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December 27, 2024

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PJM MRC Briefs: Aug. 24, 2023

Stakeholders Defer Vote on Generation Deactivation Issue Charge

VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee voted to defer a decision on an issue charge that would create a new senior task force to investigate changes to the generation deactivation process.

PJM and the RTO’s Independent Market Monitor are jointly sponsoring the problem statement and issue charge. (See “PJM and Monitor Present Generation Deactivation Issue Charge,” PJM MRC/MC Briefs: July 26, 2023.)

The scope includes discussion of the triggers for when PJM can offer a reliability-must-run (RMR) contract to a generator seeking retirement, the compensation for RMR resources and the timing of when a resource owner must notify the RTO of its intent to retire a unit.

Following feedback from the initial first read in July, the issue charge was revised to break out the discussion of resource compensation into its own phase to be considered prior to the other elements.

Paul McGlynn, PJM | © RTO Insider LLC

Presenting the proposal, PJM’s Paul McGlynn said the current compensation structure lacks clarity, as resources that opt not to use the formula rate for determining RMR compensation instead make FERC filings that can offer differing interpretations on cost recovery.

McGlynn envisions an additional RMR contract trigger for a resource that would create a shortfall in black start capability in a region if it were to retire.

PJM is seeking to lengthen the 90-day notice generators are required to provide before a desired deactivation date because the timeline leaves little time for planners to make necessary upgrades to ensure that the grid can remain reliable without the resource. Advanced knowledge of deactivations will be increasingly important given the scale of retirements PJM expects to see over the next decade, McGlynn said.

Stakeholders discussed PJM’s change to the issue charge, stating that expanding use of RMR contracts to maintain resource adequacy would be out of scope for the task force. Cost allocation for RMR contracts under the existing transmission violation trigger and changes to the capacity market also are listed as out of scope.

GT Power Group’s Tom Hyzinski said considering whether RA should be a rationale for offering an RMR contract could offer an additional tool if a large number of generators simultaneously decide to deactivate.

“We don’t want to approve an issue charge that prevents things from being discussed that need to be discussed,” Hyzinski said.

McGlynn said the RTO is already looking into improving the capacity market’s ability to ensure resource adequacy.

PJM Senior Vice President of Market Services Stu Bresler said there are backstop provisions in the tariff that allow additional capacity to be procured outside of the Base Residual Auction (BRA) cycle if the RTO falls below its targets.

Whether the process should preclude interactions with the capacity market was discussed at length both during the July meeting and on Thursday, with several stakeholders concerned the task force and its solutions could be fragmented from market changes being considered in other forums.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said several areas of the issue charge were ambiguous and could lead to procedural arguments distracting from core issues. He and other stakeholders suggested amendments to clarify that language in the issue charge, which were adopted by PJM and the Monitor.

Vistra’s Erik Heinle said the revisions had improved the issue charge from its first read but that he believes the first phase should be RMR compensation and timing.

Monitor Joe Bowring said he would support breaking the issue charge into two separate stakeholder processes, with his focus being primarily on compensation.

Peak Market Activity Credit Changes Endorsed

Stakeholders endorsed tariff revisions to address the amount of credit market participants must maintain to satisfy their peak market activity (PMA) requirement, which is their highest exposure in the past year. (See “First Read on Peak Market Activity Credit Activity Proposal Expected in August,” PJM MRC/MC Briefs: July 26, 2023.)

The changes include redefining the PMA surplus and shortfall parameters, introducing minimum exposure and minimum transfer amounts to the tariff language and increasing the PMA reset from occurring semiannually to weekly. The reset reconciles over- and under-collateralization that occurs as energy prices and demand fluctuate.

The revisions also increase the number of permissible early payments from 10 to 13 to provide more flexibility, and the rolling invoice period was increased from three weeks to four.

PJM’s Yong Hu said staff had backcast numerous solutions and believe the proposal is optimal.

Denise Foster Cronin of the East Kentucky Power Cooperative (EKPC) said the utility had concerns with PJM’s initial proposal but that stakeholders and PJM were able to produce a strong compromise.

Bresler said because the proposal was endorsed by the Risk Management Committee (RMC) on Aug. 22 without objection, it would normally have been a consent agenda item for the MRC; however, staff are aiming to implement the tariff revisions before winter.

