VALLEY FORGE, Pa. — PJM’s Ray Fernandez told attendees at last week’s Market Implementation Committee meeting that his staff are still completing calculations for part of FERC’s ruling on retroactively reallocating costs for certain transmission projects in the RTO’s territory (EL05-121).
Staff have requested to extend the compliance filing deadline until July 30, Fernandez said. In May, FERC issued an order approving a settlement on the RTO’s procedure for allocating the costs of major transmission projects. The settlement 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. (See “Response to FERC’s Cost Allocation Order,” PJM Market Implementation Committee Briefs: June 6, 2018.)
Staff are revising the allocations on 14 technical worksheets to reflect the approved split of 50% on the original annual load-ratio share basis and 50% on the solution-based distribution factor (DFAX) method. Market participants will need to review all the worksheets to understand the full implications of the revisions, Fernandez said. He hopes to have them completed within two weeks.
The order also includes a “black box” settlement for projects from 2007 through 2015 that will be rebilled over the next 10 years. Fernandez said those reallocation amounts were published as part of the settlement.
Seasonal Aggregation
Stakeholders unanimously endorsed proposed revisions for aggregating seasonal resources. PJM’s Andrea Yeaton presented the proposal, which is designed to better account for the resources’ accumulated capability. (See “Seasonal Aggregation,” PJM Market Implementation Committee Briefs: June 6, 2018.)
Independent Market Monitor Joe Bowring questioned staff’s planned procedure for day-ahead notification because PJM continues to use demand response as an emergency resource.
“Typically, you don’t have a day’s notice; you have an emergency,” he said.
PJM’s Pete Langbein said grid operators will continue to dispatch DR as necessary during emergencies but will use this approach “if we have the luxury” of receiving notification the day before. He said operators will continue the practice of dispatching resources with registration-level granularity, which is usually limited to a single customer.
Credit Requirements
Stakeholders resoundingly endorsed PJM’s recommended revisions to the financial transmission rights credit policy, rejecting both a pre-existing alternative and a proposal offered by DC Energy’s Bruce Bleiweis during discussion. Stakeholders also indicated that they strongly preferred the endorsed revisions to the status quo in a sector-weighted vote, with 193 (or 0.92) voting in favor of the changes, with 16 opposed and 11 abstentions. The votes had an endorsement threshold of 0.5.
PJM wants to implement a per-megawatt-hour minimum credit requirement to address potentially large FTR positions that have little or no credit requirements. (See “DC Energy FTR Credit Policy Complaint to FERC,” PJM Market Implementation Committee Briefs: June 6, 2018.)
The endorsed proposal, which PJM recommended, would implement a 10-cent/MWh minimum monthly credit requirement applicable to both FTR bids submitted in auctions and cleared positions held in FTR portfolios. It received 208 votes (0.95) in favor, with 12 opposed and 21 abstentions.
The alternative proposal, which would implement a 5-cent/MWh requirement, received 77 votes (0.35) in favor, with 141 opposed and 15 abstentions.
DC Energy’s proposal received 51 votes (0.44) in favor, with 66 opposed and 119 abstentions. The proposal would have required the credit calculation to account for profits or losses in the market. For example, if PJM calculated a $10 credit requirement and the market participant gained $2 in profit from market positions, the participant would submit $8 in collateral to the RTO. If the participant lost $2, collateral necessary would increase to $12.
Bleiweis said he was supportive of the endorsed proposal but hoped for additional revisions. That his proposal progressed to a vote was itself dramatic, as it appeared to have died without being seconded. However, it was announced during voting on the endorsed proposal that Panda Power Funds’ Bob O’Connell had seconded the proposal from the phone, and it was allowed to receive a vote.
PJM’s Bridgid Cummings also reviewed the results of a Credit Subcommittee poll on additional proposals the subcommittee hadn’t endorsed, which found 2% support for a 1- to 5-cent minimum monthly credit requirement on a declining tiered scale based on megawatt-hour volume; 25% support for a $50 million cap on the total minimum monthly credit requirement; 20% support for a $100,000 deductible applicable to the current undiversified adder; and 28% support for status quo.
Balancing Ratio
For anyone confused by the complexities of balancing ratio calculations and performance assessment intervals (PAIs), staff and stakeholders have agreed to develop a presentation for next month’s meeting to compare the proposals on the issue. Currently, there are four.
