PJM OC Briefs: June 8, 2023

VALLEY FORGE, Pa. — PJM’s Operating Committee endorsed a joint proposal by PJM, Public Service Enterprise Group (NYSE:PEG) and DC Energy for the RTO, transmission owners and market participants to increase information sharing ahead of extended transmission outages.

The package received unanimous support Thursday, while a competing proposal from the Independent Market Monitor (IMM) received 17% support. (See “Discussion Continues on Transmission Outage Coordination Proposals,” PJM OC Briefs: May 11, 2023.)

The joint proposal would add coordination between utilities and PJM to identify any required extended outages, evaluate the impact of those outages and expand outage information shared by the RTO.

Monitor Joseph Bowring said his proposal was designed to increase transparency about late outages and impacts on transmission congestion. He said the status quo rules have strong provisions around late outages that transmission owners (TOs) can bypass by instead reporting them as rescheduled projects.

“Our point is to increase clarity, transparency — particularly about late outages and congestion,” he said.

The IMM proposal would label outages as rescheduled when the start date is moved, adding a third category to current “on time” and “late” labels. It would also recommend that PJM identify the “congestion analysis required for transmission outage requests and associated triggers, including both the extent of overloaded facilities and the level of economic congestion,” the package’s matrix entry says. Bowring modified the proposal during the meeting to incorporate stakeholder feedback about a desire for more clarity.

Exelon’s Alex Stern argued that Bowring’s proposal was out of the scope of the outage coordination issue charge and would be inconsistent with the Consolidated Transmission Owners Agreement, which doesn’t give PJM the authority to place conditions on TO scheduling based on congestion analysis, associated triggers or whether an outage or rescheduled outage occurs before or after FTR auction bid opening dates. He cautioned against conditioning any outage requests needed to address grid reliability on market criteria.

Bowring said his proposal was focused on reporting, not changing how projects are scheduled or any TO behavior.

After Bowring modified the language of his proposal, OC Chair Anita Patel ruled the change was within the scope of the discussion.

PJM Plans to Open Stakeholder Process on RMR

PJM Senior Vice President of Operations Mike Bryson told the OC that RTO staff is working with the Monitor to draft a problem statement and issue charge to start a discussion on the reliability must-run (RMR) process, which allows PJM to contract with a deactivating generator to continue operations to maintain reliability.

Mike Bryson, PJM | © RTO Insider LLC

During recent discussions on reliability and resource adequacy, PJM has warned of risk that deactivations will outpace new resource development, creating increased reliance on RMRs to maintain resource adequacy. (See “Panel Discusses Future Reliability Landscape,” PJM CEO, Panelists Address Reliability During Annual Meeting.)

Bryson said PJM is considering the timing of when to bring the subject before stakeholders and which committee should take up the issue, adding that it would likely be the OC.

Stern advocated for having a working group or special sessions examine the issue more deeply and increase visibility for stakeholders.

PJM Seeks Information on Expected Impact of EPA Rules

PJM’s Gary Helm presented on recently proposed EPA rule changes, including the “good neighbor” plan to cut nitrogen oxide emissions. He recommended that market participants provide the RTO information on how the regulations could impact their operations as it considers what comments to submit to the EPA. (See EPA Good Neighbor Plan Expected to Accelerate Coal Plant Retirements.)

The proposed rule changes include a stricter fine particulate standard, carbon capture and sequestration (CCS) for coal-fired resources and hydrogen fuel requirements for combustion turbines (CT) over the next decade. The EPA is also considering changes to the mercury and toxic air standards to more strictly target mercury emissions through electrostatic precipitators, Helm said.

The requirements for gas and coal units would have a sliding scale for when those units must either retire, install CCS to reduce CO₂ emissions by 90%, or — for CT units — blend an increasing amount of hydrogen into their fuel. Helm said there are currently no commercially operating generators blending hydrogen into their fuel at the minimum 30% standard the EPA plans to require for larger resources by 2032. That rule would affect most of the combined cycle generators in PJM’s fleet.

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned whether the EPA is considering the infrastructure that would be required for generators to procure the amount of hydrogen required. Helm said at this point the EPA is focused on the viability of the technology.

“No one is doing that of their own volition, just running for the market with 30% hydrogen,” Helm said. “What I would say when you talk about infrastructure [is] that’s not addressed in the proposal because that’s something the administration feels is being addressed through actions being taken by the Department of Energy, the [Inflation Reduction Act] and the [Infrastructure Investment and Jobs Act].”

America’s Power CEO Michelle Bloodworth said generators will have to decide which avenue to pursue much sooner than laid out in the EPA’s rules, because states will have two years to write their implementation plans and will likely require utilities to make a determination ahead of that timeline. She added that no commercially operating power plants have 90% carbon capture and she doesn’t think the EPA has demonstrated that the technology is viable yet for coal-fired power plants or that the supporting infrastructure exists.

June 13, 2023October 26, 2023

NY Legislature Passes Bill to ID Grid Upgrades Necessary for EVs

ALBANY, N.Y. — The State Legislature on Friday passed a bill that would require state agencies and utilities to identify electric grid improvements necessary to implement an electric vehicle highway and depot charging network (S4830C/A5052).

The New York State Energy Research and Development Authority, Department of Transportation, Department of Motor Vehicles, New York State Thruway Authority, New York Power Authority, Long Island Power Authority, Department of Environmental Conservation, and electric distribution and transmission utilities would be required to evaluate what it would take to comply with the state’s many clean transportation targets.

