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November 1, 2024

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PJM OC Briefs: Nov. 2, 2023

Stakeholders Endorse Winter Weekly Reserve Target

VALLEY FORGE, Pa. — The PJM Operating Committee on Nov. 2 endorsed the RTO’s recommended winter weekly reserve target (WWRT) for the upcoming season. 

The figure is used to coordinate outages over the winter to mitigate load and forced outage uncertainty. (See “PJM Presents Recommended Winter Weekly Reserve Target Values,” PJM OC Briefs: Oct. 5, 2023.) 

PJM’s Patricio Rocha Garrido said the study recommended values of 28% for December, 30% for January and 25% for February. All three months would have higher targets than last year’s study, which had 21% for December, 27% for January and 23% for February. 

The higher values are because of changes to the modeling of forced outages over the winter and the inclusion of data from December 2022’s Winter Storm Elliott and the 2014 polar vortex. PJM historically had not included the polar vortex data because of a belief it would not reflect conditions the grid was likely to experience again, but it revised that practice following Elliott. 

The WWRT is one of three components of the annual Reserve Requirement Study. The other two, the installed reserve margin and forecast pool requirement, were endorsed by the Markets and Reliability Committee during its Oct. 25 meeting. 

PJM Presents Operations Assessment Task Force 2023 Report

PJM’s Thinzar Aung presented the results of the Operations Assessment Task Force’s 2023 winter study, which found the RTO would have a reserve margin of about 17 GW under the conditions normally studied but would be short nearly 5 GW if the specific conditions during the December 2022 winter storm were to occur again. 

No reliability issues were found for the base case under the preliminary 50/50 peak load analysis, although some re-dispatching and switching would be required because of local thermal or voltage violations. 

A total of 181.1 GW of capacity is expected to be available in the study, with a 90/10 diversified peak load of 141.4 GW. 

The single largest gas/electric contingency would reduce available generation by 4.8 GW, the study found. Paired with 16.7 GW of generation outages assumed in the analysis, 5 GW of exports and 7.2 GW of demand response, that leaves a 16.8-GW reserve margin. 

The low wind and solar scenario would reduce generation by 4 GW, leaving a 17.6-GW margin. 

The Elliott scenario increases the generation outages to 46 GW, reduces demand response to 2.4 GW and assumes a net interchange of 2.8 GW in imports. In such a scenario, PJM would be short 4.8 GW of generation. 

PJM’s Chris Pilong said the Elliott scenario was designed to replicate the worst conditions seen during the storm. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.) 

“It underscores the need to be prepared and, from a generation perspective, do everything we can to chip away at that 46,000 MW of outages,” he said. 

Quick-fix Manual Changes to Transmission Facility Cut-in Process Approved

Stakeholders endorsed a quick-fix proposal to allow PJM to delay energization of a line with a cut-in ticket if the transmission owner has not submitted evidence that all required critical tasks have been completed and the data verified by the RTO. The quick-fix process allows an issue charge and proposed manual changes to be voted on side-by-side. 

If the required data have not been received and verified by PJM by 11 a.m. on the day prior to the requested energization date, and extending the outage would not pose reliability concerns, the RTO will delay the in-service date by one day, which can be continued if the data continue to remain unavailable. PJM’s Dean Manno said it takes staff about one day to verify the data. 

Manno said critical tasks include submitting parameters such as ratings, impedance, telemetry for tie-lines and monitored priority. 

The changes are expected to be brought to the MRC for an endorsement vote Nov. 15. 

Generation Winterization Requirements Endorsed

The committee endorsed revisions to Manual 14D: Generator Operational Requirements, which include a requirement for resources to prepare for winter conditions and expanded the winterization checklist. 

Part of the manual’s periodic review, the revisions also include several administrative and clarifying changes. 

The checklist now prompts generation owners to assess safety hazards posed by snow and ice accumulation on wind and solar facilities, inspect commodities and resources that may be used in severe winter weather, and consider adding a “freeze protection operator” staff member to inspect critical equipment. 

PJM’s Vince Stefanowicz said generators can substitute PJM’s checklist for a comparable list of their own. 

Clarifying Revisions to Manual 10 Endorsed

The committee endorsed revisions to Manual 10 that would clarify that generators entering outages or their availability into eDART should report their full nameplate capability unless physically derated. 

Stefanowicz said physical derates are permanent changes to a resource that reduce its maximum output, such as components being taken offline that reduce output without the expectation of replacing them. 

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DOE to Cut Costs of Building Decarb with $30M BENEFIT Program

The U.S. Department of Energy on Nov. 6 opened a $30 million funding opportunity aimed at developing new technologies to help decarbonize the country’s building stock by improving efficiency and cutting costs of building retrofits.

Rolling out one of its trademark acronyms, DOE announced the Building Energy Efficiency Frontiers & Innovation Technologies (BENEFIT) program, which will support research, development and demonstration of new technologies for HVAC equipment, roof and attic improvements, and behind-the-meter energy management.

“The [funding opportunity announcement (FOA)] has the joint priority of making buildings more resilient [and] providing benefits to grid operators during periods of peak electricity demand and building occupants during grid outages and extreme weather events,” according to DOE. “Technologies developed in this FOA may also increase the viability and deployment of renewable energy technologies at scale by avoiding common triggers for costly upgrades, such as the need to trench new wiring to homes or increase the capacity of transformers or electrical load centers.”

