As the 2022 Atlantic hurricane season entered its fourth month, Florida Power & Light’s (NYSE:NEE) customers were starting to feel they could relax.
Storm activity had been unusually light, with just four named storms since the season started on June 5, and only the first — Tropical Storm Alex — directly impacted Florida. The season’s first hurricane, Danielle, didn’t form until Sept. 1, making 2022 the first season to have its first hurricane develop so late since 2013.
“The Atlantic was very quiet; a lot of folks out there … were saying they thought hurricane season may be over,” Andy Pankratz, FPL’s senior director of emergency preparedness, said at SERC Reliability’s Extreme Weather Webinar on Thursday. “We’ve got onsite meteorologists that were definitely not believing that, and to their credit [they] were giving us a heads-up that the Atlantic looked like it was going to be getting more active very soon. And that’s exactly what happened at the very beginning of September.”
Andy Pankratz, Florida Power & Light | SERC
Storm activity began to pick up after Danielle, but Hurricane Ian finally blew away the relative lull when it made landfall in southwest Florida as a Category 5 storm on Sept. 28, having already caused a nationwide power outage in Cuba. With 150-mph winds, the storm tied for the fifth-strongest hurricane ever to hit the contiguous U.S. And with 149 fatalities it was the deadliest storm to hit Florida since 1935.
Hurricanes are a fact of life for Florida’s utilities, but Ian took things to another level. Recalling that he “was around for” 2004’s Category 4 Hurricane Charley, Pankratz shared a graphic showing that the storm could have fit entirely within the eye of Ian, saying “it really put things into perspective.”
Ian cut power to more than 2 million of FPL’s customers, although recovery was rapid compared with earlier storms. As an executive from the company explained at SERC’s December board of directors meeting, two-thirds of affected customers were restored by the day after landfall, and restoration was complete within eight days. (See FPL Credits Grid Hardening for Fast Ian Restoration.)
Despite the fast recovery, Ian left weakened soil that proved a liability when Hurricane Nicole, the 14th and last named storm of the season, made landfall in November. Nicole, a Category 1 at its peak, was the third storm of 2022 to make landfall in Florida after Alex and Ian, and only the third November hurricane on record to do so. It was also the first hurricane to make landfall on Florida’s east coast since 2005’s Hurricane Katrina.
The unstable ground after Ian “really created some challenging conditions” for crews from FPL and other utilities assisting in recovery efforts, Pankratz said, and workers “had to really get creative” when entering affected areas. Their solutions included using barges to bring trucks into areas they could not access from land; one employee even used a kayak to reach a substation surrounded by floodwaters.
Pankratz said that although FPL sees its response to Ian and Nicole as “arguably … two of our best performances from a restoration perspective ever,” the utility is still looking for areas to improve.
“We have pages and pages and pages of lessons learned and things that we want to do better — and things that we’ve already implemented this year and are continuing to implement prior to storm season,” Pankratz said. “We’re really, really focused on lessons learned and getting better each and every time we have an event — or support an event.”
Most of the cuts from the proposed standards are for light- and medium-duty vehicles, which produce a greater volume of emissions and have more readily available alternatives to the internal combustion engine, but EPA also proposed new standards for heavy-duty vehicles.
“Today’s actions will accelerate our ongoing transition to a clean vehicles future, tackle the climate crisis head on, and improve air quality for communities all across the country,” EPA Administrator Michael Regan said at an event announcing the standards outside the agency’s headquarters.
EPA expects the rules for light- and medium-duty vehicles will cut 7.3 billion MT of CO2 between 2027 and 2055 and projects net benefits of $1.6 trillion. The heavy-duty vehicle rules would save 1.8 billion MT of CO2 and yield $320 billion in benefits.
The proposed standards for light-duty vehicles start in 2027 and ramp up to an 82 grams of CO2 per mile standard by model year 2032, while the medium duty standard ramps up to 275 grams per mile by 2032. Those represent cuts in fleet average CO2 emissions of 56% and 44%, respectively, compared to the model year 2026 standards, EPA said.
Heavy-duty vehicles have different standards depending on the type of vehicle covered, with EPA updating existing standards for 2027 and extending more stringent cuts out to model year 2032.
The standards are expected to drive significant increases in the EV share of the vehicle market, although the fact that they are technology-neutral should also drive improvements to internal combustion engines and benefit other technologies such as fuel cells.
