An emerging underfunding trend has led to some early concerns for MISO’s congestion-hedging market.

MISO says there’s a burgeoning mismatch between awarded auction revenue rights (ARRs) and actual congestion patterns in the footprint. As a result, load-serving entities hold a historically smaller share of financial transmission rights (FTRs) and the congestion value associated with ARRs is falling, the RTO said.

Staff’s John Harmon said during a Thursday Market Subcommittee teleconference that the trend began in December 2019.

The grid operator said while it won’t propose FTR market changes for the 2022-23 planning year, it said “substantial foundational rule changes” could be on the horizon to better line up ARR awards and congestion patterns. The RTO has hired an outside consultant to investigate its FTR-ARR auction structure.

ARRs and FTRs in MISO are issued based on transmission capacity and used by LSEs and other market participants as financial hedges against congestion charges in the day-ahead market. The grid operator funds FTRs through day-ahead congestion costs. An ARR is the LSE’s entitlement to a share of revenue from FTR auctions because of their historical use and investment in the transmission system.

MISO Independent Market Monitor David Patton observed that FTR obligations in 2020 exceeded congestion revenues by $74.6 million, a 4.1% shortfall.

MISO said increasing wind generation has reduced the volume of ARRs. Wind generation ARRs tend be about one-third of those associated with retiring baseload generation.

“Even though wind can produce up to 20 to 25% of energy, it has a smaller share of auction revenue rights,” Harmon said.

MISO said its FTR-ARR market was developed to “protect long-term rights with provisions for very limited, incremental portfolio change.”

Harmon said the recent move to lower generation shift factor cutoffs from 1.5% to 0.5% in the day-ahead market should better line up congestion with FTR rights. MISO will monitor the change’s effects before proposing any changes to its FTR market structure, he said. A lower generation shift factor allows staff to redispatch generators to improve transmission constraints.

Bill Booth, consultant to the Mississippi Public Service Commission, suggested MISO restrict participation in the FTR auctions to LSEs and those with long-term power contracts. WEC Energy Group’s Chris Plante has said it doesn’t seem fair that “a significant amount of day-ahead congestion revenue is allocated to entities that are not allocated any of the transmission system cost.”

Stakeholders have also recommended MISO revive its dormant FTR working group to examine potential changes to FTR and ARR mechanisms.

Harmon said MISO isn’t supportive of eliminating FTRs altogether, as some have suggested. “That would be a substantial overhaul of how we allocate congestion in our day-ahead market,” he said.

MISO Encourages Accurate Renewable Forecasts

MISO is proposing that its tariff contain direction on member-derived forecasts for dispatchable intermittent resources.

The RTO has said for months that its output forecasts for intermittent resources are consistently more accurate than those created by its members.

“As we get high wind and solar penetration, accuracy of forecasts is going to important for reliable operations and market efficiency,” Congcong Wang said of MISO’s day-ahead market and reliability commitment division.

The grid operator is proposing tariff language that members’ maximum forecast limits “reflect the most likely forecast outcome, and be directly derived from an accurate, and statistically unbiased forecast, using the most current forecast data available for the specific dispatch interval.”

The RTO also said that the forecast should be “directly derived” from a resource’s capabilities, actual generation data and weather predictions “relevant as of the time of submission.” It plans to file with FERC by December.

Staff will also periodically check its market participants’ forecasts to see if they continue to be less accurate than MISO’s. Wang said staff will reach out to market participants with chronically inaccurate forecasts before forcing them to use MISO’s forecasts. After that, a market participant can submit evidence to regain control of its forecasting.

More than 95% of MISO’s nearly 270 intermittent resources already use the grid operator’s renewable output forecasts. The RTO estimates that its footprint will contain more than 30 GW of wind and about 11 GW of solar in the next few years.

Some stakeholders have asked whether MISO couldn’t simply dictate that holdouts use MISO’s forecasts instead of making their own.

