PJM CEO Manu Asthana Warns of Potential Generation Shortfalls
CAMBRIDGE, Md. — PJM CEO Manu Asthana said 40 GW in planned retirements and lagging construction of new generation is raising questions about the long-term reliability of the grid.
“We cannot take the reliability that we enjoy in our region for granted through this energy transition; we have to take concrete steps to ensure that it will continue,” Asthana said during his keynote address for the 2022 Annual Meeting of Members prior to the convening of the Markets and Reliability Committee Oct. 24.
He said about 40 GW of generation is expected to retire by 2030, mostly due to policy decisions rather than economics, leaving PJM without a way to incentivize the units to remain online. On top of that, data centers are expected to add 10 to 15 GW of load, with an unknown amount of growth from electrification.
Approximately 30 GW worth of new interconnection service agreements have been signed this year and there’s an additional 250 GW in the interconnection queue. However, the new generation is lagging the pace of installation that has been anticipated, Asthana said. Of the 30 GW of ISAs signed this year, only 1.5 GW has been built so far.
If the pace of constructing new generation doesn’t ramp up, he said it could lead to more reliance on demand response — with curtailments becoming more commonplace than many DR participants signed up for.
“We have time, but we don’t have time to waste,” he said. “We need to take action to ensure we retain an adequate supply of dispatchable generation through the transition.”
The stakeholder process has proven itself through the challenges of the past several years, Asthana said, and will be essential to navigating the clean energy transition as well.
“I still firmly believe that the way to solve the really complex problems of the energy transition is together as a stakeholder body. Not because it’s the quickest way to get there … but because it’s the best way to get to a resilient, durable and lasting set of solutions.”
Black Start Fuel Requirements Advance to Members Committee
PJM stakeholders endorsed a slate of revisions to the tariff and several manuals to reduce the risk of black start generators being offline due to fuel unavailability. The joint PJM, Brookfield Renewable and D.C. Office of the People’s Counsel package received 94% support in the sector-weighted vote.
The proposal, which is set to go before the Members Committee next month, creates a new category of “fuel assured” generators and requires at least one such unit in each transmission zone. The criteria to qualify as a fuel assured unit vary based on the resource type, including connections to multiple interstate gas pipelines, on-site fuel storage and dual-fuel capability.
PJM Senior Engineer Dan Bennett said the effort will create a methodological approach to looking at black start reliability. “We want to make sure this service is compensated fairly and recognized for what it brings to the grid,” Bennett said.
Black start resources whose unavailability during a blackout would cause the projected zonal restoration times to increase by 10 hours or more were identified as “high impact” sites with possible mitigation strategies laid out. The proposal calls for $28,175,000 in additional black start annual revenue for mitigation of the high-impact sites.
Calpine’s David “Scarp” Scarpignato said the requirement of one fuel-assured BSR per transmission zone may be insufficient, raising the possibility of a generator being offline or damaged during a blackout. He also noted that having penalties for fuel assured resources which fail to meet the requirements, but none for non-assured generators could discourage participation in the higher tier.
Joe Bowring, president of Independent Market Monitor Monitoring Analytics, said the proposal could result in overpayments as some BSRs which would qualify as fuel assured elect not to seek that designation, forcing PJM to enroll an additional fuel assured generator. He has also questioned the value of having non-assured resources such as intermittent generators providing black start.
Monitoring Analytics’ own package, which would have prohibited intermittent resources other than run-of-river hydro from enrolling as BSRs, did not receive the support of the Operating Committee and Market Implementation Committee. Bowring did, however, thank PJM for incorporating some of his suggestions into the joint package and said that overall it’s a proposal that provides a needed solution.
Stakeholders Narrowly Reject Demand Response Problem Statement and Issue Charge
The MRC narrowly rejected an initiative to consider the use of statistical sampling for interval-metered residential customer participation as demand response in wholesale markets. The problem statement received 48% sector-weighted support, just shy of the 50% required. (See “Stakeholders Endorse Prohibiting Gas Infrastructure Participation in DR,” PJM Market Implementation Committee Briefs: Oct. 6.)
