CARMEL, Ind. — Recent preliminary load forecast data for the 2017/18 Planning Resource Auction show that each of MISO’s local resource zones has enough capacity on hand to meet its own clearing requirement.
The RTO’s 172 GW worth of total installed capacity can handily meet its 135 GW of planning reserve margin requirements, John Harmon, MISO manager of resource adequacy, said during a March 8 meeting of the Resource Adequacy Subcommittee.
A general slowdown in manufacturing and continued energy efficiency efforts across the footprint is slowing load growth and lowering peak forecasts, Harmon said.
MISO derives its load estimates from a random sampling of load-serving entities and data reviews from LSEs whose load represents 45% of the RTO’s annual peak demand, according to Michael Robinson, MISO’s principal adviser of market design.
Robinson said MISO this year encountered issues with LSEs not providing historical data, excluding methodologies for non-coincident peak and accounting for transmission losses, which the RTO already does once it receives the data. He said all LSEs eventually met the forecast reporting requirements.
“We did see a rash of LSEs that didn’t provide all the information originally,” Robinson said, suggesting the “tightening” of some documentation requirements.
Multiple stakeholders expressed concern that MISO still has 7,300 MW of unconfirmed unforced capacity a month before the auction and asked about the potential for moving up registration deadlines to get more complete data earlier — something Harmon said the RTO would consider.
Harmon said that the unforced capacity data includes about 15 generators that have applied to defer completion of their generator verification tests — which qualify resources as capacity resources or load-modifying resources — until after the 2017/18 PRA.
The RTO said that it will separately report reserve margin data from Michigan’s Local Resource Zone 7, after receiving permission from market participants there that were concerned about protecting competitive information.
Zone 7 shows a 20-GW coincident peak load and a 22-GW planning reserve margin.
Zones 3, 5 and 7 were previously grouped together, as were zones in MISO South (Arkansas’s Zone 8, Zone 9 covering Louisiana and Texas, and Mississippi’s Zone 10). Iowa’s Zone 3 and Missouri’s Zone 5 will continue to be grouped together. (See “Preliminary Load Forecast Released,” MISO Resource Adequacy Subcommittee Briefs.)
MISO will host a stakeholder call to review the results of the PRA on April 14, followed by a longer meeting on the subject April 17.
In a related matter, the deadline to seek rehearing on FERC’s order prohibiting MISO’s three-year forward auction design has passed without any parties requesting a rehearing. (See MISO Won’t Seek Rehearing on Auction Redesign.)
“MISO still believes that mechanisms are needed to support competitive retail areas,” RASC liaison Shawn McFarlane said. He added that the RTO will work with Illinois officials to develop separate capacity auction provisions for retail areas that will not affect regulated areas.
The RTO is also awaiting FERC’s decision on whether it can apply a more stringent physical withholding rule and remove some resources from market monitoring in next month’s PRA (ER17-806). (See MISO Plans Additional Capacity Auction Revamps for 2017.)
MISO attorney Jacob Krause said the RTO could implement the changes — subject to refund — prior to the auction, or that FERC could issue a deficiency letter delaying the changes until the 2018/19 PRA. The commission has until March 17 to act on the filing.
IMM Offers Own PRA External Zone Design
The Independent Market Monitor is recommending its own option for the proposed locational element to the PRA — a year after the RTO began discussing the matter.
Monitor David Patton wants the RTO to create external resource zones based on neighboring balancing authority boundaries and set a clearing price for each external zone set using a shadow price and shift factor. By comparison, MISO staff have proposed six smaller, external resource zones based on geographic groupings of generation and transmission that would be priced using sub-regional prices and clear in the PRA.
Patton’s suggestion would require MISO to quantify how much capacity would be delivered from SPP and PJM and model how the power would flow through MISO’s internal zones. He said his approach would create consistency for MISO operations even as PJM and SPP resources supply capacity.
Some stakeholders asked why an LSE would purchase from external suppliers when the price would be different from auction clearing prices.
Patton said he didn’t see a difference between an LSE contracting bilaterally to purchase power from a different MISO zone and buying megawatts from an external resource. He said he would return to the RASC next month with a more detailed proposal.