Wang said the language represents a “first big step” from the tariff being silent on forecast accuracy to prescribing careful forecasting. She said MISO doesn’t want to be too prescriptive in members’ forecasting.

Tx Customers Ask for Additional Load-forecasting Data

MISO transmission customers are asking for more insight into staff’s weekly load forecasts.

McNees Wallace and Nurick attorney Ken Stark, appearing on behalf of the Coalition of MISO Transmission Customers, said MISO is an outlier among RTOs because it doesn’t make its load forecasting data over the next week available to customers.

“MISO provides a day-ahead forecast by local balancing authority; however, that forecast is much less valuable than a current day plus six-day forward-looking forecast,” he said.

Stark said if large transmission customers had access to more specific load data, they might have been able to prepare and assist during Tuesday’s maximum generation alert and conservative operations declaration for the Midwest region. The event was unexpected because of mild weather and systemwide load of 72 GW.

He asked that customers have access to seven-day load forecasting data on the local balancing authority or local resource zone level. Stark also said MISO could make the data available to customers via a secure portal if the RTO is worried about revealing nonpublic data.

IMM: June 10 Emergency Unnecessary 

MISO’s Independent Market Monitor has concluded that the RTO did not need to escalate a maximum generation alert to a maximum emergency on June 10.

The brief emergency resulted in a surfeit of load-modifying resource (LMR) response and non-firm imports. (See “MISO Defends June Emergency Declaration,” MISO Market Subcommittee Briefs: July 8, 2021.) Ultimately, the event generated $2 million in day-ahead margin assistance payments to resources “that had to be held down to make room for the additional supply,” the IMM’s David Patton said.

“The combination of commitments, LMRs and higher imports led to a surplus in the Midwest exceeding 10 GW for most of the event,” he said.

Patton called for a more “surgical” method for deploying LMRs so that MISO is more precise in ordering curtailments. The grid operator has about 11.5 GW in LMRs participating as capacity, split 60-40 between demand response and behind-the-meter generation.

“We’re a unique RTO that … has 16, 17 GW import capability,” he said.  

Patton suggested MISO attempt modeling that contemplates non-firm imports when it is struggling and its neighbors aren’t.

He said suggested the grid operator delay making real-time commitments until control room operators are certain they’re necessary.

In this year’s State of the Market report, Patton asked the RTO to create an “uncertainty product” from fast-start resources to replace the expensive, out-of-market commitments that control room operators make. He said the system’s rising numbers of intermittent generators necessitates another class of energy reserves.

VoLL Pricing at Dead Buses Questioned 

The subcommittee meeting contained another disagreement over MISO’s policy of pricing dead buses at their $3,500/MWh value of lost load (VoLL).

Some stakeholders question how MISO can price dead buses at the VoLL when generators are unable to deliver power to customers.

Kevin Vannoy, MISO’s director of market design, said it’s an incorrect assumption that all dead buses can be traced to a catastrophic event. He said that sometimes, it’s as simple as a generator being offline.

“The value of energy is the value of energy whether it’s theoretical or possible,” Vannoy said.

“It’s a theory that cost $90 million,” Booth said, referencing VoLL pricing during Hurricane Laura.

The RTO originally said force majeure events that lead to dead buses should not be priced using VoLL. (See MISO to Outline New Pricing Plan for Hurricanes.) It said VoLL is appropriate to price capacity emergencies, even when they’re caused by force majeure, but that local and systemwide transmission emergencies should be shielded from the pricing.

“The procedures don’t speak to the cause of the emergency; they give us the tools to manage the emergency,” Vannoy told stakeholders during July’s subcommittee meeting.

Patton said February’s arctic event was a “garden variety” combination of transmission and capacity emergencies. He said it becomes difficult after emergencies to separate those caused by unavailable transmission or inadequate capacity.

“The distinction is really, I think, harmful,” Patton said in July.