Page 470 – RTO Insider

May 30, 2022June 14, 2023

PJM MRC Briefs: May 25, 2022

Start-up Cost Offer Development Proposal Endorsed

Stakeholders at last week’s PJM Markets and Reliability Committee meeting unanimously endorsed a revised proposal from the RTO and the Independent Market Monitor addressing start-up cost offer development worked on through the Cost Development Subcommittee (CDS).

Tom Hauske, principal engineer in PJM’s performance compliance department, reviewed the joint proposal to revise Manual 15: Cost Development Guidelines, along with revisions to the tariff and Operating Agreement.

The CDS initially brought two proposals for first reads to the October MIC meeting, but a vote on the proposals was postponed, allowing for more discussions and stakeholders to reach consensus on a single proposal. (See “Start-up Cost Offer Development,” PJM MIC Briefs: Oct. 6, 2021.)

Manual 15 allows the start-up costs for combined cycle units to include fuel costs after generator breaker closure and synchronization to the grid, a feature not available to other unit types, such as steam and nuclear plants. The revisions align start-up costs for all units with a soak process, or units that use steam turbines.

For units with a soak process, including steam, combined cycle and nuclear units, some of the soak costs will be included in the start-up costs from PJM’s notification to the “dispatchable output” and from the last breaker open to the shutdown process.

Steam-unit-start-up-cost-offer-procedure-(PJM)-Content.jpg

PJM’s revised steam unit start-up cost offer procedure | PJM

Units that don’t have a soak process, like combustion turbines and reciprocating engines, maintain the status quo, with start-up costs that include costs from the time of PJM’s notification to the first breaker close and from the last breaker open to the conclusion of the shutdown process.

The approved revisions include several other changes to Manual 15 to provide additional guidance and clarification, Hauske said, such as equations to calculate start-up costs, station service calculations for units with and without a soak process, and unit-specific parameter limits on includable costs.

Manual 15 allows generators to include an additional labor cost in their start-up costs, Hauske said, but generators already are permitted to include the labor cost in the unit’s capacity offer through its avoidable-cost rate (ACR). The revisions eliminate the labor cost language in the tariff and OA offer cap sections and the start-up cost calculation so that all the operating labor is includable in the ACR.

PJM is providing a six-month window for implementation to allow market sellers the opportunity to have their fuel costs or net generation used for the offset to be reviewed by the Monitor prior to the revisions going into effect.

Hauske described the new start-up cost definition included in Manual 15, which states it will “consist primarily of the cost of fuel, as determined by the unit’s start heat input (adjusted by the performance factor) times the fuel cost. It also includes operating costs, maintenance adders, emissions allowances/adders and station service power cost. Start costs can vary with the unit offline time being categorized in three unit temperature conditions: hot, intermediate and cold.”

Adrien Ford of Old Dominion Electric Cooperative offered a friendly amendment that was adopted by stakeholders to the end of the definition, which says, “Units with a soak process include nuclear, steam and combined cycle units. Units without a soak process include engines, combustion turbines, intermittent and energy storage resources.”

Ford said the suggestion came from ODEC staff to “provide clarity” for the units impacted by the changes.

“We were just looking for it to be better defined upfront when you’re first reading this, so that the puzzle has some of the overview pieces up front, and then you can get into the detail pieces later,” Ford said.

DEA Proposal Denied

Members rejected a PJM proposal to address changes to the Designated Entity Agreement, sending the issue back for more stakeholder discussions.

The proposal, which PJM was seeking a quick-fix approach to make changes, received a sector-weighted vote of 2.51 (50.2%), falling short of the necessary 3.33 threshold for adoption.

FERC in February rejected a filing by PJM in its Order 1000 compliance docket that would have updated the definition of “designated entity,” agreeing with a coalition of stakeholders that it infringed on their due process rights. (See FERC Rejects PJM Redefinition of ‘Designated Entity’ Under Order 1000.)

Ken Seiler, vice president of PJM’s planning department, said the proposal was meant to accommodate the “lack of clarity” in the OA regarding the DEA. Seiler said the existing OA language is “a little too broad,” and PJM wanted to clear up the definition.

Seiler said PJM wants to look at all construction-related activities in the RTO to make sure the process is being done efficiently.

“We’d like to take a holistic look at everything and consider how this is impacting any risk to any stakeholders, consumers or ratepayers; how it’s impacting our ability to get work done; how it’s impacting our coordination with all the other projects coming through the [transmission planning] process,” Seiler said.

Augustine Caven, manager of PJM’s infrastructure coordination department, presented the proposal consisting of a problem statement, issue charge and OA revisions.

Caven said the OA language can be interpreted differently because of the “imprecise” use of the term “designated entity,” so PJM’s proposal called for several revisions to “eliminate the ambiguities” and “align the OA language with the intent and use of the DEA.”

“Given the urgency associated with compliance considerations and the narrow scope of the issue charge, PJM believes this issue is well suited for the quick-fix process,” Caven said.

Several stakeholders questioned the use of the quick-fix process on the issue, saying the complexity of DEAs warranted more in-depth discussions.

Two different alternatives to PJM’s proposal were also presented for stakeholder consideration. Greg Poulos, executive director of the Consumer Advocates of the PJM States, offered an issue charge on behalf of the Delaware Division of the Public Advocate to allow for more education on the DEA process and the formation of a senior task force to work on any possible OA changes if needed.

Denise Foster Cronin of the East Kentucky Power Cooperative presented an alternative issue charge from EKPC, Exelon and Public Service Enterprise Group that called for endorsing PJM’s OA changes and also starting a stakeholder process to discuss other possible changes to the DEA.

In a sector-weighted vote of 3.95 (79%), members voted to table the two additional proposals until the June MRC meeting.

Dynamic Line Ratings Proposal Endorsed

Members unanimously endorsed PJM’s proposal and manual revisions supporting the interim integration of dynamic line ratings (DLRs) into its operations.

Chris Callaghan, PJM senior business solution engineer, reviewed the proposal that included corresponding revisions to Manual 1: Control Center and Data Exchange Requirements, Manual 3: Transmission Operations and Manual 3A: Energy Management System Model Update and Quality Assurance.

PPL is tentatively scheduled to go live in June with a DLR system on some of its transmission lines, Callaghan said, and PJM wanted to “enable the operational implementation of dynamic ratings” through temporary manual revisions, which will be in place pending submission of the RTO’s FERC Order 881 compliance filing.

In December, FERC ordered transmission providers to end the use of static line ratings in evaluating near-term transmission service and required transmission providers to employ ambient-adjusted ratings for short-term transmission requests of 10 days or less for all lines that are impacted by air temperature. (See FERC Orders End to Static Tx Line Ratings.)