The bill would also seek to expedite transmission and distribution infrastructure and interconnection upgrades at public sites controlled by the Thruway, as well as identify charging station sites that should be prioritized for early deployment to ensure they are upgraded quickly.

The agencies would be required to develop an evaluation within nine months of the effective date and conduct another one every three years thereafter.

With bipartisan support, the bill passed easily: 59-3 in the State Senate and 140-5 in the State Assembly.

NYPA has been driving the state’s EV buildout via the EVolve NY program, while NYSERDA has several other EV programs, but more rigorous goals in the Climate Leadership and Community Protection Act, Advanced Clean Trucks and Advanced Clean Cars II rules, and Zero Emissions Vehicles policy necessitate greater state action and coordination. NYSERDA also partners with Atlas Public Policy to analyze and track EVs’ growth in the state via the EValuateNY program.

Establishing an EV network in New York that can support an electrified transportation sector by 2050 is expected to increase demand for electricity, potentially in many areas not well connected to existing generation infrastructure. National Grid released a study in November suggesting that states, such as New York, must move faster to support the needs required to meet the explosive growth of EVs. (See Study Projects Power Demands of Highway EV Charging Network.)

The bill would “reduce the cost of interconnection, electric distribution and local transmission upgrades while serving projected vehicle traffic volumes” by seeking to “optimize fast-charger deployment among the highway charging hubs and charging development among the fleet charging zones.”

“If the upgrade process fails to outpace the time when electric vehicle adoption reaches scale, we will not have a reliable and adequate electric supply to power all the new electric vehicles on New York’s roadways,” the bill says.

Advanced Energy United applauded the bill passing. “Analyses — and subsequent grid improvements — will ensure the grid is ready for the uptick in electricity demand that EVs will bring, and save money in the long run compared to the status quo of reactive and piecemeal grid upgrades.”

“New York’s transition to EVs is a critical undertaking, but that transition will be slower and more expensive without proactive strengthening of the electricity grid,” said Karlito Almeda, AEU’s New York lead. “The analysis this bill calls for is a critical first step toward making New York’s electricity grid ready for the full transition to EVs, but we also need to ensure that utilities move ahead with implementing the grid improvements recommended in the analysis.”

June 13, 2023

Driscoll to Remain Acting NYPA CEO After Failing to Win Senate Confirmation

ALBANY, N.Y. — Justin Driscoll, the interim CEO of the New York Power Authority, remained in limbo as the state Senate finished its legislative session Friday without voting to confirm him.

Driscoll has been serving in an interim role since 2021, and the NYPA Board of Trustees voted to appoint him subject to Senate approval on July 26, 2022, after he was recommended as president and CEO by Gov. Kathy Hochul (D).

Driscoll had previously served as executive vice president and general counsel to NYPA, among other public roles, but environmental and labor groups mobilized to oppose him, citing his time in the private sector and recent comments on climate legislation.

Environmentalists and climate action groups claimed that Driscoll’s past legal work for fossil fuel companies, donations to Republicans, and opposition to the Build Public Renewables Act made him unqualified to lead an agency with an ever-expanding role in New York’s clean energy transition. The law makes the NYPA the sole provider of energy to all state owned and municipal properties and requires the authority to provide only renewable energy. The bill, which passed the legislature in May as part of the state budget, also requires that NYPA pay prevailing wages and use project labor agreements. (See “NYPA’s New Roles,” NY to Begin Banning Gas in New Construction in 2026.)

Meanwhile, Driscoll’s supporters credit him for his ability to work with everyone in the industry and for his extensive knowledge of how to achieve net-zero emissions without excessive costs or threats to reliability.

The Senate’s refusal to act on Driscoll’s appointment points to the state’s current dynamics. Democrats, who hold a supermajority in the legislature, recently torpedoed a Hochul judicial nominee whom they felt was too conservative.

Driscoll expressed support for NYPA’s expanded role in New York’s energy market in February.

“Government can play a role. Nobody is suggesting that government be the only tool. But just given the enormity of what we’re looking to achieve here, we think that NYPA and government can play an ancillary role in the energy transition,” he testified to the Senate Energy and Telecommunications Committee. (See NYPA Leader Says Expansion not Threat to Private Sector.)

But Driscoll was challenged in a joint legislative hearing, with Assemblyperson Zohran Kwame Mamdani, a New York City Democrat, pressing him on whether labor unions have been involved in NYPA’s work. (See “NYPA Boost,” NY Legislators Press Hochul Officials on Energy Transition.)

Organized labor has split over Driscoll’s nomination, with the Communications Workers of America District 1 tweeting, “NYPA is in good hands with Justin.”

United Auto Workers Region 9A, however, wrote they “were proud to support the #BuildPublicRenewables Act to turn the New York Power Authority into a national renewable energy leader,” adding that “New York needs a NYPA CEO who can lead with that vision” but “Justin Driscoll is not that person.”

At a confirmation hearing last week, Driscoll also had to respond to a report in The Buffalo News quoting allegations that he refused as NYPA’s general counsel to investigate allegations of racial discrimination at the authority. “Anyone who knows me knows that’s not me, that’s not how I operate,” Driscoll testified, according to the News. “I would never try to minimize complaints.”

Opposition

After learning that Driscoll would not be put up for a vote, Sen. Jabari Brisport, a Democrat representing parts of Northern Brooklyn, wrote, “New Yorkers spoke out so loudly against Justin Driscoll because he is quite clearly not an acceptable option to lead the historic transition mandated in the Build Public Renewables Act.

“NYPA needs a president who cares about environmental justice and labor rights, but Gov. Hochul has so far failed to put forward someone who meets that bare minimum,” he added.