While DOE has been regularly funding such R&D initiatives since 2014, according to the announcement, this year’s FOA is targeted at supporting the department’s eighth and last Earthshot, the Affordable Home Energy Shot, which Energy Secretary Jennifer Granholm launched in October at an affordable housing community in Chicago.

The goal of the initiative is to develop “next-gen” building energy-efficiency technologies that can reduce the cost of home upgrades for affordable housing by at least 50% while also reducing energy bills by 20% within a decade, Granholm said.

Those savings could be especially important for decarbonizing the “50 million single-family, multifamily and manufactured homes rented or owned by households earning less than 80% of the area median income,” DOE said.

“It’s hard to retrofit older homes,” Granholm said. “It’s older wiring, older lighting. So, one of the strategies is to look at the building envelope ― the roof, the walls ― how do you insulate those and insulate them in a way that doesn’t necessarily disturb the homeowner and cause them to have to move out?”

One possible solution would be insulation panels that can be attached to the outside of a home, which might also have “smart” wiring to connect to home appliances for demand management programs, Granholm said.

The Energy Shot — as well as the BENEFIT funding — is “about bringing down the price of all of these retrofits and installations to reduce the overall cost of energy on a month-to-month basis,” she said.

‘Pièce de Resistance’

According to DOE, residential and commercial buildings together are “the single-largest energy consuming sector of the U.S. economy.” In 2022, buildings represented 40% of total energy consumption, 74% of electricity use and 35% of energy-related carbon dioxide emissions.

Further, DOE said, “about one-third of the energy consumed in buildings is wasted, an estimated annual cost to American families and businesses of $150 billion.” Households that spend more of their disposable income on energy also are more likely to fall behind on their utility payments, the department said.

To cut the emissions, waste and utility bills, the BENEFIT FOA sets out four R&D priorities:

    • HVAC and water-heating technologies with “improved materials, components, equipment design and engineering, lower-cost manufacturing processes and easier installation.”
    • Technologies for affordable, scalable roof and attic retrofits, with a focus on energy efficiency.
    • Technologies that provide “novel approaches to maintain essential loads during blackouts and add power capacity to buildings without the need for major infrastructure upgrades.”
    • Commercial lighting upgrades, especially for commercial buildings and schools.

The FOA lays out the obstacles in developing new technologies. For example, upgrading space and water heating in commercial buildings, the announcement says, “can present complex challenges, including, but not limited to, replacing and retrofitting hydronic systems, designing solutions that overcome space constraints, addressing water heating temperature requirements, cost, contractor training for new technologies and managing occupant disruption.”

Hydronic systems provide heating and cooling via circulating water.

DOE is encouraging organizations interested in the funding to form teams, including community groups. Initial concept letters are due Dec. 18, with full applications to follow March 5, 2024. The expected date for award announcements is June 25, 2024.

Speaking in Chicago, Granholm said that as the eighth and last Earthshot, the Affordable Home Shot is the “pièce de resistance” of the program. “All of the rest have led to it.”

“To me, it’s all about the word ‘all’ — the great three-letter word,” she said. “No matter where you live — whether you live in Englewood or you live in a newly renovated home on a tree-lined street in Evanston — no matter what the size of your wallet, you should be able to have access to affordable and reliable power.”

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APS IRP Envisions Increased Renewables, Natural Gas

Arizona Public Service has filed a 15-year resource plan that lays out a strategy for meeting increasing demand and replacing capacity lost from its coal plant exit.

The plan calls for investment in “hydrogen-capable” natural gas generation, which will serve as a backup for wind and solar resources and maintain reliability.

The Palo Verde nuclear plant, which APS co-owns and operates, also will help manage costs and strengthen reliability, APS said.

Renewables will grow from 16% of APS’ energy mix to 43% in 2038, according to the integrated resource plan filed last week with the Arizona Corporation Commission (ACC).

“The immediate path ahead is clear: continued investment in affordable renewable technologies, utility-scale battery energy storage and additional hydrogen-capable natural gas facilities to provide necessary peaking and overnight load support,” APS said in its IRP.

Now that the IRP has been filed, stakeholders will have an opportunity to comment and APS will have a chance to respond before the ACC reviews the plan.

Four Corners Exit

In the plan, APS promises to exit by 2031 from the coal-fired Four Corners plant, which it operates and partly owns. APS plans to no longer have ownership in the facility by 2031, the company said in an email.

Environmental groups have called for an earlier exit from Four Corners, pointing to projections of significant cost savings from a 2028 closure.

But APS said an earlier exit creates “too significant a risk to customers at this time,” given obstacles to new resource development.

“APS does not support the early exit from Four Corners due to the grid reliability risks associated with the transition to newer, nascent technologies and increasingly limited excess capacity across the Western U.S. region,” the plan said.

The company said it will continue to study the feasibility of leaving Four Corners before 2031 as conditions change.

The IRP also has been criticized for its reliance on fossil fuels. Although coal disappears from APS’ portfolio after 2031, gas and oil hover at around 20% of the energy mix through 2038.

Alex Routhier, the Arizona clean energy manager at Western Resource Advocates, said APS must do more to speed its clean energy transition.

“We commend APS’ pledge to double its renewable energy resources by 2030, but its plan contains significant flaws,” Routhier said in a statement.

WRA said utilities must reduce their carbon emissions 80% from 2005 baseline levels by 2030 to be aligned with science-based climate goals.

