Page 1020 – RTO Insider

November 10, 2020

NEPOOL Participants Committee Briefs: Nov. 5, 2020

ISO-NE CEO Gordon van Welie last week shared the RTO’s “vision for the future” with the NEPOOL Participants Committee, which he presented as “our long-term intent” that “guides the formulation of our strategic goals.”

The RTO included a forward-looking statement that van Welie said seeks “to harness the power of competition and advanced technologies to reliably plan and operate the grid as the region transitions to clean energy.”

Publication of ISO-NE’s vision comes on the heels of recent calls for reform by the New England States Committee on Electricity (NESCOE), which wants increased transparency from the RTO and a more prominent role in the decision-making process. (See States Demand ‘Central Role’ in ISO-NE Market Design.)

The RTO’s five “strategic goals” are responsive market designs; progress and innovation; operational excellence; stakeholder engagement; and attracting, developing and retaining talent.

When it comes to the first goal, van Welie said ISO-NE wants to improve the current market structure and continue to evolve and reposition its design to accommodate the states’ transition to high levels of renewable and distributed resources. The RTO also wants to maintain a robust fleet of balancing resources and preserve the market’s ability to attract new entry.

The progress and innovation goal includes a push to evolve capabilities to support the grid as the region transitions to clean energy. It also includes improving power system and market modeling and supporting investments in transmission infrastructure to enable renewable energy, as well as a call for integrating distributed energy resources and providing data and information-based services.

According to van Welie, stakeholder engagement requires collaboratively understanding and anticipating needs, thought leadership through high-quality analysis and communication, and nurturing productive relationships with FERC, the states and market participants.

Amended DDBT Passes

The committee voted to support an amended proposal from ISO-NE to recalculate the dynamic delist bid threshold (DDBT) for Forward Capacity Auction 16.

Calpine, NESCOE and Vistra’s Dynegy offered a combined amendment to the RTO’s proposal to lower the DDBT upper bound to 75% of the net cost of new entry (CONE) and set the DDBT at the RTO’s estimated clearing price plus a margin adder calculated using 75% of net CONE.

NESCOE said it remains concerned that the ISO-NE proposal does not balance design objectives and can result in the DDBT being set too high when capacity prices increase. The organization added that the risk of the DDBT being higher, especially as it approaches net CONE, could have cost implications for consumers.

Calpine and Dynegy said the RTO’s design interferes with competitive price formation, adds significant administrative burden and risks to existing suppliers, and creates an unnecessary barrier to market exit. The amendment allows a modest margin adder to low prices when supply curves are typically flat, with the adder diminishing as expected prices increase, which preserves at least some of the benefit of the DDBT.

Previously, NESCOE presented two amendments at the Markets Committee meeting in October. One would have lowered the upper bound to 85% of net CONE and add an upper bound set at 125% of the prior auction clearing price. The second would have limited the maximum rate of change in the DDBT from auction to auction to 30% of net CONE.

Calpine and Dynegy also presented amendments at the MC that would set the DDBT at ISO-NE’s estimated clearing price plus a scaled margin that starts 75 cents above the RTO’s estimated cost of $2/MWh, decreasing to $0/MWh at net CONE, or, as an alternative, from a fixed bid to a cap price.

At the RTO’s request, the committee considered, but did not approve, the unamended DDBT proposal. The vote failed to pass with none in favor and noted abstentions.

Pathways Process Continues

Frank Felder and Frank Wolak each made presentations on “Potential Pathways to the Future Grid,” with Felder returning for “Focus on Energy Only Market and Alternative Resource Adequacy Constructs” and Wolak discussing “Long-Term Resource Adequacy with Significant Intermittent Renewables.”

Felder, a professor at Rutgers University and an expert in energy policy and electricity markets, told the committee that whether the minimum offer price rule (MOPR) applies to a forward clean energy market or integrated clean capacity market determines the potential for “double payment” for clean energy and price suppression. He said an energy-only market addresses the double payment issue and maintains a regional market, even more so with added carbon pricing. Additional changes to the ancillary services markets may be needed, however, to ensure sufficient balancing resources.

According to Felder, some alternative resource adequacy constructs could address the MOPR issue. He added that anticipated replacement of large generating resources throughout New England with new capacity with very different operating characteristics suggests the region will need to strongly consider changes to transmission planning and cost allocation to avoid costly investment decisions.

Wolak, a Stanford University economics professor and director of its program on energy and sustainable development, said that in a low-carbon world, the electricity supply sector would consist of more than 50% intermittent renewables.

Wolak said the growing share of renewables will also require investments in both grid-scale and distributed storage and active demand-side participation by customers with interval meters using dynamic retail electricity prices, in addition to automated distribution network monitoring and on-site load-shifting technologies. He added that market design should support business models that lead to efficient investments in those technologies.

Winter is Coming

In his report to the committee, ISO-NE COO Vamsi Chadalavada said that the energy market’s value was $193 million in October, down $14 million from revised September figures and $9 million from October 2019.

Chadalavada also delivered the winter outlook, including a 40% probability of above-normal temperatures for New England from December through February. There is also an equal chance for above- or below-average precipitation in the region.

In terms of winter capacity, Chadalavada said ISO-NE is projecting the lowest 50/50 operable capacity margin of 2,574 MW and a 90/10 capacity margin of 1,232 MW for the week beginning Jan. 2, 2021. The capacity outlook will be adjusted if there are extended periods of cold weather.

The 50/50 winter peak demand forecast of 20,166 MW is 310 MW lower than the 2019/20 forecast, while the 90/10 winter peak demand forecast of 20,806 MW is down by 367 MW.

Chadalavada added that unknown societal factors would likely continue to impact demand throughout the season. He said forecasting staff are continuously evaluating load trends and frequently retraining forecasting models.

The RTO also recently hosted a Generator Winter Readiness Seminar and distributed a survey to all regional generating resources. It said survey results will enhance its understanding of winter preparations across the region, temperature-specific limitations on real-time capabilities and specific protocols followed during extreme cold-weather events.

ISO-NE will continue to perform a weekly 21-day look-ahead of forecasted conditions, which provides an opportunity for generators to act in advance of an energy emergency. In addition to the Winter Generator Readiness Survey, the annual natural gas critical infrastructure survey process has been incorporated into Operating Procedure 21 before winter.

Other Action

The committee also acted on consent agenda items.

