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November 19, 2024

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Report Looks at Root Causes of Electric Rate Hikes

A new report says residential electric rates have been rising at a pace less than inflation in most states since 2010 and that the clean energy transition is not driving the increase. 

Broadly, transmission and distribution costs are rising faster than inflation, and this is a driving factor behind electric rates increasing nationwide, the report says; more narrowly, wildfires, natural gas price volatility and investments in coal plants contributed to price hikes in certain markets. 

“Clean Energy Isn’t Driving Power Spikes” was announced July 9 by Energy Innovation Policy & Technology, an energy and climate change think tank working to support policy designs intended to reduce emissions. 

The issue of rising electric bills is real, Energy Innovation said in introducing the report, and it is a huge concern for many American families. 

But clean energy, which some opponents criticize for its cost, is not to blame, the organization concludes. In fact, some of the smallest electric rate increases have been in states with high rates of wind and solar generation, such as Iowa, Kansas, Oklahoma and New Mexico. 

In ERCOT, for example, the buildout of wind and solar is estimated to have reduced wholesale electricity costs by $31.5 billion between 2010 and 2022, $11 billion of that in 2022 alone. 

Since 2010, average residential electric rates and the U.S. Consumer Price Index both have increased about 40%, the report notes, but average bills have increased only 24%, because of reduced household energy use. Energy-efficiency measures and rising use of distributed resources such as rooftop solar are credited for this. 

California, with one of the most aggressive clean energy stances of any state, has seen substantial electricity rate increases in recent years. But the report blames wildfire-related investments such as vegetation management and grid investments, which have increased to 16% of the total consumer costs for the state’s three primary investor-owned utilities. 

The grids in Colorado, Hawaii, Oregon and Texas also have sustained damage from major wildfires. 

“As climate-related risks accelerate, the cost to electricity customers of mitigating these risks will be critical to address,” the report states. 

The volatile price of natural gas is identified as another contributing factor in some states, particularly Massachusetts, which drew 64% of its electricity from gas-fired generation in 2023, compared with 49% for ISO-NE as a whole. 

The report flags other factors linked by a common theme: A regulated, guaranteed rate of return incentivizes utilities to make large capital investments rather than operational investments or other options that might be more cost-effective for customers. 

The report notes, for example, that utilities are continuing to invest in aging coal plants to keep them running, taking on significant new debt in the process. 

The report cites data from RMI showing the average remaining plant balance increased from $560/kW of capacity to $745 from 2010 to 2020 for steam boiler power plants, a category that consists mainly of coal-fired facilities. These sunk costs (plus a regulated rate of return) are passed along to ratepayers. 

Transmission and distribution costs are increasing at nearly double the rate of inflation, the report says, because of utility investment in hardening and resilience. It suggests costs could be limited by maximizing the existing grid’s potential with grid-enhancing technologies and reconductoring existing transmission corridors. 

The report cites Edison Electric Institute data showing IOUs boosted their capital investment in transmission and distribution infrastructure 64% from 2016 to 2023, more than double the rate of inflation during the same period. EEI indicates that transmission and distribution costs rose from one-fifth to one-third of total electricity revenue requirements from 2010 to 2022. 

This capital investment has been across the board, including from utilities that serve areas with slower growth of emissions-free generation, the report said, suggesting again that the rise of renewables is not driving the spending. 

The report states that these cost pressures risk canceling out the potential savings offered by renewable energy, the cost of which is expected to decrease through 2030. 

It offers several suggestions: Utilities can adopt better planning processes, use competitive procurement processes, maximize the capacity of the existing grid, enhance regional cooperation, refinance coal debt, adopt fuel cost-sharing mechanisms and change their business models to incentivize energy efficiency for customers rather than incentivizing their own capital investments. 

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NYISO Stakeholders Question Draft CEII Protection Requirements

[EDITOR’S NOTE: A previous version of this article incorrectly reported that the manual updates are being proposed NYISO. They are in fact being proposed by transmission owners.]