The manual revisions are meant to have new guidance and requirements related to the operational and technical implementation of DLR systems, Callaghan said. Some of the manual revisions include adding timeline requirements to notify PJM about any new DLR systems to be installed on the grid and to provide details on requirements for real-time and forecasted DLR submissions.

Rate and Waiver Filings

Steve Pincus, associate general counsel of PJM, reviewed a proposed problem statement and issue charge addressing service to members’ tariff rate and waiver filings under the RTO’s governing documents.

In 2018, Pincus said, PJM proposed a new OA requirement as part of a larger group of changes from the Governing Document Enhancement and Clarification Subcommittee (GDECS) that called for ensuring the RTO is “properly served with members’ and interconnection customers’ rate and waiver filings” impacting PJM and stakeholders’ rights and obligations.

Pincus said a motion was made at the September 2018 MRC meeting to defer the consideration of the revisions after some stakeholders objected to the scope of the changes coming from the GDECS. PJM approached stakeholders earlier this year about reviving discussions on the issue.

The proposed problem statement says that PJM has experienced incidents when relevant FERC filings are made by members but are not served to the RTO, including tariff and service agreement filings.

“Service of such filings on PJM is important to ensure PJM is able to intervene and participate in such proceedings to protect the interests of PJM members and markets,” the problem statement said.

Key work activities in the issue charge include education on PJM’s need to be served with rate, waiver and other filings and the development of a solution to include any changes to governing documents or manuals.

Pincus said work on the issue charge is planned for special sessions of the MRC and is expected to take six months.

Consent Agenda

Stakeholders unanimously endorsed several manual changes as part of the MRC consent agenda. They included:

revisions to Manual 3: Transmission Operations resulting from a periodic review. The changes include updating stability limitation process language in accordance with docket ER21-1802 and aligning language with the current TO/TOP matrix language.
revisions to Manual 11: Energy & Ancillary Services Market Operations, Manual 12: Balancing Operations and Manual 28: Operating Agreement Accounting addressing conforming changes for stability limits in markets and operations. FERC ruled in February that PJM has the right to refuse lost opportunity cost payments to generators that are temporarily required to limit output to prevent loss of synchronization and additional strain on the system during transmission outages.
revisions to Manual 21A: Determination of Accredited UCAP Using Effective Load Carrying Capability Analysis addressing an effective load-carrying capability model run timing update. PJM rules allow voluntary submission of unit-specific wind and solar parameters for development of backcasts for newer resources, but manual language has an expiration date of March 1 for voluntary submissions. The quick fix removes the March 1 expiration date.
revisions to Manual 36: System Restoration resulting from a periodic review. The minor changes include replacing the System Restoration Coordinators Subcommittee with System Operations Subcommittee and updating the under-frequency load shed table with new data.

May 30, 2022June 14, 2023

CAISO Tackles EDAM Design in Stakeholder Meeting

CAISO convened two days of stakeholder meetings last week to discuss its straw proposal for adding an extended day-ahead market (EDAM) to the real-time Western Energy Imbalance Market — an effort that could bring more of the West under the ISO’s umbrella without forming a Western RTO.

The ISO fast-tracked the EDAM initiative last fall following a monthslong hiatus. Three stakeholder working groups met from January through mid-March to offer input on important design elements, and CAISO incorporated the groups’ results into the EDAM straw proposal. (See CAISO Issues EDAM Straw Proposal for the West.)

Mark Rothleder, CAISO | CAISO

“In the first three months of this year, we convened working groups at an expeditious — some would say ‘crazy’ — pace,” CAISO COO Mark Rothleder said, opening the two-day meeting Wednesday. “Nonetheless, we listened and processed the information that we heard to develop the straw proposal on schedule on April 28.”

“Today, we are here to discuss the straw proposal,” Rothleder said. “We are also here to listen and receive initial feedback from you all on the straw proposal. We know the straw proposal is not the final proposal.

“I’m expecting you will come out of here maybe a little bit disappointed that there’s not more detail, maybe wanting more,” he said. “I think that’s OK. This is a longer process. We will be going through several iterations, and we can’t go through all the details today. So, I just wanted to make sure that our expectations are set.”

Panel discussions May 24 involved the EDAM’s proposed resource sufficiency rules and transmission commitments, two of the more contentious issues in the process.

Resource Sufficiency

The EDAM straw proposal would require participants to pass a day-ahead resource sufficiency evaluation (RSE) to show they have enough supply to meet internal demand and reserve requirements to avoid “leaning” on the market for additional supply. Failure to pass the RSE could lead to transfer limits or an opportunity for the entity to cure the deficiency through residual supply for a fee.

Jim Baggs, regulation and market development officer for Seattle City Light, moderated a panel on resource sufficiency. He asked panelists why resource sufficiency is so important in EDAM design.

Mike Wilding, PacifiCorp | CAISO

Mike Wilding, vice president of energy supply management at PacifiCorp, answered that “at the risk of being Captain Obvious up here, if we’re all going to go in this together — if we’re going to go into the EDAM footprint together — we have to have confidence that each of us has the ability to serve our load, and that if any single [balancing authority] gets in trouble, that that does not cascade to the rest of us.”

Jeff Spires, director of power at Powerex, said reliability remains the top priority in the West, and that much of that effort is now focused on the work of the Western Power Pool to develop its Western Resource Adequacy Program (WRAP). (See NWPP Rebrands as Western Power Pool.)

“One of the areas of concern that we have when we’re looking at EDAM and market design is whether the design can be compatible with the WRAP program,” Spires said.

Jeff Spires, Powerex | CAISO

Many EDAM participants are likely to be WRAP participants too, but it is unknown if WRAP’s resource adequacy construct and CAISO’s RSE requirements will be compatible, he said.

“That’s inherently a difficult place to start from for a market design because we are, in effect, combining two different RA programs,” Spires said, adding, “Our concern is, will the rules be designed in a way that complements WRAP or not?”

Scott Ranzal, director of portfolio management with Pacific Gas and Electric, agreed that bridging gaps between the WRAP and EDAM processes is important but said the EDAM’s proposed “resource sufficiency test is a critical step in order to actually achieve a successful operating paradigm and provide reliable service. I’ve heard no argument in this room about anybody in here saying they don’t want reliable service. The question becomes, how do we get to that, and how do we define it?”

Reliability is “not an easy task,” Ranzal said. “No argument there. But there’s plenty of really smart people here working on this problem. I do think that while it has challenges, it is a solvable problem.”