Without objection, the PC removed sunset of the forward reserve market (FRM) from the consent agenda following FERC’s Oct. 30 order rejecting the Energy Security Improvements (ESI) proposal on which the FRM sunset was contingent. (See FERC Rejects ESI Proposal from ISO-NE.)

The remainder of the consent agenda was approved with two abstentions and two oppositions because of concerns about the installed capacity requirement (ICR) and related values for Forward Capacity Auction 12’s three annual reconfiguration auctions (ARAs) set for 2021.

The PC approved net ICRs of 32,925 MW for ARA 3, 32,765 MW for ARA 2 and 32,980 MW for ARA 1. The HQICC value is 958 MW for ARA 3, with the amount rising to 969 MW for ARA 2 and down to 941 MW for ARA 1.

November 10, 2020February 13, 2025

NARUC Session Discusses EV Rates, Customer Views

Research scientist Andy Satchwell of Lawrence Berkeley National Lab had a caveat for the audience at the beginning of his presentation last week on electric vehicle rate designs and utility programs.

“The questions about what rate design and utility programs will drive EV adoption are unanswered,” he told the National Association of Regulatory Utility Commissioners’ Annual Meeting and Education Conference. But as a researcher, this does not make him unhappy. “This is an emerging and dynamic — and therefore really exciting — topic,” he enthused.

Satchwell was joined by Patty Durand, CEO of the Smart Energy Consumer Collaborative, which has been asking consumers the same questions annually for more than seven years. “We have probably the longest longitudinal study of residential consumers in the nation,” she said.

Clockwise from top left: Andy Satchwell, Lawrence Berkeley National Lab; moderator Zeryai Hagos, New York Department of Public Service; and Patty Durand, Smart Energy Consumer Collaborative | NARUC

In a second panel, Chris Budzynski, director of utility policy for Exelon; Lydia Krefta, Pacific Gas and Electric’s manager of regulatory, compliance and pilots for clean energy transportation; and Kelli Newman, senior marketing analyst for Georgia Power, discussed their utilities’ EV programs.

Durand sa id her group uses customer segmentation as the “backbone” of its research, breaking residential consumers into four groups. The “most engaged” segments are the Green Innovators, who care about sustainability, and the Tech Savvy Proteges, who embrace the “cool” factor of new technology, Durand said.

Next comes the Movable Middle: “They care a little bit about sustainability; they care a little bit about technology. They’re probably not going to do anything unless there’s an incentive, a program, marketing — some kind of thing that hooks them and gets them engaged. They will engage with the right program and messaging.”

Last, Durand said, are the Energy Indifferent. “They’re probably not going to engage. They generally are not interested in anything to do with energy. … We recommend just leaving them alone and focusing on the majority of consumers who do care or would engage.”

Clockwise from top left: Kelli Newman, Georgia Power; moderator Jamie Barber, Georgia Public Service Commission; Lydia Krefta, Pacific Gas and Electric; and Chris Budzynski, Exelon | NARUC

While only 1% of consumers currently own an EV, about 16% report they are very interested in acquiring one, and 29% are somewhat interested, Durand said. The numbers are higher for Green Innovators (29% very interested, 33% somewhat interested) and Tech Savvy Proteges (25/37%).

The segments are reflected in consumers’ willingness to pay more for an EV: A 10% increase in cost reduces interest among Green Innovators by 4 percentage points — from 51% to 47%. Interest from Tech-savvy Proteges also drops by 4 percentage points, from 40% to 37%. Interest among the Movable Middle drops 3 points from 27% to 24%.

EV Rate Design

Awareness of EV-specific rates is “extremely low” between 5 and 6% of the whole population, with even 91% of Green Innovators unaware, Durand said.

“We asked consumers, ‘If you have an EV, are you on an [EV] rate plan or would you sign up for a rate plan?’ And most consumers either didn’t answer the question or said ‘no,’” she said. “So, these are really terrible numbers for those who want EVs to be more common [and] want beneficial electrification to include transportation.”

She added: “It’s an easy-to-overcome barrier. Education is one of the easiest things to do. But this does show a problem with residential consumer awareness.”

Satchwell said some states have adopted “advanced” rate designs, including the unbundling of service costs (e.g., energy, capacity and ancillary services); hourly or sub-hourly marginal prices (vs. average utility costs); and include feeder-level or more granular marginal prices (vs. rates applied regardless of grid-specific locations).

The major debate in designing EV rates is whether they should be based on demand charges or time-of-use (TOU) rates, he said. “Demand charges can impact public charging by penalizing fast chargers, but they may, arguably, better match cost causation depending on how they’re designed,” he said. “EV supporters believe time-of-use rates are better for customer economics and better reflect that hourly marginal value.”

There are also multiple flavors of TOU rates, with some utilities offering multiple rate periods with mid-peaks and some offering super off-peak periods with significant discounts. The latter “sometimes have been referred to as matinee pricing — the same way that theaters … used to try and fill seats during the middle of the day with a huge discount,” he said.

Utilities have multiple flavors of time-of-use rates, with some offering super off-peak periods or “matinee” pricing. | Lawrence Berkeley National Lab

Some utilities offer flat “all-you-can-charge” monthly fees, such as Austin Energy, which charges $30/month but prohibits charging during peak hours.

There are also differences in metering requirements for home EV chargers. For example, Georgia Power’s whole home rate applies to all household electricity usage, which eliminates the need for additional equipment or changes to data collection and billing systems. But it can be a disincentive to EV charging if the rate is tiered with inclining block rates.

In contrast, Austin Energy’s EV-only rate requires a separate sub-meter and dedicated circuit, adding costs, but can allow clearer cost-based price signals.

Rates for commercial customers — such as fleet owners and public charging stations — are more likely to include locational and temporal specificity. San Diego Gas & Electric’s Power Your Drive program charges customers based on the CAISO day-ahead market price, with an adder for the top 200 distribution feeder load hours.

San Diego Gas & Electric’s Power Your Drive program for commercial customers is based on the CAISO day-ahead market price, with an adder for top distribution feeders. | San Diego Gas & Electric

PG&E’s Business EV rate, which took effect Oct. 1, replaced demand charges with a monthly subscription charge, which the company said lowers charging costs by 40% on average. The subscription fee, based on whether consumption is above or below 100 kW, is combined with TOU rates.

PG&E also is seeking regulators’ approval for a pilot project using dynamic hourly rates for commercial customers, also based on CAISO day-ahead prices.