The NYISO Transmission Planning Advisory Subcommittee on July 9 criticized a transmission owner proposal to include Critical Energy/Electricity Infrastructure Information (CEII) protection requirements in the ISO’s manuals over what they described as confusing wording and inconsistent requirements. 

The TOs are concerned that with the “explosion” of generator interconnection requests, there is a gap in the CEII protection requirements. 

“There are FERC CEII protection rules, but they apply to information submitted to or generated by FERC; protections do not apply to information exchanged at the ISO level,” said William Derasmo, a partner at Troutman Pepper who presented the updates on behalf of the TOs. “The idea is to try to put something in place to fill that gap.” 

Derasmo explained that the updates would be followed by conforming tariff revisions. He cited a warning from the FBI that renewable energy generation could pose additional cybersecurity risks. (See FBI Warns Power Sector of IBR Cyber Vulnerabilities.) 

“This topic is not going away,” Derasmo said. “It’s a problem that is here, and we can’t wish it away.” 

The proposed revisions would require developers of generation or transmission facilities, their consultants or any nongovernmental organizations requesting CEII from NYISO to:  

    • provide NYISO and the transmission owner with a list of any countries outside the U.S. and Canada in which they operate; 
    • obtain cybersecurity risk insurance in coverage amounts of $5 million; 
    • establish a chain of custody, policies and process to securely handle and store CEII; 
    • not engage with entities owned by, controlled by or subject to the jurisdiction of “foreign adversaries”; 
    • engage in background screenings and security training for personnel accessing CEII; 
    • provide for secure deletion of CEII from systems; and 
    • report cybersecurity incidents to the NYISO and the TO within 48 hours. 

Stakeholders seemed confused that the draft updates used multiple overlapping definitions for “critical energy infrastructure,” “critical electricity infrastructure” and “critical infrastructure.” One stakeholder called it “overkill and unnecessary.” 

“We don’t need to parse it between ‘critical electric infrastructure’ and ‘critical infrastructure,’” they said. “You’re adding an unnecessary complication.” 

Others expressed confusion that the manual updates were being proposed without the accompanying tariff revisions. Typically tariff revisions are approved by FERC first before manual updates to define the scope of revision. 

“I guess I’m really struggling with how to do it this way,” the stakeholder said. “I think you’re maybe unnecessarily causing some confusion, if not complication, here. In any event, we’re not going to have any helpful guidance until you’re proposing the tariff first.” 

One stakeholder raised the issue of “special treatment” of the TOs. The current draft of the rules would require that recipients of CEII inform NYISO and TOs of security incidents and foreign business dealings, but they would not require the ISO or TO to inform recipients of cybersecurity breaches or similar multinational dealings. 

Another stakeholder raised the point that some people who have access to CEII do not represent or work for multinational corporations with large budgets. Requiring $5 million in cybersecurity risk insurance likely would deny people and firms of this kind access to CEII. They suggested having a MyNYISO account would be enough to trigger the insurance requirement.

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ERCOT Hires New VP of Public Affairs

ERCOT announced on July 15 that it has named former American Electric Power executive Gilbert Hughes as its new vice president of public affairs, where he will coordinate communications and government affairs.

The grid operator said Hughes has four decades of experience in the electric utility industry, with a focus on Texas public policy. He served as vice president of external affairs for AEP, where he also had leadership positions in regulatory services, governmental affairs and community relations.

Hughes replaces Robert Black, who will serve as executive adviser during a transition period that begins immediately. Hughes will be responsible for the organization’s external communications, government affairs and customer support.

ERCOT CEO Pablo Vegas said in a statement that a key component of meeting the state’s reliability needs will be transparent communications with the public and close collaboration with state leaders and agencies, market participants and lawmakers.

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Pathways Participants See ‘Pivotal’ Chance to Build New Kind of RTO

The West faces a “pivotal” opportunity to develop a fresh approach to managing its electricity markets, one that could update RTO governance to better accommodate the public policy and new technology driving changes in the sector.  

