “Changes to Capacity Assignments for Large Load Additions Contemplated,” PJM MRC Briefs: April 25, 2024.)
The committee will be asked to endorse revisions to the tariff, Reliability Assurance Agreement and Operating Agreement.
Bruce Campbell, principal of Campbell Energy Advisors, representing demand response providers, will present a quick-fix proposal to extend the winter availability of DR resources. (See “Demand Response Providers Seek Expanded Availability,” PJM MRC/MC Briefs: Feb. 22, 2024.)
The committee will be asked to approve the proposed issue charge and endorse the proposed solution to key work activity 2 using the quick-fix process, which allows an issue charge and proposed solution to be voted on concurrently.
Members Committee
Consent Agenda (11:35-11:40)
The committee will be asked to endorse as part of its consent agenda:
B. proposed governing document revisions focused on correcting grammatical, formatting and reference errors in language around the interconnection process. The changes were drafted by the Governing Documents Enhancements and Clarifications Subcommittee.
C. proposed revisions to the OA, tariff and Manual 15: Cost Development Guidelines to add three market parameters for synchronous condensers: condense start-up costs, condense-to-generate costs and condense energy use. (See “Other MRC Business,” PJM MRC Briefs: April 25, 2024.)
SACRAMENTO, Calif. — Developers of floating offshore wind are calling on the California Public Utilities Commission to increase procurement targets to 10 GW by 2035, up from the initial goal of 2 GW to 5 GW by 2030, accounting for the total combined capacity that can be delivered by the state’s five new leaseholders.
“We and the other leaseholders think that the state should be targeting 10 GW by 2035 as a nice, clear, strong signal of where we’re heading that keeps us on track to meet our climate targets and our offshore wind goals,” Rick Umoff, director of government affairs at Vineyard Offshore, said at the Pacific Offshore Wind Summit, held May 13 to 15 at the SAFE Credit Union Convention Center.
Vineyard Offshore is one of the five companies that obtained leases in June 2023 to develop floating offshore wind off the California coast, and it plans to deploy up to 2 GW of power off Humboldt County. The other leases are held by RWE Offshore Holdings, Invenergy, Equinor and Golden State Wind.
Along with 2 GW to 5 GW by 2030, the California Energy Commission set a goal of deploying 25 GW by 2045. But leaseholders are asking the CPUC to set an interim target of 10 GW by 2035 to stimulate supply chain development and economies of scale needed for investment. The commission is conducting a needs assessment and will have an initial determination by Sept. 1, said an ACP California spokesperson.
“We think it’s incredibly important that the needs assessment recognizes the need for 10 GW of offshore wind development and procurement,” Martin Goff, head of renewables at Equinor, said in a summit panel. “We need to be bold at that type of scale to really get the investment needed in this industry.”
Equinor is responsible for the Atlas Wind project, which will deploy 2 GW of power 60 miles off the coast of Morro Bay. Goff said volume, predictability and certainty are essential to reaching the 10-GW target, and central procurement is one way to get there. The new target would also help signal investment in the transmission needed to accommodate the facilities.
“It’s critical that we have those volumes, the 10 GW, in this needs assessment so that you can trigger that investment in the transmission,” Goff said. “If it’s done on a strategic level, then it takes that transmission away from the generation costs, puts it into a fixed charge … and gets spread out across the state in terms of cost and not put on the developers and the ultimate cost of energy.”
Last year, the state passed AB 1373, enabling the Department of Water Resources to conduct central procurement of eligible long-lead-time resources, including offshore wind, until January 2035. (See California Governor Seeks Central Procurement Authority.) The bill gives developers a positive market signal and the confidence to invest in the substantial and expensive infrastructure needed to build floating offshore wind, Goff said.
“The central procurement entity, it’s a tool in the toolbox,” said Leuwam Tesfai, deputy executive director for energy and climate policy at the CPUC.
Central procurement will ensure that more expensive energy like offshore wind is purchased, said V. John White, executive director at the Center for Energy Efficiency and Renewable Technology.