The company powers more than 303,000 EVs in its service territory and offers $800 rebates. EVs’ share of new vehicle sales in the territory peaked at 14% in 2018 before the federal Tesla tax rebate expired. It dropped to 12% in the first quarter of 2020 before falling to 6% in the second, when the coronavirus pandemic hit the state.

In Georgia, EVs’ share of new car sales peaked at 3% in 2015, when the state offered a $5,000 tax credit. After the credit expired, the share dropped to less than 0.5% but has neared 1.5% since mid-2019. “We’ve now started to see more organic growth, and we attribute this to the affordability of some Tesla models now,” Newman said. “People who got familiar and comfortable with EV driving back in 2015 are now starting to buy electric vehicles again.”

Georgia Power’s rates range from 1 cent/kWh for super off-peak charging (11 p.m.-7 a.m.), 7 cents for off-peak (which varies by month and weekdays vs. weekends) and 20 cents for on-peak (2-7 p.m. June through September). It said drivers that spend $170/month on gasoline would pay only $19/month in charging fees if they limited their charging to the super off-peak period.

Satchwell discussed how customers respond to EV rates, based on a review of 11 evaluation reports of offerings published between 2013 and 2020, most of them short-term pilots. Most of the pilots had at least a 2:1 peak-to-off-peak price ratio, with a small number having a ratio of 4:1 or greater. Not surprisingly, higher peak-to-off-peak ratios result in more off-peak charging, he said.

PVs and EVs

But customers who owned a PV system were significantly less responsive to prices than their non-PV counterparts, according to a review of an SDG&E residential EV rate pilot. “This maybe suggests that PV customers place a higher value on [selling PV electricity back to the grid] than the increased electric costs for EV charging,” he said. “Certainly, there’s more here to unpack.”

Durand said she was shocked by her group’s finding that 50% of those with rooftop solar also own an EV.

“The interest was very high,” she said. “If as a stakeholder, you’re interested in more EV purchasing or finding customers interested in EVs, pursuing the consumers who have solar … or having policies that help consumers get solar, is a way to accelerate the transition to EV ownership.”

Government, Utility Incentives

Satchwell said that although some utilities encourage adoption of EVs through small rebates in partnerships with car dealers, federal and state tax credits have been the primary financial incentive to reduce that upfront cost of EVs to customers.

Satchwell’s review of 30 proceedings in 19 states found that about 85% of capitalized utility costs are for EV charging infrastructure on the customer-side of the meter, which addresses “range anxiety” and allows customers to participate in retail and wholesale market opportunities to sell power back to the grid, where available.

Some utilities’ investments have been to modernize their distribution grid, which can provide benefits for all customers, not just EV owners, he added.

Georgia Power is offering business customers $500 rebates on Level 2 chargers on 240-V circuits for workplace and customer charging. It is offering residential customers $250 rebates on Level 2 chargers and offering builders $100 rebates for installing 240-V garage outlets in EV-ready homes.

Car Dealers’ Lackluster Support

Durand said car dealers could encourage EV sales by pointing out that while their purchase price is higher than gasoline vehicles, they are cheaper over the long-term due to lower maintenance and fuel costs.

Dealers “don’t know enough about [EVs]; I usually come in knowing more than they do,” she said. “They are underwhelming in their endorsement of an EV. The total cost of ownership (TCO) is something that consumers don’t understand. Utilities could work with dealers and have TCO stickers on the cars so that customers can browse the lot and see: ‘Oh, this costs a little more upfront but then by year two I’m really saving money. Or the stickers could include state and federal incentives, which consumers don’t understand or know much about.”

November 10, 2020

PJM MIC Briefs: Nov. 5, 2020

PJM stakeholders last week endorsed the RTO’s package of updates to real-time value (RTV) market rules that call for additional penalties for generation operators that abuse the rules.

The RTO’s package was endorsed with 73% support at last week’s Market Implementation Committee meeting. In a nonbinding poll, the package received 55% support over maintaining the status quo.

Laura Walter, senior lead economist for PJM, provided an update on the work completed during the MIC’s special sessions on the rules and reviewed the proposed packages from the solutions matrix.

The special sessions have been taking place since January, after stakeholders endorsed an issue charge at the Markets and Reliability Committee’s meeting in December. (See “Real-time Values,” PJM MRC Brief s : Dec. 19, 2019.) The problem statement said observations indicated RTVs were being used to consistently override unit-specific parameter limits or parameter-limited exceptions.

The original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources could not meet their unit-specific parameter limits or exceptions, Walter said. Generators opting to use RTVs forfeit operating reserve credits and make-whole payments.

The PJM package would require that market participants repeatedly failing to reflect actual operating conditions in their submitted operating parameters could be referred to FERC for enforcement. A market participant would be required to enter a forced outage ticket into PJM’s Generator Availability Data System (eGADS) for the period of increased notification, start-up time and/or minimum downtime.

For the timeline of an RTV submittal, Walter said, the package would require that the requested time period not exceed one market day. She said that when an RTV is requested, it would be available for that one day; then the entire schedule would revert to the previous day’s values.

The package also calls for adding RTVs to the Tariff. Currently, RTVs are mentioned only in the manual, Walter said.

In a nonbinding poll conducted in August, 55% of stakeholders said they supported the PJM package, and 10% gave support for a package by the Independent Market Monitor, while 71% said they were satisfied with the status quo.

Details of the Monitor’s package were also presented. In a vote held after the PJM package, the Monitor’s only garnered 8% support.

The Monitor’s proposal included removing minimum run time from the list of eligible parameters with RTV submissions. It also said units that choose to run longer could self-schedule beyond the minimum run time, with PJM operator notification.

The proposal also would have aimed to prevent withholding by using longer minimum run times. Any penalties collected would have been allocated to daily real-time load.

The PJM package will now move on to the MRC in December for a first read.

Manual 11 Revisions Endorsed

Stakeholders unanimously endorsed updates to Manual 11 designed to increase transparency and conform to the current PJM process for calculating LMPs as part of the problem statement regarding five-minute dispatch and pricing.

Vijay Shah, senior engineer in real-time market operations for PJM, reviewed the proposed updates to Manual 11: Energy & Ancillary Services Market Operations. The changes include an added reference to the day-ahead and real-time sections in section 2.2: Definition of Locational Marginal Price and change “LMP verification” to “price verification” throughout section 2.10: Verification Procedure, as verification includes review of real-time and ancillary service prices.