That was the view shared by some stakeholders participating in a July 12 workshop hosted by the West-Wide Governance Pathways Initiative. It was the first in a series of four virtual meetings to explore how a proposed Western “regional organization” (RO) would structure its stakeholder processes after assuming oversight for CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market. 

The workshops, which are being facilitated by nonprofit Gridworks, will provide a comparative examination of stakeholder processes for six RTOs and ISOs — including CAISO and SPP — and the Western Power Pool’s Western Resource Adequacy Program (WRAP) to identify the best practices to be adopted by the new Western RO. 

“I think we need a bit of a reset here, because in my mind, my perception of what we’re doing with the Pathways process is to change the RTO governance model,” Fred Heutte, senior policy analyst at the NW Energy Coalition (NWEC) said during the meeting. 

The changes should go beyond procedural matters, Heutte said, “to reflect a new approach that combines market operations, grid dispatch and public policy, as represented primarily in state policy across all the diversity of all the different state policies across all the diverse states.” 

Given that emphasis, Heutte cautioned against borrowing too heavily from processes in existing RTOs. 

“The amount of friction and controversy in the East because public policy is not aligned with market design and operation — it’s been a problem for a long time, [and] it’s a growing increasingly more difficult problem,” he said. 

Mona Tierney-Lloyd, head of regulatory and institutional affairs at Enel North America, “endorsed” Heutte’s comments and added that Pathways is in a “unique position relative to every other organized market” to take a “fresh view” on governance.

She said her experience participating in “several markets” across the U.S. indicates that interests representing distributed resources have been marginalized and “relegated to some sub working group that isn’t given the same kind of attention or weight … as other member classes.” 

“We’re also at this really pivotal time of looking at new technologies coming online and really changing what is [recognized as] an electricity resource, looking at the distributed side of the resource equation more fully,” Tierney-Lloyd said, calling it “an opportunity to take a more modern look at the way the electricity system is changing and trying to incorporate that view into a stakeholder process.” 

Brian Turner, Advanced Energy United’s director of regulatory engagement in the West, took up that theme. 

“We have the opportunity to create something new that takes the best of what is and perhaps new ideas as well. Coming from a perspective of an organization that represents a lot of the new technologies that are increasingly important in the energy system, I think that that’s a perspective that is shared with nontraditional voices that have the opportunity to be represented here,” Turner said. 

‘Fair Process’

Some workshop participants offered a more positive take on existing stakeholder processes in RTOs, particularly in the East.  

Cathleen Colbert, senior director of Western markets policy at Vistra, said experience working in both CAISO and PJM helped her develop a “nuanced view” of the grid operators’ different approaches to stakeholder process. Colbert said she found CAISO’s staff-driven process suffers from an “asymmetry” of information and access, and while the ISO provides any stakeholder the opportunity to provide input, it has no obligation to consider that input.  

“Because it doesn’t have any incentive to really engage stakeholders, because they don’t need stakeholder support to get anything through their processes and environments … there’s no incentive for them to truly be involved with their stakeholders unless you have a special relationship, unless you have figured out how to build a rapport and a relationship where you get offline access,” she said. 

In contrast, Colbert finds the PJM stakeholder process, with its committee structure, to be “very open … in practice.” 

“I don’t know if it’s the voting, but the PJM stakeholder process was incredibly collaborative and inclusive, versus the CAISO one, [which] is very, very hard for stakeholders to actually participate in meaningfully,” she said. 

Heutte said CAISO’s stakeholder process is not perfect but has provided him “a relatively easy” way to submit his input on issues, while he thinks SPP’s “well structured” approach can be “very isolating.”   

“If you’re not a formal member of a committee, then you’re really not treated as others are,” he said. “And it’s not just about the voting; it’s also about who gets recognized for speaking; it’s about the weight that your comments get, if you’re not a formal member of that group.”  

Ryan Millard, senior director of West region regulatory and political affairs at NextEra Energy Resources, said “having a discussion at some point about the nuances of each process will be valuable, because maybe one process is more responsive in practice than another.” 

“I think having some discussion with folks that are familiar with PJM, SPP and other RTOs can kind of marry up the practical realities of how this structure actually works, and how responsive it is,” Millard said. 