“I think the challenge is [load-serving entities] aren’t buying these resources on their own because they’re more expensive and because they’re used to buying the cheapest resource possible,” White said. “What the central procurement offers is the opportunity for the PUC to take that decision on behalf of all the LSEs and procure resources competitively knowing that the LSEs are willing to be the ones to take it.”
Cost Concerns
Developers and utilities expressed concern over the costs associated with the buildout of offshore wind and how central procurement could play a role.
“Knowing that these resources are more expensive, how do we know that we’re getting the best price? I think there may need to be some considerations, or what I might call open book bidding, where we would disclose all the costs, the profits … so that you know there’s no hidden markup,” White said.
Cost overruns and ratepayer protection were key among utility concerns when considering central procurement. Adam Smith, director of regulatory relations at Southern California Edison, questioned whether ratepayers would “eat” the substantial costs associated with offshore wind development.
“What we would like to see is that our ratepayers are guaranteed the same guardrails and protections that they would see if the LSEs were doing the procuring,” Smith said. “If the state decides to go there, we just want to make sure our customers are protected.”
The Texas Public Utility Commission’s staff, having been waved forward by commissioners, are preparing for public comment a revised version of ERCOT’s proposed reliability standard.
During its May 16 open meeting, the commission agreed with staff suggestions that two of ERCOT’s three metrics be tweaked to strengthen their effectiveness.
“Coming up with reliability standard is really mission critical to what we’re doing on the wholesale market design side,” PUC Chair Thomas Gleeson said.
The Texas grid operator has proposed a “multi-metric” framework that establishes thresholds for three metrics: frequency, duration and magnitude of loss-of-load events (54584). PUC staff filed comments May 9 recommending changes to the duration and magnitude values’ calculations. (See related story, ERCOT Proposes ‘Multi-metric’ Approach for Reliability Standard.)
Commissioner Lori Cobos suggested ERCOT include the normalized expected unserved energy (EUE) to provide an idea of the load that won’t be served. ERCOT has said EUE is an average measure, like the loss-of-load expectation, and does not distinguish the characteristics of extreme events. The grid operator did allow that EUE is a useful measure for the expected cost of not meeting customer firm-load requirements and the expected incremental cost of modifying the reliability standard’s elements.
“I think it’s a helpful perspective to have in addition to the fundamental reliability standard that will be based on the one-in-10 with the additional criteria of duration, frequency and magnitude,” Cobos said.
Commission staff proposed adding a 0.25% exceedance probability for the 19-GW magnitude metric because it is tied directly to the grid’s operational capability. Cobos said she wants stakeholders, with their comments, to further explore the exceedance number.
“Based on just my initial thoughts, it seems to be very conservative,” she said, saying the 0.25% exceedance translates to one loss-of-load event every 400 years. Cobos suggested the rule could start at 0.25% but wondered aloud whether stakeholders might want to double it to 0.5%, the equivalent of one loss-of-load event every 200 years.
“It’s typically easier to start with more stringent standards, say one in 400, and then pull back to something less stringent,” Gleeson said.
Following stakeholder feedback, a final reliability standard could be published as soon as June 13.
The Texas Reliability Entity says its latest regional assessment indicates weatherization activities since the disastrous February 2021 winter storm have paid off.
David Penney, Texas RE’s director of reliability services, told his Board of Directors on May 15 that state legislation passed since Winter Storm Uri and on-site inspections have both improved resource performance and cold-weather resilience, as measured by outage rates and balancing contingency rates.
“We definitely see a lot of improvement with resource weatherization,” Penney said, citing the lack of outages during two more recent winter storms.
The assessment — not likely to be released until June, the entity said — also found:
The solar down-ramp magnitude continues to increase, creating potential energy adequacy shortfalls.
Misoperation rates are improving, but human performance continues to be a primary factor in both misoperations and system events.
Conventional generation fleet outage rates have improved, but long-term outage rates continue to trend higher.
Penney said the latter problem is found mostly in coal- and lignite-fired resources.
“A lot of it has to do with the way those units are operated in light [of] how the grid is being operated because of the changing resource mix,” he said. “Those units are being cycled a whole lot more.”
