FERC once again has said it needs more information on clearing price caps before MISO can proceed with sloped demand curves in its capacity auctions.
The commission issued a second deficiency letter April 23 on MISO’s plan to swap in sloped demand curves for its current vertical curve in its seasonal capacity auctions (ER23-2977).
FERC asked about the sloped demand curve design’s opt-out provision to preserve state authority and lack of clearing price caps, among other details, late last year. (See FERC Wants More Detail on MISO Sloped Demand Curve Plan.)
This week, the commission again zeroed in on MISO’s removal of its annual price cap for auction clearing prices as part of the move to sloped demand curves. It said it needs more explanation behind the RTO’s proposal to eliminate the yearly cap.
MISO has said once it implements the new curve design, the total annual price for a local resource zone could reach as high as four times the cost of new entry (CONE), depending on whether capacity shortages occur in all four seasons of the auction. However, the RTO has not explicitly listed an annual price cap in its new tariff language, telling FERC it is not necessary because its plan is clear that clearing prices will be capped at the seasonal CONE. It also said there’s only a small chance a zone would experience shortage conditions in all four seasons and if that occurred, the more-than-$1,300/MW-day prices that ensue would properly reflect an “extreme” situation.
MISO’s current auction design employs a 1.75-times-CONE price cap for a local resource zone. This year’s CONE averages $330/MW-day. The RTO has said its sloped demand curves would not allow prices to jump automatically to CONE values for small capacity shortages below reserve requirements, unlike the current, unyielding vertical demand curve.
Nevertheless, FERC asked MISO to shed more light on why it believes it is appropriate for prices to go as high as four times the cost to build new generation and how those price signals could incent more generation to show up.
FERC also asked for MISO to better explain why its current CONE cap would “degrade market efficiency and transparency when implemented with price-sensitive demand curves” like its sloped demand curve. The commission said it needed to hear more justification for the four-times-CONE construct versus the existing annual cutoff. It also questioned MISO’s stance that any “ex post adjustment of prices could lead to suboptimal resource adequacy outcomes.”
Projected load growth nationwide from data centers, electrification and increased domestic manufacturing will drive increasing demand for renewables through the next decade, NextEra Energy CEO John Ketchum said during the company’s first-quarter earnings call April 23.
“We believe the U.S. renewables and storage market opportunity has the potential to be three times bigger over the next seven years compared to the last seven, growing from roughly 140 GW of additions to approximately 375 to 450 GW,” Ketchum said.
Ketchum said the domestic solar supply chain is “much improved from two years ago,” asserting that manufacturing capacity has increased and inflationary pressures are easing.
“The U.S. will need a significant and growing amount of electricity over the next decade and beyond, a large part of which will be powered by new renewables and storage,” Ketchum said.
Ketchum said the ability to put solar and battery resources wherever needed will make them especially valuable in meeting demand from data centers in coming years.
The company reported that subsidiary Florida Power & Light placed in service 1,640 MW of solar in the first quarter, while NextEra Energy Resources had its best quarter for solar and storage origination, adding 2,765 MW to its backlog.
CFO Kirk Crews said FPL now owns and operates more than 6,400 MW of solar resources, “the largest utility-owned solar portfolio in the country.”
FPL’s 2024 10-year plan also doubled its battery storage deployment target compared to 2023, with the target now totaling 4 GW. The utility also plans to deploy 21 GW of solar over 10 years.
Crews also announced NextEra Energy Partners plans to repower an additional 100 MW of wind capacity, increasing its wind repowering target to about 1,085 MW through 2026.
Responding to a question about the potential of small modular reactors to help meet data center demand, Ketchum said he is “a real skeptic in SMRs coming into the picture to satisfy data center demand anytime in the near future. … SMRs are still a decade to 15 years away.”
NextEra reported GAAP net income of $2.27 billion ($1.10/share) for the quarter, an 8.72% increase over the same quarter last year. This was off a 14.67% decrease in total revenue for the quarter from last year’s $6.716 billion.
Citing “significant new headwinds” to securing energy resources, participants in the Western Resource Adequacy Program (WRAP) are seeking to delay the program’s “binding” penalty phase by one year, to summer 2027.
Members of the voluntary program run by the Western Power Pool (WPP) face a May 31 deadline to commit to binding operations for summer 2026.
Once committed, participants will be at risk of incurring significant penalties for coming into a binding season with capacity deficiencies compared with their “forward showing” of promised resources for that season. The penalties are based on a formula set out in the WRAP tariff, which FERC approved in February 2023.
“Some WRAP participants have expressed concerns about their ability to meet WRAP forward-showing requirements in the next few years,” members of the WRAP’s Resource Adequacy Participants Committee (RAPC) said in an April 22 letter addressed to “Western Stakeholders.”
“They are understandably concerned, due to the reasons outlined [in the letter], about moving into binding operations given the potential magnitude of deficiency charges currently included in the tariff,” the RAPC wrote.
Those reasons include:
“supply chain issues and other challenges” that “have slowed our ability to deliver and interconnect new resources”;
regional peak load growing at a rate “faster than previously expected, driven primarily by electrification and data center expansion”; and
“extreme weather events” that have “further challenged” the region’s assumptions about the volume of resources necessary to maintain reliability.