The left-leaning New York Working Families Party tweeted that “Driscoll’s close ties to fossil fuel lobbyists, contributions to climate-denying candidates and parties, and stated opposition to expanding green energy production through the BPRA makes him a poor fit to lead the NYPA into the future.”

Public Power NY, a collection of New York grassroot organizations focused on clean energy, wrote in an email sent after reports confirmed Driscoll would not receive a vote, that “thousands of New Yorkers mobilized this past week to ‘Dump Driscoll.’

“We look forward to collaborating with stakeholders to ensure we find the most qualified person to lead NYPA,” the group added.

Supporters

The Municipal Electric Utilities Association of New York State, had earlier shared its support, writing “that Mr. Driscoll is well qualified and the right choice to lead NYPA into its next chapter.”

The New York Association of Public Power (NYAPP), a group of municipal utilities and rural electric cooperatives, also supported the nomination, tweeting, “Justin is the right person to lead NYPA.”

NYPA forwarded an email inquiry from NetZero Insider to the governor’s office, which responded with a statement from a spokesperson: “Following a national search last year, Gov. Hochul recommended Justin Driscoll for president and CEO of the New York Power Authority because he has the expertise to lead the nation’s largest state-owned utility, helping New York to achieve its ambitious climate goals using both NYPA’s existing authorities and its expanded mandate to build renewable energy secured in the FY24 State Budget.”

The spokesperson also confirmed that Driscoll would remain in his acting position.

June 13, 2023October 26, 2023

Networked Geothermal Breaks Ground in Framingham

FRAMINGHAM, Mass. — Eversource broke ground on the first utility-led networked geothermal demonstration project in the country last week, launching an alternative to fossil fuel heating that climate advocates hope will eventually be able to replace much of the state’s natural gas network.

The project is a collaboration between Eversource and climate nonprofit HEET and is one of two ongoing networked geothermal projects being developed by utilities in the state. Projected to begin operating this fall, the geothermal system will provide heating and cooling to about 140 customers, including homes, low-to-moderate income apartments, businesses and a fire station.

“This is what fighting climate change on a local level looks like,” an Eversource spokesperson told the attendees of the groundbreaking ceremony.

Eversource said it expects to significantly reduce energy use and emissions in the area, projecting an approximately 75% reduction in energy use for Framingham Housing Authority renters. The U.S. Department of Energy recently awarded the project $715,000 to expand to an additional neighborhood.

“This project has been a source of envy across the state,” said Rep. Priscila Sousa of Framingham.

To improve understanding of the challenges and potential for future projects, HEET is leading a team of researchers to study and model the technology used in the geothermal system, funded by a $5 million grant from the Massachusetts Clean Energy Center and to be conducted independent of industry oversight.

Zeyneb Magavi, co-executive director of HEET, said this project will provide valuable insight on the logistical and cost constraints to scaling up the technology.

“There’s a lot of potential savings that have already been identified if we get this going to scale,” Magavi told RTO Insider.

Magavi said drilling is one major component of networked geothermal projects that will need extra attention to deploy the technology across the state.

“Drilling, drills, drillers — that aspect of the cost is really a significant portion, and the price per linear foot varies widely across the country,” Magavi said, adding that ordering a drill for a networked geothermal project currently takes about a year and a half.

“Having identified that supply chain problem — and that is a core driver of cost — we’ve actually gone ahead and submitted an effort to the Department of Energy for the Defense Production Act on heat pumps to try to open up that supply chain and bring a drill assembly and driller training center for excellence to New England.”

Magavi emphasized the potential of networked geothermal to help low-income gas customers transition away from fossil fuels.

“If we do a house-by-house transition, we are absolutely going to end up with an equity challenge whereby renters and low-income customers are going to be left on a gas system with rising prices,” Magavi said, noting that both pilot projects are being developed in neighborhoods with significant populations of low-income residents.

William Akley, president of gas business at Eversource, called the demonstration project “a great platform for the workforce transition,” which he said is critical to the company, though no representatives from organized labor groups spoke at the event.

“Operating, constructing and maintaining an underground geothermal network has a lot of parallels to what our industry and what our employees do every day,” Akley said.

June 13, 2023November 9, 2023

California EV Rebate Program Expected to Run Empty Ahead of Plan

A recent price drop for Tesla’s Model 3 and Model Y electric vehicles have made the cars eligible again for a California EV rebate, and now the incentive program is quickly running out of money.

The potential funding depletion leaves in limbo California’s popular Clean Vehicle Rebate Project (CVRP), which has issued more than 500,000 rebates totaling more than $1.1 billion since its launch in 2010.

CVRP funding that was intended to last through June 2024 is now projected to run out as soon as November.

“At this point in time, there is no [additional] allocation for CVRP and as such, we plan to close the program once funding is out and not hold the waitlist,” Raquel Cardenas with the California Air Resources Board (CARB) said during a CVRP workshop last month. Cardenas is manager of CARB’s innovative light-duty strategies section.

The status of CVRP was also discussed Thursday during a CARB workshop on the agency’s overall funding strategy for clean vehicle incentives.

CARB is expecting to receive $441 million for all of its clean vehicle incentives in the next fiscal year — a steep drop from the $2.6 billion for incentive programs that the CARB board approved last year. The programs apply to vehicles ranging from e-bikes and cars to heavy-duty trucks, as well as clean mobility options such as bike or car sharing. (See CARB Approves $2.6B in Clean Vehicle Incentives.)