Texas RE’s annual Assessment of Reliability Performance and Regional Risk Assessment is intended to inform market participants, stakeholders and policymakers of the data it gathers and the risks it sees in the interconnection. The report looks at four main areas: grid transformation, resilience to extreme events, cybersecurity, and cyber and physical security and critical infrastructure.
The report was once called the “Assessment of Reliability Performance, much to the chagrin of Texas RE CEO Jim Albright.
“‘Assessment of Reliability Performance’ was easy. ‘ARP.’ We had a nice acronym,” he said in jest, noting the report’s new acronym is ARPRRA. “Now, they’ve added ‘Regional Risk Assessment.’ That acronym gets really long, and it sounds like we’re pirates.”
Budget, Business Plan OK’d
The board approved its 2025 budget and business plan and an audit of its 2023 financial statements that reported no findings.
Texas RE proposed a 5.9% increase to the budget, from $19.11 million to $20.24 million. It said the key drivers were an 8.1% increase in payroll expense, a projected 10% increase over current actual rates for medical insurance premiums and additional compliance oversight obligations requiring more staff travel.
The budget was approved by the Members Representative Committee in April and posted for members’ comments May 7. It will now be sent to NERC.
MISO on May 14 announced that Nirav Shah, Republic Airways’ former chief information officer and vice president of information technology, will serve as its new chief digital and information officer.
Shah had worked at Republic since 2017; his roles included chief digital officer and chief information security officer. Shah also led IT applications development at financial services company OneAmerica and has held IT roles at other institutions.
At MISO, Shah will manage the digital technology division’s innovation, operations and infrastructure areas. He will be responsible for the technologies that will support market innovations and MISO’s “reliability imperative,” the phrase it uses to describe it and members’ joint responsibility to ensure the clean energy transition occurs in a reliable and organized manner.
“We are pleased to welcome Nirav aboard, and we are confident he’ll play a key role in driving us forward as we continue to navigate the ever evolving and complex energy landscape,” Todd Ramey, senior vice president of markets and digital strategy at MISO, said in a press release. “He brings a well rounded background with significant expertise, and his strategic mindset will accelerate innovation for MISO and our members.”
“MISO’s responsibility to ensure reliable power for 45 million people makes this role particularly exciting,” Shah said. “I’m eager to join such a highly skilled team during a period of dynamic change where technology is paramount to MISO achieving its strategic priorities.”
Shah holds an MBA from Missouri State University, a master’s in computer science from the University of Missouri-Kansas City and a bachelor’s in computer engineering from the University of Mumbai. He also recently completed the Chief Digital Officer program at Northwestern University’s Kellogg School of Management.
The chief digital and information officer position is a newly created role at MISO, which said it revamped its IT leadership structure following former CISO Keri Glitch’s departure last year. (See MISO Names New Chief Information Security Officer.)
MISO said that while new CISO Eric Miller is focusing on security and cybersecurity, Shah will concentrate on technology infrastructure, operations, digital innovation and data analytics. The RTO said having duties split under two roles will improve its expanding digital technology department and will prepare it for the growth and complexity that it is expecting.
“Digital technology enables all the critical work at MISO, so it has great breadth. Both functions are critical to maintain grid reliability and to meet the demand of an ever evolving technology and security landscape,” MISO said in a statement to RTO Insider.
The PJM Board of Managers has re-elected Mark Takahashi to his fourth one-year term as its chair and named David Mills as chair-elect.
The chair-elect position signifies that Mills is slated to take over in 2025 if his election is reaffirmed by a second vote next year.
“Both Mark Takahashi and David Mills have the wealth of experience needed to help PJM manage the challenges of our evolving energy landscape,” CEO Manu Asthana said in a May 16 announcement. “I look forward to our ongoing work together toward maintaining a reliable grid amid our current energy transition.”
Takahashi joined the board in 2016 and has served as chair since 2021, having previously chaired the Competitive Markets Committee. Until 2018 he was CFO for the Ascendant Group, the parent company of Bermuda Electric Light Co. He also served as CFO of CLP Holdings, a vertically integrated utility in Hong Kong, between 2008 and 2014.