In section 2.11: Price-Bounding Violations, language was updated to state that all interval prices will be posted, Shah said, and any intervals that do not pass an output consistency check will be indicated on PJM’s website. The section was not included in the first read of the changes at the MIC meeting in October.

Shah said the changes are not related to the five-minute dispatch and pricing short-term changes that were filed with FERC in July. (See PJM Stakeholders OK 5-Minute Dispatch Proposal.)

Public Distribution Microgrids

Natalie Tacka, an engineer in PJM’s applied innovation department, reviewed a proposal and provided a first read of updates to Manual 11: Energy & Ancillary Services Market Operations and Manual 18: PJM Capacity Market regarding business rules for public distribution microgrids.

Tacka said work on the issue first began last year in the former Distributed Energy Resources Subcommittee (DERS) and has continued into the new DER and Inverter-Based Resources Subcommittee (DIRS).

A microgrid is defined as a system of generating facilities and load that can operate both while connected to and off the main grid, Tacka said. PJM is looking to define a public distribution microgrid as a microgrid that contains a PJM generating facility that can generate while connected to and “islanded” from the broader grid and uses public utility distribution wires.

PJM’s public distribution microgrid concept | *PJM*

Tacka said a public distribution microgrid would not include any NERC bulk electric or transmission facilities. The electric distribution company will determine if the public distribution microgrid is wholesale or retail when islanded.

The Manual 11 language includes provisions for reflecting islanded conditions in a resource’s availability for energy and ancillary services, Tacka said, while Manual 18 language adds clarification for performance assessment interval treatment of public distribution microgrids serving as generation capacity resources.

The committee will be asked to endorse the manual changes at the MIC meeting in December.

UTC Uplift Changes

Ray Fernandez, manager of market settlements development for PJM, provided a first read of updates to Manual 28: Operating Agreement Accounting to conform with changes ordered by FERC regarding uplift charges on up-to-congestion (UTC) transactions (EL14-37).

In its order issued in July, FERC determined that PJM’s current uplift allocation rules are unjust, unreasonable and unduly preferential because they do not allocate uplift to UTCs. (See FERC Orders Uplift Charges on PJM UTCs.)

PJM was directed by the commission to submit a replacement rate that revises the RTO’s current uplift allocation rules to allocate uplift to UTCs “in a manner that treats a UTC, for uplift allocation purposes, as if the UTC were equivalent to a [decrement bid] at the sink point of the UTC.”

Fernandez said UTCs will now be allocated in both real-time and day-ahead uplift.

PJM is seeking stakeholder endorsement of the manual changes at the December MIC meeting.

November 10, 2020

PJM Operating Committee Briefs: Nov. 6, 2020

PJM stakeholders last week unanimously endorsed proposed changes to the 2021 day-ahead scheduling reserve (DASR) requirement that saw small changes from last year.

David Kimmel, PJM senior engineer of performance compliance, reviewed the preliminary proposed changes at last week’s Operating Committee meeting, along with updates to Manual 13.

The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations. It is the sum of the three-year averages of both the under-forecasted load forecast error (LFE) and eDART forced outages.

Kimmel said the final 2021 DASR requirement is 4.74%, slightly lower than the 2020 requirement of 5.07%. He said the number comes from the LFE component of 2.16%, which is up 0.01% from last year, and the forced outage component of 2.59%, down 0.33% from last year.

The final 2021 DASR value will be incorporated into Manual 13 changes and be implemented in January.

Winter Weekly Reserve Target

The committee also unanimously endorsed changes to the 2020/21 winter weekly reserve target, which changed slightly from last year’s.

2020/21 winter weekly reserve targets | *PJM*

Patricio Rocha Garrido of PJM reviewed the results of the winter weekly reserve target analysis. The targets for December, January and February are 23%, 27% and 23%, respectively, compared to 22%, 28% and 24% last year.

“These increases and decreases are based on the load uncertainty we have in our most recent reserve requirement study case,” Rocha Garrido said. “However, the values are very close, so it doesn’t make much of an impact.”

Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling and cover against uncertainties by ensuring that the loss-of-load expectation (LOLE) for winter is “practically zero,” Rocha Garrido said. For the entire year, PJM sets the LOLE at one occurrence in 10 years.

The winter weekly reserve target for each month is the highest weekly reserve percentage, Rocha Garrido said, rounded up to the next integer value.

Manual Endorsements

Stakeholders also unanimously endorsed several minor manual changes.

Maria Baptiste of PJM reviewed updates to Manual 3A: Energy Management System Model Updates and Quality Assurance. Baptiste said the changes include correcting grammatical mistakes and updating references to the behind-the-meter generation rules that took effect in September 2019. (See “Non-retail BTM Generation Rules Endorsed,” PJM MRC/MC Briefs: Sept. 2 6, 2019.)
Lagy Mathew of PJM reviewed updates to Manual 3: Transmission Operations. Mathew said the changes featured minor clarifications, including defining extra-high voltage lines as those equal to or greater than 345 kV.
Kevin Hatch of PJM reviewed updates to Manual 12: Balancing Operations to address changes from the Market Implementation Committee’s special sessions on five-minute pricing and dispatch. Hatch said the RTO has been working with the Independent Market Monitor to identify sections of Manual 12 to be updated and to improve transparency on the dispatch process. Hatch said the changes include updated terminology for “day-ahead market” instead of the outdated “two-pass system.”

November 10, 2020

Texas PUC Approves ERCOT Board Members

Texas regulators last week approved the election of Michigan Public Service Commissioner Sally Talberg and two others to three-year terms on ERCOT’s Board of Directors.

“I’m not trying to pick favorites, but I’m so excited to have Sally Talberg back,” Texas Public Utility Commission Chair DeAnn Walker said during the commission’s open meeting Thursday. “I’m glad to have her back in the ERCOT group.”

Walker said that Talberg approached her recently and asked her advice about joining the ERCOT board.

“I said absolutely,” Walker said. “I’m glad to have her back in the ERCOT group.”

Talberg advised the PUC from 2000 to 2004 during Texas’ transition to retail competition. Pat Wood III chaired the PUC at the time and would go on to also chair FERC under President George W. Bush. Judy Walsh, due to cycle off ERCOT’s board after this year, also served on the commission then.

While working on a master’s degree in public affairs from the University of Texas at Austin, Talberg also worked at the nearby Lower Colorado River Authority.

Talberg told RTO Insider she had expressed her interest in joining the ERCOT board some time ago, “initially thinking it would be some far-off prospect after serving on the MPSC.”