The RAPC wrote that the WRAP “remains a critical tool” for addressing those challenges, having “shown its value by helping quantify where we stand and where we need to go.”
“We plan to continue our best efforts to acquire and interconnect sufficient new resources to meet load growth as we strive to meet WRAP’s regional resource adequacy metrics,” it said. “We have been actively engaged in conversations with each other and Western Power Pool about when a critical mass of participants can enter binding operations of WRAP together.”
The WRAP tariff gives the WPP the flexibility to begin binding operations between 2025 and 2028. That means the RAPC’s request to shift the start date to 2027 is subject to stakeholder approval but would not require a tariff change.
“Once the revised transition plan is ready, we will submit the plan for consideration by stakeholders and the WRAP Board of Directors, following the WRAP governance process,” the RAPC wrote.
Seeking ‘Critical Mass’
In a statement responding to the RAPC letter, WPP CEO Sarah Edmonds said her organization has “worked closely” with WRAP members as they’ve considered their decision and will continue to work with them on a proposal for transitioning to binding operations.
“Our goal has always been to have a critical mass of participants in a binding program so that the West will be able to address urgent reliability needs,” Edmonds said. “That has not changed, though when and how we get there may look different than planned. Like the participants, our efforts will be focused on gaining commitment from a critical mass of participants for summer 2027.”
In a March 2023 briefing of the WECC Board of Directors, Edmonds said she hoped to see the WRAP become binding as soon as possible, but she acknowledged the binding phase still could be years away. (See WPP CEO Looks to ‘Earliest Possible’ Binding Season for WRAP.)
“To be candid, some load-serving entities are in better shape to go binding than others. Others need a little more time to adjust their procurement strategies and their positions relative to what they see coming at them,” she had said.
The WRAP participants’ move for a one-year delay indicates the RA situation in the West likely has deteriorated significantly since then.
“There is a legitimate question about whether the West will have adequate resources in the years to come. WRAP is the only regional program that specifically addresses that question,” Edmonds said in her April 22 statement.
She said WPP now will focus on how to “collect more and better data from participants” for use in “more transparent regional discussions about events where capacity is constrained as we work toward going binding.”
Role in Broader Markets
While the WPP developed the WRAP and oversees its governance, the program’s technical operations fall to SPP, whose Markets+ day-ahead offering is competing for Western participants with CAISO’s Extended Day-Ahead Market (EDAM).
Under the tariff SPP filed with FERC last month, Markets+ participants would be required to participate in the WRAP. That integration was cited by Bonneville Power Administration staff in their recommendation this month that the federal power marketing administration choose the SPP-run market over EDAM. (See BPA Staff Recommends Markets+ over EDAM.)
“WRAP has become the dominant resource adequacy program outside of California,” BPA staff said in their recommendation. “The EDAM proposal does not propose a uniform adequacy metric or require EDAM entities to participate in a resource adequacy program. Bonneville staff supports and prefers the clear and consistent requirement that all Markets+ [load-responsible entities] must participate in WRAP, which better supports regional reliability.”
The WPP has not weighed in on the competition between Markets+ and EDAM, instead emphasizing the need for the West to have a sound platform for reliability.
“We welcome the various markets in development or under discussion in the West, but their benefit comes with the efficient and economic dispatch of resources at times of need,” Edmonds said in her statement. “That only works if there are adequate planned resources available to dispatch.”
President Joe Biden on April 22 announced $7 billion in funding from the Inflation Reduction Act, to be used by states and nonprofits across the country to install solar in low-income and disadvantaged communities.
The Solar for All grants, part of the IRA’s Greenhouse Gas Reduction Fund, will fund 60 programs aimed at installing solar on low-income single-family and multifamily homes, as well as building community or shared solar programs that target consumers, such as renters, who cannot put solar on their roofs.
EPA, which is administering the program, estimates that Solar for All projects could save more than 900,000 households in low-income and disadvantaged communities $350 million annually.
Consumers who sign up for community solar programs typically receive credits on their utility bills. The selected awardees all have committed to providing at least 20% savings on utility bills for all households served by their projects, according to a senior administration official speaking on background.
Speaking in Prince William Forest Park in Virginia, Biden estimated households benefiting from Solar for All projects would save about $400 per year on utility bills.
“Energy costs are among the biggest costs for families … particularly for middle-income families,” he said. “In fact, low-income families can spend up to 30% of their paycheck on their energy bills. It’s outrageous.
“Solar for All will give us more breathing room and cleaner breathing room.”
The program also could add about 4 GW of distributed solar to local electric systems while cutting the equivalent of 30 million metric tons of carbon dioxide, according to EPA.
EPA Deputy Administrator Janet McCabe provided a breakdown of the funding during an April 19 press call: $5.5 billion will go to 49 state-level awards, $500 million to projects in tribal communities and $1 billion to multistate organizations serving low-income communities not well served by the private market.
Grant amounts range from $43.7 million to $249.8 million.
The multistate grants will “focus on low-income communities; communities around historically Black colleges and universities, Hispanic-serving institutions, and tribal colleges and universities; households served by rural and municipal electric co-ops; families in the industrial heartland; and low-income customers who are unable to build rooftop solar but could still benefit from community solar,” McCabe said.