APS projects its greenhouse gas emissions will fall from 9.3 million metric tons in 2023 to 6.7 million metric tons in 2038. Emissions in 2038 will be reduced 60% compared to 2005 baseline levels.

APS has pledged to be 100% carbon-free by 2050.

Growth Forecast

APS projects its customers will need about 14,820 MW of electricity in 2038, compared with the company’s 9,400 MW of total energy resources this year.

Contributing to the expected load growth are data centers and large industrial customers, which are attracted by the dry climate and low risk of natural disasters, APS said. Other factors are a growing population and electric vehicle adoption: APS expects more than 1 million EVs in its service territory by 2037.

Increased demand is projected to be 12,997 GWh for new data centers, 3,406 GWh for EVs and 657 GWh for residential customers.

To help meet the growing demand, APS plans to add more than 6,000 MW of solar and wind power, coupled with battery storage, by 2027.

The plan also calls for natural gas peaking resources, which could be built at existing coal plants, saving money by reusing existing infrastructure.

APS is planning about 1,800 MW of additional natural gas resources through 2038, partly offset by the retirement of around 300 MW of aging facilities.

Battery Storage, Microgrids

APS said it plans to invest heavily in battery storage, which will allow it to take advantage of low-priced excess solar generation from throughout the region. At times, APS said, market participants will even pay APS to take excess solar energy.

Still, the company said it’s planning a “responsible integration of this nascent technology” and is capping battery storage at 3 GW through 2027.

“APS will continually evaluate this cap as more industry experience is gained,” the IRP stated.

Microgrids are another strategy in the IRP. They’re expected to provide about 800 MW of capacity by 2038.

APS said it could partner on microgrids with large customers, such as data centers or factories.

“Since utility-integrated microgrids are dispatchable, they provide resource adequacy critical for reliability and resiliency,” APS said.

But if customers decide not to partner with APS on microgrids, the company likely would seek more natural gas resources.

Western Market Impacts

APS joined CAISO’s Western Energy Imbalance Market (WEIM) in 2016, a move that so far has saved $375 million. APS also has been involved in development of CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s competing Markets+.

“The creation of a day-ahead market can enable additional benefits for customers, and it is critical that these markets have independent governance and that all participating entities operate on an equal footing,” APS said.

The company said it expects to commit to one of the day-ahead programs after FERC approves tariffs for each.

For now, APS isn’t including day-ahead market participation in the IRP’s quantitative analysis.

“As potential day-ahead market structures become more certain, APS will be able to estimate the cost impacts in future IRPs from different programs and options,” the company said.

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PJM PC/TEAC Briefs: Oct. 31, 2023

Planning Committee

Stakeholders Endorse Changes to 300-MW Load Loss Criteria

VALLEY FORGE, Pa. — The Planning Committee endorsed revisions to Manual 14B to specify that the 300-MW load loss to be considered in transmission contingency analyses applies only to losses affecting a large number of customers.  

PJM’s Stan Sliwa said the change is meant to address the growth of data centers and other large load customers, which can cause a single large customer to surpass the 300-MW threshold in PJM’s reliability planning criteria.  

The proposed manual changes specify the requirement applied to load loss “impacting numerous customers” and states that the limit is not applicable to “contingencies impacting several customers that aggregate to 300 MW or higher.” 

The proposal also would grant PJM discretion to permit load loss above 300 MW on a case-by-case basis, which PJM Director of Operations Planning Dave Souder said is meant to build on the goal of targeting outages affecting a large area. 

Transmission Expansion Advisory Committee

Two Generation Deactivations Being Studied

PJM is conducting reliability analysis of two generators that have filed deactivation notifications: the 844-MW H.A. Wagner generator, owned by Talen, and the 180-MW Warrior Run Unit 1, owned by AES.  

PJM’s Perry Ng said a preliminary analysis found the retirement of the Wagner plant, which can run on coal, natural gas, and oil, would cause reliability violations. Talen has requested to take the plant offline on June 1, 2025,  

The study assumed the continued operation of Talen’s 1,295-MW Brandon Shores coal plant, whose scheduled retirement is expected to require $786 million in transmission upgrades. (See “Brandon Shores Deactivation to Require $786M in Grid Upgrades,” PJM PC/TEAC Briefs: June 6, 2023.) Both generators are sited in the Baltimore Gas and Electric transmission zone. 

The Warrior Run retirement is not expected to prompt any reliability concerns, Ng said. He said the completed analysis of the 4-MW Trent generator deactivation request found no issues. 

Supplemental Projects

FirstEnergy has revised its proposed solution to replace an aging transformer at its Homer City North 345/230-kV substation because the equipment won’t be available for over a year beyond the desired in-service date in December 2023 due to backlogged procurement schedules. The original $6.6 million project would replace the transformer with a new unit rated at 691/854 MVA and install an auxiliary 230/23-kV transformer; the new proposal would use a higher rated 913/1,147-MVA transformer and drop the auxiliary component. 

Commonwealth Edison presented a $24.1 million project to replace a 345/138-kV autotransformer and capacitor bank at its Des Plaines substation, where mechanical issues have caused the transformer to be taken out of service periodically. The project has an in-service date of Dec. 31, 2025.  