In light of the rules, EVs are forecast to make up to 67% of light-duty sales by 2032 and 44% of medium-duty sales by that year. EVs are expected to account for 8.4% of light-duty sales this year, up from just 2.2% in 2020.
Automobile manufacturers have already said they plan to switch to producing larger volumes of EVs in the coming decades. Based on those pledges and current market shares among automakers, EVs should make up 48.6% of sales by 2030. Regan said that the agency was following the market trends, which shows the standards are achievable.
“I believe that because when I look at the projections that many in the automobile industry have made — his is the future,” Regan said. “The consumer demand is there. The markets are enabling it. The technologies are enabling it.”
The EPA’s standards provide a regulatory compliment to federal incentives from recent legislation, including the Inflation Reduction Act, Infrastructure Investment and Jobs Act and the CHIPS and Science Act, which include tax credit and other funding for electrification, Regan said.
The Alliance for Automotive Innovation, which includes major automakers such as Ford and General Motors, agreed that the industry was electrifying but called EPA’s plan “aggressive by any measure.” Reaching the target depends on factors outside of automakers’ control, the group said.
“Factors outside the vehicle, like charging infrastructure, supply chains, grid resiliency, the availability of low carbon fuels and critical minerals will determine whether EPA standards at these levels are achievable,” it said.
Impacts to the Grid
EPA’s modeling predicts non-hydroelectric renewables becoming the largest overall source of electric generation by 2035, at about 46% of total generation, rising to 70% by 2050.
“As [power plant] emissions continue to decrease between 2028 and 2050 due to increasing use of renewables, and as vehicles increasingly electrify, the power sector GHG and criteria pollutant emissions associated with light- and medium-duty vehicle operation will continue to decrease,” the agency said in its light- and medium-duty rulemaking.
Light- and medium-duty vehicle rule’s impact on power generation | EPA
The additional electric vehicles will not increase electricity demand significantly, according to EPA, ranging from an increase of less than 0.4% in 2030 to about 4% in 2050. The heavy-duty rule would add another 0.1% of demand in 2027 and 2.8% in 2050. That demand growth is much smaller than what the industry dealt with as air conditioning grew in popularity, or more recent demand growth associated with the digital revolution.
“The U.S. electricity end use between the years 1992 and 2021 increased by around 25% without any adverse effects on electric grid reliability or electricity generation capacity shortages,” EPA said.
The light-duty rule highlighted analysis in California, which has found that 20% of charging loads at any time in the day can be shifted to another hour in a process that benefits car owners, other customers and the grid at large.
“Integration of electric vehicle charging into the power grid, by means of vehicle-to-grid software and systems that allow management of vehicle charging time and rate, has been found to create value for electric vehicle drivers, electric grid operators and ratepayers,” the rule said. “Management of PEV charging can reduce overall costs to utility ratepayers by delaying electric utility customer rate increases associated with equipment upgrades and may allow utilities to use electric vehicle charging as a resource to manage intermittent renewables.”
The new cars will require new charging infrastructure, with 12 million home chargers expected in 2027, increasing to more than 75 million in 2055, while workplace chargers will grow from 400,000 to 12.7 million, and public chargers will grow from 110,000 ports to more than 1.9 million.
Other infrastructure will be needed to integrate the new demands, such as upgrades to local distribution systems. But EPA found significant uncertainty on exactly what would be needed and asked for comments to weigh in on the subject.
Reactions
The rules elicited opposite reactions from the country’s two main political parties, as seen from statements from the leadership of the Senate Environment and Public Works (EPW) Committee that oversees the EPA.
“In addition to providing regulatory support to where the market is already heading, EPA’s proposed vehicle emissions standards would make significant progress in our fight against climate change,” EPW Chair Tom Carper (D-Del.) said.
“They will also save Americans money at the pump and better insulate our country from the volatility of the global oil market. I am encouraged by the Biden Administration’s step toward cleaner, more efficient cars, trucks and vans, and I hope to see a final rule by the end of the year.”
Ranking member Rep. Shelley Moore Capito (R-W. Va.) blasted the rule and said it made little sense when coupled with other actions that are shutting down “baseload” coal and natural gas plants.