Last year’s $2.6 billion in incentive funding, which CARB called historic, was part of the state’s five-year, $10 billion multi-agency package to promote zero-emission vehicle adoption. California will ban the sale of gas-powered cars in 2035.

California is now facing a ballooning budget shortfall, and Gov. Gavin Newsom’s proposed budget trims the $10 billion ZEV package to $8.9 billion. (See Proposed Calif. Budget Retains Climate, Energy Funding.)

The $2.6 billion in funding followed a $1.5 billion allocation the previous year. The proposed $441 million for clean vehicle incentives in the next fiscal year is more in line with annual funding levels in 2016 through 2020, which ranged from $391 million to $588 million.

Rebate’s MSRP Cap

Tesla cars lost eligibility for CVRP incentives in March 2022 when the Manufacturers Suggested Retail Price increased to more than the CVRP cap of $45,000. (See Tesla Ineligibility to Shake up Calif. Clean Vehicle Rebate Program.)

But Tesla’s Model 3 and Model Y regained eligibility as of Feb. 13 after the automaker lowered the MSRP. Since then, Tesla vehicles have accounted for about 80% of all CVRP rebates.

Other factors are contributing to the rapid depletion of incentive funds. CVRP rebate amounts increased in February for low-income buyers, who can now receive $7,500 for a battery-electric vehicle, up from $4,500. The rebate for a low-income buyer of a plug-in hybrid increased to $6,500 from $3,500.

And starting this summer, low-income CVRP participants will also be able to receive a $2,000 prepaid card for use at public charging stations.

Last year’s $2.6 billion for clean vehicle incentives didn’t include money for the CVRP. That’s because in FY20/21, CARB allocated $515 million to the program, an amount intended to last through June 2024.

As of May 22, $281 million in CVRP funding remained. To keep the program running through next June, another $256 million to $837 million would be needed, according to the Center for Sustainable Energy, which administers CVRP on behalf of CARB.

Other Incentive Programs

CARB’s workshop last week was the first in a series of meetings on the FY23/24 funding plan for clean vehicle incentive programs.

The agency expects to release a draft of the plan in August ahead of a second workshop on Aug. 31. In addition, a series of community and work group meetings are planned through October.

The CARB board is expected to vote on the plan in November.

During Thursday’s workshop, CARB staff gave brief updates on other clean vehicle incentive programs.

An electric bicycle incentive program is set for a “soft launch” this month followed by a statewide launch later this year. The program will provide incentives of up to $2,000 to low-income buyers of e-bikes. A total of $13 million has been allocated to the program.

The Clean Cars for All (CC4A) program provides rebates to low-income residents who are scrapping an old car and buying an EV. The program has been administered through four regional air districts, and the San Diego Air Pollution Control District intends to launch its program this year.

CARB is in the process of expanding CC4A statewide. The agency expects to announce an administrator for the statewide program this summer.

June 13, 2023November 1, 2023

PJM PC/TEAC Briefs: June 6, 2023

Planning Committee

Stakeholders Endorse Discussion on Deactivating Generators’ CIRs

VALLEY FORGE, Pa. — The PJM Planning Committee on June 6 approved a problem statement and issue charge to explore possible improvements to the existing process of transferring capacity interconnection rights (CIRs) from a retiring generator to a replacement resource at the same interconnection point.

Tonja Wicks, Elevate Renewable | © RTO Insider LLC

Proposed by East Kentucky Power Cooperative and Elevate Renewables, the problem statement says transfer requests currently have to go through the same backlogged interconnection study queue as new generators to determine if any grid upgrades are required, which can result in replacements for retired facilities taking years to begin construction.

The companies said the long turnaround increases the commercial risk for generation owners seeking replacements; incentivizes speculative projects being submitted in the queue in anticipation of retirements; and contributes to PJM’s concerns about the balance between retiring resources and new entry over the next decade. The problem statement pointed to a February white paper PJM published finding that the pace of renewable development has been slower than anticipated while legislation and economics are leading to more deactivations.

The scope of the issue charge includes only discussion of transfer requests for the same point of interconnection, which EKPC’s Denise Foster Cronin said can often use existing infrastructure and should require no material transmission upgrades. The current process is envisioned to remain for transfers involving different points of interconnection, as those are more likely to require transmission upgrades. The issue charge also aims to develop a solution that specifies that the CIR transfer process applies for all energy-injecting resources, including thermal, renewable and storage.

Responding to stakeholders questioning how a system that allows replacement resources to go through the interconnection process faster would not be skipping other projects in the queue, Paul Sotkiewicz, president of E-Cubed Policy Associates, said the CIRs the replacing resource is seeking are held by the generation owner and are already being modeled as existing on the grid.

“Why can’t those projects be moved forward, because again they’re already being modeled; it doesn’t change anything for anyone else; … it’s not jumping the queue for anyone else; those CIRs are being modeled for everyone else,” he said.

Other PC Business

Stakeholders endorsed PJM’s plan for how it will conduct the 2023 reserve requirement study, the annual process for determining the forecast pool requirement and the installed reserve margin for the following three delivery years and establish the figures for the fourth year out. The study will also set the winter weekly reserve target for the 2023/24 delivery year. (See “Reliability Requirement Study to Use New Software,” PJM PC/TEAC Briefs: May. 9, 2023.)

PJM also provided a first read of the manual changes required to codify the overhaul of the interconnection study process FERC approved in November 2022. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

Transmission Expansion Advisory Committee

Brandon Shores Deactivation to Require $786M in Grid Upgrades

yum-phil-at-pjm-pc-teac-2018-06-07-rto-insider-fi-1.jpg

Phil Yum, PJM | © RTO Insider LLC

The planned deactivation of the coal-fired Brandon Shores Generating Station, near Baltimore, will require an estimated $786 million to resolve several voltage and thermal violations, PJM’s Phil Yum told the Transmission Expansion Advisory Committee last week.