PJM Provides First Read on Reserve Certainty Issue Charge

PJM gave a first read of an issue charge and problem statement that seeks to address several areas of the reserve market, largely to address a decline in the response rate since the two tiers of reserves were consolidated in a market overhaul implemented Oct. 1. (See “PJM Seeks Stakeholder Process on Reserve Certainty,” PJM MRC/MC Briefs: July 26, 2023.)

Since presenting the issue charge to the MRC in July, PJM has revised the timeline laying out the order in which it seeks to address each of the work areas and added more education on the topics. The bulk of the immediate needs would be initiated upon approval of the issue charge, with an expected duration of six to nine months, followed by discussion on the longer-term items expected to take 12 to 18 months. Also, several changes were made to the work areas.

The immediate needs are reserve performance and penalties, aligning the offer structure with fuel procurement, deployment, and ensuring that procurement reflects system need. Longer-term needs include the eligibility requirements for reserve resources and incentivizing flexibility to meet system needs.

Bowring said he think the out-of-scope portion of the issue charge — which would allow PJM to prevent discussion of changes that could impact the RTO’s “ability to maintain reliability and compliance with NERC standards” — should be more specific and could be used by PJM to curtail discussion.

Bowring said PJM has previously made such assertions in response to participants, including the IMM, who disagreed with PJM’s approach.

“No one will propose changes that they believe will reduce reliability or compliance with NERC standards. The issue is how best to maintain reliability and compliance. There are multiple paths to those objectives. The ability to discuss options should not be arbitrarily limited,” he said.

The declining reserve response rate led PJM to increase its reserve requirement by 30% in May, overriding stakeholder objections. The Monitor at the time objected that the change was not needed and not supported by the data. PJM’s Donnie Bielak said the issue charge is intended to produce a permanent solution that is more satisfactory for stakeholders. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)

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Duke Files Settlement with Munis at FERC on Battery Dispute

Duke Energy Progress (DEP) and the North Carolina Eastern Municipal Power Agency (NCEMPA) filed a settlement with FERC on Thursday that would end a dispute over the latter using batteries to shave its peak demand (ER22-682).

Duke serves the power agency under a power purchase agreement in which the utility buys energy, capacity and reserves to meet the municipals’ demand. It charged the agency for capacity based on a 12-coincident-peak method.

NCEMPA members started shaving those peaks using behind-the-meter battery storage systems, which led to a dispute at FERC over their impact on Duke’s ability to recover its costs.

Duke believed that NCEMPA could figure out when its members’ demands were going to hit one of the 12 coincident peaks, thus dispatching batteries to avoid the capacity charges, so it filed changes to its agreement to adjust how the agency was charged for capacity to account for the batteries.

FERC in an order early last year found that Duke had failed to show its proposal was just and reasonable and set the matter for hearing and settlement judge procedures. (See FERC Orders Negotiations in Duke-Muni Contract Dispute.)

The filed settlement would resettle transactions between the two starting on Jan. 1, 2023, expressly saying no refunds would be issued for 2022. NCEMPA would be able to keep its batteries and other “energy injection devices,” but they cannot exceed 1.75% of its total capacity plus 25 MW. Any batteries or storage devices that NCEMPA uses during peak demand periods can be made subject to that cap.

The two also agreed to a new supplemental capacity charge arrangement for certain interruptible loads whose consumption might not be apparent at the monthly system peak used for calculating capacity charges.

FERC trial staff supported the settlement, saying it would solve the issues in the case in a fair and reasonable way that is consistent with the public interest. The settlement would allow NCEMPA and its members to manage their power use through energy-storage devices while addressing DEP’s concerns about their impact on its revenues, they said.

The uncontested settlement would resolve all the issues FERC set for hearing and promote consistency and predictability through 2027 with a new PPA. Duke and NCEMPA asked FERC to approve the settlement without modification or conditions.

EV Charging Pilot

Duke Energy on Monday announced it was launching a pilot program in its North Carolina utilities to offer customers a flat rate for 800 kWh/month of electricity to charge their cars.

The utility is working with Ford, General Motors and BMW to launch its “EV Complete Home Charging Plan.” Customers will pay just $19.99/month in Duke Energy Carolinas and $24.99/month in DEP for 800 kWh, which the utility said is about twice as much as the average consumer would use for their cars.