Transmission Commitment

Making sure transmission is available for EDAM transfers is one of the more difficult issues facing the program’s designers. The straw proposal offers alternative proposed approaches, which still must be weighed by stakeholders and agreed upon.

“Before the day-ahead market run, each EDAM entity will identify the transmission that may be available to the day-ahead market to support transfers between EDAM entities across the EDAM footprint,” the straw proposal says.

But how to go about it?

The CAISO working group on transmission grouped transmission into three “buckets” to “define how entities can make transmission capacity available for transfers.” Its work was incorporated into the straw proposal:

Bucket 1 is transmission required to support resource sufficiency. It consists of “transmission rights held by transmission customers of the EDAM entity or another transmission service provider within the EDAM [balancing authority area] that have contractual agreements for energy or capacity transfers for RSE accounting purposes in the day-ahead timeframe,” the straw proposal says. “These transmission rights holders must make Bucket 1 transmission available to the market because it is needed to support resource sufficiency plans across an intertie with an adjoining EDAM BAA.”
Bucket 2 consists of “transmission rights held by transmission customers of the EDAM entity or another transmission service provider within the EDAM BAA that are not associated with contractual obligations used to demonstrate resource sufficiency,” it says. “This transmission has already been sold similarly to bucket 1 transmission, but the transmission rights holder can voluntarily make it available to the EDAM in return for transfer revenue. To ensure reliable transfers, Bucket 2 transmission must be firm or conditional firm.”
Bucket 3 transmission consists of “unsold firm available transfer capability (ATC) offered by the EDAM entity, in its transmission service provider function, to support transfers at interfaces between EDAM BAAs,” the straw proposal says. “The EDAM entity would be expected to make available all remaining unsold firm ATC at an intertie with an adjoining EDAM BAA by 10 a.m. in the day-ahead market and to stop [open-access transmission tariff] sales of firm ATC at that intertie between 10 a.m. and 1 p.m. while the day-ahead market is running.”

The working group focused on two approaches to make Bucket 3 transmission available to the market.

Under Approach 1, “EDAM entities would make Bucket 3 transmission available to the market for optimization at a hurdle rate (i.e., the published tariff rate),” the straw proposal says. “The hurdle rate allows the transmission provider to recover its costs of unsold transmission supporting EDAM transfers. However, including a hurdle rate in the optimization may cause pancaking of transmission hurdle rates, limiting efficient transfer and resource scheduling in the day-ahead market.”

Scott Ranzal, PG&E | CAISO

Under Approach 2, “entities would make Bucket 3 transmission available to the market hurdle-free through a reciprocity framework, similar to the [Western Energy Imbalance Market] today, to derive mutual benefits of higher volumes of EDAM transfers. There would be no compensation for the transmission usage through the market. EDAM entities would forego transmission revenues for overall efficient use of the transmission and the associated EDAM benefits.”

In a panel discussion, Kevin Smith, an attorney representing the Balancing Authority of Northern California (BANC), said that as the working group members planned, “we were trying to put some structure around how transmission is going to be viewed, how it’s utilized and so forth. And so, the buckets just became a simple convention.”

Bucket 3, it became clear, would be a problem for EDAM.

“As we looked at this and started talking hurdle rates,” Bucket 3 became the focus, Smith said.

“I would personally like to put a dagger in the heart, forever, of the hurdle-rate concept, but that’s just my own personal view,” he said.

Kathy Anderson, senior manager of real-time operations and markets with Idaho Power, said that as the working group’s discussions continued, “it became apparent that the more hurdle rates you stick in … the less economic and effective and optimized your solution becomes.”

“So that kind of led to that concept of, well, how can we maybe not put a hurdle rate in there,” as the group ultimately proposed in Approach 2.

Stakeholder comments on the straw proposal are due by June 16. CAISO plans to hold technical workshops on EDAM in late June and July. It also plans to post videos of the May 25-26 stakeholder meeting on the initiative’s webpage.

May 30, 2022

FERC Accepts ISO-NE’s MOPR Transition Plan

FERC late Friday night accepted ISO-NE’s plan to remove its minimum offer price rule after a two-year transition period, putting an end, for now, to a twisting saga that has consumed the region’s policymakers in recent months (ER22-1528).

The order offered deference to the grid operator. While FERC’s Democratic majority expressed disappointment that the contentious rule will remain in place for another two years, they wrote that the plan met the Federal Power Act’s just-and-reasonable standard and that they had no other option but to accept it.

The outcome is a disappointment to renewable industry and environmental advocates in New England, who had hoped that the commission would step in and use its authority to order ISO-NE to immediately ditch the rule, which sets a price floor in the capacity market for state-sponsored resources.

“FERC’s decision today fails to end once and for all the reign of this harmful rule,” Melissa Birchard, director for clean energy and grid reform at the Acadia Center, said in a statement. “The last thing we need is more delays to decarbonization and reliable clean energy. FERC and ISO New England need to take decisive action now to show they’re behind state clean energy policy. They didn’t do that today.”

But the commissioners’ opinions in the order make clear they did not ultimately see that as an option, because the grid operator did not put it forward.

“Simply put, ISO-NE could have, and should have, done better,” Chairman Richard Glick wrote in a concurrence. “Nevertheless, ISO-NE submitted a different proposal — one that delays reform of the MOPR by two years — and we must evaluate the filing before [us].”

In fact ISO-NE had been, for months, working on a proposal to immediately get rid of the MOPR, before a late pivot to the transition proposal, fueled by a group of gas generating companies in the NEPOOL stakeholder process. (See In Late Twist, ISO-NE Calls for 2-Year Delay on MOPR Elimination.)

The Democratic commissioners pointed to a significant silver lining from their perspective: that the rule will be gone in two years.

“Ending the federal-state antagonism over the MOPR represents a significant step forward toward ensuring resource adequacy at just and reasonable rates, which is, after all, the entire purpose of a capacity market,” Glick wrote.

Writing jointly, Commissioners Allison Clements and Willie Phillips said ISO-NE’s filing “sets the region on course to eliminate the MOPR, a likely unjust and unreasonable tariff mechanism that, if left uncorrected, could force customers in New England to pay millions or even billions to prop up capacity that they do not want or need.”

Republican Mark Christie, who joined the Democrats in supporting the proposal, wrote separately that “RTO capacity markets … should attempt to accommodate the public policies of the states as long as the impacts, both in costs and reliability, of one or more states’ public policies are not being forced onto other states not sharing those public policies.”