Indianapolis Power and Light’s Ted Leffler said buying externally for commercial purposes — and not for reliability — represents an “imperfect hedge.”
However, MISO staff have proposed that external zones clear the PRA at a systemwide or sub-regional clearing price — and not at their offer prices. Akshay Korad of MISO’s market design and evaluation team said the RTO’s three simultaneous feasibility tests run after the auction could limit the capacity export limit of external resource zones if constraints bind and price the external zones as a marginal resource.
MISO used its four proposed MISO Midwest (formerly MISO North) external zones and two proposed MISO South external zones to run a simulation of the 2016/17 PRA. Using the projected external zones, MISO concluded that zones 2-7 could have cleared at $24.80/MW-day, instead of the actual $72/MW-day. (See MISO’s 4th Capacity Auction Results in Disparity.)
A small number of megawatts in the 2016/17 PRA caused the capacity export limit to bind, dictating the high clearing price in zones 2-7, Korad said.
“Even if you see that supply stack change a little bit, you’re going to see a change in price,” Korad said.
The six resource zones proposed by MISO are based on external zones that cleared in the most recent auction, and the number and location of external resource zones could change, said Laura Rauch, MISO manager of resource adequacy coordination.
Stakeholders asked MISO staff to come back with more pricing simulations using external zones.
Like other stakeholders, Leffler remained critical of the entire external zone concept. He asked why MISO couldn’t require LSEs to create fixed resource adequacy plans to hit their full local clearing requirements using only local resources and forbid them from relying on external resources toward their local clearing requirement.
“There ought to be a way that’s easier to do this than create external resource zones,” he said.
MISO Examines Single Year of MISO-SPP Settlement Allocation
MISO stakeholders are questioning the benefits of debating whether some costs of MISO and SPP’s transmission use settlement be allocated to holders of transmission service requests above the 1,000-MW contract path. MISO wants to determine who gets allocated the costs for using the North-South interface for about 300 MW that went above the 1,000-MW North-South limit in 2018/19.
Stakeholders will decide if the RTO can allocate a portion of the costs of just one year of the settlement — the 2018/19 planning year — based on capacity benefits, where firm TSRs from MISO South to MISO Midwest reach 1,304 MW. In all other years of the settlement from 2014-2021, TSRs were or are 1,000 MW or below.
MISO’s Jesse Moser said the question is “narrowly focused” on capacity benefits and is not a forum for negotiating other terms of the settlement agreement.
“MISO is approaching this without a desired outcome in mind. We’re facilitating discussion,” Moser said.
Multiple stakeholders said that an effort to decide the one-year allocation within MISO’s stakeholder process might not be worth pursuing considering the low monetary amount at stake.
Per the settlement agreement, MISO has until Nov. 17 to decide on an allocation to TSR holders, either by filing to alter the terms of cost allocation or making an informational filing to explain that it won’t change allocation.
“That 1,000-MW cap should have been in place in OASIS prior to December 2013,” NRG Energy’s Tia Elliott observed dryly.
Mathis wanted to know the dollar amount at stake — something Moser said he could supply at the April RASC meeting.
The settlement dictates that costs be allocated on a graduating scale based on a ratio that phases out over time — with 100% to load in the first two years of the settlement, decreasing to 45% in the third year and 10% in the seventh year, with the remaining percentage taken on by a flow-based allocation.
MISO pays about $27 million per year for use of SPP’s transmission that links the RTO’s Midwest and South region. The maximum amount MISO could pay under the settlement for heavy transmission use is $38 million per year.
MISO Wants Deferral Year to Create Queue Withdrawal Penalty
MISO is seeking a yearlong extension to develop specific penalties for generation project withdrawal, as directed by FERC in the RTO’s interconnection queue overhaul (ER17-156).
MISO attorney Jacob Krause said the RTO wants to hold off on a filing until March 31, 2017, in order to work with stakeholders to determine an appropriate penalty. He said MISO is currently seeking FERC permission for the deferral.
— Amanda Durish Cook