The pilot will use software in the cars themselves to track monthly demand, avoiding the expense of installing a separate meter.

“The average EV owner is already saving about $1,000 per year on fuel costs compared to a traditional vehicle; a predictable monthly subscription charge on top of that is going to ensure predictable savings when charging,” Kendal Bowman, president of Duke’s utility operations in North Carolina, said in a statement. “Beyond cost savings, EV charging at home tends to be convenient because drivers can leave the house with a fully-charged vehicle and lessen the number of trips to public charging stations.”

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Conservation Calls Help ERCOT Meet Near-record Demand

In what is becoming an almost daily occurrence, ERCOT on Sunday issued another appeal for voluntary conservation as the Texas grid operator continues to manage tight conditions during a brutally hot summer.

The ISO called for the market’s consumers and businesses to reduce their usage between 4 p.m. and 9 p.m. (CT). As it has since late last week, ERCOT warned of the potential to enter emergency operations because of high demand paired with expected low wind and possibly low solar generation during the evening hours when the sun sets.

The conservation call marked the fourth straight day, and seventh overall, the grid operator has asked for voluntary conservation this summer. Temperatures reached a record 109 degrees Fahrenheit in Houston and broke triple digits throughout much of the rest of Texas.

ERCOT CEO Pablo Vegas | © RTO Insider LLC

“What we’re seeing are conditions that are more tight than what we have seen on any other day this summer,” ERCOT CEO Pablo Vegas told the Public Utility Commission during an open meeting Thursday. “At this time, it’s a high likelihood that we expect to be in emergency operations this evening.”

That did not happen. The grid operator deployed its newest ancillary service, ERCOT Contingency Reserve Service (ECRS), and non-spin reserve service to close the gap between supply and demand. Pop-up rain showers in the Houston area also lowered temperatures and with it, demand — but not before an hourly average peak of 84.24 GW, more than 1 GW from a record.

ECRS dispatches resources that can respond within 10 minutes of deployment instructions and can operate for at least two straight hours. It also was deployed Friday and Saturday along with non-spin and responsive reserves; energy storage regularly supplied more than 1.2 GW of energy as well.

“Thank you to Texas residents [and] businesses for your conservation efforts, which along with additional reliability tools, helped us to get through a tight peak time,” ERCOT tweeted Thursday night, a message it has repeated several times since.

Vegas told the commission the ISO has seen a “very different profile” for wind energy, with an afternoon production of about 6 GW that is several GW lower than normal during summer months. He said the thermal dispatchable fleet has been operating at or near normal forced-outage levels.

“It’s really the combination of the very high heat, the very high demand and the low expected output of wind during the solar ramp,” Vegas said.

Temperatures are expected to cool slightly in Texas this week. ERCOT’s six-day forecast predicts demand to stay below 79 GW for the rest of the week.

The grid operator’s record for hourly average demand remains 85.44 GW, set Aug. 10. It has broken last year’s high of 80.15 GW 193 times this summer.

ERCOT staff had projected a summer peak of 82.7 GW in its final pre-summer assessment. That mark has been exceeded 98 times this summer.

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Texas Public Utility Commission Briefs: Aug. 24, 2023

Texas regulators and ERCOT stakeholders last week celebrated a year-long study of aggregated distributed energy resources (DERs) that’s resulted in two virtual power plants (VPPs) qualified and able to provide dispatchable power to the state’s grid.

The Aggregate Distributed Energy Resources (ADERs) pilot project tested how consumer-owned, small energy devices, such as energy storage systems, backup generators, controllable electric vehicle chargers and smart thermostats and water heaters, can be aggregated virtually and participate as a resource in the wholesale electricity market (53911).

Eight aggregations (ADERS), totaling 7.2 MW, participated in the pilot project. Two ADERs with customers using Tesla Electric Powerwall storage systems have completed required testing and could provide energy and ancillary services through the third quarter. One is linked to Oncor’s distribution system in North Texas, the other to CenterPoint Energy’s system in Houston.

The other six ADERs are being commissioned.