While Christie opposed PJM’s proposal to narrow its MOPR, it was in large part to the opposition of Pennsylvania and Ohio. “Here, however … no state in ISO-NE has filed in this record opposing the MOPR’s reform in ISO-NE,” he said.

ISO-NE and supporters of the proposal praised FERC’s decision. The grid operator said in a statement that it was “pleased that the commission saw this proposal for what it is: a reasonable step forward on New England’s transition to a decarbonized future.”

The New England Power Generators Association applauded the order as well. “NEPGA appreciates FERC’s decision, keeping with the commission’s longstanding practice of encouraging compromise solutions that reflect the geography, politics and specific needs of a given region,” NEPGA President Dan Dolan said in a statement.

“I think that I’ll have a celebratory drink tonight,” tweeted Brett Kruse, a vice president at Calpine and a vocal proponent for gas generators in the NEPOOL stakeholder process.

Danly’s Dissent

Republican Commissioner James Danly was the lone opponent of the proposal.

“This scheme will fail,” he wrote in a dissent, which contains several exchanges dueling with Glick’s concurrence. “This order will compromise reliability. All-in ratepayer costs will increase substantially.”

Danly, a long-time proponent of the MOPR, wrote that “a market rate design cannot be just and reasonable if it is not competitive, and it cannot be competitive when it permits states to freely manipulate prices.”

The dissent also responded to comments Glick made at a press conference after the commission’s monthly open meeting May 20.

“Chairman Glick says that I am ‘prone to hyperbole’ when I warn that blackouts are the likely outcome of the majority’s misguided policies to prop up renewables at the expense of competitive markets and existing fossil resources,” he wrote. (See Summer Forecasts Spark Warnings of ‘Reliability Crisis’ at FERC.) “Chairman Glick appears to be confusing ‘hyperbole’ with ‘reality.’ California and Texas have already experienced blackouts. Over two-thirds of the nation faces ‘elevated [reliability] risk’ this summer. I prefer a policy correction before we have more blackouts. Today’s order makes blackouts in New England, and their grave attendant consequences, far more likely.”

[Editor’s Note: A previous version of this story incorrectly stated that the ISO-NE filing contains no binding commitment to remove the MOPR after two years. In fact, the changes to the tariff do include a binding removal of the MOPR.]

May 30, 2022June 14, 2023

IMM: ERCOT Conservative Operations ‘Not Compatible’ with Energy-Only Market

ERCOT’s Independent Market Monitor criticized the grid operator’s conservative operations approach Friday, saying requiring additional operating reserves to be available in real-time runs counter to the energy-only market’s design.

In its annual State of the Market report, Potomac Economics said the market performed competitively in 2021 but that it was concerned about an increase in reliability unit commitment (RUC) activity.

The Monitor said that pricing outcomes have become “disconnected” from actual operational conditions in a market where high scarcity prices are designed to incent future investment in lieu of capacity revenues.

“While we continue to believe that an energy-only market can be successful and adapt to changing system needs, it is not compatible with ERCOT’s current conservative operational posture,” the report said. “The distortion in the market’s economic signals will diminish generators’ expected revenues, which ultimately will threaten ERCOT’s resource adequacy.”

ERCOT changed its operational posture in July 2021 after a June conservation notice — previously a routine practice — raised anxiety among generators and consumers still reeling from the days-long outages during the February winter storm.

The IMM said increasing reserves substantially affected market outcomes in the second half of the year.

The changes, which set aside 6.5-7.5 GW of dispatchable reserves in real time as opposed to previous reserve levels of 3.6-5.7 GW, included:

increased non-spinning reserve requirements;
routine use of RUCs that included issuing instructions earlier in the day and committing more longer-lead time resources; and
adjusting forecasts to more frequently rely on the highest load and lowest wind and solar forecasts.

The IMM estimated the higher procurement cost $300 to $400 million from mid-July to year’s end.

“The potential reliability benefits are difficult to justify based on the costs, particularly since the additional procurement is applied to all hours regardless of reliability need,” the Monitor said. “The energy-only market design relies on efficient pricing that reflects the reliability needs of the system. This can increase risk for market participants if ERCOT over-commits the system and renders generation owner’s decisions uneconomic.”

Doug Lewin 2022-03-22 (RTO Insider LLC) FI.jpg

Doug Lewin, Stoic Energy | © RTO Insider LLC

“The IMM confirms what a lot of people have been saying for a long time: a ‘conservative operating posture’ is really an ill-conceived, unvetted, half-baked capacity market and adds a lot of unnecessary costs to consumers’ bills,” Stoic Energy President Doug Lewin, told RTO Insider, calling the report “extremely important.”

Noting the report says ERCOT “will likely need to rely more heavily” on demand-side resources and energy storage, Lewin said, “These are two things the [Public Utility Commission] and ERCOT have done very little to advance so far.”

In the report, the IMM recommends developing an uncertainty product — a two- to four-hour ancillary service deployed when uncertainty results in tight real-time conditions — “to reflect ERCOT’s operating posture.” It also calls for a form of capacity procurement that “augments the economic signals provided by the energy-only market and ensures the adequacy of ERCOT’s resources over the long term.”

“A key component to any capacity proposal is defining a reliability standard,” the report said, noting that such discussions are already underway at the PUC as part of the market re-design’s second phase. (See PUC Selects Firm to Aid in ERCOT’s Market Redesign.)

IMM Director Carrie Bivens said she plans to be at the ERCOT Board of Directors meeting June 21 to discuss the report.

The Monitor also said transmission congestion in the real-time market was up 46%, resulting in $2.1 billion in costs. More than $560 million of that came during the winter storm.

It said ERCOT is increasingly limiting the flows across some network paths to maintain system stability in response to the increase in inverter-based resources. More than 7 GW of new wind and solar resources and 820 MW of energy storage resources came online in 2021, accounting for all but 730 MW of new generation. Congestion rent associated with the stability constraints more than doubled from $190 million in 2020 to $400 million last year.

Energy prices since 2014 (ERCOT) Content.jpg

ERCOT’s average energy prices since 2014. | ERCOT

According to the report, average energy prices were up six-fold last year to $167.88/MWh. Taking out the winter storm’s $9,000/MWh prices — which totaled more than $59 billion during the week — average prices were $40.73/MWh, consistent with 2021’s increased natural gas prices, the IMM said. Average prices in 2020 were $25.73/MWh.

Total demand for electricity increased by about 3% last year, about 1.3 GW/hour, the Monitor said. Demand in the oil-rich West Texas region was up 7.2% on average as the petroleum industry continues to recover from the COVID-19 pandemic.

