VALLEY FORGE, Pa. — At PJM’s Market Implementation Committee meeting last week, RTO staff outlined their proposal for registering aggregations of seasonal demand response resources that can’t comply with the year-round requirements of Capacity Performance. The current process fails to account for some of the resources’ overall capability depending on how they are aggregated.
PJM’s Andrea Yeaton and Terri Esterly explained the proposed revisions, which would dispatch resources individually based on their seasonal ability but account for them cumulatively for the purposes of CP. They said the changes provide greater dispatch flexibility while also reducing the administrative burden and minimizing unaccounted-for capability.
Joe Bowring, PJM’s Independent Market Monitor, expressed concerns about the proposal, notably in how it allows resources to aggregate across zones when the resources should be accounted for on a nodal basis as other resources are.
The proposal will be discussed at next month’s meeting to provide more clarity. Staff want it to become effective for the 2019/20 delivery year.
Response to FERC’s Cost Allocation Order
PJM’s Ray Fernandez outlined staff’s plans to address FERC’s order on the RTO’s procedure for allocating the costs of major transmission projects. The issue had dragged on for more than a decade in court orders and disputes between stakeholders, but after more than a year of negotiations, FERC last month approved a settlement agreement filed in June 2016 (EL05-121).
A large majority of stakeholders agreed to the settlement, which created a cost allocation formula for projects approved prior to Feb. 1, 2013, when PJM abandoned a “postage-stamp” method that billed all utilities in proportion to their load, regardless of where the projects were located. Several stakeholders, including Direct Energy and the Retail Energy Supply Association, had protested the agreement. (See Despite Lengthy Negotiations, PJM Cost Allocation Settlement Still Finds Detractors.)
Fernandez said staff were considering requesting a 30-day extension, which they filed later that afternoon. The motion requests an extension of the RTO’s compliance filing deadline to July 30, seeking a FERC response by June 14. PJM said in the request that it would affect the allocations for more than 100 baseline transmission projects.
The settlement revises the allocation for certain projects, effective back to Jan. 1, 2016, for which costs were assigned under the 100% load-ratio share method FERC had previously approved. Affected projects include those that are 500 kV or above and any associated “necessary lower-voltage facilities” as defined in PJM’s Tariff. The allocation for all such projects will be split 50% on the original annual load-ratio share basis and 50% on the solution-based distribution factor (DFAX) method.
There is also a “black-box” settlement for projects from 2007 through 2015 that will have billing credits or charges based on revisions to Appendix C of Schedule 12-C in the Tariff that will be allocated over the next 10 years.
The revisions will show up in resettlements of wholesale bills: line 1108 for the reallocations and a new charge on line 1115 for the black-box settlement, Fernandez said. The reallocation charge will have to fit 30 months of resettlements into 12 months of billing.
“That’s the way the settlement agreement is defined,” Fernandez said.
GT Power Group’s Jeff Whitehead asked whether the resettlements would be accounted for as adjustments going back to 2016 or a one-time current resettlement.
“If it’s an adjustment going back to 2016, it’s going to be challenging to pass that through” to customers, he said. Retail energy suppliers “can probably only pass that through to customers you still have from 2016, which might be unlikely.”
PJM’s Adam Keech provided more information on the performance assessment intervals (PAIs) that occurred on May 29. PJM experienced its first PAIs — along with its first load shed — since implementing them as part of its major Capacity Performance overhaul in 2015. The incident occurred after a transmission line and a transformer at the Jackson Road substation in American Electric Power’s transmission zone tripped out of service, which — combined with three other transmission lines that were on planned outages — caused concerns about being able to deliver power in a section of northwestern Indiana. (See related story, “Load Shed Event,” PJM Operating Committee Briefs: June 5, 2018.)
A PAI is triggered when PJM determines a supply reliability issue exists, and provides credits for generators that overperform their capacity commitments and penalties for those who underperform. No credits or penalties were assessed in the incident, which Keech noted was at least partly because PJM still has “base capacity” in this delivery year. Base capacity was developed as part of the transition to CP and doesn’t have the same always-available requirements as CP resources. Because the event was localized to a small area that included less than four generation owners, Keech said PJM’s confidentiality rules prevented him from releasing more information.
Direct Energy’s Marji Philips voiced concern that how PJM assesses PAIs appeared “extremely discretionary.” Keech disagreed, saying “there was no ambiguity on” the assessment and that the lack of charges or credits was “not because we exempted people arbitrarily.”
“I think until we get more clarity, that’s the only reasonable assumption,” Philips said.
Citigroup Energy’s Barry Trayers said that reporting the calculated bonuses and penalties shouldn’t be a market-sensitive issue.
“I don’t see the market gain or loss by reporting … winners or losers,” he said. “I just don’t see the results of this being a market-sensitive” issue.