Mills was elected to the board in 2021 and serves as chair of the Competitive Markets Committee, in addition to being a member of the Risk & Audit and Human Resources committees, according to the announcement. He was re-elected to his second term on the board during the May 6 Members Committee meeting. (See “Stakeholders Re-elect 3 PJM Board Members Over Consumer Dissent,” PJM Members Committee Briefs: May 6, 2024.)
The announcement also included board committee assignments, with Terry Blackwell selected as chair of the Reliability & Security Committee and Vickie VanZandt named chair of the Human Resources Committee.
ALBANY, N.Y. — The promise of doing well for both the environment and the economy (and the obstacles to that goal) were highlighted as the 2024 edition of New York’s energy storage industry conference opened.
Manufacturers, developers, regulators and researchers — each looking for ways to overcome the challenges and be part of the solution — offered updates on their progress at Capture the Energy 2024.
William Acker, executive director of the New York Battery and Energy Storage Technology Consortium (NY-BEST), highlighted these parallel goals as he welcomed attendees to the conference on May 15.
“We will be focusing a lot of discussion in this conference around how we’re going to meet New York state’s climate and energy goals that are among the most aggressive in the country and really are an opportunity to redefine things and to really get a much better future for all of us,” he said.
In most decarbonization scenarios, storage is more than an opportunity; it is an imperative.
The transition from baseload fossil generation to intermittent zero-emission renewables is predicated on there being a way to store energy in periods of excess generation for use in periods of insufficient generation.
Building enough of that storage to accomplish that depends on technological, financial, regulatory and societal factors that are mostly still evolving.
The New York State Energy Research and Development Authority is working on multiple fronts to firm up some of those factors and streamline buildout of energy storage in the state.
State Efforts
In her keynote address, NYSERDA President Doreen Harris announced the latest step in this effort: the launch of the much awaited Block 5 of the retail energy storage incentive. The $58.5 million funding package is expected to incentivize construction of 135 to 150 MW of energy storage in New York City.
“Fundamentally, when we think about this funding, it’s intended to deploy what are the most mature projects across our state in the place that it is probably needed the most, to reduce peak flows, to mitigate the need for additional distribution grid upgrades and [to] displace some of the dirtiest fossil fuel peaker plants in the region,” Harris said.
New York’s official goal is 3 GW of storage installed by 2030, but Gov. Kathy Hochul has directed that it be doubled to 6 GW. A proposed road map that would formalize that target and lay out a path to reach it has been in an extended period of review by the Public Service Commission.
“I have to tell you, we are eagerly, like you, awaiting a decision on that road map,” Harris said. “But fundamentally, that is our next step that will allow us to partner with the industry to really scale up that next wave of projects and to deploy at a much greater scale toward the 6 GW goal.”
Beyond this, NYSERDA is helping fund research and development and supporting market reforms.
Word of the Day
Adam Cohen, chief technology officer and co-founder of NineDot Energy, focused his keynote on the need for market reforms to make storage work financially.
It now operates under a haphazard system that he described as “make it fit where it can, how it can.” The term for this is “kludge,” he said, and he proceeded to describe a situation just as clunky as that word sounds.
Utility rates for the past century have been based on the axiom that generation must be designed to meet maximum anticipated need because energy cannot be stored, he said. As a result, the characteristics and benefits of energy storage are fundamentally mismatched to existing tariffs.
“It should not be a kludge anymore when we have gigawatts of these things on the grid [and] terawatt-hours of energy going to be consumed and spit back out in bursts when it’s most needed,” Cohen said.
“You should charge the battery in an optimal way, and you should export the battery and apply grid services in an optimal way, and not have to build this duct-taped version of a tariff.”
NineDot and other retail developers in New York have collaborated to produce a series of bidirectional service classification principles they would like to see: The tariff should be market-based and transparent; be universal, so it provides certainty; optimize imports and exports; provide localized adders; be adaptable to the changing grid; share savings with low-income customers; and use rates that computers can read.
Headwinds, Tailwinds
Vanessa Witte, senior research analyst on Wood Mackenzie’s storage team, said the data and analytics provider has a bullish outlook on standalone storage, primarily because of the federal investment tax credit, but also all the wind and solar generation being planned: Their volatility creates a need for storage.