PECO presented a $18.2 million project to rebuild two 96-year-old lines nearing their end of life: the 2.5-mile Plymouth Meeting-Flint 230-kV double circuit line and the Plymouth Meeting-Upper Merion 230-kV double circuit line. The Plymouth Meeting-Flint project has an estimated cost of $18.2 million, while the Plymouth Meeting-Upper Merion work has a $29.2 million cost. The projects also involve upgrades at the three substations. 

Public Service Enterprise Group presented a $105.1 million project to build a greenfield 69/13-kV substation, named Harlingen, in Hillsborough, N.J., to address rising loads at its Sunnymeade and Mount Rose substations. The substation would be cut into the Bennetts Lane-Montgomery 69-kV line and the Montgomery-Customer Sub 69-kV line. The work also includes the addition of a second 230/69-kV transformer at the Bennetts Lane substation and modifications to the buses at that facility. 

Dominion has updated a $55 million project to interconnect a new substation, Germanna, to serve a data center complex in Culpeper County, Va., with a projected 124-MW load. The substation would be cut into the Cirrus-Gordonsville 230-kV line, with an in-service date of April 16, 2026. 

AEP presented a $116.7 million project to rebuild 19 miles of its Marysville-Hyatt double circuit 345-kV line due to aging infrastructure, concerns of core corrosion and difficulty finding replacement parts. The utility stated it has about 570 miles of “paper expanded/air expanded” line rated at 345-kV in its footprint which will need replacement over the next 20 years. The Marysville-Tangy line has experienced two “permanent” and three “momentary” outages. 

AEP also presented a need for a serving a new 1,500-MW data center customer in New Carlisle, Ind., with a requested in-service date of Dec. 15, 2026. 

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Texas PUC OKs Smaller Budget, Admin Fee Increases for ERCOT

Texas regulators last week rejected ERCOT’s proposed budget and administration fee increase, agreeing instead to a more incremental growth in its revenues. 

The Public Utility Commission cut a little over $31 million from the grid operator’s original biennial budget request that was approved by its Board of Directors in June. It also set ERCOT’s administration fee at 63 cents/MWh, 11.2% lower than its first ask of 71 cents/MWh. That still is a 13.5% increase over the current admin fee of 55.5 cents/MWh. It goes into effect Jan. 1 (38533). 

ERCOT now will work with budgets of $405.7 million and $414.3 million to cover operating expenses, project spending and debt-service obligations over the next two years. It originally requested $424.03 million and $426.99 million for 2024 and 2025, respectively. 

“It is important for ERCOT to look out into the future to have stability. … I don’t like rate shock,” Commissioner Will McAdams said during the Nov. 2 open meeting. He decried the magnitude of ERCOT’s financial requests during the PUC’s previous open meeting in October. (See ERCOT Defends Admin Fee Increase Before PUC.) 

ERCOT had offered to revise the budget to $414.7 million and $416.6 million over the next two years and the admin fee to 69 cents/MWh, taking advantage of a positive $36.2 million variance identified since the June board meeting. But it wasn’t enough. (See “F&A Proposes Revised Budget,” ERCOT Board, IMM Debate Ancillary Service Costs.) 

The commission linked its approval of the budget to ERCOT’s ability to meet performance measures suggested by Commissioner Lori Cobos. They include: 

    • Delivering a value of lost load study associated with a reliability standard’s development in the first quarter of 2024. 
    • Implementing the dispatchable reliability reserve service ancillary product “as expeditiously as possible” and aligning it with the real-time co-optimization plus battery project (RTC+B). (See “TAC Tables DRRS Revision, to Discuss Options with PUC,” ERCOT Technical Advisory Committee Briefs: Oct. 24, 2023.) 
    • Implementing the performance credit mechanism market design and aligning it with RTC+B as well. 

The commission also directed ERCOT to provide it with quarterly progress reports on meeting the performance measures and an annual report related to the key performance indicators in the grid operator’s August budget submission. 

After the first admin fee increase since 2016, it will not be taken up again until 2026. ERCOT CEO Pablo Vegas said this will provide staff a stable environment as they work with stakeholders to reshape the market. 

“We are operating one of the most complex systems in the world, and arguably the most complicated in the United States right now,” Vegas said. 

Commissioner Jimmy Glotfelty urged ERCOT to “become more efficient” in reducing costs. “Too many across-the-board salary increases; too many across-the-board bonuses,” he said, pointing to $23.2 million of proposed incentives. 

ERCOT’s plan to increase its staff from 843 to more than 1,000 was met with objections from the PUC and several stakeholders commenting in the docket. The grid operator said it needs the staff to fight legal challenges dating back to the February 2021 winter storm and to respond to a nearly 300% increase in legislation introduced since the storm. The latter will require more public affairs personnel and office space near the state Capitol, ERCOT has said. 

Vegas said a 1,000-person headcount is typical of other grid operators. SPP, which manages transmission across a 14-state footprint — its western expansion will add at least four more — requested 707 employees in its 2024 budget request that was approved last month. 

Reacting to ERCOT’s plans for additional office space and more public affairs personnel, state Sen. José Menéndez (D) said, somewhat sarcastically, “Quite frankly, I will be happy to share office space with ERCOT instead of a multimillion-dollar increase to my constituents.” 

Monitor to Stay Independent

The PUC also accepted staff revisions to the request for proposals for the 2024-2027 market monitoring contract after receiving pushback from lawmakers and some stakeholders. 