The Clean Energy Fund of Texas will partner with the Bullard Center for Environmental and Climate Justice at Southern Texas University to provide technical assistance and grants for community solar projects in “low-income and disadvantaged communities on the frontlines of energy policy and grid vulnerability challenges,” according to EPA.
These projects also could include energy storage, to deliver “grid and community benefits by powering community resilience centers,” EPA said. While based in Texas, the program will fund projects in 19 Mid-Atlantic and Southeastern states, from Pennsylvania to Texas.
“EPA’s Solar for All awards will mean that low-income communities, and not just well-off communities, will feel the cost-saving benefits of solar,” John Podesta, White House senior adviser for international climate policy, said in a statement.
“Residential solar electricity leads to reduced monthly utility bills, reduced levels of air pollution in neighborhoods and ultimately healthier communities,” said Adrianne Todman, acting secretary of the Department of Housing and Urban Development.
Biden noted that Prince William Forest Park, now part of the National Park System, originally was developed by the Civilian Conservation Corps, a jobs program President Franklin D. Roosevelt launched in 1933.
The CCC was part of the inspiration for the American Climate Corps, which Biden also announced would accept applications for its initial 2,000 positions via a new website. First proposed in 2021, the initiative aims to provide corps members with jobs and training to mitigate climate change.
As part of the corps, they also will be able to access the North America’s Building Trades Unions’ (NABTU) apprenticeship-readiness program, Biden said. And the U.S. Office of Personnel Management will expand eligibility for federal employment to individuals who have completed qualifying career or technical education through Climate Corps programs.
Reactions
Clean energy and environmental advocates were mostly supportive of Solar for All while also warning of potential obstacles ahead.
Jeff Cramer, CEO of the Coalition for Community Solar Access, said the $7 billion in federal funds could “unlock multiples of private capital. … Community solar is a critical tool in the broader toolbox of distributed solar options for American households.”
Chelsea Barnes, director of government affairs and strategy for the nonprofit Appalachian Voices, called the program “a game-changer for so many under-resourced and environmental justice communities seeking a more sustainable, reliable, democratized energy system.”
“For vulnerable households that depend on electricity for their health and security, the solar and battery storage systems resulting from Solar for All could act as a literal lifeline during times of emergency,” said Marriele Mango, project director for the Clean Energy Group, which will receive funding from Solar for All as part of the Community Power Coalition.
But “smart state energy policies and streamlined implementation will determine whether American families ultimately see the savings from Solar for All on their electric bills,” said Harry Godfrey, managing director at Advanced Energy United. He pointed to “lengthy and burdensome interconnection requirements, bureaucratic permitting processes, and state energy policies and regulations that undervalue or simply obstruct community and distributed solar.”
In addition, awardees still must negotiate and finalize agreements with EPA before they can access the funds. EPA estimates all contracts will be finalized by Sept. 30.
FERC is set to vote on its long-awaited proposed rule on transmission planning and cost allocation for regional lines at a special open meeting May 13, the commission announced last week ahead of this month’s usual meeting (RM21-17).
Parties who have worked on the rule spoke with RTO Insider and in other venues April 22 about what they expect to see from the commission.
“I want to make sure that it’s sufficiently strong so that planners really do plan for the anticipated resource mix; so they actually are required to consider all the factors of what that future resource mix looks like,” Grid Strategies President Rob Gramlich said in an interview. “I want to make sure there’s an actual decision that gets made about cost allocation.”
States should obviously participate in the cost allocation process, Gramlich said, but if they cannot agree, the process should not end there; FERC should do something to move the ball forward.
The two biggest precedents in FERC’s allocation regime can often come into conflict, former Arkansas Public Service Commission Chair Ted Thomas said on a webinar hosted by the Conservative Energy Network (CEN). The ideas that beneficiaries pay, and costs are commensurate with benefits, can often clash.
If a group is having dinner at a restaurant and only one diner orders dessert to share with the table, that person effectively caused the cost, but anyone who has a morsel will be a beneficiary, said Thomas, who runs a consulting firm.
“These two principles are in conflict,” Thomas said. “Because it’s really hard to get everybody on board in the same way on the front end so that they’re all the cost-causers. But with 20/20 hindsight, when you can see that somebody benefits — well, under this other principle they’re supposed to pay. But at the end of the day cost allocation is always about negotiation.”
The rule will not change the fact that ultimately, states and other stakeholders need to negotiate over transmission cost allocation, Thomas said, but hopefully it will add guidelines to simplify that process.
The issue of cost allocation is one area where FERC’s internal debates have spilled out into public somewhat, with Commissioner Mark Christie repeatedly saying he does not want to see one state pay for another’s policies, most recently in response to a letter from a group of congressmen led by Rep. Andrew Garbarino (R-N.Y.).
“It would be grossly unfair for FERC to force consumers in other states to pay for projects implementing the policies of politicians they never got the chance to vote for, when their own states’ policymakers have not agreed to pay for those projects,” Christie said in his response. “Such an imposition is contrary to American principles of democracy, a core principle of which is that the people have the right to elect the policymakers who impose costs on them, so the people can hold them accountable.”