“Today, the Biden administration made clear it wants to decide for Americans what kinds of cars and trucks we are allowed to buy, lease and drive,” Capito said. “These misguided emissions standards were made without considering the supply chain challenges American automakers are still facing, the lack of sufficiently operational electric vehicle charging infrastructure, or the fact that it takes nearly a decade to permit a mine to extract the minerals needed to make electric vehicles, forcing businesses to look to China for these raw materials.”
Likewise, reactions among clean energy groups were largely positive, while the American Petroleum Institute lambasted the rule.
“This deeply flawed proposal is a major step toward a ban on the vehicles Americans rely on,” API CEO Mike Sommers said. “As proposed, this rule will hurt consumers with higher costs and greater reliance on unstable foreign supply chains.”
The American Council for an Energy Efficient Economy argued that EPA should have gone even further than it did.
“These are strong proposals, yet they do not give us as much progress as climate circumstances demand,” ACEEE Transportation Program Director Shruti Vaidyanathan said. “We need to move to electrified vehicles as rapidly as possible while continuing to reduce emissions from conventional vehicles, and these proposals need to be improved to get us there.”
The cost of transmission congestion doubled in the organized electricity markets between 2020 and 2021, rising by billions of dollars, according to a report released Thursday by Grid Strategies.
All of the ISOs and RTOs except for CAISO publish their congestion costs; they were up $7.7 billion on the year, which, extrapolated to the rest of the country, leads to a national cost of $13.4 billion, according to “Transmission Congestion Costs in the U.S. RTOs.”
Congestion costs rebounded in 2021 after reduced demand from the height of the COVID-19 pandemic in 2020 led to lower costs that year, but other factors helped fuel that increase.
“The price transparency and generally more favorable transmission expansion policies in the RTO regions tend to reduce congestion in those areas relative to non-RTO regions,” the paper said. “However, RTO regions have experienced more renewable deployment in recent years than non-RTO areas, which may somewhat offset those factors as renewable expansion tends to increase transmission congestion when it outpaces transmission expansion.”
The best way to cut congestion is to build new transmission, the report said, citing a PJM analysis that found that transmission enhancements approved in the past decade have cut costs to serve consumers by $280 million annually.
No similar numbers exist for how interregional lines would benefit consumers by cutting congestion, but Lawrence Berkeley National Laboratory found that interregional transmission links can have just as much, if not more, value than intraregional links.
While the bounce back from the pandemic was a national trend, different regions had different factors impacting the rise of congestion.
ISO-NE continues to deal with increased congestion as transmission development has lagged the development of renewable energy.
“A new wind generator in coastal Maine went online in late 2020, and along with other abundant wind generation, and in the absence of proactive transmission additions, congestion increased,” the report said.
Higher natural gas prices, especially on the coldest days of winter, helped to push up congestion in NYISO. MISO saw congestion costs nearly triple in 2021 to $2.8 billion, with roughly $730 million of that total alone from the February storm, also known as Winter Storm Uri, that knocked out power in Texas and surrounding states.
“This is consistent with the general pattern nationally that much of the congestion (and value of transmission) occurs in a relatively small percentage of the hours,” the report said.
SPP saw congestion prices more than double to $1.2 billion, with its market monitor attributing the increase to the distance between generation and load centers, outages of key transmission lines, volatile fuel prices and Uri.
Texas was also obviously heavily impacted by Uri, with congestion costs representing 33% of total costs in February 2021, compared to 15% in February 2020. The growth of renewables also helped push up congestion.
“In 2021, 3 GW of wind output and 3.6 GW of solar came online [in ERCOT] without concomitant transmission development, which contributed to a real-time congestion cost increase of 46%,” the report said.
The U.S. Energy Information Administration on Wednesday reported that domestic use of natural gas reached a six-year January low this year.
Domestic consumption in February 2023 was the lowest in five years for that month. As a result, EIA said in its Short-Term Energy Outlook, natural gas inventories at the end of March were 19% higher than the average over the preceding five years.
Use of natural gas is widely targeted for gradual reduction in a planned transition to renewable energy sources, but the reduced use this past winter was attributed to mild weather and the resulting decrease in demand for it as a heating fuel in the residential and commercial sectors.
This varied by region. Natural gas accounts for 70% of space-heating fuel in the Midwest Census Region and 52% in the Northeast Census Region, for example. Residential and commercial gas consumption was down 16% and 22% in those two regions, respectively, from the January-February average in the preceding five years.
