VALLEY FORGE, Pa. — PJM’s Market Implementation Committee approved manual revisions reducing the number of virtual bidding locations by almost 90%, a change approved by FERC in February to address uplift (ER18-88). (See FERC OKs Slash in Virtual Bidding Nodes for PJM.)
PJM’s Keyur Patel presented the revisions to Manual 11, which include a link to a list of the eligible locations. The changes reduce the number of bidding locations for increment offers (INCs) and decrement bids (DECs) from 11,727 to 1,563, retaining all hub and interface nodes but eliminating some aggregate and generator nodes. The number of up-to-congestion transaction (UTCs) trading points was reduced to 49 from 418.
Stakeholders approved the revisions by acclamation.
Intraday Offers
PJM’s Susan Kenney discussed other proposed revisions to Manual 11 that staff are trying to move quickly through the stakeholder process to expand the window for submitting generation offers.
Procedures implemented by PJM on April 5 to accept intraday offers limited when generators could submit offers with hourly differentiated minimum run time, notification time and minimum downtime to after the day-ahead reliability run and up to 65 minutes before the dispatch time.
Generators asked that PJM also allow submitting that information before day-ahead offers are due and during the afternoon day-ahead rebid window. PJM plans to make this change by eliminating manual language that restricts the submission timing but also clarifies that those values are used only in real-time commitment and dispatch.
“I appreciate PJM’s efforts to reinstate what I think were some unintended consequences,” NRG Energy’s Neal Fitch said. “The alternative right now is I don’t have an ability to tell PJM this information absent calling them up about every unit.”
Adrien Ford with Old Dominion Electric Cooperative agreed the revisions restore efficiency.
Offer Cap Resolution
Responding to stakeholder reservations about returning to previous language on cost-based offer caps, PJM has developed a new plan that members found acceptable. The Manual 11 revisions, which were approved by acclamation with two abstentions, will cap all offers at $1,000/MWh by default. Generators will be able to submit requests for higher cost-based offers, which PJM will screen and allow if validated.
For price-based offers, generators will have a choice: Either select “Switch to Cost” to exclude price schedules from dispatch — the option that PJM “strongly” suggests — or request the ability to submit price-based offers in line with verified cost-based offers. Kenney cautioned that sellers will be responsible to ensure the price-based offer at each segment remains compliant with verified cost-based offer caps.
Kenney acknowledged that the interaction between cost- and price-based offers is “very intertwined” and that staff are still seeking better ways to help verify offer validity.
Catherine Tyler from the Independent Market Monitor unsuccessfully urged stakeholders to oppose the stop-gap revisions and instead push for a holistic solution that automatically validates offers. She said there were instances during January’s “bomb cyclone” cold snap in which offer rules were violated, and that software options should be explored “to ensure there’s automatic compliance.”
“I think everyone would like to see Markets Gateway [PJM’s offer-submission software] take care of this problem,” Tyler said. “We all want to be in the same place at the end, but we do think there’s a different path forward.”
Modeling Node Changes
PJM’s Brian Chmielewski presented staff’s proposed manual language for replacing terminated nodes that are part of financial transmission right paths. An overview of the plan was presented at last month’s meeting but lacked proposed language. (See “Nodal Mapping,” PJM Market Implementation Committee Briefs: April 4, 2018.)
Direct Energy’s Marji Philips, who has repeatedly raised concerns with PJM’s previous plans to address this issue, voiced her approval for the updated plan and thanked PJM for working through it.
Long-term FTR Considerations
Chmielewski also presented PJM’s proposal to change the RTO’s long-term FTRs auction process and modeling practices. The IMM’s Howard Haas called the proposal a “vast improvement” but also offered two proposals that he said “may be better.”
Both of the IMM’s plans would follow PJM’s proposal for the first year forward, but years two and three wouldn’t be biddable. Both proposals would remove the “year all” option that allows bidding on a compilation of all three years. Haas suggested this would give bidders “optionality” should system conditions change unexpectedly because “right now, you can be locked into three years.”
Revenue would be allocated to load in either plan, though FTR volume in the second proposal would only be available through counterflow FTRs.
“The model would start with a net-zero transfer capability on a path, so any created capability for years two and three would have to come from counterflow positions,” Haas said. “In that case, the expectation is that there would be no net revenue available to allocate anywhere, but if there was any, you’d allocate it to load.”