Scott Miller, executive director of the Western Power Trading Forum, noted that some stakeholders see efficiencies in the “top-down” approach of CAISO’s stakeholder process, while others see benefit to the “bottom-up” approach they’ve experienced in SPP’s Markets+ and in some Eastern RTOs. 

“The struggle, I think, is how we can get something that’s very efficient, but one in which people feel it’s transparent, they’ve got equal access, and it’s a fair process,” Miller said. 

Huette expanded on that idea. 

“It’s not just the challenge of do we pick a voting-oriented approach or a nonvoting-oriented approach, but rather, what is the key challenge is to make sure that we have synchronized the stakeholder engagement process to the overall direction that we’re trying to establish with this new approach to governance,” he said. 

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MISO Monitor Spotlights Congestion Fixes, Market Mismatches in 2023

MISO’s Independent Market Monitor debuted six new market recommendations this year as part of his annual State of the Market report, released last month. 

Two of the recommendations this year stem from MISO’s ongoing struggle with expensive transmission congestion. Independent Market Monitor David Patton said the RTO’s congestion management would improve if it could decommit resources that were committed in the day-ahead market. 

Addressing the MISO Board of Directors’ Markets Committee in a July 11 teleconference, Patton said the RTO doesn’t have a process to ask day-ahead committed resources to stand down, even when they contribute to “severe congestion.” MISO could likely save several million dollars in congestion costs annually if it had a process for requesting resources to abandon their day-ahead obligations, he said. 

MISO should further develop procedures outlining when it’s appropriate for its operators to derate transmission constraints to manage congestion, Patton recommended. Operators have inconsistently applied deratings, and those out-of-market actions have produced an average of $200 million in congestion costs for the past two years. He said MISO doesn’t have a “clear procedure” that indicates when its operators should implement deratings. 

“While it’s important to derate transmission, we should only derate the transmission when it’s necessary,” Patton said. 

Outage Details

Beyond that, Patton recommended that MISO compel generation owners to fill out the reasons behind outages or outage extensions in the ticketing system the RTO uses to track scheduling. 

Patton said MISO should be requiring “clear reasons” behind outages and extensions. He said better explanations will help its understanding of the nature of outages. 

“In a lot of cases, the reason for the outage is unclear or left blank,” Patton told the board. 

Patton said descriptions have become more important because now outages can count against resources’ capacity accreditation. “Accurate outage reporting informs operations — and monitoring — in the short run and is critical for capacity accreditation in the long run.” 

Patton: More Sloped Curves

On the capacity auction front, Patton recommended that MISO use demand curves at the zonal level to better model demand in its local resource zones and produce more accurate local clearing requirements.  

Patton said he was puzzled that MISO didn’t develop a plan for zonal-level curves alongside its successful bid with FERC to use sloped demand curves in the auction at the subregional and footprint-wide level. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.) 

Without the use of zonal curves, zones that bind on either their export or import limits in the capacity auction could experience clearing prices that have little to do with reliability value, he said. 

Patton said the capacity auction this year cleared “inefficiently high shortage pricing” in Missouri’s Zone 5, which hit $720/MW-day in spring and fall. Missouri’s expected unserved energy from the shortage isn’t as risky as the clearing prices suggest, he argued. 

Nevertheless, Patton called it an “amazing step in the right direction that we now have” sloped demand curves to value capacity. 

Market Recommendations

Patton said MISO could improve market performance if it aligned its definition of aggregate pricing nodes between its financial transmission rights market and real-time and day-ahead markets. 

Currently, the aggregate pricing hubs in the FTR market change with new load. On the day-ahead and real-time markets side, load additions do not influence the aggregation of pricing nodes. Patton said MISO’s influx of large, uneven loads has caused aggregate pricing nodes in the FTR market and day-ahead and real-time markets to vary “substantially.” He recommended that MISO eliminate discrepancies in aggregation definitions between the markets. 

“You would like these aggregation zones to be identical. But in a number of cases, they’re not,” Patton said. 

