By Amanda Durish Cook

MISO’s markets performed competitively last year, but the RTO should implement several new recommendations to improve market functions, the Independent Market Monitor’s 2017 State of the Market report concluded.

MISO IMM David Patton said energy prices averaged $29.46/MWh in 2017, an 11% increase over 2016 but in line with rising prices for natural gas and other fuels.

“The markets continued to perform competitively, although we have areas of concentration with local market power,” Patton said during a June 26 conference call held by the Markets Committee of the MISO Board of Directors.

But market performance could be made more efficient, Patton said, offering seven new market recommendations in combination with past State of the Market suggestions.

Fast-Track Ideas

Patton said two of his new recommendations could be fast-tracked and not require a slot on MISO’s Market Roadmap process, which is traditionally reserved for more complex improvements.

The first: to improve market power mitigation rules. Patton said his proposed changes are “modest in scope and impact” but would help in the effectiveness of market power mitigation provisions.

“Every year, MISO makes a cleanup filing of [mitigation rules], and we collaborate with them on it,” Patton explained. This year he has recommended that MISO adjust its impact test and sanctions rules to include the impact of negative prices; make the price impact threshold for ancillary services better reflect prevailing clearing prices; and create a better generation shift factor cutoff on mitigation for broad constrained areas, a type of congested transmission area. Including negative prices in mitigation measures will allow the Monitor to “effectively mitigate conduct whose effect is to lower prices at locations and aggravate transmission constraints,” Patton said.

Patton’s second fast-track suggestion would remove transmission charges from coordinated transaction scheduling (CTS) transfers with PJM. MISO and PJM launched CTS last October to allow market participants to schedule economic transmission transactions based on forecasted energy prices in the two RTOs. While CTS should have lowered the cost of serving load in both regions, it has not been used since mid-February because MISO has been applying transmission charges to the transactions both when they are offered and scheduled, Patton said.

“We had advised that the RTOs not apply transmission charges or allocate costs to these transactions because they do not cause any of these costs,” said Patton, who estimates the charges average $6.24/MWh on MISO imports and $2.57/MWh on exports. He urged MISO to “unilaterally eliminate” all charges from CTS transactions.

“Although MISO should encourage PJM to do the same, there is no reason to wait for PJM to agree to eliminate its charges,” Patton said. “We could change these relatively quickly … This is a very discreet change,” he told MISO board members.

Quick Fix to Make-Whole Payments

Patton said another “relatively simple” market change could help MISO distribute make-whole payments more accurately: improve commitment classifications and create a process to correct classification errors.

Patton said his team has observed MISO operators misclassifying “a fair number” of resource commitments needed to manage transmission constraints as capacity commitments. The RTO assigns a classification code to any resource it commits to either satisfy capacity needs or manage transmission constraints, which determines whether the resource is eligible for make-whole payments through its revenue sufficiency guarantee (RSG), how the RSG payment will be allocated and whether the payment will be subject to mitigation. Patton said the misclassification of code assignments can have “significant” implications on revenue sufficiency guarantee allocations and market mitigation.

“ … It is imperative that MISO have a robust process for reviewing and correcting commitment classifications as needed,” Patton said. He added that he also understood some commitments can address multiple issues and constraints and called on MISO to create clearer procedures for determining a classification based on “cost-causation” principles.

Operator Accountability

Another recommendation would place more accountability on MISO operators in the control room by improving operator logging tools to better describe operator decisions and actions. Patton said MISO operators often inconsistently log or describe manual adjustments, making them difficult to evaluate later.

Operators can make several system adjustments, including changes in generating units’ operating status, real-time adjustments to forecasted load, manual redispatch of resources for system needs, alterations of real-time limits for transmission constraints, real-time adjustments to the transmission constraint demand curve and requests for market-to-market constraint tests and activations.

“Because these actions can have significant cost and market performance implications, we recommend that MISO upgrade its systems and procedures to allow these and other operator actions to be logged in a more complete and detailed manner,” Paton said, adding that MISO could include new logging tools in its effort to replace its market platform.

Day-Ahead Market Change

Patton also proposed MISO’s platform replacement effort could provide MISO the chance to evaluate the feasibility of solving the day-ahead market with 15-minute — rather than hourly — scheduling intervals. Patton said when MISO first created its markets, the day-ahead software wasn’t sophisticated enough to be more time-specific.

“By producing hourly schedules based on 60-minutes of ramp capability and hourly load forecasts, the day-ahead schedules cannot track the expected changes in real-time system needs, particularly during ramping periods. It also regularly results in generator schedule changes from hour to hour that are not feasible, which results in substantial make-whole payments,” he said.

But advances in technology might permit 15-minute day-ahead market schedules, which could improve market response times and reduce uplift costs.

Auction Improvements

Patton’s two final recommendations involve MISO’s annual Planning Resource Auction (PRA).

The first suggestion would require that installed capacity of planning resources be deliverable over the transmission network. While the Tariff already requires all resources to be deliverable to load to qualify as capacity resources, Patton says that, in one instance, MISO’s deliverability requirements are too relaxed because resources with Energy Resource Interconnection Service (ERIS) must only secure firm transmission for its unforced capacity values, which tend to be about 5% to 10% less than their full installed capacity levels.

But Patton said resources with ERIS should be required to procure firm transmission service to the full level of their installed capacity.

“The requirements imposed by MISO on ERIS resources is not consistent with the intent of the Tariff. We recommend that MISO determine deliverability for all resources based on the entire [installed capacity] of applicable planning resources,” Patton said.

Such a move will improve the accuracy of MISO’s loss-of-load studies since they are conducted with the assumption that resources will perform up to their installed capacity when available, he noted.

The Monitor also recommended MISO establish unique capacity credits in the PRA for emergency-only resources that better reflect their availability. While those resources can be compensated through the PRA, they are only required to deploy during emergencies when called on by MISO. If they “are not available to mitigate capacity shortages that usually occur early in the emergency events, then they are not providing the reliability value assumed in the planning studies and for which they are compensated,” Patton said.

An increased volume of emergency-only resources cleared in this year’s PRA. (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.) Patton pointed out that some of the resources have lead times up to 12 hours that “render them essentially unavailable in an emergency.” He said emergency-only and load-modifying resources should only receive full PRA capacity credit if “they are expected to be reasonably available in an emergency” and can respond to a benchmark not yet established by MISO.

Patton pointed out that other generation is subject to capacity-selling requirements, including qualifications based on past forced outage performance, day-ahead must-offer rules and reduced capacity credits for intermittent resources. He recommended MISO quantify emergency-only capacity credits based on factors such as expected availability, historical performance and curtailment ability.

Patton last year raised nine new market recommendations with which MISO mostly agreed. A year later, none have been implemented, although MISO continues to discuss several with stakeholders. (See MISO Board Hears State of the Market Recommendations; MISO in Harmony with IMM State of the Market Report.)

Executive Director of Market Development Jeff Bladen said MISO will provide a formal response to this year’s report within 120 days, per its Tariff.

Bladen reminded the board that MISO’s ability to take on new market improvements will continue to be “constrained” by MISO’s technology capabilities as the RTO replaces its outdated market system platform. (See “Limited Improvements for Old Platform,” MISO Platform Replacement Risks Delay, Budget Overrun.)