Commissioner Allison Clements wrote less in response to Garbarino, but she argued that the costs of failing to invest in the grid, from customers facing huge bills from last-minute reliability needs to economic development going elsewhere, need to be considered.
“The risks and costs of declining to plan holistically for a modern grid may far outweigh the short-term lure for states to ‘go at it alone’ from a transmission planning perspective,” Clements wrote.
While public policy has generated plenty of debate beyond two of FERC’s three commissioners, Clean Energy Buyers Association Senior Director Bryn Baker told the CEN webinar that is not a focus of the proposed rule.
“Public policy — I think we need to be clear that unless there’s a dramatic reversal, is not in the list of things to evaluate the need for these lines,” Baker said. “It’s not in the goal as one of those metrics. I think that was a smart decision.”
State renewable portfolio standards are not driving as much of the need for new transmission as the corporate renewable energy buyers that CEBA represents are, she added. Coupled with growing demand, getting enough supply online to secure new industries that face international competition should be key goals when considering building out the grid, she said.
MISO’s Multi-Value Project lines have helped bring online many new renewable generators, but those were much less focused on policy than reliability and economics, Gramlich told RTO Insider.
“The state policies, even in MISO, weren’t even really binding,” Gramlich said. “They would have had the same results even if they completely ignored them. So, the point is, look at the economics of generation and anticipated additions and retirements over this 20-year period. And then design the network that achieves the lowest delivered costs for consumers; and any region should be able to do that.”
Thomas said that Arkansas did give up some of its authority when it pushed Entergy into MISO, but he said that the deal was worth it.
“Do I worry about state jurisdiction? I really don’t,” Thomas said. “Particularly if you’re in a … market already, there’s some jurisdiction you give up to save $50 million a year. … You’ve bound yourself to work with other states that share these resources. But for $50 million a year that goes straight into ratepayers’ pockets, it’s worth it.”
MISO might be ahead of the other RTOs when it comes to planning, but Thomas said it was in a class of organizations that could all use improvements.
While the devil is in the details, the broad strokes of FERC’s proposal requiring proactive planning have wide support, as 174 organizations, including 59 consumer groups, supported the rule in their comments to the commission, Gramlich said.
The Future of Transmission Competition
Another issue dividing stakeholders is FERC’s proposal to pull back on Order 1000’s elimination of the federal right of first refusal for regional transmission lines, finding it caused incumbents to focus on local projects not subject to competition.
Many utilities want to see FERC at least stick with that proposal, while supporters of competition are going to appeal if the commission follows through with it.
“So, No. 1: FERC has got to tackle the competitive transmission issues they’ve teed up and re-examine rights of first refusal,” WIRES Group Executive Director Larry Gasteiger said in an interview. “I think if that’s not in there, it would kind of be a major disappointment.”
FERC has acknowledged that Order 1000 is not working correctly and the policies around ROFRs need to be reformed, he added.
The opposite needs to happen, according to Paul Cicio, chair of the Electricity Transmission Competition Coalition, made up of firms engaged in competitive transmission development and consumer groups.
“If [FERC] doesn’t embrace competition; if it doesn’t enforce Order 1000, this will be most likely the most costly consumer rule in history,” Cicio told RTO Insider. “And it’s because of the sheer magnitude of the amount of capital that is and will be spent on transmission going forward.”
Competition can serve to contain the costs of transmission, which has granted very healthy returns that stay in place for decades, he added. The price of electricity has outstripped the Consumer Price Index in terms of inflation, and in cheap natural gas and other forms of generation, transmission and distribution costs have been rising, Cicio said.
The returns on investment of 10 to 12% are very high when compared to the manufacturing industry, which Cicio also represents, and he would like to see FERC tackle cost-containment issues more generally.
Cost containment came up in many of the comments, but Gasteiger said it was not really addressed in the proposed rule.
“We’re hoping that they don’t try to add it in now, given that they haven’t really provided notice on it,” Gasteiger said. “But I know there was a lot of pressure from different commenters for FERC to weigh in on that issue.”
Any rule of this scope from FERC is guaranteed to be challenged in court; ETCC has already said it would appeal the final rule if the commission reinstates the federal ROFR, which Cicio reiterated. (See Pro Competition Group Plans to Sue if FERC Reinstates Federal ROFR.)
The Reserve Certainty Senior Task Force (RCSTF) is considering two proposals from PJM and the Independent Market Monitor aimed at improving the performance of reserve resources.
Stakeholders have been tackling reserve performance since the response rate for committed resources has fallen after a market redesign consolidated the Tier 1 and 2 synchronized reserve products and lowered the offer cap from $7.50/MWh to 2 cents. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)
The PJM package would allow operators to modify the procurement targets for 30-minute reserves without having to do so for synchronized and primary reserves and create a formula for dynamically changing the 30-minute reliability requirement, PJM’s Emily Barrett told the RCSTF during its April 17 meeting. The calculation would use the larger of the primary reserve requirement, the largest active gas contingency and the average load forecast error, plus the average forced outage rate. The requirement is set at 3,000 MW, which was double the largest contingency when the requirement was established.