The violations would spread from the BGE zone to also impact PEPCO, Dominion, PECO, APS, PPL and Met-Ed. The work to the 500-kV grid is estimated at $333 million and includes two new lines between the Peach Bottom and Graceton substations, as well as additional projects throughout the BGE, PECO and PEPCO zones. The 230- and 115-kV upgrades are estimated at $453 million and include three new substations and additional work throughout the BGE and APS zones.

The deactivation is scheduled for June 1, 2025, but Yum said the work is unlikely to be complete before that date. PJM Director of Operations Dave Souder said it will likely be necessary to seek to continue operating the generator under a reliability-must-run contract while the transmission work is ongoing.

“There’s a significant need to import to serve the load,” Souder said, adding that new high-voltage lines will be required into Baltimore to avoid voltage collapse under outage conditions.

Dominion Proposes Substations and New Lines Throughout Northern Va.

Dominion Energy has proposed several line extensions and installations to serve new substations in Northern Virginia, in part fueled by data center growth.

Two new substations in Louisa County requested by Rappahannock Electric Cooperative would be served by a $55 million project to extend the North Anna-Desper line.

Meanwhile, Northern Virginia Electric Cooperative requested a new substation to serve a new data center complex with more than 100 MW of load in Bristow. The 230-kV Gainesville-Wheeler line would be extended at a $15.75 million cost.

Another substation in the area, Daves Store, would be served by extending a 230-kV line terminating at the existing Heathcote substation to the new facility at a $40 million cost. The new lines would connect to a GIS 230-kV four-breaker arrangement.

Dominion has also proposed a $33.5 million project to address a 300-MW load drop violation related to the Daves Store, Youngs Branch and Catharpin substations. The work would extend a 1.7-mile, double-circuit 230-kV line from the new Trident substation to Daves Store and install associated 230-kV equipment at both. The bulk of the cost is to acquire rights of way for the new line at $18.5 million.

Two additional substations, Gemini and Atlas, would be constructed in Gainesville to serve data center loads exceeding 100 MW. Dominion estimates each project would cost just over $15 million to construct, including 230-kV lines to interconnect them.

Other Supplemental Projects

Exelon proposed the replacement of a circuit breaker on its 500-kV Conastone line, northeast of Baltimore near the Maryland-Pennsylvania border, at a $2.3 million cost. The company said the equipment was installed in 1992 and is now deteriorating, causing higher maintenance costs. The projected in-service date is Nov. 14, 2023.

Dominion provided an update on its proposed $40 million project to install new equipment at its Goose Creek substation in Loudoun County, Va. Because of an inability to procure a 1,440-MVA transformer to address real-time constraints, it plans to instead install an 840-MVA transformer and move up the in-service date from Dec. 15, 2026, to Dec. 15, 2023.

Dominion also proposed 230-kV projects to connect to its proposed Twin Creeks substation in Loudoun County, with a requested in-service date of Dec. 31, 2024. A line linking the new substation with the existing Pleasant View and Edwards Ferry stations comes with an estimated $20 million cost, while two lines to the Sycolin Creek substation have an estimated $28 million expense.

PJM Proposes New Standard for RTEP Window Submissions

PJM presented a new format for how projects being submitted to address needs identified in its Regional Transmission Expansion Plan (RTEP) should be organized.

The RTO’s Sami Abdulsalam said the change will be required for future RTEP windows and is expected to simplify the process for both staff and stakeholders.

The change asks submissions to eliminate the inclusion of existing infrastructure that is not relevant to the project being submitted and identify facilities that will be removed when submitting single-line diagrams. It also creates a standard format for how contingency files should be named to streamline compiling all the files PJM receives.

June 13, 2023June 14, 2023

PJM MIC Briefs: June 7, 2023

Stakeholders Reject Proposal to Expand Reactive Power Task Force Scope

VALLEY FORGE, Pa. — PJM’s Market Implementation Committee voted against endorsing a proposal by the Consumer Advocates of PJM States (CAPS) to expand the scope of the Reactive Power Compensation Task Force to include discussion of existing service rates.

CAPS Executive Director Greg Poulos argued that FERC’s January order eliminating the compensation for reactive power in MISO should force PJM to revisit the scope of the task force. That order found that generators participating in MISO’s markets do not have to be compensated for providing reactive service because it is a condition of interconnection. (See FERC Ends MISO Compensation for Reactive Power Supply.)

The proposal would have modified the task force’s issue charge to strike out a line in the “out-of-scope” section barring discussion of “any existing FERC-approved or pending reactive service rates.”

Paul Sotkiewicz, president of E-Cubed Policy Associates, said the comparison to MISO doesn’t hold up, as most of that region’s load is served by vertically integrated utilities. He added that FERC has already approved reactive rates in PJM.

Constellation Energy’s (NASDAQ:CEG) Adrien Ford said the change would have little impact on the task force’s work, as existing reactive charges are FERC-approved and could not be changed by proposals it may produce.

Carl Johnson, representing the PJM Public Power Coalition, said his members and CAPS approach the issue from the same common belief: that there isn’t a need to compensate generators operating within the common bandwidths for providing reactive power. However, he disagreed that the task force’s scope should be modified when it’s already far into its work.