Accounting for Maintenance Costs in Cost-Based Offers
It remains unclear what package of revisions stakeholders are likely to endorse regarding whether maintenance costs are includable in cost-based energy offers. PJM believes they belong in plants’ variable operations and maintenance (VOM) costs that are part of energy-market offers, while the Monitor argues they are not short-run marginal costs that belong in energy offers but instead avoidable costs that are includable in the in a unit’s capacity offer. The issue was set to receive an endorsement vote at the May Markets and Reliability Committee meeting, but stakeholders instead agreed to kick it back to the MIC for further discussion. (See “VOM Remanded,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)
PJM’s Tom Hauske presented an analysis that suggested the RTI’s proposal would raise costs by $8.1 million per year. He argued the Monitor’s assumptions on the issue were the worst case, short-term and low-probability. The Monitor’s Catherine Tyler and Joel Romero Luna presented an analysis arguing that PJM’s analysis misses the effect of higher unmitigated offers, fails to account for start-up and no-load costs and ignores cyclic starting and peaking factors.
They said 61% of combustion turbines they reviewed already have maintenance adders higher than the Energy Information Administration’s benchmarks, as do 19% of the combined cycle gas-fired turbines. They pointed to 2017 data that shows a $1/MWh increase in energy offers equates to a $14 million increase in uplift. Their proposal would lower cost-based energy offers from the status quo, while the PJM proposal would raise them, the noted.
Currently, an AEP proposal that used default EIA data is the main motion that was endorsed by the MIC for consideration at the June MRC. Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS), said one of his members plans to move the Monitor’s proposal for an endorsement vote at the meeting.
Long-term FTRs Undercut Annual FTRs
Despite an impassioned argument from the Monitor’s Howard Haas, stakeholders voted to endorse PJM’s plan for revising its long-term financial transmission rights market. PJM’s proposal received 178 votes in favor, 13 opposed and 53 abstentions for a favorability of 93%. The Monitor had offered as many as three proposals but dropped it to one for the vote. That proposal received 40 votes in favor, 147 opposed and 58 abstentions for a favorability of 21%. PJM’s proposal was preferred over the status quo by 79%, or 131 votes in favor, 35 opposed and 77 abstentions.
Haas had argued that PJM’s plan still gives away some of the transmission system capability that belongs to auction revenue rights holders because “there shouldn’t be any residual revenue allocation” left to offer into the long-term auction and “the fact that some participants aren’t taking advantage of the ARRs as they should be” shouldn’t preclude them from receiving the full benefits available. The Monitor’s plan would require market participants to find someone willing to take the opposite flow of the sought position. (See “Long-term FTRs,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)
“The problem is you’re still selling capability that belongs to the load,” he said.
Calpine’s David “Scarp” Scarpignato said it’s not PJM’s place to choose the best decisions for ARR holders and that “centralized planning” like that doesn’t work.
“You have to allow that some market participants are going to make good decisions and others are going to make less-than-optimal decisions,” he said.
Exelon’s Sharon Midgley said her company’s strategy to hedge its transmission costs “would be severely limited” under the Monitor’s proposal because the company would “have to hope someone wants to take a completely opposite position … which is unlikely.”
Black Start Fuel Security Sent to Problem Statement
PJM’s David Schweizer announced that staff’s proposal to develop fuel security requirements for black start units will be transitioned to the problem statement and issue charge structure. The RTO has been attempting to develop requirements for black start units that ensure fuel security, such as connection to multiple pipelines for gas-fired units or on-site storage. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: May 1, 2018.)
“PJM considers fuel assurance to be the ability of a unit to maintain full output during periods of fuel limitations caused by events such as seasonal weather extremes and high-impact, low-frequency events. Examples of high-impact, low-frequency events include pipeline failures or physical and cybersecurity events on a critical portion of a gas pipeline upon which black start resources may depend for fuel,” PJM said in the problem statement. “Initial analysis of PJM’s existing black start fleet indicates that approximately half of the units demonstrate fuel assurance, through dual-fuel capability, on-site fuel storage or multiple gas pipeline connections.”
The discussion will be split between the Operating Committee and the MIC. The OC will cover fuel assurance requirements, testing requirements and transition process while the MIC will address compensation issues. PJM expects the issues to take six months and be implemented by August.
Balancing Ratio Recalculation
PJM’s Pat Bruno presented two proposals for revising how the balancing ratio is calculated, recommending a more sophisticated fix but offering another in recognition of potential time constraints for having a solution implemented in time for next year’s Base Residual Auction.
The simpler option would use the balancing ratios from actual PAIs whenever possible and estimate them from the remaining intervals with the highest peak loads until there are 360 intervals, or 30 hours, total. The more complex solution would revise the formulas that use the balancing ratio — the CP nonperformance charge rate, or performance penalty rate (PPR), and the market seller offer cap (MSOC) — to include “projected performance assessment intervals,” which would be calculated for the delivery year as the average number of PAIs from the previous three delivery years. The MSOC would have a floor of 60 PAIs, or five hours, and the PPR would have floor of 180 PAIs, or 15 hours.
“It seems like you’re picking numbers that feel good rather than backing into something from an empirical basis,” Exelon’s Jason Barker said.
Scarp and GT Power Group’s Tom Hyzinski agreed that having different floors for the MSOC and PPR calculations was problematic.