Multiplying data centers and cryptocurrency mining facilities will exacerbate the problem, he added. Patton called his recommendation “complicated but fairly important.” 

MISO should begin looking into studying loads like it does interconnecting generators in the queue, Patton said, because large loads can also affect the transmission system and necessitate upgrades. 

“Some of these large loads create comparable problems to generation that’s interconnecting,” he said. 

Patton also said this year he revived an old recommendation to enforce requirements for MISO’s 30-minute reserve products. He explained that MISO often commits resources outside of the market to solve voltage and local reliability issues in load pockets. He said in some cases, shortages that weren’t priced have occurred in load pockets. 

Those situations would be best handled by allowing the market to naturally summon short-term reserves to maintain reliability, he said. The problem is most pronounced in East Texas, where MISO has come close to shedding load. Patton said that if MISO honored a requirement to use reserves instead of out-of-market actions, generation owners might be motivated to build more generation or delay retirements. 

MISO is reviewing the Monitor’s recommendations and will deliver a public reaction to the State of the Market report in October. 

At the end of the Markets Committee teleconference, Clean Grid Alliance’s David Sapper criticized MISO’s timeline for reviewing the State of the Market report for not setting aside enough time for stakeholders to discuss the merits of the Monitor’s recommendations. 

Sapper said stakeholders have only minimal time at a single Market Subcommittee meeting to react to the recommendations and aren’t allowed in on the process of MISO determining which recommendations should be taken up and which can be disregarded or delayed. 

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Counterflow: Microgrid Poster Child

Every few years I return to the subject of microgrids — just to beseech everyone to please stop the insanity.

A case in point is the recent hoopla over the completion of the Bronzeville microgrid in Chicago with the usual cheerleading by proud politicians, utility officials, public interest group representatives and media publicists, with nary a Cassandra in sight.

Cutting to the Chase

Steve Huntoon |

I have explained theory before, so let me cut to practice. This microgrid cost $30 million in order to provide 6,050 kW of backup generation to the Bronzeville neighborhood in the event of a widespread system outage in Chicago. That is $4,960/kW.

A typical Generac home generator provides 26 kW at an installed cost of $10,500. That is $404/kW.

Yes, you read that right. This microgrid is 12 times more expensive per kilowatt than a bunch of Generac home generators providing equivalent backup service. Yikes.

A Green Justification?

Nope. The microgrid’s generation is 750 kW of solar panels, 500 kW of four-hour batteries and 4,800 kW of natural gas-fired generators.

Cost-benefit Analysis

Power outages average 43 minutes per year in Bronzeville (see page 66), i.e., reliability is 99.99%. A value of lost load analysis showed that the benefit of eliminating these outages (assuming the microgrid would do that) aggregates to about $100,000 per year (again, see page 66).

The microgrid costs $5,300,000 per year (see Page 63). So, the cost of the microgrid is about 50 times the benefit value of the microgrid. Yikes.

Cost per Customer

The microgrid costs a staggering $388 per customer served per month (see page 55), four times the average customer’s monthly electric bill of $93. Of course, the microgrid is paid for with Other People’s Money (other Commonwealth Edison customers), but the key point is that if this microgrid were replicated across the ComEd system, then everyone’s monthly bill would go up about 500%. Yikes.

Critical Service Protection

It’s been highlighted by ComEd and others that the Chicago Police Department’s headquarters is within the microgrid service area — but the police HQ already had backup generation (see Page 66), as of course it should. Yikes.

OK, I’ll stop the microgrid rant.

P.S. An update to my fusion column: The gigantic European ITER project announced that “energy-producing fusion reactions — the goal of the project — won’t come until 2039, and only in short bursts,” and that “fusion cannot arrive in time to solve the problems our planet faces today.”

Here’s a reminder that we could start cooling the planet tomorrow with some sand in the stratosphere. Just sayin’.