The changes would align the 30-minute reserve requirement with the breadth of operational risks dispatchers face and would grant flexibility to increase those reserves during periods of increased risks, such as harsh weather conditions, Barrett said.
PJM’s Lisa Morelli said staff will draft manual language and more details to present to stakeholders for a potential first read during the May 15 RCSTF meeting, with the intention of holding a vote June 12.
Monitor Focuses on Communications
The Monitor’s proposal would focus on getting reserve dispatch signals to generators in a manner that they can act on as quickly as possible. Joel Luna, of Monitoring Analytics, said the Monitor and PJM have been speaking with generation owners about the root causes of poor reserve performance since last spring and found that lags in communication can lead to generators not initiating their response until minutes after PJM has begun a reserve deployment.
Pointing to a synchronized reserve event Feb. 24, 2024, Luna said about 61% of the 1,882 MW resources deployed did not meet their assignment, of which he said 1,041 MW underperformed due to communication issues. Some units were waiting for a phone call from PJM to confirm their deployment. Others experienced lag between when the all-call signal was initiated by PJM and when it was received on their end due to how those generation owners relay signals between their control centers. And some experienced lag from the required switch to manual ramp from automatic dispatch signal.
The Monitor’s proposal would replace all phone communications used to convey deployment orders with automatic electronic signals and would include the deployment MW generators are being assigned through the existing security constrained economic dispatch (SCED) signals.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said many generators are being asked to run at a loss when providing reserves and compensation needs to be addressed alongside the communication issues.
“Prices need to reflect the system conditions, and clearly that’s not the case here,” he said.
Tom Hyzinski of the GT Power Group said adopting the Monitor’s recommendations could resolve some of the issues in the reserve market and clear the air to simplify addressing any remaining design issues. So long as all other options remain on the table should the proposal be endorsed, he argued there are no downsides to advancing the Monitor’s changes.
PJM and the Independent Market Monitor presented the Deactivation Enhancement Senior Task Force (DESTF) with two proposals increasing the notification generators seeking deactivation must provide PJM and standardizing compensation for those that agree to continue operating beyond their desired retirement date.
Speaking at the April 15 task force meeting, Monitor Joseph Bowring said that when requesting payment for reliability-must-run (RMR) contracts, generators include a combination of sunk costs and estimated costs in an artificial regulated utility rate case framework that results in significant overcompensation. RMR contracts are needed for generators that want to retire but which the RTO has determined must remain online to maintain reliability for a period that can extend to five years or longer.
Bowring argued the current practice is inefficient and creates uncertainty for all parties as settlement discussions last for years. He said the Monitor’s first principle is that compensation rules should be clear and unambiguous. Under the Monitor’s proposal, generators would be paid the actual costs the generation owner would incur in keeping the unit online, net of any revenues the unit received through PJM’s markets, plus an incentive. There would be a verification process for all such costs.
The proposal would allow generators to include in their RMR compensation: actual maintenance costs; short-run marginal costs, such as fuel and consumables; and new investments needed for the generator to remain available, along with an incentive payment calculated as a percent of incurred costs. Costs related to general overhead, artificial utility rate case elements, and previously incurred capital and inventory costs would not be included.
Generators seeking retirement would be required to notify PJM of their intent six to 12 months in advance of the capacity auction for the delivery year in which the unit would go offline, with the aim of giving other market participants time to offer resources that could resolve reliability needs prompted by the deactivation.
Resources operating on an RMR contract would be dispatched only when required for reliability and would not be included when calculating the capacity emergency transfer objective and capacity emergency transfer limit values, which are inputs used to determine the amount of capacity PJM aims to procure through Base Residual Auctions (BRAs). Market sellers operating on an RMR contract would not receive capacity performance (CP) bonus payments, nor would they be subject to underperformance penalties during emergency conditions. Bowring has argued that including RMR units in the capacity market and resource stack suppresses prices that could incentivize new generation.
Bowring also argued PJM should use the same reliability criteria in defining the demand in the capacity market as it uses to define the need for an RMR contract. Currently, a unit could fail to clear in the capacity market but be deemed necessary for reliability and thus eligible for an RMR contract.
Christian McDewell, of the Pennsylvania Public Utilities Commission, said FERC rejected limiting bonus payments to capacity resources and excluding energy-only resources when it rejected changes to the CP design PJM proposed following the critical issue fast path process (ER24-98). (See FERC Rejects Changes to PJM Capacity Performance Penalties.)
Bowring said consumers shouldn’t have to pick up all the costs of keeping a fuel production facility operational in addition to the marginal costs to keep the generator online. He added that potential interactions between RMR compensation and fuel procurement warrant further stakeholder consideration.
Responding to stakeholder questions of whether PJM should be granted the ability to mandate RMR contracts, Bowring said he believes that would be unnecessary if the RMR design ensures contracts provide appropriate revenues for generators contemplating deactivation. Bowring stated that compensation should be the same in both cases and cover all actual costs of being an RMR unit plus an incentive.
