Search
`
November 5, 2024

Posted on

ACP Asks FERC for Capacity Accreditation Technical Conference

The American Clean Power Association (ACP) asked FERC last week to hold a technical conference on capacity accreditation, arguing that the commission’s rules need to keep pace with technology and the evolving grid.

The petition filed Aug. 22 is not ACP’s first attempt to get FERC to address the issue, with the commission in February rejecting a complaint the organization filed against ISO-NE alleging its capacity accreditation rules failed to account for natural gas’ performance issues in the winter. (See FERC Denies RENEW Northeast Complaint.)

“Grid operators and FERC have been addressing these issues primarily on a regional basis, but the clean energy industry believes it’s time for FERC to look at many of these issues more broadly,” ACP Vice President of Markets and Transmission Carrie Zalewski said in a statement. “Today’s petition provides an opportunity for FERC to hold open discussions that can identify the best possible capacity accreditation methods so that the reliability contributions of all resources — including renewables and storage — can be accurately accounted for.”

A central pillar of system planning and electricity market design, capacity accreditation is one of the most critical areas FERC needs to address on a holistic basis, ACP argued. Some regional differences are to be expected, but ACP said the methods should share common goals and general approaches.

Capacity accreditation methods vary widely, and they are often applied inconsistently within and across resource types, making it more difficult to accurately assess national and regional resource adequacy and to make efficient investment decisions, the organization said. With different regions taking on the issue on their own, and FERC’s ex parte rules, the commission has not been able to take a broader look at the issue, which could help its decisions.

“That constraint will continue to bind policy development going forward, because many regions are actively considering changes to their resource accreditation processes as the resource mix continues to evolve,” ACP said.

A technical conference on capacity accreditation would develop a record to foster informed decision-making on the various initiatives likely to arise over the next several years, it said. And a universal framework would not stop the regions from moving ahead on their own.

The industry has different ways of accrediting capacity, including effective load-carrying capability (ELCC), marginal reliability improvement (MRI) and measuring a resource’s output during certain peak load intervals.

All of the capacity accreditation techniques include four fundamental design characteristics.

The technique can use a deterministic metric (reflective of only one set of conditions) or probabilistic (a value based on analytical simulations across hundreds or thousands of potential conditions).

Grid operators can also use a prospective/forward-looking assessment, a retrospective assessment based on past performance or a combination that uses a prospective method at first, then adjusts retrospectively based on performance.

The third design characteristic is whether to use an average contribution, in which all resources of the same technology count the same, or a marginal contribution, in which individual resources are measured in comparison to others using the same technology.

The fourth design element is whether fuel assurance is required for individual units or handled probabilistically by unit, unit type or systemwide.

“Because capacity accreditation is increasingly being acknowledged as a critical aspect of our energy system, significant attention is now being focused on this topic in various ISO/RTO stakeholder working groups,” the petition said. “However, at present, there is no focused, coordinated discussion occurring at the federal level, either at the commission or at the North American Electric Reliability Corp.”

The industry would benefit greatly from a universal discussion around the issue, with a technical conference educating stakeholders, allowing for open discussion with FERC staff and hopefully helping to foster consensus and consistency among regions, ACP said.

Posted on

ERCOT Technical Advisory Committee Briefs: Aug. 22, 2023

ERCOT stakeholders last week endorsed the charter and leadership for a task force that will report directly to the Technical Advisory Committee and provide recommendations on real-time co-optimization (RTC) and energy storage resources’ (ESRs) state of charge (SOC).

The Real-time Co-optimization + Batteries Task Force (RTC+B) will coordinate and review ERCOT and market activities to mitigate risks and support the RTC+B program’s implementation. Its responsibilities include managing timelines, providing a forum for analysis or policy decisions and reviewing nodal protocol revision requests (NPRRs).

Battery issues unrelated to RTC are out of scope. However, ERCOT will make time available after the group’s meetings should stakeholders want to continue to explore storage.

ERCOT’s Matt Mereness, who has volunteered to chair the task force, said he simply forklifted the charter from the previous stakeholder group that produced NPRRs and other rule changes to guide staff’s implementation of RTC.

“We said, ‘What does it look like to remove implementation risk?’ And so structurally, everything is the same,” he said during TAC’s Aug. 22 meeting.

Mereness also chaired the RTC Task Force that took a first look at the market tool that procures energy and ancillary services every five minutes. Using the approved NPRRs, the new group will develop business requirements for RTC and single-model batteries and review a SOC concept for batteries. (See “RTC Stakeholder Group to Form,” ERCOT Technical Advisory Committee Briefs: July 25, 2023.)

Key policy issues include parameters for ancillary service proxy offers, triggers for initiating off-cycle security-constrained economic dispatch (SCED) executions, allowing real-time updates to current market offers and in the future with RTC, and evaluating a framework for periodic analysis comparing RTC and the ORDC.

A vendor will start developing the SOC for batteries involved in RTC in January. The task force plans to deliver its completed work in 2026.

Faced with a December target to gain ERCOT Board of Directors approval of its work, the RTC+B group will move quickly. It has already scheduled a Sept. 8 meeting to nominate a vice chair and review the RTC task force’s previous work and the sequence of activities necessary for implementation.