CPower’s Ken Schisler said the requirement that curtailment service providers use customer meter data for measurement and verification is “an unreasonable barrier for residential metering.” Obtaining access to the data from electric distribution companies remains a challenge and once that data is received, Schisler said CSPs must manage hundreds of thousands of data points when calculating winter peak load.
He also raised the possibility of security issues related to holding large volumes of residential electric usage data, saying that privacy concerns could be greater for personal versus industrial data.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said the proposal offered an opportunity to receive information about barriers to the usage of smart meter data and noted that the adoption of a problem statement would not necessitate the adoption of any solutions examined.
Alex Stern, PSE&G | © RTO Insider LLCThe electric distributor sector had the strongest opposition to the proposal, joined by transmission and generator owners. End use customers unanimously supported the proposal and other suppliers had mixed support.
Alex Stern, of Public Service Electric and Gas, told RTO Insider he believes the MRC was right to oppose PJM becoming involved in residential demand response, which he believes should be addressed by state legislators and regulators before the RTO examines its own rules.
“We really need to respect the states and consider the policy issues, including but not limited to privacy — respecting the privacy of customers, as well as the … rights and responsibilities of states versus PJM,” he said.
Bowring also told the MRC that he believes access to meter data is a state policy issue and said he worries that PJM allowing statistical sampling as a workaround to issues in obtaining that data would create a disincentive for states and CSPs to find a more direct solution.
Paul Sotkiewicz of E-Cubed Policy Associates said the usage of statistical sampling could introduce inaccuracies in the markets and questioned why metering for demand response should be treated any differently from the requirements that generators are held to. “It opens up a can of worms we shouldn’t even be talking about.”
Support for Circuit Breaker Remains Mixed
Stakeholders remained divided on several proposals to impose a circuit breaker to limit the price and duration of high energy prices. None of the seven packages produced by the Energy Price Formation Senior Task Force received 50% support over the status quo in two task force polls, with a proposal from Calpine receiving the highest at 34%.
Presenting the joint stakeholder package, which received 14% support in the polls, Adrien Ford of Old Dominion Electric Cooperative said price spikes can be helpful to encourage generators to respond to issues the grid is facing. However, sustained high prices can result in load paying for tens of millions in higher rates every day that prices remain elevated and a risk of cascading market defaults.
Under the joint package, the circuit breaker would be triggered if the average LMP was above $1,000 for a rolling 24-hour period or above $850 for a rolling 168-hour interval. PJM would also be permitted to trigger a circuit breaker response but could not block one under the proposal.
Adrien Ford, Old Dominion Electric Cooperative | © RTO Insider LLCThe circuit breaker would remain in effect until the price cap had not been reached for five consecutive business days.
The proposal would also include administrative adders to provide cost recovery if the cost to generate power exceeds the circuit breaker price cap. Ford said the current rules require generators to go before FERC to seek cost recovery; the joint stakeholder language would shift the decision to PJM instead.
Bowring said that a circuit breaker should not suppress the market price below fundamentals like the cost of gas. Nor should it artificially increase prices by including any administrative adders, like Operating Reserve Demand Curve penalties or transmission constraint penalty factors, he said.
The Calpine proposal would cap the energy component of the LMP at $2,000 when the circuit breaker is triggered; generators would be paid uplift if the LMP is too low to cover their costs. The trigger would be 90 hours of non-consecutive shortage events since June 1, followed by any subsequent event during that delivery year lasting three or more hours. The circuit breaker would continue until the shortage event has ended.
Scarpignato said the $850 price cap under the joint stakeholder proposal would likely be below the cost of gas during many emergencies, while Ford said allowing prices to go as high as the $5,700 per MWh — which is the highest they can go under cost-based offers, reserve shortages and a $2,000/MWh transmission constraint penalty factor — would result in $61 billion in energy costs for a typical winter load or nearly $40 billion without the TCPF.