PJM Proposal Centers on Notification Deadlines
The PJM package focuses more heavily on the notification requirements for deactivation and leaves compensation changes for further stakeholder deliberation. The proposal groups deactivation requests into three classifications based on the energy that would be brought offline: Requests larger than 300 MW would be required to provide notification three years in advance of their desired deactivation date; units between 100 MW and 300 MW would require one year’s notice; and those under 100 MW would follow the status quo 90-day period.
The notification period could be curtailed under PJM’s proposal if the capacity auction for the delivery year in which the resource would go offline is after the notification deadline. In such cases, generators could submit a deactivation request before the deadline for them to offer into the BRA.
Generators also would be permitted to retire earlier if PJM finds no reliability violations from by taking the unit out of service.
FERC on April 19 conditionally accepted Oklahoma Gas and Electric’s (OG&E) proposed formula rate template revisions effective Jan. 1, 2024, as requested. The commission also directed OG&E to submit a compliance filing within 30 days of the order (ER24-722).
The commission found several errors and inconsistencies in OG&E’s proposed worksheets and formulas. It said the inclusion of populated plant balances, depreciation expense and revenue requirement for SPP allocation were not shown to be just and reasonable and ordered the company to remove the data in the compliance filing.
OG&E filed the revisions in December. It requested a waiver of the commission’s 60-day prior notice requirement so an effective date of Jan. 1, 2024, could be set. The company said allowing the proposed changes to take effect at the beginning of the rate year would avoid a midyear formula rate change and simplify the future calculation of the true-up adjustment.
Western Farmers Electric Cooperative, Arkansas Electric Cooperative Corp. and Oklahoma Municipal Power Authority, all OG&E customers, protested the filing. They argued the company did not provide sufficient information to back up its claim that the formula rate changes were “exclusively ministerial.”
FERC disagreed, finding the revisions are just and reasonable, pending OG&E’s compliance filing.
“We find that the revisions … are ministerial in nature and do not change the methodology by which the rate is calculated and will have no effect on rates,” the commission said. It noted the revisions will make the formula rate template easier for interested parties to review during the annual update process.
ERCOT last week told stakeholders that its staff are not supportive of modifications to the calculation of ERCOT contingency reserve service (ECRS) after recent changes resulted in lower quantities of the product this year.
ERCOT’s Nitika Mago told the Technical Advisory Committee on April 15 that last year’s annually required review of ECRS methodology, reduced 2024 quantities by an average of 442 MW in each hour. That is about a 21% reduction in the service, she said.
“We, as we do every year, will continue to see if there are any improvements that can be made,” Mago said. “We’ll continue to work on the analysis … but at least we’re getting ready for where we want to be.”
ERCOT has drafted a nodal protocol revision request (NPRR1224) creating a trigger allowing staff to manually release ECRS from dispatchable resources earlier than they did last summer. Stakeholders have requested additional analysis on the measure and have tabled it at the Protocol Revision Subcommittee, pushing off any likely decision until midsummer. Staff said that without the guidance on an “appropriately balanced ECRS deployment trigger,” they will release the product in a similar manner to last year.
“I think we do see this as a good step forward,” Jeff Billo, ERCOT’s director of operations planning, said of the NPRR. “We see other steps being necessary, but we see this as a good initial step forward.”
ECRS was deployed last June as ERCOT’s first new ancillary service in 20 years. The grid operator’s Independent Market Monitor said in December that ECRS has created artificial supply shortages producing “massive” inefficient market costs, totaling about $12.5 billion last year through November.
Staff promised last year to re-evaluate ECRS and share the results with stakeholders by April 30. They said a holistic review of the entire ancillary service methodology could soon be necessary. That same review would better address some of the IMM’s concerns, Mago said. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.)
Mark Dreyfus, representing a coalition of Texas cities, urged for a deeper review of the IMM’s $12.5 billion figure to determine whether ERCOT induced congestion by holding excess reserves out of the energy market.
“I’ve asked, and I think others asked way back when this issue first started: Let’s all drill down; this is so important,” Dreyfus said, noting the wholesale market’s “potentially unnecessary expense.”
“Let’s drill down and find out if that really happened or what were the circumstances. I don’t think we did that drill-down, and this conversation has suffered from that,” he said.
ERCOT has disputed the IMM’s analysis, calling the numbers “unknowable.” Billo said the long-term cost is really the cost of capacity being set aside.
ERCOT’s Jeff Billo (upper right) explains staff’s thoughts on ECRS. | ERCOT
“We all understand that $12.5 billion is not a real number,” he said. “I think the calculation was probably correct, but it’s not a real number or indication of what actual costs are. We don’t even know if it’s even the right magnitude of cost. That that’s an unknowable number, because we don’t know how bidding and offer behavior would have changed.
“We don’t know what capacity may have decided they didn’t want to be there because of that change. So, I think we need to focus more on the fundamentals of what do we need and what are the cost[s] from a capacity standpoint,” Billo said.
Michele Richmond, executive director for the Texas Competitive Power Advocates trade association, argued that there would have been behavioral changes “because when you change how something works within the market, that is just a natural result.”