Chmielewski said PJM would have to analyze the IMM’s proposals before deciding whether to support them.
Stakeholders pushed back on the IMM’s proposal.
“I encourage people to take a look at Package A [PJM’s proposal] and consider supporting it,” said Exelon’s Sharon Midgley, who called for preserving the priority rights for load and retaining the term of the existing long-term FTR construct. “The value and the importance of having the financial hedging instrument for market participants with physical generation and customers … is probably equally important to maintaining load’s priority rights, which is why we prefer A. … Firms that have generation and customers, their ability to secure hedges is going to severely limited” in the IMM’s plans, she said.
Philips endorsed PJM’s request for quick action on the proposal, urging stakeholders to “not let the perfect get in the way of the good.” She hoped to have the revisions in place for the upcoming FTR auction in June.
“If we go the method of using counterflow to provide liquidity in the auction, we’re actually going to reduce liquidity,” Vitol’s Joe Wadsworth said, noting that use of counterflow to match prevailing flow resembles how the over-the-counter market works. “There’s not much liquidity in the over-the-counter markets.”
He also voiced concerns about losing transparency. “I fear that if we go the route of relying on counterflow in order to get prevailing flow in an auction, we would lose a lot of the transparency that exists today,” he said.
ODEC’s Ford said she favored PJM’s proposal since the IMM also endorsed it, even if it thought it had a better idea, American Municipal Power’s Steve Lieberman said, “any of these packages is preferable to the status quo.”
FTR Forfeitures
Midgley and Mike Borgatti, representing NextEra Energy, proposed sensitivity tests for analyzing PJM’s FTR forfeiture rule to determine if it’s overly restrictive and foreclosing legitimate trading. Exelon won MIC endorsement in March for a problem statement and issue charge to analyze the rule. (See “Exelon-backed Analyses Approved,” PJM Market Implementation Committee Briefs: March 7, 2018.)
Borgatti and Midgley argued that an overly restrictive forfeiture rule might cause competitive suppliers to add a “risk premium” to customer costs and could reduce the value of load’s auction revenue rights (ARRs) if market participants bid less for affected FTRs.
“You can’t efficiently hedge off the cost of load in the energy market, and so the result of that FTR forfeiture is inefficiency that’s going to show up ultimately as an additional cost to consumers as a risk premium,” Borgatti explained.
“We’re trying to become better educated on why we’re seeing the market outcomes [of increased forfeitures] that we’re currently seeing,” Midgley said. “We’re not really sure exactly what is wrong. I know that my firm is being impacted, and we’re seeing significant levels of forfeitures that we’ve never seen before. And it’s preventing us from using INCs and DECs and FTRs to manage legitimate business risks.”
The stakeholders proposed doing sensitivity analyses to test components of the forfeiture procedure. Borgatti compared it to determining school-zone speeds that are both safe for pedestrians and equitable for drivers.
However, IMM Joe Bowring argued that the rule is curbing behavior as it’s intended to. He offered to discuss with individual market participants how the rule was applied to their portfolio and pointed out that forfeitures have declined since the introduction of the new rule as participants have come to understand it better.
“Simply the fact that somebody is doing something doesn’t make it legitimate. The fact that somebody is managing risk doesn’t make it legitimate,” he said.
Bowring also questioned whether the intent of the initiative is to figure out how to bypass the rule.
Midgley and Borgatti denied that motivation. “I don’t think it’s either of our companies’ intent to create a cookbook for how to game the rule,” Borgatti said.
Chmielewski said PJM remains confident in its compliance filing to address FERC’s January 2017 ruling on the issue, though the commission has yet to rule on it (EL14-37, ER17-1433). (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)
Stakeholders approved manual changes supporting the compliance filing in September. (See “Stakeholders Endorse Manual Revisions,” PJM MRC/MC Briefs: Oct. 2, 2017.)
Despite that, he said PJM is willing to consider alternative perspectives. He presented an analysis that showed changing the rule’s sensitivity for its virtual test from 0.1 MW to 10 MW — or 10% of the line’s day-ahead binding limit if it’s greater — would have cut forfeitures in half and eliminated forfeitures for 12 of 67 market participants penalized. Forfeitures for September 2017 would have been reduced by half, from roughly $2 million to roughly $963,000.