“It’s not a little bit off. It’s off by a large amount, and it’s highly problematic for operators looking to put competitive offers into the market. I understand you wanting to put them in, but they need to match,” Scarp said.
As the discussion progressed, Scarp offered his own proposal that largely mirrored PJM’s except in how many PAI events are used in the calculation. PJM agreed to organize a special session on the issue for June 19.
Stakeholders expressed concerns that PJM’s formula could cause generators to lose all their annual capacity revenue in a short period. GT Power Group’s Dave Pratzon said the estimates seem excessive, particularly in light of the recent PAI event, in which generators were on the hook despite the cause being a transmission constraint.
EnerNOC’s Katie Guerry was concerned that, depending on the number of PAIs that occur, the PPR can double from $3,650/hour to $7,300/hour, while the MSOC would get smaller, starting at $255/MW-day with more PAIs and falling to $85/MW-day when there are none.
“I appreciate that you guys were trying to find a number that’s not excessively high [and] … did a lot of work [in a short time period], but it was all internal,” she said.
Bruno mentioned that FERC approved ISO-NE’s hourly penalty rate of about $5,500/hour but noted that staff are open to feedback on the proposals.
DC Energy FTR Credit Policy Complaint to FERC
PJM’s Bridgid Cummings explained the RTO’s proposed revisions to its FTR credit policy, and CFO Suzanne Daugherty explained how its position related to a complaint on the topic that DC Energy filed at FERC (EL18-170).
PJM wants to implement a per-megawatt-hour minimum credit requirement to address potentially large FTR positions that have little or no credit requirements. It’s also considering a monthly $100,000 deductible to the existing undiversified adder to address uncertainty and auction clearing disruption.
The per-megawatt-hour credit requirement dovetails with DC Energy’s request for a 5 cent/MWh requirement, which Daugherty said is the minimum PJM is seeking.
“We think that is an improvement to the credit policy that we can absolutely support,” she said.
She said staff are “not convinced yet” of DC’s second request, a mark-to-auction requirement.
“I think some of the concern is … auctions are only once a month,” so “clearing prices seem to jump around.” Sometimes they would match, she said, but other times not, particularly closer to delivery. She acknowledged some market participants have high megawatt volumes in their portfolios, but none is in collateral default. Staff are targeting a July filing to respond.
The adder deductible would be used to reduce collateral calls that create credit uncertainty and potential delay of the market clearing, as they can’t be applied until the auction is in the process of clearing. Cummings noted that 56 undiversified collateral calls were made from June 2016 to March 2018.
PJM is not recommending a deductible but wouldn’t oppose it if stakeholders endorse the idea. Staff hope to have approved revisions implemented by this fall.
Midgley and Gabel Associates’ Travis Stewart, representing NextEra Energy, presented specific examples of their concerns about FTR forfeitures. The analysis follows disputes with the Monitor at last month’s meeting about whether current rules were having the intended effect of discouraging illegitimate activity or unreasonably harming market participants who are trying to make appropriate business decisions. (See “FTR Forfeitures,” PJM Market Implementation Committee Briefs: May 2, 2018.)
“I would like to be able to use virtual transactions in the marketplace and at the same time use FTRs to hedge congestion risk,” Midgley said. “The rule is doing more than it intended to do.”
She provided an example of one hour in which Exelon was required to forfeit $47,000 in FTR revenue because a 200-MW virtual trade exceeded the testing thresholds for forfeiture on 18 FTR paths.
The forfeiture happened at 7 p.m. on Sept. 21, 2017. Six days later, NextEra experienced a similar issue with an 800-MW virtual trade at PJM’s West Hub that created $2,078 in forfeitures. Stewart said that similar incidents across the month accumulated to a total forfeiture for NextEra comparable to Exelon’s $47,000.
“There’s a lesson there, and it’s not that we need to reduce the effectiveness of the rule. It’s meant to change behavior,” Bowring said. “The only impact of the rule is to take away your profits on an hourly basis. The point of the rule is not to be punitive.”
Midgley argued that it also devalues FTRs subject to forfeitures and potentially requires load-serving entities to put risk premiums in customer rates, but Bowring said the fact that the forfeitures might cause Exelon or NextEra to devalue FTRs doesn’t mean other market participants will.
“You suggested that load will be worse off from this, but you haven’t demonstrated that, and I don’t think it’s true,” he said.
PJM’s Brian Chmielewski discussed the results of additional sensitivity analyses on the current forfeiture trigger from greater than or equal to 1 cent, to greater or equal to net 10% distribution factor. He found that forfeiture dollars would have been reduced by approximately 97% in September 2017 and 18 market participants would have received forfeitures instead of the 67 who did.
He concluded that the majority of constraints were “far away” from impacted FTRs, but Haas said that doesn’t mean anything unless there’s a “material impact.” PJM is performing additional analysis on market-to-market flowgate virtual testing that it plans to present at next month’s meeting.
“We are seeing a reduction in activity that is consistent with FTR forfeiture. That is a good thing,” Haas said.
— Rory D. Sweeney