“We do think it’s important that we get real-time co-optimization done as quickly as possible, given that it’s planned to save enormous amounts of money for the market when it’s implemented,” Mereness said.

The RTC Task Force was disbanded at the end of 2020 following the initiative’s completion. The disastrous and deadly February 2021 winter storm and the ensuing drain on staff resources postponed the initiative until recently.

SOC Transparency

In a split vote, TAC approved one of two ERCOT revision requests (NPRR1186) designed to improve the grid operator’s awareness, accounting and monitoring of an ESR’s SOC before the RTC+B project goes live.

As approved by the Protocol Revisions Subcommittee (PRS) earlier in August, the measure adds definitions and telemetry requirements related to SOC information that date back to 2018 and introduces a requirement that qualified scheduling entities (QSEs) representing an ESR telemeter the next operating hour’s ancillary service (AS) resource responsibility. It also specifies that QSEs are expected to manage the SOC to ensure that each ESR has sufficient energy to meet its AS responsibilities and that the day-ahead market (DAM) process should begin to respect the AS award limits for ESRs based on duration requirements.

ERCOT has held three workshops on NPRR1186, and it has been the subject of conversation during two PRS meetings. Still, it was discussed for 90 minutes before TAC voted on it.

Storage developers Eolian, Plus Power and Jupiter Power filed comments opposing it, saying it would disincentivize longer-duration ESRs that could diversify energy supply and help manage the growing evening ramp’s variability because “administratively applied withholding requirements” will limit the resources’ ability to provide multihour AS products.

The joint commenters suggested modifying the measure by adding a variable to the calculation of AS, eliminating the ESRs’ obligation to stop discharging energy while deployed to provide certain AS, and ensuring compliance obligations address ERCOT’s SOC monitoring goals and mitigate unintended consequences.

After TAC endorsed the NPRR in a 22-3 vote with five abstentions — with the consumer and retail electric provider segments providing the pushback — Eolian said it would appeal the approval to the ERCOT board when it meets Thursday and request ERCOT be directed to resubmit new NPRRs to separate out system coding issues from the determination of SOC parameters and related compliance obligations.

Eolian said the board should give market participants a chance to work with ERCOT to define “actual reliability issues” and determine how to solve them without creating dangerous unintended consequences.

“Failure to do so will certainly create a chilling effect in the ERCOT market by discouraging the development and construction of longer-duration ESRs in ERCOT, which will be to the detriment of grid resiliency and reliability, as well as all ERCOT consumers,” the developer wrote.

Staff pointed out that AS market products work as mechanisms that maintain reliability, not as standalone economic products, and that ESRs create a duration issue. They agreed to review how other grid operators are addressing duration issues.

“There needs to be some perspective on what’s on the system now versus what was on the system 10 years ago,” said ERCOT’s Kenan Ögelman, vice president of commercial operations.

New ORDC Price Floors Set

The committee endorsed another binding document request (OBDRR048) that sets two price floors for the operating reserve demand curve (ORDC) in a move to retain and incent new dispatchable thermal generation.

Price adders of $20/MWh and $10/MWh will come into play when operating reserves hit floors of 6,500 MW and 7,000 MW, respectively. ERCOT analysis has indicated the floors would have increased revenues to generators by about $500 million during the 2020 and 2022 pricing years. Thermal generators would have received 80% of those revenues.

The Texas Public Utility Commission approved the ORDC revisions, designed as a bridge to the PUC’s proposed performance credit mechanism market structure, this month. (See Texas PUC Approves ERCOT’s ORDC Modifications.)

Stakeholders approved the OBDRR in a 22-7 vote, with one abstention. All six members of the consumer segment voted against the measure over concerns the structure guarantees revenues and prevents customers from responding.

The Texas Industrial Energy Consumers’ John Hubbard said the organization still opposes the change and that it has filed a notice of appeal.

The OBDRR was separated from TAC’s combination ballot, which passed unanimously. The combo ballot included seven NPRRs, three revisions to the Nodal Operating Guide (NOGRRs), two additions to the Resource Registration Glossary (RRGRRs) and a change to the Planning Guide (PGRR). If approved by the board, these changes would:

    • NPRR1164: require that resource entities identify whether a resource has the potential capability, even if unverified, to be called upon or used during a black start emergency or if it has the capability for isochronous control. It would also require resource entities and transmission service providers to identify if a breaker or switch has a synchroscope or synchronism check relay and would define the terms black start-capable resource, isochronous control capable resource, synchroscope and synchronism check relay.
    • NPRR1171, NOGRR250: clarify various reliability requirements for distribution generation resources (DGRs) and distribution energy storage resources (DESRs) seeking qualification to provide AS and/or participate in SCED.
    • NPRR1173: account for Texas standard electronic transaction processing options for municipally owned utility or electric cooperative service areas in the protocols.
    • NPRR1174: establish a process allowing QSEs or congestion revenue right (CRR) account holders to return overpayment settlement funds to ERCOT.
    • NPRR1175: strengthen market entry qualification and continued participation requirements for ERCOT counterparties like QSEs and CRR account holders, classify information in the background check as protected information, modify application forms for QSEs and CRR account holders and add a new background check fee to the grid operator’s fee schedule.
    • NPRR1185: add a provision for recovery of a demonstrable financial loss arising from a verbal dispatch instruction to reduce real power output.
    • NPRR1189: changes NPRR1136’s gray-boxed language to align it with existing requirements for AS that resources can only provide fast-response service if awarded regulation service in the DAM for that resource.
    • NOGRR215: allow new remedial action schemes to only address actual or anticipated violations of transmission security criteria when market tools are insufficient and clarify the procedures for retiring schemes.
    • NOGRR249: specify methods for transmission operators to receive electronic communication of system operating limit exceedances.
    • RMGRR174: update language to reflect the current practice of posting regional transmission plans and geomagnetic disturbance assessment plans and update data sets.
    • RRGRR033: add data to the resource registration glossary pursuant to NPRR1164.
    • RRGRR035: add fields consistent with NPRR1171.
Posted on

Closed-Loop Hydro’s Climate Impact Found Less Than Batteries

A new analysis of five types of grid-scale energy storage finds that closed-loop pumped storage hydropower has the smallest climate impact.

Pumped storage hydro, or PSH, is the dominant form of utility-scale energy storage in the U.S., accounting for most of the installed capacity nationwide.

It also is among the most challenging energy resources to develop, and it provides a slow rate of return on investment. As developers and policymakers push to increase storage to supplement intermittent wind and solar power, batteries are a quicker and easier answer in the early 2020s.

But the new analysis by the National Renewable Energy Laboratory — “Life Cycle Assessment of Closed-Loop Pumped Storage Hydropower in the United States” — finds PSH more closely aligned with climate-protection goals than compressed air storage or three types of battery storage.

When considering the full impact of materials and construction, the analysis concluded, PSH has a lower global warming potential than the four other technologies, with lesser emissions of greenhouse gas.

The authors, who work at NREL’s Strategic Energy Analysis Center, published the paper in the journal Environmental Science and Technology. NREL said it provides new insight on the differences between PSH and the four other types of storage — compressed air and lithium-ion, lead-acid and vanadium redox flow batteries.

“Not all energy storage technologies provide the same services,” co-author Daniel Inman said in a news release. “We looked at compressed-air energy storage, which allows for grid-scale energy storage and provides services like grid inertia and resilience. But pumped storage hydropower is about a quarter of the greenhouse gas emissions compared to compressed air.”

The analysis involved modeling 39 preliminary designs for proposals in the United States with an average capacity of 835 MW. It found PSH carried the lowest global warming potential per unit of electricity generated, followed by the lithium and vanadium batteries, compressed air and lead batteries.

Factors beyond technology also made a significant difference: Building on a brownfield, for example, could reduce the global warming potential by 20%.

The authors factored in all inputs needed to operate and maintain the PSH facilities for 80 years and assumed they would be abandoned intact and not maintained at the end of their useful lives. Demolition likely would increase greenhouse gas emissions substantially, they noted.

Obstacles

The Department of Energy in 2021 reported the 43 PSH facilities in operation at the time had a combined capacity of 21.9 GW and accounted for 93% of the utility-scale energy storage in the U.S.

But that percentage may be changing as batteries are installed in large numbers.

Todd Briggeman, pumped storage development council chair for the National Hydropower Association, addressed the obstacles facing PSH in an article published by the association last week.

With the rapidly increasing need for dispatchable bulk storage, he wrote, PSH is experiencing a renaissance of sorts but has not taken off yet.

He offered several reasons:

    • The smaller size and modularization of batteries makes them faster and less expensive to deploy.
    • Natural gas has lower emissions than coal and is a convenient short-term solution for base-load and peak-load power.
    • The capital costs of PSH are high.
    • The low rate of return makes PSH a long-term investment, with return on investment taking 40-plus years, more than double other technologies.
    • There is not an established futures market for the ancillary benefits of PSH.

Briggeman suggests several changes that could increase market enthusiasm for PSH:

    • Government incentives have boosted the industry in other countries and are starting to help in the U.S., where there is increased early-stage interest in development of PSH since passage of the IRA.
    • Government-imposed targets or mandates might help as well.
    • The market value of PSH could increase with market design modifications such as a capacity tariff or rate for ancillary services; this would allow PSH to charge for dispatchable and flexible power services, thereby increasing its competitiveness.
    • Treating PSH as a transmission asset and part of grid infrastructure could let utilities access regulatory support and rate structures reserved for transmission; capital costs could be recovered through rates.
    • Long-term PPAs with major power users would provide the certainty of revenue that developers need to secure financing.
    • PSH could be reimagined as a scalable, modular energy source; smaller facilities would not entail the high upfront capital and real estate needs of projects that typically run in the 400- to 1,600-MW range.

Other Environmental Impact

The Department of Energy’s Water Power Technologies Office in 2019 launched its HydroWIRES Initiative (that’s Water Innovation for a Resilient Electrical System) to document and support hydropower’s role in the nation’s electricity system.

It seeks to understand and drive use of hydro resources to reduce costs while contributing reliability and resilience.