CenterPoint Executive Vice President Jason Ryan, who chaired the 20-person task force, told the Public Utility Commission during its Thursday open meeting that the pilot project shows Texas is a leader in VPP implementation.

“I’m not talking about just the leader among states in this country, but really in the world. It really changes how customers are using the distribution grid,” he said.

“Every one of those customers, by investing in whole-home backup and then being participatory in the grid, is providing additional reliability services from a private investment and taking off the socialized value of the reliability standard. The growth of this pilot is also an incredibly important data point,” Tesla’s Arushi Sharma Frank said. “You have to be able to see a resource. It needs to be visible in the system, it needs to be visible to ERCOT, it needs to be visible to the distribution service providers operating the local system and it needs to be understood to be a part of wholesale price formation.”

Arushi Sharma Frank | © RTO Insider LLC

She said the exchange of granular information between the consumers, ERCOT, distribution providers and other market participants has been invaluable.

“All of these things happening in nine months is progress on top of progress on top of progress of the kind that is taking the RTOs years to implement years,” Frank said. “Hopefully in the three years that this pilot progresses, the information that Texas will have collected on three disparate systems — retail energy distribution service, and the wholesale grid — will be incredibly valuable to the National Labs. You’ll be in the opposite position where instead of the National Labs coming to help you, you will be going to the National Labs and helping them figure out how to monetize DERs and put them into wholesale price formation.”

Frank said in a report that the project’s first phase allowed Tesla to “demonstrably assess” ADERs’ viability as providers of energy and reserves. However, Tesla also discovered the costs associated with maintaining a qualified scheduling entity (QSE) and servicing telemetry can be challenging on a small scale. She called for an increase in current QSE caps, noting ADERs’ break-even point of 15-20 MW is above that cap.

In a memo, PUC commissioner Will McAdams directed the task force and ERCOT to create a plan for the pilot’s second year, following the project’s principles.

“We would like to understand what performance metrics would need to be met to unlock expansion of grid services or size caps,” he said.

ERCOT Evaluating RMR Options

ERCOT CEO Pablo Vegas told the commission it may resort to issuing reliability must-run (RMR) contracts to ensure it has enough capacity to meet demand this winter.

The grid operator issued a market notice last week that said while it had determined a gas plant’s announced suspension would not create a reliability issue, it was conducting additional analysis to determine whether there’s a need for additional capacity from dispatchable resources for the upcoming season.

ERCOT pointed to increasing system demand and a continued reliance on variable output from renewable resources as creating the need for more analysis. It promised a decision by early October as to whether the resource would be able to suspend operations or be extended an RMR contract.

“We are looking at more broadly the needed capacity as we get into this winter season,” Vegas told the PUC. “There have been multiple units that have indicated a cease operations and mothballing status or retirement.”

Asked whether staff would evaluate a demand-side solution, Vegas responded affirmatively.

“If we move down this pathway, the requirement would be to evaluate any sort of capacity options, including the load-side,” he said. “Effectively, we would be seeking the most cost-effective solution or to close a risk if we identify one on capacity.”

Travis Kavulla, NRG Energy’s vice president of regulatory affairs and a former Montana state commissioner, tweeted that this would be the first time RMR, normally used for local reliability issues, would be used for system resource adequacy.

“This kind of creates a ‘Hotel California’ situation,” he said, referring to resources’ ability to leave. “Only CAISO has used RMR powers for this purpose.”

ERCOT said its reliability assessment of the Barney Davis 1 unit near Corpus Christi indicated it is not required to support transmission system reliability. The unit, which has a summer maximum sustainable rating of 292 MW, plans to indefinitely suspend operations on Nov. 24.

Any RMR contracts must be approved by the board.

ISO Prioritizes Market Changes

Vegas also shared development timelines for ERCOT work initiatives as a result of recently passed legislation that he called The Big Five: a reliability standard, a dispatchable reliability reserve service (DRRS), the performance credit mechanism (PCM), a multi-step floor to the operating reserve demand curve (ORDC) and real-time co-optimization (RTC).

“Those five initiatives together make up a suite of changes that are going to help to drive reliability and make changes to the market constructs that are designed to improve both operational flexibility as well as long-term resource adequacy,” Vegas said.