Discussion Continues on Capacity Offers for Generators with Co-located Load

Package sponsors continued to refine their proposals on how generators can represent co-located load in their capacity offers to reflect how configurations with service from the grid would be handled.

Past discussions largely focused on arrangements without grid service — whether load in those circumstances would be under FERC or state jurisdiction and whether generators should be able to offer the energy supplied to that load as capacity. (See “Stakeholders Continue Discussion on Co-located Load Packages,” PJM MIC Briefs: May 10, 2023.)

PJM’s proposal would retain its status quo provisions, reducing generators’ capacity interconnection rights (CIRs) in line with the amount of co-located load, imposing transmission service payments to the load serving entity (LSE) and basing settlement on the net injection at the point of interconnection.

Proposals from the Independent Market Monitor (IMM), Exelon and Advanced Energy Management Alliance (AEMA) would all measure the generator and load separately to arrive at settlements for each. The IMM would follow the status quo for reducing CIRs and transmission service charges, while Exelon and the AEMA would not reduce generators’ CIRs.

Exelon’s proposal would classify the generator as an LSE for the co-located load and the AEMA package would require the generator to procure firm point-to-point transmission service with both injection and delivery set at the generator’s point of interconnection.

Much of the discussion around defining co-located load as not receiving transmission service centered on whether such load would then fall under state jurisdiction.

PJM Senior Counsel Chen Lu said the RTO considers such arrangements to be a retail sale directly from the generator to the load. Its proposal would define the load as being state jurisdictional but would pass charges for frequency regulation, reserves and black start service to the load through the generator.

Economist Roy Shanker said he doesn’t believe it’s appropriate to determine that load is state jurisdictional while still creating mechanisms to impose PJM charges on it through the generator.

Four proposals are on the table for co-located load without grid service — from PJM, the IMM, Exelon, and a joint package from Constellation Energy and Brookfield Renewable Partners.

MIC Chair Foluso Afelumo said a vote on the proposals is planned for next month, with separate votes for proposals addressing load with and without transmission service. The committee held a poll last November that found little support for either the Monitor or Constellation Energy/Brookfield Renewable Partners proposals. (See “Limited Support for Co-located Load Proposals,” PJM MIC Briefs: Dec. 7, 2022.)

PJM Presents Expected Impact of Creation of Fifth CONE Area

PJM’s Gary Helm said analysis shows that creating a fifth cost of new entry (CONE) area for the Commonwealth Edison region would not have a significant impact on the price of resources in that area for the 2025/26 delivery year (DY), but prices could increase by 2028/29. (See “PJM Proposes Creation of Fifth CONE Area,” PJM MIC Briefs: May 10, 2023.)

PJM analysis of the impact of creating a fifth cost of new entry (CONE) area for the Commonwealth Edison region, shown to the Market Implementation Committee on June 7, 2023. | PJM

The ComEd locational deliverability area (LDA) is located in CONE area 3, which has a gross CONE of $398/MW-day for the 2025/26 DY. If the ComEd region were carved out as its own area, PJM estimates that it would result in a $401/MW-day gross CONE value, a 0.7% increase. By the 2028/29 delivery, the difference between the two is estimated to be around 6%. Helm said staff are still discussing whether PJM will seek to implement the prospective change for 2025/26.

During the May 10 MIC meeting, Helm said the proposal arose out of comments on PJM’s quadrennial review FERC filing about the impact of the Illinois Climate and Equitable Jobs Act on net CONE.

Sotkiewicz said he plans to bring a second proposal before the committee during its July meeting.

June 12, 2023

NY State Reliability Council Executive Committee Briefs: June 9, 2023

Emergency Operating Procedures

ALBANY, N.Y. — New York’s installed reserves margin (IRM) study may be overly optimistic in its emergency assistance assumptions, according to a presentation given to the New York State Reliability Council’s Executive Committee (NYSRC EC) on Friday.

NYSRC Installed Capacity Subcommittee members said preliminary discussions about a forthcoming white paper, which examines how emergency operating procedures are implemented and modeled, indicate that “conditions are tight” and that NYISO and neighboring systems are all counting on one another to provide resources in the same emergency situations.

The IRM study shows New York requiring substantial assistance in emergencies, mainly from IESO in Ontario and ISO-NE. But during tight real-time conditions, PJM typically supports New York, while IESO and ISO-NE rely on New York for export support, which could create supply problems across the Northeast during future emergencies.

ICS Chair Brian Shanahan shared how “other area’s resource adequacy models generally have lower emergency assistance assumptions, compared to what we use,” adding that “that’s putting pressure on system and resource adequacy conditions.”

Industry participants are concerned that winter could emerge as a peak period, leading to increasingly tight conditions during the season, Shanahan said.

Some attendees at the EC meeting criticized the ICS’ characterization as being too unspecific.

One attendee said “generalizations are really fraught with danger, and so we need to look specifically at each area to understand what their circumstances are and what they model.”

Howard Kosel, manager of energy management resource analysis at Con Edison, said “the statement that we’re overly optimistic on what we’re relying on to get from our neighbors is a very broad statement.”

NYISO is developing ways to adjust its modeling to account for seasonal area-specific limits to minimize future interregional disruptions. It plans to present more details about the issue at the next ICS meeting.

NYSRC Elections

The EC unanimously reelected Chris Wentlent and Mark Domino as chair and vice chair, respectively.

The NYSRC EC consists of 13 members: six representatives of current transmission owners, one wholesale seller representative, one representative of the large consumers sector, one representative of the municipals and electric cooperatives sector, and four members unaffiliated with any market participant.

