CARMEL, Ind. — MISO’s mechanism for allocating charges under its settlement with SPP was certified by a FERC administrative law judge last week (ER14-1736).
MISO has been using a temporary miscellaneous charge based on market load ratio share to collect the $1.33 million a month it is paying SPP until February for flows over 1,000 MW passing through MISO’s North-South interface. Under a settlement reached with its stakeholders, MISO will use a new, modified market load ratio share basis to allocate those costs. This method also applies to the $16 million it paid from Jan. 29, 2014, to Jan. 31, 2016, but that amount won’t be subject to resettlements, MISO Director of Market Services John Weissenborn told the Market Subcommittee on Oct. 4.
From Feb. 1, 2016, to Jan. 31, 2021, MISO will use a transitional, hybrid method, with a continuously declining percentage of the costs allocated through the new load ratio share calculation and an increasing amount through a flow-based benefits allocation methodology.
Weissenborn said the RTO will continue to allocate the costs under the current method until FERC accepts the settlement agreement and accompanying Tariff language. After approval, MISO can begin resettlement for costs from Feb. 1, 2016, and beyond.
“We can almost anticipate two resettlements: one to true-up the $1.33 million and another to implement the cost allocation,” Weissenborn said. Weissenborn said payments under a true-up will be a simple calculation, but the new cost allocation will be trickier: “The challenge that we have is that this is another new software change, but we will comply. We will get it done.”
Weissenborn said MISO will hold future stakeholder meetings on two remaining internal cost allocation issues under the settlement: how much entities with firm transmission that reduced the 1,000-MW capacity limit will have to pay and what cost allocation is needed for entities with capacity benefits that raised the Planning Resource Auction limit above 1,000 MW.
IMM Seasonal Review: Pricing Changes Still Needed
Independent Market Monitor David Patton used a review of last summer to continue his push for pricing changes.
Patton said summer’s 44% rise in energy prices over spring’s was due to increased natural gas prices and 1% larger year-over-year demand from summer 2015.
“Because of hot temperatures, we did rely more heavily on peaking resources,” Patton told the Market Subcommittee. The uptick led to more revenue sufficiency guarantee payments, culminating in a peak of almost $1.7 million in payments on July 21, when nearly all of MISO’s generating turbines were committed during a maximum generation event. The day also resulted in 1.6 GW of voluntary load curtailment, which lowered real-time energy prices to $36/MWh, even though the day-ahead price was $78/MWh. (See “IMM Makes Pricing Suggestions Following First Max Gen Event Since Polar Vortex,” MISO Markets Committee of the Board of Directors Briefs.)
“The problem with this is these are megawatts outside of MISO’s control,” Patton said. “You’re incurring an awful lot of costs just to turn these generators on. You’re certainly forcing the system to accept a lot of high-price energy. It makes it difficult to price the energy. …There are some things MISO could take a look at, and MISO is taking the process very, very slow.”
Patton repeated his suggestion that increasing the number of generators allowed to set prices under extended locational marginal pricing would temper erratic pricing.
“Procedures that say ‘turn everything on’ are not efficient, especially when there’s a more surgical” method, Patton said.
Jeff Bladen, executive director of MISO market services and liaison to the MSC, said the RTO will need to work with individual states and load-serving entities to improve the visibility of demand response. But he stood by the July 21 decision to issue the alert.
“What drove the over-commitment was not self-deployment. It was very much about the weather. Had the [stormy] weather in the forecast materialized, we would have absolutely needed the commitments,” Bladen said. Patton said he didn’t completely agree with that assessment.
Patton also said summertime outages that impacted constraints had a hand in increasing real-time congestion to $463.4 million in summer 2016 from $342.2 million in summer 2015.
MISO to Expand ELMP Price Setting, but not to IMM’s Specs
MISO Market Design Engineer Congcong Wang said the RTO is willing to expand ELMP to online resources with a one-hour start-up time without software changes.
The RTO says the possible expansion “captures a majority of peaking resources.”
Wang said the Monitor’s original recommendation that online price setting be spread to all resources with a two-hour minimum run time is neither cost effective nor beneficial with MISO’s current software. “The full expansion to two-hour minimum runtime will require software changes,” Wang said. (See MISO Study Undercuts IMM Proposal on Expanding ELMP Pricing.)
MISO’s path forward would increase eligible peaking resources from 8% to 58% on a capacity basis. Wang said the expansion without software changes captures about 60% of the Monitor’s recommendation “in terms of real-time commitment.”
With the addition of one-hour start-up units, ELMP price setting, which currently includes about 45 10-minute start-up units with a combined capacity of 1.2 GW, would increase to 179 units at 8.4 GW. The Monitor’s advice to include two-hour minimum runtime units would bring the number to 256 units at 14.4 GW.
However, MISO is not willing to budge on removing offline units from price setting in ELMP, another Monitor suggestion. Wang said MISO’s research shows that offline fast-start resource participation can address shortages. MISO said it “will work with its IMM to continue monitoring offline participation and will exclude a resource from pricing if it is found infeasible.”
Wang said MISO would likely make a final decision on resource pricing under ELMP at the December Market Subcommittee meeting.
If the RTO decides to go with the option that does not require a software change, Wang said implementation could begin in the first quarter of 2017.
MISO-PJM Coordinated Transaction Scheduling Delayed
The introduction of coordinated transaction scheduling with PJM will be delayed from March to next October, Bladen said during a Market Subcommittee liaison report.
Bladen said the date change is needed while MISO waits on PJM to complete market improvements and staff training. He added that joint filings will be made soon to update FERC on the later implementation date.
David Sapper of Customized Energy Solutions asked how stable CTS will be given that MISO is also trying to implement interface pricing rules with PJM. (See “No Consensus on Interface Pricing,” MISO/PJM Joint and Common Market Meeting Briefs.)
Bladen said while there is a relationship between the two market improvements, they aren’t related to a degree that would prevent them from being introduced independently.
“There’s no premise that you have to have one before the other,” he said. “They’re not intrinsically tied. They’re relative improvements of the same process.”
CTS is intended to reduce uneconomic flows between the two RTOs. The new product would allow traders to submit “price differential” bids that would clear when the price difference between MISO and PJM exceeds a threshold set by the bidder.
MISO Considering Moving Reserve Buy-Back into RSG
MISO is investigating a way to make up lost revenue for resources committed in real time that have previously cleared day-ahead offline supplemental reserves, said Jason Howard, MISO manager of market quality.
Currently, generators that commit in the real-time markets have to buy back their supplemental reserves.
MISO is considering providing make-whole payments to such generators through revenue sufficiency guarantee payments, Howard said. He said the proposal, which would require a Tariff change, would ensure that those units aren’t operating at a loss.
MISO looked at four years of historical data and found the average cost for buying back supplemental reserves amounts to $1 million per year across the RTO, Howard said.
— Amanda Durish Cook