The proposed “electric market monitor” position will remain the “independent market monitor,” signaling the Monitor’s independence from ERCOT. State Sen. Charles Schwertner (R), the architect behind most recent market legislation, filed a letter with the commission saying the original RFP’s language implied the Monitor no longer is “truly independent” (55222). (See ERCOT Monitor’s Name Change Raises Legislative Concerns.) 

PUC’s Barksdale English | Admin Monitor

“Hearing the concerns that have been expressed in public, I recognize the specific words I put in [the contract] are misleading. I want to walk those back,” said Barksdale English, director of compliance and enforcement for the PUC. 

The revised RFP also removes language requiring the Monitor to notify the commission before speaking publicly and clarifies that the contract’s termination is to be discussed and voted on in a public forum. 

Potomac Economics, which has served as ERCOT’s IMM since 2006, is the only organization that has responded to the RFP. Responses were due Oct. 30, and the contract begins Jan. 1. 

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PJM MIC Briefs: Nov. 1, 2023

VALLEY FORGE, Pa. — Generators that plan to come online by the start of the 2025/26 delivery year will have until Dec. 12 to notify PJM of their intent to participate in the Base Residual Auction (BRA) for that year, slated for June 2024.

PJM’s Pete Langbein told the Market Implementation Committee Nov. 1 that resources that do not notify the RTO by Dec. 12 will not be permitted to participate in the BRA; those that do will be required ultimately to enter an offer.

The requirement is one of several prospective changes to the capacity market that PJM has filed at FERC following the Critical Issue Fast Path (CIFP) process that concluded in October; if the filing is not approved, the notification process will be the same as in past years, with no firm requirements. (See PJM Files Capacity Market Revamp with FERC.)

Langbein said that if a planned resource notifies PJM it will be participating in the auction, any capacity it does not offer cannot be used in that delivery year, including through Incremental Auctions (IAs). He gave the example of a generator that could offer 100 MW into the auction entering in 80 MW. That resource would not be able to offer the remaining 20 MW into subsequent IAs for that delivery year.

An information session will be held Nov. 8 to go over the template that generation owners will be asked to submit to PJM to make the notification. Questions can be submitted to rpm_hotline@pjm.com.

Manual Revisions for New Performance Assessment Interval Triggers Endorsed

The MIC endorsed conforming revisions to Manuals 11 and 18, which sets the capacity market rules, to codify changes to the triggers initiating a performance assessment interval (PAI).

The changes were approved by the Members Committee in May and signed off on by FERC on July 28. (See FERC Approves PJM Change to Emergency Triggers.)

Generators with a capacity commitment are required to meet or exceed their obligation during a PAI or face penalties, which in the case of the December 2022 winter storm amounted to about $1.8 billion.

The changes would set two conditions for triggering a PAI, with the first requiring a primary reserve shortage paired with any one of the following: a voltage reduction warning and reduction of noncritical plant load; manual load dump warning; maximum generation emergency action; or curtailment of nonessential building load.

The second condition requires a deploy-all-resources action, manual load dump action, voltage-reduction action or load-shed directive.

The MC approval of the trigger changes also included modifications to the penalty structure that generators are subject to, but PJM’s Board of Managers included only the trigger changes in the FERC filing. Changes to the penalty structure are included in the CIFP proposal submitted to the commission Oct. 13. (See PJM Board Rejects Lowering Capacity Performance Penalties.)

Stakeholders Endorse Issue Charge on DR Energy Market Parameters

The MIC endorsed an issue charge to explore creating new parameters that demand response resources can enter into the energy market. (See “Voltus Withdraws Issue Charge on DR Offer Parameters” PJM MIC Briefs: Sept 6, 2023.)

Voltus Vice President of Energy Markets Emily Orvis said DR generators lack equivalents to some of the parameters thermal generators can include in their offers, namely maximum run times and minimum times between deployments. Adding those parameters would be particularly beneficial for consumers who can shift building heating and cooling away from peak grid periods, she said. While that energy use could be deferred, temperatures would need to be regulated after some time and a recovery period might be needed before load could be curtailed again.

Resources can offer themselves into the market for specific times of day, but that must be manually done each day and is not flexible. If a resource can be available for only two hours, it would have to choose two hours ahead of time and mark itself as available. Orvis said creating a new parameter would give PJM dispatchers flexibility to call on short-duration DR resources when they would be most economical.

Much of Wednesday’s discussion focused on educating stakeholders on how any changes to energy-only DR resources could affect accrediting corresponding capacity resources under the effective load-carrying capability (ELCC) methodology.

Langbein said economic DR participating in the energy market is treated as a separate resource from load management in the capacity market, and the parameters of one would not affect the other.

Calpine’s David “Scarp” Scarpignato pushed for discussion of any potential interactions with ELCC accreditation to be included as an educational item to check for unintended consequences.

Independent Market Monitor Joe Bowring argued the issue charge should allow for changes to the capacity rules for DR if any interactions are identified during the education process and said market rules should reflect differences between resources.

“The issue is to ensure that any such demand-side resource with limited response times should not be allowed to be a capacity resource because the proposed limits are not consistent with the obligations of demand-side capacity resources,” Bowring said.

Orvis said her priority is to keep the discussion focused on changes to the energy market side, but she acceded to adding education on ELCC interactions to the in-scope portion of the issue charge.

EE Resources Concerned About Issue Charge on Market Participation

PJM presented a first read of a problem statement and issue charge to consider how energy-efficiency resources participate in the capacity market.

Langbein said EE was introduced to the capacity market about a decade ago without any subsequent consideration of how it is functioning, and staff feel it could use a fresh set of eyes.