“What we have seen is that ECRS has sent a signal to the market that investment in dispatchable generation is needed in ERCOT. Investment decisions are not based on what happened in the past; they’re based on what the expectations are for the future,” Richmond said. “I think we need to be really cautious that we don’t chill that investment or send a message that we want reliability, but it can’t cost anything, because that’s also not realistic. A balance needs to be struck. I think that making sure what we do is the right thing for the market — not just this summer and next summer, but in the long term — is really critical.”
ERCOT: Remand IBR Rule
ERCOT plans to recommend that the Board of Directors this week remand a controversial rule change to TAC, against stressing the risk to grid reliability, staff told members.
“We still have concerns about the reliability implications of [NOGRR245] endorsed by TAC,” Dan Woodfin, ERCOT’s vice president of system operations, told TAC.
Woodfin said staff will recommend that TAC address the reliability concerns and either modify stakeholders’ proposed language or explain how the NOGRR addresses ERCOT’s reliability issues.
The NOGRR is intended to align the grid operator’s rules with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers standard for IBRs interconnecting with the grid. Two IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed the Odessa Disturbances I and II, have added urgency to the measure’s eventual passage. (See NERC Repeats IBR Warnings After Second Odessa Event.)
Stakeholders have proposed software changes to fix the issues NERC and ERCOT have identified. They have said ERCOT’s proposals, if approved, “will implement the nation’s most aggressive ride-through performance requirements to date.”
TAC in March approved amended language that stakeholders pushed through despite ERCOT’s objections. Stakeholders said the language was “carefully crafted” to reach a solution balancing risk mitigation with “economic, technological and operational realities.” (See ERCOT Technical Advisory Committee Briefs: March 27, 2024.)
“We would like to see this matter be resolved and the ERCOT board endorse the TAC-recommended comments,” said Eric Goff, who has led the stakeholder group opposing staff’s recommendation. “We might be in opposition to further remand and delays in limitation of these renewable resources. This is affecting real-world investment decisions every day, and we would like to get this matter resolved as quickly as possible.”
“Working towards more consensus is always beneficial. If there is a remand, does this end up just becoming an appeal back to the board, or is there a path to further consensus or possibly strumming the ukulele singing ‘Kumbaya?’” Luminant’s Ned Bonskowski asked Woodfin. “We made a recommendation to the board, and the presumption was for a lot of us that there were going to be folks on both sides, and then the board would end up taking some action, and then there may be action further taken at the [Texas Public Utility] Commission level. I want to make sure that we’re moving forward in a way that will continue to sharpen the pencil, if it’s possible.”
“Part of the benefit of this remand will be to further flesh out all of the pros and cons of the different approaches on each of the many issues that we’re talking about,” Woodfin responded. “That will be in the record out in public, so that both the board and the commission will have all that in front of them and be able to see all the different moving parts as this goes forward.”
Goff said his group already has an “extensive and well developed record” addressing those questions and argued against further delays. A remand could push the NOGRR to the June or August board meetings. It will then still have to go before the PUC for final approval.
“The effective date for new resources could potentially be pushed even further, and we would really like to see this pass,” Goff said.
The board’s Reliability and Markets Committee will take up the NOGRR on April 22, and the full board will consider it the next day.
Key Date for RTC+B Project
Members endorsed a white paper detailing changes to the reliability unit commitment process necessary to co-optimizing energy and ancillary service procurements to meet forecasted load and ancillary service requirements.
The paper sets the guardrails for the Real-time Co-optimization plus Batteries (RTC+B) Task Force’s design work and its scope. The document has gone through three reviews without changes, said ERCOT’s Matt Mereness, the RTC+B’s chair.
“The white paper has dealt with the design elements we need to finish our design and begin building software. It sets the foundation that we will build from,” he said. “We don’t want to slow things down waiting to get the principles defined so the NPRR doesn’t get pulled in different directions other than this white paper.”
The white paper is the first of 20 issues the RTC+B team has identified and is addressing. Mereness said the task force is wrapping up its work on requirements and hopes to release a program timeline in September laying out the schedule for the remaining work. The project remains on track for delivery in 2026.
“At this point, 2026 is still the placeholder until told otherwise,” Mereness said.
ERCOT held the first of four technical workshops on the project April 19, sharing expected dispatch and data control changes. “These are really very technical workshops, which is why they have the word ‘technical’ in them,” Mereness said.
Hanson Rejoins Committee
National Grid’s Kevin Hanson has rejoined TAC in the independent power marketer segment. He received support from Pedernales Electric Cooperative’s Eric Blakey, who kiddingly said the “ever dependable” Hanson should be up for TAC’s Spirit Award.
“He has earned it,” said Blakey, chair of TAC’s Wholesale Market Subcommittee. “He’s currently chair of three working groups. We’re trying to take away one of his responsibilities, but he’s just done an amazing job stepping in.”
Hanson replaces Seth Cochran, who recently took a position with energy trader Vitol after 13 years at DC Energy. Cochran served on ERCOT’s board for five years (2016-2020).
$435M San Antonio Project OK’d
By unanimously approving its usual combo ballot, the committee endorsed ERCOT’s proposed $435 million San Antonio South Reliability II project addressing reliability issues south of the city.
The area has been plagued with significant congestion. The grid operator in February created four new generic transmission constraints in the area to limit power transfers in north-to-south and south-to-north directions.