P.P.S. On the happy talk front through troubled times, this is the 50th anniversary of the writing of “(What’s So Funny ’Bout) Peace, Love and Understanding” by Nick Lowe, the 45th anniversary of Elvis Costello’s great cover and the 20th anniversary of the superstar cover here. If you made it to the end of this column, thank you, and please turn it up to 11.

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

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MISO to Limit Use of $10K VOLL During Long-duration Outages

CARMEL, Ind. — MISO said stakeholders have convinced it to design an off switch on its proposed $10,000/MWh value of lost load to use during extended load-shedding events.  

Speaking at a July 9 Market Subcommittee meeting, MISO’s Chuck Hansen said the RTO will work a “circuit breaker” into its new VOLL for load shedding that lasts longer than four hours.  

MISO early this year proposed using a $10,000/MWh value of lost load, nearly three times the amount of its current $3,500/MWh. (See MISO Wants $10K VOLL, a Nearly Threefold Increase.)  

Hansen said MISO foresees using VOLL for “a few intervals, maybe up to a few hours” at a time, but not over several hours and days. He said MISO is considering placing a three-step maximum value on VOLL pricing during extended periods of load shedding.  

MISO said it plans to cut VOLL in half to $5,000/MWh after four hours of load-shedding during a maximum generation emergency. When active load-shedding measures aren’t lifted in time for MISO’s 10:30 a.m. ET day-ahead market closing, MISO will extend the lower, $5,000/MWh VOLL into the next operating day. For load-shedding that continues into a second day and beyond, MISO will slash its day-ahead and real-time VOLL to $2,000/MWh for successive operating days.  

“It’s something the market’s not seen. But if we get to that point, we believe it’s best to limit pricing on extreme, multiday events,” Hansen said. “We don’t anticipate such an event, but it’s prudent to prepare for such an event.”  

Hansen said the $2,000/MWh step can continue indefinitely until the maximum generation emergency is terminated and normal operations resume. He said the RTO landed on the $2,000/MWh amount partly because it’s the hard cap on incremental energy offers in FERC’s Order 831.  

Hansen said while MISO wants to set prices to incent responses, there’s a point where “high prices aren’t enhancing reliability and are creating a high financial risk to participants.” He said it’s not appropriate to have “indefinite” pricing at $10,000/MWh when it’s not helping resolve a situation.  

Stakeholders months ago voiced apprehension over the potential for prolonged, prohibitively high prices and the cost exposure to customers under MISO’s proposed higher VOLL.  

The Organization of MISO States “strongly” encouraged MISO to include a circuit breaker mechanism in its VOLL design. Entergy also said there’s “no disagreement that [a prolonged scarcity event] could occur and cause severe financial distress and harm.”  

Hansen said the RTO is hoping to present “straightforward” tariff language at the August Market Subcommittee meeting and its proposed VOLL boundaries sometime in the fall.  

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MISO: Sloped Curve Would Have Raised 2024/25 Capacity Auction Prices

CARMEL, Ind. — As it gears up to run its first auctions using sloped demand curves, MISO last week said prices and procurement would have risen had it used them in this year’s auctions.

Over summer, several local resource zones would have experienced a six-fold jump in clearing prices, the grid operator revealed at the Resource Adequacy Subcommittee’s meeting July 10.

MISO used prototype curves that it presented to stakeholders last year to hypothetically redetermine clearing prices and additional supply procurement for the 2024/25 capacity auction. In reality, seasonal sloped demand curves will differ because the RTO will periodically update calculations that draw on historical operating costs of generators in the footprint.

MISO will have sloped demand curves in play for the 2025/26 planning year auctions after FERC last month allowed the RTO to use them in place of the vertical demand curve it had been using since 2011. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.)

For zones 1-4, 6 and 7, clearing prices this year would have jumped from $30/MW-day to $197/MW-day in summer, from $15 to $39 in fall and from 75 cents to $2.40 in winter. In the same zones, spring prices would have dropped from $34 to $32.

MISO South clearing prices would have increased less dramatically in summer, from $30/MW-day to $80/MW-day, but it followed the other zonal prices in the other seasons. MISO’s reenactment of the 2024/25 auction showed the Midwest-to-South transfer constraint binding on its limit, causing the lower summer prices between South and Midwest.