The work timeline was set at nine months, with the idea that if changes are identified that could be implemented quickly, they could be made in time for the 2025/26 BRA. Langbein said staff aren’t trying to rush any changes and if stakeholders desire more time, the work could continue longer.

Several EE market participants expressed concern about the wide range of the issue charge and urged PJM to include more clarity on the scope. They also sought assurance there would be adequate time for any changes to be understood by all stakeholders and for them to make necessary changes to their offers for the next capacity auction.

Luke Fishback of Affirmed Energy said setting the scope of the issue charge to be so broad makes it difficult for EE market participants to evaluate where the discussion may go and how it may affect their operations, creating a chilling effect. He suggested a phased approach would be preferable to allow any changes that can be made ahead of the auction to be considered while minimizing market disruption before more substantial changes.

“Let’s give adequate time and space for the exercise of evaluating a resource and, in the near term, make sure that market participants can make investments that support their class of resources,” he said.

The problem statement says PJM’s capacity market has seen significant changes since EE was introduced. EE clearing the capacity auction has grown from 78.1 MW in DY 2011/12 to 7,668.7 MW in the 2024/25 BRA, making up about 5% of the capacity procured.

The issue charge would “evaluate EE participation and consider opportunities to eliminate ambiguity regarding what qualifies as an EE resource and ensure the energy saving attributed to the EE resource is nonbiased, accurate and reasonably consistent across providers” and make any changes toward those ends.

Other Committee Business

Stakeholders endorsed an addition to Manual 11, which relates to energy and ancillary services market operations, to define the amount of energy intermittent resources with a capacity commitment are obligated to enter into the day-ahead market. Resources should enter either the larger of their economic maximum value or their expected output based on hourly forecasts. Resources could use PJM’s forecast to estimate their availability or substitute their own forecast so long as it has a higher confidence interval.

The committee also endorsed a quick-fix solution brought by PJM seeking to revise references and typos in Manual 11. The quick-fix process allows an issue charge and solution to be voted on concurrently.

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NEPOOL Votes to Delay FCA 19

The NEPOOL Participants Committee voted Nov. 2 to delay Forward Capacity Auction (FCA) 19 by one year, seeking time to revise its resource capacity accreditation rules and consider moving to a prompt and/or seasonal capacity market.  

FCA 19, for capacity commitment period (CCP) 2028/29, currently is scheduled for February 2025.  

ISO-NE recommended the one-year delay in September but has yet to make a recommendation on the larger market changes under contemplation. While the FCA typically is held three years prior to the CCP and covers a year-long period, a prompt auction would reduce the time between the auction and the CCP to a few months. A seasonal auction would break up the commitment period into two or more distinct seasons per year. (See ISO-NE Recommends Delaying FCA 19 and Discussion Continues on ISO-NE Capacity Market Changes.)

If ISO-NE ultimately decides to stick with the existing three-year FCA format after the delay to FCA19, the RTO has proposed the following five FCAs be conducted on a 10-month cycle, instead of the current year-long process, to eventually return the auction process to its current timeline. If the RTO elects to move to a prompt auction for FCA 19, it will void the timeline instituted by the delay. (See ISO-NE Details FCA 19 Domino Effect.) 

ISO-NE and NEPOOL submitted the changes with FERC on Nov. 3. 

In response to concerns about the effects of the delay on new resources seeking FCA qualification, ISO-NE proposed two changes which generally were applauded by stakeholders. FCA qualification is necessary for resources to be eligible for reconfiguration capacity auctions, which can allow them to receive capacity payments in the near term.  

First, ISO-NE agreed to allow resources lacking capacity supply obligations to submit qualification materials using the typical FCA timeline, to prevent a delay in their ability to participate in reconfiguration auctions for earlier CCPs.  

Second, the RTO noted that peak demand resources are defined after the capacity qualification deadline, which would be shifted back by a year under the proposed delay.  

To address concerns about negative effects this could have on demand resources looking to qualify in FCA 19, ISO-NE proposed that new demand capacity resources in FCA 19 will include on-peak demand resources and seasonal peak demand resources “consisting of measures that have not been in service prior to June 1, 2024.” 

ISO-NE has proposed a January 2024 effective date for the tariff changes and is continuing discussions on the potential move to prompt and seasonal market constructs. 

A correction was made on Nov. 7, 2023: An earlier version of this article incorrectly stated that the auction delay must be approved by the ISO-NE board before being submitted to FERC. The request was submitted Nov. 3.

 

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FERC, NERC Leaders Voice Concern About Loss of Everett Marine Terminal

The retirement of the Everett LNG import terminal could jeopardize the reliability and affordability of the region’s electric and gas networks, FERC Chair Willie Phillips and NERC CEO James Robb wrote in joint comments issued Monday. 

Based on the evidence presented to FERC at the New England Winter Gas-Electric Forum in June, Phillips and Robb said they have “serious concerns about certain local gas distribution systems’ ability to ensure reliability and affordability in the region without Everett.” 

“As discussions regarding the future of Everett continue, we encourage all parties to keep reliability and affordability at the center of those negotiations,” they added. 

Phillips and Robb highlighted the fallout from Winter Storm Elliott in December 2022, noting that reduced flows of gas, combined with requests from shippers for increased gas volumes, caused pipeline pressures to plummet. (See Déjà Vu as FERC, NERC Issue Recommendations over Holiday Outages.) 