But in the West Census Region, one of the coldest winters in years caused gas consumption to surge in the electric power sector more than in the residential and commercial sectors: 33% more gas was burned in January and February than the average over the preceding five years, EIA said.
The U.S. is the world’s largest producer of natural gas and more recently became the largest exporter of its liquid form. EIA projects continued year-over-year growth of LNG exports in 2023 and 2024.
Meanwhile, EIA said Tuesday that it expects continued and long-term growth in U.S. production of “associated natural gas” — gas that is extracted from oil formations.
U.S. natural gas production (Tcf) is expected to increase through 2050. | EIA
Associated natural gas historically was a footnote, accounting for only about 6% of domestic supply as recently as 2010. But in its Annual Energy Outlook, EIA is projecting it will account for approximately 20% of total U.S. natural gas production through 2050.
EIA bases its prediction on three trends:
rising oil prices that will support increased production from nontraditional or unconventional oil formations that contain significant amounts of natural gas;
the tendency of these unconventional oil wells to produce a higher ratio of natural gas to oil as they age; and
increasingly favorable economics for associated natural gas resources, in part because of official policies such as the Inflation Reduction Act’s penalties for venting and flaring methane.
Developers of the Western Interconnection’s largest transmission project in decades can begin construction after getting the go-ahead from the U.S. Bureau of Land Management on Monday.
BLM issued a notice to proceed (NTP) to the TransWest Express (TWE) project, a 732-mile high-voltage line that will be capable of transmitting 3,000 MW of energy from wind farms in Wyoming to consuming markets to the west — specifically California. The NTP is the final step of a BLM approval process begun in 2008.
“Achieving the BLM NTP milestone provides important certainty that is needed as we work to complete other pre-construction steps such as finalizing our [engineering, procurement and construction] contractor team. We plan on commencing construction activities on the TWE project before the end of the year,” TransWest CEO Bill Miller said in a statement.
TWE would cross federal land for about two-thirds of its path, traversing three Western transmission planning regions. The project would consist of three linked segments: a 405-mile, 3,000-MW HVDC line between Wyoming and Utah; a 278-mile, 1,500-MW HVAC line between Utah and Nevada; and a 49-mile, 1,500-MW HVAC transmission line in Nevada. It would connect in Utah to lines serving the Los Angeles Department of Water and Power and in Nevada to CAISO’s balancing authority area.
“Public lands continue to play a vital role in advancing President Biden’s goal of achieving a net-zero economy by 2050,” BLM Director Tracy Stone-Manning said in a press release. “This large-scale transmission line will put people to work across our public lands and will help deliver clean, renewable energy. Our responsible use of public lands today can help ensure a clean energy future for us all.”
TWE is expected to create about 1,000 jobs during its construction phase, according to BLM. The line would tap power generated by the 3-GW Chokecherry and Sierra Madre Wind Energy Project in Wyoming, which will also partially sit on public lands administered by the BLM once construction is complete.
Both TransWest and the wind project are owned by The Anschutz Corp.
Monday’s federal approval marked the second milestone for TWE in less than a month. In March, FERC approved an agreement allowing the company to continue its effort to become a participating transmission owner (PTO) in CAISO under a new “subscriber PTO” model the ISO is developing to accommodate lines not funded by its transmission access charge, a cost allocation mechanism. Instead, TransWest would be completely funded by its own customers. (See FERC OKs CAISO-TransWest Move Toward PTO Status.)
TransWest said it expects to complete construction of the first stage of the transmission project in 2027.
An energy market research group estimates that 159 GW of coal-fired power production will be online in the U.S. in 2026, down half from a peak of 318 GW in 2011.
By 2030, the Institute for Energy Economics and Financial Analysis report projects, the U.S. coal-fired fleet will be down to 116 GW, as gas, wind and solar power supplant it.
Fewer than 200 large units — those rated at 50 MW or more — now operating have not announced retirement dates, IEEFA said. The organization also noted an even steeper decline: Coal-fired plants now burn less than half as much coal and produce less than half as much electricity as they did in 2011.
Data were derived from internal IEEFA research, the U.S. Energy Information Administration, S&P Global and company reports.
IEEFA data analyst Seth Feaster, author of “U.S. on Track to Close Half of Coal Capacity by 2026,” said in a news release that the continuing trend does not bode well for the industry.