The project will now go before the board for approval, as its price tag easily exceeded the $100 million threshold, requiring the directors’ approval.
ERCOT staff identified the project while studying a different proposal. ERCOT’s independent review found the project necessary under its and NERC’s planning criteria. Staff analyzed 15 options and shortlisted four before finding its preferred option.
The combo ballot also included NOGRR and Planning Guide changes (PGRR) that, if they go before the board and are approved, would:
NOGRR255: establish high-resolution data requirements.
PGRR112: set requirements for interconnecting entities to submit dynamic data models and for transmission service providers to submit final full interconnection studies for approval at least 30 business days before the quarterly stability assessment deadline.
A second combo ballot was conducted to allow for members’ abstention on two measures related to the use of electric service identifier IDs (ESI ID). The NPRR (NPRR1212) would clarify a distribution service provider’s obligation to provide an ESI ID for a resource site that consumes load other than wholesale storage load and is not behind a non-opt-in entity tie meter.
The cooperative segment abstained from the vote, which also included PGRR114, over complaints that the NPRR pre-empts the rights of co-ops and municipalities over access to their distribution systems.
In filings submitted to the Department of Public Utilities (DPU) on April 16, the Massachusetts Attorney General’s Office (AGO) and Department of Energy Resources (DOER) expressed concern about the climate effects of proposed utility supply contracts to keep the Everett Marine Terminal (EMT) LNG import facility operating until 2030.
Despite their concerns, the AGO and DOER did not recommend the DPU reject the utilities’ petitions, noting that the contracts may be needed to support the short-term reliability of the state’s gas distribution network. Instead, the AGO and DOER called on the DPU to make any approvals contingent on additional transparency and long-term planning requirements (DPU 24-25, 24-26, 24-27 and 24-28).
The contracts between four Massachusetts gas utilities and EMT owner Constellation are intended to keep the facility open through the winter of 2030. Everett’s main customer, Constellation’s Mystic Generating Station, is set to retire at the end of May of this year. (See Constellation Reaches Agreements to Keep Everett LNG Terminal Open.)
With Mystic’s impending closure, Constellation can void the contracts if the utilities do not gain final approval from the DPU by May 1. This has led to expedited regulatory proceedings, in which state agencies and environmental groups have voiced concerns about the agreements’ projected $946 million price tag, as well as their alignment with the state’s decarbonization mandates. (See Everett LNG Contracts Face Skepticism in DPU Proceedings.)
In initial briefs filed April 16, the AGO and DOER expanded on their cost and emissions concerns and recommended additional guardrails to ensure the agreements do not hinder the state’s emissions reduction efforts.
“While the companies claim that the agreements are GWSA [Global Warmings Solutions Act] compliant, they have not provided any specific analysis to support these claims,” wrote the DOER.
National Grid, one of the state’s two major gas utilities, projects its gas demand to increase by about 11% by 2030, and its agreement with Constellation would allow the company to buy increasing amounts of LNG over the course of the contract.
The company argued in its initial brief that its agreement is needed to address “a deficit in the company’s available peak day and peak season resources.”
“The proposed agreement will not trigger any additional demand for gas,” National Grid wrote. “Any changes in demand in the commonwealth are independent of this proposed agreement, and customers will have the same demand for energy regardless of whether this proposed agreement is completed.”
Given the potential for gas demand to increase by the end of the agreements, the AGO stressed the need for the utilities to plan to develop an “exit strategy” from their reliance on Everett.
“Since 2015, [National Grid subsidiary] Boston Gas has taken no overt actions to address its readily apparent dependence on EMT,” the AGO wrote. “The company’s appetite for EMT LNG is only forecasted to burgeon four-fold over the next six years.”
Similarly, the DOER argued that “if the department approves the agreements, it should only be a short-term bridge to ensure reliability and must include a pathway to obviate each company’s need for EMT by the end of the contract terms in 2030.”
Throughout the proceedings, climate advocates have voiced concerns that the timing of the agreements lines up with the in-service date of a major pipeline expansion proposal for the Northeast. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)
The DOER recommended the DPU require the gas utilities to detail plans to “eliminate their reliance on EMT” in their Climate Compliance Plans due in the spring of 2025. The DOER also urged the DPU to mandate annual reports on gas costs, volumes, and third-party sales associated with the agreements.
These provisions are “essential in safeguarding consumers against the possibility that the companies would continue to be dependent on EMT in six-years or petition the department for approval of gas infrastructure alternatives that run counter to the Future of Gas principles or GHG emissions reduction mandates,” the DOER wrote.
Meanwhile, the AGO recommended annual reports from the utilities on their efforts to eliminate reliance on Everett, as well as on whether the agreements have aligned with the state’s decarbonization laws and the DPU’s recent “Future of Gas” orders, which discourage additional investments in gas infrastructure. (See Massachusetts Moves to Limit New Gas Infrastructure.)
Without such requirements, “ratepayers will again helplessly succumb to petitions by these LDCs [local distribution companies] for ongoing LNG supply from Constellation because, currently, these LDCs have no plan, obligation or intention [to] end their dependence on EMT,” the AGO wrote.