PJM’s Pat Bruno provided a first review of two proposals developed by staff to revise the method for calculating annual balancing ratios. (See “Balancing Ratio Recalculation,” PJM Market Implementation Committee Briefs: June 6, 2018.)
Bruno said the first proposal was “straightforward” because it would calculate the balancing ratio using the average balancing ratios from the three delivery years that immediately precede the base residual auction or, for years that don’t have at least 30 hours of PAIs, supplementing the actual number of PAIs with estimated balancing ratios calculated during the intervals of the highest RTO peak loads that do not overlap a PAI. PAIs are five minutes apiece.
The second proposal would estimate the number of PAIs expected in the delivery year using the past three years of data, but floored at five hours for calculating the default market seller offer cap (MSOC) and 15 hours for calculating the nonperformance charge rate in Capacity Performance. The proposals would include revisions to the formulas for the nonperformance charge and the MSOC.
Exelon’s Jason Barker noted the proposed MSOC formula wouldn’t always arrive at net cost of new entry multiplied by the balancing ratio if different assumptions for the expected number of penalty hours is employed.
He argued that FERC specifically approved a formula that uses a single assumption about the expected penalty hours and pegs the default offer cap to net CONE. Bruno contended that the commission approved the methodology to arrive at the formula rather than the result itself.
In response to a question by Barker, Bruno said staff “didn’t really have a formulaic approach” for choosing the 15-hour floor for the nonperformance charge, and that they “looked at the data” and came up with “what we thought was a reasonable estimate.”
David Mabry, representing the PJM Industrial Customer Coalition, called it “a balanced proposal.”
Additional proposals from Exelon and Calpine differed with PJM on the PAI calculations for the MSOC and nonperformance charge rate formulas. Calpine’s would floor both at 10 hours and calculate a number based on the past 10 years of data. Exelon’s would use a probabilistic model to look forward. Both would keep constant the number of PAIs used in the two formulas.
Energy Market Caps
PJM’s Susan Kenney reviewed staff’s two-phase plan for addressing issues with Order 831. The proposal offers a short-term fix to address conflicts in PJM’s governing documents, along with a more comprehensive long-term solution. The long-term solution will be less cumbersome than the short-term fix but will require more time to develop. The updated proposal comes after PJM’s short-term proposal failed to receive stakeholder endorsement at the May meeting of the Markets and Reliability Committee. (See “Offer Cap Revisions Stalled Again,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)
PJM is hoping to have the long-term solution ready by Nov. 1, so it should be available several weeks ahead of that so stakeholders can familiarize themselves with the changes prior to implementation, Kenney said.
She outlined some “risks” of the short-term proposal, which would cap all offers at $1,000/MWh by default and allow higher offers to submit a request for verification. The Monitor’s Catherine Tyler said those concerns are the basis for the Monitor’s preference for the “switch to cost” method, which would provide generators the option to exclude price schedules from dispatch. Otherwise, generators can request the ability to submit price-based offers in line with verified cost-based offers, but they are then on the hook to ensure price-based offers at each segment remain compliant with verified cost-based offer caps.
The long-term solution will automate the process.
VRR Curve Update
PJM’s Jeff Bastian reviewed the RTO’s proposed revisions for its quadrennial review of the variable resource requirement (VRR) curve in its Reliability Pricing Model capacity market construct, including a table comparing how the different revisions would impact the gross CONE calculation.
Based on an analysis it commissioned from the Brattle Group, PJM is recommending switching its reference resource from the Frame F to the Frame H of a General Electric turbine and updating the unit heat rate, Bastian said. The frame switch would reduce the net CONE from $405/MW-day of unforced capacity to $308. Some generators have argued against the recommendation. (See Factors in New PJM VRR Curve Still in Question.)
In the table, PJM estimated the gross CONE for 2019 by escalating the 2018 figure by nearly 3%. Bastian said PJM believes it’s important to get the 10% cost adder into the dispatch cost of the reference resource. Overall, PJM’s recommendations would reduce the energy and ancillary service offset by 22% from $72/MW-day of unforced capacity to $56 and reduce the net CONE from $333 to $251.
PJM is targeting Oct. 12 to file for FERC approval, and seeking endorsement votes by the Markets and Reliability Committee on Aug. 23 and the Members Committee during an Aug. 31 teleconference.