“This milestone is another clear sign of the ongoing and deep restructuring of the U.S. coal industry, as demand for the fuel continues to drop quickly,” he said. “It is likely to result in significant mine closures, layoffs, and falling tax and royalty payments in coal-producing states.”
IEEFA states that it takes a nonpartisan, evidence-based approach to its mission, which is to accelerate the transition to a diverse, sustainable and profitable energy economy. The 501(c)(3) nonprofit corporation lists multiple climate advocacy organizations among its financial supporters.
The Institute for Energy Economics and Financial Analysis projects a steady decline in U.S. coal-fired power generation. | Institute for Energy Economics and Financial Analysis
Its report speculates that coal power generation may decrease even more quickly than projected because of higher operation and maintenance costs for the remaining units, most of which went into service in the 1970s.
EPA in the last two months has taken multiple steps to tighten emissions regulators from coal-burning power plants; these are expected to prompt additional retirements. (See EPA Proposes Tougher MATS Regs on Coal Power Plants.)
The long-running effort to restrict and or reduce coal as a fuel in the U.S. has drawn criticism from the coal industry and its allies as a threat to energy security. But as federal and many state governments press to speed the transition from fossil fuels to emissions-free alternatives, some grid operators are voicing similar concerns. (See PJM Chief: Retirements Need to Slow down.)
The IEEFA report projects more than 80 GW of coal retirements from 2023 through 2030 and indicates 10.5 GW of the retired plants are expected to be converted to burn natural gas.
The pace of retirements will be steady over time, the report said, but not from year to year, as construction delays have ensued on renewable energy projects. For example, 11.8 GW of coal-fired capacity is currently announced for closure in 2023, less than 3 GW in 2024, 17 GW in 2025, roughly 10 GW in 2026 and 22 GW in 2027.
With the 2022 passage of the landmark Inflation Reduction Act, and its heavy emphasis on accelerating the energy transition and building a supply chain for it, the numbers could be in flux for a while.
The report noted that multiple factors in favor of coal in 2022 — soaring natural gas prices, high demand for power and the post-pandemic economic rebound — were counterbalanced by railroad delivery problems, a labor shortage and utility reluctance to increase coal use.
When coal’s use as a fuel for generating electricity in the U.S. peaked in 2011, it was responsible for 44% of power generation, EIA data cited in the report indicate. Based on current announcements and trends, coal’s power market share could decrease to 10% or less by 2030, IEEFA said.
PJM asked FERC on Tuesday to delay its next four Base Residual Auctions to give the RTO time to incorporate rule changes to address reliability concerns (ER23-1609).
The RTO initiated an accelerated stakeholder process in February to respond to concerns that the region could fall short of resources because of increased demand from electrification and a “timing mismatch” between plant retirements and new entries. It has promised to file the changes by Oct. 1. (See PJM Presents Alternative Capacity Auction Schedule.)
PJM’s Reliability Pricing Model (RPM) calls for the BRA to be held in May, three years prior to the start of the delivery year. But the schedule has been suspended since 2018 as the RTO has considered repeated changes to its capacity market rules.
The 2026/27 BRA currently is scheduled to open on June 14, 2023.
“While further delay of the upcoming RPM auctions is not ideal, continuing to conduct the auctions under the existing rules further exacerbates the challenge of procuring the necessary resources to facilitate the imminent energy transition while maintaining reliability,” PJM said. “In short, since the current tariff provisions … may be unjust and unreasonable and require change, it does not appear reasonable to continue to lock in resources on a forward basis to such provisions, particularly when they exacerbate the reliability issues that PJM has identified.”
The RTO requested to hold a BRA every six months through delivery year 2028/29.
PJM proposed the following “illustrative” BRA timeline, assuming the commission approves its proposed tariff revisions without material changes by Dec. 1, 2023:
2025/26: June 2024
2026/27: December 2024
2027/28: June 2025
2028/29: December 2025
The three-year forward schedule would resume for the 2029/30 BRA in May 2026.
PJM also proposed continuing its current practice of maintaining all third Incremental Auctions for each delivery year and canceling all IAs that fall within 10 months of the associated BRA.