For Missouri’s Zone 5, which this year experienced an 872-MW shortage in fall and a 196-MW deficit in spring, prices would have tracked other Midwest zones in summer and winter but risen from the $720/MW-day cost of new entry (CONE) price limit to $758 in fall and $751 in spring. (See Missouri Zone Comes up Short in MISO’s 2nd Seasonal Capacity Auction, Prices Surpass $700/MW-day.)

MISO did not alter capacity offers made in the 2024/25 auction for its reenactment.

The sloped demand curve design paired with MISO’s new seasonal auctions allows clearing prices to go as high as four times the CONE. The curve is meant to value capacity beyond what’s strictly necessary to meet the one-day-in-10-years loss-of-load expectation.

Alongside the higher prices, an indicative rerun of the 2024/25 auctions showed that with a sloped demand curve, MISO cleared capacity beyond its reliability targets, except in spring: 4 GW more in summer; over 4 GW more in fall; and 3 GW more in winter.

However, spring cleared nearly 127 GW, lower than the nearly 128-GW target. But MISO said the prototype demand curves show that shortages will likely need to be more pronounced in the future to trigger CONE pricing.

MISO staff did not venture a guess as to whether Zone 5 still would have returned a shortage had the sloped demand curve been used in 2024/25. Neil Shah, senior manager of market design, said there were too many factors at play in Zone 5 to say for certain what would have transpired.

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Renewable Group Asks MISO Community to Consider HVDC Capacity

CARMEL, Ind. — A renewable energy trade group has asked MISO to put more thought into how HVDC transmission’s ability to infuse the footprint with more external capacity could influence MISO’s capacity auctions.

The Southern Renewable Energy Association approached MISO and stakeholders at the July 10 Resource Adequacy Subcommittee, asking them to consider that HVDC lines can deposit far-flung generation into MISO’s local resource zones.

“In a lot of ways, this conversation is overdue. … We should be talking more about this,” SREA Transmission Director Andy Kowalczyk said. He said MISO promised more discussion on supply facilitated by HVDC in a FERC docket in 2018, but so far MISO hasn’t engaged stakeholders (ER18-2363).

Kowalczyk said HVDC-enabled capacity in the Planning Resource Auction raises questions over how those resources will clear, be priced and accredited.

He said Grain Belt Express stands to deliver substantial wind energy from Kansas and asked stakeholders to consider if generation carried by HVDC should clear at the zonal price in MISO where the line terminates.

Kowalczyk also said it might make sense for MISO to model increased capability of resources utilizing an HVDC line in its loss of load expectation studies.

He added that he didn’t want to “overhype” HVDC’s capabilities, but said the lines stand to deliver power during critical times. He said an HVDC system could impact the RTO’s reliability planning.

“There aren’t any downsides to exploring this issue and resolving a policy gap,” Kowalczyk said.

The Resource Adequacy Subcommittee agreed by consent to take up the issue at future meetings.

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MISO Proposes to Split LMR Participation, Accreditation into Fast/Slow Groups

CARMEL, Ind. — MISO said it likely will split load-modifying resource participation into two options in an effort to line up their true contributions with accreditation.

MISO’s Joshua Schabla said the RTO is considering “flexible and rigid” capacity-only demand response participation options for LMRs.

Stakeholders learned at a July 10 Resource Adequacy Subcommittee (RASC) that MISO wants to introduce a category for LMRs that take longer than 30 minutes to react. Those LMRs would be tasked with responding to the first step of a NERC Energy Emergency Alert and their accreditation would be based on response times and availability.

The second class of LMRs would commit to be available for deployment in 30 minutes or less for the second step of a NERC Energy Emergency Alert (EEA 2). Those resources would have to be able to respond to an unlimited number of EEA 2 events. Currently, LMRs must respond up to five times apiece in summer and winter months and up three times in spring and fall, and MISO must reach an EEA 2 to access LMRs.