One result was a 2020 Pacific Northwest National Laboratory report that examined the environmental impacts of PSH.

Hydro dams are viewed with skepticism by some environmentalists, who say hydropower is not nearly as benign as represented. This can lead to opposition to PSH proposals and, in combination with the factors Briggeman cited, further complicate attempts to build PSH facilities.

The 2020 report — “A Comparison of the Environmental Effects of Open-Loop and Closed-Loop Pumped Storage Hydropower” — attempted to draw some distinctions within the PSH sector.

It noted that all 43 of the PSH projects operating in the U.S. at the time were open-loop — they dam a naturally flowing body of water and use it as their lower reservoir.

By contrast, many of the proposals under consideration now are closed-loop designs — two static reservoirs that draw water for the initial fill and then draw only as needed to replace evaporation or ground seepage.

The closed-loop design has greater flexibility in siting. The 2020 report concluded closed-loop PSH generally has a lower environmental impact, as well, although its effect on geology, soil and groundwater could be greater than open-loop systems in certain circumstances.

Posted on

MISO Strengthens Resolve on Marginal Capacity Accreditation, Stakeholders Displeased

CARMEL, Ind. — Stakeholders remain frustrated with MISO’s plan to enact a marginal capacity accreditation as staff insist the approach will measure the true value of capacity.

MISO is dedicated to a new accreditation plan directly based on a combination of individual past performance and a class average performance during risky hours for different types of generation. The grid operator hopes to file the plan with FERC in November. (See MISO Intent on Marginal Accreditation and Requirements Based on Risky Hours.)

At an Aug. 23 Resource Adequacy Subcommittee meeting, MISO adviser Davey Lopez said the RTO is working to pin down more risky hours to base capacity credits on. MISO may consider adding more hours throughout the year when margins dipped to around 3% or lower, he said.

The accreditation will apply to most MISO classes of resources, including gas, coal, hydro, nuclear, storage, wind and solar. MISO’s load-modifying resources still need an accreditation plan. MISO said it also intends eventually to determine LMRs’ accreditation based on their availability during the times of highest need on the system. It said it will make a separate LMR filing next year.

Most resource accreditations will take a hit using the direct loss of load approach versus MISO’s existing accreditation calculation based on unforced capacity and availability during risky hours.

Under MISO’s new accreditation method, the class average for gas-fired resources will range from 89% to 70% based on the time of year, coal will be anywhere from 91% to 72%, hydro will receive 99% to 69%, nuclear 91% to 80%, pumped storage 98% to 57%, solar 37% to 1%, wind 18% to 12%, energy storage 95% to 94% and run-of-river resources 100%.

Lopez said MISO will prepare other loss of load modeling sensitivities that consider higher solar penetration on the system.

But Minnesota Power’s Tom Butz called for more “fully developed” future fleet mix assumptions in MISO’s loss of load modeling before MISO pursues the new accreditation.

“To say you’re not going to do that before the filing, I don’t feel that’s responsible,” he said. “That’s a shortfall of the modeling.”

Lopez said MISO plans include more factors in its future loss of load modeling. But he said MISO will not use its second planning future — the same one MISO’s long-range transmission planning currently relies on — in loss of load modeling.

“To match Future 2, that would take a significant amount of time and resources, and we have already begun analysis,” he said.

Other stakeholders asked for MISO to hold off on making a FERC filing until it can conduct more comprehensive modeling that includes future system changes.

Executive Director of Market and Grid Strategy Zak Joundi committed to sharing future projections of accreditations with stakeholders before filing for FERC approval.

Lopez said MISO already has conducted extensive modeling analysis, involving hundreds of millions of rows of data. He promised to share more findings in October.

Constellation Energy’s John Orr said MISO’s analysis seemed too “assumption-driven,” and asked for more details behind MISO’s performance assumptions by resource class.

“We’re struggling with, ‘how can this be real?’ We’re trying to understand these dramatic changes,” Orr said.

Orr said it doesn’t seem fair that other generators’ outage scheduling practices will affect the accreditation of other, similar resources.

Other stakeholders warned that MISO won’t be able to satisfactorily defend its proposal in front of FERC because resources won’t be given a fair crack at accreditation.

MidAmerican Energy’s Dehn Stevens said the direct loss of load approach is “extraordinarily complex” and makes it impossible for load-serving entities to anticipate capacity credits and plan resource additions.

“We’re really struggling with how we’re going to translate this,” Stevens said.

WEC Energy Group’s Chris Plante suggested MISO split its resource classes by age of plants so newer units aren’t grouped with outage-prone, older units.

“Maybe we shouldn’t be lumping those all in the same class,” he said.

Lopez said accreditation boils down to a simple reflection of contribution during loss of load hours in modeling. He said an accreditation based on loss of load is in the same currency as MISO’s reserve margin requirements. He said the new accreditation will resolve an existing “disconnect” in MISO’s resource adequacy construct.

“If resources perform better during those risky hours, they’re going to get a bigger slice of the credit,” Lopez said.

Xcel Energy’s Kari Hassler said stakeholders need to better understand how MISO arrived at its class average percentages.