“That dynamic put significant stress on the natural gas system, which only narrowly avoided significant outages,” Phillips and Robb wrote. The officials referenced emergency LNG injections made by Consolidated Edison that saved its system from collapse, noting that “it would have taken ‘many months’ to restore service, leaving hundreds of thousands of natural gas customers without heat in the middle of winter.” 

Speaking at the New England-Canada Business Council (NECBC) Executive Energy Conference on Nov. 1, Robb said the Northeast “dodged a major bullet last winter during Elliott.” 

“Had the temperature not warmed up on Christmas Day, Con Ed and National Grid likely would have been interrupting gas customers because the pipelines were losing pressure,” Robb added. “The restoration of a major natural gas system like the one serving New York City — we would likely still be in the process of lighting pilot lights.” 

Regarding the electric system, recent studies from ISO-NE projected out through 2032 have indicated Everett may not significantly increase the reliability of the grid under extreme winter weather conditions. Despite these findings, RTO officials have indicated it would be wise to retain the facility to hedge against uncertainty in the future energy mix. (See NE Stakeholders Debate Future of Everett at FERC Winter Gas-Elec Forum.) 

Phillips and Robb echoed these concerns about uncertainty, noting that if ISO-NE’s assumptions regarding load growth, new resources and transmission, and retirements prove to be wrong, “ensuring reliability and affordability could become challenging in the face of a significant winter event.” 

They said ISO-NE and stakeholders should pursue reforms to incentivize generators to procure the necessary fuel to keep the grid running during extreme storm events. 

“To the extent that Everett or other infrastructure plays a role in supporting electric reliability by making needed energy supplies available, in the near term or the future, such reforms should consider how to ensure that any needed reliability contributions are appropriately valued,” Phillips and Robb wrote. 

ISO-NE declined to comment on the joint statement.  

The Mystic Agreement — through which New England ratepayers cover the costs of Everett’s main customer, the Mystic Generating Station — is set to expire after this winter, coinciding with the retirement of the plant. Negotiations between Constellation (which owns both Everett and Mystic) and the local gas distribution utilities to keep Everett open have yet to produce an agreement. 

Speaking at the June forum, Carrie Allen of Constellation told FERC that “the future of the facility is not ensured” and that “we’re just running out of time.” Allen added that even if an agreement is reached to keep Everett open, there still likely would be a nine-month regulatory process. 

“There is no hard-and-fast drop-dead date,” Allen said, adding that “normally, I think we would have the supply procured at this point.” 

New Hampshire Consumer Advocate Donald Kreis, who has been a vocal opponent of propping up Everett through electric rates, called the statement from Phillips and Robb “disappointing and a bit puzzling.” 

While Everett may be needed for Massachusetts gas distribution companies, Kreis told RTO Insider, ISO-NE studies show the facility is not necessary for grid reliability and therefore its costs should not be charged to the region’s electric ratepayers. 

He called Phillips’ and Robb’s comments “potentially an unhelpful scare tactic” that could “cause people to feel a sense of alarm without any basis for doing so.” 

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PJM Recommends $5B in RTEP Transmission Projects

VALLEY FORGE, Pa. — PJM has proposed around $5 billion in transmission upgrades to address data center load growth and generation deactivations primarily in the northern Virginia region identified in the third window of the 2023 Regional Transmission Expansion Plan (RTEP). (See PJM Shortlists 3 Scenarios for 2022 RTEP Window 3.) 

PJM Senior Vice President of Planning Ken Seiler told the RTO’s Transmission Expansion Advisory Committee (TEAC) the proposal would meet energy needs through the 2027/28 delivery year while providing long-term benefits to the grid by facilitating interconnection of new resources. 

Ken Seiler, PJM | © RTO Insider LLC

“It’s well-documented that there’s going to be a lot more transmission required as we go through the energy transition, and this is an area that’s a prime example of that,” he said. “We’re going to need a number of projects to meet those needs.” 

The proposal largely tracks the 500-kV combination proposal PJM presented during the Oct. 3 TEAC meeting, which would build new 500-kV lines from northern Virginia out to the Peach Bottom substation to the northeast, the 502 Junction substation to the northwest and the Morrisville substation to the south.  

PJM created the combination proposal by merging portions of the 72 proposals it received in the competitive planning process and directing some upgrades to infrastructure to address needs not resolved by any of the proposals. The final product includes work assigned to Dominion, FirstEnergy, Exelon, LS Power, NextEra, Transource and the Public Service Enterprise Group (PSEG). 

The largest portion of the work is centered on “Data Center Alley” near Dulles Airport in Loudoun County, with over $1 billion of projects assigned to Dominion in that region. The scope includes two new 500/230-kV substations and upgrades to the Mars substation. PJM’s Sami Abdulsalam said the lines between those substations would form a ring around Data Center Alley to feed energy into the facilities. 

The proposal also includes upgrades to several 230-kV lines and substations in Virginia running between the Dooms and Gordonsville substations, as well as to the Summit D.P.-Ladysmith CT 230-kV line. The work also includes a 500-kV line from the Otter Creek facility to the High Ridge substation. 

Abdulsalam said the RTEP window includes a significant number of deactivations, including the 1,295-MW Brandon Shores generator outside Baltimore. Given the lack of resources in the interconnection queue to replace Brandon Shores, new lines will be needed to prevent reliability issues in the Baltimore Gas and Electric (BGE) zone, he said. 