The four unaffiliated members also were reelected to serve another two-year term, and all other representatives — except for the wholesale seller representative — were approved.

Wholesaler sellers are still in the process of selecting their representative, and a vote remains pending.

OSW Wind Petitions

Wentlent updated the EC about petitions submitted to the New York Public Service Commission by several renewable developers who asked for permission to amend their offshore wind renewable energy certificate (OREC) agreements due to recent inflationary pressures (15-E-0302 and 18-E-0071). (See OSW Developers Seeking More Money from New York.)

ORECs are contracts in which the New York State Energy Research and Development Authority agrees to compensate developers for the environmental benefits stemming from the electricity generated by OSW projects.

Wentlent said the issue is important because it will affect how quickly New York can replace retiring resources with new, clean generation.

NYISO has repeatedly warned that retirements pose a threat to supply adequacy. (See NYISO CEO Warns of Tightening Resource Adequacy.)

“The timing of when new resources show up and how we deal with decisions on existing resources becomes even more critical,” he said.

Inverter-based Resources Standard

NYSRC’s Reliability Rules Subcommittee hopes to finalize a proposed rule establishing minimum requirements for inverter-based resources over 20 MW by September, according to a draft road map shared with the council.

The subcommittee will revise PRR-151 based on previous stakeholder comments and then consider reposting the draft rule for additional comments in early July. (See “Inverter-based Resources Standard,” NY State Reliability Council Executive Committee Briefs: May 12, 2023.)

“This is a big deal and has got the attention of everybody across the industry,” subcommittee Chair Roger Clayton said.

“We’re in the vanguard in implementing this thing, and so we need to be comprehensive and take our time to get it right,” he added.

June 12, 2023November 8, 2023

California PUC Grants PG&E $1B in Wildfire Costs

The California Public Utilities Commission on Thursday awarded Pacific Gas and Electric more than $1.1 billion in wildfire mitigation costs despite opposition from its own Public Advocates Office and consumer groups.

The commission granted PG&E 85% of the money it requested to be collected from ratepayers over the next year. The order, written by CPUC Administrative Law Judge Camille Watts-Zagha, was approved unanimously without discussion, along with rest of the Thursday voting meeting’s lengthy consent agenda.

The public advocates said the decision was arbitrary and capricious and that the commission committed legal errors by awarding PG&E its requested costs without determining their reasonableness first, as required by state law.

It is “unprecedented to grant a utility 85% of its recovery request in interim rates without a reasonableness review,” the advocates said. “Previously, the commission has explained in detail why a grant of 55% in interim rates was equitable. Here, the commission makes no attempt to demonstrate why 85% is reasonable.”

The office said the CPUC should award PG&E a maximum of 55% of its nearly $1.4 billion request, or $770 million.

Consumer groups The Utility Reform Network (TURN) and Direct Access Customer Coalition (DACC) urged the CPUC to reject PG&E’s request entirely.

“The proposed decision would authorize interim rate recovery for over $1 billion of costs PG&E has incurred but that have not yet been determined to be reasonable,” TURN said. “In the past, and as recently as last year, the commission has limited such rate relief to extraordinary circumstances.

“Rather than continue this practice, the proposed decision would grant PG&E the full extent of the requested relief, based on little more than general assertions regarding the utility’s financial condition and the likelihood that requiring customers to prepay $1 billion could reduce interest costs by approximately $30 million,” TURN said. “In doing so, it would downplay if not ignore the repeated and consistent [upbeat] statements PG&E has made to the financial community regarding its current financial condition.”

The utility’s credit rating remained below investment grade at the end of 2022, but its outlook has since improved as its stock price has been edging upward.

PG&E contended that interim rate recovery (IRR) would improve its credit rating and benefit customers in the long run with lower corporate borrowing costs.

“The [proposed decision] correctly grants IRR because it will provide direct interest savings of approximately $30 million to PG&E customers,” the utility said. “The IRR will also improve PG&E’s financial condition and credit metrics, which could yield additional customer savings and benefits through PG&E’s improved access to capital.”

Nearly $850 million of the award will cover PG&E’s vegetation management activities to prevent wildfires.

A tree falling on a PG&E distribution line caused the nearly 1 million-acre Dixie Fire, which burned through five counties in the Sierra Nevada foothills from July to October 2021. The Zogg Fire, which killed four people in September 2020, was also ignited by a downed tree on a PG&E line, the California Department of Forestry and Fire Protection (Cal Fire) found.

Branches and trees striking PG&E lines were among the causes of a spate of fires in October 2017 that ravaged Northern California wine country, Cal Fire determined.

The decision said that the reasonableness of PG&E’s costs would be reviewed later.

“PG&E is required to refund, with interest, any excess amount it collects in comparison to the commission’s final determination on the amount reasonably incurred,” it said. “Nothing in this decision shall be construed to relieve PG&E of the burden of proving that all costs it seeks to recover in this proceeding are just and reasonable.”

The decision agreed with PG&E that “interim cost recovery confers benefits of cost savings and risk minimization to the ratepayers and utility sufficient to justify departure from the commission’s statutory duty to put costs into rates after the commission determines the costs reasonable. Based on the totality of circumstances, commencing collection of costs through rates now is consistent with the commission’s constitutional and statutory duty to review and approve rate increases.”

Spread out over PG&E’s 5.5 million customers, the rate hike is expected to add $8.67 to the utility bills of typical consumers, whose average bills now range between $111 and $180/month.