“MISO is asking us to dive in, but that’s difficult when we don’t understand,” Hassler said. She also said MISO should refrain from making changes to its loss of load modeling during its proposed three-year transition to the new accreditation. Others agreed MISO already should have a new loss of load modeling that’s more reflective of actual operations in place before it switches to the new accreditation style.

Lopez said MISO plans a September workshop to explain its loss of load modeling under the new accreditation.

Wisconsin Public Service Commissioner Tyler Huebner said he was frustrated that MISO’s modeling is so poorly understood among stakeholders that NextEra Energy and Invenergy enlisted Astrapé consulting to try to make sense of it.

With the help of Astrapé, NextEra and Invenergy concluded MISO should expand the window of risky hours it will use in the accreditation beyond the loss of load hours MISO’s annual study produces. They said, “expanding the definition of loss of load to include more critical reliability hours per season provides a more consistent signal to resources.”

Chris Miller, FERC liaison to MISO, said FERC already is examining publicly available information on MISO’s possible new accreditation method, even though it hasn’t been filed.

MISO to Change LSEs’ Reserve Responsibility in Accreditation Filing

MISO’s new accreditation proposal now contains changes to how it allocates what share of the planning reserve margin requirements load-serving entities will be responsible for. The amendment represented a change from last month’s version of the proposal.

MISO said it now will dole out a share of the PRMR to LSEs based on their local resource zones’ load during loss of load events. The move is another step away from MISO’s once-pervasive use of unforced capacity values.

MISO said it needs the change because loss of load risk occurs in extreme conditions, or during 90/10 load probability events; however, it said LSEs’ obligations are based on the expected 50/50 load probability.

Lopez said MISO’s proposal “seeks to allocate the planning reserve margin requirement to load-serving entities more commensurate to their contribution to reliability risk.”

The announcement seemed to be an unwelcome addition and visibly took stakeholders by surprise, though staff said they’d been signaling since last month they would adjust LSEs’ reserve obligations with the new accreditation style.

“It’s really scary not to have a feel for what we’re going to be responsible for,” Orr said. He argued that although MISO plans to fully implement the accreditation by 2028, that’s “already here” for some market participants. Orr pointed out that states like Michigan require resource planning four years in advance.

MISO will spend more time discussing accreditation at the next Resource Adequacy Subcommittee meeting Oct. 3-4.

Posted on

MISO South Support for Sloped Demand Curve Wanes on Opt-out Provision

CARMEL, Ind. — State regulators of MISO South are withholding support for MISO’s plan to implement a sloped demand curve in its capacity auctions based on a proposed option for states to shield themselves from the effects.

The majority of Organization of MISO States members sent a letter last week to MISO CEO John Bear, urging MISO to move away from a vertical demand curve and file for FERC approval on a sloped demand curve in the fall so it can be implemented in the 2025/26 planning year. OMS said a sloped demand curve is essential to the footprint’s future reliability.

“MISO’s current resource adequacy construct does not provide the true value of capacity and does not address the resource adequacy challenges facing the MISO region. As a result, it does not send the price signals that motivate the decisions necessary to maintain MISO’s systemwide reliability going forward,” OMS said.

MISO shares the goal to make a fall filing and use a sloped curve in the 2025/26 Planning Resource Auction. (See MISO: Sloped Demand Curve Would Have Raised 2023/24 Capacity Prices.)

During an August OMS board meeting, North Dakota Commissioner Julie Fedorchak said the sloped demand curve is “one of the most important, immediate” things MISO could do to support reliability and send a signal to dispatchable generation that their output is valuable.

However, OMS’ letter is not unanimous: MISO South states did not sign on, since OMS backed MISO’s opt-out provision contained in the demand curve proposal. The opt-out is meant to respect state jurisdiction over resource adequacy.

MISO’s opt-out provision is shaping up to require load-serving entities to opt out of the sloped demand curve for three years at a time, provided they can prove they have anywhere from 1.5 to 3% over their planning reserve margin requirement. Failure to meet the obligation could result in penalties that are 2.7 times the cost of new entry for generation.

Entergy has said MISO’s design is too harsh and instead has advocated that for LSEs to opt out, they must prove they can meet 50% of their planning reserve margin requirement for three consecutive years.

MISO staffers have said the Entergy proposal resembles the RTO’s failed attempt to institute a 50% minimum capacity obligation. (See FERC Again Rejects MISO Minimum Capacity Obligation.)

Entergy put its proposal forward for a stakeholder vote this month; the measure passed 25-20 in an email vote.

Speaking at an Aug. 22-23 Resource Adequacy Subcommittee meeting, Bill Booth, consultant to the Mississippi Public Service Commission, said a full third of MISO members opposed the letter of support, not exactly an “overwhelmingly majority” of MISO states supporting MISO’s proposal.

MISO’s Mike Robinson said the opt-out was borne out of the understanding that most of MISO’s load-serving entities already engage in some sort of integrated resource planning.

“And we respect that,” Robinson added.

Robinson said MISO isn’t on the hunt for a convex shape to the demand curve; rather, its loss of load expectation studies are informing the shape.