VOM Update
As time runs out to square away where generators can recover variable operations and maintenance (VOM) costs, stakeholders remain separated on the issue. PJM is attempting to resolve those differences prior to concluding its quadrennial review of the VRR curve since the costs could be recoverable in either the capacity or the energy market.
There are four proposals set for a vote at the July meeting of the MRC, and while the voting order on the proposals is set, a recent submission from Orange and Rockland Utilities/Rockland Electric Co. has threatened to upset the likely voting. A proposal from American Electric Power that allows use of default U.S. Energy Information Administration calculations will be up first, followed by PJM’s proposal, a proposal from the Monitor and finally RECO’s offering.
AEP’s Brock Ondayko walked through the default proposal, which includes a friendly amendment introduced at the June meeting of the MRC that would prohibit units that failed to clear in the year’s capacity auction from including fixed costs in their energy offers. (See “Variable Operations & Maintenance Packages,” PJM MRC/MC Briefs: June 21, 2018.)
PJM’s Melissa Pilong reviewed the RTO’s package, which remains unchanged from past discussions. It’s the only proposal that would allow units to include fixed costs in their energy offers if they failed to clear in the year’s capacity auction.
Tyler presented the Monitor’s proposal, which would limit costs allowed in energy offers to short-run marginal costs.
“The governing documents are just not clear on these costs and only the IMM package would clean up the definitions,” she said.
Stakeholders have been reluctant to support the Monitor’s proposal because of concern about the definition.
“Part of our disagreement comes down to the definition of short-run marginal costs,” Pratzon said.
RECO’s Brian Wilkie said his proposal was meant to strike a compromise between the generator-friendly and load-friendly proposals to ensure that stakeholders wouldn’t be stuck with the status quo if coalitions stood their ground and those proposals failed to win endorsement. RECO’s proposal would allow generators to recover VOM costs up to limits that would be posted into Manual 15. Almost all unit types would be capped at $3.50/MWh for the costs. Sub- and super-critical coal and biomass would be capped at $4/MWh; nuclear at $3/MWh; and wind, solar and hydro at $0/MWh.
“We agree with the IMM’s definition of VOM is the simplest way to put it,” Wilkie said.
He said PJM staff told him there could be “exponential” cost increases for load if either the PJM or AEP proposal is implemented and later combined with the fast-start or convex hull revisions being considered in PJM’s Energy Price Formation Senior Task Force. (See PJM Board Seeks Reserve Pricing Changes for Winter.)
Generation representatives criticized Wilkie’s use of the term “exponential,” arguing that characterization was validated by estimates. Gary Greiner of Public Service Electric and Gas said it’s unfair to group in various issues when considering isolated proposals.
“I guess that depends on what you throw into the toy box,” he said. “The proper way to do it is to look at this issue [individually] and see what impacts it would have on price.”
“Exponential implies a big change,” Barker said. “To date, I don’t know what that value is.”
The Monitor supported the proposal, along with Mabry and Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS).
“It’s not our proposal,” Tyler said of RECO’s caps, but “we believe it is better than the status quo.”
PJM attorney Chenchao Lu expressed concern about whether it would be permissible to ask FERC to approve rules that would potentially cap cost recovery below actual operating costs. Wilkie had said earlier that he was not an attorney and therefore wasn’t sure whether FERC would accept the proposal.
Wilkie said he was willing to revise the proposal to incorporate feedback from generators. Greiner had noted the changes could create a “cycling nightmare for our ops people,” and Wilkie said he would consider how to address the concerns. Pratzon said more discussion might be necessary.
Wilkie agreed to let PJM know on Thursday — before the agenda is published for the July meeting of the MRC — whether they have received much engagement on their proposal. PJM will decide, depending on that update, whether to put the issue for a vote on the agenda.
Must-offer Revisions
Bruno presented a proposal on revising the rules for what units must offer into capacity auctions. The proposal addresses many of the concerns Exelon expressed when it proposed investigating the issue. (See “Exelon-backed Analyses Approved,” PJM Market Implementation Committee Briefs: March 7, 2018.)
Bowring criticized the proposal, specifically noting his concern that this could allow hoarding of capacity injection rights and block new entry when a unit is uneconomic. He said units should offer their costs in the auction and if they do not clear, the market message is that the units are not needed and not wanted by the market at that price.
— Rory D. Sweeney