“But these spots were opening, so it happened earlier than I anticipated,” she said.

Talberg was first appointed to the PSC in 2013, serving as chairman from January 2016 to July 2020. Her term expires next July, but she has said she will step down from the commission once her appointment to the ERCOT board is official. (See “Michigan PSC’s Talberg Among Director Nominees,” ERCOT Board of Directors Briefs: June 9, 2020.)

The PUC also approved the elections of retired ISO-NE General Counsel Raymond Hepper and incumbent Director Terry Bulger to the ERCOT board. All three will serve as unaffiliated directors.

The board’s Nominating Committee has put forward former Consolidated Edison CEO Craig Ivey for the final vacant seat. Ivey will be presented to members during their virtual annual meeting in December.

D’Andrea Jumps the Gun

During the PUC’s open meetings, Walker typically opens discussion of a docket by saying she has written a memo with suggested changes. Commissioners Arthur D’Andrea and Shelly Botkin then usually express their agreement and approve the order.

The practice caught D’Andrea off-guard last week as Walker opened discussion of Oncor’s request for a limited code-of-conduct waiver from the commission’s affiliate reporting and affiliate transaction rules (50893).

ERCOT — Commissioner Arthur D’Andrea agrees with Chair DeAnn Walker’s nonexistent memo. | *Texas PUC*

“I agreed with your memo…” D’Andrea began.

“I didn’t have a memo. Arthur, why are you making it harder?” Walker responded, teasing D’Andrea. The few staffers in the socially distanced hearing room erupted in peals of laughter.

The commissioners agreed they had no concerns with the affiliate issue and approved the order.

Nuke Decommission Fund Remanded

The commission remanded back to docket management the Comanche Peak nuclear power plant’s requested review of its decommissioning cost study and funding analysis, finding that they do not include evidence required by Texas ’ a dministrative c ode (50945).

Walker noted in a memo that the study and analysis were not accompanied by a report or supporting testimony and the requested annual funding amount; the decommissioning trust fund’s administrator did not demonstrate the funds are being invested prudently and in compliance with their investment guidelines; and the administrator did not demonstrate efforts to achieve “optimum tax efficiency.”

Comanche Peak Power Co. (CPPC) administers the decommissioning fund. It wants to continue the fund’s annual contribution of nearly $20.1 million through 2025, split between the plant’s two units on a 72.3/27.7% basis. The current approved allocation amount is on a 57.1/42.9% split.

CPPC said the two units have a net after-tax value of $1.32 billion. It says according to a May decommissioning cost analysis, it will cost $1.73 billion in 2019 dollars to decommission and completely dismantle Comanche Peak. The analysis shows about a -2.5% difference between the $19.4 million required funding levels and the five-year average decommissioning-fund collections of $19.9 million annually from 2015 to 2019.

In other actions, the PUC:

authorized Southwestern Electric Power Co.’s (SWEPCO) and El Paso Electric’s (EPE) adjustments to their energy efficiency cost recovery factors. SWEPCO will be allowed to recover $5.2 million (50805) and EPE $5.9 million during the 2021 program year (50806).
allowed EPE and Entergy Texas to issue fuel refunds following settlement agreements. EPE will refund $9.4 million (50940) and Entergy $25.5 million (51037) to ratepayers.

November 10, 2020March 9, 2025

Soapbox: It’s Time for Transparency in the Grid

Mike Jacobs | UCS

By Mike Jacobs

Replacing the fossil-fueled energy supply with renewable energy requires unusual focus and substantial investment in the electricity sector. Our ability to meet these needs — elevated by climate change and the COVID-19 crisis — depends on the success of RTOs and ISOs. We at the Union of Concerned Scientists work to make these institutions more transparent, understood and responsive to science and democratically established laws.

The RTOs/ISOs evolved over decades and matured in the 1990s through a combination of electric utility industry and government regulatory desire for cooperation and efficiency. Coordination in the utility industry through competition and innovation becomes harder when the RTOs/ISOs ignore the public interest in further decarbonizing energy. The conflict between an energy market system that ignores external costs and a society and its policymakers that see the health and climate impacts of pollution from energy can’t be ignored.

These organizations have demonstrated they can deliver savings and integration of high levels of renewables.

Utilities are Different

The difference between RTOs/ISOs and better known trading platforms, such as Lyft, Uber, eBay and Amazon, is that the grid operators were established by existing monopolies. But those monopolies did not anticipate renewable energy growth driven by policy, economics or carbon limits. The influence of the incumbent players in making the rules is not found in the better known platforms. How much do the existing asset owners influence new energy technologies in the market? We can take a look at how open, transparent and interested in emissions these grid operators are.

We Have Work to Do

The RTOs/ISOs are at varied and different places on transparency and consideration of climate impacts. Broadly, the RTOs/ISOs provide regional coordination and sharing reserves through power pools that benefit consumers, allow competition and further cost savings and technology innovation. But how well does this structure, set up with advantages for the owners of existing power plants, serve to protect the climate and implement state carbon-reduction policies? When policymakers push the external costs of carbon and health into decisions that can lower carbon emissions, RTOs/ISOs should not counteract those policies and raise costs to consumers.

Transparent and Open?

Transparency builds trust. Stakeholders have to know how decisions are influenced. The public needs to know what decisions are being made.

How well members, stakeholders or even the public follow the decision-making depends in large part on the posting of meetings scheduled, agendas and the minutes of what was discussed. UCS was quick to support press access to NEPOOL when access was denied. But a wider look at the mere posting of meeting dates and agendas for the RTOs/ISOs’ governing boards differ sharply from one regional grid to the next.

In PJM, there is no schedule of board meetings available and no minutes, leaving stakeholders unsure of discussions or changes to items on which members had voted. The ISO-NE board’s meeting dates and bare agenda are available, but minutes are not. At NYISO, board meetings can be open to regulators upon request, and minutes and future dates are published. MISO mails out notices of board meetings, and even the committees of the board hold open meetings. SPP posts meeting notices and extensive minutes and materials. CAISO holds open meetings with video recordings posted on YouTube!

Carbon-aware?

The RTOs/ISOs operate in parallel (and lately in conflict) with state laws that regulate utilities and provide consumer protections, as well as with health and safety protections that address environmental externalities. The New England States Committee on Electricity’s recent vision for the grid connected the lack of transparency in stakeholder and ISO-NE board processes with the need for market reforms suited to “the New England states’ legal requirements, policy imperatives and associated consumer interests.”