June 12, 2023March 12, 2024

New England Stakeholders Discuss Clean Energy Market Mechanisms

PROVIDENCE, R.I. — As a haze of smoke and particulate matter from several massive Canadian wildfires engulfed the Northeast last week, energy industry leaders met in the 17th floor ballroom of the Graduate Providence hotel to discuss some of the challenges and opportunities of decarbonization.

Much of the discussion, hosted by the Northeast Energy and Commerce Association at the 29th annual New England Energy Conference and Exposition, centered around how the region can improve the financing of large clean energy projects, including potential market mechanisms to supplant the current reliance on power purchase agreements.

Over the past several years, New England states and stakeholders have discussed the potential for regionwide clean energy market mechanisms, such as a carbon price or a forward clean energy market (FCEM), but have struggled to come to a consensus on any such program. (See NECA Panel Ponders Forward Clean Energy Market.)

Joanna Troy, director of energy policy and planning at the Massachusetts Department of Energy Resources (DOER), said creating a market framework to incentivize large clean energy projects could help ratepayers across New England save money. She referenced the 2022 “pathways analysis,” commissioned by ISO-NE, that found the status quo of state-led PPAs to be more expensive than alternatives like a forward clean energy market, a carbon price or a hybrid.

The DOER under the administration of former Gov. Charlie Baker released a proposal for a regional FCEM in January; it outlined the creation of an independent nonprofit to oversee the market, with representatives from each New England state. Stakeholders including utilities, state agencies, municipalities and companies would voluntarily purchase different types of clean energy certificates, which would help provide financing for renewable resources.

In May, the Massachusetts Executive Office of Energy and Environmental Affairs, in consultation with the DOER and Department of Public Utilities, released a report on clean energy markets, concluding that the “use of a regional or multistate, market‐based approach to facilitate the development of clean energy generation resources — and, more broadly, to achieve and maintain a clean, reliable and affordable energy resource mix — could result in lower costs to consumers and would be beneficial for the commonwealth.”

However, the state said additional collaboration with other New England states would be necessary to develop and implement this approach and cautioned that implementing an FCEM would take years.

Thus, “Massachusetts must collaborate with its regional partners and explore more expedient market‐based approaches to support the development of clean energy, the achievement of state decarbonization requirements and reduced consumer costs,” the state concluded.

From left: Bob Grace, Sustainable Energy Advantage LLC; Cyrus Tingley, Plug Power; Alberto Aguillon, FuelCell Energy; and Sara Harari, Connecticut Green Bank | © RTO Insider LLC

“All options are on the table for how we get to a world in 2050 where we have this innovative clean energy market,” Troy said.

Susannah Hatch, director of clean energy policy at the Environmental League of Massachusetts, said studies show it will be extremely difficult to reach net-zero emissions without placing a meaningful carbon price, which should not be limited to the electricity sector.

“Having an economywide carbon price will be really important to make sure that we’re not disincentivizing electrification in other sectors,” Hatch said.

Aleks Mitreski, senior director of regulatory affairs at Brookfield Renewable Energy, said issues related to cost allocation and “finance-ability” for developers of clean energy projects have come up while trying to design a carbon pricing scheme, but he called carbon pricing “probably the easiest and best thing to do from an economic standpoint, if we can get that done.”

Hatch said an FCEM could be a useful tool but expressed concerns that a cost-based mechanism could overlook other important factors.

“While markets are really amazing at getting the lowest-cost projects and driving down costs for consumers, which is really important, they do not do quite as good a job of valuing some of the things we care about, such as environmental protection; diversity, equity and inclusion; labor standards; environmental justice; etc.,” Hatch said.

Panelists also stressed that market mechanisms must account for the variable reliability attributes of different clean energy resources, over both short- and long-term horizons.

“If we define the services that we need, then that provides the revenue opportunities for the markets to procure those services, so that we get the sort of resource mixes that will ultimately provide the region with the reliability we need as we move towards a lot more non-carbon-emitting resources,” said Chris Geissler, manager of economic analysis at ISO-NE.

Geissler highlighted the RTO’s work on the Day-Ahead Ancillary Services Initiative, which would provide new incentives for short-term reliability resources within the day-ahead market. (See ISO-NE Plans 2025 Launch for Day-Ahead Ancillary Services Initiative.)

Verifying Clean Hydrogen

As federal investment spurs interest in hydrogen development, Bob Grace, president of consultancy Sustainable Energy Advantage, made the case for a comprehensive hydrogen tracking system to verify the emissions intensity of hydrogen, tracking it from production to end use.

“At present, there is no established system for green hydrogen to be tracked and attributed between source and use,” Grace said. “A clean or green hydrogen tracking system is needed — and it’s needed soon — to enable a credible landscape for hydrogen.”

The federal tax credits created in the Inflation Reduction Act are based on a tiered system of carbon intensity: the lower the lifetime carbon intensity of the hydrogen, the greater the tax credit received.

Grace said a centralized tracking system that is not limited by geography will be essential to ensuring that hydrogen is as clean as it claims to be and that parties investing in hydrogen can rely on a framework to support due diligence and contracting. He added that the system will need to be able to track hydrogen as it is transported, stored and blended with nonrenewable fuels, while accounting for losses along the way.

“Going forward, we’re looking to pull together interested stakeholders, create a stakeholder process and find the funding to take this to the next step,” Grace said.

Cyrus Tingley of Plug Power said that while the hydrogen market has not yet been overly concerned about verification, “for it to be sustainable and bankable long term, we need it. … There’s a big volume of projects and effort out there that will ultimately depend really strongly on this.”

Tingley agreed that a multistakeholder process will be needed to create a workable verification system, overseen by a trusted and independent organization.