“It is reasonable to cancel those Incremental Auctions that are within 10 months of a Base Residual Auction in these limited delivery years because there would be little, if any, need for such auctions under a compressed Base Residual Auction schedule, as very little time would pass between the Base Residual Auction and Incremental Auctions,” PJM said. “Moreover, market participants will always have the opportunity to buy back and offer additional capacity in the third Incremental Auction before the start of the delivery year under this proposal.”
Board’s Directive
The PJM Board of Managers called for action to enhance the modeling of winter risk and correlated outages; ensure sellers can reflect nonperformance risk in their offers; improve capacity accreditation for all resources; and ensure synchronization between capacity and fixed resource requirement rules. (See PJM Board Initiates Fast-track Process to Address Reliability.)
“That does not mean that the other topics PJM and stakeholders have been examining since April 2021 in the Resource Adequacy Senior Task Force may not be included in the upcoming enhancement filing,” the RTO told FERC.
Demand on the New England regional power system fell to its lowest level in over a quarter century Sunday, thanks to the holiday, mild weather and sunshine beating down on an ever-growing number of solar panels.
ISO-NE said Tuesday that demand on the grid was the lowest it had ever recorded since the RTO began operations in 1997.
The 6,814-MW demand between 2 and 3 p.m. shattered the previous record, 7,580 MW, set May 1, 2022.
Steven Gould, ISO-NE director of operations, said the new record was not surprising.
“The evolution of New England’s power system continues,” he said in a news release. “The previous record lasted less than a year, and this one likely won’t last long either. Each day, our system operators are seeing the clean energy transition play out in real time.”
The lowest demand for electricity during the week is typically on Sunday, and Easter historically sees even lower demand than the average Sunday. Warmer temperatures on this Easter reduced demand even further. Abundant sunshine clinched the record, as behind-the-meter rooftop solar panels across the RTO’s six-state region reached an estimated peak output of more than 4,500 MW.
ISO-NE said demand rose through the predawn hours of April 9 to peak at more than 10,000 MW just after sunrise, dropped below 7,000 MW to set the record in mid-afternoon, and rebounded quickly as the sun went lower in the sky.
Demand for the day peaked at more than 12,000 MW just after sunset. This created the so-called duck curve in the flow of electricity through the grid, in which demand bottoms out in mid-afternoon rather than the overnight hours, as it usually does. The graphic representation of this phenomenon on a line chart vaguely resembles the classic rubber duck bathtub toy.
And as Gould indicated, the duck population is growing.
ISO-NE did not record its first duck curve until April 21, 2018. Through Dec. 31, 2021, it recorded 34 more duck-curve days. Then, in calendar year 2022, it recorded 45 duck curve days.
Solar power potential is at its strongest in the spring, ISO-NE noted, and 27 of the duck curve days in 2022 were in March, April and May.
Summer 2022, with its midday air conditioning demands, saw very few ducks: two in September, one in June and none in July or August.
Late autumn and early winter also see fewer ducks, as solar power generation decreases before and after the winter solstice; ISO-NE recorded only two duck curves in January 2022 and just one in December 2022.
MISO says a recent rule change that places limits on MISO board members attending meetings hosted by state regulators is necessary, despite pushback from some commission members.
The Board of Directors voted last month to remove their option to attend meetings on MISO matters arranged by state or federal regulators. The change was made after a regular review of board procedures and is contained in the MISO Board of Directors Principles of Corporate Governance, which stipulates directors’ conduct.
The revision leaves regulator-board member exchanges to take place largely during public board meetings, Advisory Committee meetings, and annual stakeholder meetings. MISO said the change is effective following the board’s vote and was necessary to avoid the perception of partiality.
“The changes were clarifying edits to emphasize that board communications with stakeholders are most appropriate and useful in connection with open and public meetings,” spokesperson Brandon Morris said in a statement to RTO Insider. “MISO’s directors are mindful of their duties and independence as directors, as well as the independence of MISO, and are sensitive to perceptions of conflicts of interest or favoritism.”
Morris said the board has declined multiple meeting requests from separate MISO sectors in the past and said it is “best that MISO’s Principles of Corporate Governance align with the Board’s practice of not meeting separately with MISO stakeholder groups.”
“The changes do not change or limit in any way the interaction that MISO’s Board has with MISO stakeholders today,” he added.
During the grid operator’s March board meeting, Michigan Public Service Commission Chair Dan Scripps and Indiana Utility Regulatory Commissioner Sarah Freeman expressed disappointment with the rule change.