The IMM said it continues to look to real-time co-optimization (RTC), which procures both energy and ancillary services every five minutes, as “the most significant change to improve the reliability and competitive performance of the ERCOT markets.” The RTC project, originally projected to cost between $50 million and $55 million, was postponed last year in the storm’s wake. (See “Passport Pushed Back 18 Months” ERCOT Technical Advisory Committee Briefs: April 28, 2021.)

The Monitor added three new recommendations this year to address inefficiencies or improve incentives affecting market performance, bringing the total of suggested market improvements to nine.

May 30, 2022

BPA Weathers Early Disruptions in Western EIM

The Bonneville Power Administration experienced two major “price excursion” events in the Western EIM within two weeks of joining the market on May 3, agency staff recounted Thursday.

“This transition [into the WEIM] has not been without trial and tribulation,” Mark Symonds, BPA director of commercial operations, said during an agency workshop to discuss WEIM implementation issues.

In the first event, occurring May 8, an “external technical issue” caused the BPA’s territory to separate from CAISO’s WEIM for more than four hours. BPA attributed the market disruption to the expiration of a third-party software vendor’s digital certificate, which prevented energy transfer schedule tags — or e-tags — from flowing into the market system.

As a result, inaccurate base schedules were submitted to the market, producing “unusual dispatches” and extremely high and low prices, Elsa Chang, BPA’s EIM program manager, told stakeholders during the workshop.

The May 8 issue started at about 9:30 a.m. PT, and WEIM prices in the BPA balancing authority area dropped deeply into negative territory at about 10:45 a.m., then rebounded to over CAISO’s $1,000/MWh energy bid cap just before 2 p.m. What followed was a series of wild fluctuations between those two levels, with prices topping $1,000/MWh and then dipping below the bid floor of $155/MWh. No other adjacent BAAs participating in the WEIM experienced similar price excursions.

After prices broke $1,000/MWh, BPA isolated itself from the market at 1:50 p.m. and remained separated until 4:10 p.m., Chang said.

“Once our vendor got notified, this issue was resolved quickly,” and BPA re-entered the market, she said.

Chang explained that market participants will not be billed or paid at the extreme prices that occurred during the episode. Instead, the event triggered CAISO’s administrative pricing, which in this circumstance is based on the last available prices before the disruption (hour ending 11 a.m.): $54/MWh for the 15-minute market and $42/MWh for real-time deliveries.

“We had exited operationally from the dispatches in the EIM, but that does not mean that we exited from the settlement provisions, which is why the CAISO utilizes this repricing methodology consistent with their tariff,” Symonds said in response to a stakeholder question. “Those prices have been established by the ISO and are flowing through the initial settlement statements received by all participating entities in the EIM.”

Donations Sought

The second price excursion event occurred May 18 after a small plane crashed near the Pacific AC Intertie, causing a curtailment of transmission schedules that cut transmission capacity for about 700 MW of BPA’s scheduled generation.

The result was a temporary surplus of generation in the BPA BAA before the agency could decrease output from its resources. In the interim, BPA was compelled to increase its dispatch into the WEIM and export more power through the market, causing BPA’s WEIM prices to decline to below -$500/MWh for three five-minute intervals.

Symonds said a final verdict on the extreme negative prices was still pending in CAISO’s price validation process.

“There are multiple reasons for which CAISO can and does routinely make price corrections. … At last check, they had not yet made their determination on this [event], and this particular trade date has not yet been settled,” he said.

Symonds cited both events in an appeal for regional stakeholders to “donate” unused transmission capacity to the WEIM to facilitate more transfers into and out of the BPA system, which will help avoid further price excursions. While BPA’s prices have tracked with those of other WEIM participants, “we appreciate that additional transmission can always help,” he said.

Symonds said also that additional transmission donations could assist with the more challenging conditions expected this summer.

“When there are high load events, particularly in the south, for example, there may be benefits of additional export capability to bring Northwest generation down to California, or in other events where we may be seeking to find additional loads for generation out of the Northwest, it can be helpful to also have export capability,” he said.

On the flip side, referring to the record-smashing heat wave the Northwest experienced in June 2021, Symonds said, “It would be good to have that import capability as well.”

May 30, 2022

MISO to Limit Market Error Resettlement Times

MISO intends to adjust the time it allows itself to retroactively correct market-pricing errors, stakeholders learned during a Market Subcommittee meeting Thursday.

The RTO’s markets can experience two types of pricing errors: implementation errors and continuing errors. Market-implementation errors are meant to be remedied near the operating day, with corrections made in time to be used in settlements. Continuing errors, on the other hand, are those discovered after settlement and could require up to two years of resettlements “from the date of MISO’s formal acknowledgement.”

MISO will seek FERC permission to impose a two-week limit on implementation errors and a one-year resettlement timeframe for continuing errors that begins ticking when the grid operator acknowledges the error in writing. Staff’s Daric Moenter said the RTO intends to file tariff changes in the third quarter for commission approval.

Under the proposal, implementation errors will be “identified, investigated and corrected” within two weeks. If they’re not discovered in time to be remedied within the two-week window, they will be subject to corrective settlements through the continuing error process, provided the pricing error meets a threshold of $100,000 or 0.5% of gross market activity per affected operating day.

“The recommended changes ensure that price accuracy is as important as certainty and permanency,” Moenter said.

Laura Rauch, senior director of transmission planning, said MISO is trying to strike a balance between correcting significant pricing errors and not spending “thousands to chase pennies.”

As an example, she said it would take millions of dollars of staff hours to make corrections two years back in addressing a daily settlement error.

Moenter said staff hope to avoid spending “an ordinate amount of staff time” on insignificant pricing errors. He said going back two years to reprice errors in the day-ahead and real-time systems can quickly become burdensome.

WPPI Energy’s Valy Goepfrich said she didn’t see any problems with the existing repricing policy and said she didn’t understand why MISO proposed the changes.

Stakeholders have said that during messy weather events, MISO employees probably don’t have time within the two weeks to review pricing and apply substitution logic to correct errors before they’re settled.

“Everything isn’t always clean and tidy here, and we’ve seen that,” Xcel Energy’s Kari Hassler pointed out in April.

Moenter asked for stakeholder feedback on the repricing proposal through June 10.

May 30, 2022

MISO Curbing Use of Emergency Commitment Statuses

CARMEL, Ind. — MISO said it will limit when some resources can use an emergency commitment status outside of emergency conditions, hoping to prod a more available resource fleet.