New York state CO2 emissions by sector | NYISO, using U.S. EIA data

There is a wide range in how the RTOs/ISOs keep informed and share data about emissions from power plants. Ten to 15 years ago, some ISOs developed a report of average marginal emissions for the evaluation of pollution savings from state energy-efficiency programs. Today, climate change driven by accumulated greenhouse gas is a bigger concern. Reporting totals of emissions over a year and by month or season will help decision-makers facing a wider variety of options to change fossil fuel use and cumulative emissions.

NYISO established an Environmental Advisory Council in 2004 that provides it with reports that include average marginal emission rates from its generation, as well as the cumulative CO2 emissions in New York from all sectors (drawing data from the U.S. Energy Information Administration). PJM reports only the average marginal rate of emissions, released each spring, and it is impossible to determine if this report is shared with the RTO’s board because there is no transparency. ISO-NE has, since 1993, made a similar annual report of marginal rates of emissions, though with an 18-month delay from the end of the year. CAISO makes monthly reports of emissions. SPP makes none.

Changed Energy Mix

Reporting on the energy mix is another measure of improvement on climate-harming emissions. SPP does post data showing enormous use of wind energy. In the spring and fall, SPP’s energy supply mix is routinely as high as 50% wind. All the other RTOs/ISOs also display their current energy mixes on their websites. These kind of data on the resources meeting electricity demand are fundamental to the RTO/ISO function. Such displaying and archiving of energy data is a minimal level of transparency not found from utilities outside the RTOs/ISOs.

The accumulation of CO2 in the atmosphere comes from the cumulative emissions from combustion (and other biological sources). A decent comparison and metric for RTO/ISO boards to monitor would show total greenhouse gas emissions from power plant operations, along with the sort of data EIA provides on fuel-burning emissions in other sectors of the economy in their regions. That reporting would allow RTO/ISO boards to monitor changes as members and utilities pursue electrification and electricity replaces fossil fuel in building and transportation. RTO/ISO boards should receive a report annually on how the grids they manage are affecting the climate.

What We Need from RTOs

Regional cooperation to meet energy demand requires transparency and openness now, as the public, leaders and utility industry members meet the challenge of climate change and decarbonize energy. Leaders of all these organizations need metrics reflecting their own operations and markets, both for daily business and for addressing climate-damaging emissions of carbon and methane.

People in government need the informed cooperation of citizens and corporations to implement policy on climate. With all the decision-making ahead, the RTOs/ISOs are going to be key for people, their polices and utilities to work together in new ways to move off climate-damaging fuels.

The New England states are asking for change from their RTO. The Mid-Atlantic states are in court over their RTO’s objection to renewable energy policy. We have to decide: Are these organizations up to the task?

Mike Jacobs is a senior energy analyst for the Union of Concerned Scientists with expertise in electricity markets, transmission and renewables integration work.

November 10, 2020

MISO to File Emergency Pricing Changes

MISO said it will file with FERC updates to its emergency pricing design by the end of the year, hoping to spur more action from suppliers when conditions get risky.

The changes involve two new minimum-offer floors, expanding the definition of fast-start resources and integrating costs of its Midwest-to-South transmission limit into prices.

The RTO will introduce two new minimum emergency-offer floors: $500/MWh for maximum generation warnings and $1,000/MWh for maximum generation events.

MISO Market Design Adviser Michaela Flagg told the Market Subcommittee on Thursday that the new floors “reflect the value of emergency supply” and said the $1,000/MWh minimum lines up with the grid operator’s established threshold of how much it’s willing to pay before entering an emergency.

Customized Energy Solutions’ Ted Kuhn urged MISO to move away from static numbers in its proposal. He said tying the emergency-offer floors to the RTO’s current value of lost load (VOLL) and operating reserve demand curve is short-sighted, especially because it is considering an increase to its outdated VOLL figure.

The VOLL has been unchanged since 2009. At the time, $3,500/MWh was the estimated price at which some customers would opt for service interruption.

“That $1,000 number is going to be quite different in perhaps the very near future,” Kuhn said.

Along with the new offer floors, MISO said it will extend resources’ eligibility to set LMPs during emergency conditions. It plans to include online resources with four-hour or less start-up times in the fast-start definition during maximum generation alerts, warnings and events.

MISO emergency pricing — MISO emergency procedures | *MISO*

MISO’s current fast-start definition requires resources to fire up within 10 minutes of notification and run for at least an hour.

“We really saw the benefits drop off after four hours, so four hours seems to be a sweet spot,” Flagg said. “It allows a lot of these resources to participate in pricing.”

Flagg said allowing a short-lived relaxation of the fast-start lead time requirement in emergencies “better aligns with the real-time commitments made during emergency operations.” Staff say it is common during emergencies for operators to commit resources with notification and start-up minimum run times between one and four hours.

“During emergency conditions, the fast-start resource definition does not align with resources committed in real-time and, therefore, prices are not able to reflect the full costs of units needed to meet system demand and reserve requirements,” MISO said.

The grid operator also wants to better incorporate into energy prices the cost of managing its Midwest-to-South transfer limit.

To do that, MISO will set a marginal value of $200/MWh on its reserve procurement enhancement constraint management.

Under the existing reserve procurement enhancement (RPE), MISO models the effects of transmission constraints on the deliverability of reserves and adds the marginal cost of delivering them to zonal reserve market-clearing prices. The RPE ensures reserves are deliverable within the Midwest and South regions and that MISO doesn’t violate its megawatt limits on the Midwest-South transmission constraint for longer than 30 minutes. The settlement agreement governing the constraint stipulates that the grid operator not exceed the contractually set megawatt limits for longer than 30 minutes.

MISO says the marginal value limit assigned to the constraint — currently administratively set between $20 and $40/MWh — does not reflect the value of meeting the reliability requirement, resulting in “insufficient reserves being cleared in the sub-region and inefficiently low prices.” The grid operator said $200/MWh is more appropriate, according to its studies.

MISO said most of its sub-regional emergencies are called “due to limited transfer capability” over the Midwest-South constraint.

VOLL Questions over Hurricane Laura

Some stakeholders continue to question whether Hurricane Laura’s landfall on Aug. 27 near the Texas-Louisiana border was the right time for MISO to administer VOLL pricing.

Laura’s landfall saw MISO’s first administrative load-shed orders and VOLL usage. (See MISO Keeps Advisories in Effect a Week After Laura.)