The Organization of MISO States, which is comprised of regulatory representatives from the 15-state footprint, said it does not have a position on the removal of regulator-scheduled meetings with MISO board members. The organization did not provide further comment.
FERC representatives did not return RTO Insider’s request for comment as to whether federal regulators will be affected by the changes.
Another governance rule change clarifies the Nominating Committee’s recommendation that the board pursue waivers to seat certain directors past MISO’s three-term limit. Board Chair Todd Raba warned last month that the board will likely have to authorize waivers to avoid an institutional knowledge gap, as multiple directors are on track to reach their term limits over the next few years. (See “Waivers May be Necessary to Retain Directors Past Term Limits,” MISO Board of Directors Briefs: March 23, 2023.)
The Nominating Committee vets and selects board candidates for the membership’s consideration. It is comprised of select board members and two MISO stakeholders, one of whom is typically from a state regulatory commission.
The board will meet privately for a strategy planning session April 18-19 in Nashville, Tennessee. The meeting won’t be open to stakeholders because the topics involve attorney-client privilege.
With MISO still years away from allowing distributed energy resource (DER) aggregators to fully participate in its markets, the RTO hosted experts this week to discuss best practices in registering DERs and data sharing.
Voltus’ Emily Orvis said she thought it was valuable to talk about MISO’s current DER registration process even if the grid operator may be six years away from final compliance with FERC Order 2222.
The RTO has requested that the commission allow it to wait until nearly 2030 to introduce a wholesale participation model for DER aggregation. It said it first needs to replace its market platform before staff have the technological capability to comply with the order. (See MISO Stakeholders Protest RTO’s Order 2222 Implementation Timeline.)
Orvis said MISO should standardize its enrollment processes for demand response, emergency demand response, load-modifying resources and dual-enrolled resources.
“The fact that there are disparate registration processes has a cascading effect,” she told stakeholders during a MISO DER Task Force conference call Tuesday. Orvis said that market participants must sometimes email sensitive customer data for LMR and emergency demand response registrations; she recommended staff adopt a single web portal for DER enrollments.
“The future is in some ways already here. We cannot wait until 2029 or whenever 2222 compliance is to figure out a more secure and streamlined registration process,” Orvis said.
She said MISO should modify its registration process so it doesn’t reject entire aggregation enrollments if a single site’s data is incorrect or changes. “For example, if one small site of 100 in an aggregation changes [its load-serving entity], the entire aggregation loses eligibility,” Orvis said.
Creation Energy founder and CEO Chris Hickman said DERs will be more useful to the grid if better data sharing is in place. He said he has always assumed an entity would step up to create and manage a collaborative tool for DER data sharing. Eventually, he said, he realized it was up to his team to establish the nonprofit registry they debuted earlier this year.
When DERs trigger grid issues, it’s because they’re incorporated with little to no operational visibility and control, Hickman said. He said DERs integrated with utility or RTO visibility and control can solve issues like poor power factor and phase balance.
“Regions like Australia, Germany, Ireland, California and Texas that have high penetrations of DERs have experienced cascading outages … and have identified a registry as the key component to help resolve issues,” Hickman said.
He said the industry has an opportunity to collaborate on a data exchange source, his organization’s Collaborative Utility Solutions, that could save billions of dollars. The nonprofit is funded by utilities’ memberships based on their size and competitive aggregators who pay for the data services. DER owners or operators are responsible for registering their assets’ information.
RTOs, state regulatory commissions, equipment vendors and other industry members are eligible for free subscriptions. Hickman said he plans to keep the subscriptions free, saying that if charged, the entities would recover their costs through utilities or consumers, effectively charging the consumer twice for the registry.
Hickman said membership costs will drop as the enrollment grows and administrative costs are dispersed.
“The more members we attract, the lower the costs go,” Hickman said. He said the system aims to replicate the Electric Power Research Institute’s (EPRI) Common Information Model.
EPRI’s Tanguy Hubert said the MISO region could house a program similar to the United Kingdom’s Flexible Power Initiative, where some DERs provide grid services by adjusting their power imports or exports.
Hubert said most of the U.K.’s DER-provided flexibility services are contracted without an advance capacity reservation for unplanned conditions. Only a fraction of capacity is contracted for planned situations under firm reservations, he said.
Andy Pankratz, Florida Power & Light | SERC