However, WoodMac also sees short-term hurdles in the renewable energy sector, such as permitting and interconnection delays, local opposition, interest rates and inflation.
“Really, we just need to accept the reality that total capex is high; interest rates are not expected to go down this year,” Witte said. “Despite some drops in supply cost and also lithium raw material costs, total capex does remain high.”
The data show multiple problems in New York, and as it stands now, she projects the state will not reach 6 GW of storage by 2030.
Fossil generation retirements are on track to far outstrip storage additions, Witte added: “Currently, what I’m showing right here is actually 2.8 GW of utility-scale [storage] by 2028. And then 4.5 GW of retirements.”
But the equation changes after 2030. Construction of wind and solar has fallen well behind schedule in New York — far enough perhaps that its 70%-by-2030 target is now out of reach — but extensive buildout still is expected. And storage must follow.
“Storage is very sensitive to state mandates, especially when paired with a financial incentive, other policies, other regulation [and] market signals; this is due to it being still very new,” Witte said. “So, New York also has a large amount of renewables coming online, not in the near future necessarily, more into the latter half of this decade, post of 2030. But it will create some clear market mechanisms by creating volatility on the grid.”
There’s one other factor at play in New York: It’s New York.
“New York is known to be one of the most difficult regions to build in. A number of developers actually don’t want to get involved in New York. There’s just too many permitting issues, the NIMBYism, the interconnection timeline, but also the interconnection costs,” Witte said. “The question is, what is the return for all of the difficulty and additional time to develop? Some areas do have higher volatility and better returns, but many areas don’t.”
She added: “Sometimes working with utilities has also proven to be really challenging. Some are not accepting the PPA cost. Others maybe want to move into ownership and don’t want to contract for PPA any more at all.”
Evolving Technology
Energy storage technology and applications are still evolving, especially the long-duration energy storage that will be critical if state policymakers do succeed in weaning New York off fossil fuels.
One after another, speakers discussed the need to advance not only the development of technology, but also high-quality execution of it.
Around the time of last year’s conference, New York City was reeling from a wave of hundreds of fires sparked by poorly made or incorrectly used lithium batteries for E-bikes and E-scooters. Soon after the 2023 conference, three unrelated fires hit New York grid-scale battery energy storage facilities in remote corners of the state, each one more serious and more widely publicized.
Harris said NYSERDA is part of the multiagency task force assembled to design safety standards and prevent further erosion of public trust in battery storage. Its work continues. (See NY Fire Code Updates Recommended for BESS Facilities.)
M. Stanley Whittingham, who was awarded the 2019 Nobel Prize in Chemistry for his work on lithium-ion batteries, raised the same issue.
“These fires we had last year … it’s sloppy manufacturing, cheap manufacturing — things go wrong,” he said. “Same as what we have in New York City with E-bikes. These are cheap batteries, all from a certain country.”
Whittingham, who is NY-BEST’s vice chair of research and a distinguished professor at Binghamton University, reminded the audience that all major commercial innovations in batteries came from the U.S. or U.K.
The U.S. can take the initiative back, he said.
“We don’t want to chase the Asians. That’s not going to work. We want to leapfrog them. So, we’re going to come up with more sustainable technology.”
The economics must get better too, Whittingham said.
“It takes 40 to 80 kWh to make a 1-kWh battery, so we have to change that.”
Brian Gemmell, COO of National Grid’s New York electric utility, said the state has only about 400 MW of utility-scale storage built toward its 6,000-MW goal at a critical time in the energy transition. He explained the need to sharply accelerate the buildout and why speed cannot be the overriding concern.
“We recognize that product development has slowed in the past year. The state has taken a crucial review of fire safety standards after the thermal runaways in 2023,” Gemmell said in his keynote address.
“So, we’re particularly focused on ensuring this standard is successfully implemented with the engagement of communities including fire first responders. I want to emphasize that safety and reliability must serve as the foundation of energy storage deployment going forward.”