The restriction is poised to mostly affect units designated to meet the grid operator’s resource adequacy requirements. Currently, such resources can use an emergency commitment status in the energy markets, making their entire output unavailable unless there’s a generation emergency. The emergency commitments don’t affect the resources’ capacity credits. (See MISO Moves to Restrict Emergency Commitments.)

MISO market design adviser Dustin Grethen said the proposal will allow the RTO’s operators to deploy units designated for resource adequacy requirements in anticipation of tight conditions, much like MISO’s registered load-modifying resources.

“Operators are counting every megawatt when they are tracking a potential shortfall of needed capacity,” Grethen said during a Resource Adequacy Subcommittee meeting Wednesday.

MISO reported that during the 2020-21 planning year, approximately 22 GW of resources used the emergency-only commitment status about 20% of the time.

Grethen said MISO will allow emergency commitment status’s use under four conditions. He said the grid operator is proposing three conditions where a unit can use the status without first seeking permission from the Independent Market Monitor:

when the unit is at its permit limit, where its top range can only be accessed in a declared emergency;
when the unit is experiencing a “severe” energy limit, such as a fuel shortage, that keeps the unit from responding to capacity emergency conditions; or
in situations where operating the unit would go against “good utility practice” because the unit risks damage if it operates under high temperatures, high pressure or vibrations, or leaks or cracks in equipment.

MISO is also proposing a “catch-all” condition, where a unit can use the status if it consults with and receives permission from the IMM ahead of time, or while a limiting factor is occurring.

Grethen said MISO wanted a “catch-all” category because the three conditions won’t likely cover all scenarios where a unit needs to use the emergency commitment status.

Stakeholders have said that a unit sometimes uses an emergency-only status for inspections, tours, testing, quick maintenance or because of emissions limits.

MISO wants the changes enacted in time for the 2024-25 planning year.

May 30, 2022November 13, 2023

ERCOT Technical Advisory Committee Briefs: May 25, 2022

Stakeholders, Staff Try for Consensus on Gen Outage Approvals

ERCOT stakeholders and staff are continuing to hash out their differences and reach a consensus over the grid operator’s methodology for approving and denying planned generation maintenance outages.

Staff said they will review comments from stakeholders on the maximum daily resource planned outage capacity (MDRPOC) calculation, the key feature in ERCOT’s plan to evaluate outage requests. They plan to bring the revised methodology to the Board of Directors for its approval during its June 21 meeting.

In the meantime, staff agreed to hold a workshop on the MDRPOC calculation and to give the Technical Advisory Committee a chance to consolidate the three sets of comments generation members provided. They have said ERCOT’s goal is to allow as much capacity and flexibility as possible for planned outages while maintaining reliability.

The complex calculation takes installed thermal resources’ seasonal capacity, installed intermittent renewable resources’ capacity and other available capacity, and adds them together. It then subtracts from that targeted reserve capacity, forecasted reduction from price-responsive demand and other inputs.

Staff said using planned outages from last year, the highest since 2019, the proposed methodology’s calculated maximum outage capacity provides at least 20% additional margin for through 2026. They said the MDRPOC would require some outages to be moved earlier in the spring and later in the fall.

Woody Rickerson, ERCOT vice president of system planning and weatherization, said staff compared the calculation with what has been used in the past as an aggregate for the fleet and found the new methodology allows 10 to 15% more outages.

“I think that the methodology is such that there are some places that can be adjusted,” he said. “If we started having a number of planned outages that can’t be fit, then we can look at some of these dials.”

Staff have agreed to stakeholders’ request to regularly review the methodology and provide annual updates to TAC. They offered to track the number of outages denied for being over the MDRPOC but said it would be too time-consuming to post inputs used to calculate the cap, noting that the process will be automated.

“For any given point in time, we could do ad hoc reports,” Rickerson said. “Setting up something that shows every hour for five years is a bigger project and takes more time. This whole process is meant to be adjusted.”

The board in April granted staff’s appeal of a revised nodal protocol revision request (NPRR1108) that gives the grid operator the authority to review, coordinate and approve or deny all planned generation maintenance outages. Stakeholders earlier rejected staff’s version of the measure, unanimously approving an NPRR as amended by several joint commentators. (See ERCOT Board of Directors Briefs: April 28, 2022.)

Staff drafted NPRR1108 to meet the requirements of legislation passed last year in the wake of the February winter storm that led to the near collapse of the Texas Interconnection. Senate Bill 3 included a provision that the grid operator “shall review, coordinate and approve or deny requests by providers of electric generation service … for a planned power outage during any season and for any period of time.”

ERCOT’s Credit Limits Align with Others

ERCOT staff told the committee that the grid operator’s unsecured credit limits process aligns with those of the six other U.S. grid operators. They limit counterparties to a $50 million cap in unsecured credit, as does ERCOT, with the total amount of outstanding unsecured credit ranging from approximately $100 million to $1.75 billion. ERCOT currently has about $1.4 billion in outstanding unsecured credit.

The ERCOT board requested the information after tabling NPRR1112 in April. The revision request lowers the unsecured credit limits to $30 million and was approved by TAC in April over staff’s objections. ERCOT then appealed the decision to the board.

Director John Swainson said during the April meeting that TAC’s argument “should raise a level of doubt in the board about the wisdom of proceeding” with the approach.

“We’re not going there to propose anything other than providing information they wanted,” ERCOT’s Mark Ruane said. “If the board feels it’s appropriate, we are certainly at any time willing to discuss looking at the credit rules as they currently stand.”

A 2013 decision by the Commodity Futures Trading Commission exempted grid operators from some legislative provisions. It disallowed the use of unsecured credit to cover credit exposure from financial transmission rights and reduced caps on unsecured credit limits to no more than $50 million per counterparty.

TAC Vice Chair Bob Helton, with Engie North America, said he will work with ERCOT staff to ensure the committee has an advocate for its position when the issue comes up again before the board.

Members to Work on Board Relationship

TAC’s leadership is working with ERCOT staff to set up a work session, tentatively scheduled for June 14, to consolidate around new processes for interacting with the grid operator’s new board.

Helton said he and Chair Clif Lange, who was absent from the TAC meeting, have had several discussions with the new board members that he termed “very positive.”

“It was apparent that the board was trying to indicate they completely see the need for the stakeholder process and TAC, and that they want to take full advantage as they can … of the talent and the knowledge of the stakeholder process and TAC,” Helton said. “We felt really pretty good about that coming out of” the meetings.

He said there is no plan to have the committee report to the board’s new Reliability and Markets committee, but that TAC will need to decide how it communicates with both the full board and the new committee. TAC members also plan to review the appeals process at the board and develop a way to consider revision requests requested by the Public Utility Commission on a separate track, Helton said.