Under the pair of options, LMRs’ must-offer requirement would kick in during MISO’s capacity advisories or emergency declaration hours. The first set of LMRs would submit their real-time availability through MISO’s market user interface for MISO dispatch; the second set of LMRs would continue to communicate availability through MISO’s demand-side response interface for scheduling instructions.

MISO said it may rename one of the two categories to something other than LMR. The grid operator warned stakeholders in May that it needs to reassess its LMR concept and requirements. (See MISO Says Risk Driving It to LMR Reorganization, Stronger Requirements.)

MISO first proposed in spring that all LMRs should be available in 30 minutes or less, with those unable to meet those response times relegated to participating as demand response resources. It’s since walked back that proposal after stakeholder criticism. Multiple stakeholders argued that the 30-minute minimum was too drastic and that MISO was trying to treat LMRs — with characteristics that vary wildly — the same.

Schabla said one lenient and one rigorous LMR class should allow most of MISO’s 12 GW of LMRs to continue participation in MISO with a more honest stock of their abilities.

“We want to be mindful — compassionate, frankly — about what these resources are capable of,” he said. “There still is value to resources that take longer to respond.”

MISO hasn’t yet landed on a maximum response time it will accept from the slower class of LMRs. Currently, MISO LMRs have a requirement to be ready in six hours or less.

Schabla said the type of participation LMRs opt for and how quickly they can respond will set the value of their capacity accreditation, with LMRs participating in the second category naturally receiving the most capacity value. However, he said MISO has yet to work out “firm numbers” behind accreditation calculations and will release more detail on the methodology in August.

Bill Booth, consultant to the Mississippi Public Service Commission, asked if MISO had to upend its current LMR construct at all and if it could instead simply create a “super LMR” category for the fastest resources.

Schabla said the second participation option can be thought of as the “super LMR.”

Sustainable FERC Project’s Natalie McIntire thanked MISO for incorporating nuance into LMR accreditation and allowing resources the chance to help the system based on their ability.

Other stakeholders weren’t as convinced.

Executive Director of Market Innovation Zak Joundi asked stakeholders to be open-minded about MISO’s proposal, though they might not like it. He said MISO is trying to capture the value of LMRs based on how they perform.

“We are trying to better utilize this asset class. Period,” Joundi said. He said when the LMR class was created, MISO had a large surplus and virtually never used them. Now, Joundi said an increasingly intermittent fleet and volatile weather means MISO and stakeholders should rethink LMRs as something MISO needs to tap into more often.

“Going forward this is 12 GW that we are likely to leverage, and we need to have the visibility and the confidence that we can utilize them,” Joundi said.

MISO has said its historical data shows actual LMR availability always is lower when compared to the cleared LMR capacity in Planning Resource Auctions. It also has said some LMRs clear auctions without ever making themselves available.

WEC Energy Group’s Chris Plante said his control room operators currently “don’t have a full grasp of what they’re supposed to be reporting and when.” He said MISO isn’t clear about what it expects of LMRs, and it should address that first before reinventing LMR participation.

Plante called MISO’s proposal a “complete divergence of what LMRs have been.”

Joundi reminded stakeholders the LMR accreditation isn’t set to go live until the 2028/29 planning year. He said MISO is working in parallel to be clearer about what it expects of its LMRs.

“MISO seems to be proposing solutions before it understands what the problems really are. That’s unfortunate,” WPPI Energy’s Todd Komplin said.

Komplin introduced a motion and vote in the RASC urging MISO to better investigate the gulf it reports between LMRs’ reported availability and the capacity LMRs clear in auctions. He also asked the RTO to investigate why its control room operators are “effectively using LMRs to address capacity emergencies.”

MISO market participants will vote via email on the RASC motion over the next week.

Komplin said MISO is not explaining why a six-hour lead time on LMRs no longer is sufficient and why it needs LMRs readied in as little as 30 minutes.

Joundi said the motion likely would result in MISO examining what it can do to support LMR contribution. But he qualified that research would occur simultaneously alongside the new participation and accreditation proposal for LMRs.