Jason Barker of Constellation and Sotkiewicz both said they could not support any of the current proposals and urged further discussion to find a compromise package. The MRC is scheduled to consider endorsing a package at its next meeting.
MRC Discusses Transmission Constraint Penalty Factor Revisions
The MRC reviewed a proposal to provide PJM with added flexibility to modify the transmission constraint penalty factor when transmission upgrades are already underway. The PJM proposal aims to provide a solution to an issue identified in 2020, after one of just three transmission lines into Virginia’s Northern Neck peninsula was put on outage for a planned upgrade.
The outage caused price fluctuations that pushed the TCPF to its default of $2,000/MWh in the real-time energy market. Since the completion of the upgrades would resolve the issue and it wouldn’t be possible for new generation to be added prior to the work being finished, PJM successfully argued to FERC that the design of the penalty factor created “unjust and unreasonable energy market rates” for consumers. (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)
Bowring argued that while PJM’s filing proposal addressed a real issue, its proposal would allow the RTO to subjectively determine penalty factors and does not address why penalty factors are triggered so often. Bowring said the penalty factors increased average PJM prices 11.2% in the first half of 2021 and 6.1% in the first half of 2022. Bowring stated that PJM reduces transmission line ratings by 5% and triggers these transmission constraint penalty factors unnecessarily.
A second IMM proposal failed to garner significant support over the PJM package and the status quo in an EPFSTF poll. The IMM’s alternative would broaden the trigger criteria and use a different methodology for the circuit breaker.
The PJM proposal is scheduled to be considered for endorsement by the MRC at its next meeting.
Two Proposals Remain on Variable Operations and Maintenance Costs
The MRC continued discussion of two competing packages to streamline the accounting of variable operations and maintenance costs.
The PJM proposal would create default adders for minor maintenance and operating costs as an alternative to generators submitting unit-specific information and would provide definitions of major maintenance and minor maintenance for more clarity on which costs fall into each.
The Constellation package mirrors the PJM language with the exception of removing the refueling and associated maintenance from variable costs, with Barker saying those expenses should be considered part of the unit’s capacity offer, rather than its cost-based energy offer. He said such operations are “fixed” costs that don’t vary with run time.
“Defining planned outage costs as a component of VOM will require a significant annual VOM accounting for all nuclear units; akin to developing an ACR for each unit each year,” Constellation’s presentation said.
The Market Implementation Committee endorsed the PJM package with 70% support at its Sept. 7 meeting, with Constellation’s advancing as an alternative with 54% support. (See “Two Alternatives on VOM Advance to MRC,” PJM Market Implementation Committee Briefs: Sept. 7, 2022.)
Stern said PSEG supports Constellation’s language because it aligns with efforts to preserve nuclear power as a zero emission resource.
Bowring and Sotkiewicz, however, said the package would create a special carveout for one type of generation, with the latter asking if Barker would support an amendment to include time-based operations from other resource types. Barker said such a change would be too major for him to accept as a friendly amendment and would require additional stakeholder input.
Reworked Language on Critical Gas Infrastructure Participation in Demand Response Presented
PJM gave an overview of changes made to the language of a slate of Operating Agreement, Reliability Assurance Agreement and manual revisions to prohibit critical gas infrastructure from participating in demand response programs. Following MIC feedback that the definition of the infrastructure to be affected could be vague, staff removed the word “significantly” from the phrase “which if curtailed, will significantly impact the delivery of natural gas to bulk-power system natural gas-fired generation. (See “Stakeholders Endorse Prohibiting Gas Infrastructure Participation in DR,” PJM Market Implementation Committee Briefs: Oct. 6.)
The timeline for scheduling of future votes on the package has also been changed, with a vote at the Members Committee moved to December to avoid having the MRC and MC voting on the measure on the same day.