“If we’re going to do this auction, let’s do it right, and make sure the supply and demand reflect market fundamentals, and stand up a more efficient market,” Robinson said.

Stakeholders Question Separate Curves for Midwest, South

Meanwhile, some stakeholders remain dissatisfied with MISO plans to develop separate demand curves for its Midwest and South subregions.

MISO plans to churn out separate, seasonal demand curves for MISO Midwest and MISO South to account for seasonal margin requirements and the possibility of the transfer constraint binding. MISO said it will develop curves independent of one another based on its systemwide loss of load expectation study.

But stakeholders said they struggled with the rationale to create separate curves. Customized Energy Solutions’ David Sapper asked why MISO would continue to calculate a footprint-wide planning reserve margin requirement but maintain subregional demand curves.

Robinson said MISO is starting from established practices that it’s comfortable with.

“We made a conscious decision not to change the loss of load analysis,” MISO’s Neil Shah said. MISO’s loss of load analysis doesn’t currently contemplate MISO’s subregional transfer limit.

WEC Energy Group’s Chris Plante said applying separate curves for the Midwest and South creates a “slippery slope” because market participants place different values on excess capacity.

“Where does it end?” Plante asked. “We could create separate curves for each local resource zone. … There’s a limit to where we can keep tacking things onto our [resource] adequacy construct.”

“This was a compromise,” Executive Director of Market and Grid Strategy Zak Joundi said, adding that MISO began with the assumption that it would have a single curve. However, he said that’s not how the system operates and how recent Planning Resource Auction clearing prices have shaken out. MISO has experienced price separation between the Midwest and South multiple times after capacity auctions.

MISO Independent Market Monitor David Patton said he was confused as to why MISO is treating the Midwest and the South as if they’re “islands” with the curves when that’s not how the system operates. MISO had said it’s unlikely but possible under the new curves for price separation between the regions to occur even without a binding subregional transfer limit, prompting Patton’s remarks.

WPPI’s Steve Leovy said MISO is pursuing a “very aggressive timeline” that could result in some “half-baked” concepts finding their way into the filing.

As part of the move to a sloped curve, MISO will remove its annual price cap. In the future, the total annual price for a local resource zone could reach as high as four times the cost of new entry (CONE) if shortages occur in all four seasons. MISO’s current auction design employs a 1.75 times CONE price cap for a local resource zone.

MISO’s new curve design will preserve states’ right to set their own planning reserve margin for their jurisdictional utilities. To date, no state has ever elected to supersede MISO’s reserve requirements.

Posted on

MISO Expects Sedate Fall, Emerges Unscathed from Heat Emergency

MISO said it likely can take on fall with sufficient capacity and minimal operating challenges.

The grid operator issued a fall outlook last week, where it said it should have enough capacity to last the season. It anticipates having 119 GW in firm capacity to handle an expected 107-GW peak in September, 102 GW in October to cover an 89-GW peak and 106 GW in November for an 87-GW peak.

MISO said it should be able to operate squarely within its nonemergency resources through November. However, it said on the slim chance it experiences a confluence of load that could rise as high as 117 GW with unusually high generation outages, it could require all of its 10 GW in load-modifying resources on a September day. That’s the most serious possible scenario MISO foresees. The RTO first must issue a maximum generation emergency to access any of its load-modifying resources.

MISO’s record fall demand stands at 115 GW on Sept. 22, 2017.

On average, MISO experiences nearly 33 GW in generation outages over the fall; outages have hit almost 45 GW at certain times during past seasons.

The National Oceanic and Atmospheric Administration is anticipating a warmer-than-normal autumn for MISO South and average precipitation across the MISO footprint.

MISO may have the worst of summer high temps behind it after it declared a maximum generation emergency to manage heat-driven load and forced generation outages Aug. 24. The grid operator ordered load-modifying resources for more than seven hours and escaped the heat wave without taking the most serious step of load shed. (See related story, MISO Calls 1st Summertime Emergency amid Systemwide Heat Wave.) By Thursday night, it had terminated its maximum generation warning, capacity advisory, conservative operations instructions and hot weather alert for the entire footprint. However, it issued a fresh alert early Friday for lingering heat in MISO South.

Posted on

MISO Revisiting Tx Reconfiguration Studies Due to Low Approval Rates

CARMEL, Ind. — MISO is open to making edits to its process for approving transmission reconfiguration plans that reduce congestion costs to increase the programs’ odds of approval.

MISO has approved two congestion cost reconfigurations of 44 submittals to date, resulting in a 4.5% approval rate. The grid operator said it’s evaluating its market study process for reconfigurations “due to time commitment and low approval rates.”

Multiple stakeholders said the RTO’s low approval rate of reconfiguration proposals is disappointing. They said when load-serving entities submit a reconfiguration plan, it already has a healthy amount of study behind it.

At the Aug. 22 Reliability Subcommittee, Alliant Energy’s Mitch Myhre asked for MISO to conduct a nonpublic sit down with stakeholders to get a better understanding of study input and “why results are coming out the way they are.”

MISO said it may introduce some edits to its transmission reconfiguration study and approval process at a future Reliability Subcommittee.