ERCOT will work with consultants to update a previous value-of-lost-load study and to perform a review of its cost of new entry metric, currently valued at $105,000/MW-year after a 2012 analysis. Commission staff plan to file a proposed rulemaking on a reliability standard based on the ISO’s study; the PUC will take up the proposal in January.

ERCOT has considered a reliability standard since a 2011 winter event and has long operated with a 13.75% target reserve margin based on a 0.1 loss-of-load expectation and a traditional dispatchable generation fleet. The PUC opened a docket (54584) earlier this year to evaluate and establish an appropriate reliability standard.

The grid operator’s staff has proposed a three-part framework that considers the duration and magnitude of a loss-of-load event besides the occurrence’s frequency. It’s intended to better quantify risks associated with an LOLE when intermittent resources comprise a large percentage of the generation fleet.

The commission already has approved the ORDC’s changes but it still must endorse a document that formalizes the two price floors. Staff will make the software changes in November and must file reports on performance metrics and DRRS’ effects in 2024 and 2025, respectively. (See Texas PUC Approves ERCOT’s ORDC Modifications.)

ERCOT staff and stakeholders will resume their work on RTC and energy storage resources’ state of charge, work delayed by the disastrous 2021 winter storm. The Real-time Co-optimization + Batteries Task Force will meet Sept. 8 with a 2026 deployment target. (See “Staff, Stakeholders Get Serious on RTC, Energy Storage,” ERCOT Technical Advisory Committee Briefs: Aug. 22, 2023.)

ERCOT also is developing a “framing document” outlining PCM decision points for the PUC. Vegas said staff will take the commission’s feedback and prepare a strawman proposal for a series of workshops with stakeholders and PUC work sessions. ERCOT and the market monitor will perform a cost-benefit analysis before the Texas Legislature next meets in 2025, after which protocols will be drafted.

Vegas said he expects it will take another two years to implement the PCM. The market construct would retroactively reward dispatchable generation that meet performance criteria during the tightest grid periods with incentive payments.

Asked whether RTC, a market tool that procures energy and ancillary services every five minutes, will still be needed when the PCM is deployed, Vegas said efficiency, reliability and market transparency are key factors.

“We should always be looking at the combination of tools we have to incentivize the goals of the ERCOT grid,” he said.

The DRRS is a non-spin ancillary service that supports system reliability and mitigates the use of reliability unit commitment. It is open to resources capable of running for at least four hours at their high sustained limit; being online and dispatchable no more than two hours after being called on; and with the dispatchable flexibility to address inter-hour operational challenges.

ERCOT plans to move nodal protocol revision requests through the stakeholder process this fall to codify the DRRS’ sub-type. Upon approval early next year, staff will make system changes and begin offering the service by Dec. 1, 2024.

PUC Rules Against SWEPCO

The commission gave Southwestern Electric Power Co. (SWEPCO) until Sept. 8 to explain why and how the recovery of carrying costs alone is tied to and adequately accounts for the PUC’s determination on the prudence of a recently retired coal plant (53931).

The order is related to SWEPCO’s application to reconcile fuel costs. An administrative law judge in July found the retirement decision to be prudent after the utility reached a partial settlement agreement resolving all other issues.

SWEPCO’s parent company, American Electric Power, announced the 580-MW Pirkey plant’s retirement in 2020. The unit, which sits in SPP’s Texas footprint, stopped operating in March. In May, the Texas commission rejected the utility’s application to build 237 MW of accredited renewable capacity at the Pirkey site. (See Texas PUC Rejects SWEPCO Application for Renewables at Pirkey.)

The PUC plans to take up the matter during its Sept. 28 open meeting.

The commission also denied SWEPCO’s rehearing request of its May denial of renewable resources at Pirkey, saying that their acquisition is not in the public interest (53625).

In other proceedings, the PUC:

    • Gave El Paso Electric Co. until Sept. 23 to advise the commission what it intends to do with its application for proposed electric vehicle-ready pilot programs and tariffs following a recent law that addresses the operation of public EV charging stations and goes into effect on Sept. 1 (54614).
    • Overturned an ALJ’s decision approving Wind Energy Transmission Texas’ interim wholesale transmission rates following appeals by Texas Industrial Energy Consumers and Steering Committee of Cities Served by Oncor (55029).
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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.

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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.
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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.

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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.

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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.

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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.