Erik Spoerke, energy storage materials lead at Sandia National Laboratories, drew back to the longer view to give a better sense of where all these incremental setbacks and advances are leading.
He’s leaving Sandia after 20 years to take an advisory role in the U.S. Department of Energy’s Office of Electricity.
“I’m trying to help them understand how we can make grid-scale long-duration storage viable,” he said in his keynote speech.
He gets asked why he’s making such a large transition, taking a policy position after decades of hands-on work in the lab.
“Really, an important part of the motivation here is to recognize that in the next 10 years, we’re expecting there to be more change to the grid infrastructure than in the last century. That’s a pretty good jump. … And there’s been a few times in history we can think about where there’s been that kind of colossal technical endeavor.”
MISO on May 15 said it plans to move ahead after all with Entergy Louisiana’s original version of a $260 million reliability project proposed for the southeast part of the state.
The RTO announced about eight months ago it would delay recommending Entergy’s project to study alternatives. But this week it revealed it was unable to choose a suitable substitution, as the project’s higher-voltage alternative configurations were not cost effective.
The project initially was introduced for MISO’s 2023 Transmission Expansion Plan (MTEP 23) as the third phase of Entergy Louisiana’s three-part, nearly $2 billion Amite South reliability project to satisfy the utility’s local reliability criteria. The RTO ultimately advanced a substitution for the first phase of the project last year. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)
This time, however, MISO said Entergy’s original proposal to construct a 40-mile, 230-kV line between its Adams Creek and Robert substations and upgrade the substations is more appropriate for the area than the 500-kV possibilities it analyzed. Entergy said in addition to the line solving potential overloads, the project would help it meet load growth in the Amite South load pocket and address upcoming generation retirements, which could be exacerbated by EPA’s new power plant emissions rules. Entergy also reasoned the line would provide an “additional hardened path” into Amite South, which can be useful during restorations following hurricanes or other extreme events.
MISO studied two alternatives to Entergy’s proposal, including a $1.1 billion option involving construction of two 500-kV substations and more than 50 miles of 500-kV line. However, the RTO said construction costs would be too high and the project itself would be impractical to build.
A second alternative — resulting in a new 500/230-kV station, an 11-mile 500-kV line to operate at 230 kV and a 26-mile 230-kV line — was found to cost about $100 million more than Entergy’s original proposal without solving any other reliability issues, MISO said.
MISO plans to recommend Entergy’s project proceed as a late addition to MTEP 23. It will run its recommendation past the Planning Advisory Committee before seeking approval from the Board of Directors’ System Planning Committee and, later this year, from the board itself.
ISO-NE has re-elected current Directors Caren Anders, Steve Corneli and Michael Curran, the RTO announced May 16.
The re-elected members have “significant expertise in clean energy, consumer advocacy, transmission, wholesale electricity and financial markets, and deployment of complex IT systems,” ISO-NE wrote in a press release.
ISO-NE relies on a slate voting system to elect its board, which consists of 10 members serving three-year terms. Some NEPOOL stakeholders previously have taken issue with the system, arguing participants should be able to vote on individual candidates.
The slate was nominated by a committee featuring current board members, NEPOOL sector chairs and Phil Bartlett, chair of the Maine Public Utilities Commission. The slate was approved by the NEPOOL Participants Committee in early May.
“We’re thrilled to have Caren, Steve and Michael remaining with us,” ISO-NE CEO Gordon van Welie said. “Their extensive and diverse experience and expertise remain critical as the region continues its transition to a clean, reliable energy future.”
Anders has a background in transmission and has worked for Quanta Technology, Duke Energy and Exelon. Corneli works as an independent clean energy adviser and previously worked on climate and market policy issues for NRG Energy. Curran is the retired chair of the Boston Stock Exchange and has expertise in investment and financial services.
The RTO’s most recent IRS Form 990 shows that Anders, Corneli and Curran made between $138,000 and $164,000 for seven to nine hours of work per week in 2022.
Board members must not be affiliated with any company that participates in the region’s wholesale electricity markets.
AMES, Iowa — There’s no going back on waning capacity in MISO, panelists agreed this week at a gathering of state regulators, though predictions of escalating load growth have some skeptical.