The board wants TAC to comprise members that “have the ability to make the decisions and move things forward,” he said, “rather than having to take things back to their company all the time.”

“You don’t need to be an officer of the company,” Helton said, referring to an issue first raised last summer. (See ERCOT Technical Advisory Committee Briefs: July 28, 2021.)

Helton and Lange plan to take the work session’s results back to the full TAC for its June 29 meeting. They face a July 11 deadline to get their information back to the board.

$1.2M to be Uplifted to Market

Staff told the committee that more than $1.2 million in nonemergency short pays from the 2021 winter storm won’t be covered by securitization and will have to be recovered by an uplift to the market. ERCOT was to begin invoicing the funds on Friday and will begin distributing the funds to short-paid entities during the next several weeks.

Retailer Entrust Energy, which went into bankruptcy last year, owes the bulk of the $1.2 million.

ERCOT issued a market notice May 20 with the estimated cumulative aggregate short-paid amount at $2.3 billion. Much of that is owed by Brazos Electric Power Cooperative, currently in bankruptcy proceedings over the nearly $1.9 billion it owes the market.

TAC Honors Uvalde Shooting Victims

Helton asked for a moment of silence for those who died in the mass shooting the day before the meeting in Uvalde, only 160 miles away from ERCOT’s Austin headquarters.

“We live in a cruel world, an unsafe world, an unforgiving world,” he said. “I can’t imagine as a parent going through that … having to go through the tragedy of the loss of a child.”

Disconnected Load Still to be Served

The committee unanimously approved NPRR1100, which clarifies that a generation or energy storage resource (ESR) may serve customer load when the customer and the resource are both disconnected from the system because of a transmission or distribution outage. It is limited to configurations where the resource and customer load are using privately owned transmission and distribution infrastructure during a private microgrid island operation. The NPRR recharacterizes the load from wholesale storage (WSL) to non-WSL on an operating day basis as necessary to ensure the ESR load not eligible for WSL treatment is not provided WSL treatment.

The measure was voted on separately from the combination ballot, which also passed unanimously. The combo ballot included five other NPRRs and single changes to the Nodal Operating Guide revision (NOGRR) and the Planning Guide (PGRR):

- NPRR1110: modifies the black start service (BSS) confidential information, contract period and backup fuel requirements; increases the BSS procurement period from two to four years; and adds an on-site 72-hour priority fuel requirement that can be waived in whole or in part to procure a sufficient number or preferred combination of resources.
- NPRR1119: deletes extraneous protocol language that should have been removed as part of NPRR978.
- NPRR1121: automates the market notice used in the exceptional fuel cost submission process to notify market participants when the costs have been submitted for the operating day.
- NPRR1129: allows ERCOT to post on its website a list of electric service identifiers for transmission-voltage customer opt-outs from the securitization of $2.1 billion for load-serving entities’ extraordinary costs incurred during the 2021 winter storm.
- NPRR1130: extends the sunset date for weatherization inspection fees from Sept. 1, 2022, to July 31, 2023.
- NOGRR240: establishes frequency and voltage ride-through requirements for new DC ties interconnecting with ERCOT after Jan. 1, 2021, and the ties that will be modified.
- PGRR100: revises the annual planning model base case update frequency from triannual to biannual, aligning it with the Steady-State Working Group’s plan to adjust its current case-building schedule to a biannual basis.

The ballot’s passage also approved the Large Flexible Load Task Force’s charter and leadership. Bill Blevins, ERCOT director of grid coordination, will chair the group, and consultant Bob Wittmeyer, who primarily represents municipalities and cooperatives, will serve as vice chair.

The task force is developing policy recommendations for integrating large flexible loads into the ERCOT system. It met May 24 to discuss interconnection issues and divvy up work assignments.

May 30, 2022January 3, 2024

MISO Makes Business Case on Long-range Transmission Plan

MISO members began an email vote last week on whether to recommend MISO’s $10 billion long-range transmission plan to the Board of Directors as staff made final pitches for the project portfolio.

The members’ advisory vote was originally slated to take place during a special Planning Advisory Committee (PAC) teleconference Friday, but some requested voting by email.

Voting will conclude June 6. The $10.3 billion, 345-kV package will then advance to the board’s System Planning Committee for its consideration. The full board will hold a final vote on the portfolio in July.

Presenting the long-range transmission plan’s (LRTP) business case to board members on Thursday, Vice President of System Planning Jennifer Curran said the plan is “critical” to MISO serving load as the footprint transitions to a new resource mix.

Curran called the initial search for long-range projects “one of the most if not the most complicated studies” MISO has ever undertaken. She said staff have been studying the transmission “in earnest” since 2020.

“That seems like a long time, but it’s really quick considering the amount of transmission analysis and the magnitude of it. … It’s been a lot in a short amount of time,” she said.

Curran said the package is MISO’s “least-regrets” assembly of projects based on a “conservative view” of members’ clean energy and decarbonization goals. She said staff will soon begin studying the LRTP’s second phase of possible projects “because the world continues to change aggressively.” That portfolio will contemplate a more rapid resource evolution and could yield projects with higher voltages than 345 kV.

MISO plans to continue monthly stakeholder workshops to discuss the second batch of LRTP solutions.

The RTO said its first portfolio will mitigate future excessive loading on existing lines and prevent possible voltage collapse across the Midwest. It anticipates the LRTP portfolio will yield anywhere from $23 billion to about $52 billion in financial benefits over 20 to 40 years of the projects, a 2.6:1 overall benefit-to-cost ratio. The grid operator estimates Midwestern cost-allocation zones will see cost-to-benefit ratios ranging from 2.1:1 to 3.2:1.

MISO’s benefit estimates for the first cycle of its long-range transmission plan | MISO

During the PAC teleconference, Clean Grid Alliance’s Natalie McIntire said MISO’s benefit estimates are cautious and said there are likely more unquantified benefits, especially reliability improvements.

The RTO has reduced the portfolio’s costs to $10.32 billion from $10.38 billion. It expects the 20- to 40-year present value of the projects’ total revenue requirement to range from $14.2 billion to $16.9 billion.

“Some of the projects increased in cost, some decreased in cost,” Jarred Miland, senior manager of transmission planning coordination, said. He said the portfolio is targeted to be in service by 2030, but that final in-service dates and costs are still subject to change.

MISO’s Joe Reddoch said staff will monitor long-term inflation trends and update cost projects if inflation materially affects construction costs.