Xcel Energy’s Kari Hassler said that because VOLL pricing was applied after-the-fact, generator actions as the event unfolded were motivated by circumstance, not pricing.

“I don’t want to say it was a misuse of VOLL, but it didn’t incent generators,” Hassler said.

WPPI Energy economist Valy Goepfrich said she pictured VOLL discerning cost-causation and not for use “during a disaster.” Other stakeholders agreed that cost-causation is difficult to trace in a natural disaster.

November 9, 2020

UPDATED: Nevada Clean Energy Amendment Winning

[UPDATED Nov. 9 11:25 a.m. ET to reflect election results.]

A measure in Nevada to enshrine a clean energy mandate in the state constitution is heading to victory, while New Mexico voters approved an overhaul of their state’s Public Regulation Commission, and Arizonans elected another Democrat to the state’s Corporation Commission.

Votes remained uncounted in Nevada, but ballot Question 6 was leading 57% to 43% as of Sunday night, according to the secretary of state’s website. The measure asked voters for the second time in two years if the state should make clean energy goals a part of its constitution.

A law signed by Democratic Gov. Steve Sisolak in April 2019 requires the state to get half its electricity from non-carbon-emitting resources by 2030, but environmentalists worried it could be overturned by elected officials if the political winds shift and sought a more permanent solution.

Amendments to Nevada’s constitution must be approved in two consecutive elections, so the question faced a final vote this year after winning 59% support in 2018. That effort, like the current one, was bankrolled by California billionaire and environmental activist Tom Steyer. (See Climate Policy on the Ballot Tuesday.)

An array near Las Vegas is among the utility-scale solar projects that Nevadans increasingly rely on for renewable power. | *U.S. Bureau of Land Management*

New Mexico

New Mexicans voted 55% to 45% for a constitutional amendment to revamp the PRC from a five-member body elected by district to a three-member body of at-large utility commissioners appointed by the governor.

A nominating committee will make recommendations of “professionally qualified nominees” under the measure, which prohibits more than two of the PRC’s members from belonging to the same political party. The new law replaces commissioners’ staggered four-year terms with six-year appointments.

It takes effect Jan. 1, 2023, ending the terms of elected members at the close of 2022.

Two members of the PRC backed the ballot measure, arguing that utility regulators should have experience in the complex field. Some of those elected to the PRC lack the backgrounds needed to understand and rule on regulatory issues, Commissioners Cynthia Hall and Stephen Fischmann wrote in an opinion piece published in a number of the state’s newspapers.

“The public and the utility companies that serve them deserve to have commissioners with meaningful expertise when they begin working as commissioners,” Hall and Fischmann wrote. “That means graduate-level education plus significant industry or regulatory experience. Commissioners should be experts at the outset, not rookies.”

Hall was re-elected to a two-year term on the commission Tuesday; Democrat Joseph Maestas was newly elected to an open seat.

Other members of the PRC contended that allowing the governor to appoint its members would deprive voters, especially those in rural disadvantaged communities, of the opportunity to influence ratemaking and policy decisions.

“There is no requirement for any sort of geographic representation, which makes it extremely likely that the commission would be dominated by members from the urban population centers rather than rural New Mexico,” Commissioners Theresa Becenti-Aguilar and Jefferson Byrd wrote in a competing op-ed.

Commissioners were also divided in their support of a landmark law from 2019 that requires the state’s investor-owned utilities to get 100% of energy from carbon-free sources by 2045. Both Hall and Maestas support the measure.

Arizona

In a close and contentious race for three seats on the ACC, Democratic newcomer Anna Tovar led a pack of six candidates to win election, along with two Republicans. Tovar, one of a slate of three Democrats backed by New York billionaire Michael Bloomberg, secured nearly 18% of votes cast.

Republican incumbent Lea Marquez Peterson came in second with 17%, closely followed by Republican Jim O’Connor, who had a similar vote tally.

Left behind were Democrats Bill Mundell and Shea Stanfield and Republican Eric Sloan, each of whom fell short of the top three vote getters.

Potentially at stake in the race is an Oct. 29 commission decision to adopt a 100% clean energy mandate by midcentury. California, New Mexico and Washington also have 100% clean-energy

The commission, which currently has four Republicans and one Democrat, voted 3-2 for the mandate. Chairman Bob Burns and Commissioner Boyd Dunn, neither of whom sought re-election, voted with Democrat Sandra Kennedy in support of the measure.

With the two Republicans winning office, the decision could be reversed. Republican Commissioner Justin Olson expressed his dismay with the potential cost to ratepayers in a statement after the Oct. 29 vote. Marquez Peterson opposed the move. And O’Connor said he would vote to reverse the decision if elected, The Arizona Republic reported.

November 8, 2020

CAISO Further Reorganizes Executive Suite

CAISO said Friday it was continuing to shake up its leadership team under new CEO Elliot Mainzer and recently appointed Chief Operating Officer Mark Rothleder.

The reorganization, which takes effect Monday, is a combination of promotions, expanded duties and interim appointments. All the executives involved will report to Rothleder, CAISO said. (See CAISO Leadership Changes Continue.) The changes will also bring together previously separate functions, including market policy, planning and operations, the ISO said.

“This restructuring will give us the opportunity to look at our roles and responsibilities from a fresh perspective and enhance alignment and integration from market policy to system dispatch,” Rothleder said in a news release.

Among the personnel changes:

Khaled Abdul-Rahman, executive director of power systems and smart grid technology development, will become vice president of power system and market technology.
Anna McKenna, assistant general counsel for regulatory issues, will step in as interim head of market policy and performance, Rothleder’s prior job, while CAISO searches for a replacement.
Neil Millar, recently appointed as vice president for transmission planning and infrastructure development, will have an expanded role, including overseeing operations engineering services.
John Phipps, director for real-time operations, will become executive director of grid operations.
Janet Morris, executive director of program management, will take on an expanded role as executive director of program and application management.
Hugo Frech, director of infrastructure engineering and network operations, will be promoted to executive director of the same areas.

“I would like to congratulate Mark and Khaled on their executive promotions and to thank the other members of my skilled leadership team who have stepped into new roles to support this reorganization,” Mainzer said in a statement.

Mainzer, the former head of the Bonneville Power Administration, became CEO on Sept. 30, a day after former CEO Steve Berberich retired. (See CAISO Retiring, Incoming CEOs Field Questions.)