New OMS Executive Director Tricia DeBleeckere opened the Organization of MISO States’ third annual Resource Adequacy Summit May 14-15 at Iowa State University, predicting that MISO will be managing a shallower supply for years to come.
“We’re going to have to live in this new world order of tight margins,” DeBleeckere said.
MISO President Clair Moeller agreed some capacity insufficiency within MISO is here to stay. He said it was unsurprising to MISO that one of the resource adequacy zones returned a shortage for the upcoming planning year. He said most zones were “right on the edge” of adequacy.
MISO’s capacity auction April 25 returned insufficient capacity for the upcoming fall and spring 2025 in Missouri’s Zone 5, where capacity prices hit a $719.81/MW-day limit, on par with building new generation. Otherwise, all local resource zones cleared at $30/MW-day in the summer, $15/MW-day in the fall, $0.75/MW-day in the winter and $34.10/MW-day in the spring. Zone 5 contains local balancing authorities Ameren Missouri and the city of Columbia, Mo.’s Water and Light Department. (See Missouri Zone Comes up Short in MISO’s 2nd Seasonal Capacity Auction, Prices Surpass $700/MW-day.)
Moeller defended his standing as a “storm crow” on resource adequacy.
“The reason it’s not bad is because I’ve been telling you all to worry about it,” he joked with regulators.
Former OMS Executive Director and Wisconsin Public Service Commissioner Marcus Hawkins said despite thinning reserves, MISO members are fortunate to operate under an established resource adequacy construct. Hawkins said parts of the country just now are trying to launch the “basic resource adequacy construct that’s been operating in MISO land since 2011.”
DeBleeckere said MISO’s recent and proposed modifications are “unheard of and groundbreaking” and probably the largest transformation of its resource adequacy construct ever.
Hawkins said that there’s a lot of buzz around booming load growth now, but he qualified that MISO at one time predicted as much as 12 GW of new demand that hasn’t materialized. He also said the footprint has lived through the “Groundhog Day” of MISO predicting major capacity shortfalls “three to five years from now for every year since 2015.”
Hawkins said despite dire estimates, MISO, utilities and states survived without catastrophe. He said there’s value in taking stock of predictions that didn’t pan out.
“We have to have these more nuanced conversations and be realistic about what has transpired after those predictions,” he said, prescribing “new, hard conversations on what is an appropriate level of risk to plan for.”
Hawkins said MISO’s and states’ plans will be reliant on one another’s information more than ever.
“Resource adequacy on paper is much different than serving load in operations. You can’t just feel good that you’ve hit your resource adequacy targets on paper,” Hawkins said.
Despite Hawkins’ plea for moderating expectations around load growth and capacity deficits, he was followed by a panel titled, “Load Growth Galore.”
Grid Strategies’ Rob Gramlich predicted the end of the country’s 25 years of flat load growth. He said Grid Strategies’ recent report shows Indiana and Michigan are especially ripe for new industrial load in MISO.
“Like many, we’ve gotten interested in load growth in the last six to nine months. It seems to be the biggest thing changing everything we thought we needed to do,” Gramlich said.
Gramlich said the nation is at an “inflection point” of new applications for data center servers occurring alongside the Biden administration’s push for stronger domestic manufacturing and the open question of hydrogen’s potential importance.
Gramlich said expanding load is evidenced in MISO by utilities’ requests for expedited project reviews, which have more than quadrupled since 2020. MISO’s expedited transmission project reviews are a bellwether of load growth, as they’re most often used to accommodate new load connections.
Gramlich said MISO is “already doing pretty well on forward-looking” transmission planning to connect new generation to serve load growth. He said the RTO likely is ahead of the curve on FERC’s newly issued Order 1920 concerning transmission planning. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) However, he suggested MISO dedicate an internal group, or tap an independent entity or the Organization of MISO States, to contribute to load forecasting.
“We really as an industry have lost our muscle memory on load forecasting,” Gramlich said.
Google’s Betsy Beck said MISO should turn to “nontraditional data sources” and initiate discussions with large industrial customers in addition to compiling forecasts from their load-serving entities to more comprehensively view future demand.