Making Use of Existing Routes

Aubrey Johnson, the grid operator’s vice president of system planning and competitive transmission, said about 90% of the first LRTP portfolio will use existing and adjacent rights of way, or “yellow fields.” He said the planning team paid careful attention to where transmission lines could use existing rights of way.

“We think this will be a significant contributor to the speed of the regulatory process,” he said.

Director Nancy Lange, a former Minnesota commissioner, asked whether MISO expects any of the projects to be delayed or rejected by state regulators.

Johnson said though all state regulatory processes are different, using existing transmission routes should maximize the projects’ prospects.

MISO President Clair Moeller said states realized that the grid operator’s last long-range transmission projects in 2011 worked as a portfolio and were “quite responsive” to the proposal. He acknowledged that the Cardinal-Hickory Creek line remains in legal limbo a decade later over a planned river crossing route in Wisconsin. (See Enviro Groups Push Wis. DNR to Scrutinize Cardinal-Hickory Creek Line.)

However, Minnesota Public Utilities Commission staffer Hwikwon Ham warned during an earlier Market Subcommittee meeting last week that the first LRTP portfolio could temporarily increase the already high congestion levels because construction will be carried out very close to existing lines in the footprint.

OMS Hears Different Benefits Perspective

The Organization of MISO States recently hired an engineering firm to conduct an independent review of the LRTP, which the firm called a “comprehensive assessment.”

RLC Engineering’s Rick Conant said during an April OMS board meeting that the first cycle of projects doesn’t resolve all of MISO’s overloading issues. He said more thermal fixes would likely arrive with the second cycle of long-range projects.

However, RLC said it arrived at a 1.4:1 B/C ratio for the first group of projects, smaller than MISO’s overall projection of 2.6:1. The firm’s Waine Whittier said despite the findings, the projects still are beneficial to pursue.

OMS has not made the RLC study public, though its members have discussed the results in open meetings.

Competitive Bidding Question Remains Open

MISO will release a draft list of long-range facilities that will be considered for competitive bidding by June 1. Johnson said staff are still analyzing “the competitive landscape.”

Also last week, the RTO made a FERC filing to change its competitive transmission process to exclude “short segments and conductor-only” work from competitive bidding eligibility (ER22-1955). Brian Pedersen, senior manager of competitive transmission administration, said some smaller projects will be necessary to accommodate the long-range projects and “are not best suited for competition.”

Some members said they were taken by surprise that MISO would file the tariff changes without first consulting the stakeholder community.

May 30, 2022June 14, 2023

NYISO Monitor Proposes Capacity Pricing Overhaul

NYISO’s Market Monitoring Unit is recommending a new capacity market pricing structure that it says would lower costs and improve incentives for market participants making long-term investments.

Presenting highlights of the Monitor’s 2021 State of the Market Report to the Management Committee on Wednesday, Potomac Economics’ Pallas LeeVanSchaick said that the current processes for setting the installed reserve margin (IRM) and locational capacity requirement (LCR) “aren’t well coordinated with each other.”

“It is not possible for the NYISO to address the concerns discussed above in a piecemeal fashion,” the report says.

It proposes to institute an overhauled capacity market pricing structure, dubbed locational marginal pricing of capacity (C-LMP).

The market has just four fixed pricing regions, so when transmission constraints arise within one, it can lead to inefficient results. For example, in recent years the Monitor has observed bottlenecks going into Western New York capacity zones from Central New York zones, and from Staten Island into the rest of New York City, that are not represented by the current capacity zone configuration, the report said.

“We’ve seen that the lack of a treatment of constraints upstate has accentuated some of the fluctuations in the IRM and LCRs,” LeeVanSchaick said. In addition, “the LCR optimizer has a flawed objective function. … It’s not only that it doesn’t find an efficient solution; it’s also problematic because there are aspects of it [overly sensitive to small changes in inputs] that contribute to more volatility in the requirements.”

These constraints can be a barrier to entry for new resources, which are required to pay for transmission upgrades to receive capacity rights if they are not fully deliverable throughout their entire capacity region. Offshore wind and battery projects in Long Island were recently assigned costly deliverability upgrades that are not required of incumbents that are limited by the same constraints, the report said.

Potential New Entry and Retirement Trends (Potomac Economics) Content.jpg

Potential new entries include intermittent renewables principally motivated by REC solicitations and potential retirements include a number of dual fuel peaking units leaving through 2025. | Potomac Economics

The report says C-LMP would:

“produce more granular prices that are better aligned with NYISO’s planning criteria;
be more adaptable to changes in resource mix and transmission flows;
remove unnecessary barriers to new entry in the interconnection process;
be less burdensome for the ISO to administer; and
reduce the overall costs of maintaining reliability.”

“There are some emerging concerns that we see with potential new entry and retirements,” LeeVanSchaick said. “On the new entry side, of course, it’s a lot of intermittent renewables that are principally motivated by [renewable energy credit] solicitations, and on the potential retirement side you have of course Indian Point 3 in 2021. But then you’ve also got a number of dual-fuel peaking units leaving as well through 2025.”

Price Trends

All in price trends | Potomac Economics

LeeVanSchaick also discussed pricing trends over the last few years. Gas prices are clearly driving energy prices, but they are not the single biggest factor, he said.

“We saw a big increase from 2020 to 2021, not only [because of] gas prices but certainly the Indian Point nuke retirements that are ongoing,” LeeVanSchaick said. “Between those two years it certainly is contributing to the higher prices in Eastern New York. We [also] saw more planned and forced transmission outages in 2021.” Last year also saw extra high levels of forced transmission outages into Long Island.

“Lastly we saw the return to normal consumption patterns, or more normal, in 2021 than they were in 2020 from COVID,” LeeVanSchaick said. “We saw higher gas prices, higher electric demand [and a] very large reduction in capacity prices in New York City.”

EAS Market Recommendations

The Monitor also recommended changes to the energy and ancillary services markets, including to compensate reserve providers that increase transfer capability by allowing use of higher line ratings; increase the reserve demand curve for statewide requirements to reduce out-of-market actions and reflect risk to load; eliminate offline fast-start pricing, which undermines incentives for flexible resources; and model transient voltage recovery (TVR) constraints on the East End of Long Island in the energy market.

Increased penetration of intermittent or variable generation will accentuate the need for these changes, the report says, and the evolving resource mix will increase the need for longer lead time reserves to address net load forecast uncertainty.

“This is potentially reserves that don’t have to be 10 or 30 minutes; they can be potentially just available in an hour, two hours, three hours or four hours; but it would be in a time frame that would allow the NYISO to meet what are going to be increasing requirements for reserves to deal with that load forecast uncertainty,” LeeVanSchaick said.