One of Mainzer’s first actions was to promote Rothleder, one of several vice presidents at the ISO, to his new role as second-in-command.

Mainzer will oversee the redesigned executive organization.

“The new team will enable Mainzer to focus on strategy, culture and stakeholder engagement while strengthening the ISO’s capacity to effectively integrate new resources and enhance reliability during the transition to a decarbonized electricity grid,” CAISO said.

November 8, 2020

NY Power Panel Looks at Methane, Renewables

The New York Climate Action Council’s Power Generation Advisory Panel on Thursday decided to take on the issue of methane gas leakage as part of an effort to scope out by next fall a statutorily mandated path to reduce the state’s greenhouse gas emissions 40% by 2030 and no less than 85% by 2050.

New York PSC Chair John B. Rhodes | *New York DPS*

“After good discussion about the narrower methane leaks and associated emissions and safety consequences on the natural gas system, we’re going to turn this analysis into statements that reflect collective thinking,” said John B. Rhodes, chairman of both the panel and the state’s Public Service Commission. The panel is one of six, each sector-specific, advising the CAC.

The panel also discussed the broader issue of developing and integrating renewable energy resources onto the New York grid.

The Climate Leadership and Community Protection Act (CLCPA) directs the state’s Department of Environmental Conservation (DEC) to include upstream emissions in its statewide emission calculations. New York on Oct. 27 concluded its hearings and public comment process on statewide emissions limits for 2030 and 2050 proposed by the DEC — 60% and 15%, respectively — of estimated 1990 GHG emissions. (See New York Holds Final CLCPA Emissions Hearings.)

The Future of Gas

Kit Kennedy, director of energy and transportation for the Natural Resources Defense Council, said that addressing methane leakage is a natural part of dealing with GHG emissions, but that it should be done in a way that doesn’t extend the life of the natural gas system.

“We do know we are going to have to get off gas to meet the CLCPA goals, at least fossil gas,” Kennedy said. She said she was concerned about language indicating a continued need for natural gas in the near to medium term. “I don’t know what that means, [as well as] needing gas to ensure reliability. I prefer that we keep those issues as distinct as possible.”

New York’s GHG emissions in 2015 were virtually unchanged from 1990 levels, according to a recent study that highlights upstream impacts and the role of methane under the state’s revised reporting rules. (See NY Study Highlights Rising Methane Emissions.)

New York Power Panel — A 100-year time frame map of methane (CH4) emissions by county in New York state in 2017; officials expect in January to issue the 20-year time frame study mandated by the CLCPA. | *NYSERDA*

The issue of methane leakage is inexorably tied with a solution for the missing 25% of emissions reductions in 2040, said John Reese, senior vice president of Eastern Generation, which controls approximately 5,000 MW of generation in the state, including some peaker units.

“We need to look at what it takes to mitigate the leakage, and [if we are] going to use the natural gas system infrastructure system going forward to meet some of the other needs that currently are unfilled in 2040,” Reese said. “Looking at this in a stovepipe or isolated manner will be problematic. The impact piece of this is the first step before we can look at how we go about dealing with this larger issue.”

Macy Testani, assistant project manager at the New York State Energy Research and Development Authority (NYSERDA), said that consumers, not utilities, pay for leaks from points beyond the main natural gas pipelines and that there is little incentive to fix the aging pipes that run to many residences and businesses. She referred to a 2019 study that breaks down the leakage in-state in terms of upstream, midstream and downstream sides, the latter contributing significantly to overall emissions attributed to gas infrastructure.

Rhodes interrupted to say that, “It is certainly the case that the state regulatory apparatus and the utilities are prioritizing repair to the riskiest stretches of leak-prone pipe, in this case being a safety concern of explosion.”

William Acker, executive director of the New York Battery and Energy Storage Consortium (NY-BEST), said that methane is more impactful but also more reactive, meaning a lot of the methane in the atmosphere is naturally consumed each year.

“You can stop the leaks, or you can react the methane and get rid of it,” Acker said. “It might be that there’s an economically viable path that stops the major leaks and reacts some of the methane to get rid of it. … Has there been any research on that, or is that an area being considered at all? … It may be a crazy idea.”

Testani said that NYSERDA and the DEC have not looked at the reactivity of methane in the current mitigation project, but “we’re at the point where we need all crazy ideas to consider.”

The CLCPA also requires that methane emissions be compared with CO2 over a 20-year period rather than the 100-year time frame still used by virtually all other governments in the world. Testani said NYSERDA expects to issue the draft 20-year time frame analysis in January.

Bring on the Renewables

The CLCPA requires that 40% of the benefits of state investments in clean energy reaches disadvantaged communities, which are often located near the dirtiest oil- and gas-fired peaker plants. The state is taking “an accelerated approach” to meeting those investment goals, said John Williams, vice president for policy and regulatory affairs at NYSERDA.

A big challenge in retiring those peakers “is not just a peaking issue; it’s also an overall energy production issue,” NYISO Executive Vice President Emilie Nelson said.

Many studies show that, especially in light of climate change, sustained periods of weather patterns, such as lulls in the wind or less sunshine in winter, are not conducive to high renewable output, she said.

“That could happen on a seasonal basis for quite a long duration, so it’s a daily cycle; it’s a seasonal cycle; so, that’s not just a peak issue,” Nelson said.

NRDC’s Kennedy brought up possible barriers to developing renewables, such as the buyer-side mitigation policies from NYISO that were partly rejected by FERC Rejects NYISO Bid to Aid Public Policy Resources.)

“Despite the new siting law in New York, siting and community concerns and opposition are still a big issue … as is access to all for renewables, which ties into equity and environmental justice concerns,” Kennedy said. “I’d also like us to dig a little deeper into some of the assumptions … like lack of suitable space for large-scale renewables downstate.” S

he urged panel members to “make sure we are not locking ourselves into traditional thinking.”

Lisa Dix, New York representative for the Sierra Club Beyond Coal Campaign, brought up barriers in NYISO to dispatching storage and said she wanted to “amplify the question mark” on the lack of space issue, suggesting that NYSERDA officials assessing build-ready sites look in New York City and Long Island.

“In the process of getting rid of dirty peaker plants, how will those sites be reused?” Dix said.

In response to Dix, Nelson said that in August, “NYISO did implement a full complement of storage rules that allow participation of storage directly in our energy markets. … So, there is an option for participation and dispatchability by storage resources within the wholesale markets.” (See NYISO’s 2nd Storage Compliance Almost Hits Mark.)