“Really what this trigger is doing is if you’re looking at any binding constraint in the day-ahead market with a 100-MW limit or less, you’re basically saying it has to have a 10-MW or more impact, which may or may not make sense depending on how you look at it,” Chmielewski explained.
Under questioning from stakeholders, he acknowledged that the issue could benefit from further analysis.
“If 10 MW is too high, what’s too low? Is 0.1 too low?” he asked.
He said he couldn’t determine whether there would be any market resettlements if the rule is changed again, but that “it’s possible.”
Balancing Ratio
PJM’s Pat Bruno reviewed the RTO’s proposal to address concerns with calculating the balancing ratio (B) used in the default market seller offer cap (MSOC). The calculation became an issue after PJM was unable to determine a MSOC for 2018 and was forced to implement a stop-gap number. (See “Balancing Ratio Study Changed,” PJM Markets and Reliability Committee Briefs: April 19, 2018.)
PJM’s proposal would calculate average hourly balancing ratios from as many performance assessment intervals (PAIs) as have occurred within the past three years and supplement them with estimated hourly balancing ratios from as many of the remaining peak hours as is necessary to meet the required number of hours of PAIs. Currently, that number is 30. The balancing ratios would be averaged together for a final balancing ratio for the year.
PJM argues the proposal is straightforward, reasonable and able to be completed within the necessary amount of time.
Bowring suggested in his proposal that the balancing ratio can be estimated using a forward-looking model of performance assessment intervals.
“If there are no performance assessment [intervals], there is no B and we don’t need to make one up by inventing various weird ways of pretending there really was one,” Bowring said. “It’s still possible to get to an offer cap. … Let’s not make things up. Let’s actually do a model … based on PJM’s current modeling to determine what we expect to happen.”
Quadrennial Review of VRR Curve
Stakeholders asked PJM to justify its recommended revisions to key parameters for the annual capacity auction following its quadrennial review of the demand curve. PJM reviews the calculation of its demand, or variable resource requirement (VRR), curve every four years and makes recommendations based on an analysis of the curve’s performance. (See PJM to Consider Revisions to Demand Curve Design.)
Among PJM’s more controversial recommendations is that stakeholders ignore the recommendation of the Brattle Group, which performed the performance analysis, and continue to base the VRR curve on the cost of new entry (CONE) calculations for a gas-fired combustion turbine. Brattle recommended changing to the CONE for a combined cycle unit, which it said is cheaper.
“This curve has proven over the past years to be reliable and robust,” Bruno said in defense of the CT-based curve.
“I really expected some evaluation of the shape of the curve … and there wasn’t any of that,” said James Wilson, who consults for several consumer advocates within the RTO’s footprint.
Bruno argued that Brattle reviewed the curve’s shape, as the Tariff requires.
AMP’s Lieberman asked why PJM thought it was appropriate to shift the curve right four years ago based on Brattle’s recommendations — increasing the expense to consumers and profits to generators — but not back when they recommend it four years later. ODEC’s Ford echoed the concerns.
Calpine’s David “Scarp” Scarpignato said he wasn’t “convinced” that the curve reduces excess capacity.
“There are a lot of barriers to exit going on. … I don’t think you can study the curve in isolation like that,” he said.
PJM is not recommending a change in the cap, so it would remain 1.5 times net CONE or 0.7 times gross CONE.
Order 844 Revisions
PJM briefed the MIC on its response to FERC’s April order requiring RTOs to submit monthly reports detailing their uplift payments and operator-initiated commitments (Order 844, RM17-2). PJM has until Sept. 7 to make its compliance filing implementing the changes, which have to go into effect by Jan. 7. (See FERC Orders RTOs to Shine Light on Uplift Data.)
RTOs/ISOs are required to report:
- total uplift payments for each transmission zone, separated by day and uplift category;
- total uplift payments for each resource monthly; and
- megawatts of operator-initiated commitments in or near real time and after the close of the day-ahead market, broken out by transmission zone and the reason for the commitment.
In addition, the order requires PJM to add to its Tariff the transmission constraint penalty factor values used in market software; the circumstances under which the penalty factors can set LMPs; and the procedures for temporarily changing transmission constraint penalty factor values.
A discussion on the topic is planned for a special MIC meeting May 10.
— Rory D. Sweeney