MISO members have been paying more attention to transmission reconfigurations with congestion costs on the rise. Last year, MISO assembled a nonpublic Reconfiguration for Congestion Cost Task Team, which focuses on transmission owners’ plans to reroute transmission flows during times of heavy congestion costs. The task team maintains a monthly list of the top congested constraints within the footprint that might benefit from a reconfiguration.

Some MISO members have said it’s imperative MISO use reconfiguration plans because major transmission expansion that will ease congestion still is years away from being built.

Posted on

ERO Adds Energy Policy to Risk Priorities List

The ERO’s communication with energy policymakers is becoming increasingly crucial to ensuring the reliability of the electric grid, according to NERC’s 2023 ERO Reliability Risk Priorities Report released this week.

NERC’s Reliability Issues Steering Committee (RISC) develops the report every two years, based on input from ERO Enterprise stakeholders and policymakers on the risk areas of most concern to them. The organization’s Board of Trustees accepted the report last week at its meeting in Ottawa, with Chair Ken DeFontes calling it “the best [reliability risk report] I’ve ever seen.”

Reliability risks in the 2023 report are grouped into five risk profiles:

    • Energy policy — on the federal, state and provincial levels;
    • Grid transformation — including grid planning, resource adequacy and performance and the changing resource mix;
    • Security risks — physical, cyber and electromagnetic pulse;
    • Resilience to extreme events; and
    • Critical infrastructure interdependence.

Energy policy is a new addition to the risk profiles; the others were present in the 2019 and 2021 reports. (See Grid Transformation, Cybersecurity Lead 2021 ERO Risk Report.) The new risk reflects the implementation of “decarbonization, decentralization and electrification” policies by federal, state and local governments across NERC’s footprint and their potential impact on reliability.

Speaking to the Board of Trustees last week, RISC Chairman Brian Slocum said that although energy policy has previously been considered “outside of the purview of NERC,” when committee members brought the topic up for inclusion they met with broad encouragement.

“We brought this as a topic to everybody [on the RISC] — are you comfortable with us putting this into the risk report? And [we] got support from all of the members that this is something that we need to talk about,” Slocum said. “Dealing with jurisdiction issues in the distribution-transmission interface and federal and state jurisdictional issues, we have to be able to talk about these things. I feel as though this is one of the most impactful things in the risk report … just bringing this opportunity for people to feel comfortable bringing up this topic and talking about it.”

The report’s authors explained that “energy policy can drive changes in the planning and operation” of the electric grid that “could present risks to its reliable operation.” Addressing this requires the ERO to develop “strong collaboration and partnerships” with policy makers to ensure that they understand the importance of grid reliability and prioritize it during their deliberations.

All five risk profiles are intertwined, the report said. Decarbonization and electrification initiatives are causing the deployment of non-synchronous generation as well as natural gas resources. The transformation also includes adoption of demand response, microgrids and other technologies that are more dependent on communication technology and electronics and thus introduce new security risks.

Extreme temperatures and disruption of wind and solar power supplies may also impact reliability. The introduction of new generation types also increases the critical infrastructure interdependencies. Just as the interruption of natural gas supplies can idle combined cycle facilities, outages in the telecommunications system may also “hamper situational awareness and real time [grid] operation.”

The interdependencies work both ways: For example, the electrification of transportation may make delivery of essential goods more difficult in power outages from a hurricane.

Trustee Larry Irving, who is CEO of a telecommunications consulting firm, warned at last week’s meeting that the communication industry is more vulnerable to electric outages than most customers realize, and emphasized the need for collaboration with NERC’s peers in other industries.

“When we had the [2003 blackout], 94% of American households had a landline phone; those landline phones had their own power,” Irving said. “Today, fewer than one in three households have a landline. We’re dependent upon [cellular] towers, which may or may not have electricity … so even if your battery and your phone work, you don’t have a phone.”

“The point I’m trying to make is, I don’t know if we do enough with the telecommunication industry,” he continued. “If we have a coordinated [cyber] attack in this country, the two places they’re going to go after, if they’re smart, would be the telecommunication industry and this industry.”

Posted on

MISO Calls 1st Summertime Emergency amid Systemwide Heat Wave

CARMEL, Ind. — MISO instated maximum generation procedures Thursday to manage a pervasive heat wave blanketing its footprint.

The grid operator called a maximum generation event to begin at noon ET as temperatures climbed to 95 degrees Fahrenheit and above throughout most of its system. It de-escalated the emergency into a maximum generation warning effective at 7:30.

MISO topped 122 GW of demand during the evening peak, short of its all-time peak demand record of 127 GW, set July 20, 2011. By 5 p.m., hub LMPs were around $220/MWh in MISO Midwest and $150/MWh in MISO South.

Ahead of the demand surge, MISO forecast a 127-GW peak by 5 p.m. with a little more than 121 GW in cleared offers.

MISO emergency

Real-time prices at hubs at 5:30 p.m. Aug. 24 | MISO

MISO previously enacted a footprint-wide capacity advisory and conservative operations Monday, before a maximum generation alert for Thursday. As it geared up for the day, the RTO asked all members to update their market data with their best available information. MISO said it was contending with forced generation outages paired with abnormally high temperatures and higher load than forecast a day prior.