“If the transmission is delayed, something will have to give. Either load needs to be dropped … or some generation shows up. We don’t currently have any generation in the queue” that would come online in time, he said. 

About 11 GW of generation is expected to retire within the Window 3 time frame, which extends to 2028, while 7.5 GW of new data center load will come online. 

The proposal is expected to cost about $4.9 billion based on the cost estimates included in project submissions, while the independent estimates of those projects amount to $5.4 billion. 

Consumer Advocates Frustrated

A second first read of the proposal is scheduled for the Dec. 5 TEAC meeting, after which PJM plans to bring the recommendation to the Board of Managers for approval. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said advocates had been frustrated when previous RTEP windows were approved by the board in July with little time after the second read for stakeholders to submit comments. 

“There was significant frustration about the time given after the second read and what is the purpose of a second read,” he said. 

Philip Sussler, of the Maryland Office of People’s Counsel (OPC), said the RTEP process could be improved by creating a clearer way for comments to be submitted and for more documents to be public. Several members of the public requested information about how to write letters to the Board of Managers during the meeting. 

Residents who live along the proposed pathways questioned whether several aspects of the work would require new rights of way and expressed doubt about the feasibility of multiple transmission owners requiring certificates of public convenience and necessity (CPCNs). Maryland ratepayers also questioned why needs primarily in Virginia were being solved with transmission buildout across Maryland. 

PJM’s Augustine Caven said staff considered several factors in forming the proposal, including siting and permitting challenges. Other factors include cost containment provisions, constructability, outage coordination, development on new versus disturbed land and scheduling risks such as land and material procurement. 

“PJM recognizes the need for working the permitting process, the regulatory process in four states and that’s something that we’ll definitely have to tackle … but I think the idea here is to move forward with those conversations as quickly as possible and recognizing that it will be a parallel process trying to get the permitting in all four states,” Caven said. 

PJM said that much of the transmission work to the west would be brownfield, while the majority in the east would require new land or expanded rights of way. 

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Stakeholders Call for Structural Changes to CAISO’s Resource Adequacy Program

FOLSOM, Calif. — CAISO stakeholders last week questioned if the ISO’s resource adequacy fleet is sufficient to meet its needs.

At a Nov. 1 meeting of CAISO’s Resource Adequacy Modeling and Programming Design Working Group, Stephen Keehn, a senior adviser at Southern California Edison, said a change in the fleet requires a change in the way RA sufficiency is analyzed, and participants spent the bulk of the meeting dealing with how to adjust the framework.

Participants highlighted what they felt was a lack of visibility of non-RA resources, those resources that aren’t committed to serve an RA obligation of a load-serving entity within CAISO. Without transparency on what non-RA resources exist, what they’re being used for or whether they are under contract, market participants lack information on available capacity, therefore calling into question the efficiency of the RA program as a whole.

CAISO and its stakeholders are still in the early stages of grappling with how to redesign the RA program to account for changing conditions on the grid. The changes include a looming shortage of resources, increasing variability in energy supply and demand, and the evolving nature of resource planning frameworks in California and across the West.

The ISO is also contending with the rapid growth of energy-limited resources — such as batteries — on its grid, as well as the emergence in California of community choice aggregators (CCAs) as major LSEs, whose expansion has fragmented the landscape from a reliability perspective.

Representatives from CalCCA, Pacific Gas and Electric, Northern California Power Agency and the California Public Utilities Commission’s Public Advocates Office called for increased visibility into non-RA.

Lauren Carr, senior market policy analyst with CalCCA, said that while CAISO has visibility into all the resources in its footprint, it’s unclear what a resource is being used for if it’s not included in an RA showing.

“We don’t know, when we look at that list of non-RA resources, if it’s just that they’re not in a showing but could be dedicated to CAISO … or if they’re under contract or dedicated for some other use like substitution,” Carr said. “We think increased visibility into where supply that’s not on an RA showing is dedicated to would be useful.”

CAISO publishes monthly non-RA showings, though, leaving some confused about the lack of visibility.

“The ISO should have visibility into every resource within its operational footprint,” said Brian Theaker, vice president of Western regulatory and market affairs with Middle River Power. If a resource isn’t included in a showing, he explained, it’s likely because of substitution or holding back capacity for planned outages, which is a problem of its own.

Larger Structural Issues

In line with Theaker’s thinking, Chris Devon, director of energy market policy with Terra-Gen, suggested that the lack of visibility into non-RA resources is representative of broader structural issues such as modeling and planned outages that, if addressed, would eliminate the larger problem.

“I think that this issue of needing to increase visibility of non-RA is a symptom of the California RA overall,” said Devon.

Stakeholders also suggested addressing the default planning reserve margin before discussing visibility of non-RA. Sibyl Geiselman, market policy adviser with Public Generating Pool, questioned whether the PRM was high enough to both ensure reliability and meet a one-in-10 loss-of-load expectation, adding that an increased PRM could decrease the need for backstop procurement of non-RA resources.

“If you fix the upstream issue of making sure that the program is truly providing an adequate fleet,” said Geiselman, “then some of these downstream issues become hopefully less critical and less challenging because you have enough resources.”

While stakeholders went further into the weeds discussing the plausibility of multiyear contracts for RA resources, counting rules and backstop procurement, they consistently returned to the theme of needing to address CAISO’s entire RA modeling structure.