Great River Energy Director of Resource Planning Zac Ruzycki urged utilities to have “open and honest discussions” with companies about the size, location and longevity of their new loads.
He said utilities and MISO may have to get comfortable with forecasting being “a lot more work” and more probabilistic going forward, given the confluence of sweeping changes.
Minnesota Public Utilities Commissioner Joe Sullivan said when he thinks about a hypothetical, 1-GW data center coming online in Minnesota, he can’t help but think that the new, daily load would be larger than the electricity ultimately produced from the state’s largest mining operation or refinery.
Ruzycki said it’s more likely than not that Great River Energy will be serving substantially more load within a decade.
“We feel fairly confident that’s going to be the case,” he said, adding that utilities are going to have to “do more with less” to serve larger loads with fewer baseload resources. Ruzycki said that’s why Great River is partnering with Form Energy to pilot a 1.5-MW long-duration iron-air battery capable of 100 hours of continuous dispatch.
Ruzycki said Great River Energy is building the battery — due online at its Cambridge peaking plant sometime next year — not to make money, but to see how the technology behaves.
Ruzycki said MISO’s mostly solar and wind interconnection queue means there are days ahead with curtailments due to “extreme production and low demand.” He said a long-duration battery can soak up excess generation from renewable generation over multiple days.
“Including new technology is challenging but necessary,” Ruzycki said.
MISO President Advocates for Restraint in Load Forecasting, Unit Retirements
But MISO President Clair Moeller cautioned that load growth might not ascend to the heights some are expecting.
“I’ve noticed when people are selling you something, they can be hyperbolic. So, how much of this is hyperbole and how much of it really is load growth?” he asked rhetorically. He also told attendees not to confuse “the interested public with the public interest.”
Lumpy load growth matters depending on location, Moeller said. He joked that he doesn’t care if a new data center eyes Ohio as its home base, but that same data center sited in Indiana might give him anxiety.
Moeller said utilities are in the unenviable position of balancing customers representing new load, customer affordability, shareholder interests and governor’s offices desiring economic development before another state can snap it up.
He said utilities, regulators and RTO planners should engage with economic development organizations and lawmakers “so everybody’s goals get on the table at the same time.” He said “a lack of coordination is risky” for the grid.
Moeller said the supply chain is the “governor” on how fast new load can be served and said the COVID-19 pandemic showed the “brittleness” of the supply chain.
“It’s two years to a data center and four years to a transformer,” Moeller said. “We’ve got to think this through in order to get a safe transition.”
Moeller said past transitions in the energy industry since 1900 have been “layered,” where new technologies were spread on top of operating older technologies.
“We didn’t turn anything off until we were well and done with it. Now, this transition is: ‘Turn stuff off and then turn stuff on,’” Moeller said.
He said MISO isn’t opposed to inverter-based resources but wants to make sure the technologies to support them for 24/7 output are tested. MISO sometimes is criticized as “pro-gas” by environmental groups, Moeller said, but added that he sees MISO as “pro-reliability.”
“Reducing the carbon footprint doesn’t have to mean turning off all the carbon-producing resources. It could mean make sure you use it only when you need it,” he said.
Moeller said in the past two years, the electrification of the economy is accelerating, data center load is swelling and manufacturing is reshoring.
“Now, what we’ve got to say, ‘Is that a wave or is that a trend?’”
Moeller also said robust transmission connections keep the lights on during 100-year events that are beginning to occur every other year. He said it’s unlikely any one grid operator can hold enough available generation to weather all storms.
However, Moeller implied there’s a transactional nature to imports and exports aided by transmission. He said that while MISO has supported TVA with exports — at one point during December 2022’s winter storm it was forced to stop to protect its own system — TVA never has returned the favor. Now, MISO isn’t inclined to lend a hand to TVA in future weather events because of that flow’s one-sidedness, Moeller said.
Moeller said MISO is meticulously drafting its second, $17 billion to $23 billion long-range transmission portfolio.
“The worst thing you can do is plan $20 billion in transmission and miss all the locations where the data centers want to be,” he said.