DTE Energy’s 1.1-GW Fermi 2 nuclear plant south of Detroit was offline during the week’s hottest weather. The company was forced to perform an unscheduled outage because of a coolant leak.

“We’ll see how this week shapes up. We’ve already sent out several hot weather alerts and capacity advisories,” MISO Director of Market Administration John Harmon said ahead of the emergency declaration and the most intense heat at the Reliability Subcommittee’s meeting Tuesday.

The Tennessee Valley Authority also struggled alongside MISO in the heat. On Thursday, the U.S. Energy Information Administration reported that TVA’s 27 GW in net generation was no match for 32 GW in forecasted demand. The federal utility had been relying on gigawatts of imports from MISO and its other neighbors since Sunday.

August had already been peppered with tricky operating conditions and alerts related to summer heat stressing MISO’s grid.

The RTO also declared conservative operations instructions to members in Wisconsin and parts of its northern footprint Aug. 3. At the time, MISO said it was experiencing tight capacity, a loss of generating units and low wind production.

MISO issued another round of conservative operations for MISO South on Aug. 11 and again on Aug. 14. In that timeframe, South was also subjected to multiple hot weather alerts and capacity advisories.

Before this week, MISO had not encountered a summertime energy emergency; it avoided ordering up load-modifying resources during another heat wave in late July. (See MISO Preps for Heat Wave, Anticipates Annual Demand Peak.) The blistering temperatures wrought a 121-GW peak July 27, which until now stood as MISO’s annual peak. Otherwise, systemwide load averaged 86 GW in July.

MISO achieved a little more than 3-GW all-time solar peak July 25. At the Reliability Subcommittee meeting, Harmon said the RTO expects to keep eclipsing solar output records as utilities bring more facilities online.

Posted on

NCUC Approves Duke Energy’s Bill-funded Efficiency Programs

The North Carolina Utilities Commission on Wednesday approved two programs for on-bill efficiency funding in Duke Energy’s territories.

Both Duke Energy Carolinas and Duke Energy Progress (DEP) won approval for a residential tariff on-bill (TOB) program that is meant to offer customers a way to pay for energy efficiency upgrades over time through their monthly bills.

“By using premises-specific modeling based on an in-home assessment, applying all available rebates and incentives and utilizing an initial copayment, if necessary, the customer’s TOB monthly charge will not exceed the customer’s projected average monthly savings over the repayment term of up to 12 years,” NCUC said in its order.

In a separate order issued Wednesday, NCUC approved a pilot program for DEP’s “Multi-Family New Construction Tariffed on Bill Pilot.” The five-year pilot program is meant to evaluate the effectiveness of on-bill funding for upgrading the efficiency of apartment buildings as they are under construction.

The program will be focused on apartment complexes with 700 to 1,000 units, and DEP can implement eligibility requirements so that participants are spread around its footprint and not dominated by a few residential developers.

The upfront costs for energy efficiency improvements have long been identified as a significant obstacle for customers wishing to improve their homes. The TOB program is meant to overcome that barrier, the commission said in its order.

The residential TOB tariff is linked to the meter at a specific address, so even if the customer who signed up moves, it would stay with whoever buys the residence. The TOB charges will recover the initial investment plus interest equal to Duke’s utilities most recently approved weighted average cost of capital.

The TOB program for both utilities is open to individually metered residential customers who are served under the residential rate schedule, regardless of whether the owner occupies the residence or leases it. Customers need a 12-month billing history to establish the baseline consumption used to model projected energy savings.

Duke will maintain and repay any equipment as required. Customers must notify it when they notice something in need of repair, and the utility will fix it within five business days. Customers have 30 days to report malfunctions.

The TOB program covers heating ventilation and air conditioning equipment, including smart thermostats, thermal boundary improvements, heat pump water heaters and other equipment on a case-by-case basis.

Initially, Duke plans to target customers who would stand to reap the biggest benefits, but over time it expects many of its customers will want to use the TOB program.

Though the NCUC ordered some changes to Duke’s filing, it found the program was in the public interest. The changes involved clarifications over how customers can repay Duke early for its work, at which point the utility will no longer be obligated to repair equipment.

Duke agreed to notify customers of any other programs that could pay for efficiency upgrades at lower costs — or for free — to the extent it is aware of them. Duke also agreed to work with the state to see how funding from the federal Inflation Reduction Act could be coordinated with the TOB program.

DEP’s apartment building pilot program can be used to add wall insulation, improved heat pumps, Energy Star appliances and heat pump water heaters when new buildings are being constructed. Duke will pay the incremental costs for more efficient equipment and recover their costs from tenants’ monthly bills, minus any applicable efficiency incentives.

Property owners will be responsible for maintaining all installed equipment and for timely repair measures. They are able to pay off Duke after three years in the program and thus end the extra monthly payments.

The commission required DEP to change the prepayment plan so that when an apartment complex owner pays off the utility early, it does not have to pay the interest it would have over the full term of the program. The regulator reasoned that the utility would be able to invest that money in other areas while having fully recovered its upfront costs.